issue-1996-05-10•Federal Register final rules — 1996-05-10
Federal Register final rules — 1996-05-10
issue-1996-05-10Federal Register final rules — 1996-05-10Regulation
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FR Doc. 96-11776 Marine Mammal Special Exception Permits to Take, Import and Export Marine Mammals; Update of Office of Management and Budget (OMB) Approval Numbers
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21926-21939]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11776]
[[Page 21925]]
_______________________________________________________________________
Part IX
Department of Commerce
_______________________________________________________________________
National Oceanic and Atmospheric Administration
_______________________________________________________________________
15 CFR Part 902
50 CFR Parts 216 and 222
Reporting and Recordkeeping Requirements; Final Rule
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and
Regulations
[[Page 21926]]
DEPARTMENT OF COMMERCE
National Oceanic and Atmospheric Administration
15 CFR Part 902
50 CFR Parts 216 and 222
[Docket No. 960419116-6116-01; I.D. 122492C]
RIN 0648-AD11
Marine Mammal Special Exception Permits to Take, Import and
Export Marine Mammals; Update of Office of Management and Budget (OMB)
Approval Numbers
AGENCY: National Marine Fisheries Service (NMFS), National Oceanic and
Atmospheric Administration (NOAA), Commerce.
ACTION: Final rule.
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SUMMARY: This final rule updates and consolidates the regulations for
special exception permits to: Take, import, export, or carry out any
other otherwise prohibited act involving marine mammals for the
purposes of scientific research, enhancing the survival or recovery of
a marine mammal species or stock (enhancement), educational and
commercial photography, and public display under the Marine Mammal
Protection Act of 1972 (MMPA); take, import, export or carry out any
other otherwise prohibited act concerning endangered or threatened
marine mammals for scientific purposes or enhancement under the
Endangered Species Act of 1973 (ESA); and, determine the status and
disposition of rehabilitated stranded marine mammals. This rule sets
forth revised procedures for these permits in order to make
administration of the NMFS marine mammal permit program more efficient,
consistent, and predictable.
This rule also updates OMB Paperwork Reduction Act approval numbers
for applications and reports for special exception permits.
EFFECTIVE DATE: This final rule is effective June 10, 1996.
ADDRESSES: National Marine Fisheries Service, (F/PR1), 1315 East-West
Highway, Silver Spring, MD 20910.
FOR FURTHER INFORMATION CONTACT: Laurel Bryant or Ann Terbush, Permits
Division, Office of Protected Resources, 301/713-2289.
SUPPLEMENTARY INFORMATION:
Purpose
A proposed rule was published (58 FR 53320, October 14, 1993) to
consolidate into a single set of regulations all permitting
requirements under the MMPA, the ESA, and the Fur Seal Act (FSA) to
take, import, or export all protected species under the NMFS
jurisdiction for purposes of scientific research or enhancement, and
public display, and to provide clear procedures for the disposition of
rehabilitated stranded marine mammals.
In contrast, this final rule implements only a part of that
proposed rule; namely, it establishes basic permit requirements
applicable to all permits to take, import and export marine mammals and
marine mammal parts for purposes of scientific research and
enhancement, photography, and public display (for captures and initial
imports) under the MMPA; provides additional permit criteria specific
to scientific research and enhancement only; and establishes clarified
administrative procedures for determining the releasability or non-
releasability of rehabilitated stranded marine mammals and their
disposition.
Scope
This notice responds to the comments and the final rule
incorporates a number of the changes recommended by commenters. In
addition, the rule implements certain statutory changes made to the
MMPA by the MMPA Amendments of 1994 (1994 Amendments) (Public Law 103-
238) enacted on April 30, 1994.
Photography and public display. Not included in this final rule are
the additional requirements specific to photography or public display
established by the 1994 Amendments. The 1994 Amendments included
significant changes regarding these activities. Accordingly, NMFS will
publish separate proposed rules for public comment for these areas.
ESA species. It is important to note that this final rule applies
to the issuance of special exception permits under both the MMPA and
ESA for species of marine mammals only. However, activities involving
species other than marine mammals that are protected under the ESA will
continue to require a permit issued under separate ESA regulations.
History
The 1993 proposed rule. The proposed rule proposed to amend and
consolidate permit regulations under the FSA, MMPA and the ESA to
facilitate ``one-stop shopping'' for the issuance of permits to take
``protected species'' (including species that are depleted under the
MMPA, and threatened and endangered under the ESA) for purposes of
scientific research, enhancement and public display. The proposed rule
was also designed to establish permit conditions capable of addressing
the various circumstances that had evolved over two decades of issuing
permits to take marine mammals. For example, although photography of
marine mammals in the wild is a common source of research and
educational information, the MMPA did not provide an exception for such
an activity. The 1993 proposed rule attempted to facilitate research
related photography under statutory provisions for bona fide scientific
research and enhancement activities, while at the same time guarding
against the use of research permits for commercial activities, which
had become a growing concern. However, comments received on the
proposed rule were critical of these provisions as being too
restrictive and bureaucratic. The new authority to issue permits for
educational and commercial photography provided by the 1994 Amendments
eliminates the need for addressing photography in much detail under
scientific research permits.
The proposed rule was originally open for public comment for a 60-
day period. A number of focused briefings on the proposed rule were
held for a variety of interested parties, including Congress, various
groups directly affected by the regulations, and the public. In
addition, NMFS held three regional public hearings: Silver Spring, MD
on December 3; Oakland, CA on December 6; and Chicago, IL on December
8. A combined total of 53 oral and written testimonies was submitted
for the record through the public hearing process. Due to the level of
interest expressed, NMFS extended the public comment period for an
additional 30 days, closing on January 28, 1994. In addition, a
transcribed question and answer session was held with certain
representatives of the public display industry at their request. A
total of 187 comments were received from individuals and organizations
representing the scientific research community, public display
industry, and conservation and animal protection interests. A
discussion of and response to those comments is detailed below.
The 1994 Amendments. The 1994 Amendments substantially revised the
MMPA. The statutory changes to the MMPA that impact this final rule
include: Statutorily defining the term harassment; providing a General
Authorization for bona fide research involving only Level B harassment;
waiving the public comment process for research permits to be issued
under emergency situations; eliminating the
[[Page 21927]]
statutory restriction against duplication of scientific research
projects; statutorily providing for the issuance of permits for
purposes of educational and commercial photography; and substantial
changes to the public display provisions of the Act, eliminating the
basis for many of the provisions that had been included in the proposed
rule.
Response to 1993 Comments and Discussion of 1994 Amendments. Many
commenters found the scope and organization of the proposed rule to be
confusing, arguing that they had difficulty determining which
regulations applied to their expressed interest.
Organization. In the proposed rule, each regulatory section was
subdivided into four categories: General (i.e., basic requirements
applicable to all permits), Public display, Scientific research, and
Enhancement. This required a reviewer to identify within each section,
both the basic permit requirements and the requirements particular to
their area of interest.
In response, these final regulations have been significantly
reorganized by removing non-statutory general conditions and reporting
requirements from regulatory text; listing requirements basic to all
permits in Secs. 216.33 through 216.40 (i.e., application procedures,
issuance criteria, permit restrictions, conditions, reporting
requirements, amendment procedures, and penalties); and providing the
additional requirements applicable to each special exception purpose in
separately identified sections (i.e., Sec. 216.41 contains the
additional requirements for Scientific Research). The table of contents
has been revised to include identification of sections reserved for
future photography and public display regulations.
A number of comments questioned why the proposed rule would amend
the Pribilof Islands and northern fur seal regulations issued under the
FSA (part 215). These regulations were included to reduce regulatory
burden and confusion by consolidating, under the MMPA, the requirements
contained under the FSA regarding the take, transportation,
importation, exportation or possession of fur seals or their parts for
educational, scientific or exhibition purposes. However, these changes
to part 215 were included in the interim final rule for the General
Authorization for bona fide scientific research (59 FR 50372 October 3,
1994) and are, therefore, not included with this final rule.
Disruption as a part of harassment. The proposed definition of
harass drew general criticism over its inclusion of the term
disruption. Commenters argued that, combined with the 1993 proposed
appendix of approach guidelines and reporting requirements, inclusion
of the term would create too much bureaucratic burden, over-reporting
of takes, and stifle scientific research. Commenters also expressed
concern that NMFS would not enforce the moratorium on taking against
someone unintentionally harassing a marine mammal. Members of the
public disrupting sea lions hauled-out at a public wharf were cited as
an example. Although commenters did not believe NMFS would institute
enforcement actions for such incidents of unintentional harassment, or
that it was the intent of Congress to focus on such incidents, they
were concerned that NMFS might impose a higher standard on researchers.
The 1994 Amendments defined harassment, and it is that definition that
is included in this rule (see Sec. 216.3 Definitions).
Approach guidelines (Appendix B). In view of the statutory changes
defining harassment, and in response to the comments, NMFS has
eliminated the Appendix B listing of approach guidelines and will
instead refer applicants to the appropriate regional office(s) to
receive any approach guidelines developed for the species of marine
mammals specific to that region.
Reporting. Comments were generally critical of the reporting
requirements regarding scientific research, arguing that the detail
requested on behavioral responses was excessive, and the amount of data
requested could compromise a researcher's ``stock-in-trade'' by forcing
public documentation of data and information before it could be
synthesized into published material.
In conjunction with the previous discussion, NMFS points out that a
recurring theme throughout the history of issuing permits for the
harassment of marine mammals has been the need for objective standards
for identifying stressful responses in marine mammals to activities and
closeness of approach which harass them. Such standards would prove
valuable in facilitating better management practices in the wild and
controlling against activities which may be detrimental to individual
marine mammals or their stocks. In an effort to maintain this aspect of
the reporting requirements while at the same time easing burdens, the
reporting requirements have been made more flexible by emphasizing
summaries of information and researcher discretion for determining
``noteworthy'' behavioral responses.
General take category. Many comments expressed support for a
general take category allowing for routine, non-invasive harassment for
purposes of scientific research, photography and whale watching.
The 1994 Amendments defined harassment and divided such takes into
two levels of impact: Level A harassment has the potential to injure,
and Level B harassment has only the potential to disturb (Sec. 216.3
Definitions). Bona fide scientific research projects which do not
exceed Level B harassment on species not listed under the ESA are
eligible for authorization under the new General Authorization
category. This authorization is a streamlined process without public
comment for low levels of harassment (Level B). A final rule based on
comments received on the interim final rule (59 FR 50372. October 3,
1994) implementing the General Authorization now in effect, will be
published separately in the Federal Register. The new permit category
to harass marine mammals in the wild for purposes of educational and
commercial photography also will allow only Level B harassment. A
proposed rule for photography permits will be published in the Federal
Register at a later date.
With regard to whale watching, there is no statutory exception
provided for observational cruise activities, however, such activities
can be conducted carefully without harassing marine mammals. Therefore,
NMFS will continue to inform prospective vessel operators of guidelines
to follow in an effort to avoid harassment.
Fees. A great deal of controversy was generated by NMFS' proposal
to increase the fees for processing permits. Comments ranged from
perceiving these fees as intentionally punitive against various
permitted activities, to detailed suggestions for tiering the fees
based on the type of permit, the level of staff review involved, and
the financial disposition of the applicant.
In view of the significant changes made to the public display
provisions of the statute, the nominal fees associated with scientific
research, and a complete absence of any likely consensus on the subject
of scientific research fees, NMFS has eliminated the proposed fee
structure. This issue may be reconsidered at some time in the future.
In the interim, no fee will be charged for these special exception
permits.
Ethics of captivity. Many comments discussed the ethics of
captivity, questioning the practice of holding marine mammals for
public display and suggesting that a ban be placed on all captivity.
Since the passage of the MMPA in 1972, Congress has recognized the
[[Page 21928]]
public display of marine mammals as an exception to the moratorium on
taking. Congress continued to recognize public display in the 1994
Amendments by continuing to provide for this activity in statute, and
increasing significantly the authority and discretion of the public
display industry over the marine mammals they hold.
Appendix A and C. As proposed in 1993, an Appendix A was provided
for listing the activities that would require a special exception
permit. In addition, an Appendix C provided the application information
anticipated for special exception permits. Due to the controversy
generated by the proposed scale of fees and the corresponding
activities listed in Appendix A, NMFS has eliminated Appendix A. NMFS
has also eliminated Appendix C and on request will provide application
instructions for each permit category.
Bona fide scientific research (Sec. 216.3). A number of comments
were critical of the proposed definition of bona fide scientific
research, arguing that it extended unlimited discretion to NMFS for
determining what was bona fide. The definition in the 1994 Amendments
closely parallels the definition in the proposed rule. In practice,
NMFS expects that the definition provides flexibility to an applicant
rather than unlimited discretion to the agency.
Custody (Sec. 216.3). In response to comments on the proposed
definition, and in consideration of the extensive changes to the public
display provisions by the 1994 Amendments, the definition of custody
has been simplified.
Humane (Sec. 216.3). Several comments were critical of the proposed
definition of humane, arguing that the definitions utilized by the
National Institutes of Health or American Veterinary Medicine
Association should be adopted instead. In response, NMFS points out
that the definition is essentially identical to the definition in the
statute.
Interactive program (Sec. 216.3). A number of comments expressed a
range of concerns over the definition of interactive program. Some
commenters stated that NMFS had no authority over these activities,
while others urged the elimination of therapeutic swim programs due to
lack of bona fide scientific research criteria. The 1994 Amendments
eliminated MMPA's jurisdiction over these public display captive care
and maintenance issues, eliminating the need to define interactive
program.
Public display (Sec. 216.3). A number of comments criticized the
proposed definition of public display for being at odds with the MMPA
and in violation of First Amendment rights by including the requirement
for educational and conservation programs as part of the definition. It
was suggested that the proposed definition parallel that contained in
statute.
There is no definition of public display contained in the statute.
Rather, prior to the 1994 Amendments, public display was referred to in
the context of issuing a permit for public display to an applicant
which offers a program for education or conservation purposes that,
based on professionally recognized standards of the public display
community, is acceptable to the Secretary of Commerce (Secretary). In
keeping with this reference, NMFS included in the proposed rule
reference of these programs as part of the definition.
The 1994 Amendments eliminated the requirement that public display
education and conservation programs be acceptable to the Secretary.
Public display education and conservation programs are now only subject
to self-regulation. Accordingly, reference to education and
conservation programs has been eliminated from the definition.
Initial review process (Sec. 216.33(c)). A number of comments were
critical of the initial review process, arguing that it provided NMFS
an opportunity to reject a permit application before receiving the
benefit of public comment. The purpose of the initial review is to
ensure that an application is appropriate, valid, and complete prior to
its publication for public review. Premature publication without
benefit of such determination could expose the applicant and agency to
unnecessary administrative burdens, delays, and public confusion.
Adequate EA/EIS information (Sec. 216.33(c)). Several comments
expressed confusion over the requirement that an applicant submit
sufficient information to enable NMFS to determine whether the proposed
activity will be categorically excluded from further environmental
documentation under the National Environmental Policy Act of 1969
(NEPA).
NEPA applies to federally approved, initiated, or funded activities
that impact the human environment. As such, it is necessary to retain
this requirement of applicants in order to comply with NEPA. In an
effort to provide regulatory ``one-stop-shopping'', NMFS is making
every effort to include up front all requirements and provisions
mandated by statute. Compliance with NEPA is a critical component of
that process. As in the past, NMFS will make every effort to assist an
applicant with NEPA compliance. Nevertheless, it is the responsibility
of the applicant to consider the potential impacts of its proposed
activity and provide the necessary information accordingly.
Marine Mammal Commission's (MMC) failure to comment
(Sec. 216.33(d)). Many comments were critical of the provision which
would regard the MMC's failure to comment on an application as a
recommendation to deny the permit. It was suggested that the failure to
comment by the MMC should be regarded as a recommendation to issue, and
that recommendations to deny a permit be available for review by the
applicant.
NMFS believes it would be inappropriate to default a no-comment to
a recommendation status. However, in the same vein, NMFS recognizes the
unfairness of defaulting to a denial status. In response, the
recommendation to deny has been replaced with ``no objection to
issuance'' (Sec. 216.33(d)(2)). With regard to comments received from
the MMC on permit applications, these are a matter of public record and
have always been available to anyone interested in reviewing them.
Duplication. Several comments criticized proposed language
controlling against unnecessary duplication of scientific research
projects, pointing out that duplication is an important aspect of
investigating the soundness of a hypothesis. This language was a direct
implementation of statutory language which specified scientific
research to ``not involve unnecessary duplication of research.''
The 1994 Amendments struck from the statute the language
restricting unnecessary duplication. Therefore, duplication is no
longer a regulatory matter except as it relates to whether a proposed
activity is bona fide scientific research, and the need to monitor
against the cumulative impact of activities with the potential to
exceed Level B harassment (Sec. 216.34(a)(4)).
Notarized copy (Sec. 216.35(j)). A number of comments were critical
over the requirement that an original or notarized copy of the special
exception permit be in the possession of the permit holder during the
time of the authorized special exception activity. This provision was
argued as unnecessary and too restrictive. In reconsidering the value
of this provision for purposes of enforcement against fraud, NMFS has
determined that an original or a copy of an original will satisfy the
intent behind this requirement and has revised the provision
accordingly.
Import and export (Sec. 216.37). A number of comments were critical
of the
[[Page 21929]]
provisions for regulating the import and export of marine mammal parts
for scientific research, claiming that they were too bureaucratic and
would stifle activities such as research and education. In addition,
there was concern expressed over lost research opportunities and
information due to the prohibition against importing marine mammal
parts which resulted from a lethal activity otherwise prohibited under
the Act (Sec. 216.41(c)(1)(v)).
As originally mandated in 1972, the restriction against the import
and export of marine mammal parts was designed to prevent the
development of commercial markets for marine mammal parts or products
derived therefrom. However, the circumstances of bona fide scientific
research involving import and export of marine mammal parts are varied,
making clarity in regulations difficult. In addition, previously only
the export of ESA listed species and parts was prohibited. The 1994
Amendments extended this prohibition to all marine mammals and marine
mammal parts, except for the export of living marine mammals for
purposes of public display.
In response, NMFS has made every effort to implement the intent of
the law without creating undue burden against scientific research
activities by ensuring that adequate documentation is provided for a
part's acquisition, location and possession. Flexibility has also been
provided at the sole discretion of the Office Director regarding
importation of parts for bona fide scientific research that may have
resulted from prohibited activities. For example, as a general rule it
is illegal to import parts that have been taken in violation of
domestic and foreign law. However, acknowledging the research value of
some of these parts, the Office Director may authorize their
importation for bona fide scientific research purposes.
Major and minor amendments (Sec. 216.39). Some confusion was
expressed over the need to maintain a distinction between major and
minor amendments, suggesting that all amendments be treated as major
amendments, thereby reducing the confusion over the two terms. In
response, NMFS believes that not all amendments should be required to
go through a public review process, and that only those amendments that
change elements of a permit which are statutorily highlighted as
fundamental permit terms and conditions should be subject to public
review (i.e., changes in: the number and species of marine mammals
affected; the manner in which they are taken; the location; and the
period of time the permit is valid). Other changes (i.e., minor
amendments) are most appropriately addressed on a case-by-case basis
between the permit holder and the Office Director without additional
opportunity for public comment. Consistent with this policy, comments
received, and in keeping with current administration of the program,
the process for a hearing on a minor amendment as outlined in the
proposed rule has been eliminated from this rule.
Lethal take as critically important (Sec. 216.41(b)(2)). Several
commenters criticized the use of the phrase ``critically important
research need'' as being too ambiguous a requirement for research
results involving lethal take. In response, NMFS notes that this
language is taken directly from the statute, which remains unchanged by
the 1994 Amendments.
Publication of research results (Sec. 216.41(c)(1)(ii)). A number
of commenters expressed concern over the requirement that research
results be published within a ``reasonable period of time'',
questioning what the agency would define as reasonable. In response, it
would be arbitrary and impractical to define in advance what would
constitute a reasonable period of time applicable to all circumstances.
As such, NMFS has retained this requirement as a necessary
characteristic of bona fide scientific research and would argue that by
not defining what is reasonable the regulations provide adequate
flexibility and deference to the researcher. In addition, Congress also
recognized publication and availability of research results as
necessary characteristics of bona fide scientific research by including
these parameters in the new statutory definition of bona fide research
(Sec. 216.3).
Personnel experience and direct supervision (Secs. 216.35(f)-(g)
and 216.41(c)). A number of comments expressed criticism of the
requirements that all personnel conducting permitted activities under
the authority of a scientific research permit must be directly
supportive of and necessary for the permitted research activity. It was
argued that this was a matter of internal personnel management and not
an issue of regulatory concern. In addition, several commenters argued
against the requirement that activities be conducted under the direct
supervision of the principal investigator or a co-investigator, finding
this to be too restrictive.
In response, permits are issued based in significant part on the
determination that the proposed activity is to be conducted by
qualified individuals capable of accomplishing the activity, in this
case bona fide scientific research. Much of that determination is
necessarily based on the qualifications of the applicant, principal
investigator (PI), co-investigator(s) and any supportive personnel
listed to conduct work under the terms of the permit. As such, NMFS has
retained this language and would note that discretion over personnel
matters is left entirely to the applicant.
Direct supervision over permitted activities by the PI or a co-
investigator has been retained by NMFS as a necessary requirement
(Sec. 216.41(c)(1)(iii)). In the past, inexperienced personnel have
conducted permitted activities involving the take, import or export of
marine mammals without direct supervision and left a project vulnerable
to criticism and litigation.
It is important and reasonable to presume that the PI or a co-
investigator will be directly involved in the activity authorized under
a permit. However, this requirement should in no way be construed as a
``draconian effort'' to force critical research personnel to supervise
the most routine of functions. Rather, it is intended to ensure the
integrity of a bona fide research permit and the activities it has
authorized. Qualified individuals may be designated in the permit as
co-investigators to conduct, or directly supervise the conduct of, the
taking, import and export activities authorized under a permit, but the
PI is ultimately responsible for all such activities. To ensure that
the roles and responsibilities of the PI and co-investigator(s) are
clearly understood, definitions for both of these terms have been added
(see Sec. 216.3).
Prohibiting public display of marine mammals held for research
(Sec. 216.41(c)(1)(vi)). A number of comments expressed concern over
restricting the public display of marine mammals held for scientific
research. Some comments identified specific instances in which research
facilities display their marine mammals as a means of educating the
public about the research and receiving donations for financial support
of research projects.
As scientific research and public display are recognized by statute
as two separate activities, NMFS has retained this restriction as a
necessary distinction between these activities. However, in response to
concerns over the public viewing of marine mammals involved with
research projects, the regulatory exceptions to this restriction
clearly provide adequate flexibility to
[[Page 21930]]
allow such activities, under appropriate conditions, to occur under a
scientific research permit.
Marketable products (Sec. 216.41(c)(1)(vii)). One of the more
contentious areas of comment was the prohibition against the commercial
sale of products derived from activities conducted under a scientific
research permit. Concern was primarily expressed by commercial entities
specializing in photographic coverage of research. In addition, many
criticized the proposed definition of marketable product as beyond the
jurisdiction of NMFS.
The proposed rule was in part driven by increasing reports and
concerns about abuse of the scientific research permit system for
commercial purposes. Although NMFS recognized the educational and
scientific value of photographic coverage of marine mammals in
conjunction with research, scientific research permits had, in some
instances, been exploited for commercial purposes.
The 1994 Amendments acknowledged the need to provide for
photographic activities in a controlled manner by permitting low levels
of harassment of marine mammals for the purposes of commercial and
educational photography. This new provision eliminated the need for
much of the restrictive language included in the proposed rule for
scientific research as well as for the need to define marketable
product.
Permit conditions and reporting requirements. The regulatory text
establishes permit-specific conditions and restrictions. By contrast,
non-statutory general permit conditions and reporting requirements have
been eliminated from the regulatory text. As a general rule, these
general conditions and reporting requirements tend to vary given the
nature of the permitted activity. Elimination of the permit conditions
and reporting requirements provides NMFS with greater flexibility,
allowing it to incorporate only those conditions and requirements that
are appropriate to the permit. Appropriate general conditions and
reporting requirements will be incorporated into the permit itself, and
must be adhered to along with all other terms and conditions.
Most of the general conditions and reporting requirements that may
be incorporated into a permit issued under this subpart, appear below.
Additionally, these conditions and requirements may also be obtained
from NMFS upon request (see ADDRESSES).
Conditions and Reporting Requirements for All Permits Conditions
1. The permit holder shall provide the Director (Regional Director)
written notice of the date, time, and port at least one week in advance
of any import or export, unless this notice is waived by the Regional
Director in writing in advance.
2. The permit holder shall not, in interstate or foreign commerce,
deliver, receive, carry, transport, ship, purchase, or sell, or attempt
any of the same, any threatened or endangered marine mammal species
acquired under this subpart except with the prior approval of the
Office Director and subject to any conditions the Office Director may
prescribe.
3. Upon request by the Office Director, the permit holder shall
allow any employee of NOAA or any other person designated by the Office
Director to inspect or observe the permit holder's records, facilities,
marine mammals, marine mammal parts, and activities, and shall provide
all additional information related to any inspection.
4. If activities authorized under a special exception permit have
adverse unforeseen effects on the ecosystem of which marine mammals are
a part, the permit holder must suspend permitted activities and notify
the Regional Director, and, if marine mammals are involved, the Office
Director, of the circumstances and any relevant observations and
recommendations. The permit holder shall not continue such permitted
activities until specifically authorized by the Regional Director or,
if marine mammals are involved, the Office Director.
5. The Permit holder must immediately cease all permitted
activities if so required by the Office Director on the basis of new
information that demonstrates that the permitted activities may have an
adverse effect on individual marine mammals, on the species or stock,
or on the marine ecosystem, that was not anticipated at the time of
permit issuance. Permitted activities may be resumed by the permit
holder only upon specific authorization by the Office Director, and
subject to any terms or conditions that the Office Director determines
necessary, consistent with the provisions of 216.35.
6. The permit holder shall participate in a cooperative endangered
and threatened marine mammal breeding program if requested by the
Office Director.
7. When animal-specific information for live import or capture is
not available at the time of permit issuance, the permit holder must
request authorization by the Office Director prior to importing or
initiating a capture activity for long-term or permanent captive
maintenance (i.e., other than short-term capture and release) of a
living marine mammal. The permit holder must:
i. Request authorization to import or capture at least 30 days
prior to the proposed importation or capture date;
ii. Provide the proposed dates and, for imports, country of origin,
port of entry, description of the marine mammals to be imported, and,
for captures, the location of the capture and associated taking;
iii. Identify the proposed method, including, but not limited to, a
detailed description of the containers/devices to be used and any
special care required, modes (i.e., aircraft, truck, other), duration
(including any transfer points), and date of transport, and the
attending veterinarian, or authorized support personnel of the permit
holder knowledgeable in the area of marine mammal care for the species
concerned, who will accompany the marine mammal; and
iv. Provide a license and or registration issued by the Animal and
Plant Health Inspection Service; a certification, to the satisfaction
of the Office Director, that all applicable standards under the Animal
Welfare Act will be complied with, and that any violations of those
standards have been resolved and any required corrective actions taken,
or will be within a period specified by the Office Director; and a
certification from the responsible veterinarian that the transport will
be conducted in compliance with the applicable standards of the Animal
Welfare Act.
Reporting
1. Annual reports. All permit holders shall file written annual
reports with the Office Director. Annual reports shall provide
information requested by the Office Director, and shall be filed on the
date set forth in the permit. At the discretion of the Office Director,
the reporting deadline may coincide with the end of the permit holder's
fiscal year or research season.
2. Special reports. Special reports include but are not limited to:
a. Live captures. Where the permit authorizes a capture from the
wild, the permit holder shall submit a written live capture report to
the Office Director within 30 days of capture. The report shall set
forth the time and specific location (i.e., latitude/longitude) of the
capture, the number of marine mammals chased or detained incidental to
[[Page 21931]]
capture, and any deaths, injuries or complications that arose in
connection with capture. For each marine mammal listed, the report must
set forth the animal's size, age, sex, and reproductive condition.
b. Lethal take. Where a lethal take is authorized under the permit,
the permit holder shall submit a written report to the Office Director
within 30 days of the authorized lethal take. Where an actual or
presumed lethal take occurs inadvertent or incidental to permitted
activities, the permit holder shall notify the Office Director within
12 hours of the lethal take, or within 12 hours of return to port if
the taking occurred at sea. This lethal take report or notification, as
applicable, shall set forth the date, time, location, number, and, to
the extent possible, age/size, sex, and reproductive condition of each
animal killed. For inadvertent or incidental mortalities, notification
shall also include the circumstances accompanying the incident and all
actions taken to reduce the potential for future occurrences. A
necropsy must be conducted and a report submitted if required by the
Office Director.
c. Initial importation of marine mammal parts. Within 30 days of
the initial importation of any marine mammal part, the permit holder
shall submit a written report to the Office Director. The report shall
include a description of the part and the unique number assigned to the
part.
d. Transfer, export or re-importation of marine mammal parts. The
permit holder shall provide written notification to the Regional
Director within 30 days after any transfer, export, or re-import of a
marine mammal part. Notification shall include: A description of the
part and unique number; the person to whom the part was transferred,
exported or reimported and, if applicable, the recipient's permit
number; the purpose of the transfer, export or reimport; and, for
transfers, certification that the recipient has agreed to comply with
the requirements of Sec. 216.37(a) for subsequent transfers.
e. Other. If the permit holder observes an unexpected event that
may pose a significant adverse affect upon the health or welfare of a
living marine mammal species subject to the permit, or the marine
ecosystem of which they are a part, the permit holder shall submit a
brief written report to the Office Director describing the
circumstances concerned and all relevant observations or
recommendations.
Additional Scientific Research and Enhancement Conditions and Reporting
Requirements
Conditions
In addition to those conditions detailed above, scientific research
and enhancement permits are subject to the following conditions:
1. Unless approved by the Office Director, the PI and co-
investigators identified in the permit shall not be changed. A request
to change a co-investigator listed under the permit must be submitted
by the permit holder and include a description of the activity to be
conducted by the proposed co-investigator, the manner in which such
activity is a part of the permitted activity, and information regarding
the proposed co-investigator equivalent to that required for the PI in
an initial application.
2. The transfer and transport of marine mammals held for purposes
of scientific research or enhancement must be authorized by NMFS.
Reporting
In addition to the reporting requirements detailed above,
scientific research and enhancement permits are subject to the
following reporting requirements:
1. Annual reports. For scientific research and enhancement permits,
the annual report also shall include the following information:
a. To the extent practicable, for each marine mammal taken,
imported, exported, or otherwise affected pursuant to permitted
activities: The species, age, size, sex, and reproductive condition of
the animal; the date, location, and manner of taking, import, or
export; and for tagged animals, the dates each animal was tagged and
tracked;
b. For each marine mammal part taken, imported, exported or
otherwise affected pursuant to permitted activities, a description of
the part and its assigned identification number;
c. The personnel and vessels involved in the conduct of the
permitted research or enhancement and their respective functions;
d. For each marine mammal placed on public display: The name and
location of the display facility; and the number of days the animal was
displayed; and
e. A summary of all research and enhancement activities conducted
during the past year.
2. Final reports. Scientific research and enhancement permit
holders shall submit a final report to the Office Director within 180
days of the last annual report. The final report shall include:
a. A summary of all research or enhancement objectives, hypotheses,
and testing (including methodology).
b. A summary of results and the manner in which such results relate
to the research or enhancement objectives;
c. Where the authorized take, import, export or other activity
involves a species or stock designated, or proposed to be designated,
as depleted, endangered or threatened, an assessment of whether and how
the scientific research or enhancement activity contributed to the
achievement of any recovery objectives established for the species or
stock.
d. For scientific research: An indication of where and when the
research findings will be published or otherwise made available to the
public or scientific community;
e. For enhancement: A description of the manner in which the
enhancement program contributed significantly to maintaining or
increasing distribution or abundance, enhanced the health or welfare of
the species or stock, or was necessary to ensure the survival or
recovery of the affected species or stock in the wild; and an
assessment of the need for additional enhancement, along with specific
recommendations;
f. Where marine mammals designated as depleted, endangered, or
threatened are held captive under an enhancement permit, the report
shall describe the manner in which the captive maintenance has
contributed directly to the survival or recovery of the species or
stock; and
g. A description of the disposition of any marine mammal parts,
including an identification of the part as required in
Sec. 216.37(a)(4) and the manner of disposition.
3. Special reports. Information on marine mammals held captive must
be submitted for purposes of the Marine Mammal Inventory. Such
information includes animal-specific data when animals are initially
obtained, and subsequent updates to be submitted for any changes in the
captive holding status (i.e., animal identification, sex, estimated or
actual birth date, date of acquisition or disposition by the permit
holder, source of acquisition including location of the take from the
wild if applicable, name of recipient if animal is transferred,
notation if animal was acquired as the result of a stranding, date and
cause of death, and prior notification of any sale, purchase, export,
or transport). At the request of the Office Director, a necropsy report
shall be submitted following report of a death.
[[Page 21932]]
Classification
NMFS prepared an Environmental Assessment (EA) for the 1993
proposed rule and concluded that this final rule will not significantly
affect the human environment. Therefore, preparation of an
Environmental Impact Statement on this action is not required by
section 102(2) of NEPA or its implementing regulations. Copies of the
EA remain available on request (see ADDRESSES). NEPA requirements as
they pertain to individual permits that may be issued under these
proposed regulations will be addressed on a case-by-case basis.
This final rule has been determined to be not significant for
purposes of E.O. 12866 and is consistent with the President's
Regulatory Reform Initiative to reduce regulatory burden on the public.
This rule clarifies current permitting procedures that were found not
significant during the proposed stage.
In accordance with the Regulatory Flexibility Act (5 U.S.C. 601 et
seq.), an Initial Regulatory Flexibility Analysis (IRFA) was prepared
and NMFS solicited comments in the proposed rule on the economic
impacts to small business entities (available upon request (see
ADDRESSES). The IRFA determined that the projected economic impact of
the proposed revisions on affected small business entities would be
primarily administrative, a combination of paperwork burden costs,
permit fees (some of which would be greater than the fees under current
permit regulations), and the proposed requirement of a surety bond for
the care, maintenance, and disposition of captive marine mammals. NMFS
believed that it was unlikely that significant economic impact would
result from the requirements of the proposed regulations beyond the
economic impacts associated with paperwork requirements, associated
permit administration, and similar requirements imposed under existing
regulations. However, sufficient financial and economic data was not
available for NMFS to conduct an in-depth economic analysis,
particularly in regards to the permit fees and surety bond requirement.
NMFS sought comments on the anticipated economic effects during the
public comment period. The comments submitted in response to this
request addressed public display activities exclusively, which have
been eliminated from this rule.
Due to statutory changes made by Congress in the 1994 Amendments,
significant portions of the proposed rule have been eliminated,
including the collection of permit fees and the proposed requirement
for surety bonds. In addition, activities involving the issuance of
permits for purposes of public display were significantly reduced by
the 1994 Amendments, further reducing any economic impact associated
with paperwork costs contained in this final rule.
As a result, the impact of this final rule on small business
entities is primarily in the form of paperwork burdens. Paperwork
requirements include permit applications and reports, which may be
annual, special, and/or final. The projected economic impact on small
business entities as a result of the paperwork requirements was
estimated in the IRFA as a total of $123,260 annually for a universe of
462 entities, or about $267.00 per entity, an amount not significant
for purposes of the Regulatory Flexibility Act. Accordingly, the
Assistant General Counsel for Legislation and Regulation of the
Department of Commerce certified to the Chief Counsel for Advocacy of
the Small Business Administration that this rule would not have a
significant economic impact on a substantial number of small entities.
As a result, a Final Regulatory Flexibility Analysis was not prepared.
This rule contains collections of information subject to the
Paperwork Reduction Act. The collection of this information has been
approved by the Office of Management and Budget for special exception
permits, OMB Control Number 0648-0084. The public burden for collection
of this information is estimated to average 29 hours per response for
permit applications and major amendment requests, 3 hours for minor
amendments and authorization requests, and an average of 8 hours per
response for various reporting requirements that range from 12 hours
for scientific research annual reports to 2 hours for necropsies.
Notwithstanding any other provision of law, no person is required
to respond to nor shall a person be subject to a penalty for failure to
comply with a collection of information subject to the requirements of
the Paperwork Reduction Act unless that collection of information
displays a currently valid OMB Control Number.
NMFS has determined that these final regulations do not directly
affect the coastal zone of any state with an approved coastal zone
management program.
Under NOAA Administrative Order 205-11, 7.01, dated December 17,
1990, the Under Secretary for Oceans and Atmosphere has delegated to
the Assistant Administrator for Fisheries, NOAA, the authority to sign
material for publication in the Federal Register.
List of Subjects
15 CFR Part 902
Reporting and recordkeeping requirements.
50 CFR Part 216
Administrative practice and procedure, Exports, Imports, Indians,
Marine mammals, Penalties, Reporting and recordkeeping requirements,
Transportation.
50 CFR Part 222
Administrative practice and procedure, Endangered and threatened
species, Exports, Imports, Reporting and recordkeeping requirements,
Transportation.
Dated: May 6, 1996.
Gary Matlock,
Program Management Officer, National Marine Fisheries Service.
For reasons set out in the preamble, 15 CFR chapter IX and, under
the authority of 16 U.S.C. 1361 et seq., 50 CFR chapter II are amended
as follows:
15 CFR CHAPTER IX
PART 902--NOAA INFORMATION COLLECTION REQUIREMENTS UNDER THE
PAPERWORK REDUCTION ACT: OMB CONTROL NUMBERS
1. The authority citation for part 902 continues to read as
follows:
Authority: 44 U.S.C. 3501 et seq.
2. In Sec. 902.1, paragraph (b) the table is amended by removing in
the left column under 50 CFR, the entries ``216.24(d)'', ``216.31'',
and ``222.23'', and in the right column, in corresponding positions,
the control numbers; and by adding, in numerical order, the following
entries to read as follows:
Sec. 902.1 OMB control numbers assigned pursuant to the Paperwork
Reduction Act.
* * * * *
(b) * * *
------------------------------------------------------------------------
CFR part or section where the
information collection requirement is Current OMB control number (all
located numbers begin with 0648-)
------------------------------------------------------------------------
* * * * *
50 CFR:
* * * * *
216.24(d)............................ -0099 and -0217
* * * * *
216.27............................... -0084
216.37............................... -0084
[[Page 21933]]
216.38............................... -0084
216.39............................... -0084
216.41............................... -0084
* * * * *
------------------------------------------------------------------------
50 CFR CHAPTER II
PART 216--REGULATIONS GOVERNING THE TAKING AND IMPORTING OF MARINE
MAMMALS
3. The authority citation for part 216 continues to read as
follows:
Authority: 16 U.S.C. 1361 et seq., unless otherwise noted.
4. In Sec. 216.3, definitions for ``Co-investigator'', ``Custody'',
``Facility'', ``Humane'', ``Intrusive research'', ``Principal
investigator'', ``Public display'', and ``Rehabilitation'' are added in
alphabetical order, and the definition of ``Soft part'' is revised to
read as follows:
Sec. 216.3 Definitions.
* * * * *
Co-investigator means the on-site representative of a principal
investigator.
* * * * *
Custody means holding a live marine mammal pursuant to the
conditional authority granted under the MMPA, and the responsibility
therein for captive maintenance of the marine mammal.
* * * * *
Facility means, in the context specific to captive marine mammals,:
(1) One or more permanent primary enclosures used to hold marine
mammals captive (i.e., pools, lagoons) and associated infrastructure
(i.e., equipment and supplies necessary for the care and maintenance of
marine mammals) where these enclosures are either located within the
boundaries of a single contiguous parcel of land and water, or are
grouped together within the same general area within which enclosure-
to-enclosure transport is expected to be completed in less than one
hour; or
(2) A traveling display/exhibit, where the enclosure(s) and
associated infrastructure is transported together with the marine
mammals.
* * * * *
Humane means the method of taking, import, export, or other
activity which involves the least possible degree of pain and suffering
practicable to the animal involved.
* * * * *
Intrusive research means a procedure conducted for bona fide
scientific research involving: A break in or cutting of the skin or
equivalent, insertion of an instrument or material into an orifice,
introduction of a substance or object into the animal's immediate
environment that is likely either to be ingested or to contact and
directly affect animal tissues (i.e., chemical substances), or a
stimulus directed at animals that may involve a risk to health or
welfare or that may have an impact on normal function or behavior
(i.e., audio broadcasts directed at animals that may affect behavior).
For captive animals, this definition does not include:
(1) A procedure conducted by the professional staff of the holding
facility or an attending veterinarian for purposes of animal husbandry,
care, maintenance, or treatment, or a routine medical procedure that,
in the reasonable judgment of the attending veterinarian, would not
constitute a risk to the health or welfare of the captive animal; or
(2) A procedure involving either the introduction of a substance or
object (i.e., as described in this definition) or a stimulus directed
at animals that, in the reasonable judgment of the attending
veterinarian, would not involve a risk to the health or welfare of the
captive animal.
* * * * *
Principal investigator means the individual primarily responsible
for the taking, importation, export, and any related activities
conducted under a permit issued for scientific research or enhancement
purposes.
Public display means an activity that provides opportunities for
the public to view living marine mammals at a facility holding marine
mammals captive.
* * * * *
Rehabilitation means treatment of beached and stranded marine
mammals taken under section 109(h)(1) of the MMPA or imported under
section 109(h)(2) of the MMPA, with the intent of restoring the marine
mammal's health and, if necessary, behavioral patterns.
* * * * *
Soft part means any marine mammal part that is not a hard part.
Soft parts do not include urine or fecal material.
* * * * *
5. In Sec. 216.13, the section heading is revised and paragraph (d)
is added to read as follows:
Sec. 216.13 Prohibited uses, possession, transportation, sales, and
permits.
* * * * *
(d) Any person to violate any term, condition, or restriction of
any permit issued by the Secretary.
6. In Sec. 216.26, the section heading and paragraphs (b), (c), and
(d) are revised and the introductory text to the section and paragraph
(e) are added to read as follows:
Sec. 216.26 Collection of certain marine mammal parts without prior
authorization.
Notwithstanding any other provision of this subpart:
* * * * *
(b) Notwithstanding the provisions of subpart D, soft parts that
are sloughed, excreted, or discharged naturally by a living marine
mammal in the wild may be collected or imported for bona fide
scientific research and enhancement, provided that collection does not
involve the taking of a living marine mammal in the wild.
(c) Any marine mammal part collected under paragraph (a) of this
section or any marine mammal part collected and imported under
paragraph (b) of this section must be registered and identified, and
may be transferred or otherwise possessed, in accordance with
Sec. 216.22(c). In registering a marine mammal part collected or
imported under paragraph (b) of this section, the person who collected
or imported the part must also state the scientific research or
enhancement purpose for which the part was collected or imported.
(d) No person may purchase, sell or trade for commercial purposes
any marine mammal part collected or imported under this section.
(e) The export of parts collected without prior authorization under
paragraph (b) of this section may occur if consistent with the
provisions at Sec. 216.37(d) under subpart D.
7. In subpart C, Sec. 216.27 is added to read as follows:
Sec. 216.27 Release, non-releasability, and disposition under special
exception permits for rehabilitated marine mammals.
(a) Release requirements. (1) Any marine mammal held for
rehabilitation must be released within six months of capture or import
unless the attending veterinarian determines that:
(i) The marine mammal might adversely affect marine mammals in the
wild;
(ii) Release of the marine mammal to the wild will not likely be
successful given the physical condition and behavior of the marine
mammal; or
(iii) More time is needed to determine whether the release of the
marine mammal to the wild will likely be successful. Releasability must
be
[[Page 21934]]
reevaluated at intervals of no less than six months until 24 months
from capture or import, at which time there will be a rebuttable
presumption that release into the wild is not feasible.
(2) The custodian of the rehabilitated marine mammal shall provide
written notification prior to any release into the wild.
(i) Notification shall be provided to:
(A) The NMFS Regional Director at least 15 days in advance of
releasing any beached or stranded marine mammal, unless advance notice
is waived in writing by the Regional Director; or
(B) The Office Director at least 30 days in advance of releasing
any imported marine mammal.
(ii) Notification shall include the following:
(A) A description of the marine mammal, including its physical
condition and estimated age;
(B) The date and location of release; and
(C) The method and duration of transport prior to release.
(3) The Regional Director, or the Office Director as appropriate,
may:
(i) Require additional information prior to any release;
(ii) Change the date or location of release, or the method or
duration of transport prior to release;
(iii) Impose additional conditions to improve the likelihood of
success or to monitor the success of the release; or
(iv) Require other disposition of the marine mammal.
(4) All marine mammals must be released near wild populations of
the same species, and stock if known, unless a waiver is granted by the
Regional Director or the Office Director.
(5) All marine mammals released must be tagged or marked in a
manner acceptable to the Regional Director or the Office Director. The
tag number or description of the marking must be reported to the
Regional Director or Office Director following release.
(b) Non-releasability and postponed determinations. (1) The
attending veterinarian shall provide the Regional Director or Office
Director with a written report setting forth the basis of any
determination under paragraphs (a)(1)(i) through (iii) of this section.
(2) Upon receipt of a report under paragraph (b)(1) of this
section, the Regional Director or Office Director, in their sole
discretion, may:
(i) Order the release of the marine mammal;
(ii) Order continued rehabilitation for an additional 6 months; or
(iii) Order other disposition as authorized.
(3) No later than 30 days after a marine mammal is determined
unreleasable in accordance with paragraphs (a)(1)(i) through (iii) of
this section, the person with authorized custody must:
(i) Request authorization to retain or transfer custody of the
marine mammal in accordance with paragraph (c) of this section, or;
(ii) Humanely euthanize the marine mammal or arrange any other
disposition of the marine mammal authorized by the Regional Director or
Office Director.
(4) Notwithstanding any of the provisions of this section, the
Office Director may require use of a rehabilitated marine mammal for
any activity authorized under subpart D in lieu of animals taken from
the wild.
(5) Any rehabilitated beached or stranded marine mammal placed on
public display following a non-releasability determination under
paragraph (a)(1) of this section and pending disposition under
paragraph (c) of this section, or any marine mammal imported for
medical treatment otherwise unavailable and placed on public display
pending disposition after such medical treatment is concluded, must be
held in captive maintenance consistent with all requirements for public
display.
(c) Disposition for a special exception purpose. (1) Upon receipt
of an authorization request made under paragraph (b)(3)(i) of this
section, or release notification under (a)(2), the Office Director may
authorize the retention or transfer of custody of the marine mammal for
a special exception purpose authorized under subpart D.
(2) The Office Director will first consider requests from a person
authorized to hold the marine mammal for rehabilitation. The Office
Director may authorize such person to retain or transfer custody of the
marine mammal for scientific research, enhancement, or public display
purposes.
(3) The Office Director may authorize retention or transfer of
custody of the marine mammal only if:
(i) Documentation has been submitted to the Office Director that
the person retaining the subject animal or the person receiving custody
of the subject animal by transfer, hereinafter referred to as the
recipient, complies with public display requirements of 16 U.S.C.
1374(c)(2)(A) or, for purposes of scientific research and enhancement,
holds an applicable permit, or an application for such a special
exception permit under Sec. 216.33 or a request for a major amendment
under Sec. 216.39 has been submitted to the Office Director and has
been found complete;
(ii) The recipient agrees to hold the marine mammal in conformance
with all applicable requirements and standards; and
(iii) The recipient acknowledges that the marine mammal is subject
to seizure by the Office Director:
(A) If, at any time pending issuance of the major amendment or
permit, the Office Director determines that seizure is necessary in the
interest of the health or welfare of the marine mammal;
(B) If the major amendment or permit is denied; or
(C) If the recipient is issued a notice of violation and
assessment, or is subject to permit sanctions, in accordance with 15
CFR part 904.
(4) There shall be no remuneration associated with any transfer,
provided that, the transferee may reimburse the transferor for any and
all costs associated with the rehabilitation and transport of the
marine mammal.
(5) Marine mammals undergoing rehabilitation or pending disposition
under this section shall not be subject to public display, unless such
activities are specifically authorized by the Regional Director or the
Office Director, and conducted consistent with the requirements
applicable to public display. Such marine mammals shall not be trained
for performance or be included in any aspect of a program involving
interaction with the public; and
(6) Marine mammals undergoing rehabilitation shall not be subject
to intrusive research, unless such activities are specifically
authorized by the Office Director in consultation with the Marine
Mammal Commission and its Committee of Scientific Advisors on Marine
Mammals, and are conducted pursuant to a scientific research permit.
(d) Reporting. In addition to the report required under
Sec. 216.22(b), the person authorized to hold marine mammals for
rehabilitation must submit reports to the Regional Director or Office
Director regarding release or other disposition. These reports must be
provided in the form and frequency specified by the Regional Director
or Office Director.
8. In subpart D, Secs. 216.31 through 216.34 are revised;
Secs. 216.35 through 216.44 are added; and Sec. 216.30 and Secs. 216.46
through 216.49 are added and reserved to read as follows:
Subpart D--Special Exception Permits
216.30 [Reserved]
216.31 Definitions.
216.32 Scope.
216.33 Permit application submission, review, and decision
procedures.
216.34 Issuance criteria.
216.35 Permit restrictions.
216.36 Permit conditions.
[[Page 21935]]
216.37 Marine mammal parts.
216.38 Reporting.
216.39 Permit amendments.
216.40 Penalties and permit sanctions.
216.41 Permits for scientific research and enhancement.
216.42 Photography. [Reserved]
216.43 Public display. [Reserved]
216.44 Applicability/transition.
216.45 General authorization.
216.46-216.49 [Reserved]
Sec. 216.30 [Reserved]
Sec. 216.31 Definitions.
For the purpose of this subpart, the definitions set forth in 50
CFR part 217 shall apply to all threatened and endangered marine
mammals, unless a more restrictive definition exists under the MMPA or
part 216.
Sec. 216.32 Scope.
The regulations of this subpart apply to:
(a) All marine mammals and marine mammal parts taken or born in
captivity after December 20, 1972; and
(b) All marine mammals and marine mammal parts that are listed as
threatened or endangered under the ESA.
Sec. 216.33 Permit application submission, review, and decision
procedures.
(a) Application submission. Persons seeking a special exemption
permit under this subpart must submit an application to the Office
Director. The application must be signed by the applicant, and provide
in a properly formatted manner all information necessary to process the
application. Written instructions addressing information requirements
and formatting may be obtained from the Office Director upon request.
(b) Applications to export living marine mammals. For applicants
seeking a special exception permit to export living marine mammals, the
application must:
(1) Be submitted through the Convention on International Trade in
Endangered Fauna and Flora management authority of the foreign
government or, if different, the appropriate agency or agencies of the
foreign government that exercises oversight over marine mammals.
(2) Include a certification from the foreign government that:
(i) The information set forth in the application is accurate;
(ii) The laws and regulations of the foreign governmentinvolved
allow enforcement of the terms and conditions of the permit, and that
the foreign government will enforce all terms and conditions; and
(iii) The foreign government involved will afford comity to any
permit amendment, modification, suspension or revocation decision.
(c) Initial review. (1) NMFS will notify the applicant of receipt
of the application.
(2) During the initial review, the Office Director will determine:
(i) Whether the application is complete.
(ii) Whether the proposed activity is for purposes authorized under
this subpart.
(iii) If the proposed activity is for enhancement purposes, whether
the species or stock identified in the application is in need of
enhancement for its survival or recovery and whether the proposed
activity will likely succeed in its objectives.
(iv) Whether the activities proposed are to be conducted consistent
with the permit restrictions and permit specific conditions as
described in Sec. 216.35 and Sec. 216.36(a).
(v) Whether sufficient information is included regarding the
environmental impact of the proposed activity to enable the Office
Director:
(A) To make an initial determination under the National
Environmental Policy Act (NEPA) as to whether the proposed activity is
categorically excluded from preparation of further environmental
documentation, or whether the preparation of an environmental
assessment (EA) or environmental impact statement (EIS) is appropriate
or necessary; and
(B) To prepare an EA or EIS if an initial determination is made by
the Office Director that the activity proposed is not categorically
excluded from such requirements.
(3) The Office Director may consult with the Marine Mammal
Commission (Commission) and its Committee of Scientific Advisors on
Marine Mammals (Committee) in making these initial, and any subsequent,
determinations.
(4) Incomplete applications will be returned with explanation. If
the applicant fails to resubmit a complete application or correct the
identified deficiencies within 60 days, the application will be deemed
withdrawn. Applications that propose activities inconsistent with this
subpart will be returned with explanation, and will not be considered
further.
(d) Notice of receipt and application review. (1) Upon receipt of a
valid, complete application, and the preparation of any NEPA
documentation that has been determined initially to be required, the
Office Director will publish a notice of receipt in the Federal
Register. The notice will:
(i) Summarize the application, including:
(A) The purpose of the request;
(B) The species and number of marine mammals;
(C) The type and manner of special exception activity proposed;
(D) The location(s) in which the marine mammals will be taken, from
which they will be imported, or to which they will be exported; and
(E) The requested period of the permit.
(ii) List where the application is available for review.
(iii) Invite interested parties to submit written comments
concerning the application within 30 days of the date of the notice.
(iv) Include a NEPA statement that an initial determination has
been made that the activity proposed is categorically excluded from the
requirement to prepare an EA or EIS, that an EA was prepared resulting
in a finding of no significant impact, or that a final EIS has been
prepared and is available for review.
(2) The Office Director will forward a copy of the complete
application to the Commission for comment. If no comments are received
within 45 days (or such longer time as the Office Director may
establish) the Office Director will consider the Commission to have no
objection to issuing a permit.
(3) The Office Director may consult with any other person,
institution, or agency concerning the application.
(4) Within 30 days of publication of the notice of receipt in the
Federal Register, any interested party may submit written comments or
may request a public hearing on the application.
(5) If the Office Director deems it advisable, the Office Director
may hold a public hearing within 60 days of publication of the notice
of receipt in the Federal Register. Notice of the date, time, and place
of the public hearing will be published in the Federal Register not
less than 15 days in advance of the public hearing. Any interested
person may appear in person or through representatives and may submit
any relevant material, data, views, or comments. A summary record of
the hearing will be kept.
(6) The Office Director may extend the period during which any
interested party may submit written comments. Notice of the extension
must be published in the Federal Register within 60 days of publication
of the notice of receipt in the Federal Register.
[[Page 21936]]
(7) If, after publishing a notice of receipt, the Office Director
determines on the basis of new information that an EA or EIS must be
prepared, the Office Director must deny the permit unless an EA is
prepared with a finding of no significant impact. If a permit is denied
under these circumstances the application may be resubmitted with
information sufficient to prepare an EA or EIS, and will be processed
as a new application.
(e) Issuance or denial procedures. (1) Within 30 days of the close
of the public hearing or, if no public hearing is held, within 30 days
of the close of the public comment period, the Office Director will
issue or deny a special exception permit.
(2) The decision to issue or deny a permit will be based upon:
(i) All relevant issuance criteria set forth at Sec. 216.34;
(ii) All purpose-specific issuance criteria as appropriate set
forth at Sec. 216.41, Sec. 216.42, and Sec. 216.43;
(iii) All comments received or views solicited on the permit
application; and
(iv) Any other information or data that the Office Director deems
relevant.
(3) If the permit is issued, upon receipt, the holder must date an
FR Doc. 96-11776 Marine Mammal Special Exception Permits to Take, Import and Export Marine Mammals; Update of Office of Management and Budget (OMB) Approval Numbers
d
sign the permit, and return a copy of the original to the Office
Director. The permit shall be effective upon the permit holder's
signing of the permit. In signing the permit, the holder:
(i) Agrees to abide by all terms and conditions set forth in the
permit, and all restrictions and relevant regulations under this
subpart; and
(ii) Acknowledges that the authority to conduct certain activities
specified in the permit is conditional and subject to authorization by
the Office Director.
(4) Notice of the decision of the Office Director shall be
published in the Federal Register within 10 days after the date of
permit issuance or denial and shall indicate where copies of the
permit, if issued, may be reviewed or obtained. If the permit issued
involves marine mammals listed as endangered or threatened under the
ESA, the notice shall include a finding by the Office Director that the
permit:
(i) Was applied for in good faith;
(ii) If exercised, will not operate to the disadvantage of such
endangered or threatened species; and
(iii) Is consistent with the purposes and policy set forth in
section 2 of the ESA.
(5) If the permit is denied, the Office Director shall provide the
applicant with an explanation for the denial.
(6) Under the MMPA, the Office Director may issue a permit for
scientific research before the end of the public comment period if
delaying issuance could result in injury to a species, stock, or
individual, or in loss of unique research opportunities. The Office
Director also may waive the 30-day comment period required under the
ESA in an emergency situation where the health or life of an endangered
or threatened marine mammal is threatened and no reasonable alternative
is available. If a permit is issued under these circumstances, notice
of such issuance before the end of the comment period shall be
published in the Federal Register within 10 days of issuance.
(7) The applicant or any party opposed to a permit may seek
judicial review of the terms and conditions of such permit or of a
decision to deny such permit. Review may be obtained by filing a
petition for review with the appropriate U.S. District Court as
provided for by law.
Sec. 216.34 Issuance criteria.
(a) For the Office Director to issue any permit under this subpart,
the applicant must demonstrate that:
(1) The proposed activity is humane and does not present any
unnecessary risks to the health and welfare of marine mammals;
(2) The proposed activity is consistent with all restrictions set
forth at Sec. 216.35 and any purpose-specific restrictions as
appropriate set forth at Sec. 216.41, Sec. 216.42, and Sec. 216.43;
(3) The proposed activity, if it involves endangered or threatened
marine mammals, will be conducted consistent with the purposes and
policies set forth in section 2 of the ESA;
(4) The proposed activity by itself or in combination with other
activities, will not likely have a significant adverse impact on the
species or stock;
(5) Whether the applicant's expertise, facilities, and resources
are adequate to accomplish successfully the objectives and activities
stated in the application;
(6) If a live animal will be held captive or transported, the
applicant's qualifications, facilities, and resources are adequate for
the proper care and maintenance of the marine mammal; and
(7) Any requested import or export will not likely result in the
taking of marine mammals or marine mammal parts beyond those authorized
by the permit.
(b) The opinions or views of scientists or other persons or
organizations knowledgeable of the marine mammals that are the subject
of the application or of other matters germane to the application will
be considered.
Sec. 216.35 Permit restrictions.
The following restrictions shall apply to all permits issued under
this subpart:
(a) The taking, importation, export, or other permitted activity
involving marine mammals and marine mammal parts shall comply with the
regulations of this subpart.
(b) The maximum period of any special exception permit issued, or
any major amendment granted, is five years from the effective date of
the permit or major amendment. In accordance with the provisions of
Sec. 216.39, the period of a permit may be extended by a minor
amendment up to 12 months beyond that established in the original
permit.
(c) Except as provided for in Sec. 216.41(c)(1)(v), marine mammals
or marine mammal parts imported under the authority of a permit must be
taken or imported in a humane manner, and in compliance with the Acts
and any applicable foreign law. Importation of marine mammals and
marine mammal parts is subject to the provisions of 50 CFR part 14.
(d) The permit holder shall not take from the wild any marine
mammal which at the time of taking is either unweaned or less than
eight months old, or is a part of a mother-calf/pup pair, unless such
take is specifically authorized in the conditions of the special
exception permit. Additionally, the permit holder shall not import any
marine mammal that is pregnant or lactating at the time of taking or
import, or is unweaned or less than eight months old unless such import
is specifically authorized in the conditions of the special exception
permit.
(e) Captive marine mammals shall not be released into the wild
unless specifically authorized by the Office Director under a
scientific research or enhancement permit.
(f) The permit holder is responsible for all activities of any
individual who is operating under the authority of the permit;
(g) Individuals conducting activities authorized under the permit
must possess qualifications commensurate with their duties and
responsibilities, or must be under the direct supervision of a person
with such qualifications;
(h) Persons who require state or Federal licenses to conduct
activities authorized under the permit must be duly licensed when
undertaking such activities;
(i) Special exception permits are not transferable or assignable to
any other person, and a permit holder may not require any direct or
indirect compensation from another person in return for requesting
authorization for such person to conduct the taking,
[[Page 21937]]
import, or export activities authorized under the subject permit;
(j) The permit holder or designated agent shall possess a copy of
the permit when engaged in a permitted activity, when the marine mammal
is in transit incidental to such activity, and whenever marine mammals
or marine mammal parts are in the possession of the permit holder or
agent. A copy of the permit shall be affixed to any container, package,
enclosure, or other means of containment, in which the marine mammals
or marine mammal parts are placed for purposes of transit, supervision,
or care. For marine mammals held captive and marine mammal parts in
storage, a copy of the permit shall be kept on file in the holding or
storage facility.
Sec. 216.36 Permit conditions.
(a) Specific conditions. (1) Permits issued under this subpart
shall contain specific terms and conditions deemed appropriate by the
Office Director, including, but not limited to:
(i) The number and species of marine mammals that are authorized to
be taken, imported, exported, or otherwise affected;
(ii) The manner in which marine mammals may be taken according to
type of take;
(iii) The location(s) in which the marine mammals may be taken,
from which they may be imported, or to which they may be exported, as
applicable, and, for endangered or threatened marine mammal species to
be imported or exported, the port of entry or export;
(iv) The period during which the permit is valid.
(2) [Reserved]
(b) Other conditions. In addition to the specific conditions
imposed pursuant to paragraph (a) of this section, the Office Director
shall specify any other permit conditions deemed appropriate.
Sec. 216.37 Marine mammal parts.
With respect to marine mammal parts acquired by take or import
authorized under a permit issued under this subpart:
(a) Marine mammal parts are transferrable if:
(1) The person transferring the part receives no remuneration of
any kind for the marine mammal part;
(2) The person receiving the marine mammal part is:
(i) An employee of NMFS, the U.S. Fish and Wildlife Service, or any
other governmental agency with conservation and management
responsibilities, who receives the part in the course of their official
duties;
(ii) A holder of a special exception permit which authorizes the
take, import, or other activity involving the possession of a marine
mammal part of the same species as the subject part; or
(iii) In the case of marine mammal parts from a species that is not
depleted, endangered or threatened, a person who is authorized under
section 112(c) of the MMPA and subpart C of this part to take or import
marine mammals or marine mammal parts;
(iv) Any other person specifically authorized by the Regional
Director, consistent with the requirements of paragraphs (a)(1) and
(a)(3) through (6) of this section.
(3) The marine mammal part is transferred for the purpose of
scientific research, maintenance in a properly curated, professionally
accredited scientific collection, or education, provided that, for
transfers for educational purposes, the recipient is a museum,
educational institution or equivalent that will ensure that the part is
available to the public as part of an educational program;
(4) A unique number assigned by the permit holder is marked on or
affixed to the marine mammal part or container;
(5) The person receiving the marine mammal part agrees that, as a
condition of receipt, subsequent transfers may only occur subject to
the provisions of paragraph (a) of this section; and
(6) Within 30 days after the transfer, the person transferring the
marine mammal part notifies the Regional Director of the transfer,
including a description of the part, the person to whom the part was
transferred, the purpose of the transfer, certification that the
recipient has agreed to comply with the requirements of paragraph (a)
of this section for subsequent transfers, and, if applicable, the
recipient's permit number.
(b) Marine mammal parts may be loaned to another person for a
purpose described in paragraph (a)(3) of this section and without the
agreement and notification required under paragraphs (a)(5) and (6) of
this section, if:
(1) A record of the loan is maintained; and
(2) The loan is for not more than one year. Loans for a period
greater than 12 months, including loan extensions or renewals, require
notification of the Regional Director under paragraph (a)(6).
(c) Unless other disposition is specified in the permit, a holder
of a special exception permit may retain marine mammal parts not
destroyed or otherwise disposed of during or after a scientific
research or enhancement activity, if such marine mammal parts are:
(1) Maintained as part of a properly curated, professionally
accredited collection; or
(2) Made available for purposes of scientific research or
enhancement at the request of the Office Director.
(d) Marine mammal parts may be exported and subsequently reimported
by a permit holder or subsequent authorized recipient, for the purpose
of scientific research, maintenance in a properly curated,
professionally accredited scientific collection, or education, provided
that:
(1) The permit holder or other person receives no remuneration for
the marine mammal part;
(2) A unique number assigned by the permit holder is marked on or
affixed to the marine mammal specimen or container;
(3) The marine mammal part is exported or reimported in compliance
with all applicable domestic and foreign laws;
(4) If exported or reimported for educational purposes, the
recipient is a museum, educational institution, or equivalent that will
ensure that the part is available to the public as part of an
educational program; and
(5) Special reports are submitted within 30 days after both export
and reimport as required by the Office Director under Sec. 216.38.
Sec. 216.38 Reporting.
All permit holders must submit annual, final, and special reports
in accordance with the requirements established in the permit, and any
reporting format established by the Office Director.
Sec. 216.39 Permit amendments.
(a) General. Special exception permits may be amended by the Office
Director. Major and minor amendments may be made to permits in response
to, or independent of, a request from the permit holder. Amendments
must be consistent with the Acts and comply with the applicable
provisions of this subpart.
(1) A ``major amendment'' means any change to the permit specific
conditions under Sec. 216.36(a) regarding:
(i) The number and species of marine mammals that are authorized to
be taken, imported, exported, or otherwise affected;
(ii) The manner in which these marine mammals may be taken,
imported, exported, or otherwise affected, if the proposed change may
result in an increased level of take or risk of adverse impact;
[[Page 21938]]
(iii) The location(s) in which the marine mammals may be taken,
from which they may be imported, and to which they may be exported, as
applicable; and
(iv) The duration of the permit, if the proposed extension would
extend the duration of the permit more than 12 months beyond that
established in the original permit.
(2) A ``minor amendment'' means any amendment that does not
constitute a major amendment.
(b) Amendment requests and proposals. (1) Requests by a permit
holder for an amendment must be submitted in writing and include the
following:
(i) The purpose and nature of the amendment;
(ii) Information, not previously submitted as part of the permit
application or subsequent reports, necessary to determine whether the
amendment satisfies all issuance criteria set forth at Sec. 216.34,
and, as appropriate, Sec. 216.41, Sec. 216.42, and Sec. 216.43.
(iii) Any additional information required by the Office Director
for purposes of reviewing the proposed amendment.
(2) If an amendment is proposed by the Office Director, the permit
holder will be notified of the proposed amendment, together with an
explanation.
(c) Review of proposed amendments. (1) Major amendments. The
provisions of Sec. 216.33(d) and (e) governing notice of receipt,
review and decision shall apply to all proposed major amendments.
(2) Minor amendments. (i) After reviewing all appropriate
information, the Office Director will provide the permit holder with
written notice of the decision on a proposed or requested amendment,
together with an explanation for the decision.
(ii) If the minor amendment extends the duration of the permit 12
months or less from that established in the original permit, notice of
the minor amendment will be published in the Federal Register within 10
days from the date of the Office Director's decision.
(iii) A minor amendment will be effective upon a final decision by
the Office Director.
Sec. 216.40 Penalties and permit sanctions.
(a) Any person who violates any provision of this subpart or permit
issued thereunder is subject to civil and criminal penalties, permit
sanctions and forfeiture as authorized under the Acts, and 15 CFR part
904.
(b) All special exception permits are subject to suspension,
revocation, modification and denial in accordance with the provisions
of subpart D of 15 CFR part 904.
Sec. 216.41 Permits for scientific research and enhancement.
In addition to the requirements under Sec. 216.33 through
Sec. 216.38, permits for scientific research and enhancement are
governed by the following requirements:
(a) Applicant. (1) For each application submitted under this
section, the applicant shall be the principal investigator responsible
for the overall research or enhancement activity. If the research or
enhancement activity will involve a periodic change in the principal
investigator or is otherwise controlled by and dependent upon another
entity, the applicant may be the institution, governmental entity, or
corporation responsible for supervision of the principal investigator.
(2) For any scientific research involving captive maintenance, the
application must include supporting documentation from the person
responsible for the facility or other temporary enclosure.
(b) Issuance Criteria. For the Office Director to issue any
scientific research or enhancement permit, the applicant must
demonstrate that:
(1) The proposed activity furthers a bona fide scientific or
enhancement purpose;
(2) If the lethal taking of marine mammals is proposed:
(i) Non-lethal methods for conducting the research are not
feasible; and
(ii) For depleted, endangered, or threatened species, the results
will directly benefit that species or stock, or will fulfill a
critically important research need.
(3) Any permanent removal of a marine mammal from the wild is
consistent with any applicable quota established by the Office
Director.
(4) The proposed research will not likely have significant adverse
effects on any other component of the marine ecosystem of which the
affected species or stock is a part.
(5) For species or stocks designated or proposed to be designated
as depleted, or listed or proposed to be listed as endangered or
threatened:
(i) The proposed research cannot be accomplished using a species or
stock that is not designated or proposed to be designated as depleted,
or listed or proposed to be listed as threatened or endangered;
(ii) The proposed research, by itself or in combination with other
activities will not likely have a long-term direct or indirect adverse
impact on the species or stock;
(iii) The proposed research will either:
(A) Contribute to fulfilling a research need or objective
identified in a species recovery or conservation plan, or if there is
no conservation or recovery plan in place, a research need or objective
identified by the Office Director in stock assessments established
under section 117 of the MMPA;
(B) Contribute significantly to understanding the basic biology or
ecology of the species or stock, or to identifying, evaluating, or
resolving conservation problems for the species or stock; or
(C) Contribute significantly to fulfilling a critically important
research need.
(6) For proposed enhancement activities:
(i) Only living marine mammals and marine mammal parts necessary
for enhancement of the survival, recovery, or propagation of the
affected species or stock may be taken, imported, exported, or
otherwise affected under the authority of an enhancement permit. Marine
mammal parts would include in this regard clinical specimens or other
biological samples required for the conduct of breeding programs or the
diagnosis or treatment of disease.
(ii) The activity will likely contribute significantly to
maintaining or increasing distribution or abundance, enhancing the
health or welfare of the species or stock, or ensuring the survival or
recovery of the affected species or stock in the wild.
(iii) The activity is consistent with:
(A) An approved conservation plan developed under section 115(b) of
the MMPA or recovery plan developed under section 4(f) of the ESA for
the species or stock; or
(B) If there is no conservation or recovery plan, with the Office
Director's evaluation of the actions required to enhance the survival
or recovery of the species or stock in light of the factors that would
be addressed in a conservation or recovery plan.
(iv) An enhancement permit may authorize the captive maintenance of
a marine mammal from a threatened, endangered, or depleted species or
stock only if the Office Director determines that:
(A) The proposed captive maintenance will likely contribute
directly to the survival or recovery of the species or stock by
maintaining a viable gene pool, increasing productivity, providing
necessary biological information, or establishing animal reserves
required to support directly these objectives; and
[[Page 21939]]
(B) The expected benefit to the species or stock outweighs the
expected benefits of alternatives that do not require removal of marine
mammals from the wild.
(v) The Office Director may authorize the public display of marine
mammals held under the authority of an enhancement permit only if:
(A) The public display is incidental to the authorized captive
maintenance;
(B) The public display will not interfere with the attainment of
the survival or recovery objectives;
(C) The marine mammals will be held consistent with all
requirements and standards that are applicable to marine mammals held
under the authority of the Acts and the Animal Welfare Act, unless the
Office Director determines that an exception is necessary to implement
an essential enhancement activity; and
(D) The marine mammals will be excluded from any interactive
program and will not be trained for performance.
(vi) The Office Director may authorize non-intrusive scientific
research to be conducted while a marine mammal is held under the
authority of an enhancement permit, only if such scientific research:
(A) Is incidental to the permitted enhancement activities; and
(B) Will not interfere with the attainment of the survival or
recovery objectives.
(c) Restrictions. (1) The following restrictions apply to all
scientific research permits issued under this subpart:
(i) Research activities must be conducted in the manner authorized
in the permit.
(ii) Research results shall be published or otherwise made
available to the scientific community in a reasonable period of time.
(iii) Research activities must be conducted under the direct
supervision of the principal investigator or a co-investigator
identified in the permit.
(iv) Personnel involved in research activities shall be reasonable
in number and limited to:
(A) Individuals who perform a function directly supportive of and
necessary to the permitted research activity; and
(B) Support personnel included for the purpose of training or as
backup personnel for persons described in paragraph (c)(1)(iv)(A).
(v) Any marine mammal part imported under the authority of a
scientific research permit must not have been obtained as the result of
a lethal taking that would be inconsistent with the Acts, unless
authorized by the Office Director.
(vi) Marine mammals held under a permit for scientific research
shall not be placed on public display, included in an interactive
program or activity, or trained for performance unless such activities:
(A) Are necessary to address scientific research objectives and
have been specifically authorized by the Office Director under the
scientific research permit; and
(B) Are conducted incidental to and do not in any way interfere
with the permitted scientific research; and
(C) Are conducted in a manner consistent with provisions applicable
to public display, unless exceptions are specifically authorized by the
Office Director.
(vii) Any activity conducted incidental to the authorized
scientific research activity must not involve any taking of marine
mammals beyond what is necessary to conduct the research (i.e.,
educational and commercial photography).
(2) Any marine mammal or progeny held in captive maintenance under
an enhancement permit shall be returned to its natural habitat as soon
as feasible, consistent with the terms of the enhancement permit and
the objectives of an approved conservation or recovery plan. In
accordance with section 10(j) of the ESA, the Office Director may
authorize the release of any population of an endangered or threatened
species outside the current range of such species if the Office
Director determines that such release will further the conservation of
such species.
Sec. 216.42 Photography. [Reserved]
Sec. 216.43 Public display. [Reserved]
Sec. 216.44 Applicability/transition.
(a) General. The regulations of this subpart are applicable to all
persons, including persons holding permits or other authorizing
documents issued before June 10, 1996, by NMFS for the take, import,
export, or conduct of any otherwise prohibited activity involving a
marine mammal or marine mammal part for special exception purposes.
(b) Scientific research. Any intrusive research as defined in
Sec. 216.3, initiated after June 10, 1996, must be authorized under a
scientific research permit. Intrusive research authorized by the Office
Director to be conducted on captive marine mammals held for public
display purposes prior to June 10, 1996, must be authorized under a
scientific research permit one year after June 10, 1996.
* * * * *
Secs. 216.46-216.49 [Reserved]
PART 222--ENDANGERED FISH OR WILDLIFE
9. The authority citation for part 222 is revised to read as
follows:
Authority: 16 U.S.C. 1531 et seq.
10. In Sec. 222.23, the first sentence in paragraph (b) is revised
to read as follows:
Sec. 222.23 Permits for scientific purposes or to enhance the
propagation or survival of the affected endangered species.
* * * * *
(b) Application procedures. To obtain such a permit, an application
must be made to the Director in accordance with this subpart, except
for marine mammal permits which shall be issued in accordance with the
provisions of part 216, subpart D of this chapter, and sea turtle
permits which shall be issued in accordance with part 220, subpart E of
this chapter.
* * * * *
[FR Doc. 96-11776 Filed 5-9-96; 8:45 am]
BILLING CODE 3510-22-W
Complete official Federal Register PDF
FR Doc. 96-11763 Radio Broadcasting Services; Various Locations
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Page 21384]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11763]
-----------------------------------------------------------------------
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 73
Radio Broadcasting Services; Various Locations
AGENCY: Federal Communications Commission.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Commission, on its own motion, editorially amends the
Table of FM Allotments to specify the actual classes of channels
allotted to various communities. The changes in channel classifications
have been authorized in response to applications filed by licensees and
permittees operating on these channels. This action is taken pursuant
to Revision of Section 73.3573(a)(1) of the Commission's Rules
Concerning the Lower Classification of an FM Allotment, 4 FCC Rcd 2413
(1989), and the Amendment of the Commission's Rules to permit FM
Channel and Class Modifications [Upgrades] by Applications, 8 FCC Rcd
4735 (1993).
EFFECTIVE DATE: May 10, 1996.
FOR FURTHER INFORMATION CONTACT: Kathleen Scheuerle, Mass Media Bureau,
(202) 418-2180.
SUPPLEMENTARY INFORMATION: This is a synopsis of the Commission's
Report and Order, adopted April 26, 1996, and released May 6, 1996. The
full text of this Commission decision is available for inspection and
copying during normal business hours in the Commission's Reference
Center (Room 239), 1919 M Street, NW., Washington, DC. The complete
text of this decision may also be purchased from the Commission's copy
contractors, International Transcription Services, Inc., 2100 M Street,
NW., Suite 140, Washington, DC 20037, (202) 857-3800.
List of Subjects in 47 CFR Part 73
Radio broadcasting.
Part 73 of title 47 of the Code of Federal Regulations is amended
as follows:
PART 73--[AMENDED]
1. The authority citation for part 73 continues to read as follows:
Authority: Secs. 303, 48 Stat., as amended, 1082; 47 U.S.C. 154,
as amended.
Sec. 73.202 [Amended]
2. Section 73.202(b), the Table of FM Allotments under Arkansas, is
amended by removing Channel 233A and adding Channel 233C3 at West
Helena.
3. Section 73.202(b), the Table of FM Allotments under California,
is amended by removing Channel 276A and adding Channel 276B1 at
Oakhurst, by removing Channel 286A and adding Channel 286B1 at Pacific
Grove, and by removing Channel 239A and adding Channel 242A at
Twentynine Palms.
4. Section 73.202(b), the Table of FM Allotments under Kansas, is
amended by removing Channel 284A and adding Channel 284C3 at Fort
Scott.
5. Section 73.202(b), the Table of FM Allotments under Maine, is
amended by removing Channel 249A and adding Channel 249B.
6. Section 73.202(b), the Table of FM Allotments under Montana, is
amended by removing Channel 233C and adding Channel 233C1 at Great
Falls and by removing Channel 257C and adding Channel 257A at Red
Lodge.
7. Section 73.202(b), the Table of FM Allotments under Nebraska, is
amended by removing Channel 249A and adding Channel 249C1 at Holdrege.
8. Section 73.202(b), the Table of FM Allotments under New Mexico,
is amended by removing Channel 266C3 and adding Channel 266A at White
Rock.
9. Section 73.202(b), the Table of FM Allotments under South
Carolina, is amended by removing Channel 232A and adding Channel 232C3
at Goose Creek.
Federal Communications Commission.
Andrew J. Rhodes,
Acting Chief, Allocations Branch, Policy and Rules Division, Mass Media
Bureau.
[FR Doc. 96-11763 Filed 5-9-96; 8:45 am]
BILLING CODE 6712-01-F
Complete official Federal Register PDF
FR Doc. 96-11762 Radio Broadcasting Services; Tillamook, OR
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21384-21385]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11762]
-----------------------------------------------------------------------
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 73
[MM Docket No. 95-153; RM-8702]
Radio Broadcasting Services; Tillamook, OR
AGENCY: Federal Communications Commission.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Commission, at the request of Brian Lord, allots Channel
231A to Tillamook, OR, as the community's second local FM transmission
service. See 60 FR 55358, October 31, 1995. Channel 231A can be
allotted to Tillamook in compliance with the Commission's minimum
distance separation requirements with a site restriction of 5.8
kilometers (3.6 miles) west, at coordinates 45-27-27 North Latitude;
123-55-00 West Longitude, to avoid a short-spacing to Station KPDQ-FM,
Channel 229C, Portland, Oregon. Canadian concurrence in the allotment
has been received since Tillamook is located within 320 kilometers (200
miles) of the U.S.-Canadian border. With this action, this proceeding
is terminated.
DATES: Effective June 17, 1996. The window period for filing
applications will open on June 17, 1996, and close on July 18, 1996.
[[Page 21385]]
FOR FURTHER INFORMATION CONTACT: Leslie K. Shapiro, Mass Media Bureau,
(202) 418-2180.
SUPPLEMENTARY INFORMATION: This is a synopsis of the Commission's
Report and Order, MM Docket No. 95-153, adopted April 16, 1996, and
released May 3, 1996. The full text of this Commission decision is
available for inspection and copying during normal business hours in
the FCC Reference Center (Room 239), 1919 M Street, NW., Washington,
DC. The complete text of this decision may also be purchased from the
Commission's copy contractor, International Transcription Service,
Inc., (202) 857-3800, 2100 M Street, NW., Suite 140, Washington, DC
20037.
List of Subjects in 47 CFR Part 73
Radio broadcasting.
Part 73 of title 47 of the Code of Federal Regulations is amended
as follows:
PART 73--[AMENDED]
1. The authority citation for part 73 continues to read as follows:
Authority: Secs. 303, 48 Stat., as amended, 1082; 47 U.S.C. 154,
as amended.
Sec. 73.202 [Amended]
2. Section 73.202(b), the Table of FM Allotments under Oregon, is
amended by adding Channel 231A at Tillamook.
Federal Communications Commission.
Andrew J. Rhodes,
Acting Chief, Allocations Branch, Policy and Rules Division, Mass Media
Bureau.
[FR Doc. 96-11762 Filed 5-9-96; 8:45 am]
BILLING CODE 6712-01-F
Complete official Federal Register PDF
FR Doc. 96-11761 Radio Broadcasting Services; Wellsville, NY
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Page 21385]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11761]
-----------------------------------------------------------------------
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 73
[MM Docket No. 95-162; RM-8714]
Radio Broadcasting Services; Wellsville, NY
AGENCY: Federal Communications Commission.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Commission, at the request of Erin Communications, Inc.,
substitutes Channel 278A for Channel 228A at Wellsville, NY, and
modifies Station WJQZ(FM)'s license to specify operation on the
alternate Class A channel. See 60 FR 55821, November 3, 1995. The
substitution of channels could allow Station WJQZ(FM) to improve its
facilities from its present 3 kW to 6 kW. With this action, this
proceeding is terminated.
EFFECTIVE DATE: June 17, 1996.
FOR FURTHER INFORMATION CONTACT: Leslie K. Shapiro, Mass Media Bureau,
(202) 418-2180.
SUPPLEMENTARY INFORMATION: This is a synopsis of the Commission's
Report and Order, MM Docket No. 95-162, adopted April 16, 1996, and
released May 3, 1996. The full text of this Commission decision is
available for inspection and copying during normal business hours in
the FCC Reference Center (Room 239), 1919 M Street, NW., Washington,
DC. The complete text of this decision may also be purchased from the
Commission's copy contractor, International Transcription Service,
Inc., (202) 857-3800, 2100 M Street, NW., Suite 140, Washington, DC
20037.
List of Subjects in 47 CFR Part 73
Radio broadcasting.
Part 73 of title 47 of the Code of Federal Regulations is amended
as follows:
PART 73--[AMENDED]
1. The authority citation for part 73 continues to read as follows:
Authority: Secs. 303, 48 Stat., as amended, 1082; 47 U.S.C. 154,
as amended.
Sec. 73.202 [Amended]
2. Section 73.202(b), the Table of FM Allotments under New York, is
amended by removing Channel 228A and adding Channel 278A at Wellsville.
Federal Communications Commission.
Andrew J. Rhodes,
Acting Chief, Allocations Branch, Policy and Rules Division, Mass Media
Bureau.
[FR Doc. 96-11761 Filed 5-9-96; 8:45 am]
BILLING CODE 6712-01-F
Complete official Federal Register PDF
FR Doc. 96-11745 706 Agencies; Orange County (NC) Human Relations Commission and Palm Beach County (FL) Office of Equal Opportunity; Designation as Fair Employment Practices Agencies
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Page 21370]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11745]
=======================================================================
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EQUAL EMPLOYMENT OPPORTUNITY COMMISSION
29 CFR Part 1601
706 Agencies; Orange County (NC) Human Relations Commission and
Palm Beach County (FL) Office of Equal Opportunity; Designation as Fair
Employment Practices Agencies
AGENCY: Equal Employment Opportunity Commission.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Equal Employment Opportunity Commission amends its
regulations designating certain State and local fair employment
practices agencies (706 Agencies) so that they may handle employment
discrimination charges within their jurisdictions. Publication of this
amendment effectuates the designation of the Orange County (NC) Human
Relations Commission and the Palm Beach County (FL) Office of Equal
Opportunity.
EFFECTIVE DATE: May 10, 1996.
FOR FURTHER INFORMATION CONTACT:
Boyce Nolan, Equal Employment Opportunity Commission, Office of Program
Operations, Charge Resolution Review Program, 1801 L Street, N.W.,
Washington, D.C. 20507, Telephone (202) 663-4856.
SUPPLEMENTARY INFORMATION:
List of Subjects in 29 CFR Part 1601
Administrative practice and procedure, Equal employment
opportunity, Intergovernmental relations.
Accordingly, title 29, chapter XIV, part 1601 of the Code of
Federal Regulations is amended as follows:
PART 1601--PROCEDURAL REGULATIONS
1. The authority citation for part 1601 continues to read as
follows:
Authority: 42 U.S.C. 2000e to 2000e-17; 42 U.S.C. 12111 to
12117.
2. Section 1601.74(a) is amended by adding in alphabetical order
the following agencies:
Sec. 1601.74 Designated and notice agencies.
(a) * * *
Orange County (NC) Human Relations Commission
* * * * *
Palm Beach County (FL) Office of Equal Opportunity
* * * * *
Signed at Washington, D.C. this 2nd day of May, 1996.
For the Commission.
Gilbert F. Casellas,
Chairman.
[FR Doc. 96-11745 Filed 5-9-96; 8:45 am]
BILLING CODE 6750-01-M
Complete official Federal Register PDF
FR Doc. 96-11742 Removal of Obsolete Regulations Concerning Owner-Operators
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21387-21388]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11742]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Surface Transportation Board
49 CFR Parts 1164 and 1311
[STB Ex Parte No. 545]
Removal of Obsolete Regulations Concerning Owner-Operators
AGENCY: Surface Transportation Board.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Surface Transportation Board (the Board) is removing from
the Code of Federal Regulations obsolete regulations concerning owner-
operators.
EFFECTIVE DATE: May 10, 1996.
FOR FURTHER INFORMATION CONTACT: Beryl Gordon, (202) 927-7513. [TDD for
the hearing impaired: (202) 927-5721.]
SUPPLEMENTARY INFORMATION: Effective January 1, 1996, the ICC
Termination Act of 1995, Pub. L. No. 104-88, 109 Stat. 803 (ICCTA)
abolished the Interstate Commerce Commission (ICC) and established the
Board within the Department of Transportation. Section 204(a) of ICCTA
provides that ``[t]he Board shall promptly rescind all regulations
established by the [ICC] that are based on provisions of law repealed
and not substantively reenacted by this Act.''
Generally, prior to enactment of the Motor Carrier Act of 1980
(MCA-80), motor common and contract carriers needed licenses from the
ICC (certificates for common carriers, permits for contract carriers)
in order to operate. These licenses were based on public convenience
and necessity and fitness standards. Motor common and contract carriers
could only charge rates that were filed with the ICC in tariffs or
schedules.
The regulations involved here relaxed these regulatory requirements
for owner-operators transporting food. The part 1164 regulations were
based on former 49 U.S.C. 10922(b)(4)(E), 10923(b)(5)(A), and 11145(c).
The part 1311 regulations were based on former 49 U.S.C. 10762(a)(1)
and 10762(g), as well as former sections 10922(b)(4)(E) and
10923(b)(5)(A). Under the Trucking Industry Regulatory Reform Act
(TIRRA), Title II of the Hazardous Materials Transportation Act
Amendments of 1994, Pub. L. No. 103-311 (August 26, 1994), and the
ICCTA, these statutory provisions were repealed, and we are accordingly
removing the obsolete part 1164 and part 1311 regulations.
PART 1164--LICENSING
Sections 5(a)(3) and 10(a)(2) of the MCA-80 provided exceptions for
owner-operators to the licensing provisions then generally applicable
for obtaining certificates and permits. These sections of the MCA-80
were codified, as here relevant, at former 49 U.S.C. 10922(b)(4)(E) and
49 U.S.C. 10923(b)(5)(A). Owner-operators were allowed to obtain
operating authority from the ICC to transport food and certain other
commodities 1 through a fitness-only application procedure.2
The ICC issued regulations implementing the new statute in Owner-
Operator Food Transportation, 132 M.C.C. 521 (1981) (Owner-
Operator).3
---------------------------------------------------------------------------
\1\ These commodities were food and other edible products
included for human consumption (excluding alcoholic beverages and
drugs), agricultural limestone, and fertilizers and other soil
conditioners. For brevity, these commodities will be referred to as
food products.
\2\ The statute limited this provision to transportation by the
owner of the vehicle, except in emergency situations, and to
situations in which the annual tonnage of food products transported
did not exceed the annual tonnage of exempt commodities transported.
Former 49 U.S.C. 11145(c) required the ICC to ``streamline'' the
annual method of reporting tonnage.
\3\ These regulations were originally found in 49 CFR part
1138, but they were redesignated at 49 CFR part 1164 on November 1,
1982 (47 FR 49534). They defined the term ``emergency situations''
and promulgated an annual reporting requirement to certify
compliance with the statute's annual tonnage limitation.
---------------------------------------------------------------------------
TIRRA again amended former sections 10922 and 10923. Sections 207
and 208 of TIRRA eliminated the provisions of 49 U.S.C. 10922(b)(4)(E)
and 49 U.S.C. 10923(b)(5)(A) and also modified other parts of sections
10922 and 10923 to apply the fitness-only standard to all non-household
goods motor property common and contract carrier applicants. See
Revised MC-Licensing Appl. Forms and Regs., 10 I.C.C.2d 386, 387
(1994).4 Thus, since the passage of TIRRA, owner operators have
been able to obtain authority to transport food products under that
standard regardless of the annual tonnage and ownership of the
vehicle.5
---------------------------------------------------------------------------
\4\ Effective January 1, 1995, the ICC was to issue authorities
to carriers upon finding that the applicant was in compliance with
(1) ICC regulations and safety requirements; (2) DOT safety fitness
requirements; and (3) minimum financial responsibility requirements
established by the ICC pursuant to 49 U.S.C. 10927.
\5\ Truck licensing was again changed under the ICCTA.
Permanent licensing for motor carriers of property was eliminated.
49 U.S.C. 13902. Now, motor carriers are registered for a term
determined by the Secretary of Transportation based on fitness
standards (safety and insurance) similar to those in TIRRA. A two-
year transition period is established to allow motor common and
contract carriers to be issued certificates and permits under the
TIRRA framework. 49 U.S.C. 13902(d). Although ICCTA eliminates the
distinction between motor common and contract carriage, each carrier
can be separately registered during the transition period.
---------------------------------------------------------------------------
Because former sections 10922(b)(E)(5), 10923(b)(5)(A), and
11145(c) have been eliminated, we will remove the obsolete regulations
at 49 CFR part 1164.
PART 1311--RATE FILINGS
Section 5(a) of the MCA-80 modified for owner-operators the
requirement to file tariffs and schedules: former 49 U.S.C. 10762 was
amended by the addition of a new subsection (g) mandating the
streamlining of rate filing requirements of motor carriers holding
authority issued under former section 10922(b)(4)(E) and
10923(b)(5)(a). Also, former section 10762(a)(1) was amended
[[Page 21388]]
to require the filing of only minimum rates for owner-operator
transportation of food products. In Owner-Operator, supra, the ICC
adopted regulations at 49 CFR part 1311 that permitted owner-operators
of food products to file, in lieu of tariffs or schedules, a letter
statement containing the transportation services performed and the
minimum rates.6
---------------------------------------------------------------------------
\6\ The ICC later eliminated by exemption the requirement that
motor contract carriers file a schedule of rates. Exemption--Mtr.
Contr. Car.--Tariff Filing Requirements, 133 M.C.C. 150 (1983),
aff'd sub nom. Central & Southern Motor Freight Ass'n v. United
States, 757 F.2d 301 (D.C. Cir. 1985), cert. denied, 474 U.S. 1019
(1985).
---------------------------------------------------------------------------
Section 206 of TIRRA further amended former section 10762(a)(1) by
removing the tariff filing requirement for individually (as
distinguished from collectively) set rates of motor common carriers of
property (other than household goods and carriers involved with water
carriers in the noncontiguous domestic trade). Motor contract carriers
were no longer required to file actual or minimum rates.7
---------------------------------------------------------------------------
\7\ Although sections 207 and 208 of TIRRA eliminated former
sections 10922(b)(4)(E) and 10923(b)(5)(A), TIRRA did not remove
former section 10762(g), the provision for streamlined rate filing
for owner-operator transportation of food products.
---------------------------------------------------------------------------
The ICCTA further modified the rate filing requirements. Former
section 10762(g) was removed. Now, under 49 U.S.C. 13702, motor
carriers only need to file a tariff with the Board for transportation
in noncontiguous domestic trade (with certain exceptions).
Because the statutory bases for the part 1311 regulations have been
repealed, we are eliminating these obsolete rules.
This action will not significantly affect either the quality of the
human environment or the conservation of energy resources.
List of Subjects
49 CFR Part 1164
Foods, Freight, Motor carriers, Reporting and recordkeeping
requirements.
49 CFR Part 1311
Foods, Freight, Motor carriers.
Decided: April 24, 1996.
By the Board, Chairman Morgan, Vice Chairman Simmons, and
Commissioner Owen.
Vernon A. Williams,
Secretary.
PARTS 1164 AND 1311--[REMOVED]
For the reasons set forth in the preamble and under the authority
of 49 U.S.C. 721(a), title 49, chapter X of the Code of Federal
Regulations is amended by removing parts 1164 and 1311.
[FR Doc. 96-11742 Filed 5-9-96; 8:45 am]
BILLING CODE 4915-00-P
Complete official Federal Register PDF
FR Doc. 96-11737 Hazardous Air Pollutants: Amendment to Regulations Governing Equivalent Emission Limitations by Permit
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21370-21372]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11737]
=======================================================================
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 63
[AD-FRL-5503-3]
Hazardous Air Pollutants: Amendment to Regulations Governing
Equivalent Emission Limitations by Permit
AGENCY: Environmental Protection Agency (EPA).
ACTION: Direct final rule.
-----------------------------------------------------------------------
SUMMARY: On May 20, 1994, the Agency promulgated a rule in the Federal
Register governing the establishment of equivalent emission limitations
by permit, pursuant to section 112(j) of the Clean Air Act (Act). After
the effective date of a Title V permit program in a State, each owner
or operator of a major source in a source category for which the EPA
was scheduled to, but failed to promulgate a section 112(d) emission
standard will be required to obtain an equivalent emission limitation
by permit. The permit application must be submitted to the Title V
permitting authority 18 months after the EPA's missed promulgation
date. This action amends the original Regulations Governing Equivalent
Emission Limitations by Permit rule. This amendment delays the section
112(j) permit application deadline for all 4-year source categories
listed in the regulatory schedule by 180 days until November 15, 1996.
This action is needed to alleviate unnecessary paperwork for both major
source owners or operators and permitting agencies.
EFFECTIVE DATE: May 10, 1996.
ADDRESSES: Docket. All information used in the development of this
final action is contained in the preamble below. However, Docket No. A-
93-32, containing the supporting information for the original
Regulations Governing Equivalent Emission Limitations by Permit rule is
available for public inspection and copying between 8:00 a.m. and 5:30
p.m., Monday through Friday at the Air and Radiation Docket and
Information Center (6102), Room M-1500, U.S. Environmental Protection
Agency, 401 M Street, S.W., Washington, D.C. 20460; telephone (202)
260-7548, fax (202) 260-4000. A reasonable fee may be charged for
copying.
FOR FURTHER INFORMATION CONTACT: Mr. James Szykman or Mr. Anthony
Wayne, Emission Standards Division (MD-13), U.S. Environmental
Protection Agency, Research Triangle Park, North Carolina 27711,
telephone (919) 541-2452 (Szykman) or (919) 541-5439 (Wayne).
[[Page 21371]]
SUPPLEMENTARY INFORMATION: In the Proposed Rules Section of this
Federal Register, EPA is proposing a rule that is identical to this
direct final rule. If significant, adverse comments are timely received
on the proposed rule, the direct final rule will be withdrawn, and all
such comments will be addressed in a subsequent final rule based on the
proposed rule. If no significant, adverse comments are timely received
on the proposed final rule, then the direct final rule remains
effective upon publication, and no further action is contemplated on
the parallel proposal published today.
The information presented in this preamble is organized as follows:
I. Background
II. Summary of Rule Change and Rationale
A. Permit Application Deadline
B. Effective Date
C. Judicial Review
III. Administrative Requirements
A. Docket
B. Regulatory Impact Analysis
C. Impact on Reporting Requirements
D. Impact on Small Entities
E. Reduction of Governmental Burden
F. Environmental Justice
G. Unfunded Mandates
I. Background
Section 112(e) of the Clean Air Act (the Act) requires the Agency
to publish a schedule for promulgating regulations establishing
hazardous air pollutants (HAP) emission standards for all source
categories listed pursuant to Section 112 of the Act. The Act further
directs that this regulatory schedule require the promulgation of
emission standards for at least 40 source categories by 1992, for at
least 25 percent of the listed categories by 1994, for at least 50
percent of the listed categories by 1997, and all remaining categories
by the year 2000. These are commonly referred to as the 2-year, 4-year,
7-year, and the 10-year maximum achievable control technology (MACT)
standards, respectively. This regulatory schedule was published by EPA
on December 3, 1993 (58 FR 64931).
If EPA should fail to promulgate a MACT standard for a listed
source category by 18 months after the date in the regulatory schedule,
section 112(j) of the Act requires owners or operators of major sources
within that source category to obtain a Title V permit, if the major
source is located in a State with an approved Title V permit program.
This permit will require compliance with an emission limitation
equivalent to that which the major source would have been subject to
had EPA promulgated a timely MACT standard for that source category.
On May 20, 1994, EPA issued a final rule for implementing section
112(j) (59 FR 26429). This rule requires major source owners or
operators to submit a permit application by the date 18 months after a
missed date on the regulatory schedule. In accordance with this
regulation, the deadlines for submittal of permit applications are as
follows:
------------------------------------------------------------------------
112(j) permit
Emission standard Regulatory schedule application
deadline
------------------------------------------------------------------------
4-year......................... 11/15/94........... 5/15/96
7-year......................... 11/15/97........... 5/15/99
10-year........................ 11/15/00........... 5/15/02
------------------------------------------------------------------------
II. Summary of Rule Change and Rationale
A. Permit Application Deadline
To date, EPA has promulgated several 4-year MACT standards and
intends to promulgate MACT standards for all of the remaining 4-year
source categories within the 18-month period following the date in the
regulatory schedule. All of the remaining 4-year source categories for
which MACT standards must be promulgated have court-ordered deadlines
with the latest deadline coinciding with the section 112(j) permit
application deadline of May 15, 1996.
In order for owners or operators of major sources to submit a
timely permit application in the event that EPA would fail to
promulgate a 4-year emission standard, applicants would have to begin
preparation of these applications immediately. If EPA promulgates
standards in accordance with the court-ordered schedule, this would
result in an unnecessary burden for both the owners or operators and
the Title V permitting agencies.
The EPA believes that ample authority for this rule revision exists
under the de minimis doctrine. That doctrine allows EPA to promulgate a
rule that avoids a statutory requirement if (1) following that
requirement would yield an environmental benefit of trivial or no
value, and (2) the statutory scheme is not so rigid as to preclude this
result. Alabama Power Co. v. Costle, 636 F.2d 323, 360-61 (D.C. Cir
1979). The EPA believes both tests are met here. Regarding the first
point, it should be intuitively apparent that requiring sources to
complete applications for a case-by-case determination is pointless
when it is very likely that EPA will promulgate the MACT standard
within a timeframe that renders the entire case-by-case exercise moot.
This is precisely the case with regard to the pending 4-year MACT
standards, all of which are under a court-ordered deadline for issuance
close to the date applications are due. Regarding the second test, the
language of section 112(j)(2), requiring that applications be submitted
on a date ``beginning'' 18 months after a deadline has been missed, and
the clear intent of the statute that case-by-case determinations should
be made where they will serve as a substitute for the pending MACT
standard, together suggest a level of flexibility in the statutory
scheme sufficient to allow resort to the de minimis rationale.
The EPA is amending the definition of ``Section 112(j) deadline''
in Sec. 63.51 of the final rule to delay the section 112(j) permit
application deadline for all 4-year source categories by 180 days until
November 15, 1996. The EPA believes that this new application deadline
will allow sufficient time to promulgate the remaining 4-year emission
standards and is consistent with the intent of section 112(j). If EPA
does promulgate the emission standards before this time, permit
applications or reopenings will be governed by Title V requirements.
B. Effective Date
The EPA is publishing this rule as a final rule, and it is
effective immediately upon publication. The Agency believes that this
action is supported by the ``good cause'' exception in the
Administrative Procedures Act, which permits an agency for ``good
cause'' to proceed directly to a final rule where issuing a proposed
rule would be ``impracticable, unnecessary, or contrary to the public
interest'' [5 U.S.C. 553(b)(B)] and for ``good cause found'' [5 U.S.C.
553(d)] to dispense with the general requirement that a rule be
published 30 days before its effective date. The EPA believes that good
cause exists here to issue a final, immediately effective rule because
of the nearness of the May 15, 1996, permit application deadline (for
major sources in the 4-year source category) specified in the May 20,
1994 (59 FR 26429) final rule. If the changes in this rulemaking were
only being proposed, then the May 15, 1996, deadline would still be in
effect and this would negate the intent of this change to the rule to
delay the permit application deadline until November 15, 1996, for
sources in the 4-year source category. Furthermore, EPA views this
action to delay the permit application deadline as noncontroversial.
C. Judicial Review
Under Section 307(b)(1) of the Act, judicial review of the actions
taken by this final rule is available only by the filing of a petition
for review in the U.S.
[[Page 21372]]
Court of Appeals for the District of Columbia Circuit within 60 days of
publication of this action. Under Section 307(b)(2) of the Act, the
requirements that are the subject of this final rule may not be
challenged later in civil or criminal proceedings brought by EPA to
enforce these requirements.
III. Administrative Requirements
A. Docket
The docket for this regulatory action is A-93-32, the same docket
as the original final rule, and a copy of today's amendment to the
final rule will be included in the docket. The docket is an organized
and complete file of all the information submitted to, or otherwise
considered by, EPA in the development of the original rulemaking. The
principal purposes of the docket are:
(1) To allow interested parties a means to identify and locate
documents so that they can effectively participate in the rulemaking
process, and
(2) To serve as the record in case of judicial review. The docket
is available for public inspection at EPA's Air and Radiation Docket
and Information Center, which is listed under the ADDRESSES section of
this document.
B. Regulatory Impact Analysis
This rule was classified ``non-significant'' under Executive Order
12866 and therefore was not reviewed by the Office of Management and
Budget.
C. Impact on Reporting Requirements
The information collection requirements of the previously
promulgated rule for Regulations Governing Equivalent Emission
Limitations by Permit were submitted to and approved by the Office of
Management and Budget. A copy of this Information Collection Request
(ICR) document (OMB control number 2060-0266) may be obtained from
Sandy Farmer, OPPE Regulatory Information Division (2136), U.S.
Environmental Protection Agency, 401 M Street, S.W., Washington, D.C.
20460, or by calling (202) 260-2740. Today's change to the final rule
to delay the deadline for submittal of section 112(j) permit
applications does not affect the information collection burden
estimates made previously. Therefore, the ICR has not been revised.
D. Impact on Small Entities
The Regulatory Flexibility Act of 1980 requires the identification
of potentially adverse impacts of Federal regulations upon small
business entities. The Act specifically requires the completion of a
Regulatory Flexibility Analysis in those instances where small business
impacts are possible. Because this rulemaking imposes no economic
impacts, adverse or otherwise, a Regulatory Flexibility Analysis has
not been prepared.
Pursuant to the provisions of 5 U.S.C. 605(b), I hereby certify
that this rule will not have a significant economic impact on a
substantial number of small business entities.
E. Reduction of Governmental Burden
Executive Order 12875 (``Enhancing the Intergovernmental
Partnership'') is designed to reduce the burden to State, local, and
Tribal governments of the cumulative effect of unfunded Federal
mandates. The Order recognizes the need for these entities to be free
from unnecessary Federal regulation to enhance their ability to address
problems they face and provides for Federal agencies to grant waivers
to these entities from discretionary Federal requirements. The Order
applies to any regulation that is not required by statute and that
creates a mandate upon a State, local, or Tribal government. The EPA
anticipates that there will be no additional cost burden imposed on
State, local, and Tribal governments as a result of today's action.
Indeed, the purpose of the action is to reduce unnecessary burden on
permitting agencies.
F. Environmental Justice
Executive Order 12898 requires that each Federal agency shall make
achieving environmental justice part of its mission by identifying and
addressing, as appropriate, disproportionately high and adverse human
health or environmental effects of its programs, policies, and
activities on minority and low-income populations. Today's action will
help ensure timely compliance and the application of consistent
regulatory requirements by allowing the section 112(d) MACT standards
to become effective without triggering an unnecessary section 112(j)
process. Therefore, no adverse human health or environmental effects
are anticipated as a result of today's action.
G. Unfunded Mandates
Under Section 202 of the Unfunded Mandates Reform Act of 1995
(``Unfunded Mandates Act''), the EPA must prepare a budgetary impact
statement to accompany any proposed or final rule that includes a
Federal mandate that may result in estimated costs to State, local, or
tribal governments in the aggregate; or to the private sector, of $100
million or more. Under Section 205, the EPA must select the most cost-
effective and least burdensome alternative that achieves the objectives
of the rule and is consistent with statutory requirements. Section 203
requires the EPA to establish a plan for informing and advising any
small governments that may be significantly or uniquely impacted by the
rule.
The EPA has determined that the action promulgated today does not
include a Federal mandate that may result in estimated costs of $100
million or more to either State, local, or tribal governments in the
aggregate, or to the private sector. Therefore, the requirements of the
Unfunded Mandates Act do not apply to this action.
List of Subjects in 40 CFR Part 63
Environmental protection, Administrative practices and procedures,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.
Dated: May 3, 1996.
Carol M. Browner,
Administrator.
For the reasons set out in the preamble, 40 CFR Part 63 is amended
as follows:
PART 63--[AMENDED]
1. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
2. In Sec. 63.51, the definition of ``Section 112(j) deadline'' is
revised to read as follows:
Sec. 63.51 Definitions.
* * * * *
Section 112(j) deadline means the date 18 months, after the date by
which a relevant standard is scheduled to be promulgated under this
part, except for all major sources listed in the source category
schedule for which a relevant standard is scheduled to be promulgated
by November 15, 1994, the section 112(j) deadline is November 15, 1996.
* * * * *
[FR Doc. 96-11737 Filed 5-9-96; 8:45 am]
BILLING CODE 6560-50-P
Complete official Federal Register PDF
FR Doc. 96-11736 Clean Air Act Reclassification; Arizona-Phoenix Nonattainment Area; PMINF10
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21372-21378]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11736]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 81
[AZR91-0003; FRL-5503-7]
Clean Air Act Reclassification; Arizona-Phoenix Nonattainment
Area; PM10
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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[[Page 21373]]
SUMMARY: In this document EPA is making a final finding that the
Phoenix Planning Area (PPA) has not attained the PM10 (particulate
matter 10 microns or less in aerodynamic diameter) national ambient air
quality standards (NAAQS) by the applicable attainment date in the
Clean Air Act (CAA) for moderate PM10 nonattainment areas,
December 31, 1994. This finding is based on EPA's review of PM10
ambient air quality data. As a result of this finding, the PPA is
reclassified as a serious PM10 nonattainment area by operation of
law. The intended effect of the reclassification is to allow the State
18 months from the effective date of this action to submit a new State
Implementation Plan (SIP) demonstrating attainment of the PM10
NAAQS by December 31, 2001, the CAA attainment date for serious areas.
EFFECTIVE DATE: This action is effective on June 10, 1996.
FOR FURTHER INFORMATION CONTACT: Wallace Woo, Chief, Plans Development
Section (A-2-2), Air Planning Branch, Air and Toxics Division, U.S.
Environmental Protection Agency, Region 9, 75 Hawthorne Street, San
Francisco, California 94105, (415) 744-1207.
SUPPLEMENTARY INFORMATION:
I. Background
A. CAA Requirements and EPA Actions Concerning Designation and
Classification
On November 15, 1990, the date of enactment of the 1990 Clean Air
Act Amendments (CAA), PM10 areas meeting the qualifications of
section 107(d)(4)(B) of the Act were designated nonattainment by
operation of law. Once an area is designated nonattainment, section 188
of the Act outlines the process for classification of the area and
establishes the area's attainment date. Pursuant to section 188(a), all
PM10 nonattainment areas were initially classified as moderate by
operation of law upon designation as nonattainment. These nonattainment
designations and moderate area classifications were codified in 40 CFR
part 81 in a Federal Register notice published on November 6, 1991 (56
FR 56694).
Under section 188(c)(1) of the CAA, the attainment deadline for all
PM10 nonattainment areas originally classified as moderate was no
later than December 31, 1994. Under section 188(d), EPA may, upon
application by a state, extend the attainment deadline if the state has
complied with all requirements and commitments pertaining to the area
in the applicable implementation plan. In addition, in order to qualify
for an extension there must have been no more than one exceedance of
the 24 hour national ambient air quality standard (NAAQS) in the area
in the year preceding the extension year, and the annual mean
concentration of PM10 in the area for such year must be less than
or equal to the standard. Under this provision, EPA may grant up to two
one year extensions if these conditions have been met.
B. Reclassification as Serious Nonattainment
EPA has the responsibility, pursuant to sections 179(c) and
188(b)(2) of the CAA, of determining within six months of the
applicable attainment date, whether PM10 nonattainment areas have
attained the NAAQS. Section 179(c)(1) of the Act provides that these
determinations are to be based upon an area's air quality as of the
attainment date, and section 188(b)(2) is consistent with this
requirement. EPA makes the determinations of whether an area's air
quality is meeting the PM10 NAAQS based upon air quality data
gathered at monitoring sites in the nonattainment area and entered into
the Aerometric Information Retrieval System (AIRS). These data are
reviewed to determine the area's air quality status in accordance with
EPA guidance at 40 CFR part 50, Appendix K.
Pursuant to Appendix K, attainment of the annual PM10 standard
is achieved when the annual arithmetic mean PM10 concentration is
equal to or less than 50 g/m\3\. The annual average is
determined by first calculating the average PM10 concentration for
each calendar quarter. The annual average is then calculated by
averaging the four calendar quarter averages. Attainment of the 24 hour
standard is determined by calculating the expected number of
exceedances of the 150 g/m\3\ limit per year. The 24 hour
standard is attained when the expected number of exceedances is 1.0 or
less. A total of three consecutive years of clean air quality data is
generally necessary to show attainment of the 24 hour and annual
standards for PM10. A complete year of air quality data, as
referred to in 40 CFR part 50, Appendix K, is comprised of all four
calendar quarters with each quarter containing data from at least 75
percent of the scheduled sampling days.
Under section 188(b)(2)(A) of the CAA, a moderate PM10
nonattainment area must be reclassified as serious by operation of law
after the statutory attainment date if the Administrator finds that the
area has failed to attain the NAAQS. Pursuant to section 188(b)(2)(B),
EPA must publish a notice in the Federal Register identifying those
areas that failed to attain the standard and the resulting
reclassification.
C. Effect of Reclassification
PM10 nonattainment areas reclassified as serious under section
188(b)(2) of the CAA are required to submit, within 18 months of the
area's reclassification, SIP revisions providing for the implementation
of best available control measures (BACM) no later than four years from
the date of reclassification. The SIP also must contain a demonstration
that the implementation of BACM will provide for attainment of the
PM10 NAAQS no later than December 31, 2001. EPA has provided
specific guidance on developing serious area PM10 SIP revisions in
an addendum to the General Preamble to Title I of the Clean Air Act.
See 59 FR 41998 (August 16, 1994).
D. Proposed Finding of Failure to Attain
On June 7, 1995 EPA proposed to find that the Phoenix Planning Area
(PPA) had failed to attain the PM10 NAAQS by the applicable
attainment date. 60 FR 30046. This proposed finding was based on
PM10 monitoring data collected by Maricopa County during the years
1992 through 1994. The air quality monitoring data for the PPA showed
three violations of the 24 hour PM10 NAAQS in 1992 and violations
of the annual PM10 NAAQS in 1992 and 1993. The air quality
monitoring data are discussed in detail in the Notice of Proposed
Rulemaking (NPRM). 60 FR 30046, 30047. The following table summarizes
the data on which EPA has based its finding of failure to attain:
----------------------------------------------------------------------------------------------------------------
24 hour exceedances Annual exceedances
Site ----------------------------------------------------------------------------------
Conc. Date 1992 1993
----------------------------------------------------------------------------------------------------------------
4732 S. Central, Phoenix..... 171 g/m\3\ 11/20/92 .................... ....................
158 g/m\3\ 12/2/92 .................... ....................
1475 E. Pecos, Chandler...... 156 g/m\3\ 11/20/92 56 g/m\3\ 58 g/m\3\
----------------------------------------------------------------------------------------------------------------
[[Page 21374]]
On October 20, 1995, the State requested, under section 188(d) of
the CAA, that EPA extend the attainment deadline for the PPA from
December 31, 1994 to December 31, 1995. This request was based on the
lack of recorded exceedances of the PM10 NAAQS in 1994. In 1995,
however, the PPA recorded two exceedances of the 24 hour NAAQS. On June
28, 1995 a concentration of 160 g/m\3\ was recorded at the
Chandler monitoring site, and on July 30, 1995 a concentration of 252
g/m\3\ was recorded, also at the Chandler monitoring site.
Additionally, the annual average concentration at the Chandler site in
1995 was 57.9 g/m\3\. Thus, while the State technically
qualified for a one year attainment date extension, the 1995 violations
effectively moot this request because the area cannot qualify for a
second extension. Therefore, EPA does not intend to act on the State's
extension request.
II. Response to Comments on Proposed Finding
During the public comment period on EPA's proposed finding, the
Agency received comment letters from: one State legislator; the Arizona
Department of Environmental Quality (ADEQ); the Arizona Department of
Transportation (ADOT); the Arizona Motor Transport Association; the
Maricopa Association of Governments (MAG); and the Maricopa County
Board of Supervisors. The issues raised in these comment letters are
summarized below and are followed by EPA's responses.
A. Economic Impacts of EPA's Finding
Comment: EPA's determination in the proposed rulemaking that a
finding of failure to attain the PM10 standard is not subject to
certain requirements in Executive Order (E.O.) 12866 or the Unfunded
Mandates Reform Act is incorrect, as is EPA's certification that this
action does not have a significant impact on small entities.
Response: Under E.O. 12866, 58 FR 51735 (October 4, 1993), EPA is
required to determine whether regulatory actions are significant and
therefore should be subject to Office of Management and Budget (OMB)
review, economic analysis, and the requirements of the E.O. The E.O.
defines a ``significant regulatory action'' as one that is likely to
result in a rule that may meet at least one of the four criteria
identified in section 3(f), including, under paragraph (1), that the
rule may ``have an annual effect on the economy of $100 million or more
or adversely affect, in a material way, the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities.''
Sections 202, 203 and 205 of the Unfunded Mandates Reform Act of
1995 (Unfunded Mandates Act), 2 U.S.C. Secs. 1501-1571, requires EPA to
assess whether various actions undertaken in association with proposed
or final regulations include a Federal mandate that may result in
estimated costs of $100 million or more to the private sector, or to
State, local or tribal governments in the aggregate.
Under the Regulatory Flexibility Act, 5 U.S.C. Sec. 601 et seq.,
EPA must prepare a regulatory flexibility analysis assessing the impact
of any proposed or final rule on small entities. 5 U.S.C Secs. 603 and
604. Alternatively, EPA may certify that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small not-for-profit
enterprises, and government entities with jurisdiction over populations
of less than 50,000.
Under section 188(b)(2) of the CAA, EPA findings of failure to
attain are based upon air quality considerations, and reclassification
of nonattainment areas must occur by operation of law in light of
certain air quality conditions. Such findings and reclassification do
not, in-and-of-themselves, impose any new requirements on any sectors
of the economy. In addition, because the statutory requirements for the
differently classified areas are clearly defined, and because those
requirements are automatically triggered by classifications that, in
turn, are triggered by air quality values, findings of failure to
attain and reclassification cannot be said to impose a materially
adverse impact on State, local, or tribal governments or communities.
This conclusion does not in any way reflect a determination
regarding estimated or actual impacts of a reclassification on
Arizona's economy. It is important to understand that the sole
regulatory action that EPA is taking under the CAA involves only a
factual finding of whether the Phoenix area attained the PM10
standards by December 31, 1994, the statutory attainment date for
moderate areas. If EPA finds that the area has failed to attain by the
deadline, then the area is reclassified as serious, not by EPA, but by
operation of law. A finding by EPA that an area has failed to timely
attain the PM10 standards is based on air quality monitoring data
collected by Maricopa County and ADEQ from 1992 through 1994. The
statute does not require any action on EPA's part, since the CAA
specifies automatic reclassification of an area as a result of a
finding that the area has not attained the PM-10 standards. See section
188(b)(2). Because EPA's role in making such a finding is essentially
ministerial, the Agency has concluded that it does not impose any new
requirements or mandates on any sector of the State economy.
For the above reasons, EPA has determined that the finding of
failure to attain being made today would result in none of the effects
identified in section 3(f) of E.O. 12866 and is therefore not a
significant regulatory action, as defined in the E.O. Similarly, EPA
has concluded that the finding of failure to attain does not constitute
a Federal mandate within the meaning of the Unfunded Mandates Act.
Furthermore, the Agency has certified that the redesignation of the
attainment status of an area under section 107(d) of the CAA does not
have a significant economic impact on a substantial number of small
entities under the Regulatory Flexibility Act. See 46 FR 8709 (January
27, 1981). Because the regulatory impact of reclassification under
section 188(b) of the CAA is no different substantively from that
associated with designations, such actions are also not expected to
have significant impacts on small entities.
EPA wishes to emphasize, however, that the reclassification of the
Phoenix area is only the first step in developing a strategy to bring
ambient concentrations of PM10 in the area to healthful levels. As
with the State's moderate area SIP, which EPA approved on April 10,
1995 (60 FR 18010), development of a control strategy for the State's
serious area SIP will involve an assessment of the economic feasibility
of implementing any particular control measure. If Arizona determines
that a measure cannot be implemented because it is not economically
feasible, the State need only provide EPA with a reasoned justification
for that determination. EPA believes there will be sufficient
opportunity for ADEQ and other State agencies, local planning agencies,
the general public, and the regulated community to assess the economic
impacts of control measure implementation while they develop the
serious area SIP.
B. State Monitoring and Modeling Study
Comment: ADEQ claims that reclassification is not necessary because
the State and local governments have undertaken a study to better
characterize the sources contributing to the nonattainment problem in
the PPA.
[[Page 21375]]
The study will enable the State to define the control measures
necessary to attain and maintain the PM10 NAAQS. As a result the
PPA will be able to demonstrate attainment by implementing reasonably
available control measures (RACM) rather than BACM.
Response: EPA acknowledges the difficulties in assessing the
contributions from various sources to total PM10 concentrations
and fully supports the State's efforts to accurately identify those
sources which have caused the PPA to be in nonattainment of the
standards. Nonetheless, section 188(b)(2) of the CAA does not afford
EPA any discretion in determining whether the area has in fact attained
the PM10 NAAQS by the statutorily mandated attainment date. EPA
regulations generally require three years of ambient monitoring data in
order to assess an area's attainment status. See 40 CFR part 50,
Appendix K. As discussed in section I.D. of this notice, based on air
quality data collected during the years 1992 through 1994, EPA has
determined that the PPA has not attained the PM10 NAAQS.
Moreover, the State recently reported two additional violations of
the PM10 NAAQS at the Chandler monitoring site in 1995. While for
the purposes of this rulemaking EPA is only considering air quality
data from 1992 through 1994, these 1995 violations further support
EPA's determination that PPA has failed to attain the PM10
standard.
C. EPA's Current Review of the PM10 NAAQS
Comment: Reclassification of the PPA is untimely in light of the
pending revision of the PM NAAQS. State and local agencies will have to
spend considerable resources to develop a plan for a standard that may
no longer be in effect.
Response: Section 109(d)(1) of the Clean Air Act requires that
``not later than December 31, 1980, and at five-year intervals
thereafter'' EPA review and revise, if warranted, air quality criteria
and national ambient air quality standards. EPA is currently under
court order to complete its review of the particulate matter NAAQS by
June 28, 1997.
This review may or may not result in a replacement and/or revision
of the PM10 NAAQS. The Agency is currently considering the
addition of a new PM NAAQS that targets fine particulate matter, such
as particles with an aerodynamic diameter less than or equal to a
nominal 2.5 micrometers. However, the Agency is also considering
retaining a PM10 standard. Although the PM NAAQS review process is
incomplete at this time, recent epidemiologic studies show consistent
positive associations of ambient PM exposure with adverse health
effects, including mortality and morbidity. Given the significant
health effects associated with PM, vigorous enforcement of the current
PM10 requirements is critical to ensure protection of the public
health. Until a revision of the NAAQS occurs, the current NAAQS and the
requirements relating to them remain in force. In the event that a new
NAAQS is promulgated, a transition policy that addresses current
requirements and ensures protection of the public health will be
developed.
D. Air Quality Monitoring
Comment: There should be a more detailed review of the
circumstances surrounding the location of the two monitoring sites
which recorded exceedances to insure that the locations are not
anomalies improperly reflecting local conditions. It would not be
appropriate to impose a classification upon the entire region due to
what may be anomalies for just two sites out of nine.
Response: In order to meet Federal monitoring regulations, agencies
which operate air monitoring networks are required to design these
networks in order to meet certain monitoring objectives. These
objectives are to determine: 1) the highest concentrations expected to
occur in the area covered by the network; 2) representative
concentrations in areas of high population density; 3) the impact on
ambient pollution levels of significant sources or source categories;
and 4) general background concentration levels. See 40 CFR part 58,
Appendix D.
Both the South Phoenix and Chandler sites are located in order to
measure PM10 concentrations in areas of high population density.
The Maricopa County Environmental Services Department (MCESD) and ADEQ,
the agencies responsible for operating the pollutant monitoring network
in the PPA, conduct an annual review of the monitoring network as
required by Federal regulations. See 40 CFR part 58.26 and 40 CFR part
58, Appendix F. EPA believes the South Phoenix and Chandler monitoring
stations are correctly sited and meet all applicable Federal
requirements.
Comment: According to section 2.11 of the Quality Assurance
Handbook for Air Pollution Control, PM10 monitors have a precision
error of 10% when addressing the PM10 24 hour NAAQS.
Therefore, two of the recorded violations, with readings below 165
g/m3, could be within the NAAQS when this error variation is
accounted for.
Response: EPA's quality assurance procedures establish minimum
acceptable operating limits for PM10 sampling equipment. The
10% to which the commenter refers is not directly related
to the final PM10 ambient concentration, but rather to the air
flow rate through the PM10 sampler. The ambient concentration is
calculated from the particle mass collected on a filter medium, the
volume of air pulled through the filter, and the amount of time the
sampler is operated. The 10% to which the commenter refers
is the acceptable range of deviation for the air flow rate through the
sampler. Nevertheless, EPA recognizes the validity of the commenter's
concern regarding the 10% threshold. However, this 10%
threshold is not an allowance or a leeway to adjust data, rather it is
a limit which if exceeded alerts the field or laboratory monitoring
personnel to a possible sample validity problem. Readings beyond the
10% threshold can mean heavy filter loading or decreases in the sampler
flow rate. Air flow rates beyond this 10% threshold may necessitate
invalidating all samples collected since the last sampler calibration.
See Quality Assurance Handbook for Air Pollution Control, section
2.11.3.4, Sample Validation and Documentation.
Comment: According to EPA's Exceptional Event Guideline, high winds
are defined as an hourly speed of greater than or equal to 30 mph or
gusts equal to or greater than 40 mph with little or no precipitation.
The western regional climate center in Reno, Nevada reported that
November 20, 1992 was the windiest day of the quarter in the PPA with
wind speeds up to 40 mph and no precipitation. Therefore the exceedance
recorded on that date (156 g/m3) should be classified as an
exceptional event. Furthermore, all of the PM10 NAAQS violations
in the PPA were impacted by short term construction activities. The
Exceptional Event Guideline states that construction and demolition
activities are exceptional events.
Response: EPA has established criteria and procedures to identify
or ``flag'' data which may be affected by ``exceptional events'' in its
``Guideline on the Identification and Use of Air Quality Data Affected
by Exceptional Events,'' July 1986 (Guideline). Under the flagging
system, state and local air pollution control agencies are responsible
for initially identifying and documenting data influenced by
exceptional events. These agencies are expected to develop the
appropriate
[[Page 21376]]
background information necessary to support a decision to flag an
individual piece of data. The agencies must then submit the information
to EPA for concurrence. Flagging a piece of data or data set does not
exclude that data from being used for nonattainment designations or
classifications. The actual exclusion would only be allowed if, as a
result of a public review process, the responsible government agency,
in this case EPA, determines that the data are inappropriate for use in
a specific regulatory activity. Neither the MCESD nor ADEQ requested
that these data be flagged as exceptional events, nor were these data
proposed to be excluded from any specific regulatory action.
Notwithstanding the fact that the State did not initiate the
flagging process, EPA would have evaluated whether the exceedances in
question were affected by exceptional events had the commenter provided
documentation demonstrating that they qualified as such. There are
basically two issues which must be addressed in order to determine
whether an exceedance of the NAAQS was due to an exceptional event.
First, there must be a link between a specific PM10 generating
activity (e.g., forest or structural fire, construction/demolition
activity) and the suspect data. Second, there must be a determination
that the activity is not likely to recur.
Regarding high winds, the commenter only referenced part of the
definition in the Guideline of a high wind event. The definition in
full is ``hourly windspeed of greater than or equal to 30 mph or gusts
equal to or greater than 40 mph, with [little or] no precipitation. The
high wind condition with [little or] no precipitation and dry soil must
be associated with a significant contribution (estimated to be > 85% by
weight) of crustal material on the PM sampling medium.'' The commenter
did not provide any supporting information on the type of particulate
matter which contributed to the PM10 exceedance on November 20,
1992. Furthermore, no information was provided to show that this wind
event was itself exceptional, i.e. that it was not expected to recur.
As to construction activities, the commenter again only sites a
portion of the definition of construction/demolition activities that
would qualify as exceptional events. The Guideline states that
construction/demolition activities that last for only a short period of
time, are within a reasonable distance of the monitoring site and that
are implementing all reasonable control measures may be flagged as
exceptional events. Flagged data should be limited to sites that are
classified as micro- or middle-scale and downwind with respect to the
construction activity. The Chandler monitoring site is classified as a
neighborhood scale site. See 40 CFR part 58, Appendix D for an
explanation of the difference in spatial scales. As with the high wind
claim, the commenter also did not address the likelihood of the
construction activity's recurrence. In the State's approved moderate
area PM10 SIP, construction activities are recognized as
controllable sources of PM10 and are now regulated under Maricopa
County Rule 310.
To summarize, the commenter did not provide any supporting
information or data showing that the high winds or construction
activities did, in fact, have a direct causal link to the PM10
NAAQS exceedances or, if so, the magnitude of the contribution from
these sources. The commenter simply asserted that the high winds and
construction activities occurred. Furthermore, the commenter did not
address the likelihood of the recurrence of these conditions. In fact,
the SIP development process is intended to prevent exceedances from
anthropogenic activities such as construction by providing for planning
by the State and local community to help ensure such activities
adequately mitigate their contribution to PM10 air quality
problems.
Comment: The two locations where violations were recorded are only
two of nine SLAMS sites and data from the seven clean sites should also
be considered in deciding whether the PPA should be reclassified. The
recorded violations are only 14%, 5%, and 4% over the PM10 NAAQS
and these values are not ``seriously'' in excess of the PM10
NAAQS.
Response: Maricopa County's nine station network is only a
representative sample of the PPA's air quality. These nine stations
cover 2,920 square miles. Monitoring is only conducted on a one in
every six day schedule. Therefore, for every one sample taken, there
are five days for which the air quality is unknown. If there were other
sites set up to represent conditions similar to those of the violating
sites, it is possible that more violations would have been recorded.
Pursuant to 40 CFR, part 50, Appendix K, an exceedance is defined
as a value which is measured above the level of the 24 hour standard
after rounding to the nearest 10 g/m3 (i.e. values ending
in 5 or greater are rounded up). Therefore, had the highest recorded
values in the 1992 to 1994 period been 154 g/m3 or less,
the concentrations would not have been considered exceedances of the
NAAQS. However, the PM10 concentrations recorded in the Phoenix
area, 156 g/m3, 158 g/m3, and 171
g/m3, are above that level and are therefore considered
exceedances.
Further, the claim that the exceedances were not ``seriously in
excess'' of the NAAQS is without validity. The PM10 NAAQS are set
at a level required to protect public health. The standards are
designated levels, not ranges, of PM10 above which the air quality
is considered unhealthy. The reclassification of the PPA is based on
the fact that violations of the standards have occurred, and continue
to occur, rather than on the severity of the violations.
E. National PM10 Standard
Comment: EPA should not apply a nationwide PM10 standard to an
arid Southwest region such as the PPA.
Response: Section 109 of the CAA requires EPA to promulgate primary
and secondary NAAQS for certain types of air pollutants. These
standards are based on criteria which reflect current scientific
knowledge of the effect of these pollutants on public health and
welfare.
On July 1, 1987 EPA promulgated the NAAQS for PM10. 52 FR
24663 (July 1, 1987). While the types of sources and the ability to
control them differ from one area of the country to another, the human
health effects of PM10 pollution are the same whether one resides
in New York City or Phoenix. Therefore, in order to protect human
health, the standards must be the same nationwide.
However, unlike the NAAQS, the SIP development process is intended
to address variability in source types. While the CAA does impose
certain minimum control requirements, ultimately it is up to the state
and the affected local communities to choose the particular control
measures that best address their unique air pollution problem. In
developing the control measures, a state may consider the economic and
technological feasibility of implementing a particular control measure.
III. Today's Final Action
EPA is today taking final action to find that the PPA did not
attain the PM10 NAAQS by December 31, 1994, the CAA attainment
date for moderate PM10 nonattainment areas. As a result of this
final finding, the PPA is reclassified by operation of law as a serious
PM10 nonattainment area.
IV. Executive Order (EO) 12866
Under E.O. 12866, 58 FR 51735 (October 4, 1993), EPA is required to
determine whether regulatory actions
[[Page 21377]]
are significant and therefore should be subject to OMB review, economic
analysis, and the requirements of the Executive Order. The Executive
Order defines a ``significant regulatory action'' as one that is likely
to result in a rule that may meet at least one of the four criteria
identified in section 3(f), including, under paragraph (1), that the
rule may ``have an annual effect on the economy of $100 million or more
or adversely affect, in a material way, the economy, a sector of the
economy, productivity, competition, jobs, the environment, public
health or safety, or State, local, or tribal governments or
communities.''
The Agency has determined that the finding of failure to attain
finalized today would result in none of the effects identified in
section 3(f). Under section 188(b)(2) of the CAA, findings of failure
to attain and reclassification of nonattainment areas are based upon
air quality considerations and must occur by operation of law in light
of certain air quality conditions. They do not, in-and-of-themselves,
impose any new requirements on any sectors of the economy. In addition,
because the statutory requirements are clearly defined with respect to
the differently classified areas, and because those requirements are
automatically triggered by classifications that, in turn, are triggered
by air quality values, findings of failure to attain and
reclassification cannot be said to impose a materially adverse impact
on State, local, or tribal governments or communities.
V. Regulatory Flexibility
Under the Regulatory Flexibility Act, 5 U.S.C. Sec. 601 et seq.,
EPA must prepare a regulatory flexibility analysis assessing the impact
of any proposed or final rule on small entities. 5 U.S.C Secs. 603 and
604. Alternatively, EPA may certify that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small not-for-profit
enterprises, and government entities with jurisdiction over populations
of less than 50,000.
As discussed in sections II.A. and IV of this notice, findings of
failure to attain and reclassification of nonattainment areas under
section 188(b)(2) of the CAA do not in-and-of-themselves create any new
requirements. Therefore, I certify that today's final action does not
have a significant impact on small entities.
VI. Unfunded Mandates
Under sections 202, 203 and 205 of the Unfunded Mandates Reform Act
of 1995 (Unfunded Mandates Act), signed into law on March 22, 1995, EPA
must assess whether various actions undertaken in association with
proposed or final regulations include a Federal mandate that may result
in estimated costs of $100 million or more to the private sector, or to
State, local or tribal governments in the aggregate.
EPA believes, as discussed above, that the finding of failure to
attain and reclassification of the Phoenix Planning Area are factual
determinations based upon air quality considerations and must occur by
operation of law and, hence, do not impose any federal
intergovernmental mandate, as defined in section 101 of the Unfunded
Mandates Act.
List of Subjects in 40 CFR Part 81
Environmental protection, Air pollution control, Intergovernmental
relations, Particulate matter.
Dated: April 29, 1996.
Felicia Marcus,
Regional Administrator.
40 CFR part 81 is amended as follows:
PART 81--[AMENDED]
1. The authority citation for part 81 continues to read as follows:
Authority: 42 U.S.C. 7407, 7501-7515, 7601.
2. Section 81.303 is amended by revising the table for Arizona--PM-
10, to read as follows:
Sec. 81.303 Arizona.
* * * * *
Arizona--PM-10
----------------------------------------------------------------------------------------------------------------
Designation Classification
Designated Area ------------------------------------------------------------------------------
Date Type Date Type
----------------------------------------------------------------------------------------------------------------
Cochise County:
Paul Spur/Douglas planning 11/15/90 Nonattainment............... 11/15/90 Moderate.
area.
Township 23 South, Range
25 East (T23S, R25E):
T23S,R26E
T23S, R27E
T23S, R28E
T24S, R25E
T24S, R26E
T24S, R27E
T24S, R28E
Santa Cruz County:
Nogales planning area........ 11/15/90 Nonattainment............... 11/15/90 Moderate.
The portions of the
following Townships
which are within the
State of Arizona and lie
east of 111 deg.
longitude:
T23S, R13E
T23S, R14E
T24S, R13E
T24S, R14E
Rillito planning area........ 11/15/90 Nonattainment............... 11/15/90 Moderate.
[[Page 21378]]
Townships:
T11S, R9E
T11S, R10E
T11S, R11E
T11S, R12E
T12S, R8E
T12S, R9E
T12S, R10E
T12S, R11E
T12S, R12E
Pima County
Ajo planning area............ 11/15/90 Nonattainment............... 11/15/90 Moderate.
Township T12S, R6W, and
the following sections
of Township T12S, R5W:
a. Sections 6-8
b. Sections 17-20,
and
c. Sections 29-32
Maricopa and Pinal Counties
Phoenix planning area........ 11/15/90 Nonattainment............... 6/10/96 Serious.
The rectangle determined
by, and including--
T6N, R3W
T6N, R7E
T2S, R3W
T2S, R7E
T1N, R8E
Yuma County:
Yuma planning area........... 11/15/90 Nonattainment............... 11/15/90 Moderate.
Townships:
T7S-R21W, R22W;
T8S-R21W, R22W, R23W,
R24W
T9S-R21W, R22W, R23W,
R24W, R25W;
T10S-R21W, R22W,
R23W, R24W, R25W
Pinal and Gila Counties:
Hayden/Miami planning area... 11/15/90 Nonattainment............... 11/15/90 Moderate.
Townships: T4S, R16E T5S,
R16E T6S, R16E plus the
portion of Township T3S,
R16E that does not lie
on the San Carlos Indian
Reservation, and the
rectangle formed by, and
including, Townships
T1N, R13E
T1N, R15E
T6S, R13E
T6S, R15E
Gila County (part):
Payson: T10N, Sections 1-3, 1/20/94 Nonattainment............... 1/20/94 Moderate.
10-15, 22-27, and 34-36 of
R9E; T11N, Sections 1-3, 10-
15, 22- 27, and 34-36 of
R9E; T10-11N, R10E; T10N,
Sections 4-9, 16-21, and 28-
33 of R11E; T11N, Sections 4-
9, 16-21, and 28-33 of R11E..
Mohave County (part):
Bullhead City: T21N, R20-21W, 1/20/94 Nonattainment............... 1/20/90 Moderate.
excluding Lake Mead National
Recreation Area; T20N, R20-
22W; T19N, R21-22W excluding
Fort Mohave Indian
Reservation..
Rest of State................ 11/15/90 Unclassifiable..............
----------------------------------------------------------------------------------------------------------------
* * * * *
[FR Doc. 96-11736 Filed 5-9-96; 8:45 am]
BILLING CODE 6560-50-P
Complete official Federal Register PDF
FR Doc. 96-11729 Establishment of Class E Airspace; Camp Guernsey, Wyoming
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Page 21364]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11729]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 71
[Airspace Docket No. 96-ANM-5]
Establishment of Class E Airspace; Camp Guernsey, Wyoming
AGENCY: Federal Aviation Administration (FAA), DOT.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This action establishes the Camp Guernsey, Wyoming, Class E
airspace to accommodate a new instrument approach procedure at Camp
Guernsey Airport, Camp Guernsey, Wyoming. The area will be depicted on
aeronautical charts for pilot reference.
EFFECTIVE DATE: 0901 UTC, June 20, 1996.
FOR FURTHER INFORMATION CONTACT:
James Riley, ANM-532.2, Federal Aviation Administration, Docket NO. 96-
ANM-5, 1601 Lind Avenue S.W., Rentor, Washington, 98055-4056; telephone
number: (206) 227-2537.
SUPPLEMENTARY INFORMATION:
History
On February 29, 1996, the FAA proposed to amend part 71 of Federal
Aviation Regulations (14 CFR part 71) by establishing the Camp
Guernsey, Wyoming, Class E airspace designation (61 FR 7757).
Interested parties were invited to participate in the rulemaking
proceeding by submitting written comments on the proposal. No comments
were received. The coordinates for this airspace docket are based on
North American Datum 83. Class E airspace is published in Paragraph
6005 of FAA Order 7400.9C dated August 17, 1995, and effective
September 16, 1995, which is incorporated by reference in 14 CFR 71.1.
The Class E airspace designation listed in this document will be
published subsequently in the Order.
The Rule
This amendment to part 71 of Federal Aviation Regulations
establishes Class E airspace at Camp Guernsey, Wyoming. The FAA has
determined that his proposed regulation only involves an established
body of technical regulations for which frequent and routine amendments
are necessary to keep them operationally current. It, therefore, (1) is
not a ``significant regulatory action'' under Executive Order 12866;
(2) is not a ``significant rule'' under DOT Regulatory Policies and
Procedures (44 FR 11034; February 26, 1979); and (3) does not warrant
preparation of a regulatory evaluation as the anticipated impact is so
minimal. Since this is a routine matter that will only affect air
traffic procedures and air navigation, it is certified that this rule
will not have a significant economic impact on a substantial number of
small entities under the criteria of the Regulatory Flexibility Act.
List of Subjects in 14 CFR Part 71
Airspace, Incorporation by reference, Navigation (air).
Adoption of the Amendment
In consideration of the foregoing, 14 CFR part 71 is amended as
follows:
PART 71--[AMENDED]
1. The authority citation for 14 CFR part 71 continues to read as
follows:
Authority: 49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854, 24
FR 9565, 3 CFR, 1959-1963 Comp., p. 389; 14 CFR 11.69.
Sec. 71.1 [Amended]
2. The incorporation by reference in 14 CFR 71.1 of the Federal
Aviation Administration Order 7400.9C, Airspace Designations and
Reporting Points, dated August 17, 1995, and effective September 16,
1995, is amended as follows:
Paragraph 6005 Class E airspace areas extending upward from 700
feet or more above the surface of the earth.
* * * * *
ANM WY E5 Camp Guernsey, WY [New]
Camp Guernsey Airport, WY
(Lat. 42 deg.15'35'' N, long. 104 deg.43'42'' W)
That airspace extending upward from 700 feet above the surface
within a 6.7 mile radius of the Camp Guernsey Airport, and within
6.4 miles each side of the 141 deg. bearing from the Camp Guernsey
Airport, extending from the 6.7-mile radius to 17.8 miles southeast
of the Camp Guernsey Airport.
* * * * *
Issued in Seattle, Washington, on April 18, 1996.
Richard E. Prang,
Acting Assistant Manager, Air Traffic Division, Northwest Mountain
Region.
[FR Doc. 96-11729 Filed 5-9-96; 8:45 am]
BILLING CODE 4910-13-M
Complete official Federal Register PDF
FR Doc. 96-11728 Establishment of Class E Airspace; John Day, Oregon
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21364-21365]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11728]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
14 CFR Part 71
[Airspace Docket No. 96-ANM-002]
Establishment of Class E Airspace; John Day, Oregon
AGENCY: Federal Aviation Administration (FAA), DOT.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This action established the John Day, Oregon, Class E airspace
to accommodate a Global Positioning System (GPS) Standard Instrument
Approach Procedure (SIAP) to the John Day State Airport.
EFFECTIVE DATE: 0901 UTC, August 15, 1996.
FOR FURTHER INFORMATION CONTACT:
James C. Frala, Operations Branch, ANM-532.4, Federal Aviation
Administration, Docket No. 96-ANM-002, 1601 Lind Avenue, SW, Renton,
Washington 98055-4056; telephone number: (202) 227-2535.
SUPPLEMENTARY INFORMATION:
History
On March 18, 1996, the FAA proposed to amend part 71 of the Federal
Aviation Regulations (14 CFR part 71) to establish Class E airspace at
John Day, Oregon, to accommodate a new GPS SIAP to the John Day State
Airport (61 FR 10910). Interested parties
[[Page 21365]]
were invited to participate in the rulemaking proceeding by submitting
written comments on the proposal. No comments were received.
The coordinates for this airspace docket are based on North
American Datum 83. Class E airspace areas extending upward from 700
feet or more above the surface of the earth are published in paragraph
6005 of FAA Order 7400.9C dated August 17, 1995, and effective
September 16, 1995, which is incorporated by reference in 14 CFR 71.1.
The Class E airspace listed in this document will be published
subsequently in the Order.
The Rule
This amendment to part 71 of Federal Aviation Regulations
establishes Class E airspace at John Day, Oregon. The FAA has
determined that this regulation only involves an established body of
technical regulations for which frequent and routine amendments are
necessary to keep them operationally current. It, therefore, (1) is not
a ``significant regulatory action'' under Executive Order 12866; (2) is
not a ``significant rule'' under DOT Regulatory Policies and Procedures
(44 FR 11034; February 26, 1979); and (3) does not warrant preparation
of a regulatory evaluation as the anticipated impact is so minimal.
Since this is a routine matter that will only affect air traffic
procedures and air navigation, it is certified that this rule will not
have a significant economic impact on a substantial number of small
entities under the criteria of the Regulatory Flexibility Act.
List of Subjects in 14 CFR Part 71
Airspace, Incorporation by reference, Navigation (air).
Adoption of the Amendment
In consideration of the foregoing, the FAA amends 14 CFR part 71 as
follows:
PART 71--[AMENDED]
1. The authority citation for 14 CFR part 71 continues to read as
follows:
Authority: 49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854, 24
FR 9565, 3 CFR, 1959-1963 Comp., p. 389; 14 CFR 11.69.
Sec. 71.1 [Amended]
2. The incorporation by reference in 14 CFR 71.1 of the Federal
Aviation Administration Order 7400.9C, Airspace Designations and
Reporting Points, dated August 17, 1995, and effective September 16,
1995, is amended as follows:
Paragraph 6005 Class E airspace areas extending upward from 700
feet or more above the surface of the earth.
ANM-OR E5 John Day, OR
John Day State Airport, OR
(Lat 44 deg.24'14''N, long. 118 deg.57'49''W)
That airspace extending upward from 700 feet above the surface
within a 6.5-mile radius of the John Day State Airport; that
airspace extending upward from 1,200 feet above the surface within a
9-mile radius of the John Day State Airport, and that airspace
within 4 miles either side of a line bearing 076 deg. true from the
John Day State Airport, extending from the 9-mile radius to a point
38 miles northeast of the airport, and within an area bounded on the
northwest by V357, on the northeast by V4, on the southeast of V269,
and on the southwest by V500; excluding that airspace within Federal
Airways.
* * * * *
Issued in Seattle, Washington, on May 1, 1996.
Richard E. Prang,
Acting Assistant Manager, Air Traffic Division, Northwest Mountain
Region.
[FR Doc. 96-11728 Filed 5-9-96; 8:45 am]
BILLING CODE 4910-13-M
Complete official Federal Register PDF
FR Doc. 96-11727 Establishment of Class E Airspace; Hollister, CA
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21365-21366]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11727]
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
14 CFR Part 71
[Airspace Docket No. 95-AWP-13]
Establishment of Class E Airspace; Hollister, CA
AGENCY: Federal Aviation Administration (FAA), DOT.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This action establishes a Class E airspace area at Hollister,
CA. The development of a Global Positioning System (GPS) Standard
Instrument Approach Procedure (SIAP) to Runway (RWY) 31 has made this
action necessary. The intended effect of this action is to provide
adequate controlled airspace for Instrument Flight Rules (IFR)
operations at Hollister Municipal Airport, Hollister, CA.
EFFECTIVE DATE: 0901 UTC August 15, 1996.
FOR FURTHER INFORMATION CONTACT: William Buck, Airspace Specialist,
Operations Branch, AWP-530, Air Traffic Division, Western-Pacific
Region, Federal Aviation Administration, 15000 Aviation Boulevard,
Lawndale, California, 90261, telephone (310) 725-6556.
SUPPLEMENTARY INFORMATION:
History
On January 8, 1996, the FAA proposed to amend part 71 of the
Federal Aviation Regulations (14 CFR part 71) by establishing a Class E
airspace area at Hollister, CA (61 FR 549). On March 11, 1996, the FAA
issued a supplemental notice to amend this proposal to establish a
Class E airspace area at Hollister, (61 FR 9655). This action will
provide adequate controlled airspace to accommodate a GPS SIAP to RWY
31 at Hollister Municipal Airport, Hollister, CA.
Interested parties were invited to participate in this rulemaking
proceeding by submitting written comments on the proposals to the FAA.
No comments to the proposals were received. Class E airspace
designations are published in paragraph 6005 of FAA Order 7400.9C dated
August 17, 1995, and effective September 16, 1995, which is
incorporated by reference in 14 CFR 71.1. The E airspace designation
listed in this document will be published subsequently in this Order.
The Rule
This amendment to part 71 of the Federal Aviation Regulations (14
CFR part 71) establishes a Class E airspace area at Hollister, CA. The
development of a GPS SIAP to RWY 31 has made this action necessary. The
intended effect of this action is to provide adequate controlled
airspace for aircraft executing the GPS RWY 31 SIAP at Hollister
Municipal Airport, Hollister, CA.
The FAA has determined that this regulation only involves an
established body of technical regulations for which frequent and
routine amendments are necessary to keep them operationally current.
Therefore, this regulation--(1) is not a ``significant regulatory
action'' under Executive Order 12866; (2) is not a ``significant rule''
under DOT Regulatory Policies and Procedures (44 FR 10034; February 26,
1979); and (3) does not warrant preparation of a Regulatory Evaluation
as the anticipated impact is so minimal. Since this is a routine matter
that will only affect air traffic procedures and air navigation, it is
certified that this rule will not have a significant economic impact on
a substantial number of small entities under the criteria of the
Regulatory Flexibility Act.
List of Subjects in 14 CFR Part 71
Airspace, Incorporation by reference, Navigation (air).
Adoption of the Amendment
In consideration of the foregoing, the Federal Aviation
Administration amends 14 CFR part 71 as follows:
PART 71--[AMENDED]
1. The authority citation for 14 CFR part 71 continues to read as
follows:
[[Page 21366]]
Authority: 49 U.S.C. 106(g), 40103, 40113, 40120; E.O. 10854, 24
FR 9565, 3 CFR, 1959-1963 Comp., p. 389; 14 CFR 11.69.
Sec. 71.1 [Amended]
2. The incorporation by reference in 14 CFR 71.1 of the Federal
Aviation Administration Order 7400.9C, Airspace Designations and
Reporting Points, dated August 17, 1995, and effective September 16,
1995, is amended as follows:
Paragraph 6005 Class E airspace areas extending upward from 700
feet or more above the surface of the earth.
* * * * *
AWP CA E5 Hollister, CA [New]
Hollister Municipal Airport, CA
(Lat. 36 deg.53'36''N, long. 121 deg.24'37''W)
That airspace extending upward from 700 feet above the surface
within a 4.2-mile radius of the Hollister Municipal Airport and
within 2 miles each side of the 142 deg. bearing from the Hollister
Municipal Airport, extending from the 4.2-mile radius to 10 miles
southeast of the Hollister Municipal Airport and within 2 miles each
side of the 320 deg. bearing from the Hollister Municipal Airport
extending from the 4.2-mile radius to 5.4 miles northwest of the
Hollister Municipal Airport.
* * * * *
Issued in Los Angeles, California, on April 23, 1996.
Harvey R. Riebel,
Acting Manager, Air Traffic Division, Western-Pacific Region.
[FR Doc. 96-11727 Filed 5-9-96; 8:45 am]
BILLING CODE 4910-13-M
Complete official Federal Register PDF
FR Doc. 96-11644 Implementation of a Vanity Call Sign System
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21385-21386]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11644]
-----------------------------------------------------------------------
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Part 97
[PR Docket No. 93-305; FCC 96-184]
Implementation of a Vanity Call Sign System
AGENCY: Federal Communications Commission.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This action revises the amateur service rules to make clear
that a renewal application, filed at the address specified by the
Commission on the same date as the license expiration, is timely. Also,
an application for a vanity call sign, filed at the address specified
in the Wireless Telecommunications Bureau Fee Filing Guide on the same
date as the license expiration, is timely. The rule amendments are
necessary so that licensees will know that they have continuing
authority to operate, pending action on their applications. The effect
of this action is to assure licensees that their operating authority is
continued until the final disposition of the applications.
EFFECTIVE DATE: June 10, 1996.
FOR FURTHER INFORMATION CONTACT: Maurice J. DePont, Federal
Communications Commission, Washington, D. C. 20554, (202) 418-0690.
SUPPLEMENTARY INFORMATION: This is a summary of the Commission's Second
Memorandum Opinion and Order, adopted April 23 , 1996, and released May
3, 1996. The complete text of this Commission action, including the
rule amendments, is available for inspection and copying at the Federal
Communications Commission, Room 246, 1919 M Streeet, N. W., Washington,
D. C. The complete text of this Second Memorandum Opinion and Order may
also be obtained from the Commission's copy contractor, International
Transcription Services, Inc., 2100 M Street, N.W., Suite 140,
Washington, D.C. 20037, telephone (202) 857-3800.
Summary of Second Memorandum Opinion and Order
1. By this action, we are amending the amateur service rules to
state that an application for license renewal, received at the address
specified by the Commission on the same date as the license expiration,
is timely.
2. Also, by this action, we are amending the amateur service rules
to state that an application for a vanity call sign, received at the
address specified in the Wireless Telecommunications Bureau Fee Filing
Guide on the same date as the license expiration, is timely.
3. These amendments will assure licensees that they have continuing
authority to operate until there is a final disposition of the
application.
4. The amended rules are set forth below, effective June 10, 1996.
5. This Second Memorandum Opinion and Order and the rule amendments
are issued under the authority contained in 47 U.S.C. 154(i) and
303(r).
List of Subjects in 47 CFR Part 97
Call signs, Radio.
Federal Communications Commission.
William F. Caton,
Acting Secretary.
Final Rules
Part 97 of Chapter I of Title 47 of the Code of Federal Regulations
is amended as follows:
[[Page 21386]]
PART 97--AMATEUR RADIO SERVICE
1. The authority citation for Part 97 continues to read as follows:
Authority: 48 Stat. 1066, 1082, as amended: 47 U.S.C. Secs. 154,
303. Interpret or apply 48 Stat. 1064-1068, 1081-1105, as amended;
47 U.S.C. 151-155, 301-609, unless otherwise noted.
2. Section 97.21 is amended by revising the last sentence of
paragraphs (a)(3)(i) and (a)(3)(ii) to read as follows:
Sec. 97.21 Application for a modified or renewed license.
(a) * * *
(3) * * *
(i) * * * When the application for renewal of the license has been
received by the FCC at 1270 Fairfield Road, Gettysburg, PA 17325-7245
on or before the license expiration date, the license operating
authority is continued until the final disposition of the application.
(ii) * * * When the application has been received at the proper
address specified in the Wireless Telecommunications Bureau Fee Filing
Guide on or before the license expiration date, the license operating
authority is continued until final disposition of the application.
* * * * *
[FR Doc. 96-11644 Filed 5-9-96; 8:45 am]
BILLING CODE 6712-01-P
Complete official Federal Register PDF
FR Doc. 96-11643 Future Development of Paging Systems and Implementation of Section 309(j) of the Communications Act; Competitive Bidding
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21380-21384]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11643]
=======================================================================
-----------------------------------------------------------------------
FEDERAL COMMUNICATIONS COMMISSION
47 CFR Parts 22 and 90
[WT Docket No. 96-18; PP Docket No. 93-253; FCC 96-183]
Future Development of Paging Systems and Implementation of
Section 309(j) of the Communications Act; Competitive Bidding
AGENCY: Federal Communications Commission.
ACTION: Interim measure; modification.
-----------------------------------------------------------------------
SUMMARY: In this First Report and Order in WT Docket No. 96-18 and PP
Docket No. 93-253, the Commission modifies the interim measures imposed
in the Notice of Proposed Rulemaking (NPRM) in this docket. In the
NPRM, the Commission addressed how paging applications should be
treated during the pendency of this rulemaking, and imposed an across-
the-board freeze on new applications for paging licenses with an
exception for Common Carrier Paging (CCP) and Private Carrier Paging
(PCP) licensees with nationwide exclusivity. The Commission is
modifying the interim freeze imposed in the NPRM by allowing all
incumbent paging licensees subject to the interim freeze to apply for
additional transmission sites on the same channel, on a primary basis,
within 65 kilometers (40 miles) of an operating transmission site. An
application must be accompanied by a certification that the applicant
is an incumbent paging licensee, and the proposed site is within 65
kilometers (40 miles) of an authorized transmission site that was
licensed to the same applicant on the same channel on or before
February 8, 1996 and which is operational as of the date the
application for the additional transmitter site is filed. All
applications filed by CCP incumbent licensees and 929 MHz PCP incumbent
licensees on exclusive channels will be put on Public Notice to allow
for competing applications to be filed.
The Commission resumes processing all pending non-mutually
exclusive applications that were filed by incumbents with the
Commission on or before February 8, 1996. The February 8, 1996 freeze
interrupted the 30 or 60 day filing window in some cases. Therefore,
the Wireless Telecommunications Bureau will release a Public Notice
with attached copies of the prior Public Notices containing the pending
paging applications. All pending applications filed by incumbents on or
before February 8, 1996 that were not on Public Notice for the required
30 or 60 days, will be deemed to continue to be on Public Notice for
the remaining amount of time until the required 30 or 60 day window for
filing competing applications expires.
The Commission's objective in modifying the interim freeze is to
allow the incumbent paging licensees the flexibility needed to expand
paging systems to continue to serve their customers and convert to
flexible wide-area synchronous protocol technology during the interim
period, while preventing an increase in telecommunications investment
fraud.
EFFECTIVE DATE: May 10, 1996.
FOR FURTHER INFORMATION CONTACT: Mika Savir, Commercial Wireless
Division, Wireless Telecommunications Bureau, at (202) 418-0620.
SUPPLEMENTARY INFORMATION: This First Report and Order in WT Docket No.
96-18 and PP Docket No. 93-253, adopted April 22, 1996, and released
April 23, 1996, is available for inspection and copying during normal
business hours in the FCC Reference Center, Room 230, 1919 M Street
N.W., Washington D.C. The complete text may be purchased from the
Commission's copy contractor, International Transcription Service,
Inc., 2100 M Street, N.W., Suite 140, Washington D.C. 20037, (202) 857-
3800)). Synopsis of First Report and Order:
I. Background
1. In this docket, the Commission is examining the paging
regulations in light of the statutory objective of regulatory symmetry
for all Commercial Mobile Radio Services (CMRS) established in the
Omnibus Budget Reconciliation Act of 1993, Pub. L. No.
[[Page 21381]]
103-66 (1993 Budget Act). The 1993 Budget Act amended the
Communications Act to divide all mobile services into two categories,
CMRS and private mobile radio service (PMRS), and mandated that
substantially similar mobile services receive comparable regulatory
treatment. In the CMRS Third Report and Order, Implementation of
Sections 3(n) and 332 of the Communications Act, GN Docket No. 93-252,
Third Report and Order, 59 FR 59945 (November 21, 1994) (CMRS Third
Report and Order), the Commission concluded that CCP and PCP are
substantially similar services and should be subject to comparable
regulation. Under Section 6002(c)(2)(B) of the 1993 Budget Act,
reclassified PCP licensees retain their PMRS status on a grandfathered
basis until three years after the date of enactment of the legislation
which occurred on August 10, 1993. PMRS paging services, as well as
CMRS paging services, are subject to the interim and final measures in
this proceeding.
2. In the NPRM, Revision of Part 22 and Part 90 of the Commission's
Rules to Facilitate Future Development of Paging Systems and
Implementation of Section 309(j) of the Communications Act--Competitive
Bidding, WT Docket No. 96-18, Notice of Proposed Rulemaking, 61 FR
06199 (February 16, 1996) (NPRM), the Commission proposed a transition
to geographic market area licensing for all paging services. In the
NPRM, the Commission also proposed to adopt competitive bidding rules
for mutually exclusive paging applications. Additionally, the
Commission suspended acceptance of new applications for paging
channels, as of February 8, 1996. The Commission allowed incumbents to
make minor modifications to their existing systems, so long as the
modifications did not increase their composite interference contour.
The Commission also allowed all licensees with nationwide exclusivity
to continue to add sites without restrictions.
3. The Commission received comments and reply comments on the
interim proposals. Based on the arguments raised by the commenters, the
Commission concludes that partially lifting the interim freeze for
incumbent licensees would be in the public interest.
II. First Report and Order
A. Interim Freeze
4. In the NPRM, the Commission requested comment on an expedited
basis on whether, during the pendency of this proceeding, incumbents
should be allowed to file new applications to expand or modify their
existing systems in a way that would expand their existing interference
contours, with such modifications receiving only secondary site
authorization. The Commission also requested comment from interested
parties on other alternatives for allowing expansion or modification of
existing sites during the interim period. Commenters offered numerous
suggestions for partially lifting the freeze. The Commission concurs
with the commenters that partially lifting the interim freeze is
necessary to allow incumbents flexibility in serving their customers
and upgrading their equipment, and that these additions or
modifications should be given primary, not secondary, status.
5. Commenters all generally oppose the interim freeze, particularly
for incumbent licensees. Most of the commenters also oppose secondary
site licensing, on the grounds that it would discourage investment,
encourage speculation, and could result in future loss of service to
the public. Several commenters propose that as an interim measure
incumbent licensees be permitted to add sites to within 40 miles of an
operating site. Commenters also offer other suggestions such as that
incumbents be allowed to add sites if the service area of the new site
overlaps with existing authorized sites by a minimum of 50 percent, or
that they be allowed to expand their systems as long as the expansions
do not interfere with other current adjacent licensees.
6. Commenters also argue that the freeze gives undue advantage to
nationwide carriers, while decreasing the ability of the remainder of
the industry to compete. One commenter noted that the paging freeze
gives a competitive edge to Personal Communications Services (PCS).
Several commenters observed that the paging industry is converting to a
flexible wide-area synchronous protocol which requires additional
sites.
7. A group of paging carriers and paging equipment manufacturers,
the Coalition for a Competitive Paging Industry (Coalition), filed an
Emergency Petition for immediate lifting of the freeze. The Commission
incorporates the Petition into the record of this proceeding. The
Coalition also filed reply comments on the interim licensing issue,
which make many of the same arguments set forth in the Petition. To the
extent that the Commission grants limited relief from the freeze for
incumbent licensees, the Petition is granted. In all other respects,
the Commission denies the Petition. The Coalition argues that the
freeze is unlawful, arbitrary and capricious, and an abuse of
discretion on the grounds that: (1) There is insufficient spectrum
available on currently allocated paging channels to accommodate
additional systems; (2) paging carriers who are upgrading their
technology are prevented by the freeze from filing the modification
applications required to implement their networks; and (3) the
Commission has discriminated against carriers serving local and
regional markets by exempting nationwide carriers from the freeze. The
Coalition also filed an ex parte letter proposing that: (1) The
Commission accept applications filed by incumbents to expand or modify
existing systems; (2) applications would be subject to Public Notice
and competing applications if required under the rules in effect as of
February 7, 1996; (3) requests for exclusivity on 929 MHz channels
would be granted in appropriate cases under the rules in effect on
February 7, 1996; and (4) mutually exclusive applications would not be
processed until the conclusion of the rulemaking unless the parties
could agree to eliminate mutual exclusivity through agreement.
8. The Federal Trade Commission (FTC) filed comments to, inter
alia, explain the extent of the telecommunications investment fraud
associated with paging licenses. According to the FTC, the investment
fraud is of two basic types: (1) License ``application mills'' that
sell application preparation services for acquisition of wireless
licenses for a fee of several thousand dollars per license; and (2)
``build-out'' schemes, in which investors are sold interests in limited
liability companies or partnerships that claim they will acquire
licenses and build and operate telecommunications systems. Both of
these schemes are carried out by telemarketers calling unsophisticated
consumers and deceiving them about the profitability of the licenses,
and the consumers generally lose their entire investment. In January
1996, the FTC filed six actions as part of ``Project Roadblock''
against the telemarketers who sold application preparation and
acquisition services for paging licenses. The FTC observes that in the
Commission's database of pending 931 MHz applications, over 72 percent
of the applicants are individuals, rather than businesses. The FTC also
notes that 92 percent of license holders on 929 MHz channels are
individuals. According to the FTC, the high percentage of individual
applicants strongly suggests that many of these individuals are victims
of the
[[Page 21382]]
application mills. The FTC observes that telemarketing fraud has caused
the Commission to process thousands of license applications for
consumers who will never provide telecommunications services to the
public, and contributes substantially to the backlog of pending
applications and the quantity of mutually exclusive applications.
According to the FTC, the freeze against accepting new applications has
a strong deterrent effect on application mill fraud.
9. The Commission explains that it rejects the arguments of the
Coalition and other commenters that the freeze is unlawful because it
was not based on prior notice and comment. The Commission notes that
the suspension of acceptance of applications is a procedural action
that does not require notice and comment under the Administrative
Procedure Act (APA). Additionally, the Commission notes that it has
imposed similar freezes without prior notice and comment in other
rulemaking proceedings when there was a proposal to make the transition
to geographic area licensing and auction rules.
10. The Commission also rejects the arguments of commenters that
imposing a freeze was arbitrary or an abuse of the Commission's
discretion. The freeze remains essential to ensure that the goals of
the rulemaking are not compromised. The primary argument raised by
commenters against the freeze is that there is limited ``white space''
to be auctioned; however this contention is undermined by the
commenters' argument that the freeze is causing severe economic harm.
If there were in fact little or no white space left to be licensed,
maintaining the freeze would have minimal impact. The Commission notes
that while paging channels are heavily encumbered, there is some
available spectrum that is of considerable value to applicants.
11. The Commission also states that the freeze is necessary to
combat telemarketing schemes involving paging application fraud. The
FTC estimates that fraudulent investment schemes centered on acquiring
FCC licenses for wireless technologies have been the most prevalent
telemarketing investment scams of the 1990s, costing consumers hundreds
of millions of dollars. If the freeze were to be lifted, it could
inadvertently encourage a resumption of fraudulent activity by
application mills seeking to induce unsophisticated investors into
filing applications. The Commission also stated a concern that the
proposal to use auctions in this service may stimulate speculative
activity by parties seeking to warehouse free spectrum.
12. The Commission notes that the commenters have raised valid
reasons to support partially lifting the freeze for the remainder of
the interim period: the paging industry needs flexibility to make
modifications and additions to systems to continue to serve their
customers; licensees are in the process of converting to flexible wide-
area synchronous protocol technology to increase data delivery speeds
and therefore require additional base stations to maintain the existing
service area; and the nationwide carriers may have a competitive
advantage over the non-nationwide incumbent licensees in the local and
regional markets. The Commission concludes that the interim freeze
should be partially lifted for incumbent paging licensees.
13. As of May 10, 1996, the Commission is modifying the interim
freeze imposed in the NPRM, by allowing all incumbent paging licensees
subject to the interim freeze to apply for additional transmission
sites on the same channel, on a primary basis, within 65 kilometers (40
miles) of an operating transmission site. An application will be
accepted only if it is accompanied by a certification that (1) the
applicant is an incumbent paging licensee, and (2) the proposed site is
within 65 kilometers (40 miles) of an authorized transmission site that
was licensed to the same applicant on the same channel on or before
February 8, 1996 and which is operational as of the date the
application for the additional transmitter site is filed. The
applications from incumbent paging licensees on a non-nationwide CCP
channel and incumbent paging licensees on an exclusive PCP channel will
be placed on public notice and subject to competing applications within
the applicable filing window.
14. The Commission states that while it will accept initial
applications as described above only from incumbents, but it will not
limit eligibility to file competing applications once the incumbent's
initial application is filed. If no competing application is filed, the
incumbent's initial application can be granted. If a competing
application is filed, both applications will be treated as mutually
exclusive and will be held in abeyance until the conclusion of this
proceeding.
B. Interference Contour
15. In the NPRM, the Commission stated that incumbent licensees on
all bands except the nationwide channels could add sites to existing
systems, or modify existing sites during the pendency of this
rulemaking proceeding, if the addition or modification does not expand
the interference contour of the incumbent's existing system. The
Commission stated in a footnote that for such purposes, the
interference contour would be based on a median field strength of 21
dBV/m, and referenced the proposed mathematical formulas for
calculating the service and interfering contours for paging systems.
16. The Commission's reference to the proposed formula to calculate
the interference contour during the interim period caused some
confusion among the commenters. The commenters object to the proposed
formula to calculate the interference contour during the interim period
because it would shrink their current interference contour. The
commenters also contend that this proposal was unlawful because it was
retroactive and was not subject to the required notice and comment
procedures.
17. The Commission clarifies that it is not applying the proposed
interference contour formula on a retroactive basis to any current
sites. For purposes of interim licensing, incumbents may use the
interference contour defined under the current rules to determine
whether internal sites may be added or modified. The Commission notes
that this will allow 939 MHz licensees to make internal system changes
so long as they do not expand the composite circular interference
contour of their existing stations as defined in Section 22.537(f) of
the rules. The Commission also clarifies that the tables in Section
22.537(f) may be used on an interim basis by licensees on 929 MHz
exclusive channels to determine where stations may be added.
C. Exempt Services
18. Commenters have asked the Commission to clarify that the freeze
does not apply to Basic Exchange Telecommunications Radio Systems
(BETRS), Special Emergency Radio Service (SERS), and two-way mobile
telephone service on the two-way channels listed in Section 22.561 and
these rural telephone channels should be exempt from the freeze. The
Commission observes that this proceeding was initiated to examine the
paging regulations in light of the statutory objective of regulatory
symmetry for all CMRS established in the 1993 Budget Act. BETRS are
licensed under the Rural Radiotelephone Service, which is a fixed
service, not a mobile service, and by definition is not CMRS.
Implementation of Sections 3(n) and
[[Page 21383]]
332 of the Communications Act, GN Docket No. 93-252, Second Report and
Order, 59 FR 18493 (April 19, 1994) (CMRS Second Report and Order).
Therefore, BETRS are not subject to the interim paging freeze.
Similarly, conventional Rural Radiotelephone Service provided on the
channels listed in Sections 22.561 and 22.563 is not a mobile service,
and is not subject to the interim freeze in this proceeding. The
Commission is also exempting SERS from the interim freeze.
D. Processing of Pending Applications
19. In this First Report and Order, the Commission establishes
consistent procedures for processing applications filed on or before
February 8, 1996. Pursuant to Sections 22.120(d) and 22.127,
applications for 150 MHz and 450 MHz channels are placed on Public
Notice for 30 days, and applications for 931 MHz channels are on Public
Notice for 60 days to allow other applicants to file competing
applications. All applications that were filed with the Commission on
or before February 8, 1996 have been on Public Notice; however, the
February 8, 1996 interim freeze interrupted the 30 or 60 day filing
window in some cases. After the release of this First Report and Order,
the Wireless Telecommunications Bureau will release a Public Notice
with attached copies of the prior Public Notices containing the pending
paging applications. Once the Public Notice is released, all pending
applications filed by incumbents that were not on Public Notice for the
required 30 or 60 days will be deemed to be on Public Notice for the
remaining amount of time until the required 30 or 60 day period for
filing competing applications expires. The Commission will not issue an
additional Public Notice for these pending CCP applications. Upon
expiration of the remaining filing period for these pending CCP
applications filed by incumbents, the applications that are not
mutually exclusive will be processed.
20. All 929 MHz PCP exclusive applications filed by incumbents
which were processed through the frequency coordinator, and filed with
the Commission on or before February 8, 1996, and are not mutually
exclusive, will be processed. Applications for PCP channels submitted
by incumbents to the frequency coordinator but not filed with the
Commission prior to February 8, 1996, may be resubmitted to the
frequency coordinator, and then may be filed with the Commission,
provided that the applicant certifies that the applicant is an
incumbent licensee with an operating system.
E. Canadian and Mexican Coordination During the Interim Period
The Commission states that in cases where coordination must be
obtained in Canadian or Mexican border areas, licensees must continue
to file applications with the Commission to allow for such coordination
under the interim licensing procedures.
III. Conclusion
22. The Commission concludes that the revisions to the interim
measures adopted in this First Report and Order will enable paging
licensees to continue expansion of their systems and enhance the
quality of service to the public while this proceeding is pending. At
the same time, the limitations on new applications during the interim
period will prevent spectrum warehousing and deter application fraud.
The Commission emphasizes that the measures set forth in this First
Report and Order are interim measures only, and that the long-term
proposals for geographic licensing of paging channels will be
determined in the future.
IV. Procedural Matters and Ordering Clauses
A. Regulatory Flexibility Analysis
As required by Section 604 of the Regulatory Flexibility Act, the
Commission has prepared a Final Regulatory Flexibility Analysis for the
Interim Measures in the First Report and Order of the expected impact
on small entities of the modification of the interim measures.
Statement of the Need for and Objectives of Measures: In the First
Report and Order, the Commission is modifying the interim measures,
specifically, the interim freeze on new paging applications imposed in
the Notice of Proposed Rulemaking, to permit incumbent paging licensees
to apply for additional licenses to add transmission sites to existing
paging systems on the same channel as the existing systems, provided
that the additional transmission site is within 65 kilometers (40
miles) from an operating transmission site in the applicant's system.
This modification of the interim measure will allow paging companies
additional flexibility to expand their systems during the interim
period.
Summary of Significant Issues Raised by Comments to the Initial
Regulatory Flexibility Analysis (IRFA): There were no comments to the
IRFA regarding the interim measures.
All significant alternatives are discussed in the First Report and
Order.
B. Paperwork Reduction Act
This First Report and Order contains a new information collection.
The Commission, as part of its continuing effort to reduce paperwork
burdens, has submitted this to Office of Management and Budget (OMB)
for emergency approval under the Paperwork Reduction Act of 1995,
Public Law 104-13. The Commission has requested OMB approval by April
29, 1996.
Further Information: For additional information concerning the
information collections contained in this First Report and Order,
contact Dorothy Conway at (202) 418-0217 or via the Internet at
[email protected].
Supplementary Information:
Title: Revision of Part 22 and Part 90 of the Commission's Rules to
Facilitate Future Development of Paging Systems and Implementation of
Section 309(j) of the Communications Act--Competitive Bidding.
Type of Review: New Collection.
Respondents: Common Carrier Paging licensees and Private Carrier
Paging licensees filing applications for additional transmission sites.
Number of Respondents: Approximately 2000.
Estimated Time Per Response: Approximately 0.08 hours for each
respondent to read and sign the certification.
Total Annual Burden: A burden of approximately 160 hours.
Needs and Uses: On February 8, 1996, the Commission adopted a
Notice of Proposed Rule Making (NPRM) that examines ways to establish a
comprehensive and consistent regulatory scheme that will simplify and
streamline licensing procedures and provide a flexible operating
environment for both common carrier and private paging services. The
NPRM imposed an interim across-the-board freeze on new paging
applications.
On April 22, 1996, the Commission adopted the First Report and
Order that modified the interim freeze imposed in the NPRM to allow the
incumbents in the paging industry the flexibility needed to serve the
public, and upgrade to more spectrally efficient equipment. The First
Report and Order allows incumbent common carrier paging and private
carrier paging licensees to expand their current paging systems by
applying for additional transmission sites on the same channel within
65 kilometers (40 miles) from their existing operating transmission
sites. This modification of the interim measures is limited to
incumbent licensees. Paging applicants must certify in writing that:
(1) The applicant is an incumbent
[[Page 21384]]
paging licensee, and (2) the proposed site is within 65 kilometers (40
miles) of an authorized transmission site that was licensed to the same
applicant on the same channel on or before February 8, 1996 and which
is operational as of the date the application for the additional
transmitter site is filed. This modification of the interim measures is
effective May 10, 1996.
C. Ex Parte Rules--Non-Restricted Proceeding
Ex parte presentations are permitted except during the Sunshine
Agenda period, provided they are disclosed as provided in the
Commission's rules, 47 CFR 1.1202, 1.1203, 1.1206(a).
D. Authority
The above action is authorized under the Communications Act,
Secs. 4(i), 303(r), 309(c), 309(j), and 332, 47 U.S.C. 154(i), 303(r),
309(c), 309(j), and 332, as amended.
E. Ordering Clauses
It is Ordered that, pursuant to the authority of sections 4(i),
303(r), 309(c), 309(j), and 332 of the Communications Act of 1934, as
amended, 47 U.S.C. 154(i), 303(r), 309(c), 309(j), and 332, this First
Report and Order is adopted and the interim freeze set forth in the
Notice of Proposed Rulemaking in this docket is modified, effective May
10, 1996 as set forth herein.
It is further ordered that the Emergency Petition for Immediate
Withdrawal of Freeze filed by the Coalition for a Competitive Paging
Industry on February 28, 1996, is granted to the extent discussed
herein, and denied in all other respects.
List of Subjects
47 CFR Part 22
Communication common carriers, Reporting and recordkeeping
requirements.
47 CFR Part 90
Common carriers, Reporting and recordkeeping requirements.
Federal Communications Commission.
William F. Caton,
Acting Secretary.
[FR Doc. 96-11643 Filed 5-9-96; 8:45 am]
BILLING CODE 6712-01-P
Complete official Federal Register PDF
FR Doc. 96-11639 Computation of Combined Taxable Income Under The Profit Split Method When the Possession Product is a Component Product or an End- Product Form for Purposes of the Possessions Credit Under Section 936
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21366-21370]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11639]
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DEPARTMENT OF THE TREASURY
Internal Revenue Service
26 CFR Part 1
[TD 8669]
RIN 1545-AR18
Computation of Combined Taxable Income Under The Profit Split
Method When the Possession Product is a Component Product or an End-
Product Form for Purposes of the Possessions Credit Under Section 936
AGENCY: Internal Revenue Service (IRS), Treasury.
ACTION: Final regulations.
-----------------------------------------------------------------------
SUMMARY: This document contains final regulations relating to the
computation of combined taxable income under the profit split method.
These regulations amend the current regulations and provide revised
rules for taxpayers to compute combined taxable income under the profit
split method when the possession product chosen for purposes of section
936(h)(5) of the Internal Revenue Code is a component product or an
end-product form. These regulations are necessary to provide guidance
to taxpayers electing the profit split method of computing taxable
income under section 936(h)(5).
DATES: These regulations are effective May 10, 1996. See Supplementary
Information for applicability dates.
FOR FURTHER INFORMATION CONTACT: Jacob Feldman, 202-622-3870 (not a
toll-free number).
SUPPLEMENTARY INFORMATION:
Background
On January 12, 1994, the IRS published a notice of proposed
rulemaking in the Federal Register (INTL-0068-92, 59 FR 1690, 1994-1
C.B. 820) relating to the computation of combined taxable income under
the profit split method under section 936(h)(5) (relating to the
possessions credit for U.S. companies doing qualified business in
Puerto Rico and certain U.S. possessions). A number of written public
comments were received concerning the proposed regulations and a public
hearing was held on July 11, 1994. After consideration of all the
comments, the proposed regulations are adopted as revised by this
Treasury decision. The revisions are discussed below.
Discussion
The proposed regulations would amend Sec. 1.936-6(b)(1), Q&A 12.
Under the proposed regulations, combined taxable income for a taxpayer
that elects the profit split method for a possession product that is
either a component product or an end-product form would be determined
by multiplying the combined taxable income of the integrated product
that includes the possession product by a production cost ratio. In the
case of a component product, the combined taxable income of the
integrated product would be multiplied by a ratio the numerator of
which is the production costs of the component product and the
denominator of which is the production costs of the integrated product.
The combined taxable income of an end-product form would be determined
in a similar manner using the production costs of the end-product form.
The regulations were proposed to be effective for taxable years
beginning after 1993.
Taxpayers have argued that the regulations should not be adopted as
proposed because they would violate the arm's length standard under
section 482 and that a necessary consequence of the abandonment of the
arm's length standard would be distortions in taxpayers' income. That
is, income would be computed inconsistently for related versus
unrelated party sales of the same product, under the same terms and in
the same market.
The proposed regulations did not apply the arm's length standard to
component products and end-product forms under the profit-split method
because application of section 482 in this context is inconsistent with
the statutory framework. The effect of the profit split method when
applied to possession products is to minimize disputes between
taxpayers and the IRS because, unlike section 482 methods, there is no
need to perform functional analyses to allocate income among the
parties. Because Congress eliminated the section 482 analysis from the
profit split method, the proposed regulations did not reinject this
analysis into the area of intermediate products.
In response to taxpayer comments, however, the IRS and Treasury are
providing an election to taxpayers that sell the same possession
product in both component form and integrated form if the transactions
meet certain section 482 standards. This method is both simple to apply
and produces consistent results with respect to related and unrelated
party transactions. Under this method, the combined taxable income from
covered sales of the component product shall be determined by using the
same per unit combined taxable income as is derived from uncontrolled
sales of the product as an integrated product. Taxpayers may elect to
compute the combined taxable income for an end-product form in a
similar manner if all excluded components are manufactured by a member
of the affiliated group that includes the possession corporation and
also sold by the group separately in uncontrolled transactions. In that
case, the combined taxable income of the end-product form will be
computed by reducing the combined taxable income of the integrated
product that includes the end-product form by the combined taxable
income of the excluded components determined under the rules of section
936 as if the excluded components were possession products. In order to
make the election, the uncontrolled sales must meet the comparability
standards of the fourth sentence of Sec. 1.482-3(b)(2)(ii)(A), which
requires that the uncontrolled and controlled transactions have no
differences or minor differences for which adjustment can be made.
However, under a no loss limitation, in no case can the taxpayer use as
its per
[[Page 21367]]
unit combined taxable income for a component product or an end-product
form an amount that exceeds the per unit combined taxable income of the
integrated product that includes the component product or end-product
form.
In 1993, Congress adopted limitations on the amount of the section
936 credit; the taxpayer may be subject to an activity based limitation
or may elect a percentage limitation. The election for the percentage
limitation had to be made for the first taxable year beginning after
December 31, 1993. Taxpayers commented that the proposed regulations
created uncertainty with respect to the consequences of making the
percentage limitation election and, therefore, the period for making
the election should be extended until after the regulations are
finalized. This comment is adopted. Taxpayers that have not elected the
percentage limitation under section 936(a)(1) for the first taxable
year beginning after December 31, 1993, may so elect if the taxpayer
has elected the profit split method and the computation of combined
taxable income is affected by Sec. 1.936-6(b)(1) Q&A 12.
With respect to the proposed effective date, taxpayers commented
that the regulations should not be applied retroactively. One of the
justifications for the proposed rule was that it would simplify the
computation of combined taxable income and applying the regulation
retroactively would not simplify the computation because it would
require filing amended returns. This comment is adopted in part. The
regulation is effective for taxable years ending 30 days after May 10,
1996. If however, the election under paragraph (v) of A. 12 of
Sec. 1.936-6(b)(1) is made, this election must be made for the
taxpayer's first taxable year beginning after December 31, 1993, and if
not made effective for that year, the election cannot be made for any
later taxable year.
The last sentence of paragraph (vi) of A. 13 of Sec. 1.936-6(b)(1)
in the proposed regulations provided that, for purposes of determining
the estimated tax liability of an affiliate of the possessions
corporation with respect to income allocated to it from the possessions
corporation, the income would be deemed received on the last day of the
taxable year of each such affiliate in which or with which the taxable
year of the possessions corporation ended. This rule is limited to
taxable years beginning prior to January 1, 1995. For taxable years
beginning after December 31, 1994, quarterly estimated tax payments
will be required as provided under section 711 of the Uruguay Round
Agreements, Public Law 103-465 (1994), page 230, and any administrative
guidance issued by the IRS thereunder. See Rev. Proc. 95-23 (1995-1
C.B. 693).
Accordingly, the proposed regulations are finalized as proposed
except with respect to the changes discussed above and the necessary
conforming changes.
Special Analyses
It has been determined that this Treasury decision is not a
significant regulatory action as defined in EO 12866. Therefore, a
regulatory assessment is not required. It has also been determined that
this regulation does not have a significant impact on a substantial
number of small entities. Thus, the Regulatory Flexibility Act (5
U.S.C. chapter 6) does not apply to these regulations, and therefore, a
Regulatory Flexibility Analysis is not required. Pursuant to section
7805(f) of the Internal Revenue Code, the notice of proposed rulemaking
preceding these regulations was submitted to the Small Business
Administration for comment on its impact on small business.
Drafting Information
The principal authors of these regulations are Jacob Feldman and
Mary Gillmarten of the Office of Associate Chief Counsel
(International), IRS. Other personnel from the IRS and Treasury
Department participated in their development.
List of Subjects in 26 CFR Part 1
Income taxes, Reporting and recordkeeping requirements.
Adoption of Amendments to the Regulations
Accordingly, 26 CFR part 1 is amended as follows:
PART 1--INCOME TAXES
Paragraph 1. The authority citation for part 1 continues to read in
part as follows:
Authority: 26 U.S.C. 7805 * * *
Par. 2. In Sec. 1.936-6, paragraph (b)(1) is amended by:
1. Revising Q. 10.
2. Amending A. 10 by:
a. Redesignating the text of A. 10 as paragraph A. 10(i).
b. Removing the last two sentences of newly designated A.
10(i).
c. Adding paragraphs A. 10 (ii) through (v).
3. Revising the first sentence of A. 11.
4. Revising Q&A. 12.
5. Revising A. 13.
The revisions and addition read as follows:
Sec. 1.936-6 Intangible property income when an election out is made;
cost sharing and profit split options; covered intangibles.
* * * * *
(b) * * *
(1) * * *
Q. 10: If the possessions corporation is entitled to use the profit
split method in the situation described in Q. 9 (leasing units of the
possession product or use of such units in the taxpayer's own trade or
business), how should it compute combined taxable income with respect
to such units?
A. 10: (i) * * *
(ii) If the possession product is a component product or an end-
product form, the combined taxable income with respect to the
possession product shall be determined under Q&A. 12 of this paragraph
(b)(1).
(iii) For purposes of determining the basis of a component product
or an end-product form, the deemed sales price of such product must be
determined. The deemed sales price of the component product shall be
determined by multiplying the deemed sales price of the integrated
product that includes the component product by a ratio, the numerator
of which is the production costs of the component product and the
denominator of which is the production costs of the integrated product
that includes the component product. The deemed sales price of an end-
product form shall be determined by multiplying the deemed sales price
of the integrated product that includes the end-product form by a
ratio, the numerator of which is the production costs of the end-
product form and the denominator of which is the production costs of
the integrated product that includes the end-product form. For the
definition of production costs, see Q&A. 12 of this paragraph (b)(1).
(iv)(A) If combined taxable income is determined under paragraph
(v) of A. 12 of this paragraph (b)(1), in the case of a component
product, the deemed sales price shall be determined by using the actual
sales price of that product when sold as an integrated product (as
adjusted under the rules of the fourth sentence of Sec. 1.482-
3(b)(2)(ii)(A)).
(B) If combined taxable income is determined under paragraph (v) of
A. 12 of this paragraph (b)(1), in the case of an end-product form, the
deemed sales price shall be determined by subtracting from the deemed
sales price of the integrated product that includes the end-product
form (e.g., the leased property) the actual sales price of the excluded
component when sold as an
[[Page 21368]]
integrated product to an unrelated person (as adjusted under the rules
of the fourth sentence of Sec. 1.482-3(b)(2)(ii)(A)).
(v) The full amount of income received under the lease shall be
treated as income of (and be taxed to) the U.S. affiliate and not the
possessions corporation.
* * * * *
A. 11: The U.S. affiliate shall be treated, for purposes of
computing its basis in such units, as if it had repurchased such units
immediately following the deemed sale and at the deemed sales price as
provided in Q&A. 10 of this paragraph (b)(1). * * *
Q. 12: If the possession product is a component product or an end-
product form, how is the combined taxable income for such product to be
determined?
A. 12: (i) Except as provided in paragraph (v) of this A. 12,
combined taxable income for a component product or an end-product form
is computed under the production cost ratio (PCR) method.
(ii) Under the PCR method, the combined taxable income for a
component product will be the same proportion of the combined taxable
income for the integrated product that includes the component product
that the production costs attributable to the component product bear to
the total production costs (including costs incurred by the U.S.
affiliates) for the integrated product that includes the component
product. Production costs will be the sum of the direct and indirect
production costs as defined under Sec. 1.936-5(b)(4) except that the
costs will not include any costs of materials. If the possession
product is a component product that is transformed into an integrated
product in whole or in part by a contract manufacturer outside of the
possession, within the meaning of Sec. 1.936-5(c), the denominator of
the PCR shall be computed by including the same amount paid to the
contract manufacturer, less the costs of materials of the contract
manufacturer, as is taken into account for purposes of the significant
business presence test under Sec. 1.936-5(c) Q&A. 5.
(iii) Under the PCR method the combined taxable income for an end-
product form will be the same proportion of the combined taxable income
for the integrated product that includes the end-product form that the
production costs attributable to the end-product form bear to the total
production costs (including costs incurred by the U.S. affiliates) for
the integrated product that includes the end-product form. Production
costs will be the sum of the direct and indirect production costs as
defined under Sec. 1.936-5(b)(4) except that the costs will not include
any costs of materials. If the possession product is an end-product
form and an excluded component is contract manufactured outside of the
possession, within the meaning of Sec. 1.936-5(c), the denominator
shall be computed by including the same amount paid to the contract
manufacturer, less cost of materials of the contract manufacturer, as
is also taken into account for purposes of the significant business
presence test under Sec. 1.936-5(c) Q&A. 5.
(iv) This paragraph (iv) of A. 12 illustrates the computation of
combined taxable income for a component product or end-product form
under the PCR method. S, a possessions corporation, is engaged in the
manufacture of microprocessors. S obtains a component from a U.S.
affiliate, O. S sells its production to another U.S. affiliate, P,
which incorporates the microprocessors into central processing units
(CPUs). P transfers the CPUs to a U.S. affiliate, Q, which incorporates
the CPUs into computers for sale to unrelated persons. S chooses to
define the possession product as the CPUs. The combined taxable income
for the sale of the possession product on the basis of the given
production, sales, and cost data is computed as follows:
Production costs (excluding costs of materials):
1. O's costs for the component......................... 100
2. S's costs for the microprocessors................... 500
3. P's costs for the CPU's (the possession
product).............................................. 200
4. Q's costs for the computers......................... 400
5. Total production costs for the computer (Add lines 1
through 4)............................................ 1,200
6. Combined production costs for the CPU (the
possession product) (Add lines 1 through
3).................................................... 800
7. Ratio of production costs for the CPUs (the
possession product) to the production costs for the
computer.............................................. 0.667
Determination of combined taxable income for computers:
Sales:
8. Total possession sales of computers to unrelated
customers and foreign affiliates...................... 7,500
Total costs of O, S, P, and Q incurred in production of a
computer:
9. Production costs (enter from line
5).................................................... 1,200
10. Material costs .................................... 100
11. Total costs (line 9 plus line 10).................. 1,300
12. Combined gross income from sale of computers (line
8 minus line 11)...................................... 6,200
Expenses of the affiliated group (other than foreign
affiliates) allocable and apportionable to the computers
or any component thereof under the rules of Secs. 1.861-
8 through 1.861-14T and 1.936-6 (b)(1), Q&A. 1:
13. Expenses (other than research expenses)............ 980
Research expenses of the affiliated group allocable and
apportionable to the computers:
14. Total sales in the 3-digit SIC Code................ 12,500
15. Possession sales of the computers (enter from line
8).................................................... 7,500
16. Cost sharing fraction (divide line 15 by line
14)................................................... 0.6
17. Research expenses incurred by the affiliated group
in 3-digit SIC Code multiplied by 120
percent............................................... 700
18. Cost sharing amount (multiply line 16 by line
17)................................................... 420
19. Research of the affiliated group (other than
foreign affiliates) allocable and apportionable under
Secs. 1.861-17 and 1.861-14T(e)(2) to the
computers............................................. 300
20. Enter the greater of line 18 or line 19............ 420
Computation of combined taxable income of the computer and
the CPU:
21. Combined taxable income attributable to the
computer (line 12 minus line 13 and line
20)................................................... 4,800
22. Combined taxable income attributable to CPUs
(multiply line 21 by line 7) (production cost
ratio)................................................ 3,200
23. Share of combined taxable income apportioned to S
(50 percent of line 22)............................... 1,600
Share of combined taxable income apportioned to U.S.
affiliate(s) of S:
24. Adjustments for research expenses (line 18 minus
line 19 multiplied by line 7)......................... 80
25. Adjusted combined taxable income (line 22 plus line
24)................................................... 3,280
26. Share of combined taxable income apportioned to
affiliates of S (line 25 minus line 23)............... 1,680
[[Page 21369]]
(v)(A) If a possession product is sold by a taxpayer or its
affiliate to unrelated persons in covered sales both as an integrated
product and as a component product and the conditions of paragraph
(v)(C) of this A. 12 are satisfied, the taxpayer may elect to determine
the combined taxable income derived from covered sales of the component
product under this paragraph (v). In that case, the combined taxable
income derived from covered sales of the component product shall be
determined by using the same per unit combined taxable income as is
derived from covered sales of the product as an integrated product, but
subject to the limitation of paragraph (v)(D) of this A. 12.
(B) In the case of a possession product that is an end-product
form, if all of the excluded components are also separately sold by the
taxpayer or its affiliate to unrelated persons in uncontrolled
transactions and the conditions of paragraph (v)(C) of this A. 12 are
satisfied, the taxpayer may elect to determine the combined taxable
income of such end-product form under this paragraph (v). In that case,
the combined taxable income derived from covered sales of the end-
product form shall be determined by reducing the per unit combined
taxable income from the integrated product that includes the end-
product form by the per unit combined taxable income for excluded
components determined under the rules of this paragraph (v), but
subject to the limitation of paragraph (v)(D) of this A. 12. For this
purpose, combined taxable income of the excluded components must be
determined under section 936 as if the excluded components were
possession products.
(C) In the case of component products, this paragraph (v) applies
only if the sales price of the possession product sold in covered sales
as an integrated product (i.e., in uncontrolled transactions) would be
the most direct and reliable measure of an arm's length price within
the meaning of the fourth sentence of Sec. 1.482-3(b)(2)(ii)(A) for the
component product. For purposes of applying the fourth sentence of
Sec. 1.482-3(b)(2)(ii)(A), the sale of the integrated product that
includes the component product is treated as being immediately preceded
by a sale of the component (i.e. without further processing) in a
controlled transaction. In the case of end-product forms, this
paragraph (v) applies only if the sales price of excluded components
separately sold in uncontrolled transactions would be the most direct
and reliable measure of an arm's length price within the meaning of the
fourth sentence of Sec. 1.482-3(b)(2)(ii)(A) for all excluded
components of an integrated product that includes an end-product form.
For purposes of applying the fourth sentence of Sec. 1.482-
3(b)(2)(ii)(A), the sale of the integrated product that includes
excluded components is treated as being immediately preceded by a sale
of the excluded components (i.e. without further processing) in a
controlled transaction. Under the fourth sentence of Sec. 1.482-
3(b)(2)(ii)(A), the uncontrolled transactions referred to in this
paragraph (v)(C) must have no differences with the controlled
transactions that would affect price, or have only minor differences
that have a definite and reasonably ascertainable effect on price and
for which appropriate adjustments are made (resulting in appropriate
adjustments to the computation of combined taxable income). If such
adjustments cannot be made, or if there are more than minor differences
between the controlled and uncontrolled transactions, the method
provided by this paragraph (v)(C) cannot be used. Thus, for example,
these uncontrolled transactions must involve substantially identical
property in the same or a substantially identical geographic market,
and must be substantially identical to the controlled transaction in
terms of their volumes, contractual terms, and market level. See
Sec. 1.482-3(b)(2)(ii)(B).
(D) In no case can the per unit combined taxable income as
determined under paragraph (v)(A) or (B) of this A. 12 be greater than
the per unit combined taxable income of the integrated product that
includes the component product or end-product form.
(E) The provisions of this paragraph (v) are illustrated by the
following example. Taxpayer manufactures product A in a U.S.
possession. Some portion of product A is sold to unrelated persons as
an integrated product and the remainder is sold to related persons for
transformation into product AB. The combined taxable income of
integrated product A is $400 per unit and the combined taxable income
of product AB is $300 per unit. The production cost ratio with respect
to product A when sold as a component of product AB, is 2/3. Unless the
taxpayer elects and satisfies the conditions of this paragraph (v), the
combined taxable income with respect to A will be $200 per unit
(combined taxable income for AB of $300 x the production cost ratio
of 2/3). If, however, the comparability standards of paragraph (v)(C)
of this A. 12 are met, the taxpayer may elect to determine combined
taxable income of product A when sold as a component of product AB
using the same per unit combined taxable income as product A when sold
as an integrated product. However, the per unit combined taxable income
from sales of product A as a component product may not exceed the per
unit combined taxable income on the sale of product AB. Therefore, the
combined taxable income of component product A may not exceed $300 per
unit.
(vi) Taxpayers that have not elected the percentage limitation
under section 936(a)(1) for the first taxable year beginning after
December 31, 1993, may do so if the taxpayer has elected the profit
split method and computation of combined taxable income is affected by
Q&A.12 of this paragraph (b)(1).
(vii) The rules of Q&A. 12 of this paragraph (b)(1) apply for
taxable years ending 30 days after May 10, 1996. If, however, the
election under paragraph (v) of A. 12 of Sec. 1.936-6(b)(1) is made,
this election must be made for the taxpayer's first taxable year
beginning after December 31, 1993, and if not made effective for that
year, the election cannot be made for any later taxable year. A
successor corporation that makes the same or substantially similar
products as its predecessor corporation cannot make an election under
paragraph (v) of A.12 of Sec. 1.936-6(b)(1) unless the election was
made by its predecessor corporation for its first taxable year
beginning after December 31, 1993.
* * * * *
A. 13: (i) The income shall be allocated to affiliates in the
following order, but no allocations will be made to affiliates
described in a later category if there are any affiliates in a prior
category--
(A) First, to U.S. affiliates (other than tax exempt affiliates)
within the group (as determined under section 482) that derive income
with respect to the product produced in whole or in part in the
possession;
(B) Second, to U.S. affiliates (other than tax exempt affiliates)
that derive income from the active conduct of a trade or business in
the same product area as the possession product;
(C) Third, to other U.S. affiliates (other than tax-exempt
affiliates);
(D) Fourth, to foreign affiliates that derive income from the
active conduct of a U.S. trade or business in the same product area as
the possession product (or, if the foreign members are resident in a
country with which the U.S. has an income tax convention, then to those
foreign members that have a permanent establishment in the United
States that derives income in the same product area as the possession
product); and
(E) Fifth, to all other affiliates.
(ii) The allocations made under paragraph (i)(A) of this A. 13
shall be
[[Page 21370]]
made on the basis of the relative gross income derived by each such
affiliate with respect to the product produced in whole or in part in
the possession. For this purpose, gross income must be determined
consistently for each affiliate and consistently from year to year.
(iii) The allocations made under paragraphs (i)(B) and (i)(D) of
this A. 13 shall be made on the basis of the relative gross income
derived by each such affiliate from the active conduct of the trade or
business in the same product area.
(iv) The allocations made under paragraphs (i)(C) and (i)(E) of
this A. 13 shall be made on the basis of the relative total gross
income of each such affiliate before allocating income under this
section.
(v) Income allocated to affiliates shall be treated as U.S. source
and section 863(b) does not apply for this purpose.
(vi) For purposes of determining an affiliate's estimated tax
liability for income thus allocated for taxable years beginning prior
to January 1, 1995, the income shall be deemed to be received on the
last day of the taxable year of each such affiliate in which or with
which the taxable year of the possessions corporation ends. For taxable
years beginning after December 31, 1994, quarterly estimated tax
payments will be required as provided under section 711 of the Uruguay
Round Agreements, Public Law 103-465 (1994), page 230, and any
administrative guidance issued by the Internal Revenue Service
thereunder.
* * * * *
Margaret Milner Richardson,
Commissioner of Internal Revenue.
Approved: April 4, 1996.
Leslie Samuels,
Assistant Secretary of the Treasury.
[FR Doc. 96-11639 Filed 5-9-96; 8:45 am]
BILLING CODE 4830-01-U
Complete official Federal Register PDF
FR Doc. 96-11607 Audits of State and Local Governments
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21386-21387]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11607]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF TRANSPORTATION
Office of the Secretary
49 CFR Parts 18 and 90
[OST Docket No. OST-96-1343]
RIN 2105-AC44
Audits of State and Local Governments
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: In connection with the President's Regulatory Reform
Initiative, the Department of Transportation (DOT) is reviewing all of
its existing regulations. As a result of the review we have identified
49 CFR part 90 as an unnecessary regulation that should be removed. The
rule essentially repeats verbatim the requirements of Office Management
and Budget (OMB) Circular A-128, Audits of State and Local Governments.
The rule is being replaced by minor amendments to 49 CFR part 18, to
reference Federal audit requirements in OMB circulars.
DATES: This regulation is effective June 10, 1996.
FOR FURTHER INFORMATION CONTACT: Robert G. Taylor, U.S. Department of
Transportation, Office of Acquisition and Grant Management, M-62, 400
Seventh Street, S.W., Room 9401, Washington, D.C. 20590, (202) 366-
4289.
SUPPLEMENTARY INFORMATION:
Background
Audit requirements for State and local grantees are based on the
Single Audit Act of 1984 (31 U.S.C. 7501-7507). These requirements have
been implemented in OMB Circular A-128, Audits of State and Local
Governments (50 FR 19114-19119). These audit requirements have been
implemented in DOT in 49 CFR part 18 and in 49 CFR part 90, Audits of
State and Local Governments. Part 90 is merely a republication of OMB
Circular A-128. The Department has determined that part 90 is
unnecessary, and has decided to rescind part 90 and add a reference to
OMB Circular A-128 in Section 26, Non-Federal Audits, of part 18.
This action represents no change in DOT audit policy, but makes
implementation of OMB Circular A-128 consistent with the manner other
OMB management circulars are implemented. A copy of OMB Circular A-128
can be obtained from the information contact above.
A reference to OMB Circular A-133, ``Audits of Institutions of
Higher Education and Other Nonprofit Institutions,'' has also been
added to Section 26 of part 18 to inform subrecipients of State or
local governments who are institutions of higher education or other
nonprofit organizations of the audit requirements imposed on them. This
requirement is contained in 49 CFR part 19, Uniform Administrative
Requirements for Grants and Agreements With Institutions of Higher
Education, Hospitals, and Other Nonprofit Organizations.
Regulatory Analyses and Notices
Executive Order 12866 (Regulatory Planning and Review) and DOT
Regulatory Policies and Procedures
The Department of Transportation has determined that this
rulemaking is not a significant regulatory action within the meaning of
Executive Order 12866, nor a significant regulation under the
Department's Regulatory Policies and Procedures. The action is a
reissuance of current requirements. Because of this, the Department
certifies that this regulatory action is nonsignificant under the
Department of Transportation's Regulatory Policies and Procedures.
Regulatory Flexibility Act of 1980
The Regulatory Flexibility Act (5 U.S.C. 605(b)) requires that, for
each rule with a ``significant economic impact on a substantial number
of small entities,'' an analysis be prepared describing the rule's
impact on small entities and identifying any significant alternatives
to the rule that would minimize the economic impact on small entities.
We certify that these regulations will not have a significant economic
impact on a substantial number of small entities because they do not
affect the amount of funds provided in the covered programs, but rather
reissue administrative and procedural requirements.
Executive Order 12612 (Federalism Assessment)
This action has been analyzed in accordance with the principles and
criteria contained in Executive Order 12612. The rules primarily apply
to State and local governments, but this is merely a reissuance of
current requirements. Accordingly, the Department certifies that this
action does not have sufficient Federalism implications to warrant a
full Federalism Assessment under the principles and criteria contained
in Executive Order 12612.
Paperwork Reduction Act
There are no additional collection of information requirements in
this final rule.
Justification to Issue Final Rule
Under the Administrative Procedure Act, to issue a final rule
without an NPRM, it is necessary to make a finding that issuing an NPRM
would be impractical, unnecessary, or contrary to the public interest.
This action involves no substantive change in policy, but makes
implementation of OMB Circular A-128 consistent with implementation of
other OMB Circulars. Instead of a rule that republished OMB Circular A-
128, we are incorporating the Circular by reference. Since an NPRM
would not result in the receipt of useful information, its issuance is
unnecessary. The action is in the public interest because, in
accordance with the President's regulatory reinvention efforts, we are
eliminating a duplicative regulation.
List of Subjects
49 CFR Part 18
Accounting, Contract programs, Grant programs, Grants
administration, Intergovernmental relations, Reporting and
recordkeeping requirements.List of
[[Page 21387]]
49 CFR Part 90
Audits, Grant programs, Grants administration.
Issued this 1st day of May 1996 at Washington, D.C.
Federico Pena,
Secretary of Transportation.
Accordingly, for the reasons set forth above, Subpart A of Title 49
of the Code of Federal Regulations is amended as set forth below.
PART 18--UNIFORM ADMINISTRATIVE REQUIREMENTS FOR GRANTS AND
COOPERATIVE AGREEMENTS TO STATE AND LOCAL GOVERNMENTS
1. The authority for Part 18 continues to read as follows:
Authority: 49 USC 322(a).
2. Section 18.26 is amended by adding paragraphs (d) and (e) to
read as follows:
Sec. 18.26 Non-Federal Audits.
* * * * *
(d) Governmental recipients and subrecipients are subject to the
Single Audit Act of 1984 (31 U.S.C. 7501-7507), and OMB Circular A-128,
``Audits of State and Local Governments.''
(e) Subrecipients of Federal assistance that are institutions of
higher education or other nonprofit organizations are subject to OMB
Circular A-133, Revised, ``Audits of Institutions of Higher Education
and Other Non-Profit Institutions.'' State and local governments may
choose to apply the provisions of OMB Circular A-128 to certain public
hospitals and institutions of higher education.
PART 90--[REMOVED]
3. Part 90 is hereby removed.
[FR Doc. 96-11607 Filed 5-9-96; 8:45 am]
BILLING CODE 4910-62-P
Complete official Federal Register PDF
FR Doc. 96-11494 Airworthiness Standards; Transport Category Rotorcraft Performance
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21894-21901]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11494]
[[Page 21893]]
_______________________________________________________________________
Part V
Department of Transportation
_______________________________________________________________________
Federal Aviation Administration
_______________________________________________________________________
14 CFR Part 29
Airworthiness Standards: Transport Category Rotorcraft Performance;
Final Rule
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and
Regulations
[[Page 21894]]
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Part 29
[Docket No. 24802; Amendment No. 29-40]
RIN 2120-AB36
Airworthiness Standards; Transport Category Rotorcraft
Performance
AGENCY: Federal Aviation Administration (FAA), DOT.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This rule adopts new and revised airworthiness standards for
the performance of transport category rotorcraft. The changes define
more clearly the factors for determining takeoff, climb, and landing
performance requirements. These changes provide an improved level of
safety associated with recent technological advances in the design of
turboshaft engines and rotorcraft.
EFFECTIVE DATE: June 10, 1996.
FOR FURTHER INFORMATION CONTACT: T.E. Archer, Policy and Procedures
Group (ASW-110), Rotorcraft Standards Staff, Aircraft Certification
Service, Federal Aviation Administration, Fort Worth, Texas 76193-0110,
telephone (817) 222-5126.
SUPPLEMENTARY INFORMATION:
Background
This final rule is based on a Notice of Proposed Rulemaking (NPRM)
(Notice 90-1), issued January 2, 1990 (55 FR 698, January 8, 1990). The
NPRM was preceded by an Advance Notice of Proposed Rulemaking (ANPRM)
(Notice 85-19) issued October 9, 1985 (50 FR 42126, October 17, 1985),
and by a public meeting on April 30, 1986 (51 FR 4504, February 5,
1986), in Fort Worth, Texas. A transcript of that meeting is contained
in the docket for this rulemaking. Supplemental Notice of Proposed
Rulemaking (SNPRM) (Notice 90-1A), issued June 15, 1994 (59 FR 33598,
June 29, 1994), modified Notice 90-1 by including a minimum descent
height of 15 feet.
Amendment 29-21 (48 FR 4373, January 26, 1983) revised the
transport category rotorcraft airworthiness requirements to provide for
an increased level of safety in several areas, including performance.
Subsequently, a Federal Aviation Administration (FAA) program to
develop guidance material (Advisory Circulars 27-1 and 29-2A) for
certification of rotorcraft in accordance with the requirements of
Title 14 of the Code of Federal Regulations (Title 14) part 29 (part
29) revealed a need for some additions to and clarification of the
provisions of Amendment 29-21. Those additions and clarification are
included in this amendment.
Amendment 29-21 modified the applicability limits of Categories A
and B of Transport Category Rotorcraft. Category A rotorcraft must meet
a higher level of safety, including the requirement to have multiple
engines, and be able to continue safe flight after an engine failure.
Category B rotorcraft may be either single or multiengine, but the
changes adopted in Amendment 29-21 limited this category further to a
maximum capacity of nine passengers and 20,000 pounds gross weight. No
changes are made to those limits in this amendment.
A significant element of Notice 90-1 was a proposed minimum climb
gradient for the Category A takeoff path. This standard was proposed to
standardize the climb gradient for helicopters regardless of their
airspeeds and to facilitate heliport planning. The present standard
requires a minimum rate of climb for the takeoff path; however,
recently certificated rotorcraft, as well as most rotorcraft currently
under development, produce maximum rates of climb at higher airspeeds
than the previous generation of rotorcraft. For a specific rate of
climb, the climb gradient decreases as climb airspeed increases. This
results in a shallower climb gradient for modern, high-speed rotorcraft
than for older, slow-speed rotorcraft. Notice 90-1 proposed a minimum
climb gradient based on the present rate-of-climb requirement and the
lower airspeed of older rotorcraft. At the time Notice 90-1 was issued,
FAA analysis suggested that this change would have involved an
acceptably small weight (payload) penalty. However, more precise data
supplied by the commenters in response to the notice indicate there
would be a payload penalty of 450 pounds or greater for a current
10,000-pound class helicopter. This could represent as much as 20 to 25
percent of the passenger payload, which one commenter characterized as
totally unacceptable. Upon reconsideration, the FAA agrees that the
proposal would have a significantly more burdensome effect and would
not be cost beneficial, and as noted in the following discussion, the
proposal for requiring minimum climb gradient is not adopted in this
rule.
All interested persons have been given an opportunity to
participate in the making of these amendments, and due consideration
has been given to all comments received. Except for the change
described above and for the nonsubstantive, editorial, and clarifying
changes as discussed herein, the proposals have been adopted as
proposed.
Discussion of Comments
Five commenters each responded to Notices 85-19 and 90-1. These
commenters represent worldwide manufacturers, operators, and
airworthiness authorities. The commenters' recommendations and the
suggested changes are summarized in the following discussions. Four
commenters responded to Notice 90-1A and all agreed with that proposal.
14 CFR 29.1 Applicability
Notice 90-1 proposed to change the reference in paragraph (e) from
Secs. 29.79 to 29.87, which is redesignation of the section number for
the height-velocity envelope. There were no comments; therefore, the
proposal is adopted.
New 14 CFR 29.49 Performance at Minimum Operating Speed (Old
Sec. 29.73)
Notice 90-1 proposed to redesignate Sec. 29.73 as Sec. 29.49 to
relocate the requirements for helicopter hover performance. For
transport category helicopters, hover performance is analogous to the
stall speed for transport category airplanes and provides the basis for
all other performance requirements. Therefore, by placing the
requirements for hovering performance first, the other requirements
more logically follow.
One commenter proposes a requirement for one-engine-inoperative
(OEI) hover performance both in and out-of-ground effect (OGE). This
comment, also made in response to the ANPRM, is beyond the scope of
this rule as proposed in the notice.
This commenter also recommends that OGE controllability (in 17-knot
winds from any direction) should also be required. The FAA disagrees.
Past FAA policy has permitted OGE performance to be presented in zero
wind if a minimum of yaw control remains (i.e., must be able to
generate a positive yaw rate) or to be demonstrated with some wind
condition if the demonstrated conditions are clearly identified in the
Rotorcraft Flight Manual (RFM). The validity of this policy has been
borne out by good service experience; therefore, the 17-knot criteria
are not considered necessary in determining OGE controllability.
Therefore, the FAA considers the calm-wind OGE hover performance data
with no related controllability limit are the minimum data that should
be provided, and the amendment is adopted as proposed. The
[[Page 21895]]
requirement to provide performance information about OGE hover and the
maximum safe wind for the data presented is clarified in the new
Sec. 29.1587(a)(6) and revised Sec. 29.1587(b)(8).
14 CFR 29.51 Takeoff Data: General
Notice 90-1 proposed to change the sections referenced in the
introductory text of paragraph (a) to correspond to the applicable
sections numbered in accordance with these new amendments. No comments
were received; therefore, the proposal is adopted as proposed.
14 CFR 29.53 Takeoff: Category A
This proposal would separate, in the text, the Category A takeoff
requirement from the definition of a decision point. No comments were
received; therefore, the proposal is adopted as proposed.
New 14 CFR 29.55 Takeoff Decision Point: Category A
Notice 90-1 proposed to add this new section to redefine the
takeoff critical decision point (CDP) previously contained in
Sec. 29.53; it further proposed to remove the requirement to identify
the CDP by height and airspeed, since height alone or other factors may
be more appropriate. A commenter suggests that the section title and
other references to ``critical decision point'' be changed to ``takeoff
decision point (TDP).'' The commenter notes that TDP is compatible with
the term ``landing decision point (LDP)'' already in other regulatory
parts. The FAA agrees; accordingly, ``critical decision point'' is
changed to ``takeoff decision point.''
Additionally, a commenter to Sec. 29.59 states that engine failure
and the TDP do not occur at the same time because of necessary pilot-
recognition time. The FAA agrees that a time interval for pilot
recognition of the engine failure must be included when establishing
the TDP. Calculating a pilot-recognition time interval when determining
the TDP is a natural part of the TDP-determining process. Current
industry practice already adequately considers this pilot-recognition
time interval in determining the TDP. Therefore, to explicitly state
this requirement in the regulations imposes no additional economic
burden on manufacturers. Also, to harmonize Title 14 and the Joint
Aviation Requirements (JAR's), the certification requirements for the
Joint Aviation Authorities (JAA) of Europe, an explicit adoption of the
pilot-recognition time interval is necessary. Therefore, since a pilot-
recognition time interval is currently being used by manufacturers, and
the FAA and the manufacturers are interested in harmonizing Title 14
and the JAR's, a new paragraph (c) has been added to Sec. 29.55 to
require that a pilot-recognition time interval be included in the TDP
determination.
This section is adopted with changes as discussed.
14 CFR 29.59 Takeoff Path: Category A
Notice 90-1 proposed to move the rejected takeoff requirements to a
new Sec. 29.62 and more clearly define the takeoff path from the start
of the takeoff to completion at 1,000 feet above the takeoff surface.
It also proposed the new phrase ``critical decision point,'' now
changed to ``takeoff decision point'' as explained in new Sec. 29.55.
The most significant proposed change was to establish minimum climb
gradients along the takeoff path. Present requirements specify only a
rate of climb. The use of gradients would have assisted heliport
designers and provided additional safe ground clearance. The FAA
estimated that inclusion of these gradients would introduce only a
slight performance penalty. However, as discussed earlier, more precise
data submitted by commenters indicate that adopting these gradients
would result in an unanticipated decrease in the payload of a 10,000-
pound class rotorcraft. Therefore, present rate-of-climb requirements
are retained; the proposed minimum climb gradient is not adopted; and
the remaining paragraphs of Sec. 29.59 are renumbered accordingly.
One commenter proposes that a new section be introduced to require
information on the takeoff path acceleration segment distance when
accelerating from VTOSS to Vy and that Sec. 29.1587 also be
amended to require these data. The commenter's proposal is beyond the
scope of Notice 90-1; therefore, the proposal is not included in the
amendment as adopted but may be appropriate for future rulemaking.
Another commenter disagrees that engine failure and CDP (now TDP)
occur at the same time. The FAA agrees as discussed previously under
Sec. 29.55. Accordingly, the proposed Sec. 29.59(a)(2) has been
reworded by changing critical decision point to engine failure point;
and by adding the phrase, ``. . . continue to the TDP, and then . . .''
to paragraph (a)(3). These additions clarify that consideration of the
time interval between engine failure and the pilot's recognition of the
failure is necessary in establishing TDP.
Notice 90-1, with respect to loss of altitude after engine failure,
proposed no minimum height during descent to attain VTOSS except
that touchdown should not occur. Also, Notice 90-1 proposed that a
minimum ground clearance be determined during certification and the
data included in the RFM. Several commenters objected to the proposal
and stated that a minimum ground clearance value should be specified in
the rule. Wide support was expressed by European authorities,
manufacturers, and operators to limit the descent to not less than 15
feet above the takeoff surface. Also, this minimum height was reflected
in the European JAA, Notice of Proposed Amendment (NPA) 29-2,
Preliminary Issue 1. However, since Notice 90-1 proposed to eliminate
the existing 35-foot minimum height of part 29, requiring a new minimum
height of a specified value in excess of that proposed was more
stringent than that proposed in Notice 90-1. Therefore, the FAA issued
Notice 90-1A to include a minimum descent height of 15 feet and all
commenters agreed. Hence, the minimum descent height of 15 fee is
adopted as proposed by Notice 90-1A. However, the paragraph is shown as
(e) rather than (g) as proposed by Notice 90-1A due to renumbering as
discussed previously.
New 14 CFR 29.60 Elevated Heliport Takeoff Path: Category A
Notice 90-1 proposed to add this section to introduce the
requirements for pinnacle takeoff path, Category A. However, two
commenters suggest using the term ``elevated'' rather than ``pinnacle''
since ``elevated'' is a more common term. The FAA agrees, and the word
``pinnacle'' has been replaced with ``elevated heliport'' wherever
used. Several commenters also recommend that the requirement for
takeoff climb gradients be deleted from this section. Therefore, as in
the ground-level takeoff path, the climb gradients proposed for this
section have also been removed because data submitted by commenters
indicate that adopting these gradients would result in an unanticipated
decrease in payload.
However, the FAA notes that the proposal for this section was not
clear in Notice 90-1. The section, as proposed, would require a
continuous maneuver from the start of the takeoff unit reaching 1,000
feet above the takeoff surface with two specific rate-of-climb
requirements at 200 and 1,000 feet above the takeoff surface. A
continuous climb was never intended by the FAA. For example, if the
descent below the takeoff surface is 200 feet, using a continuous climb
standard would require a total initial climb of 400 feet to regain a
point 200 feet above the takeoff surface. Therefore, climbing at a rate
of 100 feet per minute would take
[[Page 21896]]
4 minutes to regain a point 200 feet above the takeoff surface while
the current One Engine Inoperative (OEI) standards only require that
2\1/2\ minutes of emergency power be available. Hence, the time for
this descent-climb would not be compatible with the time-limited OEI
power level that is permitted. Therefore, this paragraph has been
clarified to indicate that the distances to be measured will be the
vertical magnitude of any descent below the takeoff surface and the
horizontal distance from the start of the takeoff to the point where a
positive rate of climb is established at an airspeed of at least
VTOSS. This will be considered to be the end of the takeoff
distance. (See Sec. 29.61.) From the end of the takeoff distance, climb
data will be used for the remainder of takeoff path planning. The rate-
of-climb requirements at 200 and 1,000 feet above the takeoff surface
will remain the same but will be clearly identified as separate
requirements and not a part of a continued takeoff maneuver. Climb
gradients were also included in the proposal but, as previously
discussed, are not adopted. This section is adopted with changes as
discussed.
New 14 CFR 29.61 Takeoff Distance: Category A
Notice 90-1 proposed to add a new section to define more clearly
the parameters to be used in determining takeoff distance. No comments
were received on this proposal. However, in view of the previous
discussion of elevated heliports and the changes to Sec. 29.60, a
second paragraph is added to more clearly define takeoff distances.
Also, as discussed for the new Sec. 29.59, a requirement for
considering the pilot recognition interval following engine failure is
recognized in the new Sec. 29.61. The addition of Sec. 29.61(b) states
explicitly that the takeoff distance for elevated heliports is defined
the same as that for nonelevated heliports except that there is no
requirement that the rotorcraft remain at least 35 feet above the
takeoff surface. This provision harmonizes Title 14 and the JAR.
Section 29.61(b) relieves applicants from the requirement to attain and
maintain at least 35 fee of altitude when determining the takeoff
distance from an elevated heliport. Thus, the takeoff distance will be
shorter for rotorcraft that take off from an elevated heliport. Thus,
the takeoff distance will be shorter for rotorcraft that take off from
an elevated heliport that the distance needed to reach 35 feet above
the takeoff surface as required by Sec. 29.61(a) for rotorcraft that
take off from a nonelevated heliport. This reduction in takeoff
distance will result from an exchange of the inherent altitude of the
elevated heliport for airspeed and subsequently rate of climb. The FAA
has determined that this relieving provision will neither increase the
economic burden on any applicant nor increase the scope of this rule.
Therefore, the proposal is adopted with the noted changes.
New 14 CFR 29.62 Rejected Takeoff: Category A
Notice 90-1 proposed to separate the text of the rejected takeoff
criteria from the takeoff path section and impose the restriction for
the use of only primary controls while airborne. No comments were
received; therefore, the proposal is adopted with the change of CDP to
TDP, the change of ``takeoff decision'' to ``engine failure,'' and the
addition of ``the rotorcraft continuing to takeoff decision point,'' as
explained in the discussion of new Sec. 29.55.
New 14 CFR 29.64 Climb: General
This new section relocates and clarifies the general climb
requirements. No comments were received; therefore, the proposal is
adopted without change.
14 CFR 29.65 Climb: All Engines Operating
Notice 90-1 proposed to add a general requirement to determine
Category a rotorcraft climb performance. Currently Category A
rotorcraft climb performance is required only when VNE (never-
exceed speed) is less than best climb speed (VY) at sea level. No
comments were received; therefore, the proposal is adopted without
change.
14 CFR 29.67 Climb: One-engine-Inoperative
Notice 90-1 proposed to include the takeoff climb gradients as a
part of the general climb requirement, as well as the OEI climb
requirements to be met at 200 and 1,000 feet above the takeoff surface.
Commenters recommend that the climb gradient requirements be
removed. The FAA agrees because data submitted by commenters indicate
that adopting these gradients would result in an unanticipated decrease
in payload. Therefore, the proposed climb gradient requirements are not
adopted. However, the rate of climb requirements are adopted as
proposed. Also, various clarifying word changes have been made
including adding the words ``climb following'' before ``takeoff'' in
paragraph (a)(2)(ii) to clarify that the unfavorable center of gravity
applies to the climb following takeoff. The proposal is adopted with
the noted changes.
14 CFR 29.75 Landing: General
Notice 90-1 proposed to revise the general landing requirements to
separate specific requirements and to provide references to those
specific landing requirement sections. No comments were received;
therefore, the proposal is adopted without change.
14 CFR 29.77 Landing Decision Point
Notice 90-1 proposed to add the new requirement for designation of
a landing decision point (LDP), which has been an industry practice
although not required in all recent Category A certifications. No
comments were received; therefore, the proposal is adopted without
change except for clarifying that, in accordance with the discussion
for Sec. 29.55, pilot recognition time must be considered.
14 CFR 29.79 Landing: Category A
Notice 90-1 proposed to establish the Category A landing
requirements as a separate section with only minor revision from the
present requirements. One commenter discusses studies and computer
predictions for approaches and landings at elevated heliports but does
not propose any changes. Since no changes were recommended, and the FAA
does not see a need for any changes based on the commenters'
discussion, the proposal is adopted without change.
New 14 CFR 29.81 Landing Distance: Category A
Notice 90-1 proposed a new section to require landing distances to
be determined from specific heights. One commenter suggests that the
proposed flight profile between LDP and touchdown using an elevated
heliport is unduly restrictive. This comment was based on the
commenter's concern that the proposal would require consideration of a
25-foot high screen at the approach edge of the elevated heliport. The
FAA notes that this is not the intent of this section. The proposed
horizontal landing distance determined from a point 25 feet higher than
the elevated heliport need not be contained within the heliport landing
surface. ``Pinnacle'' has been changed to ``elevated heliport'' in
accordance with previous discussions. Therefore, the proposal is
adopted with the change as noted.
New 14 CFR 29.83 Landing: Category B
Notice 90-1 proposed a new Sec. 29.83 that included moving the
Category B landing requirement presently in Sec. 29.75(c) into this new
section and required landing distances to be determined power-on rather
than power-off. One commenter suggests
[[Page 21897]]
deleting the requirement to avoid the unsafe area of the height-
velocity (HV) envelope since Category B rotorcraft with nine or fewer
passengers and less than 20,000 pounds do not have the HV envelope as a
limitation and may transit the unsafe area of the HV envelope during
landing. The FAA disagrees. While the commenter is correct about the HV
envelope not being a limitation for Category B rotorcraft with nine or
fewer passengers, the FAA cannot agree with presenting data that
include normal operations within the unsafe area of the HV envelope.
Certain operations (e.g., external loads and hoist work) are not
necessarily limited by the type certification HV envelope; however, the
operator still should be aware that the operations do not involve
normal procedures, and the operator should evaluate the risk in
accordance with the applicable regulations (e.g., part 133). Therefore,
the proposal is adopted without change.
New 14 CFR 29.85 Balked Landing: Category A (Old Sec. 29.77)
Notice 90-1 proposed to redesignate present Sec. 29.77 as a new
Sec. 29.85, to clarify the relationship between the landing decision
point and balked landing, and to remove the prohibition against
descending below 35 feet above the landing surface. The proposal only
specified that the rotorcraft ``not touch down'' during descent. One
commenter proposes that some minimum height be required. As previously
discussed under Sec. 29.59, the FAA agrees; however, Notice 90-1
proposed to allow the rotorcraft to descend below the current 35-foot
height as long as it does not touch down. Therefore, the FAA issued
Notice 90-1A to include the 15-foot minimum descent height. Three
commenters to Notice 90-1A fully agreed with the proposed changes. One
commenter agreed provided the working for Sec. 29.85(c) read
identically to the wording of Notice 90-1. However, it was necessary to
amend the wording in proposed paragraph (c) to add the minimum descent
height restriction requirements. Otherwise, the wording is identical.
Also, as previously discussed the term ``elevated'' will be used rather
than ``pinnacle.'' Therefore, the proposal is adopted by adding the 15-
foot minimum descent height and the amended wording to paragraph (c)
and by adding the phrase ``failed and failure recognized'' to paragraph
(b) to specify that the time interval for pilot recognition of engine
failure must be considered as discussed in Sec. 29.55.
New 14 CFR 29.87 Height-velocity Envelope (Old Sec. 29.79)
Notice 90-1 proposed to redesignate Sec. 29.79 as a new Sec. 29.87
and to revise the engine power conditions to be used. No comments were
received; therefore, the proposal is adopted with only editorial
changes.
14 CFR 29.1323 Airspeed Indicating System
Notice 90-1 proposed to change the term ``height-speed'' to
``height-velocity'' to agree with other changes in the proposal. No
comments were received; therefore, the proposal is adopted without
change.
14 CFR 29.1587 Performance Information
Notice 90-1 proposed to change this section to conform to other
changes in the proposal. One commenter suggests requiring, as
performance information, the steady gradient of climb for each weight,
altitude, and temperature for which takeoff data are scheduled for the
two conditions between the end of the takeoff and at 1,000 feet above
the takeoff surface. The FAA does not agree. This would require a
significant increase in the number of flight tests for compilation of
data and for FAA verification of this data, with resulting significant
adverse economic impact and no perceived safety benefits. As discussed
with respect to the new Sec. 29.49, the requirement to provide OGE
performance data, including the maximum safe wind for the data
presented, is added to the Category A requirements in
Sec. 29.1587(a)(6). Also, Sec. 29.1587(b)(8) is revised to reflect that
OGE performance data, including maximum safe wind for the data
presented, is no longer optional. Even though the new paragraph (a)(6)
and the revised paragraph (b)(8) were not proposed, they only require
the presentation in the Rotorcraft Flight Manual of the new OGE
performance data, including the maximum wind for the data presented.
The collection of the data is now required by the new Sec. 29.49. New
paragraph (a)(6) and revised paragraph (b)(8) state explicitly what
would otherwise be required during the certification process to
demonstrate compliance with the new required Sec. 29.49. In addition to
clarifying Sec. 29.49(c), the new paragraph (a)(6) for Category A
rotorcraft and the revised paragraph (b)(8) for Category B rotorcraft
have identical provisions and additionally harmonize the FAR and the
JAR. Based on these factors, the minimal burden placed on manufacturers
of presenting the data that they are required to develop, and the
remote likelihood of an adverse comment, it is unnecessary to solicit
prior public comment on these nonsubstantive changes. Therefore, the
proposal is adopted with the noted changes.
Regulatory Evaluation Summary
Changes to federal regulations must undergo several economic
analyses. First, Executive Order 12866 directs Federal agencies to
promulgate new regulations or modify existing regulations only if the
potential benefits to society outweigh the potential costs. Second, the
Regulatory Flexibility Act of 1980 requires agencies to analyze the
economic impact of regulatory changes on small entities. Finally, the
Office of Management and Budget directs agencies to assess the effects
of regulatory changes on international trade. In conducting these
assessments, the FAA has determined that this rule: (1) Will generate
benefits exceeding its costs and is not ``significant'' as defined in
Executive Order 12866; (2) is not ``significant'' as defined in DOT's
Policies and Procedures; (3) will not have a significant impact on a
substantial number of small entities; and (4) will not impact
international trade. These analyses, available in the docket, are
summarized below.
Cost/Benefit Analysis
The rule includes 31 changes to 21 sections of part 29. Twenty
eight of the changes are either editorial in nature or update the
regulations to correspond with current technology. Three changes, as
discussed below, were singled out for study because they are more
substantive in terms of cost and/or benefit impact. The FAA has
determined that these requirements will have no or negligible economic
impacts on manufacturers and operators.
Section 29.49(b)--Performance at Minimum Operating Speed (Category
B Hover Performance). This rule renumbers Sec. 29.73 to 29.49, deletes
paragraph (b)(2), and removes the minimum hover performance requirement
for Category B helicopters (but still requires that hover performance
data be developed and provided by the manufacturer). There will be no
cost impact resulting from this change, since test requirements are
unchanged and design changes are not required. Although the same amount
of hover performance data will still be required from manufacturers,
operators will benefit by being able to capitalize on a small increase
in gross weight and payload.
Section 29.49(c)--Performance at Minimum Operating Speed (Out-of-
[[Page 21898]]
Ground Effect Hover Performance). The rule will require that
manufacturers provide out-of-ground effect (OGE) hover ceiling data to
operators. Manufacturers have historically provided this information on
a voluntary basis. Industry sources estimate that requiring OGE hover
data will add, at most, an additional 3 to 5 flight test hours. At a
cost of $24,800 per flight test hour, this represents an additional
cost to manufacturers of $74,400 to $124,000 (in 1994 dollars) per
certification.
OGE hover performance data is needed by operators that conduct
external lift operations. If an operator were to conduct external lift
operations without OGE hover data, the operator might pick up
excessively heavy loads. While a single excessive load would not
necessarily lead to an accident, it could create excessive stress on
the dynamic components of the helicopter that could eventually lead to
fatigue failure of a critical component and, subsequently, an accident.
The expected benefit of averting a single accident entailing just one
serious injury and/or moderate damage to the helicopter would easily
exceed the upper-bound certification cost of $124,000.
Other advantages of requiring that manufacturers provide OGE hover
data are that: (1) Operators will no longer be concerned that
manufacturers might arbitrarily stop providing the data, (2) operators
may feel more confident about the data because the FAA would be
approving it, and (3) the FAA can assure uniformity in the presentation
of data between manufacturers.
Section 29.83--Landing: Category B. The rule will require that
approach and landing tests for Category B rotorcraft be made with power
on rather than with engine power off. This is a more normal flight
profile. This change will benefit pilots by providing more useful data
in the flight manual for flight planning purposes since pilots normally
plan for power-on landings. This will be particularly useful if a
rotorcraft is operating at or near maximum gross weight in or around
unimproved landing areas where landing distances are more critical.
This will also increase the safety of test pilots since they will be
required to perform fewer power-off tests. There are no or negligible
additional costs associated with this change.
Regulatory Flexibility Determination
The Regulatory Flexibility Act of 1980 (RFA) was enacted by
Congress to ensure that small entities are not unnecessarily and
disproportionately burdened by government regulations. The RFA requires
a Regulatory Flexibility Analysis if a proposed or final rule would
have a significant economic impact, either detrimental or beneficial,
on a substantial number of small entities. FAA Order 2100.14A,
Regulatory Flexibility Criteria and Guidance, prescribes standards for
complying with RFA review requirements in FAA rulemaking actions. The
Order defines ``small entities'' in terms of size thresholds,
``significant economic impact'' in terms of annualized cost threshold,
and ``substantial number'' as a number which is not less than eleven
and which is more than one-third of the small entities subject to the
proposed or final rule.
The rule will affect manufacturers and operators of future type-
certificated transport category rotorcraft. For manufacturers, Order
2100.14A specifies a size threshold for classification as a small
entity as 75 or fewer employees. Since no part 29 rotorcraft
manufacturer has 75 or fewer employees, the rule will not have
significant economic impact on a substantial number of small
manufacturers. For operators, the benefits of increased payloads would
probably not exceed the annualized thresholds specified in the Order;
consequently, the rule will not have a significant economic impact on a
substantial number of small operators.
International Trade Impact
The rule will have little or no impact on trade for either U.S.
firms doing business in foreign markets or foreign firms doing business
in the United States.
Federalism Implications
The regulations adopted herein will not have substantial direct
effects on the States, on the relationship between the national
government and the States, or on the distribution of power and
responsibilities among the various levels of government. Therefore, in
accordance with Executive Order 12612, it is determined that these
amendments do not have sufficient federalism implications to warrant
the preparation of a Federalism Assessment.
Conclusion
For the reasons discussed in the preamble, and based on the
findings in the Regulatory Flexibility Determination and the
International Trade Impact Analysis, the FAA has determined that this
regulation is not a significant regulatory action under Executive Order
12866. In addition, the FAA certifies that these changes will not have
a significant economic impact, positive or negative, on a substantial
number of small entities under the criteria of the Regulatory
Flexibility Act. All changes are found to have negligible or no cost
impacts. Small entities are not affected because transport rotorcraft
are manufactured by large entities, and trade is not affected since
foreign manufacturers also must comply with the requirements of part
29. This proposal is considered to be nonsignificant under DOT
Regulatory Policies and Procedures (44 FR 11034, February 26, 1979). A
regulatory evaluation of the changes, including a Regulatory
Flexibility Determination and International Trade Impact Analysis, has
been placed in the docket. A copy may be obtained by contacting the
person identified under FOR FURTHER INFORMATION CONTACT.''
List of Subjects in 14 CFR Part 29
Air transportation, Aircraft, Aviation safety, Rotorcraft, Safety.
The Amendment
In consideration of the foregoing, the Federal Aviation
Administration amends part 29 of Title 14, Code of Federal Regulations
(14 CFR part 29) as follows:
PART 29--AIRWORTHINESS STANDARDS: TRANSPORT CATEGORY ROTORCRAFT
1. The authority citation for part 29 continues to read as follows:
Authority: 49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
2. Section 29.1 is amended by revising paragraph (e) to read as
follows:
Sec. 29.1 Applicability.
* * * * *
(e) Rotorcraft with a maximum weight of 20,000 pounds or less but
with 10 or more passengers seats may be type certificated as category B
rotorcraft provided the Category A requirements of Secs. 29.67(a)(2),
29.87, 29.1517, and subparts C, D, E, and F of this part are met.
* * * * *
3. Section 29.73 is redesignated as Sec. 29.49 and revised to read
as follows:
Sec. 29.49 Performance at minimum operating speed.
(a) For each Category A helicopter, the hovering performance must
be determined over the ranges of weight, altitude, and temperature for
which takeoff data are scheduled--
(1) With not more than takeoff power;
(2) With the landing gear extended; and
[[Page 21899]]
(3) At a height consistent with the procedure used in establishing
the takeoff, climbout, and rejected takeoff paths.
(b) For each Category B helicopter, the hovering performance must
be determined over the ranges of weight, altitude, and temperature for
which certificate is requested, with--
(1) Takeoff power;
(2) The landing gear extended; and
(3) The helicopter in ground effect at a height consistent with
normal takeoff procedures.
(c) For each helicopter, the out-of-ground effect hovering
performance must be determined over the ranges of weight, altitude, and
temperature for which certification is requested with takeoff power.
(d) For rotorcraft other than helicopters, the steady rate of climb
at the minimum operating speed must be determined over the ranges of
weight, altitude, and temperature for which certification is requested
with--
(1) Takeoff power; and
(2) The landing gear extended.
4. Section 29.51 is amended by revising the introductory text of
paragraph (a) to read as follows:
Sec. 29.51 Takeoff data: general.
(a) The takeoff data required by Secs. 29.53, 29.55, 29.59, 29.60,
29.61, 29.62, 29.63, and 29.67 must be determined--
* * * * *
5. Section 29.53 is revised to read as follows:
Sec. 29.53 Takeoff: Category A.
The takeoff performance must be determined and scheduled so that,
if one engine fails at any time the start of takeoff, the rotocraft
can--
(a) Return to, and stop safely on, the takeoff area; or
(b) Continue the takeoff and climbout, and attain a configuration
and airspeed allowing compliance with Sec. 29.67(a)(2).
6. A new Sec. 29.55 is added to read as follows:
Sec. 29.55 Takeoff decision point (TDP): Category A.
(a) The TDP is the first point from which a continued takeoff
capability is assured under Sec. 29.59 and is the last point in the
takeoff path from which a rejected takeoff is assured within the
distance determined under Sec. 29.62.
(b) The TDP must be established in relation to the takeoff path
using no more than two parameters; e.g., airspeed and height, to
designate the TDP.
(c) Determination of the TDP must include the pilot recognition
time interval following failure of the critical engine.
7. Section 29.59 is revised to read as follows:
Sec. 29.59 Takeoff path: Category A.
(a) The takeoff path extends from the point of commencement of the
takeoff procedure to a point at which the rotorcraft is 1,000 feet
above the takeoff surface and compliance with Sec. 29.67(a)(2) is
shown. In addition--
(1) The takeoff path must remain clear of the height-velocity
envelope established in accordance with Sec. 29.87;
(2) The rotocraft must be flown to the engine failure point; at
which point, the critical engine must be made inoperative and remain
inoperative for the rest of the takeoff;
(3) After the critical engine is made inoperative, the rotorcraft
must continue to the takeoff decision point, and then attain
VTOSS;
(4) Only primary controls may be used while attaining VTOSS
and while establishing a positive rate of climb. Secondary controls
that are located on the primary controls may be used after a positive
rate of climb and VTOSS are established but in no case less than 3
seconds after the critical engine is made inoperative; and
(5) After attaining VTOSS and a positive a climb, the landing
gear may be retracted.
(b) During the takeoff path determination made in accordance with
paragraph (a) of this section and after attaining VTOSS and a
positive rate of climb, the climb must be continued at a speed as close
as practicable to, but not less than, VTOSS until the rotocraft is
200 feet above the takeoff surface. During this interval, the climb
performance must meet or exceed that required by Sec. 29.67(a)(1).
(c) From 200 feet above the takeoff surface, the rotorcraft takeoff
path must be level or positive until a height 1,000 feet above the
takeoff surface is attained with not less than the rate of climb
required by Sec. 29.67(a)(2). Any secondary or auxiliary control may be
used after attaining 200 feet above the takeoff surface.
(d) Takeoff distance will be determined in accordance with
Sec. 29.61.
(e) During the continued takeoff, the rotorcraft shall not descend
below 15 feet above the takeoff surface when the takeoff decision point
is above 15 feet.
8. A new Sec. 29.60 is added to read as follows:
Sec. 29.60 Elevated heliport takeoff path: Category A.
(a) The elevated heliport takeoff path extends from the point of
commencement of the takeoff procedure to a point in the takeoff path at
which the rotorcraft is 1,000 feet above the takeoff surface and
compliance with Sec. 29.67(a)(2) is shown. In addition--
(1) The requirements of Sec. 29.59(a) must be met;
(2) While attaining VTOSS and a positive rate of climb, the
rotocraft may descend below the level of the takeoff surface if, in so
doing and when clearing the elevated heliport edge, every part of the
rotocraft clears all obstacles by at least 15 feet;
(3) The vertical magnitude of any descent below the takeoff surface
must be determined; and
(4) After attaining VTOSS and a positive rate of climb, the
landing gear may be retracted.
(b) The scheduled takeoff weight must be such that the climb
requirements of Sec. 29.67 (a)(1) and (a)(2) will be met.
(c) Takeoff distance will be determined in accordance with
Sec. 29.61.
9. A new Sec. 29.61 is added to read as follows:
Sec. 29.61 Takeoff distance: Category A.
(a) The normal takeoff distance is the horizontal distance along
the takeoff path from the start of the takeoff to the point at which
the rotorcraft attains and remains at least 35 feet above the takeoff
surface, attains and maintains a speed of at least VTOSS, and
establishes a positive rate of climb, assuming the critical engine
failure occurs at the engine failure point prior to the takeoff
decision point.
(b) For elevated heliports, the takeoff distance is the horizontal
distance along the takeoff path from the start of the takeoff to the
point at which the rotorcraft attains and maintains a speed of at least
VTOSS and establishes a positive rate of climb, assuming the
critical engine failure occurs at the engine failure point prior to the
takeoff decision point.
10. A new Sec. 29.62 is added to read as follows:
Sec. 29.62 Rejected takeoff: Category A.
The rejected takeoff distance and procedures for each condition
where takeoff is approved will be established with--
(a) The takeoff path requirements of Secs. 29.59 and 29.60 being
used up to the engine failure point, the rotorcraft continuing to
takeoff decision point, and the rotorcraft landed and brought to a stop
on the takeoff surface;
(b) The remaining engines operating within approved limits;
(c) The landing gear remaining extended throughout the entire
rejected takeoff; and
(d) The use of only the primary controls until the rotorcraft is on
the
[[Page 21900]]
ground. Secondary controls located on the primary control may not be
used until the rotorcraft is on the ground. Means other than wheel
brakes may be used to stop the rotorcraft if the means are safe and
reliable and consistent results can be expected under normal operating
conditions.
11. A new Sec. 29.64 is added to read as follows:
Sec. 29.64 Climb: general.
Compliance with the requirements of Secs. 29.65 and 29.67 must be
shown at each weight, altitude, and temperature within the operational
limits established for the rotorcraft and with the most unfavorable
center of gravity for each configuration. Cowl flaps, or other means of
controlling the engine-cooling air supply, will be in the position that
provides adequate cooling at the temperatures and altitudes for which
certification is requested.
12. Section 29.65 is amended by revising paragraph (a) to read as
follows and by removing paragraph (c):
Sec. 29.65 Climb: all engines operating.
(a) The steady rate of climb must be determined--
(1) With maximum continuous power;
(2) With the landing gear retracted; and
(3) A Vy for standard sea level conditions and at speeds
selected by the applicant for other conditions.
* * * * *
13. Section 29.67 is revised to read as follows:
Sec. Climb: one-engine-inoperative (OEI).
(a) For Category A rotorcraft, in the critical takeoff
configuration existing along the takeoff path, the following apply:
(1) The steady rate of climb without ground effect, 200 feet above
the takeoff surface, must be at least 100 feet per minute for each
weight, altitude, and temperature for which takeoff data are to be
scheduled with--
(i) The critical engine inoperative and the remaining engines
within approved operating limitations, except that for rotorcraft for
which the use of 30-second/2-minute OEI power is requested, only the 2-
minute OEI power may be used in showing compliance with this paragraph;
(ii) The landing gear extended; and
(iii) The takeoff safety speed selected by the applicant.
(2) The steady rate of climb without ground effect at 1,000 feet
above the takeoff surface must be at least 150 feet per minute for each
weight altitude, and temperature for which takeoff data are to be
scheduled with--
(i) The critical engine inoperative and the remaining engines at
maximum continuous power including OEI maximum continuous power, if
approved, or at 30-minute power for rotorcraft for which certification
for use of 30-minute power is requested;
(ii) The most unfavorable center of gravity for climb following
takeoff;
(iii) The landing gear retracted; and
(iv) The speed selected by the applicant.
(3) The steady rate of climb (or descent) in feet per minute, at
each altitude and temperature at which the rotocraft is expected to
operate and at any weight within the range of weights for which
certification is requested, must be determined with--
(i) The critical engine inoperative and the remaining engines at
maximum continuous power including OEI maximum continuous power, if
approved, and at 30-minute power for rotorcraft for which certification
for the use of 30-minute power is requested;
(ii) The landing gear retracted; and
(iii) The speed selected by the applicant.
(b) For multiengine Category B rotorcraft meeting the Category A
engine isolation requirements, the steady rate of climb (or descent)
must be determined at the speed for best rate of climb (or minimum rate
of descent) at each altitude, temperature, and weight at which the
rotorcraft is expected to operate, with the critical engine inoperative
and the remaining engines at maximum continuous power including OEI
maximum continuous power, if approved, and at 30-minute power for
rotorcraft for which certification for the use of 30-minute power is
requested.
14. Section 29.75 is revised as follows:
Sec. 29.75 Landing: general.
(a) For each rotorcraft--
(1) The corrected landing data must be determined for a smooth,
dry, hard, and level surface;
(2) The approach and landing must not require exceptional piloting
skill or exceptionally favorable conditions; and
(3) The landing must be made without excessive vertical
acceleration or tendency to bounce, nose over, ground loop, porpoise,
or water loop.
(b) The landing data required by Secs. 29.77, 29.79, 29.81, 29.83,
and 29.85 must be determined--
(1) At each weight, altitude, and temperature for which landing
data are approved;
(2) With each operating engine within approved operating
limitations; and
(3) With the most unfavorable center of gravity.
15. Section 29.77 is redesignated as Sec. 29.85 and a new
Sec. 29.77 is added to read as follows:
Sec. 29.77 Landing decision point: Category A.
The landing decision point (LDP) must be established at not less
than the last point in the approach and landing path at which a balked
landing can be accomplished under Sec. 29.85 with the critical engine
failed or failing and with the engine failure recognized by the pilot.
16. Section 29.79 is redesignated as Sec. 29.87 and a new
Sec. 29.79 is added to read as follows:
Sec. 29.79 Landing: Category A.
(a) For Category A rotorcraft--
(1) The landing performance must be determined and scheduled so
that if the critical engine fails at any point in the approach path,
the rotorcraft can either land and stop safely or climb out and attain
a rotorcraft configuration and speed allowing compliance with the climb
requirement of Sec. 29.67(a)(2);
(2) The approach and landing paths must be established with the
critical engine inoperative so that the transition between each stage
can be made smoothly and safely;
(3) The approach and landing speeds must be selected by the
applicant and must be appropriate to the type of rotorcraft; and
(4) The approach and landing path must be established to avoid the
critical areas of the height-velocity envelope determined in accordance
with Sec. 29.87.
(b) It must be possible to make a safe landing on a prepared
landing surface after complete power failure occurring during normal
cruise.
17. A new Sec. 29.81 is added to read as follows:
Sec. 29.81 Landing distance: Category A
The horizontal distance required to land and come to a complete
stop (or to a speed of approximately 3 knots for water landings) from a
point 50 feet above the landing surface (25 feet for Category A
elevated heliport landing operations) must be determined from the
approach and landing paths established in accordance with Sec. 29.79.
18. A new Sec. 29.83 is added to read as follows:
Sec. 29.83 Landing: Category B.
(a) For each Category B rotorcraft, the horizontal distance
required to land and come to a complete stop (or to a speed of
approximately 3 knots for water landings) from a point 50 feet above
the landing surface must be determined with--
[[Page 21901]]
(1) Speeds appropriate to the type of rotocraft and chosen by the
applicant to avoid the critical areas of the height-velocity envelope
established under Sec. 29.87; and
(2) The approach and landing made with power on and within approved
limits.
(b) Each multiengined Category B rotorcraft that meets the
powerplant installation requirements for Category A must meet the
requirements of--
(1) Sections 29.79 and 29.81; or
(2) Paragraph (a) of this section.
(c) It must be possible to make a safe landing on a prepared
landing surface if complete power failure occurs during normal cruise.
19. Redesignated Sec. 29.85 is revised to read as follows:
Sec. 29.85 Balked landing: Category A.
For Category A rotocraft, the balked landing path must be
established so that--
(a) With the critical engine inoperative, the transition from each
stage of the maneuver to the next stage can be made smoothly and
safely;
(b) With the critical engine failed and the failure recognized at
the landing decision point on the approach path selected by the
applicant, a safe climbout can be made at speeds allowing compliance
with the climb requirements of Sec. 29.67(a) (1) and (2); and
(c) The rotocraft does not descend below 15 feet above the landing
surface. For elevated heliport operations, descent may be below the
level of the landing surface provided the deck edge clearance of
Sec. 29.60 is maintained and the descent distance below the landing
surface is determined.
20. Redesignated Sec. 29.87 is revised to read as follows:
Sec. 29.87 Height-velocity envelope.
(a) If there is any combination of height and forward velocity
(including hover) under which a safe landing cannot be made after
failure of the critical engine and with the remaining engines (where
applicable) operating within approved limits, a height-velocity
envelope must be established for--
(1) All combinations of pressure altitude and ambient temperature
for which takeoff and landing are approved; and
(2) Wright from the maximum weight (at sea level) to the highest
weight approved for takeoff and landing at each altitude. For
helicopters, this weight need not exceed the highest weight allowing
hovering out-of-ground effect at each altitude.
(b) For single-engine or multiengine rotorcraft that do not meet
the Category A engine isolation requirements, the height-velocity
envelope for complete power failure must be established.
Section 29.1323 is amended by revising paragraph (b)(2)(ii) to
read as follows:
Sec. 29.1323 Airspeed indicating system.
* * * * *
(b) * * *
(2) * * *
(ii) Avoidance of the critical areas of the height-velocity
envelope as established under Sec. 29.87.
* * * * *
22. Section 29.1587 is amended by revising (a)(4), (a)(5), (b)(3)
and (b)(8) and adding a new (a)(6) to read as follows:
Sec. 29.1587 Performance information.
* * * * *
(a) * * *
(4) The rejected takeoff distance determined under Sec. 29.62 and
the takeoff distance determined under Sec. 29.61 or Sec. 29.63;
(5) The landing data determined under Sec. 29.81 or Sec. 29.83; and
(6) Out-of-ground effect hover performance determined under
Sec. 29.49 and the maximum safe wind demonstrated under the ambient
conditions for data presented.
(b) * * *
(3) The landing distance, appropriate airspeed, and type of landing
surface, together with all pertinent information that might affect this
distance, including the effects of weight, altitude, and temperature;
* * * * *
(8) Out-of-ground effect hover performance determined under
Sec. 29.49 and the maximum safe wind demonstrated under the ambient
conditions for data presented; and
* * * * *
Issued in Washington, DC, on May 2, 1996.
David R. Hinson,
Administrator.
[FR Doc. 96-11494 Filed 5-9-96; 8:45 am]
BILLING CODE 4910-13-M
Complete official Federal Register PDF
FR Doc. 96-11493 Rotorcraft Regulatory Changes Based on European Joint Aviation Requirements
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21904-21908]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11493]
[[Page 21903]]
_______________________________________________________________________
Part VI
Department of Transportation
_______________________________________________________________________
Federal Aviation Administration
_______________________________________________________________________
14 CFR Parts 27 and 29
Rotorcraft Regulatory Changes Based on European Joint Aviation
Requirements; Final Rule
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and
Regulations
[[Page 21904]]
DEPARTMENT OF TRANSPORTATION
Federal Aviation Administration
14 CFR Parts 27 and 29
[Docket No. 28008; Amendment No. 27-33, 29-39]
RIN 2120-AF65
Rotorcraft Regulatory Changes Based on European Joint Aviation
Requirements
AGENCY: Federal Aviation Administration, DOT.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Federal Aviation Administration (FAA) is amending the
airworthiness standards for normal and transport category rotorcraft.
The changes revise airworthiness standards for performance, systems,
propulsion, and airframes. The changes increase the regulatory safety
level, clarify existing regulations, and standardize terminology. The
changes are based on standards incorporated by the European Joint
Aviation Authorities (JAA) for Joint Aviation Requirements (JAR) 27 and
29. These changes are intended to harmonize the U.S. rotorcraft
airworthiness standards with the European JAR.
EFFECTIVE DATE: August 8, 1996.
FOR FURTHER INFORMATION CONTACT:
Carroll Wright, Regulations Group Rotorcraft Directorate, Aircraft
Certification Service, Federal Aviation Administration, Fort Worth,
Texas 76193-0111, telephone (817) 222-5120.
SUPPLEMENTARY INFORMATION:
Background
These amendments are based on Notice of Proposed Rulemaking (NPRM)
No. 94-36 published in the Federal Register on December 28, 1994 (59 FR
67068). That notice proposed to amend the airworthiness standards for
both normal and transport category rotorcraft based on recommendations
from the Aviation Rulemaking Advisory Committee (ARAC). By announcement
in the Federal Register (57 FR 58846, December 11, 1992), the ``JAR/FAR
27 and 29 Harmonization Working Group'' was chartered by the ARAC. The
working group included representatives from four major rotorcraft
manufacturers (normal and transport) and representatives from Aerospace
Industries Association of America, Inc. (AIA), Association Europeene
des Constructeurs de Material Aerospatial (AECMA), Helicopter
Association International (HAI), JAA, and the FAA Rotorcraft
Directorate. This broad participation is consistent with FAA policy to
involve all known interested parties as early as practicable in the
rulemaking process.
The Harmonization Working Group was tasked with making
recommendations to the ARAC regarding JAA Notices of Proposed Amendment
(NPA's). The ARAC subsequently recommended that the FAA revise the
airworthiness standards for normal and transport category rotorcraft to
those currently in the JAR 27 and 29.
The FAA evaluated the ARAC recommendations and proposed changes to
the rotorcraft airworthiness standards in 14 CFR parts 27 and 29 (parts
27 and 29). These proposed changes evolved from the FAA, JAA, and
industry meetings of 1990-1992 and the ARAC recommendations of 1993.
The changes proposed to (1) incorporate current design and testing
practices into the rules by requiring additional performance data, (2)
incorporate additional powerplant and rotor brake controls
requirements, (3) incorporate bird-strike protection requirements, and
(4) harmonize the certification requirements between parts 27 and 29
and the JAR. The proposals for part 27 included JAA's harmonized NPA's
27-Basic and 27-1, and the proposals for part 29 included NPA's 29-
Basic and 29-1 through 29-5. This rule contains the harmonized rule
language of those sections of the NPA's except for Sec. 27.602 of NPA
27-Basic and Sec. 29.602 of NPA 29-4.
In proposed rule, NPRM 94-36, there were several instances in which
a few descriptive words were proposed to either be removed from or
added to regulatory text. These word changes were adequately described
in the amendatory language to NPRM 94-36 when that proposal was
published in the Federal Register. However, at least one commenter
misunderstood the amendatory language. Therefore, to avoid possible
misunderstanding about the final rule language, the paragraphs with the
minor rule language changes are reproduced in their entirety in this
final rule. Also, the numbering of other regulations referenced in
Secs. 29.1587(a)(4) and (a)(5) has been changed, and a new
Sec. 29.1587(a)(6) has been added. The current Sec. 29.1587(a)(6),
which is being redesignated in this rule as Sec. 29.1587(a)(7), was
added by the Transport Category Rotorcraft Performance Rule published
elsewhere in this issue of the Federal Register.
In this final rule, under the heading ``Appendix C to Part 27--
Criteria for Category A,'' the NPRM 94-36 cites to Advisory Circular
(AC) material have been removed since AC material is advisory only. A
note has been added that informs the reader that there is appropriate
guidance material available. Further, the requirement to meet
Sec. 29.571 standards for certification as a part 27 Category A
rotorcraft has been removed from the Appendix C listing. The FAA has
determined that the current Sec. 27.571 contains sufficient
certification standards to maintain an adequate level of safety for
part 27 Category A rotorcraft, and an additional requirement of testing
to Sec. 29.571 standards is unnecessary.
Discussion of Comments
Interested persons have been afforded an opportunity to participate
in the making of these amendments. Due consideration has been given to
the comments received. Comments were received from the JAA, HAI,
Transport Canada, and the United Kingdom Civil Aviation Authority
(UKCAA).
The JAA agrees with the proposed rule and the effort to harmonize
certification regulations of the U.S. and the European communities. To
fulfill harmonization objectives, the JAA prepared an NPA identical to
the NPRM and will publish the JAR final rule at the same time as this
time as this final rule for parts 27 and 29.
HAI comments that the proposals faithfully reflect the
recommendation made to the FAA by the ARAC on rotorcraft regulatory
changes. HAI further comments that the NPRM reflects prudent rulemaking
to increase safety, economic viability, and harmonization within
realistic requirements and urges the adoption of the proposal.
Transport Canada comments that the NPRM was not the same as the
ARAC recommendations in that there were changes in the nonregulatory
sections (preamble) and in the proposed text of the rule. The commenter
states that these changes cause concern because the discrepancies may
lead to different interpretations. The commenter notes that the meaning
of Sec. 29.547 was changed because the word ``main'' had been removed
in the ARAC recommendations but was not removed in the NPRM. This
commenter also states that the requirements of Secs. 29.547 and 29.917
are redundant because Sec. 29.571 also requires the identification of
the principal structural elements (PSE) that includes rotors and rotor
drive systems with the establishment of the inspections and replacement
times for those PSE's. Additionally, the commenter says that
Sec. 29.610 should state that it addresses only ``direct effects'' of
lightning and electricity and
[[Page 21905]]
that indirect effects are covered elsewhere in Secs. 29.954, 29.863,
29.1309, etc. This commenter also states that Sec. 29.1309 should
retain the reference to Sec. 29.610. This commenter also suggests
adding a new requirement and paragraph to Appendix B to part 29 that
would require an additional, self-powered third attitude indicator.
The FAA agrees with Transport Canada that editorial changes between
the ARAC recommendations and the NPRM are a concern because the
differences may lead to different interpretations. To obviate this
concern, editorial changes have been made in the final rule language to
make it consistent with the ARAC recommended language. Also, the FAA
agrees with Transport Canada that the word ``main'' had been removed
from the introductory paragraph of Sec. 29.547(c), (d), and (e) in the
ARAC recommended language but, as previously discussed, had not been
shown as removed in the NPRM rule language. However, the word ``main''
is being removed from this final rule.
The FAA does not agree with this commenter that Secs. 29.547,
29.571, and 29.917 are redundant in requiring identification of
principal structural elements (PSE's), which include rotors and rotor
drive systems, and the establishment of the inspections, replacement
times of those PSE's. Section 29.547(b) requires a design assessment
for main and tail rotor structure components (rotor hub, blades, pitch
control mechanisms, etc); Sec. 29.571 requires fatigue evaluation of
structural components; and Sec. 29.917 requires a design assessment of
the rotor drive system (drive shafts, transmission, gearboxes, etc).
Therefore, these are non redundant requirements. The language is
adopted as proposed.
The FAA agrees with the intent of this commenter's suggestion that
Sec. 29.610 should clearly indicate that it addresses only ``direct
effects'' of lightning and electricity. However, this was achieved in
the NPRM by adding the word ``structure'' between the words
``rotorcraft'' and ``must'' in Sec. 29.610(a) to clarify that this
paragraph applied to rotorcraft structure and not to systems and
equipment. Accordingly, the language is adopted as proposed.
The FAA does not agree with this commenter that Sec. 29.1309 should
retain the reference to Sec. 29.610. The NPRM added the word
``structure'' to Sec. 29.610 to clarify that the paragraph applied to
rotorcraft structure and not to systems and equipment. Since
Sec. 29.1309(h) applies to lightning protection of systems and
equipment, it is inappropriate to reference Sec. 29.610, which applies
to lightning protection of structures. The commenter's proposal to
retain the reference to Sec. 29.610 is not adopted.
The FAA disagrees with this commenter's suggestion that a new
requirement and paragraph be added to part 29, Appendix B, to require
an additional, self-powered third attitude indicator. Part 29, Appendix
B, paragraph VIII(a)(2) currently requires a standby attitude indicator
that is independent of the aircraft electrical generating system.
Additionally, part 29, Appendix B, paragraph VIII(b)(5)(iii) states,
``The equipment, systems, and installations must be designed so that
one display of the information essential to the safety of flight that
is provided by the instruments will remain available to a pilot,
without additional crew-member action, after any single failure or
combination of failures that is not shown to be extremely improbable *
* *.'' Currently, the only practical design to meet the extremely
improbable (10-9) requirement of part 29, Appendix B, for the
display of information essential to flight safety after a single
failure or combination of failures is the design that uses a third
attitude indicator powered by a source other than the aircraft
electrical generating system. However, the FAA does not wish to limit
future alternative designs that may meet the extremely improbable
standard without a third attitude indicator. The suggestion of the
commenter to add a requirement for a self-powered third attitude
indicator is not adopted.
The UKCAA comments that Proposal No. 13 in NPRM 94-36 proposed to
amend Sec. 29.923(b)(3)(i), to require two applications of 2-minute
power following each application of 30-second power, instead of the one
application of 2-minute power previously proposed. The UKCAA fully
supports the proposed changes in NPRM 94-36. However, the UKCAA further
comments that since publication of NPRM 94-36, the FAA published
Amendment 29-34 (59 FR 47764, September 16, 1994) that states in part,
``When conducted on a bench test, the test sequence must be conducted
following stabilization at take-off power.'' The commenter states that
the reason for adding this sentence, as stated in the preamble to
Amendment 29-34, remains valid, and this sentence should therefore be
included in the final rule developed from NPRM 94-36.
The FAA concurs with the UKCAA that the reason for adding the
sentence, ``When conducted on a bench test, the test sequence must be
conducted following stabilization at take-off power'' remains valid and
the sentence should be retained in Sec. 29.923(b)(3)(i). The sentence
was adopted in Amendment 29-34 due to a commenter's statement that if
the 5-minute takeoff power run to qualify the drive system is conducted
as part of the endurance run, and the 30-second/2-minute OEI
requirements are conducted on a bench test, then the takeoff power 5-
minute run will be conducted twice on the same set of gears. The FAA
did not intend to duplicate the takeoff power 5-minute run if the OEI
requirements are conducted on a bench test, and the sentence was
adopted for clarification. Since the omission of the sentence in NPRM
94-36 was inadvertent, since the reasons for including the sentence
remain valid, and since the sentence is relieving in nature and does
not place any additional burden on manufacturers, it is unnecessary to
solicit prior public comment. Therefore, the sentence is restored as
requested by the commenter.
After considering all of the comments, the FAA has determined that
air safety and the pubic interest support adoption of the amendments
with the changes noted.
Regulatory Evaluation Summary
Proposed changes to federal regulations must undergo several
economic analyses. First, Executive Order 12866 directs that each
Federal agency shall propose or adopt a regulation only upon a reasoned
determination that the benefits of the intended regulation justify its
costs. Second, the Regulatory Flexibility Act of 1980 requires agencies
to analyze the economic effect of regulatory changes on small entities.
Third, the Office of Management and Budget directs agencies to assess
the effect of regulatory changes on international trade. In conducting
these analyses, the FAA has determined that this rule: (1) would
generate benefits that justify its costs and is not ``a significant
regulatory action'' as defined in the Executive Order; (2) is
nonsignificant as defined in DOT's Regulatory Policies and Procedures;
(3) would not have a significant impact on substantial number of small
entities; and (4) will lessen restraints on international trade. These
analyses, available in the docket, are summarized below.
Cost-Benefit Analysis
All of the changes to part 27 and all but four of the changes to
part 29 will impose no or insignificant costs on rotorcraft
manufacturers since they largely reflect current design practices. In
recent years, manufacturers have incorporated engineering and
structural improvements into rotorcraft designs
[[Page 21906]]
that exceed minimum regulatory requirements with the aim of increasing
operating efficiencies, payload capabilities, and marketability in
world markets. Many of these improvements have also inherently improved
safety codification of these improvement and other changes will ensure
continuation of enhanced safety levels in future rotorcraft designs.
The changes will also increase harmonization and commonality
between U.S. and European airworthiness standards. Harmonization will
eliminate the need to comply with different FAA and JAA airworthiness
requirements, thus reducing manufacturers' certification costs. Based
on experience in a recent certification, one rotorcraft manufacturer
indicated that complying with different FAA and JAA requirements
resulted in several hundred thousand dollars of excessive certification
costs (as related to all part 27 and 29 requirements). The duplicate
certification costs avoided by the harmonized rule alone could outweigh
the relatively modest increase in certification costs imposed by the
few new requirements. Following is a summary of the four changes to
part 29 that will impose additional costs totaling approximately
$160,000 per type certification. The safety benefits of these changes
are expected to easily exceed the incremental costs.
Section 29.547--Main and tail rotor structure. While manufacturers
currently perform the design assessment as an integral part of the
design requirements of Sec. 29.917, there will be some incremental
costs to formalize the existing information. These costs are included
in the cost estimates of Sec. 29.917 summarized below. Formal
identification and assessment of critical component failures will
increase safety by providing more comprehensive maintenance information
to operators. The benefits of averting a single accident will exceed
the relatively low incremental costs of compliance.
Section 29.631--Bird strike. Manufacturers indicate that present
rotorcraft structures can withstand impacts with 2.2 pound birds;
therefore, no incremental manufacturing costs are anticipated.
Nonrecurring testing and analysis costs of the requirement are
estimated to be $107,000 per type certification. A review of National
Transportation Safety Board (NTSB) data for the period 1983-1991
reveals two rotorcraft accidents caused by bird strikes. One accident
resulted in one serious injury, one minor injury, and substantial
damage to the rotorcraft (tail rotor separation); in the other
accident, the rotorcraft was destroyed but there were no injuries.
There is at least an equal probability of such accidents in the future,
given the tendencies toward higher operating speeds. The benefits of
averting a single accident will exceed the incremental costs of the
amendment.
Section 29.917--Design. The incremental costs to formalize existing
design information for the rotor structure (Sec. 29.547 above) and
drive system are estimated to total $47,000 per type certification.
Formal identification and assessment of critical component failures of
the rotor drive system will increase safety by providing more
comprehensive maintenance information to operators. The benefits of
averting a single accident caused directly or indirectly by a lack of
relevant data would easily exceed the incremental costs.
Section 29.1587--Performance information. Since the required climb
gradient data are already available from the results of flight tests
required to obtain performance information, the only additional costs
will be those associated with incorporating the data into the Flight
Manual, estimated to total $6,000 per type certification. The
availability and accuracy of performance data are paramount to
operational safety. The benefits of averting a single accident caused
directly or indirectly by a lack of relevant performance information
will easily exceed the incremental costs.
Regulatory Flexibility determination
The Regulatory Flexibility Act of 1980 (RFA) was enacted by
Congress to ensure that small entities are not unnecessarily and
disproportionately burdened by Federal Regulations. The RFA requires a
Regulatory Flexibility Analysis if a proposed rule would have ``a
significant economic impact on a substantial number of small
entities.'' Based on the criteria of FAA Order 2100.14A, the FAA has
determined that the rule will not have a significant impact on a
substantial number of small entities.
The rule will affect manufacturers of future type-certificated
normal (part 27) and transport category (part 29) rotorcraft. For
manufacturers, Order 2100.14A defines a small entity as one with 75 or
fewer employees and a significant economic impact as annualized costs
of $19,000 or more. The FAA has determined that the rule will not have
a significant economic impact on a substantial number of small
manufacturers since (1) no part 29 and only two part 27 rotorcraft
manufacturers have 75 or fewer employees, and (2) the annualized
certification costs of the rule are less than $19,000.
International Trade Impact Assessment
The rule will not constitute a barrier to international trade,
including the export of American rotorcraft to other countries and the
import of rotorcraft into the United States. Instead, the changes will
harmonize with certification procedures of the JAA and thereby enhance
free trade.
Conclusion
For the reasons discussed above, including the findings in the
Regulatory Flexibility Determination and the International Trade Impact
Analysis, the FAA has determined that this regulation is not a
significant regulatory action under Executive Order 12866. In addition,
the FAA certifies that this regulation will not have a significant
economic impact, positive or negative, on a substantial number of small
entities under the criteria of the Regulatory Flexibility Act. This
regulation is considered nonsignificant under DOT Order 2100.5. A final
regulatory evaluation of the regulation, including a final Regulatory
Flexibility Determination and International Trade Impact Analysis, has
been placed in the docket. A copy may be obtained by contacting the
person identified under FOR FURTHER INFORMATION CONTACT.
List of Subjects in 14 CFR Parts 27 and 29
Air transportation, Aircraft, Aviation safety, Rotorcraft, Safety.
The Amendments
In consideration of the foregoing, the Federal Aviation
Administration amends parts 27 and 29 of Title 14, Code of Federal
Regulations (14 CFR parts 27 and 29) as follows:
PART 27--AIRWORTHINESS STANDARDS: NORMAL CATEGORY ROTORCRAFT
1. The authority citation for part 27 continues to read as follows:
Authority: 49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
2. Section 27.1 is amended by adding a new paragraph (c) to read as
follows:
Sec. 27.1 Applicability.
* * * * *
(c) Multiengine rotorcraft may be type certificated as Category A
provided the requirements referenced in appendix C of this part are
met.
3. Section 27.65 is amended by revising paragraphs (b)(2)
introductory text and (b)(2)(ii) to read as follows:
[[Page 21907]]
Sec. 27.65 Climb: all engines operating.
* * * * *
(b) * * *
(2) The steady rate of climb must be determined--
* * * * *
(ii) Within the range from sea level up to the maximum altitude for
which certification is requested;
* * * * *
4. Section 27.1141 is amended by redesignating existing paragraphs
(c) and (d) as paragraphs (d) and (e) and by adding a new paragraph (c)
to read as follows:
Sec. 27.1141 Powerplant controls: general.
* * * * *
(c) Each control must be able to maintain any set position
without--
(1) Constant attention; or
(2) Tendency to creep due to control loads or vibration.
* * * * *
5. New Sec. 27.1151 is added to read as follows:
Sec. 27.1151 Rotor brake controls.
(a) It must be impossible to apply the rotor brake inadvertently in
flight.
(b) There must be means to warn the crew if the rotor brake has not
been completely released before takeoff.
6. Part 27 is amended by adding a new appendix C to read as
follows:
Appendix C to Part 27--Criteria for Category A
C27.1 General.
A small multiengine rotorcraft may not be type certificated for
Category A operation unless it meets the design installation and
performance requirements contained in this appendix in addition to
the requirements of this part.
C27.2 Applicable part 29 sections. The following sections of
part 29 of this chapter must be met in addition to the requirements
of this part:
29.45(a) and (b)(2)--General.
29.49(a)--Performance at minimum operating speed.
29.51--Takeoff data: General.
29.53--Takeoff: Category A.
29.55--Takeoff decision point: Category A.
29.59--Takeoff Path: Category A.
29.60--Elevated heliport takeoff path: Category A.
29.61--Takeoff distance: Category A.
29.62--Rejected takeoff: Category A.
29.64--Climb: General.
29.65(a)--Climb: AEO.
29.67(a)--Climb: OEI.
29.75--Landing: General.
29.77--Landing decision point: Category A.
29.79--Landing: Category A.
29.81--Landing distance (Ground level sites): Category A.
29.85--Balked landing: Category A.
29.87(a)--Height-velocity envelope.
29.547(a) and (b)--Main and tail rotor structure.
29.861(a)--Fire protection of structure, controls, and other parts.
29.901(c)--Powerplant: Installation.
29.903(b) (c) and (e)--Engines.
29.908(a)--Cooling fans.
29.917(b) and (c)(1)--Rotor drive system: Design.
29.927(c)(1)--Additional tests.
29.953(a)--Fuel system independence.
29.1027(a)--Transmission and gearboxes: General.
29.1045(a)(1), (b), (c), (d), and (f)--Climb cooling test
procedures.
29.1047(a)--Takeoff cooling test procedures.
29.1181(a)--Designated fire zones: Regions included.
29.1187(e)--Drainage and ventilation of fire zones.
29.1189(c)--Shutoff means.
29.1191(a)(1)--Firewalls.
29.1193(e)--Cowling and engine compartment covering.
29.1195(a) and (d)--Fire extinguishing systems (one shot).
29.1197--Fire extinguishing agents.
29.1199--Extinguishing agent containers.
29.1201--Fire extinguishing system materials.
29.1305(a) (6) and (b)--Powerplant instruments.
29.1309(b)(2) (i) and (d)--Equipment, systems, and installations.
29.1323(c)(1)--Airspeed indicating system.
29.1331(b)--Instruments using a power supply.
29.1351(d)(2)--Electrical systems and equipment: General (operation
without normal electrical power).
29.1587(a)--Performance information.
Note: In complying with the paragraphs listed in paragraph C27.2
above, relevant material in the AC ``Certification of Transport
Category Rotorcraft'' should be used.
PART 29--AIRWORTHINESS STANDARDS: TRANSPORT CATEGORY ROTORCRAFT
7. The authority citation for part 29 continues to read as follows:
Authority: 49 U.S.C. 106(g), 40113, 44701, 44702, 44704.
8. Section 29.547 is amended by revising the heading; by revising
paragraph (a); by revising the introductory text in paragraphs (c),
(d), and (e); by revising paragraph (e)(1)(ii); and by adding paragraph
(b) to read as follows:
Sec. 29.547 Main and tail rotor structure.
(a) A rotor is an assembly of rotating components, which includes
the rotor hub, blades, blade dampers, the pitch control mechanisms, and
all other parts that rotate with the assembly.
(b) Each rotor assembly must be designed as prescribed in this
section and must function safely for the critical flight load and
operating conditions. A design assessment must be performed, including
a detailed failure analysis to identify all failures that will prevent
continued safe flight or safe landing, and must identify the means to
minimize the likelihood of their occurrence.
(c) The rotor structure must be designed to withstand the following
loads prescribed in Secs. 29.337 through 29.341 and 29.351:
* * * * *
(d) The rotor structure must be designed to withstand loads
simulating--
* * * * *
(e) The rotor structure must be designed to withstand the limit
torque at any rotational speed, including zero.
In addition:
(1) * * *
* * * * *
(ii) For the main rotor, the limit engine torque specified in
Sec. 29.361.
* * * * *
9. Section 29.610 is amended by revising the heading; by revising
paragraph (a); and by adding a new paragraph (d) to read as follows:
Sec. 29.610 Lightning and static electricity protection.
(a) The rotorcraft structure must be protected against catastrophic
effects from lightning.
* * * * *
(d) The electric bonding and protection against lightning and
static electricity must--
(1) Minimize the accumulation of electrostatic charge;
(2) Minimize the risk of electric shock to crew, passengers, and
service and maintenance personnel using normal precautions;
(3) Provide an electrical return path, under both normal and static
electricity on the functioning of essential electrical and electronic
equipment.
(4) Reduce to an acceptable level the effects of lightning and
static electricity on the functioning of essential electronic
equipment.
10. Section 29.629 is revised to read as follows:
Sec. 29.629 Flutter and divergence.
Each aerodynamic surface of the rotorcraft must be free from
flutter and divergence under each appropriate speed and power
condition.
11. Section 29.631 is added before the undesignated center heading,
``Rotors'' to read as follows:
Sec. 29.631 Bird strike.
The rotorcraft must be designated to ensure capability of continued
safe flight and landing (for Category A) or safe landing (for Category
B) after impact with a 2.2-lb (1.0 kg) bird when
[[Page 21908]]
the velocity of the rotorcraft (relative to the bird along the flight
path of the rotorcraft) is equal to VNE or VH (whichever is
the lesser) at altitudes up to 8,000 feet. Compliance must be shown by
tests or by analysis based on tests carried out on sufficiently
representative structures of similar design.
12. Section 29.917 is amended by redesignating existing paragraph
(b) as (c) and by adding a new paragraph (b) to read as follows:
Sec. 29.917 Design.
* * * * *
(b) Design assessment. A design assessment must be performed to
ensure that the rotor drive system functions safely over the full range
of conditions for which certification is sought. The design assessment
must include a detailed failure analysis to identify all failures that
will prevent continued safe flight or safe landing and must identify
the means to minimize the likelihood of their occurrence.
* * * * *
13. Section 29.923 is amended by revising paragraph (b)(3)(i) to
read as follows:
Sec. 29.923 Rotor drive system and control mechanism tests.
* * * * *
(b) * * *
(3) * * *
(i) Immediately following any one 5-minute power-on run required by
paragraph (b)(1) of this section, simulate a failure for each power
source in turn, and apply the maximum torque and the maximum speed for
use with 30-second OEI power to the remaining affected drive system
power inputs for not less than 30 seconds. Each application of 30-
second OEI power must be followed by two applications of the maximum
torque and the maximum speed for use with the 2 minute OEI power for
not less than 2 minutes each; the second application must follow a
period at stabilized continuous or 30 minute OEI power (whichever is
requested by the applicant). At least one run sequence must be
conducted from a simulated ``flight idle'' condition. When conducted on
a bench test, the test sequence must be conducted following
stabilization at take-off power.
* * * * *
14. Section 29.1305 is amended by redesignating existing paragraphs
(a)(6) through (a)(25) as paragraphs (a)(7) through (a)(26) and by
adding a new paragraph (a)(6) to read as follows:
Sec. 29.1305 Powerplant instruments
* * * * *
(a) * * *
(6) An oil pressure indicator for each pressure-lubricated gearbox.
* * * * *
15. Section 29.1309 is amended by revising paragraph (h) to read as
follows:
Sec. 29.1309 Equipment, systems, and installations
* * * * *
(h) In showing compliance with paragraphs (a) and (b) of this
section, the effects of lightning strikes on the rotorcraft must be
considered.
16. Section 29.1351(d) is revised to read as follows:
Sec. 29.1351 General
* * * * *
(d) Operation with the normal electrical power generating system
inoperative.
(1) It must be shown by analysis, tests, or both, that the
rotorcraft can be operated safely in VFR conditions for a period of not
less than 5 minutes, with the normal electrical power generating system
(electrical power sources excluding the battery) inoperative, with
critical type fuel (from the standpoint of flameout and restart
capability), and with the rotorcraft initially at the maximum
certificated altitude. Parts of the electrical system may remain on
if--
(i) A single malfunction, including a wire bundle or junction box
fire, cannot result in loss of the part turned off and the part turned
on;
(ii) The parts turned on are electrically and mechanically isolated
from the parts turned off; and
(iii) The electrical wire and cable insulation, and other
materials, of the parts turned on are self-extinguishing when tested in
accordance with Sec. 25.1359(d) in effect on September 1, 1977.
(2) Additional requirements for Category A Rotorcraft.
(i) Unless it can be shown that the loss of the normal electrical
power generating system is extremely improbable, an emergency
electrical power system, independent of the normal electrical power
generating system, must be provided, with sufficient capacity to power
all systems necessary for continued safe flight and landing.
(ii) Failures, including junction box, control panel, or wire
bundle fires, which would result in the loss of the normal and
emergency systems, must be shown to be extremely improbable.
(iii) Systems necessary for immediate safety must continue to
operate following the loss of the normal electrical power generating
system, without the need for flight crew action.
17. Section 29.1587 is amended by redesignating (a)(6) as (a)(7),
by removing ``and'' from the end of paragraph (a)(5), and by adding a
new paragraph (a)(6) to read as follows:
Sec. 29.1587 Performance Information.
* * * * *
(a) * * *
(6) The steady gradient of climb for each weight, altitude, and
temperature for which takeoff data are to be scheduled, along the
takeoff path determined in the flight conditions required in
Sec. 29.67(a)(1) and (a)(2):
(i) In the flight conditions required in Sec. 29.67(a)(1) between
the end of the takeoff distance and the point at which the rotorcraft
is 200 feet above the takeoff surface (or 200 feet above the lowest
point of the takeoff profile for elevated heliports);
(ii) In the flight conditions required in Sec. 29.67(a)(2) between
the points at which the rotorcraft is 200 and 1000 feet above the
takeoff surface (or 200 and 1000 feet above the lowest point of the
takeoff profile for elevated heliports); and
* * * * *
18. Part 29 Appendix B is amended by adding a new paragraph
VIII(b)(6) to read as follows:
Appendix B to Part 29--Airworthiness Criteria for Helicopter Instrument
Flight
* * * * *
VIII * * *
(b) * * *
(6) In determining compliance with the requirements of
Sec. 29.1351(d)(2), the supply of electrical power to all systems
necessary for flight under IFR must be included in the evaluation.
Issued in Washington, DC, on May 2, 1996.
David R. Hinson,
Administrator.
[FR Doc. 96-11493 Filed 5-9-96; 8:45 am]
BILLING CODE 4910-13-M
Complete official Federal Register PDF
FR Doc. 96-11467 Deletion of Obsolete CFR Sections Pertaining to Farm Service Agency (Formerly Farmers Home Administration) Programs
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21361-21362]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11467]
========================================================================
Rules and Regulations
Federal Register
________________________________________________________________________
This section of the FEDERAL REGISTER contains regulatory documents
having general applicability and legal effect, most of which are keyed
to and codified in the Code of Federal Regulations, which is published
under 50 titles pursuant to 44 U.S.C. 1510.
The Code of Federal Regulations is sold by the Superintendent of Documents.
Prices of new books are listed in the first FEDERAL REGISTER issue of each
week.
========================================================================
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and
Regulations
[[Page 21361]]
DEPARTMENT OF AGRICULTURE
Rural Housing and Comunity Development Service
Rural Business and Cooperative Development Service
Rural Utilities Service
Farm Service Agency
7 CFR Parts 1841, 1843, 1845, 1903, 1945, 1980, and 2054
RIN 0560-AE72
Deletion of Obsolete CFR Sections Pertaining to Farm Service
Agency (Formerly Farmers Home Administration) Programs
AGENCY: Farm Service Agency, USDA.
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: This final rule removes, as unnecessary, regulations
pertaining to: the Emergency Livestock and Economic Emergency loan
programs; the Agricultural Resource Conservation Demonstration Program
(ARCDP); the employment, pay, and functions of Farmers Home
Administration (FmHA) county or area committees; and voluntary debt
adjustment. This action is being taken as part of the National
Performance Review program to eliminate excess regulations and to
improve the quality of those that remain in effect.
EFFECTIVE DATE: June 3, 1996.
FOR FURTHER INFORMATION CONTACT: Steven R. Bazzell, Senior Loan
Officer, Farm Service Agency, United States Department of Agriculture,
Farm Credit Programs Loan Making Division, Ag Box Code 0522, Room 5438-
S, 14th & Independence Avenue, SW, Washington, DC 20250-0522;
Telephone: 202-720-3889; or Facsimile: 202-690-1117; E-mail:
[email protected].
SUPPLEMENTARY INFORMATION:
Executive Order 12866
The Office of Management and Budget did not review this rule
because it was determined to be ``not significant'' for the purposes of
Executive Order 12866.
Regulatory Flexibility Act
The Regulatory Flexibility Act is not applicable to this rule since
the Farm Service Agency (FSA) is not required by 5 U.S.C. 553, or any
other provision of law, to publish a notice of proposed rulemaking to
effect these administrative changes.
Environmental Evaluation
This action will not have a significant impact on the quality of
the environment. Therefore, neither an Environmental Assessment nor an
Environmental Impact Statement is required.
Executive Order 12778
This rule was reviewed in accordance with Executive Order 12778.
The provisions of the rule do not preempt State laws, are not
retroactive, and do not involve administrative appeals.
Executive Order 12372
For reasons set forth in the Notice to 7 CFR, part 3015, subpart V
(48 FR 29115, June 24, 1983), the programs and activities within in
this rule are excluded from the scope of Executive Order 12372, which
requires intergovernmental consultation with State and local officials.
Paperwork Reduction Act
This final rule does not impose any new information or
recordkeeping requirements on the public. The Agency will update the
data documenting the burden on the public at its regularly scheduled
paperwork burden submissions to OMB.
Background
This final rule removes obsolete regulations concerning former
Farmers Home Administration (FmHA) Farmer Programs loans. Under the
Department of Agriculture Reorganization Act of 1994 (Pub.L. 103-354)
(1944 Act), FmHA programs were transferred to other USDA agencies. FmHA
Farmer Programs now are being administered as Farm Credit Programs by
the Farm Service Agency (FSA). The Emergency Livestock (EL) program
regulations under CFR parts 1841, 1843, 1845 and 1980, subpart C are
removed because the Emergency Livestock Credit Act of 1974 (Pub.L. 93-
357), as amended, expired on September 30, 1979. The Economic Emergency
(EE) program regulations at 7 CFR part 1945, subpart C and part 1980,
subpart F are removed because the Emergency Agricultural Credit
Adjustment Act of 1978 (Pub.L. 95-334), was repealed by section 1851 of
the Food, Agriculture, Conservation and Trade Act of 1990 (Pub. L. 101-
624). FSA also is deleting the regulations for administering the
Agricultural Resource Conservation Demonstration Program (ARCDP), 7 CFR
part 1980 subpart J, because the Department of Agriculture
Reorganization Act of 1994 transferred the responsibility for
administering the ARCDP from the former FmHA to the Natural Resources
Conservation Service, USDA. Regulations concerning the employment, pay,
and functions of former FmHA county committees at 7 CFR part 2054,
subpart W also will be eliminated because Sec. 227 of the 1994 Act
abolished FmHA county committees. FSA is examining the role that the
county or area county committees of the former Agricultural
Stabilization and Conservation Service, now part of FSA, can play in
the agricultural credit area and may promulgate regulations concerning
this. Finally, regulations concerning voluntary debt adjustment at 7
CFR part 1903, subpart A, are removed because they are duplicative of
comprehensive loan servicing regulations under 7 CFR part 1951.
[[Page 21362]]
List of Subjects
7 CFR Part 1841
Agricultural Credit, Loan Guarantees, Loan Liquidation, Loan
Servicing, Transfers and Assumptions.
7 CFR Part 1843
Agricultural Credit, Loan Liquidation, Loan Making, Loan Servicing.
7 CFR Part 1845
Agricultural Credit, Emergency Assistance, Guaranteed Loans,
Livestock.
7 CFR Part 1903
Agricultural Credit, Debt Adjustment, Loan Servicing.
7 CFR Part 1945
Agricultural Credit, Economic Emergency, Emergency Assistance.
7 CFR Part 1980
Agricultural Credit, Agricultural Resource Conservation
Demonstration Program.
7 CFR Part 2054
County Committee Function, Elections, Employment.
For the reasons set out in the preamble, CFR Chapter XVIII is
amended as follows:
PARTS 1841, 1843, 1845, 1903, AND 2054--[REMOVED]
1. Parts 1841, 1843, 1845, 1903, and 2054 are removed.
PART 1945--[AMENDED]
2. Part 1945 is amended by removing subpart C (Secs. 1945.101-
1945.150).
PART 1980--[AMENDED]
3. Part 1980 is amended by removing subpart C (Secs. 1980.201-
1980.294 and Appendix A), subpart F (Secs. 1980.501-1980.600 and
Appendices A and B), and subpart J (Secs. 1980.901 through 1980.1000
and Appendices A through D).
Signed at Washington, D.C. on April 24, 1996.
Eugene Moos,
Under Secretary for Farm and Foreign Agricultural Services.
[FR Doc. 96-11467 Filed 5-9-96; 8:45 am]
BILLING CODE 3410-05-P
Complete official Federal Register PDF
FR Doc. 96-11454 Community Reinvestment Act Regulations
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21362-21364]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11454]
=======================================================================
-----------------------------------------------------------------------
DEPARTMENT OF THE TREASURY
Office of the Comptroller of the Currency
12 CFR Part 25
[Docket No. 96-08]
RIN 1557-AB51
FEDERAL RESERVE SYSTEM
12 CFR Part 228
[Regulation BB; Docket No. R-0822]
FEDERAL DEPOSIT INSURANCE CORPORATION
12 CFR Part 345
RIN 3064-AB27
DEPARTMENT OF THE TREASURY
Office of Thrift Supervision
12 CFR Part 563e
[Docket No. 96-32]
RIN 1550-AA96
Community Reinvestment Act Regulations
AGENCIES: Office of the Comptroller of the Currency, Treasury (OCC);
Board of Governors of the Federal Reserve System (Board); Federal
Deposit Insurance Corporation (FDIC); Office of Thrift Supervision,
Treasury (OTS).
ACTION: Joint final rule; correcting amendment.
-----------------------------------------------------------------------
SUMMARY: The OCC, Board, FDIC, and OTS (collectively, the agencies) are
correcting their joint final rule concerning the Community Reinvestment
Act (CRA), which was published on May 4, 1995, and amended by a
subsequent joint final rule published on December 20, 1995. This
document corrects a cross-reference to Small Business Administration
regulations, which were recently amended. This correcting amendment
makes no substantive change in the requirements of the current
regulations.
EFFECTIVE DATE: May 10, 1996.
FOR FURTHER INFORMATION CONTACT:
OCC: Bert A. Otto, Acting Deputy Comptroller for Compliance, (202)
874-5216; or Matthew Roberts, Director, Community and Consumer Law
Division, (202) 874-5750, Office of the Comptroller of the Currency,
250 E Street, SW., Washington, DC 20219.
BOARD: Glenn E. Loney, Associate Director, Division of Consumer and
Community Affairs, (202) 452-3585; Robert deV. Frierson, Assistant
General Counsel, Legal Division, (202) 452-3711; or Leonard N. Chanin,
Managing Counsel, Division of Consumer and Community Affairs, (202)
452-3667, Board of Governors of the Federal Reserve System, 20th Street
and Constitution Avenue, NW., Washington, DC 20551.
FDIC: Bobbie Jean Norris, Chief, Fair Lending Section, Division of
Compliance and Consumer Affairs, (202) 942-3090; Robert W. Mooney, Fair
Lending Specialist, Division of Compliance and Consumer Affairs, (202)
942-3092; or Ann Hume Loikow, Counsel, Regulation and Legislation
Section, Legal Division, (202) 898-3796, Federal Deposit Insurance
Corporation, 550 17th Street, NW., Washington, DC 20429.
OTS: Timothy R. Burniston, Director, Compliance Policy, (202) 906-
5629; Theresa A. Stark, Project Manager, Compliance Policy, (202) 906-
7054; or John Flannery, Attorney, Regulations and Legislation Division,
Chief Counsel's Office, (202) 906-7293, Office of Thrift Supervision,
1700 G Street, NW., Washington, DC 20552.
SUPPLEMENTARY INFORMATION:
Introduction
The agencies jointly are amending their regulations implementing
the CRA (12 U.S.C. 2901 et seq.). This joint final rule makes a
technical correction to the agencies' joint CRA regulations, 12 CFR
parts 25, 228, 345, and 563e. Those regulations establish the framework
and criteria by which the agencies assess an institution's record of
helping to meet the credit needs of its community, including low- and
moderate-income neighborhoods, consistent with safe and sound
operations, and provide that the agencies will take those assessments
into account in reviewing certain applications.
Background
Last year, the agencies revised their CRA regulations. They adopted
a joint final rule, which was published on May 4, 1995 (60 FR 22156).
The agencies published a correction and clarification to the joint
final rule on December 20, 1995 (60 FR 66048).
Need for Correction to the Final Rule
The agencies' joint final rule, as amended, defines ``community
development'' to mean activities that promote economic development by
financing businesses or farms that meet the size eligibility standards
of 13 CFR 121.802(a) (2) and (3). These size eligibility standards
refer to the Small Business Administration's size
[[Page 21363]]
limitations for Development Company and Small Business Investment
Company (SBIC) programs. See 60 FR 22159 (May 4, 1995) and 60 FR 66049
(Dec. 20, 1995).
On January 31, 1996, the Small Business Administration amended its
regulations. See 61 FR 3280. Effective March 1, 1996, the size
limitations for Development Company and SBIC programs are described at
13 CFR 121.301 (b) and (c). 61 FR 3294. Therefore, it is necessary to
amend the agencies' CRA regulations to reflect this change.
The agencies are amending their regulations to mention by name the
SBA's Development Company and SBIC programs, as well as to refer
readers to 13 CFR 121.301. The agencies believe that reference both to
the programs by name and to the SBA's regulation by section will more
clearly describe the size standards to which the agencies are referring
while continuing to direct interested parties to the size standards'
general location in the SBA's regulations.
The agencies find that notice and public procedure concerning this
correcting amendment are impracticable, unnecessary, and contrary to
the public interest under 5 U.S.C. 553(b)(B). The agencies make this
finding because these correcting amendments involve only technical
corrections to the agencies' CRA regulations and make no substantive
changes to the agencies' CRA regulations.
In addition, under 5 U.S.C. 553(d)(3), the agencies have determined
to make this correcting amendment effective with less than 30 days
prior publication. The agencies find that there is good cause for
shortened notice due to the minor nature of the changes. Furthermore,
the SBA's amended regulation became effective March 1, 1996 (61 FR
3280), thereby making the current cross-references in the agencies' CRA
regulations erroneous as of that date.
Regulatory Flexibility Act
Pursuant to section 605(b) of the Regulatory Flexibility Act, the
OCC, Board, FDIC, and OTS hereby certify that this joint final rule
will not have a significant economic impact on a substantial number of
small entities. The agencies expect that this joint final rule will not
have significant secondary or incidental effects on a substantial
number of small entities, or create any additional burden on small
entities. This joint final rule merely makes a technical correction to
a cross-reference in the rules already adopted by the agencies and will
not increase burden on institutions. Accordingly, a regulatory
flexibility analysis is not required.
Paperwork Reduction Act of 1995
There are no collection of information requirements in this joint
final rule.
Executive Order 12866
OCC and OTS: The OCC and the OTS have determined that this joint
final rule is not a significant regulatory action as defined in
Executive Order 12866.
Unfunded Mandates Reform Act of 1995
OCC and OTS: Section 202 of the Unfunded Mandates Reform Act of
1995, Pub. L. 104-4, 109 Stat. 48 (1995) (Unfunded Mandates Act),
requires that covered agencies prepare a budgetary impact statement
before promulgating a rule that includes any Federal mandate that may
result in the expenditure by State, local, and tribal governments, in
the aggregate, or by the private sector, of $100 million or more in any
one year. If a budgetary impact statement is required, section 205 of
the Unfunded Mandates Act also requires covered agencies to identify
and consider a reasonable number of regulatory alternatives before
promulgating a rule. As discussed in the preamble, this joint final
rule amends the agencies' CRA regulations by making one technical
correction. Therefore, the OCC and the OTS have determined that this
joint final rule will not result in expenditures by State, local, and
tribal governments, or by the private sector, of $100 million or more
in any one year. Accordingly, the OCC and the OTS have not prepared a
budgetary impact statement or specifically addressed the regulatory
alternatives considered.
List of Subjects
12 CFR Part 25
Community development, Credit, Investments, National banks,
Reporting and recordkeeping requirements.
12 CFR Part 228
Banks, banking, Community development, Credit, Federal Reserve
System, Investments, Reporting and recordkeeping requirements.
12 CFR Part 345
Banks, banking, Community development, Credit, Investments,
Reporting and recordkeeping requirements.
12 CFR Part 563e
Community development, Credit, Investments, Reporting and
recordkeeping requirements, Savings associations.
Office of the Comptroller of the Currency
12 CFR CHAPTER I
For the reasons discussed in the joint preamble, 12 CFR part 25 is
amended as follows:
PART 25--[AMENDED]
1. The authority citation for part 25 continues to read as follows:
Authority: 12 U.S.C. 21, 22, 26, 27, 30, 36, 93a, 161, 215,
215a, 481, 1814, 1816, 1828(c), and 2901 through 2907.
Sec. 25.12 [Amended]
2. In Sec. 25.12(h)(3), the cross reference ``13 CFR 121.802(a)(2)
and (3)'' is revised to read ``the Small Business Administration's
Development Company or Small Business Investment Company programs (13
CFR 121.301)''.
Dated: April 2, 1996.
Eugene A. Ludwig,
Comptroller of the Currency.
Federal Reserve System
12 CFR CHAPTER II
For the reasons discussed in the joint preamble, 12 CFR part 228 is
amended as follows:
PART 228--[AMENDED]
1. The authority citation for part 228 continues to read as
follows:
Authority: 12 U.S.C. 321, 325, 1828(c), 1842, 1843, 1844, and
2901 et seq.
Sec. 228.12 [Amended]
2. In Sec. 228.12(h)(3), the cross reference ``13 CFR 121.802(a)
(2) and (3)'' is revised to read ``the Small Business Administration's
Development Company or Small Business Investment Company programs (13
CFR 121.301)''.
By order of the Board of Governors of the Federal Reserve
System, March 20, 1996.
William W. Wiles,
Secretary of the Board.
Federal Deposit Insurance Corporation
12 CFR CHAPTER III
For the reasons discussed in the joint preamble, 12 CFR part 345 is
amended as follows:
PART 345--[AMENDED]
1. The authority citation for part 345 continues to read as
follows:
Authority: 12 U.S.C. 1814-1817, 1819-1820, 1828, 1831u and 2901-
2907, 3103-3104, and 3108(a).
[[Page 21364]]
Sec. 345.12 [Amended]
2. In Sec. 345.12(h)(3), the cross reference ``13 CFR 121.802(a)
(2) and (3)'' is revised to read ``the Small Business Administration's
Development Company or Small Business Investment Company programs (13
CFR 121.301)''.
By order of the Board of Directors of the Federal Deposit
Insurance Corporation.
Dated: April 3, 1996.
Jerry L. Langley,
Executive Secretary.
Office of Thrift Supervision
12 CFR CHAPTER V
For the reasons discussed in the joint preamble, 12 CFR part 563e
is amended as follows:
PART 563e--[AMENDED]
1. The authority citation for part 563e continues to read as
follows:
Authority: 12 U.S.C. 1462a, 1463, 1464, 1467a, 1814, 1816,
1828(c), and 2901 through 2907.
Sec. 563e.12 [Amended]
2. In Sec. 563e.12(g)(3), the cross reference ``13 CFR 121.802(a)
(2) and (3)'' is revised to read ``the Small Business Administration's
Development Company or Small Business Investment Company programs (13
CFR 121.301).''
Dated: April 5, 1996.
By the Office of Thrift Supervision.
Jonathan L. Fiechter,
Acting Director.
[FR Doc. 96-11454 Filed 5-9-96; 8:45 am]
BILLING CODE 4810-33-P, 6210-01-P, 6714-01-P, 6720-01-P
Complete official Federal Register PDF
FR Doc. 96-11338 Fenoxaprop-Ethyl; Extension of Study Due Date and Time-Limited Tolerances
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21378-21380]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-11338]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 180
[PP 9F3714/R2214; FRL-5354-1]
RIN 2070-AB78
Fenoxaprop-Ethyl; Extension of Study Due Date and Time-Limited
Tolerances
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
SUMMARY: This rule extends the time-limited tolerances for fenoxaprop-
ethyl from April 12, l996 to November 1, l997. This time extension was
requested by AgrEvo USA Company to coordinate a delay in initiation of
a repeat oncogenicity study required to change the interim (time-
limited) tolerances, required for the use of fenoxaprop-ethyl in the
culture of wheat, to permanent tolerances. The originial petitioner was
Hoechst Celanese Corp. of North Somerville, NJ 08876. In l994 Hoechst
Celanese Corp. and NOR-AM Chemical formed a partnership Company, AgrEvo
USA Company; and AgrEvo USA
[[Page 21379]]
Company became the registrant of fenoxaprop-ethyl pesticide products.
EFFECTIVE DATE: May 10, 1996.
ADDRESSES: Written objections and hearing requests, identified by the
docket number [PP 9F3714/R2214] may be submitted to: Hearing Clerk
(1900), Environmental Protection Agency, Rm. M3708, 401 M St., SW.,
Washington, DC 20460. A copy of any objections and hearing requests
filed with the Hearing Clerk should be identified by the docket number
and submitted to: Public Response and Program Resources Branch, Field
Operations Division (7506C), Office of Pesticide Programs,
Environmental Protection Agency, 401 M St. SW., Washington, DC 20460.
In person, bring copies of objections and hearing requests to: Rm.
1132, CM #2, 1921 Jefferson Davis Highway, Arlington, VA. 22202. Fees
accompanying objections shall be labeled ``Tolerance Petition Fees''
and forwarded to: EPA Headquarters Accounting Operations Branch, OPP
(tolerance Fees) P.O. Box 360277M, Pittsburgh, PA 15251.
A copy of objections and hearing requests filed with the Hearing
Clerk may also be submitted electronically by sending electronic mail
(e-mail) to: [email protected]. Copies of objections and
hearing requests must be submitted as an ASCII file avoiding the use of
special characters and any form of encryption. Copies of objections and
hearing requests will also be accepted on disks in WordPerfect 5.1 file
format or ASCII file format. All copies of objections and hearing
requests in electronic form must be identified by the docket number [PP
9F3714/R2214]. No Confidential Business Information (CBI) should be
submitted through e-mail. Electronic copies of objections and hearing
requests on this rule may be filed online at many Federal Depository
Libraries. Additional information on electronic submissions can be
found below in this document.
FOR FURTHER INFORMATION CONTACT: By mail: Joanne Miller (PM 23),
Registration Division (7505C), Office of Pesticide Programs, U. S.
Environmental Protection Agency, 401 M St., SW., Washington, DC 20460.
Office location and telephone number: Rm. 237, CM #2, 1921 Jefferson
Davis Hwy., Arlington, VA 22202, (Telephone No. (703-305-6226), e-mail:
[email protected].
SUPPLEMENTARY INFORMATION: Interim tolerances that expire April 12,
l996 were established for residues of fenoxaprop-ethyl on August 15,
l991. The petitioner, Hoechst Celanese Corp., agreed to submitting a
repeat mouse oncogenicity study within 4 years from the date of
registration of fenoxaprop-ethyl pesticide products for use in the
culture of wheat. The due date for the study data became April 12,
l996, 4 years and 8 months from the date of first registration of
fenoxaprop-ethyl in the culture of wheat. The added 8 months were to
allow adequate time for the Agency's review of the study. The
initiation of the mouse oncogenicity study was delayed due to the
Agency's requirement for a repeat range finding study. The time line
for submitting the study was extended to November 1, l996 to coordinate
it with the time required for reviewing the range finding study.
Considering the time required to review the study, the present action
extends the time-limited tolerances to November 1, l997. The time
alloted for Agency review of the study is presently 12 months. There is
no information and experience with the pesticide that indicate that
this action would pose significant risk to public health.
A ``Notice of Filing'' a request to amend pesticide petition (PP)
9F3714 by proposing to amend 40 CFR 180.430 to extend the time-limited
tolerances for residues of the herbicide Fenoxyaprop-ethyl was
published on in the Federal Register on April 3, 1996 (61 FR 14772-
14773) (FRL-5358-4). There were no substantive responses to the notice.
Only a typographical error was noted from the public. That error is
corrected in the present Final rule.
Any person adversely affected by this regulation may, within 30
days after publication of this document in the Federal Register, file
written objections to the regulation and may also request a hearing on
those objections. Objections and hearing requests must be filed with
the Hearing Clerk, at the address given above (40 CFR 178.20). A copy
of the objections and/or hearing requests filed with the Hearing Clerk
should be submitted to the OPP docket for this rulemaking. The
objections submitted must specify the provisions of the regulation
deemed objectionable and the grounds for the objections (40 CFR
178.25). Each objection must be accompanied by the fee prescribed by 40
CFR 180.33(i). If a hearing is requested, the objections must include a
statement of the factual issue(s) on which a hearing is requested, the
requestor's contentions on such issues, and a summary of any evidence
relied upon by the objector (40 CFR 178.27). A request for a hearing
will be granted if the Administrator determines that the material
submitted shows the following: There is genuine and substantial issue
of fact; there is a reasonable possibility that available evidence
identified by the requestor would, if established, resolve one or more
of such issues in favor of the requestor, taking into account
uncontested claims or facts to the contrary; and resolution of the
factual issue(s) in the manner sought by the requestor would be
adequate to justify the action requested (40 CFR 178.32).
EPA has established a record for this rulemaking under docket
number [PP 9F3714/R2214] (including any comments and data submitted
electronically). A public version of this record, including printed,
paper versions of electronic comments, which does not include any
information claimed as CBI, is available for inspection from 8 a.m. to
4:30 p.m., Monday through Friday, excluding legal holidays. The public
record is located in Room 1132 of the Public Response and Program
Resources Branch, Field Operations Division (7506C), Office of
Pesticide Programs, Environmental Protection Agency, Crystal Mall #2,
1921 Jefferson Davis Highway, Arlington, VA.
Electronic comments may be sent directly to EPA at:
[email protected] .
Electronic comments must be submitted as an ASCII file avoiding the
use of special characters and any form of encryption.
The official record for this rulemaking, as well as the public
version, as described above will be kept in paper form. Accordingly,
EPA will transfer any copies of objections and hearing requests
received electronically into printed, paper form as they are received
and will place the paper copies in the official rulemaking record which
will also include all comments submitted directly in writing. The
official rulemaking record is the paper record maintained at the
address in ``ADDRESSES'' at the beginning of this document.
Under Executive Order 12866 (58 FR 51735, October 4, 1993), the
Agency must determine whether the regulatory action is ``significant''
and therefore subject to all the requirements of the Executive Order
(i.e., Regulatory Impact Analysis, review by the Office of Management
and Budget (OMB)). Under section 3(f), the order defines
``significant'' as those actions likely to lead to a rule (1) having an
annual effect on the economy of $100 million or more, or adversely and
materially affecting a sector of the economy, productivity,
competition, jobs, the environment, public health or safety, or State,
local or tribal governments or communities (also known as
``economically significant''); (2) creating
[[Page 21380]]
serious inconsistency or otherwise interfering with an action taken or
planned by another agency; (3) materially altering the budgetary
impacts of entitlement, grants, user fees, or loan programs; or (4)
raising novel legal or policy issues arising out of legal mandates, the
President's priorities, or the principles set forth in this Executive
Order.
Pursuant to the terms of this Executive Order, EPA has determined
that this rule is not ``significant'' and is therefore not subject to
OMB review.
Pursuant to the requirements of the Regulatory Flexibility Act
(Pub. L. 96-354, 94 Stat. 1164, 5 U.S.C. 601-612), the Administrator
has determined that regulations establishing new tolerances or raising
tolerance levels or establishing exemptions from tolerance requirements
do not have a significant economic impact on a substantial number of
small entities. A certification statement to this effect was published
in the Federal Register of May 4, 1981 (46 FR 24950).
List of Subjects in 40 CFR Part 180
Environmental protection, Administrative practice and procedure,
Agricultural commodities, Pesticides and pests, Reporting and
recordkeeping requirements.
Dated: April 29, 1996.
Stephen L. Johnson,
Director, Registration Division, Office of Pesticide Programs.
Therefore, 40 CFR, chapter I, part 180 is amended as follows:
PART 180--[AMENDED]
1. The authority citation for part 180 continues to read as
follows:
Authority: 21 U.S.C. 346a and 371.
2. In Sec. 180.430 by revising paragraph (b) to read as follows:
Sec. 180.430 Fenoxaprop-ethyl; tolerances for residues.
* * * * *
(b) Time-limited tolerances, to expire November 1, 1997, are
established for the combined residues of the herbicide fenoxaprop-ethyl
[() ethyl 2-[4-[(6-chloro-2-
benzoxazolyl)oxy]phenoxy]propanoate] and its metabolites [2-[4-[(6-
chloro-2-benzoxazoly)oxy]phenoxy]propanoic acid and 6-chloro-2,3-
dihydrobenzoxazol-2-one], each expressed as fenoxaprop-ethyl, in or on
the following raw agricultural commodities:
------------------------------------------------------------------------
Parts per
Commodities million
------------------------------------------------------------------------
Cattle, fat................................................ 0.05
Cattle, meat............................................... 0.05
Cattle, mbyp............................................... 0.05
Goats, fat................................................. 0.05
Goats, meat................................................ 0.05
Goats, mbyp................................................ 0.05
Hogs, fat.................................................. 0.05
Hogs, meat................................................. 0.05
Hogs, mbyp................................................. 0.05
Horses, fat................................................ 0.05
Horses, meat............................................... 0.05
Horses, mbyp............................................... 0.05
Milk....................................................... 0.02
Sheep, fat................................................. 0.05
Sheep, meat................................................ 0.05
Sheep, mbyp................................................ 0.05
Wheat, grain............................................... 0.05
Wheat, straw............................................... 0.05
------------------------------------------------------------------------
[FR Doc. 96-11338 Filed 5-09-96; 8:45 am]
BILLING CODE 6560-50-F
Complete official Federal Register PDF
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21540-21736]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-10694]
[[Page 21539]]
_______________________________________________________________________
Part II
Department of Energy
_______________________________________________________________________
Federal Energy Regulatory Commission
_______________________________________________________________________
18 CFR Parts 35, 37 and 385
Electric Utilities (Federal Power Act); Promoting Wholesale Competition
Through Open Access Non-Discriminatory Transmission Services by Public
Utilities; Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities; Final Rules and Proposed Rule
Federal Register / Vol. 61, No. 92 / Friday, May 10, 1996 / Rules and
Regulations
[[Page 21540]]
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Parts 35 and 385
[Docket Nos. RM95-8-000 and RM94-7-001; Order No. 888]
Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery of
Stranded Costs by Public Utilities and Transmitting Utilities
Issued April 24, 1996.
AGENCY: Federal Energy Regulatory Commission, DOE.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission (Commission) is
issuing a Final Rule requiring all public utilities that own, control
or operate facilities used for transmitting electric energy in
interstate commerce to have on file open access non-discriminatory
transmission tariffs that contain minimum terms and conditions of non-
discriminatory service. The Final Rule also permits public utilities
and transmitting utilities to seek recovery of legitimate, prudent and
verifiable stranded costs associated with providing open access and
Federal Power Act section 211 transmission services. The Commission's
goal is to remove impediments to competition in the wholesale bulk
power marketplace and to bring more efficient, lower cost power to the
Nation's electricity consumers.
EFFECTIVE DATE: This Final Rule will become effective on July 9, 1996.
FOR FURTHER INFORMATION CONTACT:
David D. Withnell (Legal Information--Docket No. RM95-8-000), Office of
the General Counsel, Federal Energy Regulatory Commission, 888 First
Street NE., Washington, DC 20426, (202) 208-2063
Deborah B. Leahy (Legal Information--Docket No. RM94-7-001), Office of
the General Counsel, Federal Energy Regulatory Commission, 888 First
Street NE., Washington, DC 20426, (202) 208-2039
Michael A. Coleman (Technical Information), Office of Electric Power
Regulation, Federal Energy Regulatory Commission, 888 First Street NE.,
Washington, DC 20426, (202) 208-1236.
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission also provides all
interested persons an opportunity to inspect or copy the contents of
this document during normal business hours in the Public Reference Room
at 888 First Street, NE., Washington, DC 20426.
The Commission Issuance Posting System (CIPS), an electronic
bulletin board service, provides access to the texts of formal
documents issued by the Commission. CIPS is available at no charge to
the user and may be accessed using a personal computer with a modem by
dialing 202-208-1397 if dialing locally, or 1-800-856-3920 if dialing
long distance. CIPS is also available through the Fed World system (by
modem or Internet). To access CIPS, set your communications software to
19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex,
no parity, 8 data bits and 1 stop bit. The full text of this order will
be available on CIPS indefinitely in ASCII and WordPerfect 5.1 format.
The complete text on diskette in Wordperfect format may also be
purchased from the Commission's copy contractor, La Dorn Systems
Corporation, also located in the Public Reference Room at 888 First
Street NE., Washington, DC 20426.
Table of Contents
I. Introduction/Summary
II. Public Reporting Burden
III. Background
IV. Discussion
A. Scope of the Rule
1. Introduction
2. Functional Unbundling
3. Market-based Rates
4. Merger Policy
5. Contract Reform
6. Flow-based Contracting and Pricing
B. Legal Authority
1. Bases for Legal Authority
2. Response to Commenters Opposing our Legal Authority
C. Comparability
1. Eligibility to Receive Non-discriminatory Open Access
Transmission
2. Service that Must be Provided by Transmission Provider
3. Who Must Provide Non-discriminatory Open Access Transmission
4. Reservation of Transmission Capacity by Transmission
Customers
5. Reservation of Transmission Capacity for Future Use by
Utility
6. Capacity Reassignment
7. Information Provided to Transmission Customers
8. Consequences of Functional Unbundling
D. Ancillary Services
1. Definitions and Descriptions
2. Obligations of Transmission Providers and Transmission
Customers with Respect to Ancillary Services
3. Unbundling and Bundling Ancillary Services
4. Reassignment of Ancillary Services
5. Pricing of Ancillary Services
6. Accounting for Ancillary Services
E. Real-Time Information Networks
F. Coordination Arrangements: Power Pools, Public Utility
Holding Companies, Bilateral Coordination Arrangements, and
Independent System Operators
1. Tight Power Pools
2. Loose Pools
3. Public Utility Holding Companies
4. Bilateral Coordination Arrangements
G. Pro Forma Tariff
1. Tariff Provisions That Affect The Pricing Mechanism
2. Priority for Obtaining Service
3. Curtailment Provisions
4. Specific Tariff Provisions
H. Implementation
I. Federal and State Jurisdiction: Transmission/Local
Distribution
J. Stranded Costs
1. Justification for Allowing Recovery of Stranded Costs
2. Cajun Electric Power Cooperative, Inc. v. FERC
3. Responsibility for Wholesale Stranded Costs (Whether to Adopt
Direct Assignment to Departing Customers)
4. Recovery of Stranded Costs Associated with New Wholesale
Requirements Contracts
5. Recovery of Stranded Costs Associated with Existing Wholesale
Requirements Contracts
6. Recovery of Stranded Costs Caused by Retail-Turned-Wholesale
Customers
7. Recovery of Stranded Costs Caused by Retail Wheeling
8. Evidentiary Demonstration Necessary--Reasonable Expectation
Standard
9. Calculation of Recoverable Stranded Costs
10. Stranded Costs in the Context of Voluntary Restructuring
11. Accounting Treatment for Stranded Costs
12. Definitions, Application, and Summary
K. Other
1. Information Reporting Requirements for Public Utilities
2. Small Utilities
3. Regional Transmission Groups
4. Pacific Northwest
5. Power Marketing Agencies
6. Tennessee Valley Authority
7. Hydroelectric Power
8. Residential Customers
V. Environmental Statement
VI. Regulatory Flexibility Act Certification
VII. Information Collection Statement
VIII. Effective Date
Regulatory Text
Appendices (These Appendices will not appear in the Code of
Federal Regulations)
A. List of Section 211 Applications
B. List of Commenters in Docket Nos. RM95-8-000 and RM94-7-001
C. Allegations of Public Utilities Exercising Transmission
Dominance
D. Pro Forma Open Access Transmission Tariff
E. List of Group 1 Public Utilities
F. List of Group 2 Public Utilities
G. Legal Analysis of Commission Jurisdiction Over the Rates,
Terms and Conditions of Unbundled Retail Transmission In Interstate
Commerce
H. U.S. NOX Emissions
[[Page 21541]]
Statement of Commissioner Hoecker
Statement of Commissioner Massey
I. Introduction/Summary
Today the Commission issues three final, interrelated rules
designed to remove impediments to competition in the wholesale bulk
power marketplace and to bring more efficient, lower cost power to the
Nation's electricity consumers.1 The legal and policy cornerstone
of these rules is to remedy undue discrimination in access to the
monopoly owned transmission wires that control whether and to whom
electricity can be transported in interstate commerce. A second
critical aspect of the rules is to address recovery of the transition
costs of moving from a monopoly-regulated regime to one in which all
sellers can compete on a fair basis and in which electricity is more
competitively priced.
---------------------------------------------------------------------------
\1\ These rules are the rules on open access and stranded costs
in the above dockets (FERC Stats. & Regs. para. 31,036), and an
accompanying rule on Open Access Same-Time Information System and
Standards of Conduct (OASIS Final Rule) (FERC Stats. & Regs. para.
31,037) being issued contemporaneously. The Commission also is
issuing contemporaneously a notice of proposed rulemaking on
capacity reservation open access transmission tariffs in Docket No.
RM96-11-000, FERC Stats. & Regs. para. 32,517. These final rules and
proposed rule are being published concurrently in the Federal
Register.
---------------------------------------------------------------------------
In the year since the proposed rules were issued,2 the pace of
competitive changes in the electric utility industry has accelerated.
By March of last year, 38 public utilities had filed wholesale open
access transmission tariffs with the Commission. Today, prodded by such
competitive changes and encouraged by our proposed rules, 106 of the
approximately 166 public utilities that own, control, or operate 3
transmission facilities used in interstate commerce have filed some
form of wholesale open access tariff. In addition, since the time the
proposed rules were issued, numerous state regulatory commissions have
adopted or are actively evaluating retail customer choice programs or
other utility restructuring alternatives. These events have been
spurred by continuing pressures in the marketplace for changes in the
way electricity is bought, sold, and transported. Increasingly,
customers are demanding the benefits of competition in the growing
electricity commodity market.
---------------------------------------------------------------------------
\2\ On March 29, 1995, the Commission issued two notices of
proposed rulemaking concerning open access transmission and stranded
cost recovery. Promoting Wholesale Competition Through Open-Access
Non-Discriminatory Transmission Service by Public Utilities and
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Notice of Proposed Rulemaking and Supplemental Notice of
Proposed Rulemaking, 60 FR 17662 (April 7, 1995), FERC Stats. &
Regs. para. 32,514 (1995). On December 13, 1995, the Commission
issued a notice of proposed rulemaking on information systems. Real-
Time Information Networks and Standards of Conduct, Notice of
Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC Stats. &
Regs. para. 32,516 (1995).
\3\ The Commission's notice of proposed rulemaking in the above
dockets proposed to apply the proposed requirements to public
utilities that own and/or control facilities used for the
transmission of electric energy in interstate commerce. ``Own and/or
control'' is intended to include public utilities that ``operate''
facilities used for the transmission of electric energy in
interstate commerce. However, we have modified the Final Rule
regulatory text to remove any ambiguity.
---------------------------------------------------------------------------
The Commission estimates the potential quantitative benefits from
the Final Rule will be approximately $3.8 to $5.4 billion per year of
cost savings, in addition to the non-quantifiable benefits that include
better use of existing assets and institutions, new market mechanisms,
technical innovation, and less rate distortion. The continuing
competitive changes in the industry and the prospect of these benefits
to customers make it imperative that this Commission take the necessary
steps within its jurisdiction to ensure that all wholesale buyers and
sellers of electric energy can obtain non-discriminatory transmission
access, that the transition to competition is orderly and fair, and
that the integrity and reliability of our electricity infrastructure is
maintained.
In this Rule, the Commission seeks to remedy both existing and
future undue discrimination in the industry and realize the significant
customer benefits that will come with open access. Indeed, it is our
statutory obligation under sections 205 and 206 of the Federal Power
Act (FPA) to remedy undue discrimination.
To do so, we must eliminate the remaining patchwork of closed and
open jurisdictional transmission systems and ensure that all these
systems, including those that already provide some form of open access,
cannot use monopoly power over transmission to unduly discriminate
against others. If we do not take this step now, the result will be
benefits to some customers at the expense of others. We have learned
from our experience in the natural gas area the importance of
addressing competitive transition issues early and with as much
certainty to market participants as possible.
Accordingly, in this proceeding and in the accompanying proceeding
on OASIS, the Commission, pursuant to its authorities under sections
205 and 206 of the FPA:
Requires all public utilities that own, control or operate
facilities used for transmitting electric energy in interstate commerce
To file open access non-discriminatory transmission
tariffs that contain minimum terms and conditions of non-discriminatory
service;
To take transmission service (including ancillary
services) for their own new wholesale sales and purchases of electric
energy under the open access tariffs;
To develop and maintain a same-time information system
that will give existing and potential transmission users the same
access to transmission information that the public utility enjoys, and
further requires public utilities to separate transmission from
generation marketing functions and communications;
Clarifies Federal/state jurisdiction over transmission in
interstate commerce and local distribution and provides for deference
to certain state recommendations; and
Permits public utilities and transmitting utilities to
seek recovery of legitimate, prudent and verifiable stranded costs
associated with providing open access and FPA section 211 transmission
services.
Open Access
The Final Rule requires public utilities to file a single open
access tariff that offers both network, load-based service and point-
to-point, contract-based service. The Rule contains a pro forma tariff
that reflects modifications to the NOPR's proposed terms and conditions
and also permits variations for regional practices. All public
utilities subject to the Rule, including those that already have
tariffs on file, will be required to make section 206 compliance
filings to meet the new pro forma tariff non-price minimum terms and
conditions of non-discriminatory transmission. Utilities may propose
their own rates in a section 205 compliance filing.
The Rule provides that public utilities may seek a waiver of some
or all of the requirements of the Final Rule. In addition, non-public
utilities may seek a waiver of the tariff reciprocity provisions.
The Final Rule does not generically abrogate existing requirements
contracts, but will permit customers and public utilities to seek
modification, or termination, of certain existing requirements
contracts on a case-by-case basis. As to coordination arrangements and
contracts, the Rule finds that these arrangements and contracts may
need to be modified to remove unduly discriminatory transmission access
and/or pricing provisions. Such arrangements and agreements include
power pool agreements, public utility
[[Page 21542]]
holding company agreements, and certain bilateral coordination
agreements. The Rule provides guidance and timelines for modifying
unduly discriminatory coordination arrangements and contracts, and
specifies when the members of such arrangements must begin to conduct
trade with each other using the same open access tariff offered to
others. The Rule also provides guidance regarding the formation of
independent system operators (ISOs).
The Rule does not require any form of corporate restructuring, but
will accommodate voluntary restructuring that is consistent with the
Rule's open access and comparability policies.
As discussed in the NOPR, not all owners or controllers of
interstate transmission facilities are subject to the Commission's
jurisdiction under sections 205 and 206 of the FPA and therefore are
not subject to this Rule's open access requirements. Therefore, the
Final Rule retains the proposed reciprocity provision in the pro forma
tariff. Without such a provision, non-open access utilities could take
advantage of the competitive opportunities of open access, while at the
same time offering inferior access, or no access at all, over their own
facilities. Thus, open access utilities would be unfairly burdened. We
note that some non-jurisdictional utilities have expressed an interest
in a mechanism for obtaining a Commission determination that their
transmission tariffs satisfy the reciprocity provisions in the pro
forma tariffs, and we provide such a mechanism in the Rule.
The Final Rule does not generically provide for market-based
generation rates. Although the Rule codifies the Commission's prior
decision that there is no generation dominance in new generating
capacity, intervenors in cases may raise generation dominance issues
related to new capacity. In addition, to obtain market-based rates for
existing generation, we will continue to require public utilities to
show, on a case-by-case basis, that there is no generation dominance in
existing capacity. Further, in all market-based rate cases, we will
continue to look at whether an applicant and its affiliates could erect
other barriers to entry and whether there may be problems due to
affiliate abuse or reciprocal dealing.
Finally, contemporaneously with this Rule the Commission issues an
NOPR on capacity reservation tariffs as an alternative, and perhaps
superior, means of remedying undue discrimination.
Transmission/Local Distribution
The Rule clarifies the Commission's interpretation of the Federal/
state jurisdictional boundaries over transmission and local
distribution. While we reaffirm our conclusion that this Commission has
exclusive jurisdiction over the rates, terms, and conditions of
unbundled retail transmission in interstate commerce by public
utilities, we nevertheless recognize the very legitimate concerns of
state regulatory authorities as they contemplate direct retail access
or other state restructuring programs. Accordingly, we specify
circumstances under which we will give deference to state
recommendations. Although jurisdictional boundaries may shift as a
result of restructuring programs in wholesale and retail markets, we do
not believe this will change fundamental state regulatory authorities,
including authority to regulate the vast majority of generation asset
costs, the siting of generation and transmission facilities, and
decisions regarding retail service territories. We intend to be
respectful of state objectives so long as they do not balkanize
interstate transmission of power or conflict with our interstate open
access policies.
Stranded Costs
With regard to stranded costs, the Final Rule adopts the
Commission's supplemental proposal. It will permit utilities to seek
extra-contractual recovery of stranded costs associated with a limited
set of existing (executed on or before July 11, 1994) wholesale
requirements contracts and provides that the Commission will be the
primary forum for utilities to seek recovery of stranded costs
associated with retail-turned-wholesale transmission customers. It also
will allow utilities to seek recovery of stranded costs caused by
retail wheeling only in circumstances in which the state regulatory
authority does not have authority to address retail stranded costs at
the time the retail wheeling is required. The Rule retains the revenues
lost approach for calculating stranded costs and provides a formula for
calculating such costs.
Environmental Issues
The Commission has prepared a Final Environmental Impact Statement
(FEIS) evaluating the possible environmental consequences of changes in
the bulk power marketplace expected to occur as a result of the open
access requirements of this Final Rule. The FEIS focuses, as do most
commenters, on possible increases in emissions of nitrogen oxides
(NOX) from certain fossil-fuel fired generators, which could
affect air quality in the producing region and in areas to which these
emissions may be carried.
In response to comments on the Draft EIS, the Commission performed
numerous additional studies. The FEIS finds that the relative future
competitiveness of coal and natural gas generation is the key variable
affecting the impact of the Final Rule. If competitive conditions favor
natural gas, the Rule is likely to lead to environmental benefits. Both
EPA and the Commission staff believe this projected scenario is the
more likely one. If competitive conditions favor coal, the Rule may
lead to small negative environmental impacts. However, even using the
most extreme, unlikely assumptions about the future of the industry,
the negative consequences are not likely to occur until after the turn
of the century. Because the impacts will remain modest at least until
2010, there is no need for an interim mitigation program. In addition,
even if the data showed more significant negative consequences
requiring mitigation, the Commission does not have the statutory
authority under the Federal Power Act or the expertise to address this
possible far-term problem. The Commission believes, however, that there
is time for federal and state air quality authorities to address any
potential adverse impact as part of a comprehensive NOX regulatory
program under the Clean Air Act.4
---------------------------------------------------------------------------
\4\ 42 U.S.C. 7401, et seq.
---------------------------------------------------------------------------
Despite our conclusions regarding the lack of environmental impacts
expected to result from the Rule, the Commission has examined a wide
variety of proposals for mitigating possible adverse effects. We share
the view of most commenters that the preferred approach for mitigating
increased NOX emissions generally is a NOX cap and trading
regulatory program comparable to that developed by Congress to address
sulfur dioxide emissions in the Clean Air Act Amendments of 1990.5
The Commission has examined various means of establishing such a
program, including use of existing federal authorities under the Clean
Air Act, cooperative efforts by state and federal air quality
regulators, and development of a new emissions regulatory program
administered by the Commission under the Federal Power Act. The
Commission has concluded that a NOX regulatory program could best
be developed and administered under the Clean Air Act, in cooperation
with interested states, and offers to lend Commission support
[[Page 21543]]
to that effort should it become necessary.
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\5\ 42 U.S.C.A. 7651b-e.
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Conclusion
The Commission believes that the Final Rule will remedy undue
discrimination in transmission services in interstate commerce and
provide an orderly and fair transition to competitive bulk power
markets.
II. Public Reporting Burden
The Open Access Final Rule and the Stranded Cost Final Rule specify
filing requirements to be followed by public utilities that own,
control or operate transmission facilities in interstate commerce in
making non-discriminatory open access tariff filings and filings to
recover legitimate, prudent and verifiable stranded costs. The
information collection requirements of the final rules are attributable
to FERC-516 ``Electric Rate Filings.'' The current total annual
reporting burden for FERC-516 is 828,300 hours.
A. Docket No. RM95-8-000 (Open Access Final Rule)
The Open Access Final Rule requires public utilities filing non-
discriminatory open access tariffs to provide certain information to
the Commission. The Commission estimated that the public reporting
burden for the information collection would average 300 hours per
response. This estimate included time for reviewing the requirements of
the Commission's regulations, searching existing data sources,
gathering and maintaining the necessary data, completing and reviewing
the collection of information, and filing the revised information. No
comments on the burden estimate were received. Because the Final Rule
adopts essentially the same information requirements that are contained
in the proposed rule, we believe that the average filing burden is same
for the Final Rule.
In the proposed rule, the Commission noted that there are
approximately 328 public utilities, including marketers and wholesale
generation entities. We initially estimated that 137 public utilities
own, control or operate facilities used for the transmission of
electric energy in interstate commerce, and would be subject to the
filing requirements of the proposed rule. Upon further review, the
Commission believes that approximately 166 public utilities will
respond to the information collection. Accordingly, the public
reporting burden is estimated to be 49,800 hours.
B. Docket No. RM94-7-001 (Stranded Cost Final Rule)
In the supplemental notice of proposed rulemaking, the Commission
estimated that the information requirements of the proposed rule would
not differ substantially from those contained in the initial proposed
rule. In that notice, the Commission estimated that the public
reporting burden for the information requirements contained in the
proposed rule would be 50 hours per response with 10 responses
annually. No comments on this filing burden were received. The
information requirements adopted in the Stranded Cost Final Rule are
not substantially different from those in the proposed rule. Therefore,
the Commission concludes that there will be no additional public filing
burden associated with the Stranded Cost Final Rule.
III. Background
In the NOPR, we set out a detailed statement of the events leading
up to this rulemaking. We repeat that background here, updated to
reflect what has happened since March 1995, and discuss why it is
necessary to undertake regulatory reform in the electric industry at
this time. We do so to provide the necessary backdrop to our action in
adopting this Rule.
A. Structure of the Electric Industry at Enactment of Federal Power Act
The Federal Power Act was enacted in an age of mostly self-
sufficient, vertically integrated electric utilities, in which
generation, transmission, and distribution facilities were owned by a
single entity and sold as part of a bundled service (delivered electric
energy) to wholesale and retail customers. Most electric utilities
built their own power plants and transmission systems, entered into
interconnection and coordination arrangements with neighboring
utilities, and entered into long-term contracts to make wholesale
requirements sales (bundled sales of generation and transmission) to
municipal, cooperative, and other investor-owned utilities (IOUs)
connected to each utility's transmission system. Each system covered
limited service areas. This structure of separate systems arose
naturally due primarily to the cost and technological limitations on
the distance over which electricity could be transmitted.
Through much of the 1960s, utilities were able to avoid price
increases, but still achieve increased profits, because of substantial
increases in scale economies, technological improvements, and only
moderate increases in input prices.6 Thus, there was no pressure
on regulatory commissions to use regulation to affect the structure of
the industry.7
---------------------------------------------------------------------------
\6\ Paul L. Joskow, Inflation and Environmental Concern:
Structural Change in the Process of Public Utility Regulation, 17 J.
Law & Econ. 291, 312 (1974); see also Charles F. Phillips, Jr., The
Regulation of Public Utilities 11 (1988).
\7\ See Joskow, supra at 312; see also Phillips, supra at 12.
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B. Significant Changes in the Electric Industry
In the late 1960s and throughout the 1970s, a number of significant
events occurred in the electric industry that changed the perceptions
of utilities and began a shift to a more competitive marketplace for
wholesale power.8 This was the beginning of periods of rapid
inflation, higher nominal interest rates, and higher electricity
rates.9 During this time, consumers became concerned about higher
electricity rates and questioned any price increases filed by
utilities.10
---------------------------------------------------------------------------
\8\ See Joskow, supra at 312; see also Phillips, supra at 12-13.
\9\ See Joskow, supra at 312-13; see also Phillips, supra at 13.
The Arab oil embargo resulted in significantly higher oil prices
through the 1970s. See Richard J. Pierce, Jr., The Regulatory
Treatment of Mistakes in Retrospect: Canceled Plants and Excess
Capacity, 132 U. Pa. L. Rev. 497, 501 (1984).
\10\ See Joskow, supra at 313; see also Phillips, supra at 13.
---------------------------------------------------------------------------
During this same time frame, the construction of nuclear and other
capital-intensive baseload facilities--actively encouraged by federal
and some state governments--contributed to the continuing cost
increases and uncertainties in the industry.11 These investments
were made based on the assumptions that there would be steady increases
in the demand for electricity and continued large increases in the
price of oil.12 However, due to conservation and economic
downturns, the expected demand increases did not materialize. Load
growth virtually disappeared in some areas, and many utilities
unexpectedly found themselves with excess capacity.13 In addition,
by the 1980s, the oil cartel collapsed, with a resulting glut of low-
priced oil.14 At the same time, inflation substantially increased
the costs of these large
[[Page 21544]]
baseload generating plants.15 Surging interest rates further
increased the cost of the capital needed to finance and capitalize
these projects and completion schedules were significantly extended by,
in part, more stringent safety and environmental requirements.16
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\11\ See generally Jersey Central Power & Light Company v. FERC,
810 F.2d 1168, 1171 (D.C. Cir. 1987).
\12\ Id.
\13\ See Pierce, supra at 503. By 1983, the Department of Energy
had estimated that the sunk costs for canceled nuclear plants alone
amounted to $10 billion. Id. at 498.
\14\ Id.
\15\ See Bernard S. Black & Richard J. Pierce, Jr., The Choice
Between Markets and Central Planning in Regulating the U.S.
Electricity Industry, 93 Col. L. Rev. 1339, 1346 (1993) (``Actual
costs of nuclear power plants vastly exceeded estimates, sometimes
by as much as 1000%.'').
\16\ See Phillips, supra at 13. Fossil fuel-fired plants became
subject to increased regulation as a result of the Clean Air Act of
1970, and its 1977 amendments. 42 U.S.C. 7401-7642. In 1971, nuclear
plant licensing became subject to the environmental impact statement
requirements of the National Environmental Policy Act of 1969. 42
U.S.C. 4332. Following the 1979 accident at the Three Mile Island
nuclear plant, nuclear plants also became subject to additional
safety regulations, resulting in higher costs. See Energy
Information Administration, The Changing Structure of the Electric
Power Industry 1970-1991 (March 1993) 35. Between 1976 and 1980,
most states and many localities instituted laws governing power
plant siting.
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As a result, expensive large baseload plants for which there was
little or no demand, came onto the market or were in the process of
being constructed. Accordingly, between 1970 and 1985, average
residential electricity prices more than tripled in nominal terms, and
increased by 25% after adjusting for general inflation.17
Moreover, average electricity prices for industrial customers more than
quadrupled in nominal terms over the same period and increased 86%
after adjusting for inflation.18 The rapidly increasing rates for
electric power during this period, together with the opportunities
provided by the Public Utility Regulatory Policies Act of 1978 (PURPA)
(discussed infra), also prompted some industrial customers to bypass
utilities by constructing their own generation facilities. This further
exacerbated rate increases for remaining customers--primarily
residential and commercial customers.
---------------------------------------------------------------------------
\17\ Based on retail prices reported in Energy Information
Administration (EIA), Monthly Energy Review, January 1995, Table 9.9
(Prices adjusted for inflation using the GDP Deflator (1987 = 100)).
\18\ Id.
---------------------------------------------------------------------------
Consumers responded to these ``rate shocks'' by exerting pressure
on regulatory bodies to investigate the prudence of management
decisions to build generating plants, especially when construction
resulted in cost overruns, excess capacity, or both. Between 1985 and
1992, writeoffs of nuclear power plants totalled $22.4 billion.19
These writeoffs significantly reduced the earnings of the affected
utilities.20 Delays in obtaining rate increases to reflect the
effects of inflation further reduced investor returns. Thus, many
utilities became reluctant to commit capital to long-term construction
decisions involving large scale generating plants.21
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\19\ See Black & Pierce, supra at 1346 (These writeoffs were
``about 17% of the book value of total 1992 utility investment.'').
\20\ Id.
\21\ Id. (``The high perceived risk of future disallowances
reversed utilities' incentives to overinvest, and made utilities
extremely reluctant to build new power plants.'').
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In addition to economic changes in the industry, significant
technological changes in both generation and transmission have occurred
since 1935. Through the 1960s, bigger was cheaper in the generation
sector and the industry was able to capitalize on economies of scale to
produce power at lower per-unit costs from larger and larger
plants.22 As a result, large utility companies that could finance
and manage construction projects of larger scale had a price advantage
over smaller utility companies and customers who might otherwise have
considered building their own generating units. Scale economies
encouraged power generation by large vertically-integrated utility
companies that also transmitted and distributed power. Beginning in the
1970s, however, additional economies of scale in generation were no
longer being achieved.23 A significant factor was that larger
generation units were found to need relatively greater maintenance and
experience longer downtimes.24 The electric industry faced the
situation ``where the price of each incremental unit of electric power
exceeded the average cost.'' 25 Bigger was no longer better.
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\22\ See Preston Michie, Billing Credits for Conservation,
Renewable, and Other Electric Power Resources: an Alternative to
Marginal-Cost-Based Power Rates in the Pacific Northwest, 13
Environmental Law 963, 964-65 (1983).
\23\ Id. at 965.
\24\ Energy Information Administration, The Changing Structure
of the Electric Power Industry 1970-1991 (March 1993) 37 (``As
larger units were constructed, however, utilities discovered that
downtime was as much as 5 times greater for units larger than 600
megawatts than for units in the 100-megawatt range.'')
\25\ Id.; see also George A. Perrault, Downsizing Generation:
Utility Plans for the 1990s, Pub. Util. Fort. 15-16 (Sept. 27, 1990)
(``The large base-load generating units that form the backbone of
utility systems are almost totally absent from capacity plans for
the 1990s.'').
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Further dictating against larger generation units were advances in
technologies that allowed scale economies to be exploited by smaller
size units, thereby allowing smaller new plants to be brought on line
at costs below those of the large plants of the 1970s and earlier. Such
new technologies include combined cycle units and conventional steam
units that use circulating fluidized bed boilers.26
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\26\ ``From 1982 through 1991, the average capacity of
fluidized-bed units increased rapidly to 72 megawatts for 4 units in
1991. The average capacity for the 19 units planned to begin
operating in 1992 through 1995 increases to 83 megawatts.'' Energy
Information Administration, The Changing Structure of the Electric
Power Industry 1970-1991 (March 1993) 38.
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The combined cycle generating plants generally use natural gas as
their primary fuel. This technology has been made possible by the
development of more efficient gas turbines, shorter construction lead
times, lower capital costs, increased reliability, and relatively
minimal environmental impacts.27 Similarly, the circulating
fluidized bed combustion boilers, fueled by coal and other conventional
fuels, provide a more efficient and less polluting resource.
---------------------------------------------------------------------------
\27\ See Charles E. Bayless, Less is More: Why Gas Turbines Will
Transform Electric Utilities, Pub. Util. Fort. (Dec. 1, 1994) 21.
---------------------------------------------------------------------------
Today, ``the optimum size (of generation plants) has shifted from
(more than 500 MW) (10-year lead time) to smaller units (one-year lead
time) (in the 50- to 150-MW range).'' 28 Indeed, smaller and more
efficient gas-fired combined-cycle generation facilities can produce
power on the grid at a cost ranging from 5 cents per kWh to less than 3
cents per kWh.29 This is significantly less than the costs for
large plants constructed and installed by utilities over the last
decade, which were typically in the range of 4 to 7 cents per kWh for
coal plants and 9 to 15 cents for nuclear plants.30 Significant
changes have also occurred in the transmission sector of the industry.
Technological advances in transmission have made possible the economic
transmission of electric power over long distances at higher
voltages.31 This has
[[Page 21545]]
made it technically feasible for utilities with lower cost generation
sources to reach previously isolated systems where customers had been
captive to higher cost generation. In addition, the nature and
magnitude of coordination transactions 32 have changed
dramatically since enactment of the FPA, allowing increased coordinated
operations and reduced reserve margins. Substantial amounts of
electricity now move between regions, as well as between utilities in
the same region. Physically isolated systems have become a thing of the
past.
---------------------------------------------------------------------------
\28\ Id. at 24. See also Wallace E. Brand, Is Bigger Better?
Market Power in Bulk Power Supply: From FDR to NOPR, Pub. Util.
Fort. (Feb. 15, 1996) 23 at 25 (while the optimal baseload unit size
is about 500 MW for coal-fired steam turbines, the optimal size for
gas fired combined-cycle units is about 150 to 200 MW).
\29\ FERC staff calculations based in part on combined-cycle
plant cost data reported in 1994 FERC Form No. 1 for a sample of
units placed in service during 1990-94. Costs vary with regional
fuel and construction costs, among other reasons.
\30\ Coal and Nuclear plant cost data reported in 1994 FERC Form
No. 1 and the EIA report, Electric Plant Cost and Power Production
Expenses 1991, 1993 DOE/EIA-0455(91), for plants placed in service
during 1986-94; see also The 1994 Electric Executives' Forum, Bakke
(President and CEO of the AES Corporation), Pub. Util. Fort. (June
1, 1994) 45 (``New generation can be built at about 3 cents per
kilowatt-hour (U.S. average). Old generation costs about twice that
* * *'').
\31\ See Black & Pierce, supra at 1345 (In the late 1960s and
1970s, improved transmission efficiency and development of regional
transmission networks ``made it possible to build power plants up to
1000 miles from power users.'').
\32\ Coordination transactions are voluntary sales or exchanges
of specialized electricity services that allow buyers to realize
cost savings or reliability gains that are not attainable if they
rely solely on their own resources. For sellers, these transactions
provide opportunities to earn additional revenue, and to lower
customer rates, from capacity that is temporarily excess to native
load capacity requirements.
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C. The Public Utility Regulatory Policies Act and the Growth of
Competition
In enacting PURPA,33 Congress recognized that the rising costs
and decreasing efficiencies of utility-owned generating facilities were
increasing rates and harming the economy as a whole.34 To lessen
dependence on expensive foreign oil, avoid repetition of the 1977
natural gas shortage, and control consumer costs, Congress sought to
encourage electric utilities to conserve oil and natural gas.35 In
particular, Congress sanctioned the development of alternative
generation sources designated as ``qualifying facilities'' (QFs) as a
means of reducing the demand for traditional fossil fuels.36 PURPA
required utilities to purchase power from QFs at a price not to exceed
the utility's avoided costs and to sell backup power to QFs.37
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\33\ Pub. L. No. 95-617, 92 Stat. 3117 (codified in U.S.C.
sections 15, 16, 26, 30, 42, and 43).
\34\ See generally FERC v. Mississippi, 456 U.S. 742, 745-46
(1982).
\35\ The Power Plant and Industrial Fuel Use Act of 1978. Pub.
L. No. 95-617, 92 Stat. 3117 (codified in U.S.C. sections 15, 16,
26, 30, 42, and 43).
\36\ QFs include certain cogenerators and small power producers.
PURPA also added sections 210, 211, and 212 to the FPA, providing
the Commission with authority to approve applications for
interconnections and, in limited circumstances, wheeling. However,
under section 211, as enacted in PURPA, the Commission could approve
an application for wheeling only if it found, inter alia, that the
order ``would reasonably preserve existing competitive
relationships.'' Because of this and other limitations in sections
211 and 212 as originally enacted, the provision was virtually
ineffective. Only one section 211 order was ever issued pursuant to
the original provision, and it was pursuant to a settlement. See
Public Service Company of Oklahoma, 38 FERC para. 61,050 (1987). As
discussed infra, section 211 was subsequently revised by the Energy
Policy Act of 1992.
\37\ 456 U.S. at 750. Congress recognized that encouragement was
needed in part because utilities had been reluctant to purchase
electric power from, and sell power to, nonutility generators. Id.
at 750-51.
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PURPA specifically set forth limitations on who, and what, could
qualify as QFs. In addition to technological and size criteria, PURPA
set limits on who could own QFs.38 Notwithstanding these
limitations, QFs proliferated. In 1989, there were 576 QF facilities.
By 1993, there were more than 1,200 such facilities.39 For the
same time period, installed QF capacity increased from 27,429 megawatts
to 47,774 megawatts.40 The rapid expansion and performance of the
QF industry demonstrated that traditional, vertically integrated public
utilities need not be the only sources of reliable power.
---------------------------------------------------------------------------
\38\ For example, PURPA provided that a cogeneration facility or
small power production facility could not be owned by a person
primarily engaged in the generation or sale of electric power (other
than from cogeneration or small power production facilities). See 16
U.S.C.
\39\ Energy Information Administration, Electric Power Annual
1993 (December 1994) 124 (Table 77).
\40\ Id. EIA data for 1989 through 1991 was for facilities of 5
megawatts or more and for 1992 and 1993 was for facilities of 1
megawatt or more. A comparison with Table 74 on page 121 for the
years 1992 and 1993 reveals that this mixing of data bases is likely
of minimal effect.
---------------------------------------------------------------------------
During this period, the profile of generation investment began to
change, and a market for non-traditional power supply beyond the
purchases required by PURPA began to emerge. QFs were limited to
cogenerators and small power producers.41
---------------------------------------------------------------------------
\41\ Generally, the law has imposed an 80 MW cap on small power
producers. A limited exception enacted in 1990 permitted small power
facilities that could exceed 80 MW and still qualify as QFs under
PURPA. This exception was limited to certain solar, wind, waste, and
geothermal small power production facilities and only covered
applications for certification of facilities as qualifying small
power production facilities that were submitted no later than
December 31, 1994 and for which construction commences no later than
December 31, 1999. See Solar, Wind, Waste, and Geothermal Power
Production Incentives Act of 1990, Pub. L. No. 101-575, 104 Stat.
2834 (1990), amended, Pub. L. No. 102-46, 105 Stat. 249 (1991).
---------------------------------------------------------------------------
However, other non-traditional power producers who could not meet
the QF criteria began to build new capacity to compete in bulk power
markets, without such PURPA benefits as the mandatory purchase
requirements. These producers, known as independent power producers
(IPPs), were predominantly single-asset generation companies that did
not own any transmission or distribution facilities. While traditional
utilities were generally reluctant at that time to invest in new
generating facilities under cost of service regulation, utilities
increasingly became interested in participating in this new generation
sector. They organized affiliated power producers (APPs), with assets
not included in utility rate base, and sought to sell power in their
own service territories and the territories of other utilities. At the
same time, power marketers arose. These entities--owning no
transmission or generation--buy and sell power.42
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\42\ The first power marketer in the electric industry was
Citizens Energy Corporation. See Citizens Energy Corporation, 35
FERC para. 61,198 (1986). Power marketers take title to electric
energy. Power brokers, on the other hand, do not take title and are
limited to a matchmaking role.
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There were two major impediments to the development of IPPs and
APPs. First, the ownership restrictions of the Public Utility Holding
Company Act (PUHCA) 43 severely inhibited these new entities from
entering the generation business.44 Second, these entities needed
transmission service in order to compete in electricity markets.
---------------------------------------------------------------------------
\43\ 15 U.S.C. 79 et seq.
\44\ As discussed infra, Congress eventually provided a means to
avoid the PUHCA restrictions by creating exempt wholesale generators
(EWGs) in the Energy Policy Act.
---------------------------------------------------------------------------
While the Commission had no authority to remove PUHCA
restrictions,45 it encouraged the development of IPPs and APPs, as
well as emerging power marketers, by authorizing market-based rates for
their power sales on a case-by-case basis and by encouraging more
widely available transmission access. From 1989 through 1993,
facilities owned by IPPs and other non-traditional generators (other
than QFs) increased from 249 to 634 and their installed capacity
increased from 9,216 megawatts to 13,004 megawatts.46 Indeed,
``[i]n 1992, for the first time, generating capacity added by
independent producers exceeded capacity added by utilities.'' 47
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\45\ The industry was successful to some extent in developing
ownership structures that permitted such investment. See, e.g.,
Commonwealth Atlantic Limited Partnership, 51 FERC para. 61,368 at
62,240 and n.20 (1990).
\46\ Energy Information Administration, Electric Power Annual
1993 (December 1994) 124 (Table 77).
\47\ Black & Pierce, supra at 1349 n.25.
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Market-based rates helped to develop competitive bulk power
markets. A generating utility allowed to sell its power at market-based
rates could move more quickly to take advantage of short-term or even
long-term market opportunities than those laboring under traditional
cost-of-service tariffs, which entail procedural delays in achieving
tariff approvals and changes.
In approving these market-based rates, the Commission required,
inter alia, that the seller and any of its affiliates lack market power
or mitigate any market
[[Page 21546]]
power that they may have possessed.48 The major concern of the
Commission was whether the seller or its affiliates could limit
competition and thereby drive up prices. A key inquiry became whether
the seller or its affiliates owned or controlled transmission
facilities in the relevant service area and therefore, by denying
access or imposing discriminatory terms or conditions on transmission
service, could foreclose other generators from competing.49 As we
have previously explained:
\48\ See, e.g., Ocean State Power, 44 FERC para. 61,261 (1988);
Commonwealth Atlantic Limited Partnership, 51 FERC para. 61,368
(1990); Citizens Power & Light Company, 48 FERC para. 61,210 (1989);
Orange and Rockland Utilities, Inc., 42 FERC para. 61,012 (1988);
Doswell Limited Partnership, 50 FERC para. 61,251 (1990) (Doswel);
and Dartmouth Power Associates Limited Partnership, 53 FERC para.
61,117 (1990).
\49\ See, e.g., Doswell, 50 FERC at 61,757.
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The most likely route to market power in today's electric
utility industry lies through ownership or control of transmission
facilities. Usually, the source of market power is dominant or
exclusive ownership of the facilities. However, market power also
may be gained without ownership. Contracts can confer the same
rights of control. Entities with contractual control over
transmission facilities can withhold supply and extract monopoly
prices just as effectively as those who control facilities through
ownership.50
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\50\ Citizens Power & Light Corporation, 48 FERC para. 61,210 at
61,777 (1989) (emphasis in original); see also Utah Power & Light
Company, PacifiCorp and PC/UP&L Merging Corporation, 45 FERC para.
61,095 at 61,287-89 (1988), order on reh'g, 47 FERC para. 61,209,
order on reh'g, 48 FERC para. 61,035 (1989), remanded in part sub
nom. Environmental Action, Inc. v. FERC, 939 F.2d 1057 (D.C. Cir.
1991), order on remand, 57 FERC para. 61,363 (1991).
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As entry into wholesale power generation markets increased, the
ability of customers to gain access to the transmission services
necessary to reach competing suppliers became increasingly
important.51 In addition, beginning in the late 1980s, in order to
mitigate their market power to meet Commission conditions, public
utilities seeking Commission approval of mergers or consolidations
under section 203 of the FPA or Commission authorization for blanket
approval of market-based rates for generation services under section
205 of the FPA, filed ``open access'' transmission tariffs of general
applicability.52 The Commission applied its market rate analysis
to IOUs, as well as IPPs, APPs, and marketers, and allowed IOUs to sell
at market-based rates only if they opened their transmission systems to
competitors.53 The Commission also approved proposed mergers on
the condition that the merging companies remedy anticompetitive effects
potentially caused by the merger by filing ``open access'' tariffs.
These early ``open access'' tariffs required only that the companies
provide point-to-point transmission services, which is a much narrower
requirement than that being imposed in this Rule and did not require
transmission owners to provide to others the same quality of service
that they themselves enjoyed.
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\51\ In earlier years, a few customers were able to obtain
access as a result of litigation, beginning with the Supreme Court's
decision in Otter Tail Power Company v. United States, 410 U.S. 366
(1973). Additionally, some customers gained access by virtue of
Nuclear Regulatory Commission license conditions and voluntary
preference power transmission arrangements associated with federal
power marketing agencies. See, e.g., Consumers Power Company, 6 NRC
887, 1036-44 (1977) and The Toledo Edison Company and Cleveland
Electric Illuminating Company, 10 NRC 265, 327-34 (1979). See
Florida Municipal Power Agency v. Florida Power and Light Company,
839 F. Supp. 1563 (M.D. Fla. 1993). See also Electricity
Transmission: Realities, Theory and Policy Alternatives, The
Transmission Task Force Report to the Commission, October 1989, 197.
\52\ See, e.g., Public Service Company of Colorado, 59 FERC
para. 61,311 (1992), reh'g denied, 62 FERC para. 61,013 (1993); Utah
Power & Light Company, et al., Opinion No. 318, 45 FERC para. 61,095
(1988), order on reh'g, Opinion No. 318-A, 47 FERC para. 61,209
(1989), order on reh'g, Opinion No. 318-B, 48 FERC para. 61,035
(1989), aff'd in relevant part sub nom. Environmental Action Inc. v.
FERC, 939 F.2d 1057 (D.C. Cir. 1991); Northeast Utilities Service
Company (Public Service Company of New Hampshire), Opinion No. 364-
A, 58 FERC para. 61,070, reh'g denied, Opinion No. 364-B, 59 FERC
para. 61,042, order granting motion to vacate and dismissing request
for rehearing, 59 FERC para. 61,089 (1992), affirmed in relevant
part sub nom. Northeast Utilities Service Company v. FERC, 993 F.2d
937 (1st Cir. 1993).
\53\ See, e.g., Public Service of Indiana, Inc., 51 FERC para.
61,367 (1990), reh'g denied, 52 FERC para. 61,260 (1990), appeal
dismissed sub nom. Northern Indiana Public Service Company v. FERC,
954 F.2d 736 (D.C.Cir. 1992).
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Following PURPA, the economic and technological changes in the
transmission and generation sectors helped give impetus to the many new
entrants in the generating markets who could sell electric energy
profitably with smaller scale technology at a lower price than many
utilities selling from their existing generation facilities at rates
reflecting cost. However, it became increasingly clear that the
potential consumer benefits that could be derived from these
technological advances could be realized only if more efficient
generating plants could obtain access to the regional transmission
grids. Because many traditional vertically integrated utilities still
did not provide open access to third parties and still favored their
own generation if and when they provided transmission access to third
parties, barriers continued to exist to cheaper, more efficient
generation sources.
D. The Energy Policy Act
In response to the competitive developments following PURPA, and
the fact that PUHCA and lack of transmission access remained major
barriers to new generators, Congress enacted Title VII of the Energy
Policy Act of 1992 (Energy Policy Act).54 A goal of the Energy
Policy Act was to promote greater competition in bulk power markets by
encouraging new generation entrants, known as exempt wholesale
generators (EWGs), and by expanding the Commission's authority under
sections 211 and 212 of the FPA to approve applications for
transmission services.55
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\54\ Pub. L. No. 102-486, 106 Stat. 2776 (1992), codified at,
among other places, 15 U.S.C. 79z-5a and 16 U.S.C. 796 (22-25),
824j-l.
\55\ See El Paso Electric Company and Central and South West
Services Inc., 68 FERC para. 61,181 at 61,914 (1994) (CSW); see also
Paul Kemezis, FERC's Competitive Muscle: The Comparability Standard,
Electrical World 45 (Jan. 1995) (``In EPAct, Congress made it clear
that the electric-power industry was to move toward a fully
competitive market system, but left most of the implementation to
FERC.'').
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An EWG is defined as
Any person determined by the Federal Energy Regulatory
Commission to be engaged directly, or indirectly through one or more
affiliates as defined in [PUHCA] section 2(a)(11)(B), and
exclusively in the business of owning or operating, or both owning
and operating, all or part of one or more eligible facilities and
selling electric energy at wholesale.56
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\56\ 15 U.S.C. 79z-5a.
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If the Commission, upon an application, determines that a person is
an EWG, that person will be exempt from PUHCA.57 This provision
removed a significant impediment to the development of IPPs and APPs by
allowing them to develop projects as EWGs free from the strictures of
PUHCA or the QF PURPA limitations.
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\57\ 15 U.S.C. 79z-5a(e).
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While sections 211 and 212, as enacted by PURPA, were intended to
provide greater access to the transmission grid, the limitations placed
on these sections made them unusable in virtually all
circumstances.58 However, as amended by the Energy Policy Act,
these sections now give the Commission broader authority to order
transmitting utilities to provide wholesale transmission services, upon
application, to any electric utility, Federal power marketing agency,
or any other person generating electric energy for sale for resale.
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\58\ See supra note 36.
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The Energy Policy Act also added section 213 to the FPA. Section
213(a) requires a transmitting utility that does not agree to provide
wholesale transmission service in accordance with a good faith request
to provide a written explanation of its proposed rates, terms, and
conditions and its analysis of any
[[Page 21547]]
physical or other constraints.59 Section 213(b) required the
Commission to enact a rule requiring transmitting utilities to submit
annual information concerning potentially available transmission
capacity and known constraints.60
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\59\ See Policy Statement Regarding Good Faith Requests for
Transmission Services and Responses by Transmitting Utilities Under
Sections 211(a) and 213(a) of the Federal Power Act, as Amended and
Added by the Energy Policy Act of 1992, 58 FR 38964 (July 21, 1993),
FERC Stats. & Regs., Regulations Preambles para. 30,975 (1993)
(Policy Statement Regarding Good Faith Requests for Transmission
Services).
\60\ See New Reporting Requirements Implementing Section 213(b)
of the Federal Power Act and Supporting Expanded Regulatory
Responsibilities Under the Energy Policy Act of 1992, and Conforming
and Other Changes to Form No. FERC-714, 58 FR 52420 (October 8,
1993), FERC Stats. & Regs., Regulations Preambles para. 30,980
(Order No. 558), reh'g denied, Order No. 558-A, 65 FERC para. 61,324
(1993), regulations modified, 59 FR 15333 (April 1, 1994), FERC
Stats. & Regs., Regulations Preambles para. 30,993.
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E. The Present Competitive Environment
Following the Energy Policy Act, the Commission established rules:
(1) For certain generators to obtain EWG status and thus an exemption
from PUHCA; 61 and (2) that required transmission information
availability. The Commission also pursued a number of initiatives aimed
at fostering the development of more competitive bulk power markets,
including aggressive implementation of section 211, a new look at undue
discrimination under the FPA, easing of market entry for sellers of
generation from new facilities, and initiation of a number of industry-
wide reforms. As stated by the Commission, in recognition of the
Congressional goal in the Energy Policy Act of creating competitive
bulk power markets:
\61\ See Order No. 550, Filing Requirements and Ministerial
Procedures for Persons Seeking Exempt Wholesale Generator Status, 58
FR 8897 (February 18, 1993), FERC Stats. & Regs., Regulations
Preambles para. 30,964, order on reh'g, Order No. 550-A, 58 FR 21250
(April 20, 1993), FERC Stats. & Regs., Regulations Preambles para.
30,969 (1993). As recognized by Congress and the Commission,
availability of transmission information is critical in developing
competitive markets. See supra notes 59 and 60. This opened the
``black box'' of information that previously was available only to
transmission owners.
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Our goal is to facilitate the development of competitively priced
generation supply options, and to ensure that wholesale purchasers of
electric energy can reach alternative power suppliers and vice versa.
62
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\62\ See Recovery of Stranded Costs by Public Utilities and
Transmitting Utilities, Notice of Proposed Rulemaking, 59 FR 35274
(July 11, 1994), FERC Stats. & Regs., Proposed Regulations para.
32,507 at 32,866 (Stranded Cost NOPR); American Electric Power
Service Corporation, 67 FERC para. 61,168, clarified, 67 FERC para.
61,317 (1994).
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1. Use of Sections 211 and 212 to Obtain Transmission Access
The Commission has aggressively implemented sections 211 and 212 of
the FPA, as amended by the Energy Policy Act, in order to promote
competitive markets.63 When wheeling requests under sections 211
and 212 have been made, the Commission has required wheeling in almost
all of the requests it has processed. To date, the Commission has
issued orders (proposed or final) requiring wheeling in 12 of the 14
cases it has acted on.64
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\63\ 16 U.S.C.A. 824j-824k (West 1985 and Supp. 1994).
\64\ See, e.g., final orders issued in City of Bedford, 68 FERC
para. 61,003 (1994), reh'g denied, 73 FERC para. 61,322 (1995);
Florida Municipal Power Agency v. Florida Power & Light Company, 67
FERC para. 61,167 (1994), order on reh'g, 74 FERC para. 61,006
(1996); Minnesota Municipal Power Agency, 68 FERC para. 61,060
(1994); and Tex-La Electric Cooperative of Texas, 69 FERC para.
61,269 (1994); see also Appendix A.
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As a general matter, section 211 has permitted some inroads to be
made by customers in obtaining transmission service from public
utilities that historically have declined to provide access to their
systems, or have offered service only on a discriminatory basis. Under
section 211, the Commission has granted requests for the broader type
of service that most utilities historically have refused to provide--
network service. Although transmission owners have provided limited
amounts of unbundled point-to-point transmission service, third-party
customers have not been able to obtain the flexibility of service that
transmission owners enjoy.
In Florida Municipal, a section 211 case, the Commission ordered
``network,'' rather than the narrower ``point-to-point,''
service.65 Network service permits the applicant to fully
integrate load and resources on an instantaneous basis in a manner
similar to the transmission owner's integration of its own load and
resources. At the same time, the Commission made the generic finding
that the availability of transmission service will enhance competition
in the market for power supplies and lead to lower costs for consumers.
The Commission explained that as long as the transmitting utility is
fully and fairly compensated and there is no unreasonable impairment of
reliability, transmission service is in the public interest.66
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\65\ See Florida Municipal Power Agency v. Florida Power & Light
Company, 65 FERC para. 61,125, reh'g dismissed, 65 FERC para. 61,372
(1993), final order, 67 FERC para. 61,167 (1994), order on reh'g, 74
FERC para. 61,006 (1996). The Commission has ``characterized point-
to-point service as involving designated points of entry into and
exit from the transmitting utility's system, with a designated
amount of transfer capability at each point.'' El Paso Electric
Company v. Southwestern Public Service Company, 68 FERC para. 61,182
at 61,926 n.9 (1994) (citing Entergy Services, Inc., 58 FERC para.
61,234 at 61,768 (1993), reh'g dismissed, 68 FERC para. 61,399
(1994)). Network service allows more flexibility by allowing a
transmission customer to use the entire transmission network to
provide generation service for specified resources and specified
loads without having to pay multiple charges for each resource-load
pairing.
\66\ Florida Municipal, 67 FERC at 61,477.
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As discussed infra, based on the mounting competitive pressures in
the industry and rapidly evolving markets, we have concluded that
section 211 alone is not enough to eliminate undue discrimination. The
comments received on the proposed rules, discussed in detail infra,
confirm this conclusion. The significant time delays involved in filing
an individual service request for bilateral service under section 211
place the customer at a severe disadvantage compared to the
transmission owner and can result in discriminatory treatment in the
use of the transmission system. It is an inadequate procedural
substitute for readily available service under a filed non-
discriminatory open access tariff. As the Commission noted in Hermiston
Generating Company, ``[t]he ability to spend time and resources
litigating the rates, terms and conditions of transmission access is
not equivalent to an enforceable voluntary offer to provide comparable
service under known rates, terms and conditions.'' 67
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\67\ 69 FERC para. 61,035 at 61,165 (1994), reh'g denied, 72
FERC para. 61,071 (1995); see also Southwest Regional Transmission
Association, 69 FERC para. 61,100 at 61,398 (1994), order on
compliance filing, 73 FERC para. 61,147 (1995) (SWRTA).
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2. Commission's Comparability Standard
In the Spring of 1994, the Commission began to address the problem
of the disparity in transmission service that utilities provided to
third parties in comparison to their own uses of the transmission
system. In the seminal case in this area, American Electric Power
Service Corporation (AEP), the company voluntarily proposed a tariff of
general applicability that would offer firm, point-to-point
transmission service for a minimum of one month.68 The Commission
accepted the proposed transmission tariff for filing and suspended its
effectiveness for one day, subject to refund.69 Rehearing requests
challenged the Commission's summary approval of the restriction of
service to point-to-point as being discriminatory and
anticompetitive.70 The rehearing
[[Page 21548]]
requests argued that the tariff should be expanded to include network
services such as those used by the transmission owner. On rehearing,
the Commission announced a new standard for evaluating claims of undue
discrimination.
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\68\ 64 FERC para. 61,279 (1993), reh'g granted, 67 FERC para.
61,168, clarified, 67 FERC para. 61,317 (1994).
\69\ The Commission explained that AEP could limit the service
it was offering because it was ``providing the service voluntarily
under a tariff of general applicability.'' 64 FERC at 62,978.
\70\ AEP, 67 FERC at 61,489.
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The Commission found that a voluntarily offered, new open access
transmission tariff that did not provide for services comparable to
those that the transmission owner provided itself was unduly
discriminatory and anticompetitive.71 In reaching that conclusion,
the Commission broadened its undue discrimination analysis (which
traditionally had focused on the rates, terms, and conditions faced by
similarly situated third-party customers) to include a focus on the
rates, terms, and conditions of a utility's own uses of the
transmission system:
\71\ With respect to anticompetitive effects, the Commission
explained that it has ``adhered to the Supreme Court's determination
that the Commission's 'important and broad regulatory power * * *
carries with it the responsibility to consider, in appropriate
circumstances, the anticompetitive effects of regulated aspects of
interstate utility operations pursuant to sections 202 and 203, and
under like directives contained in sections 205, 206 and 207.' Gulf
States Utilities Company v. FPC, 411 U.S. 747, 758-59 (1972).'' Id.
at 61,490 (footnote omitted). The Commission reaffirmed that it
would examine how best to fulfill this responsibility, as well as
its responsibility to prevent undue discrimination, in light of the
changing conditions in the electric utility industry. Id.
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(A)n open access tariff that is not unduly discriminatory or
anticompetitive should offer third parties access on the same or
comparable basis, and under the same or comparable terms and
conditions, as the transmission provider's uses of its
system.72
\72\ Id. at 61,490.
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Refocusing the analysis was necessitated by the changing conditions
in the electric utility industry, including the emergence of non-
traditional suppliers and greater competition in bulk power markets.
Because a transmission provider may use its system in different ways
(e.g., to integrate load and resources when serving retail native load,
to make off-system sales or purchases, or to serve wholesale
requirements customers), the Commission set for hearing the factual
issues associated with identifying those uses, as well as any potential
impediments or consequences to providing comparable services to third
parties.73
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\73\ Id. at 61,490-91.
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After AEP, the Commission applied this comparability standard to a
proposed open access transmission tariff that was filed by Kansas City
Power & Light Company (KCP&L) in support of a proposal to sell
generation at market-based rates.74 The Commission explained that,
in light of AEP, the utility's proposed open access transmission tariff
(which provided only for point-to-point service) did not adequately
mitigate its transmission market power so as to justify allowing the
requested market-based rates. KCP&L could charge market-based rates for
sales only if it modified its proposed transmission tariff to reflect
the AEP comparability standard.
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\74\
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
See Kansas City Power & Light Company, 67 FERC para. 61,183
(1994), reh'g pending.
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Since then, the Commission has required comparable service in a
variety of contexts, and has set for hearing the factual issues
associated with comparable service. For example, the Commission found
that market power can be adequately mitigated only if a merged company
offers transmission services in accordance with the AEP comparability
standard.75 The Commission further held that, even if a merger
does not result in an increase in market power, the merger would not be
consistent with the public interest under section 203 of the FPA unless
the merged company offers comparable transmission services, as defined
in AEP.76 The Commission therefore announced a transmission
comparability requirement for all new mergers:
\75\ E.g., CSW, supra, 68 FERC at 61,914.
\76\ Id.
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Given the transition of the electric utility industry as a
whole, we conclude that, absent other compelling public interest
considerations, coordination in the public interest can best be
secured only if merging utilities offer comparable transmission
services.77
\77\ Id. at 61,915 (footnote omitted).
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In Heartland Energy Services, Inc.,78 the Commission applied
its comparability standard to an affiliated electric power marketer
seeking blanket authorization to sell electricity at market-based
rates. The Commission explained that
\78\ 68 FERC para. 61,223 (1994).
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For all future cases involving blanket approval of market-based
rates an offer of comparable transmission services will be required
before the Commission will be able to find that transmission market
power has been adequately mitigated. In the context of an affiliated
power marketer, this means that all of its affiliated utilities must
have a comparable transmission tariff on file.79
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\79\ Id. at 62,060. In InterCoast Power Marketing Company, 68
FERC para. 61,248, clarified, 68 FERC para. 61,324 (1994), the
Commission rejected an affiliated marketer's proposal to sell at
market rates without its affiliate utility offering comparable
transmission services. The Commission stated that the only way to
ensure that InterCoast does not have transmission market power is to
require its affiliated public utility to offer comparable
transmission services. See also LG&E Power Marketing Inc., 68 FERC
para. 61,247 at 62,120-21 (1994). The Commission added that this is
consistent with encouraging competitive bulk power markets as
envisioned by the Energy Policy Act of 1992. Id. at 62,132.
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The Commission also denied a request by a company affiliated with a
transmission-owning utility seeking permission to sell power at market-
based rates to a particular customer. The denial was without prejudice
to refiling such a request in a new section 205 proceeding, but only
after the affiliated transmission-owning utility filed a comparable
transmission service tariff.80 The Commission added that it
\80\ See Hermiston Generating Company, 69 FERC para. 61,035 at
61,164 (1994), reh'g pending. The Commission subsequently accepted
the rates on a cost basis. See Letter Order dated November 10, 1994.
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Will require comparability in any situation in which a seller
seeking market-based rates is affiliated with an owner or controller
of transmission facilities.81
\81\ Id. at 61,165.
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The Commission has also stated that ``it will henceforth apply the
transmission comparability standard announced in the AEP case to all
transmitting utility members of an RTG.'' 82
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\82\ See SWRTA, 69 FERC at 61,397; see also PacifiCorp, the
California Municipal Utilities Association, and the Independent
Energy Producers (on behalf of Western Regional Transmission
Association), 69 FERC para. 61,099, order on reh'g, 69 FERC para.
61,352 (1994), order on compliance filing, 71 FERC para. 61,158
(1995) (WRTA). An RTG is a regional transmission group. It is
defined as ``a voluntary organization of transmission owners,
transmission users, and other entities interested in coordinating
transmission planning (and expansion), operation and use on a
regional (and inter-regional.'' Policy Statement Regarding Regional
Transmission Groups, 58 FR 41626 (August 5, 1993), FERC Stats. &
Regs., Regulations Preambles para. 30,976 at 30,870 n. 4 (RTG Policy
Statement).
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The Commission further declared that comparable services must be
provided through ``open access'' tariffs rather than only on a
contract-by-contract basis:
(T)ariffs are essential to the provision of comparable services.
Tariffs set out the services that are available and the terms and
conditions under which those services will be made available * * *.
(In contrast), a negotiation process creates uncertainty and imposes
on customers delay and other transaction costs that the transmitting
utility members of an RTG do not incur when using the transmission
for their own benefit. Moreover, the ability to execute separate
transmission agreements with different but similarly situated
customers is the ability to unduly discriminate among them. A tariff
ensures against such discrimination in the RTG.83
\83\ SWRTA, 69 FERC at 61,398.
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[[Page 21549]]
Thus, the Commission required the RTGs to amend their bylaws to
commit all transmitting utility members to offer comparable
transmission services to other RTG members pursuant to a transmission
tariff or tariffs.
As discussed below, since the AEP comparability standard was
announced, the Commission has set for hearing 44 open access tariffs to
determine what constitutes comparable service. This number includes
tariffs filed subsequent to the Open Access NOPR. All tariffs have now
been made subject to the outcome of the Final Rule.
3. Lack of Market Power in New Generation
In 1994 in the KCP&L case, discussed in the prior section, the
Commission continued to recognize that transmission remains a natural
monopoly. However, it found that, in light of the industry and
statutory changes that now allow ease of market entry, no wholesale
seller of generation has market power in generation from new
facilities.84 In particular, the Commission explained that it had
previously noted in Entergy Services, Inc. that
\84\ KCP&L, 67 FERC para. 61,183 (1994).
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There was significant evidence that non-traditional power
project developers, including qualifying facilities and independent
power projects, are becoming viable competitors in long-run
markets.85
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\85\ Id. at 61,557 (citing Entergy Services, Inc., 58 FERC para.
61,234 at 61,756 and nn. 63 and 65 (Entergy)).
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The Commission further explained that since Entergy, Congress had
enacted the Energy Policy Act, which had lowered barriers to the entry
of new suppliers by creating a new class of power suppliers--EWGs--that
are exempt from the provisions of PUHCA.86 The Commission
concluded that, in considering market-based rate proposals for
generation sales, it need only focus on market power in transmission,
generation market power in short-run markets, and other barriers to
entry.87
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\86\ Id. The Commission added that ``after examining generation
dominance in many different cases over the years, we have yet to
find an instance of generation dominance in long-run bulk power
markets.'' Id.
\87\ Id.
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4. Further Commission Action Addressing a More Competitive Electric
Industry
To address the fact that the electric industry is becoming more
competitive, and to remove barriers that might inhibit a more
competitive industry, the Commission has initiated a number of
proceedings: (1) Stranded Cost NOPR,88 (2) Transmission Pricing
Policy Statement,89 (3) Pooling Notice of Inquiry,90 (4)
Regional Transmission Group (RTG) Policy Statement,91 and (5)
Notice of Inquiry on Merger Policy.92
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\88\ FERC Stats. & Regs. para. 32,507 (1994).
\89\ Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities Under the Federal
Power Act, 59 FR 55031 (November 3, 1994), FERC Stats. & Regs.,
Regulations Preambles para. 31,005 (Transmission Pricing Policy
Statement).
\90\ Inquiry Concerning Alternative Power Pooling Institutions
Under the Federal Power Act, 59 FR 54851 (October 26, 1994), FERC
Stats. & Regs., Notices para. 35,529 (1995) (Pooling Notice of
Inquiry).
\91\ FERC Stats. & Regs. para. 30,976 (RTG Policy Statement).
\92\ FERC Stats. & Regs. para. 35,531 (1996).
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In the Stranded Cost NOPR the Commission recognized that the trend
toward greater transmission access and the transition to a fully
competitive bulk power market could cause some utilities to incur
stranded costs as wholesale requirements customers (or retail
customers) use their supplier's transmission to purchase power
elsewhere. As the Commission noted, a utility may have built facilities
or entered into long-term fuel or purchased power supply contracts with
the reasonable expectation that its customers would renew their
contracts and would pay their share of long-term investments and other
incurred costs. If the customer obtains another power supplier, the
utility may have stranded costs. If the utility cannot locate an
alternative buyer or somehow mitigate the stranded costs, the
Commission explained that ``the costs must be recovered from either the
departing customer or the remaining customers or borne by the utility's
shareholders.'' 93 Accordingly, the Commission proposed to
establish provisions concerning the recovery of wholesale and retail
stranded costs by public utilities and transmitting utilities.
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\93\ FERC Stats. & Regs. para. 32,507 at 32,864.
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In the Transmission Pricing Policy Statement, the Commission
announced a new policy providing greater flexibility in the pricing of
transmission services provided by public utilities and transmitting
utilities. The Commission traditionally had allowed only postage-stamp,
contract-path pricing.94 Under the new policy, we will permit a
variety of proposals, including distance sensitive and flow-based
pricing, which may be more suitable for competitive wholesale power
markets.95 The Commission explained that this ``(g)reater pricing
flexibility is appropriate in light of the significant competitive
changes occurring in wholesale generation markets, and in light of our
expanded wheeling authority under the Energy Policy Act of 1992.''
96 However, the Commission explained that any new transmission
pricing proposal must meet the Commission's AEP comparability standard.
The Commission further explained that comparability of service applies
to price as well as to terms and conditions.97
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\94\ Most transmission contracts set a single price for energy
flow over a utility's transmission system. This single-price policy
is called ``postage stamp'' pricing because the rate does not depend
on how far the power moves within a company's transmission system.
If power flows through several companies, traditional industry
practice is to specify that power flows along a ``contract path''
consisting of the transmission-owning utilities between the ultimate
receipt and delivery points. See Indiana Michigan Power Company, 64
FERC para. 61,184 at 62,545 (1993).
\95\ Unlike with postage stamp pricing, with distance-sensitive
pricing the cost of moving power through a company depends on how
far the power moves within the company. In contrast to contract path
pricing, flow-based pricing establishes a price based on the costs
of the various parallel paths actually used when the power flows.
Because flow-based pricing can account for all parallel paths used
by the transaction, all transmission owners with facilities on any
of the parallel paths could be compensated for the transaction.
\96\ FERC Stats. & Regs. para. 31,005 at 31,136.
\97\ Id. at 31,142.
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The Commission issued the Pooling Notice of Inquiry to receive
comments on traditional power pools and on alternative power pooling
institutions that are being explored in today's more competitive
environment. The Commission expressed concern that
(G)iven the ongoing changes in the competitive environment of
the electric utility industry--in particular, the potential for
substantially increased access to transmission--we must consider
whether we are appropriately balancing our dual objectives of
promoting coordination and competition.98
\98\ FERC Stats. & Regs. para. 35,529 at 35,715.
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Accordingly, the Commission explained that it wished to look at
alternative power pooling institutions and to re-examine the role of
more traditional power pools in today's environment of increased
competition. In particular the Commission expressed its intent to
ensure that its policies ``are consistent with the development of a
competitive bulk power market.'' 99
---------------------------------------------------------------------------
\99\ Id. at 35,714. As explained below, the Commission held
technical conferences on issues surrounding power pools and
competition.
---------------------------------------------------------------------------
In the RTG Policy Statement, the Commission announced a policy
encouraging the development of RTGs. The Commission explained that a
primary purpose of RTGs is to facilitate transmission access for
potential users and voluntarily resolve disputes over such service. The
Commission has approved the formation of three
[[Page 21550]]
RTGs.100 One of the conditions is that each RTG member must offer
comparable transmission services by tariff to other RTG members.
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\100\ See WRTA and SWRTA, supra, and Northwest Regional
Transmission Association, 71 FERC para. 61,397 (1995).
---------------------------------------------------------------------------
In the merger NOI, the Commission indicated that it will review
whether its criteria and policy for evaluating mergers need to be
modified in light of the changing circumstances occurring in the
electric industry.
In addition to the Commission's actions, a number of states have
initiated proceedings concerning retail wheeling or proposed
legislation for retail wheeling, that is, for ultimate consumers to
choose their supplier of power, or other restructuring
proposals.101
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\101\ At least 12 states have retail wheeling proposals,
legislation, or pilot programs underway--Alabama, California,
Connecticut, Illinois, Massachusetts, Michigan, New Hampshire, New
York, Ohio, Rhode Island, Vermont, and Wisconsin. At least 14 other
states are investigating retail wheeling. Currently, according
to a report of the NARUC-affiliated National Council on
competition and the Electric Industry, 41 States are actively
involved in investigating whether and how to restructure their
respective electric power markets. Of this total, 29 State
regulatory authorities * * * have initiated investigations. In
addition, five State legislatures are involved in similar
investigations, while seven other States have joint regulatory/
legislative proceedings underway.
Testimony of the Honorable Cheryl L. Parrino, Chair of the
Wisconsin Public Service Commission, on behalf of the National
Association of Regulatory Utility Commissioners, before the United
States Senate Committee on Energy and Natural Resources (March 6,
1996).
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5. Events Since Issuance of Open Access NOPR
Since issuance of the Open Access NOPR, public utilities have
filed, in some form or another, 47 open access tariffs. In acting on
those filings, the Commission has made all of the non-rate terms and
conditions of those proposed tariffs subject to the outcome of this
Final Rule.102
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\102\ See American Electric Power Service Corporation, et al.,
72 FERC para. 61,287 at 61,238 (1995).
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Over the last year, the Commission also has received and analyzed
more than 20,000 pages of comments that were received from over 400
commenters, as well as additional information provided by industry
participants at a number of Commission-initiated technical
conferences.103 Those technical conferences addressed several
issues--ancillary services, pro forma tariffs, power pools, and ISOs--
and provided significant input to the Commission's formulation of this
Final Rule.
---------------------------------------------------------------------------
\103\ Attached to this Final Rule as Appendix B is a list of
commenters and the abbreviations used to designate them, including
those commenters that filed late.
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F. Need for Reform
The many changes discussed above have converged to create a
situation in which new generating capacity can be built and operated at
prices substantially lower than many utilities' embedded costs of
generation. As discussed above, new generation facilities can produce
power on the grid at a cost of less than 3 cents per kWh to 5 cents per
kWh, yet the costs for large plants constructed and installed over the
last decade were typically in the range of 4 to 7 cents per kWh for
coal plants and 9 to 15 cents for nuclear plants.
Non-traditional generators are taking advantage of this opportunity
to compete. Indeed, the non-traditional generators' share of total U.S.
electricity generation increased from 4 percent in 1985 to 10 percent
in 1993.104 Much of this increased share of generation is the
result of competitive bidding for new generation resources that has
occurred in 37 states. Since 1984, almost 4,000 projects, representing
over 400,000 MW, have been offered in response to requests. Over 350
projects have been selected to supply 20,000 MW, and, of these, 126 are
now online producing almost 7,800 MW of power.105
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\104\ Energy Information Administration, Performance Issues for
a Changing Electric Power Industry (January 1995) 10 and (Figure 5).
\105\ Current Competition, November 1994, Vol. 5, No. 8, at 8.
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In addition, the cost of utility-generated electricity differs
widely across the major regions of the United States. Average utility
rates range from 3 to 5 cents in the Northwest to 9 to 11 cents in
California. Electricity consumers are demanding access to lower cost
supplies available in other regions of the United States, and access to
the newer, lower cost generation resources. Therefore, it is important
that the non-traditional generators of cheaper power be able to gain
access to the transmission grid on a non-discriminatory open access
basis.
The Commission's goal is to ensure that customers have the benefits
of competitively priced generation. However, we must do so without
abandoning our traditional obligation to ensure that utilities have a
fair opportunity to recover prudently incurred costs and that they
maintain power supply reliability. As well, the benefits of competition
should not come at the expense of other customers. The Commission
believes that requiring utilities to provide non-discriminatory open
access transmission tariffs, while simultaneously resolving the
extremely difficult issue of recovery of transition costs (discussed
infra), is the key to reconciling these competing demands.
Non-discriminatory open access to transmission services is critical
to the full development of competitive wholesale generation markets and
the lower consumer prices achievable through such competition.106
Transmitting utilities own the transportation system over which bulk
power competition occurs and transmission service continues to be a
natural monopoly. Denials of access (whether they are blatant or
subtle), and the potential for future denials of access, require the
Commission to revisit and reform its regulation of transmission in
interstate commerce. As discussed in detail in Section IV.B., such
action is required by the FPA's mandate that the Commission remedy
undue discrimination.
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\106\ As discussed above, a significant number of public
utilities still do not have any form of an ``open access'' tariff on
file with the Commission and no public utility has on file a non-
discriminatory open access tariff as defined by this Rule.
---------------------------------------------------------------------------
Since the time the NOPR issued, the Commission staff has completed
an FEIS that provides a quantitative estimate of some of the cost
savings expected from this Rule: approximately $3.8 to $5.4 billion per
year. Other non-quantifiable benefits are also expected from this Rule
and include: (1) Better use of existing assets and institutions; (2)
new market mechanisms; (3) technical innovation; and (4) less rate
distortion. These potential benefits to the Nation's electricity
consumers and the economy as a whole confirm the need to take generic
action to remove barriers to competition. In what follows, we set out
the changes necessary to remedy undue discrimination and to ensure a
fair transition to a more competitive regulatory regime.
IV. Discussion
A. Scope of the Rule
1. Introduction
The Commission has determined that non-discriminatory open access
transmission services (including access to transmission information)
and stranded cost recovery are the most critical components of a
successful transition to competitive wholesale electricity markets.
These issues are the focal point of this Rule, the accompanying rule on
open access same-time information systems, and the accompanying
proposed rule on capacity reservation tariffs.
[[Page 21551]]
In undertaking these initiatives, however, we are mindful that they
are part of a broader picture of evolving issues affecting the electric
industry and that other Commission policies will play an important role
in ensuring the full development of competitive markets. Among the many
issues that are important to competitive bulk power markets are:
independent system operators (ISOs); regional transmission groups;
generation market power; utility merger policy; and the development of
innovative transmission pricing alternatives, such as flow-based,
distance-sensitive transmission pricing methodologies that reflect
incremental costs. In particular, we believe that ISOs have great
potential to assist us and the industry to help provide regional
efficiencies, to facilitate economically efficient pricing, and,
especially in the context of power pools, to remedy undue
discrimination and mitigate market power. Although we discuss some of
these issues in this Rule, we will further develop our policies in
other proceedings as well to accommodate and encourage more efficient
market structures.
We now address the comments received on the scope of the proposed
rulemaking.
2. Functional Unbundling
In the NOPR, the Commission preliminarily found that functional
unbundling of wholesale generation and transmission services is
necessary to implement non-discriminatory open access
transmission.107 At the same time, the Commission explained that
the proposed rule would accommodate, but not require, corporate
unbundling (which could include selling generation or transmission
assets to a non-affiliate (divestiture) or the less aggressive step of
establishing separate corporate affiliates to manage a utility's
transmission and generation assets). However, we invited comments on
functional unbundling and asked whether it is a strong enough measure
to ensure non-discriminatory open access transmission without some form
of corporate restructuring.
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\107\ FERC Stats. & Regs. para.32,514 at 33,080.
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Comments
Commenters take both sides on whether functional unbundling is
sufficient to assure non-discriminatory open access transmission or
whether a stronger measure, such as corporate unbundling, is needed.
Supporting Functional Unbundling
Various commenters, including utilities and state commissions,
generally support functional unbundling as sufficient to assure non-
discriminatory open access transmission and oppose requiring corporate
unbundling or divestiture.108 Several commenters state that
functional unbundling will remedy discrimination without creating the
inefficiencies and additional costs that corporate restructuring would
create.109
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\108\ E.g., Ohio Edison, UtiliCorp, Pennsylvania P&L, Atlantic
City, Montana Power, IL Com, Seattle, OK Com, TX Industrials,
MidAmerican, Southwestern, Southern, DOD, Public Service Co of CO,
SC Public Service Authority, Florida Power Corp, DOE, WP&L, Com Ed,
SBA, Consumers Power, CA Com, UT Com, Houston L&P, KCPL, EEI.
\109\ E.g., Florida Power Corp, El Paso, PSNM, and SC Public
Service Authority.
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A number of other commenters argue that the Commission has no
authority under the FPA to require divestiture of transmission
assets.110 Several of these commenters assert that, even if the
Commission has the authority, the electric industry, unlike the natural
gas industry, is not ready for mandated corporate unbundling because
electric utilities still serve a high percentage of retail customers
and own large amounts of the generating capacity. They assert that
transmission system operation requires the operator to have control
over much of the generating capacity.
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\110\ E.g., Southwestern, PECO, El Paso, Florida Power Corp,
NSP, Public Service E&G, MidAmerican.
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Various other commenters also support functional unbundling, but
believe that safeguards are needed to make it work.111 Power
Marketing Association, for example, suggests a number of safeguards:
adoption of cost allocation mechanisms to ensure that utilities do not
shift costs from generation to transmission; random audits of utility
books; a requirement that each utility file a code of conduct that
provides for maximum separation of generation and transmission
functions; and active oversight and complaint procedures with strong
penalties for abuse. OK Com and GA Com believe that functional
unbundling along with the safeguard of the Commission's complaint
process will provide sufficient incentive for non-discriminatory open
access transmission.
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\111\ E.g., NRECA, IN Com, Power Marketing Association, TDU
Systems, NorAm, Turlock, Texaco, Utility Shareholders, NSP, El Paso,
Utility Investors Analysts, PECO, Florida Power Corp, UT Com,
Sierra, Carolina P&L, SoCal Gas, OK Com, FL Com, Southern.
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Supporting Corporate Unbundling
A number of commenters see weaknesses in functional unbundling and
argue that some form of corporate unbundling is necessary to assure
non-discriminatory open access transmission.112 American Forest &
Paper says that there is affiliate abuse in the gas industry and argues
that the electric industry presents even more serious potential for
abuse because it is still dominated by vertically integrated
utilities.113 UAMPS asserts that functional unbundling is
insufficient because the utility will still favor itself on issues
related to transmission planning, capital investment, and operation and
maintenance and replacement costs.
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\112\ E.g., American Forest & Power, American National Power, ND
Com, IL Com, UAMPS, NIEP, APPA, Public Power Council, Municipal
Energy Agency Nebraska, Missouri Basin MPA, Texaco, Direct Services
Industries, Calpine, CCEM, Wisconsin Coalition, VT DPS.
\113\ See also American National Power, ND Com, Calpine.
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NIEP argues that divestiture of generation assets from transmission
and distribution is the preferred mechanism for mitigating market
power. It further suggests that if corporate divestiture is not
feasible the Commission should
Seek to achieve ``virtual divestiture'' by requiring that the
utility generation function be separated from transmission and
distribution functions in a separate corporate affiliate, or
business unit, and that affiliate transaction rules be established
to guard against possible abuses. 114
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\114\ NIEP Initial Comments at 4.
It maintains that the Commission has broad authority to protect
against undue discrimination and anticompetitive behavior and can order
divestiture if such action is required to remedy such behavior.115
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\115\ See also Municipal Energy Agency Nebraska, Direct Services
Industries.
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FTC and DOJ argue that operational unbundling, an example of which
is the formation of an independent system operator (ISO), likely would
be more effective than functional unbundling and less costly than
industry-wide divestiture.116 FTC describes operational unbundling
as ``structural institutional arrangements, short of divestiture, that
would separate operation of the transmission grid and access to it from
economic interests in generation.'' It gives as an example the
California proposal under which utilities would continue to own
transmission lines, but an independent system operator would have
operational control. DOJ also suggests ``a separate authority'' to
[[Page 21552]]
manage the grid and access to the grid, joint ventures, and voluntary
pooling arrangements. These commenters argue that operational
unbundling would be easier to enforce than functional unbundling.
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\116\ Others oppose operational unbundling. See, e.g., Carolina
P&L, Salt River.
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DOE states that separation of the control of transmission from
vertically-integrated companies does not necessarily require a poolco
or any particular market mechanism. It suggests the possibility of an
ISO that is functionally separate from any buyer or seller of
generation, but would not perform all the functions of a poolco.
United Illuminating supports ``operational unbundling'' that would
either (1) eliminate vertical integration and divestiture of
transmission assets, leading to the formation of a regional
transmission company, or (2) develop a regional contractual approach to
transmission services that eliminates the transmission owner's market
power and fairly allocates support of the transmission facilities
between native load and third-party users of the system.
Commission Conclusion
We conclude that functional unbundling of wholesale services is
necessary to implement non-discriminatory open access transmission and
that corporate unbundling should not now be required. As we explained
in the NOPR, functional unbundling means three things:
(1) A public utility must take transmission services (including
ancillary services) for all of its new wholesale sales and purchases of
energy under the same tariff of general applicability as do others;
(2) A public utility must state separate rates for wholesale
generation, transmission, and ancillary services;
(3) A public utility must rely on the same electronic information
network that its transmission customers rely on to obtain information
about its transmission system when buying or selling power.
We believe that these requirements are necessary to ensure that
public utilities provide non-discriminatory service.117 These
requirements also will give public utilities an incentive to file fair
and efficient rates, terms, and conditions, since they will be subject
to those same rates, terms, and conditions.
---------------------------------------------------------------------------
\117\ When and how functional unbundling is to be achieved for
requirements transactions and for various types of coordination
arrangements, including power pools, is discussed at Sections IV.A.5
and IV.F. Functional unbundling of ancillary services is discussed
in Section IV.D.
---------------------------------------------------------------------------
However, we recognize that additional safeguards are necessary to
protect against market power abuses. Functional unbundling will work
only if a strong code of conduct (including a requirement to separate
employees involved in transmission functions from those involved in
wholesale power merchant functions) is in place. In the RINs NOPR, the
Commission proposed a code of conduct that would apply to all public
utility transmission providers. As the Commission explained,
[T]his code of conduct would require, among other matters, a
separation of the utilities' transmission system operations and
wholesale marketing functions, and would define permissible and
impermissible contacts between employees that conduct wholesale
generation marketing functions and employees that handle
transmission system operations and reliability in the system control
center or at other facilities or locations.118
\118\ Real-Time Information Networks and Standards of Conduct,
Notice of Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC
Stats. & Regs., Proposed Regulations para. 32,516 at 33,170 (1995).
---------------------------------------------------------------------------
Adoption of this code of conduct, discussed in detail in the
accompanying final rule on OASIS,119 is needed to ensure that the
transmission owner's wholesale marketing personnel and the transmission
customer's marketing personnel have comparable access to information
about the transmission system.
---------------------------------------------------------------------------
\119\ The final rule on information systems no longer uses the
terminology RINs. The new terminology used is OASIS--Open Access
Same-time Information System--which we will use in this Final Rule.
---------------------------------------------------------------------------
As noted by OK Com and GA Com, a further safeguard--section 206--is
available if a public utility seeks to circumvent the functional
unbundling requirements. Under section 206, any person is free to file
a complaint with the Commission detailing any alleged misbehavior on
the part of the public utility or its affiliates concerning matters
subject to our jurisdiction under the FPA. Similarly, the Commission
may, on its own motion, initiate a proceeding to investigate the
practices of the public utility and its affiliates.
We believe that functional unbundling, coupled with these
safeguards, is a reasonable and workable means of assuring that non-
discriminatory open access transmission occurs. In the absence of
evidence that functional unbundling will not work, we are not prepared
to adopt a more intrusive and potentially more costly mechanism--
corporate unbundling--at this time.
Several commenters discuss the need to encourage or even to require
ISOs in the context of functional unbundling. We believe that ISOs have
the potential to provide significant benefits (e.g., to help provide
regional efficiencies, to facilitate economically efficient pricing,
and, especially in the context of power pools, to remedy undue
discrimination and mitigate market power) and will further our goal of
achieving a workably competitive market. As we learned at our technical
conference on power pools, many utilities are examining ISOs and
corporate unbundling in various shapes and forms, particularly in the
context of power pools. We discuss ISOs extensively in our section on
power pools where we believe they will have an important role to play.
However, in the context of individual utility transactions, we believe
that the less intrusive functional unbundling approach outlined above
is all that we must require at this time. Nevertheless, we see many
benefits in ISOs, and encourage utilities to consider ISOs as a tool to
meet the demands of the competitive marketplace.
As a further precaution against discriminatory behavior, we will
continue to monitor electricity markets to ensure that functional
unbundling adequately protects transmission customers. At the same
time, we will analyze all alternative proposals, including formation of
ISOs, and, if it becomes apparent that functional unbundling is
inadequate or unworkable in assuring non-discriminatory open access
transmission, we will reevaluate our position and decide whether other
mechanisms, such as ISOs, should be required.
Finally, while we are not now requiring any form of corporate
unbundling, we again encourage utilities to explore whether corporate
unbundling or other restructuring mechanisms may be appropriate in
particular circumstances. Thus, we intend to accommodate other
mechanisms that public utilities may submit, including voluntary
corporate restructurings (e.g., ISOs, separate corporate divisions,
divestiture, poolcos), to ensure that open access transmission occurs
on a non-discriminatory basis. We also will continue to monitor--and
stand ready to work with parties engaging in--innovative restructuring
proposals occurring around the country.
3. Market-Based Rates
a. Market-Based Rates for New Generation
In the NOPR, the Commission proposed to codify its determination in
Kansas City Power & Light Company 120
[[Page 21553]]
that the generation dominance standard for market-based sales from new
capacity be dropped.121 The proposed new section 35.27 would
provide:
\120\ 67 FERC para. 61,183 at 61,557 (1994), reh'g pending
(KCP&L).
\121\ FERC Stats. & Regs. para. 32,514 at 33,050.
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Notwithstanding any other requirements, any public utility
seeking authorization to engage in sales for resale of electric
energy at market-based rates shall not be required to demonstrate
any lack of market power in generation with respect to sales from
capacity first placed in service on or after June 10, 1996.122
\122\ Id. at 33,154.
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However, this proposal would not affect the Commission's continuing
authority to look at whether an applicant and its affiliates could
erect other barriers to entry and whether there may be affiliate abuse
or reciprocal dealing.123
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\123\ 67 FERC at 61,557.
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Comments
A number of commenters support the Commission's determination in
KCP&L 124 and several of them explicitly support the Commission's
proposed codification.125 EEI asserts that more than 50 percent of
new generation is from non-utility sources and that recent competitive
solicitations for new capacity have been greatly over-subscribed.
Entergy argues that there is no evidence in any proceeding thus far of
a market power problem in long-run markets.
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\124\ E.g., Entergy, EEI, Atlantic City, Duke Centerior, Houston
L&P, Montana-Dakota Utilities, Canadian Petroleum Producers, DOE,
Florida Power Corp, PSNM.
\125\ E.g., EEI, Centerior, Houston L&P, NYSEG.
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Other commenters, however, oppose codifying KCP&L.126 They
believe that market power in long-run markets exists for both new and
old generation due to, for example, constraints on interface
capabilities and unduly long notice periods for replacement of
purchases. They argue that there is not enough of a distinction between
new and old generation to treat them differently. TDU Systems also
notes that the Commission in KCP&L did not take into account the
differences between firm and non-firm bulk power. NIEP and ELCON
conclude that the Commission erroneously found in KCP&L that no
wholesale seller of generation has market power in generation from new
facilities. NIEP asserts that in each service area there is usually
only one wholesale buyer--the utility--who also is virtually always a
wholesale seller of generation. Under these circumstances, NIEP argues
that there cannot be arm's-length bargaining. Environmental Action
complains that the Commission's proposal to codify KCP&L ignores
significant factors that impede entry to generation markets, such as
utility resistance to purchased power, state government-created
barriers to non-utility generation, pancaking of rates under the
contract path approach, sunk investment, and scale economies.
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\126\ E.g., TDU Systems, ELCON, NRECA, Environmental Action,
NIEP, APPA, Power Marketing Association, EGA.
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Commission Conclusion
In reviewing applications to sell at market-based rates, whether
from new (unbuilt) capacity or existing capacity, we require that the
seller (and each of its affiliates) must not have, or must have
mitigated, market power in generation and transmission and not control
other barriers to entry. In order to demonstrate the requisite absence
or mitigation of transmission market power, a transmission-owning
public utility seeking to sell at market-based rates must have on file
with the Commission an open access transmission tariff for the
provision of comparable service. In addition, the Commission considers
whether there is evidence of affiliate abuse or reciprocal
dealing.127
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\127\ See, e.g., MidAmerican Energy Company, 74 FERC para.
61,211 (1996).
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In KCP&L, we stated that ``in light of industry and statutory
changes which allow ease of market entry, we therefore will no longer
require rate applicants to submit evidence of generation dominance in
long-run bulk power markets.'' 128 We further explained that we
had examined ``generation dominance in many different cases over the
years'' and had ``yet to find an instance of generation dominance in
long-run bulk power markets.'' 129 Commenters have criticized our
findings in KCP&L, but no commenter has provided any evidence of
generation dominance in long-run bulk power markets. Moreover, we have
seen no such evidence in any of the market-based rate cases we have
considered since KCP&L. Based on the comments received, we will codify
the Commission's determination in KCP&L that the generation dominance
standard for market-based sales from new capacity should be dropped.
Because the Commission's findings in KCP&L applied to long-run markets,
we will revise proposed Sec. 35.27 to apply to sales from capacity for
which construction has commenced on or after the effective date of this
Rule.130
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\128\ KCP&L, 67 FERC at 61,557. See also discussion in proposed
rule, FERC Stats. & Regs. at 33,067-68.
\129\ Id.
\130\ The NOPR's proposed language that a public utility would
not have to demonstrate a lack of market power in generation for
sales from capacity first placed in service on or after the date 30
days after the final rule is published in the Federal Register does
not properly reflect the finding in KCP&L. Because KCP&L addressed
new or unbuilt generation, the proposed language is being revised as
indicated above and as set forth in the regulatory text included
with this Final Rule.
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The Commission wishes to clarify that dropping the generation
dominance standard for new capacity does not affect the demonstration
that an applicant must make in order to qualify for market-based rates
for sales from its existing generating capacity. In other words, the
fact that an applicant need not demonstrate its lack of generation
dominance with respect to new capacity cannot be used to ``bootstrap''
the authorization of market-based rates for its existing capacity.
Moreover, our evaluation of market-based rates for existing capacity
will include consideration of new capacity.
In addition, the fact that we are codifying KCP&L does not mean
that we will ignore specific evidence presented by an intervenor that a
seller requesting market-based rates for sales from new generation
nevertheless possesses generation dominance. For example, if the
evidence indicated that the new generator, due to its proximity to an
existing transmission constraint, could significantly influence the
ability to move power across the constraint, we would consider such
evidence in determining whether to grant the applicant's
request.131 If such evidence is presented, the Commission will
evaluate whether the evidence disproves the premise that the seller
lacks generation dominance with respect to its new capacity.
---------------------------------------------------------------------------
\131\ Cf. Wisconsin Electric Power Company, et al., 74 FERC
para. 61,069 at 61,193 (1996).
---------------------------------------------------------------------------
If the applicant has existing generation, the sales from which are
authorized to be made on a market basis, the Commission would consider
whether the new generation (when added to the existing generation with
market-based authority) results in the applicant having generation
dominance. On the other hand, if the applicant has existing generation,
the sales from which are subject to cost-of-service regulation, the
Commission would not include this generation in its analysis of the
applicant's request for market-based rates for its new generation. The
question of whether or not the applicant lacks generation dominance
with respect to its existing capacity is relevant only if, and when,
the seller applies to the Commission for authority to make wholesale
sales for its existing capacity at market-based rates.
If evidence regarding an applicant's generation dominance with
respect to
[[Page 21554]]
its new capacity is submitted, the applicant would be required to
provide a satisfactory rebuttal.
b. Market-Based Rates for Existing Generation
In the NOPR, the Commission explained that increased competition
resulting from open access transmission may reduce or even eliminate
generation-related market power in the short-run market (sales from
existing capacity).132 Because market power has been the primary
concern of the Commission in analyzing requests for market-based rates
for such sales, we sought comments on the effect of industry-wide non-
discriminatory open access on our criteria for authorizing power sales
at market-based rates. The Commission also sought comments on whether
the generation dominance standard should be dropped for market-based
sales from existing capacity.
---------------------------------------------------------------------------
\132\ FERC Stats. & Regs. para. 32,514 at 33,093-94.
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Comments
Many commenters support, but many also oppose, market-based rates
for existing generation without a case-specific analysis of generation
dominance.
Supporting Market-Based Rates for Existing Generation
Many commenters (primarily IOUs and a number of state commissions)
assert that existing generators will not possess market power after
implementation of non-discriminatory open access transmission and that
market-based rates should be permitted generically for sales from
existing generation.133
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\133\ E.g., EEI, CINergy, Central Illinois Public Service,
Citizens Utilities, Com Ed, Ohio Edison, Allegheny, Southern,
Portland, NRRI, Pennsylvania P&L, PECO, Dayton P&L, Utilities For
Improved Transition, Centerior, Houston L&P, Duke, ConEd, IPALCO,
Salt River, PJM, NU, NYSEG, Oklahoma G&E, PA Com, OK Com, CT DPUC,
CA Com, MT Com.
---------------------------------------------------------------------------
EEI asserts that market power concerns generally would be
transitory, limited to the time needed to build new facilities. Thus,
it recommends that all markets be declared competitive by a date
certain and that market-based rates then be allowed, with customers
permitted to file complaints. Florida Power Corp believes that existing
procedures under sections 205 and 206 will adequately protect
consumers. Other commenters also urge the Commission to eliminate its
generation dominance standard, but assert that the Commission should
allow a showing of market dominance in a complaint or show cause
proceeding.134 CT DPUC notes that the Commission should be able to
rely on rules of conduct, market mechanisms, and monitoring to curb any
market power that may exist.
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\134\ E.g., Consumers Power, Portland, Dayton P&L, CSW.
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Utilities For Improved Transition argues that if utilities cannot
get market-based rates, the new players in the market will have an
unfair advantage, since they do not have to carry the traditional
utilities' burden of older, less efficient plants.
Entergy proposes a screening test that would permit the Commission
to ``deregulate'' wholesale sales to certain short-run markets. CINergy
recommends that after industry-wide open access tariffs become
effective, the Commission adopt a rebuttable presumption that all
markets are workably competitive; that presumption could be rebutted in
a section 206 proceeding.135
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\135\ See also Citizens Utilities.
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UtiliCorp, while it believes that market power will probably be
fully mitigated by open access, also argues that the Commission should
examine generation dominance on a region-by-region basis.136
Montana-Dakota Utilities argues that the Commission should allow all
suppliers in a power pool or RTG to have market-based rates after a
Commission finding that there is sufficient generation competition
within the region.
---------------------------------------------------------------------------
\136\ See also CSW, Industrial Energy Applications, Public
Service Co of CO, Coalition for Economic Competition.
---------------------------------------------------------------------------
Duke states that it would be highly inconsistent for the Commission
to require open access, but not allow utilities to compete in the
market. It further states that the relevant market should be determined
using standard antitrust techniques; the Commission should examine the
options available to customers and determine whether the utility
possesses monopoly power in a relevant market.
Opposing Market-Based Rates for Existing Generation
Many commenters are concerned that even with open access tariffs
certain generators will be able to exercise market dominance.137
For example, NARUC argues that utilities retain market power through
their ownership of existing generation and transmission facilities,
favorable long-term contracts for fuel and other inputs, and access to
superior generation sites.138 NRECA believes that the universe of
generation providers is still too narrow to assume a competitive market
and that other factors, such as transmission constraints and pancaking
of rates, will inhibit the development of competitive markets.139
FTC says that, although comparable transmission access could broaden
the relevant geographic market for generation, the Commission should
not assume that there will be no market power. It says that the
Commission must continue to evaluate each case.140 TDU Systems
argues that the Commission cannot move to market-based rates without a
Congressional determination that deregulation of wholesale electric
rates should be implemented. It further asserts that the Commission
does not have a factual basis for a reasoned conclusion that regulated
utilities do not have market dominance--full open access is only a goal
at this time, and the success of open access will depend upon the
transmission rate structures the Commission approves.
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\137\ E.g., NRECA, TDU Systems, MT Com, SMUD, NEPCO, Orange &
Rockland, El Paso, American Forest & Paper, NIPSCO, AEC & SMEPA, OH
Com, IL Com, IN Com, Legal Environmental Assistance, LG&E, Cajun,
Industrial Energy Applications, LEPA, MA DPU, MI Com, FTC, Minnesota
P&L, SC Public Service Authority, WP&L, NARUC, Canadian Petroleum
Producers, DOD, CCEM, Environmental Action, American Wind, Cajun,
NIEP, EGA, TAPS, ELCON, Consolidated Natural Gas.
\138\ See also NIEP, Pacificorp, CA Energy Com.
\139\ See also MT Com, TDU Systems, Soyland.
\140\ See also AEC & SMEPA, NIPSCO, El Paso (discusses a
particular transmission constraint that it states limits its access
to suppliers).
NRECA is also concerned that mergers may create a handful of
``mega-public utilities'' that may affect a regional generation
market and that the Commission should apply more traditional
antitrust principles in analyzing the impacts of mergers.
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LEPA raises concerns that the small bulk power suppliers, QFs, co-
generators, EWGs, IPPs, and marketers (who provide non-requirements
power) may not be able to bring competition to the wholesale market.
LEPA concludes that ``barriers will exist unless buyers have full
access to requirements power itself, rather than just to the chance to
acquire the individual components of requirements power.'' 141 TDU
Systems raises concerns about the limited number of generation
providers and the effect of possible future mergers. It also argues
that pancaked rates raise the cost of transmission to third parties,
thereby restricting the geographic scope of markets. As a result, TDU
Systems asserts that individual generators in highly concentrated
regions will still be able to exert market power. OH Com expresses
concerns that restrictions on siting of generation and transmission
will favor nearby generators. SC Public Service Authority argues that
if the Commission allows utilities to recover stranded costs their
market power will not be mitigated, since customers will
[[Page 21555]]
have to pay exit fees to switch suppliers.142
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\141\ LEPA Initial Comments Affidavit of William G. Shepherd at
4.
\142\ See also DOD and WP&L. IL Com suggests that the Commission
allow market-based rates to a utility on the condition that the
utility forego stranded cost recovery.
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CCEM notes that in Order No. 636 gas pipelines were not allowed
market-based rates for merchant sales until after transmission had been
completely unbundled and non-discriminatory open access had been fully
implemented.
DOE and DOJ assert that open access should not be assumed to
mitigate market power sufficiently to justify deregulation of existing
generation--structural changes, such as control of the regional grid by
an independent entity, are required. DOE requests that the Commission
continue to look for affiliate abuse when reviewing market-based rates
for new generation. Similarly, EPA is concerned that even with open
access, individual generators may still exert market power by their
domination of a particular geographic market. It is also concerned that
low-cost plants that are subject to weaker environmental standards
could have a market advantage. NEPOOL Review Committee requests that
the Commission not approve any market prices ``where the market into
which the seller proposes to sell is not effectively competitive due to
the absence of regional transmission products and prices.''143
---------------------------------------------------------------------------
\143\ NEPOOL Review Committee Initial Comments at 28.
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Commission Conclusion
While the Commission expects this Rule to facilitate the
development of competitive bulk power markets, we find that there is
not enough evidence on the record to make a generic determination about
whether market power may exist for sales from existing generation. We
continue to have concerns about how to define the relevant markets and
believe that a more rigorous analysis is needed than can be achieved
with the limited market data that is now available. We will continue
our case-by-case approach that allows market-based rates based on an
analysis of generation market power in first tier and second tier
markets.144 In particular cases, however, the effect of the
mandatory open access prescribed by this Final Rule may lead to the
consideration of geographic markets for the applicant's generation
products that are broader in scope than the first-tier and second-tier
markets currently considered.145 By the same token, in some cases,
evidence of the effects of transmission constraints may circumscribe
the scope of the relevant geographic market for the applicant's
generation products.
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\144\ See, e.g., Southwestern Public Service Company, 72 FERC
para. 61,208 at 61,996 (1995).
\145\ The Commission's practice is to define the relevant
markets as those utilities directly interconnected to the applicant
(first-tier markets). For each first-tier market, we consider all
utilities interconnected to the first-tier utility and all utilities
interconnected to the applicant as competitors in that relevant
market. Thus, the competitors include the second-tier utilities
directly interconnected to the relevant market and those other
first-tier utilities that can reach the market by virtue of the
applicant's open access transmission tariff. See, e.g., Kansas City
Power & Light Company, 67 FERC para. 61,183 at 61,556; and Heartland
Energy Services, Inc., 68 FERC para. 61,223 at 62,061.
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While we will continue to apply the first-tier/second-tier
analysis, we will allow applicants and intervenors to challenge the
presumption implicit in the Commission's practice that the relevant
geographic market is bounded by the second-tier utilities. Thus, for
instance, applicants may present evidence that the relevant market is
in fact broader than the first or second tier. In support of such a
contention, an applicant would need to show more than the existence of
open access. For example, an applicant might attempt to demonstrate the
lack of significant transmission constraints in the more broadly
defined market and that cumulative transmission rates would not
significantly affect the ability of more distant suppliers to compete
in the relevant market. Similarly, an intervenor may present evidence
that, due to the existence of significant transmission constraints
within the first- and second-tier markets, the relevant market is in
fact more limited in scope.146
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\146\ See Wisconsin Public Service Corporation, 75 FERC para.
61, ______, slip op. at 6-7 (1996).
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Finally, we will maintain our current practice of allowing market-
based rates for existing generation to go into effect subject to
refund. To the extent that either the applicant or intervenors in
individual cases offer specific evidence that the relevant geographic
market ought to be defined differently than under the existing test, we
will examine such arguments through formal or paper hearings.
Because our goal is to develop more competitive bulk power markets,
we will continue to monitor markets to assess the competitiveness of
the market in existing generation, and we will modify our market rate
criteria if and when appropriate. However, any changes we might make to
our analysis for authorizing market-based rates in the future will not
upset transactions entered into pursuant to existing market-based rate
authority. The policies we put in place today to develop a smoothly
functioning transmission access regime will provide useful experience
and information for assessing the effects of generation concentration.
4. Merger Policy
In the NOPR, the Commission did not address possible ramifications
of the NOPR with regard to its existing merger policy.
Comments
A number of commenters suggest that the Commission should
reevaluate its merger policy in light of the NOPR.147 They further
suggest a number of changes that they believe need to be made to the
Commission's existing merger policy.
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\147\ E.g., NRECA, TAPS, Wisconsin Coalition, APPA.
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Most commenters raising this issue express concerns that mergers
will lessen competition and hinder achievement of competitive bulk
power markets.148 For example, NRECA indicates that the
Commission's merger policy is at a crossroads. It believes that it is
essential for the Commission to reevaluate its merger policy in concert
with the proposed rulemakings.149 Similarly, TAPS recommends that
the Commission reevaluate its merger criteria to ensure that in a more
competitive era, mergers are found to be consistent with the public
interest only if they are pro-competitive. Several commenters argue
that the Commission should continue to conduct a case-by-case
investigation of the product and geographic markets that will be
affected by a proposed merger.150
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\148\ E.g., Wisconsin, Rosebud, NRECA, IN Com, Wisconsin
Coalition, NIEP, Minnesota P&L, APPA.
\149\ See also APPA.
\150\ E.g., Wisconsin Coalition, MMWEC.
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A number of commenters also suggest certain changes that they would
like to see in the Commission's merger policy.151 APPA recommends
that, at a minimum, all merger approvals considered by the Commission
should be conditioned on: (1) Filing an open access transmission
tariff, (2) demonstrating no market power in generation or ancillary
services, and (3) granting all existing requirements customers of the
merged entity the right to convert existing contracts to rights to
equivalent transmission capacity. Several commenters suggest adopting
the U.S. Department of Justice Merger
[[Page 21556]]
Guidelines in analyzing merger proposals.152
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\151\ E.g., APPA, Wisconsin Coalition, Minnesota P&L, IN Com.
\152\ E.g., Wisconsin Coalition.
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Environmental Action and others contend that merging utilities must
be required to demonstrate real net benefits to retail and wholesale
customers that could not otherwise be achieved but for the proposed
merger.153
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\153\ E.g., TAPS, Wisconsin Coalition.
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Commenters also argue that the Commission should use its merger
conditioning authority to order divestiture of transmission and
generation when required to ensure competition.154 Environmental
Action and NEPOOL Review Committee suggest conditioning merger
applications on the existence of regional transmission pricing
arrangements to mitigate any generation market power gained by the
merging entities.
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\154\ E.g., NIEP, Wisconsin Coalition, TAPS, Environmental
Action.
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Commission Conclusion
The Commission appreciates the concerns and suggestions raised with
respect to our merger policy. However, since the time the NOPR was
issued (and comments received thereon), we issued a Notice of Inquiry
on the Commission's merger policy in Docket No. RM96-6-000.155
There we indicated that we will review whether our criteria and
policies for evaluating mergers need to be modified in light of the
changing circumstances, including this final rule, that are occurring
in the electric industry. The NOI proceeding will permit us to consider
comments from all interested participants and, at the same time, allow
us to review our merger criteria and policies in light of this final
rule. We are committed to reviewing our merger policy in a timely
manner in the ongoing NOI proceeding.156
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\155\ FERC Stats. & Regs. para. 35,531 (1996).
\156\ Our decision to review our merger policy in a separate NOI
proceeding is not intended to affect a utility's business decision
of whether a merger may be in the economic interest of its
ratepayers and stockholders. The NOI proceeding will not prevent us
from reviewing merger applications in as timely a manner as
possible.
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5. Contract Reform
In the NOPR, the Commission explained that it believed that it
could remedy unduly discriminatory practices and achieve more
competitive bulk power markets without abrogating existing wholesale
power supply contracts that bundle generation and transmission services
and existing wholesale transmission contracts.157 Thus, we
proposed to apply the functional unbundling requirement only to
transmission services under new requirements contracts, new
coordination contracts, and new transactions under existing
coordination contracts. However, the Commission did invite comment on
whether it would be contrary to the public interest to allow all or
some of the above types of existing contracts to remain in effect.
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\157\ FERC Stats. & Regs. para. 32,514 at 33,093.
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Comments
Requirements and Transmission Contracts
Many of the commenters (including utility customers and third-party
power suppliers) addressing this issue oppose abrogating existing
contracts on a generic basis.158 A number of the commenters
contend that existing contracts should be retained because they are the
result of mutually beneficial bargaining.159 SMUD and TANC are
concerned that existing contracts providing for transmission service
that is superior to the pro forma tariffs not be abrogated.160
Ohio Edison argues that existing contracts have contributed to the
emergence of competition, meet the specific needs of the parties, have
been approved by the Commission, and have not been found to be unduly
discriminatory or violative of the public interest, and that their
preservation is consistent with the Energy Policy Act, most notably
amended section 211 of the FPA. PacifiCorp and AEP express concern that
contract abrogation would create competitive instability. American
Forest & Paper argues that the Commission cannot refuse to honor
existing contracts if it expects a competitive bulk power market to
emerge.
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\158\ E.g., Dayton P&L, NSP, Montaup, Southwestern, Ohio Edison,
Consumers Power, Allegheny, Public Generating Pool, NEPCO,
Pennsylvania P&L, Southwest TDU Group, Arizona, DOD, El Paso,
Florida Power Corp, AEC & SMEPA, Atlantic City, Texaco, Tampa, CSW,
Central Illinois Public Service, CA Cogen, ConEd, GA Com,
Consolidated Natural Gas, Ohio Valley, Pacific Northwest Coop, Salt
River, Oglethorpe, Minnesota P&L, NYSEG, Brazos, Southern,
Washington Water Power, CINergy, SoCal Edison, Hoosier EC.
\159\ E.g., AEC & SMEPA, Cajun, Carolina P&L, NSP, Pennsylvania
P&L, UNITIL, Southwestern, CSW.
\160\ See also Dairyland, DE Muni, Arkansas Cities, Ohio Valley.
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Numerous commenters further argue that contract abrogation requires
a fact-based, contract-specific evaluation, and they oppose any generic
declaration that existing contracts are contrary to the public
interest.161 Some suggest that generic contract abrogation cannot
be justified under the public interest standard.162
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\161\ E.g., AEP, Associated EC, DOD, El Paso, NEPCO, Ohio
Edison, PSNM, Southwest TDU Group, Utilities For Improved
Transition, NYSEG, Citizens Utilities, NM Com, EGA. See also NRECA,
TDU Systems, Blue Ridge, CCEM, Industrial Energy Applications, APPA,
Cajun, Springfield, DE Muni, Missouri Basin MPA, TANC, Wolverine
Coop Members, FL Com, Citizens Utilities, Soyland (support contract
abrogation on a case-by-case basis).
\162\ E.g., Utilities For Improved Transition, NSP,
Southwestern, DE Muni.
---------------------------------------------------------------------------
Missouri Basin MPA argues that the Commission should allow
abrogation of existing wholesale power and transmission arrangements if
the customer can demonstrate the undue competitive disadvantage caused
by the arrangement.
A few commenters support some form of generic contract
abrogation.163 CCEM asserts that existing wholesale requirements
customers must be given the right to convert to transmission service
under non-discriminatory open access tariffs.164 CCEM notes that
this is the same relief from undue discrimination that the Commission
afforded to pipeline customers in Order Nos. 436 and 500.165 CCEM
emphasizes that here, in contrast to what occurred in the gas industry,
``[c]onversion rights should be understood as the logical quid pro quo
for introducing extra-contractual stranded-cost recovery rights into
the wholesale requirements contracts of electric utilities.'' 166
NRECA asserts that it would be unduly discriminatory to allow new
transmission customers to use the open access transmission tariffs, but
not allow existing customers the same access.167
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\163\ E.g., NRECA, CCEM, ELCON, DE Muni, Oglethorpe. Portland
maintains that it would be in the public interest to abrogate
existing contracts completely, but recommends that such action be
taken only on a case-by-case basis.
\164\ See also VT DPS, NYMEX.
\165\ See also VT DPS, Portland.
\166\ CCEM Initial Comments at 26. See also ELCON, VT DPS, Blue
Ridge, NYMEX, OK Com, Missouri Basin MPA, Texas-New Mexico, TDU
Systems.
\167\ See also TDU Systems, Texas-New
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
Mexico, TAPS, Wisconsin
Municipals.
---------------------------------------------------------------------------
TAPS says that if those who now have discriminatory contracts are
forced to live with those contracts, a fully competitive market will be
delayed considerably.168 Moreover, TAPS argues, the Commission has
a statutory duty to remedy the undue discrimination that it is only now
recognizing. Even if the Commission will not abrogate these contracts
across the board, TAPS asserts that we should use our section 206
authority to do so on a contract-by-contract basis.
---------------------------------------------------------------------------
\168\ See also NorAm. UtiliCorp argues that existing contracts
should not be allowed to extend indefinitely (as through
``evergreen'' clauses) without adopting comparability. See also
Texaco, Wisconsin Municipals, Phelps Dodge.
---------------------------------------------------------------------------
San Francisco requests that the Commission clarify that a holder of
capacity rights under an existing
[[Page 21557]]
contract can extend contractual rights to transmission access at least
coterminous with the life of the project and under a roll-over or
renewal contract on the same basis as provided in the existing
contract. Anoka EC proposes that when a wholesale purchaser's contract
expires, it should have a right of first refusal to contract for the
transmission capacity to which it previously had a right. Knoxville
urges the Commission to require renegotiation of the notice and/or term
of all existing contracts for which the voluntary termination period
exceeds the time frame for implementation of the final rule.
NEPCO suggests that we require existing power contracts that allow
rate changes to be separated into their generation and transmission
components, without otherwise disturbing their terms; this would allow
comparisons between the transmission service the utility provides to
its power customers and the service it offers to others.169
---------------------------------------------------------------------------
\169\ See also Industrial Energy Applications.
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Coordination Agreements
CINergy argues that coordination agreements should not be excluded
from the comparability standard and that the Commission should use its
authority under section 206 to require amendments to such agreements,
just as it did in Order 636 in requiring unbundling of pipeline supply
contracts. CINergy suggests that public utilities should be given up to
three years to file the amendments to avoid hardship on the industry
and the Commission's staff. CINergy further asserts that future
transactions conducted under coordination agreements should be
unbundled and the transmission component subjected to the comparable
transmission service requirement.
Others argue that purchases under existing coordination agreements
made on behalf of retail native load should not be unbundled.170
NY Com and IL Com recommend that proposed Sec. 35.28(c) be modified to
state that the functional unbundling requirement ``exclude(s) those
wholesale purchases made by the utility to serve existing or expected
native retail load.''
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\170\ E.g., Con Ed, Detroit Edison, IL Com.
---------------------------------------------------------------------------
Utilities For Improved Transition disagrees with the idea that new
transactions under existing coordination agreements should be subject
to the rule.171 It argues that the sanctity of coordination
contracts should be the same as for other contracts. Coordination
contracts are not simply agreements to agree in the future, according
to Utilities For Improved Transition; they set forth terms and rates
and merely leave the timing of transactions to be resolved in the
future. Moreover, it argues that the Commission has given no reason to
abandon its practice of encouraging coordination sales by allowing
price flexibility.
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\171\ See also Utility Workers Union, VEPCO.
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Commission Conclusion
Requirements and Transmission Contracts
We do not believe it is appropriate to order generic abrogation of
existing requirements and transmission contracts. While the Commission
did generically find it appropriate to modify natural gas contracts to
complete the move to a competitive commodity market in natural gas, we
face a different situation here. At the time the Commission addressed
this situation in the natural gas industry, it was faced with shrinking
natural gas markets, statutory escalations in natural gas ceiling
prices under the Natural Gas Policy Act, and increased production of
gas.172 In other words, there was a market failure in the industry
that required the extraordinary measure of generically allowing all
customers to break their contracts with pipelines.
---------------------------------------------------------------------------
\172\ See Pierce, Richard J., Reconstituting the Natural Gas
Industry from Wellhead to Burnertip, 9 Energy L.J. 1 (1988).
---------------------------------------------------------------------------
In contrast, there is no such market failure in the electric
industry. Although changes in the industry have been and continue to be
dramatic, we do not believe they compel generic abrogation of
requirements and transmission contracts.173
---------------------------------------------------------------------------
\173\ In addition, we do not believe that unfavorable
requirements contracts will derail the attainment of competitive
wholesale power markets. Indeed, many of the commenters support this
position and seek to retain their existing requirements contracts.
---------------------------------------------------------------------------
While we have concluded that current conditions in the wholesale
power market do not warrant the generic modification of requirements
contracts, we conclude nonetheless that the modification of certain
requirements contracts on a case-by-case basis may be appropriate. We
conclude further that, even if customers under such contracts are bound
by so-called Mobile-Sierra clauses, they nonetheless ought to have the
opportunity to demonstrate that their contracts no longer are just and
reasonable.
The Commission finds that it would be against the public interest
to permit a Mobile-Sierra clause in an existing wholesale requirements
contract to preclude the parties to such a contract from the
opportunity to realize the benefits of the competitive wholesale power
markets. For purposes of this finding, the Commission defines existing
requirements contracts as contracts executed on or before July 11,
1994.174 By operation of this finding, a party to a requirements
contract containing a Mobile-Sierra clause no longer will have the
burden of establishing independently that it is in the public interest
to permit the modification of such contract. The party, however, still
will have the burden of establishing that such contract no longer is
just and reasonable and therefore ought to be modified.
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\174\ This is consistent with the definition of existing
requirements contracts we have used for purposes of stranded cost
recovery.
---------------------------------------------------------------------------
This finding complements the Commission's finding that,
notwithstanding a Mobile-Sierra clause in an existing requirements
contract, it is in the public interest to permit amendments to add
stranded cost provisions to such contracts if the public utility
proposing the amendment can meet the evidentiary requirements of this
Rule.175 The Commission's complementary Mobile-Sierra findings are
not mutually exclusive. Any contract modification approved under this
Section shall provide for the utility's recovery of any costs stranded
consistent with the contract modification. The stranded costs must be
prudently incurred, legitimate and verifiable, as provided in Section
IV.J. Further, the Commission has concluded that if a customer is
permitted to argue for modification of existing contracts that are less
favorable to it than other generation alternatives, then the utility
should be able to seek modification of contracts that may be beneficial
to the customer.
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\175\ See Section IV.J.5.
---------------------------------------------------------------------------
The Commission believes that the most productive way to analyze
contract modification issues is to consider simultaneously both the
selling public utility's claims, if any, that it had a reasonable
expectation of continuing to serve the customer beyond the term of the
contract and the customer's claim, if any, that the contract no longer
is just and reasonable and therefore ought to be modified. Thus, if the
selling public utility intends to claim stranded costs, it must present
that claim in any section 206 proceeding brought by the customer to
shorten or terminate the contract. Similarly, if the customer intends
to claim that the notice or termination provision of its existing
requirements contract is unjust and unreasonable, it must present that
claim in any proceeding brought by the selling public utility to seek
recovery of stranded
[[Page 21558]]
costs. This will promote administrative efficiency and will permit the
Commission to consider how the contracting parties' claims bear on one
another.
The Commission does not take contract modification lightly. Whether
a utility is seeking a contract amendment to permit stranded cost
recovery based on expectations beyond the stated term of the contract,
or a customer is seeking to shorten or eliminate the term of an
existing contract, we believe that each has a heavy burden in
demonstrating that the contract ought to be modified. Still, we believe
that given the industry circumstances now facing us, both selling
utilities and their customers ought to have an opportunity to make the
case that their existing requirements contracts ought to be modified.
By providing both buyers and sellers this opportunity, the Commission
attempts to strike a reasonable balance of the interests of all market
participants. The Commission expects that many of the arguments
presented by buyers and sellers in such proceedings will be fact
specific.
We note that because we are not abrogating existing requirements
and transmission contracts generically and because the functional
unbundling requirement of the Final Rule applies only to new wholesale
services, the terms and conditions of the Final Rule pro forma tariff
do not apply to service under existing requirements contracts. However,
if a customer's existing bundled service (transmission and generation)
contract or transmission-only contract expires, and the customer takes
any new transmission service from its former supplier, the terms and
conditions of the Final Rule tariff would then apply to the
transmission service that the customer receives.
A further issue concerning firm contract customers is their right
to transmission capacity (and the rate for such capacity) when their
contracts expire by their own terms or become subject to renewal or
rollover. We have concluded that all firm transmission customers
(requirements and transmission-only), upon the expiration of their
contracts or at the time their contracts become subject to renewal or
rollover, should have the right to continue to take transmission
service from their existing transmission provider. The limitations are
that the underlying contract must have been for a term of one-year or
more and the existing customer must agree to match the rate offered by
another potential customer, up to the transmission provider's maximum
filed transmission rate at that time, and to accept a contract term at
least as long as that offered by the potential customer.176 This
means that there is no right to grandfather the historical price of the
transmission service. Thus, if not enough capacity is available to meet
all requests for service, the right of first refusal gives the capacity
to the existing customer who had contractually been using the capacity
on a long-term, firm basis, assuming that it meets the conditions set
forth above. Moreover, this limited right of first refusal is not a
one-time right of first refusal for contracts existing as of the date
of the final rule, but is an ongoing right that may be exercised at the
end of all firm contract (including all future unbundled transmission
contracts) terms. A customer converting existing bundled service to the
Final Rule pro forma tariff would not have a reservation priority for
capacity expansions, unless the existing contract provides for future
transmission to the customer that requires capacity expansion.177
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\176\ This right of first refusal exists whether or not the
customer buys power from the historical utility supplier or another
power supplier. If the customer chooses a new power supplier and
this substantially changes the location or direction of its power
flows, the customer's right to continue taking transmission service
from its existing transmission provider may be affected by
transmission constraints associated with the change.
\177\ The above discussion on a right of first refusal addresses
firm contract customers. However, the same logic applies to retail
customers.
---------------------------------------------------------------------------
Finally, with respect to all existing requirements contracts and
tariffs that provide for bundled rates, we will require all public
utilities to make informational filings setting forth the unbundled
power and transmission rates reflected in those contracts and tariffs.
These informational rates must be submitted to the Commission within 60
days of publication of the Final Rule in the Federal Register and must
also be included as a line item on all bills submitted to wholesale
customers in the third month following the effective date of this final
rule. The unbundled informational rates will permit wholesale customers
to compare rates in anticipation of their contracts expiring so that
they can evaluate alternative contracts.
Coordination Agreements
The situation as to coordination agreements requires a slightly
different approach.178 While we also believe that as a general
matter it is important not to generically abrogate any coordination
agreements, this is particularly true for non-economy energy
coordination agreements that may reflect complementary long-term
obligations among the parties. This type of agreement presents special
problems and, as discussed below, we will not generically require this
type of coordination agreement to be modified.179
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\178\ For purposes of this discussion, we define coordination
agreements as all power sales agreements, except requirements
service agreements. In addition, for purposes of implementing the
non-discriminatory, open access requirements of the Final Rule, we
are dividing bilateral coordination agreements into two general
categories: (1) Economy energy coordination agreements are contracts
and service schedules thereunder that provide for trading of
electric energy on an ``if, as, and when available'' basis, but do
not require either the seller or buyer to engage in a particular
transaction; and (2) non-economy energy coordination agreements are
any non-requirements service agreements, except economy energy
coordination agreements.
\179\ The requirements for power pools and other multilateral
arrangements are discussed in detail in Section IV.F.
---------------------------------------------------------------------------
Hundreds of coordination agreements exist in the industry today.
Many are open-ended agreements that permit new transactions to occur
well into the future. Because these contracts may not expire of their
own terms in a reasonable time, they may present a larger and more
enduring obstacle to non-discriminatory open access and more
competitive bulk power markets. Thus, to assure that non-discriminatory
open access becomes a reality in the relatively near future, we will
partially modify existing economy energy coordination agreements. We
will condition future sales and purchase transactions under existing
economy energy coordination agreements 180 to require that the
transmission service associated with those transactions be provided
pursuant to this Rule's requirements of non-discriminatory open access,
no later than December 31, 1996.181 We also will require that for
new economy energy coordination agreements 182 where the
transmission owner uses its transmission system to make economy energy
sales or purchases, the transmission owner must take such service under
its own transmission tariff as of the date trading begins under the
agreement.183
---------------------------------------------------------------------------
\180\ Those executed prior to 60 days after publication of the
Open Access Rule in the Federal Register.
\181\ The requirement to unbundle future transactions under
existing economy energy coordination agreements means that if the
transmission owner uses its transmission system to make economy
energy coordination sales or purchases, it must take service for
these transactions under its own transmission tariff after December
31, 1996.
\182\ Those executed 60 days after publication of the Open
Access Rule in the Federal Register.
\183\ Accordingly, transmission service needed for sales or
purchases under all new economy energy coordination agreements will
be pursuant to the Final Rule pro forma tariff.
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[[Page 21559]]
Finally, we will treat non-economy energy coordination agreements
differently. We will not require their modification. However, this does
not insulate such agreements from complaints that transmission service
provided under such agreements be provided pursuant to the Final Rule
pro forma tariff.
With respect to coordination pricing practices, we conclude that
non-discriminatory open access consistent with the requirements of this
Rule is necessary if we are to allow utilities to continue to use
market-driven pricing, such as split-the-savings pricing, for
coordination sales. Absent such non-discriminatory open access, a
utility would be able to deny access to others so as to obtain a higher
price for its own power sales.
6. Flow-Based Contracting and Pricing
In the NOPR, the Commission discussed the procedures to be used in
establishing Stage One rates. These Stage One rates were proposed as an
administrative convenience. The proposal merely followed the long-
established practice of establishing rates on the basis of contract
path pricing.184 The Commission made no determination with respect
to the appropriateness of flow-based pricing or contracting for other
purposes.185
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\184\ A contract path is simply a path that can be designated to
form a single continuous electrical path between the parties to an
agreement. Because of the laws of physics, it is unlikely that the
actual power flow will follow that contract path.
\185\ Flow-based pricing or contracting would be designed to
account for the actual power flows on a transmission system. It
would take into account the ``unscheduled flows'' that occur under a
contract path regime.
---------------------------------------------------------------------------
Comments
Most of the commenters addressing this issue recommend that
industry or the Commission--either in this rule or ultimately--dispense
with the traditional contract path basis for pricing and contracting.
Most commenters also recommend that the Commission adopt or encourage a
regional approach to the solution of transmission pricing problems,
though they differ markedly in how to account for flows.186
---------------------------------------------------------------------------
\186\ E.g., APPA, TAPS, NY Energy Buyers, Arcadia, Brownsville,
Detroit Edison Customers, AMP-Ohio, Michigan Systems.
---------------------------------------------------------------------------
Transmission customers generally seek to rid themselves of
``pancaked'' transmission rates that are associated with the
traditional approach to transmission pricing.187 They propose the
development of regionwide transmission rates, perhaps determined on a
pool or RTG basis. Most, however, do not discuss how to account for
unscheduled flows.188
---------------------------------------------------------------------------
\187\ E.g., AMP-Ohio, NRECA, APPA, Detroit Edison Wholesale
Customers, MMWEC, Missouri Basin MPA, Air Liquide, American Wind
Energy, Associated Power, CCEM.
\188\ Some commenters propose the development of a regional rate
on a postage stamp basis, without regard to distance travelled or
the actual path of power flows. E.g., Air Liquide, American National
Power, CA Energy Co. Several commenters do, however, propose ways to
account for unscheduled flows. E.g., American Forest & Paper, DE
Muni, Lower Colorado River Authority.
---------------------------------------------------------------------------
Many transmission providers, some regulatory authorities, and some
individuals strongly support flow-based pricing. Most of these
commenters recognize a need for a regional approach to resolve
transmission pricing concerns.189 However, many of them also
appear to accept contract pricing in the near term because of the need
to implement open access quickly.190 NERC recommends that the
Commission maintain an open position on the transfer scheduling process
and supports changes in the process to reflect actual power flows. EEI
suggests that the Commission should be willing to deviate from a
contract path approach, since competition may be accompanied by greater
unscheduled flows and contract pricing is not well equipped to deal
with such flows. However, EEI concludes that a single approach to
pricing will not be appropriate for all systems.
---------------------------------------------------------------------------
\189\ E.g., CSW, EDS Utilities, Dominion, CINergy, KS Com, CT
DPUC, Com Ed, Hogan.
\190\ NYMEX favors contract path pricing because of its
familiarity and believes that the issue should primarily be resolved
by the transmitting utilities. AEP believes that the primary
responsibility lies with industry to develop alternative pricing
structures.
---------------------------------------------------------------------------
Other commenters, however, do raise concerns with respect to flow-
based pricing. AEC & SMEPA considers flow-based pricing to be flawed
because that method makes an individual customer responsible for load
flow effects caused by a third party's development of the third-party's
transmission system over which the customer and its transmission
provider had no control. Dayton P&L fears that competition would be
lessened under flow-based pricing because utilities with large
transmission systems would dominate the market.
Several commenters oppose Southern's and United Illuminating's
flow-based proposals, arguing that the methodologies are based on
estimates of actual flows or a set of conditions with limited
applicability. Various commenters also believe that a single rate is
flawed and could cause just as many problems as contract path
pricing.191
---------------------------------------------------------------------------
\191\ E.g., NU, NEPCO, BECO, Florida Power Corp.
---------------------------------------------------------------------------
Most commenters appear to believe that the Commission endorsed
contract path pricing in the NOPR. Hogan expresses concern that many
industry participants' understanding of the pro forma tariffs is based
on the fiction of the contract path. The MT Dept of Environmental
Quality believes that despite the Commission's pledge to consider
innovative pricing proposals,192 such proposals will receive heavy
scrutiny, while conventional contract path pricing proposals will
receive nearly automatic approval. Dominion is concerned that relying
on the initiative of individual transmission owners to develop flow-
based pricing will yield slow and patchy results.
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\192\ See FERC Stats. & Regs. para. 31,005.
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Commission Conclusion
We will not, at this time, require that flow-based pricing and
contracting be used in the electric industry. In reaching this
conclusion, we recognize that there may be difficulties in using a
traditional contract path approach in a non-discriminatory open access
transmission environment, as described by Hogan and others. At the same
time, however, contract path pricing and contracting is the
longstanding approach used in the electric industry and it is the
approach familiar to all participants in the industry. To require now a
dramatic overhaul of the traditional approach--such as a shift to some
form of flow-based pricing and contracting--could severely slow, if not
derailed for some time, the move to open access and more competitive
wholesale bulk power markets. In addition, we believe it is premature
for the Commission to impose generically a new pricing regime without
the benefit of any experience with such pricing. We welcome new and
innovative proposals, but we will not impose them in this Rule.
While we are not requiring the use of any form of flow-based
pricing, we recognize that some versions of flow-based pricing could
have benefits. For example, some versions of flow-based pricing could
more accurately reflect and price the actual power flows on
transmission systems and thus could produce efficiency gains, better
generation siting decisions, and benefits for customers and utilities
alike. Other versions could more accurately assign capacity rights in
accordance with a party's contribution to capacity costs.
These potential benefits, however, will not simply come about in
the abstract. Flow-based pricing methodologies that will achieve the
benefits sought by most of the
[[Page 21560]]
participants in the industry are in a development stage and require
further work and refinement to address some of the difficulties
associated with flow-based approaches. Concurrent work on OASIS and
resolving available transmission capability issues may help resolve
flow-based issues. However, as demonstrated by the paucity of possible
methodologies presented in the comments, developing workable
methodologies will be difficult. As we explained in our Transmission
Pricing Policy Statement, we are receptive to proposals for alternative
rate methodologies, such as distance-sensitive and flow-based pricing,
as long as the proposals are well supported. However, we have yet to
receive a formal rate application for a flow-based pricing methodology
that has been tested enough that it can be required on a generic basis.
Thus, we have decided to go forward to achieve open access and more
competitive wholesale bulk power markets without waiting for the
development of a generic flow-based pricing methodology.
We wish to emphasize further that in taking this approach we are
not endorsing the traditional contract path approach as the only
available approach. We continue to approve contract path pricing
because it is the long-established pricing method that comes to us in
rate filings by the electric industry, is administratively convenient
and feasible, and thus is a practical way to move forward now. We
remain open to alternative methodologies, but need to see better
developed approaches from the industry before we can consider generic
adoption of alternative pricing.
We also believe the adoption of flow-based pricing will be more
practical on a regional, instead of individual utility, basis. Some
forms of flow-based pricing may even require a regional approach. To
this extent, regional ISOs could be a valuable mechanism for
implementing such pricing reforms.
B. Legal Authority
The Commission reaffirms its conclusion in the NOPR that we have
the authority under the FPA to order wholesale transmission services in
interstate commerce to remedy undue discrimination by public utilities.
We analyze below the relevant cases examining our wheeling authority,
then discuss and respond to the legal arguments raised by the
commenters.
1. Bases for Legal Authority
a. Undue Discrimination/Anticompetitive Effects
In upholding the Commission's order requiring non-discriminatory
open access in the natural gas industry, the court in Associated Gas
Distributors v. FERC stated that the Natural Gas Act ``fairly
bristles'' with concern for undue discrimination.193 The same is
true of the FPA. The Commission has a mandate under sections 205 and
206 of the FPA to ensure that, with respect to any transmission in
interstate commerce or any sale of electric energy for resale in
interstate commerce by a public utility, no person is subject to any
undue prejudice or disadvantage. We must determine whether any rule,
regulation, practice or contract affecting rates for such transmission
or sale for resale is unduly discriminatory or preferential, and must
prevent those contracts and practices that do not meet this standard.
As discussed below, AGD demonstrates that our remedial power is very
broad and includes the ability to order industry-wide non-
discriminatory open access 194 as a remedy for undue
discrimination. The AGD court reached this decision even in the face of
prior cases that acknowledged that Congress did not mandate common
carriage or explicitly empower the Commission to order direct access
for either gas transporters or electric utilities. Moreover, the
Commission's power under the FPA ``clearly carries with it the
responsibility to consider, in appropriate circumstances, the
anticompetitive effects of regulated aspects of interstate utility
operations pursuant to (FPA) sections 202 and 203, and under like
directives contained in sections 205, 206, and 207.'' 195
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\193\ Associated Gas Distributors v. FERC, 824 F.2d 981, 998
(D.C. Cir. 1987), cert. denied, 485 U.S. 1006 (1988) (AGD).
\194\ We use the term ``open access'' to refer to a public
utility's obligation to put a tariff on file offering service to
eligible customers. Access is not open to all. Specifically, the
tariff is not an offer to serve retail customers if state law does
not permit retail wheeling.
\195\ Gulf States Utilities Company v. FPC, 411 U.S. 747, 758-59
(1973).
---------------------------------------------------------------------------
Therefore, based on the mandates of sections 205 and 206 of the FPA
and the case law interpreting the Commission's authority over
transmission in interstate commerce, we conclude that we have ample
legal authority--indeed, a responsibility--under section 206 of the FPA
to order the filing of non-discriminatory open access transmission
tariffs if we find such order necessary as a remedy for undue
discrimination or anticompetitive effects.196 We discuss below the
primary court decisions that touch on our wheeling authority under
sections 205 and 206.
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\196\ In most situations, discrimination that precludes
transmission access or gives inferior access will have at least
potential anticompetitive effects because it limits access to
generation markets and thereby limits competition in generation.
Similarly, it is probable that any transmission provision that has
anticompetitive effects would also be found to be unduly
discriminatory or preferential because the anticompetitive provision
would most likely favor the transmission owner vis-a-vis others.
---------------------------------------------------------------------------
The Commission's authority to order access as a remedy for undue
discrimination under the Natural Gas Act (NGA) was upheld and discussed
in detail in AGD. In AGD, the court upheld in relevant part the
Commission's Order No. 436.197 That order found the prevailing
natural gas company practices to be ``unduly discriminatory'' within
the meaning of section 5 of the NGA (the parallel to section 206 of the
FPA) and held that if pipelines wanted blanket certification for their
transportation services, they must commit to transport gas for others
on a non-discriminatory basis; in other words, they must provide non-
discriminatory open access.
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\197\ Order No. 436, Regulation of Natural Gas Pipelines After
Partial Wellhead Decontrol, FERC Stats. & Regs., Regulations
Preambles para. 30,665 (1985).
---------------------------------------------------------------------------
In upholding the Commission's authority to require open access, the
court first noted that the opponents' arguments against such authority
must proceed ``uphill.'' The statute contains no language forbidding
the Commission to impose common carrier status on pipelines, let alone
forbidding the Commission to impose ``a specific duty that happens to
be a typical or even core component of such status.'' The court found
that the legislative history cited by the opponents came nowhere near
overcoming this statutory silence. Rather, the legislative history
supported only the proposition that Congress itself declined to impose
common carrier status.198 Emphasizing Congress' deep concern with
undue discrimination, the court found that the Commission had ample
authority to ``stamp out'' such discrimination:
\198\ AGD, supra, 824 F.2d at 997.
---------------------------------------------------------------------------
The issue seems to come down to this: Although Congress
explicitly gave the Commission the power and the duty to achieve one
of the prime goals of common carriage regulation (the eradication of
undue discrimination), the Commission's attempted exercise of that
power is invalid because Congress in 1906 and 1914 and 1935 and 1938
itself refrained from affixing common carrier status directly onto
the pipelines and from authorizing the Commission to do so.
[[Page 21561]]
And this proposition is said to control no matter how sound the
Order may be as a response to the facts before the Commission. We
think this turns statutory construction upside down, letting the
failure to grant a general power prevail over the affirmative grant
of a specific one.199
---------------------------------------------------------------------------
\199\ Id. at 998.
The AGD court found that court decisions under the FPA did not support
the view that the Commission's authority to ``stamp out'' undue
discrimination is hamstrung by an inability to require non-
discriminatory open access as a remedy. These decisions are discussed
below.
One of the earliest cases on wheeling is Otter Tail Power Company
v. United States (Otter Tail).200 In that case, the Supreme Court
rejected the argument that the District Court, in a civil antitrust
suit, could not order wheeling because to do so would conflict with the
FPC's purported wheeling authority.201 The Court explained that
Congress had decided not to impose a common carrier obligation on the
electric power industry and noted that the Commission was not at that
time expressly granted power to order wheeling.202 In effect, it
concluded that because Congress did not include common carrier
provisions in the FPA, the Commission must not have any express
authority to order wheeling that would preclude the District Court from
imposing a wheeling remedy. Nowhere, however, did the Court say that
the Commission lacked authority under section 206 to remedy undue
discrimination. Indeed, that was simply not a matter before the Court
or of any consequence to its decision.
---------------------------------------------------------------------------
\200\ 410 U.S. 366 (1974).
\201\ 410 U.S. at 375-76.
\202\ Id. at 374-76.
---------------------------------------------------------------------------
In the FPA, while Congress elected not to impose common carrier
status on the electric power industry, it tempered that determination
by explicitly providing the Commission with the authority to eradicate
undue discrimination--one of the goals of common carriage
regulation.203 By providing this broad authority to the
Commission, it assured itself that in preserving ``the voluntary action
of the utilities'' it was not allowing this voluntary action to be
unfettered. It would be far-reaching indeed to conclude that Otter
Tail, which was a civil antitrust suit that raised issues entirely
unrelated to our authority under section 206, is an impediment to our
achieving one of the primary goals of the FPA--eradicating undue
discrimination in transmission in interstate commerce in the electric
power industry.
---------------------------------------------------------------------------
\203\ See AGD, 824 F.2d at 998.
---------------------------------------------------------------------------
In Richmond Power & Light Company v. FERC (Richmond),204 the
FPC, in reaction to the 1973 oil embargo, was attempting to reduce
dependence on oil. The FPC requested that utilities with excess
capacity wheel power to the New England Power Pool (NEPOOL). In
response, several suppliers and transmission owners filed rate
schedules with the FPC that provided for voluntary wheeling. Richmond
Power & Light Company (Richmond) objected to these filings, claiming
that they were unreasonable because they did not guarantee transmission
access. The FPC refused to compel the utilities to wheel Richmond's
power, stating that it did not have the authority to order a public
utility to act as a common carrier.
---------------------------------------------------------------------------
\204\ 574 F.2d 610 (D.C. Cir. 1978).
---------------------------------------------------------------------------
The D.C. Circuit upheld the Commission. It acknowledged that
Richmond's argument was persuasive in some respects, but stated that
any conditions the Commission might impose could not contravene the
FPA. The court examined the legislative history of the FPA and stated
that ``[i]f Congress had intended that utilities could inadvertently
bootstrap themselves into common-carrier status by filing rates for
voluntary service, it would not have bothered to reject mandatory
wheeling * * *.'' 205
---------------------------------------------------------------------------
\205\ Id. at 620.
---------------------------------------------------------------------------
However, the D.C. Circuit in no way indicated that the Commission
was foreclosed from ordering transmission as a remedy for undue
discrimination. Richmond also had argued that the alleged refusal of
the American Electric Power Company (AEP) and its affiliate, Indiana &
Michigan Electric Company (Indiana), to wheel Richmond's excess energy
was unlawful discrimination because AEP and Indiana wheeled higher-
priced electricity from other AEP affiliates. The court acknowledged
that Richmond's claim of unlawful discrimination was theoretically
valid, but found that Richmond had failed to prove its case. It noted
that if Richmond had argued that the rates were unjustifiably
discriminatory, or that Indiana's failure to use its transmission
capability fully or to purchase less expensive electricity for wheeling
resulted in unnecessarily high rates, a different case would be before
the court.206 The case thus does not in any way limit the
Commission's authority to remedy undue discrimination.
---------------------------------------------------------------------------
\206\ Id. at 623, nn.53 and 57.
---------------------------------------------------------------------------
In Central Iowa Power Cooperative v. FERC,207 the FPC 208
reviewed the terms of the Mid-Continent Area Power Pool (MAPP)
Agreement under its section 205 and 206 authority. The agreement
contained two membership limitations. First, the agreement established
two classes of membership, with one class being entitled to more
privileges than the other. Second, the agreement excluded non-
generating distribution systems from pool services. The FPC found the
first limitation on membership--the two-class system--to be unduly
discriminatory and not reasonably related to MAPP's objectives. The FPC
conditioned approval of the agreement under section 206 on the removal
of the unduly discriminatory provision. The FPC found that the second
limitation, the exclusion of non-generating distribution systems, was
not anticompetitive and did not render the agreement inconsistent with
the public interest.
---------------------------------------------------------------------------
\207\ 606 F.2d 1156 (D.C. Cir. 1979).
\208\ While Central Iowa was pending, certain of the functions
of the FPC were transferred to the FERC under the DOE Organization
Act. Accordingly, the FERC was substituted for the FPC as the
respondent in the case.
---------------------------------------------------------------------------
On appeal, the D.C. Circuit affirmed the FPC's decision. The court
found that the FPC did have authority to order changes in the scope of
the MAPP agreement, if the agreement was unjust, unreasonable, unduly
discriminatory or preferential under section 206 of the FPA. The court
stated:
The Commission had authority, * * * under section 206 of the
Act, * * * to order changes in the limited scope of the Agreement,
including the addition of pool services, if, in the absence of such
modifications, the Agreement presented ``any rule, regulation,
practice or contract (that was) unjust, unreasonable, unduly
discriminatory or preferential.'' 209
---------------------------------------------------------------------------
\209\ 606 F.2d at 1168.
However, the court agreed with the FPC's conclusion that the limited
scope of MAPP was not unjust, unreasonable, or unduly discriminatory.
The court recognized that a pool was not invalid under section 206
merely because a more comprehensive arrangement was possible.
The D.C. Circuit upheld the Commission's refusal to eliminate the
second limitation on membership by ordering MAPP participants to wheel
to non-generating electric systems.210 However, neither the
Commission nor the court was presented with the argument that wheeling
was necessary as a remedy for undue discrimination.
---------------------------------------------------------------------------
\210\ Id. at 1169; see also Municipalities of Groton v. FERC,
587 F.2d 1296 (D.C. Cir. 1978).
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[[Page 21562]]
In Florida Power & Light Company v. FERC (Florida),211 the
Commission ordered Florida Power & Light Company (FP&L) to file a
tariff setting forth FP&L's policy relating to the availability of
transmission service.212 FP&L objected to including such a policy
statement in its tariff and argued that the filing of such a policy
would convert FP&L into a common carrier by obligating it to offer
service to all customers.213 There was no finding that the action
ordered was necessary to remedy undue discrimination.
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\211\ 660 F.2d 668 (5th Cir. 1981), cert. denied sub nom. Fort
Pierce Utilities Authority v. FERC, 459 U.S. 1156 (1983).
\212\ FP&L provided transmission service when four conditions
were met: (1) The specific potential seller and buyer were
contractually identified; (2) the magnitude, time and duration of
the transaction were specified prior to the commencement of the
transmission; (3) it could be determined that the transmission
capacity would be available for the term of the contract; and (4)
the rate was sufficient to cover FP&L's costs.
\213\ All utilities requesting wheeling services, subject to
availability, would be entitled to receive transmission service
under the filed terms. Any changes to a filed rate must be filed
with the Commission. This is the so-called ``filed rate doctrine.''
See Northwestern Public Service Company v. Montana-Dakota Utilities
Company, 181 F.2d 19, 22 (8th Cir. 1980), aff'd, 341 U.S. 246
(1951).
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The Fifth Circuit Court of Appeals agreed with FP&L that the
mandatory filing of the policy statement would require FP&L to provide
transmission service beyond its voluntary commitment because such a
requirement would change its duties and liabilities.214 The
Commission order would impose common carrier status on FP&L, the court
found.215 The court noted that the Commission did not rely on a
finding of anticompetitive behavior and therefore the court did not
address the Commission's power to remedy antitrust violations.216
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\214\ Under the filed rate doctrine, a refusal to wheel would be
unduly discriminatory under section 206 of the FPA. As the court
acknowledged, a customer refused service could petition the
Commission to find that FP&L's policy of availability was unduly
discriminatory under section 206(a) of the FPA. The court said that
in the absence of a tariff on file, a utility refused wheeling
services would be unable to claim discrimination under section
206(a) of the FPA. 660 F.2d at 675 (expressing ``serious doubts that
such a petition would be successful in the absence of a tariff'').
\215\ Id. at 676.
\216\ Id. at 678.
---------------------------------------------------------------------------
The AGD court explicitly rejected the claim that the above line of
cases establishes that the Commission lacks authority to require non-
discriminatory open access.217 Opponents of the Commission's order
argued in AGD that Richmond and Florida, supra, stand for the
proposition that the Commission cannot indirectly do what it allegedly
cannot do directly, that is, impose common carriage. The AGD court
rejected these arguments, stating that the petitioners read the
electric cases far too broadly:
\217\ The AGD court did not address New York State Electric &
Gas Corporation v. FERC, 638 F.2d 388 (2d Cir. 1980), cert. denied,
454 U.S. 821 (1981) (NYSEG), presumably because that case did not
concern whether the Commission could order wheeling as a remedy for
undue discrimination.
---------------------------------------------------------------------------
(n)either Richmond nor Florida comes anywhere near stating that the
Commission is barred from imposing an open-access condition in all
circumstances.218
---------------------------------------------------------------------------
\218\ 824 F.2d at 999.
The court noted that the Florida case had expressly left open the
question of whether the Commission would be entitled to use an open
access condition as a remedy for anticompetitive conduct, and that in
Richmond the D.C. Circuit had said little more than that unwillingness
to transmit for all could not be automatically deemed undue
discrimination. The court also noted the Central Iowa case, supra, in
which it had upheld a Commission order that found a power pooling
agreement discriminatory on its face because the agreement gave one
class of membership privileged status over another. The court stated
that the Central Iowa case ``upholds the power of the Commission to
subject approval of a set of voluntary transactions to a condition that
providers open up the class of permissible users.'' 219 The court
added that it refused to ``turn statutory construction upside down'' by
letting Congress' failure to grant a general power of common carriage
prevail over the affirmative grant of the specific power to eradicate
undue discrimination.220
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\219\ Id. at 999.
\220\ Id. at 1006.
---------------------------------------------------------------------------
We conclude that AGD's analysis of undue discrimination under
sections 4 and 5 of the Natural Gas Act is equally applicable to an
undue discrimination analysis under sections 205 and 206 of the FPA.
The Commission and courts have long recognized that the NGA was
patterned after the FPA and that the two statutes should be interpreted
in the same manner.221 Thus, we conclude that we have the
authority to remedy undue discrimination and anticompetitive effects by
requiring all public utilities that own, control or operate
transmission facilities to file non-discriminatory open access
transmission tariffs.
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\221\ See, e.g., FPC v. Sierra Pacific Power Company, 350 U.S.
348, 353 (1956); Arkansas Louisiana Gas Company v. Hall, 453 U.S.
571, 577 n.7 (1981); and Kentucky Utilities Company v. FERC, 760
F.2d 1321, 1325 n.6 (D.C. Cir. 1985). Section 206 of the FPA was
recently revised and now differs from section 5 of the NGA, but not
in a manner significant to our discussion here. See 16 U.S.C. 824e
(b) and (c).
---------------------------------------------------------------------------
b. Section 211 of the Federal Power Act
In concluding that we must invoke our section 206 authority to
remedy undue discrimination and anticompetitive effects in the electric
industry, we have carefully considered the goals of Title VII of the
Energy Policy Act, and whether section 211 of the FPA, by itself, is
sufficient to remedy undue discrimination in public utility
transmission services. Title VII of the Energy Policy Act, which
amended section 211 of the FPA to give the Commission broader authority
to order wheeling in the public interest on a case-by-case basis,
reflects the intent of Congress to encourage competitive wholesale
electric markets. Section 211 provides a means for wholesale power
sellers and buyers to obtain transmission services necessary to compete
in, or to reach, competitive markets, and is a valuable tool to
encourage competitive markets. However, in amending section 211,
Congress left unaltered the authorities and obligations of the
Commission under sections 205 and 206 (similar to our authorities and
obligations under sections 4 and 5 of the NGA) to remedy undue
discrimination. In addition, as discussed below, reliance on section
211 alone in some circumstances can result in the perpetuation of,
rather than the elimination of, undue discrimination and
anticompetitive effects.
First, there are inherent delays in the procedures for obtaining
service under section 211. However, for competitive reasons, many
transactions must be negotiated relatively quickly. Many competitive
opportunities will be lost by the time the Commission can issue a final
order under section 211. Case-by-case section 211 proceedings are not a
substitute for tariffs of general applicability that permit timely,
non-discriminatory access on request.
Second, discrimination is inherent in the current industry
environment in which some customers and sellers are served by open
access systems, and others have to rely on negotiated bilateral
arrangements or the mandatory section 211 process. The end result is
discrimination in the ability to obtain transmission services, as well
as in the quality and prices of the services. This national patchwork
of open and closed transmission systems, with disparate terms and
conditions of service, cannot be cured effectively through section 211.
The Commission believes that its actions under sections 205 and 206
will complement the section 211 procedures
[[Page 21563]]
to achieve both the Energy Policy Act's goals of creating more
competitive bulk power markets and lower rates for consumers and the
Federal Power Act's explicit direction in section 205(b) that no public
utility shall, with respect to any transmission in interstate commerce,
grant any undue preference or advantage to any person or subject any
person to any undue prejudice or disadvantage.
2. Response to Commenters Opposing Our Legal Authority
a. Authority to Order Open Access Tariffs
Comments
Initial Comments Supporting Commission Authority
A number of commenters support or state that they do not oppose the
Commission's authority to order open access tariffs.222 NIEP and
CCEM explain that the AGD decision supports the Commission's action in
this proceeding. ELCON asserts that the Commission's ``extensive
treatment of the relevant case law demonstrating FERC's authority to
remedy this discrimination is legally sound.'' UtiliCorp argues that
section 211 supports, rather than undermines, the Commission's
authority for the NOPR because it reflects Congress's intention to
encourage more competitive bulk power markets.
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\222\ NIEP, ELCON, CINergy, UtiliCorp, TAPS, SBA, Entergy, NY
Energy Buyers, Sierra.
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Initial Comments Opposing Commission Authority
Other commenters assert that the Commission has improperly relied
on sections 205 and 206 of the FPA to require open access.223 They
argue, for instance, that Otter Tail should be read as a broad
constraint on the Commission's authority to order wheeling for any
purpose and that the AGD decision does not undermine that holding or
the cases following Otter Tail.224 In support, some of these
commenters discuss Richmond Power & Light, New York State Electric &
Gas Corporation, and Florida Power & Light Company, the same cases
discussed by the Commission in the NOPR.225
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\223\ E.g., EEI, Atlantic City, Allegheny, VA Com, PA Com, Ohio
Edison, Southern, Utilities For Improved Transition, Dayton P&L,
SCE&G, Centerior, BG&E, Central Hudson, NY Com, Salt River, Carolina
P&L, Union Electric, VEPCO, Utility Workers Union.
\224\ EEI, VA Com, Union Electric.
\225\ E.g., EEI, VA Com, NY Com, PA Com, Salt River, Southern,
Dayton P&L, Detroit Edison, BG&E.
---------------------------------------------------------------------------
For example, EEI highlights the AGD court's discussion noting the
difference between the legislative history of the NGA and that of the
FPA, which the court stated was not as strong as that of the NGA.
Moreover, EEI argues that the court found that section 7 of the NGA
provided support for the Commission's actions in Order No. 436 and that
such section 7 conditioning authority is lacking under the FPA.
Allegheny notes that AGD did not overrule Otter Tail. Dayton P&L states
that, in the gas case, the Commission was responding to voluntary
filings by pipelines. It also says that before the NOPR, the Commission
itself saw its authority as more limited. SCE&G points to differences
between Commission jurisdiction over public utilities and gas pipelines
and criticizes the Commission's alleged assumption that the
circumstances involved in the gas and electric industries are virtually
identical.
PA Com argues that the attempt to analogize to the NGA and the
cases that refer to that Act is inconsistent with the technical and
engineering realities of the electric transmission grid and that
extensive comparisons between the natural gas industry and the electric
industry are misleading.226
---------------------------------------------------------------------------
\226\ See also NY Com (NGA has no parallel provision to section
211 of the FPA), Salt River.
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FL Com argues that, in relying on sections 205 and 206 to establish
generic open access transmission tariffs for all public utilities, the
Commission violates the court's decision in Cajun Electric Power
Cooperative v. FERC, 28 F.3d 173 at 179 (D.C. Cir. 1994), where, FL Com
argues, the court refused to allow the Commission to use a non-
evidentiary ruling when there were material facts at issue.
Reply Comments
CCEM responds that EEI and others confuse the obligations of a
common carrier with the duty of public utilities not to unduly
discriminate. It says that AGD supports the Commission's authority
because the legislative history of the FPA and the NGA are similar with
respect to common carriage. According to CCEM, early versions of both
statutes would have made the regulated industries operate as common
carriers (citing Otter Tail, the legislative history of the FPA, the
legislative history of the Public Utility Holding Company Act, and the
legislative history of the Mineral Leasing Act), but that Congress
chose not to impose the common carrier obligations.
CCEM also says that the duties the Commission imposed on the gas
industry and those in the NOPR are not common carriage in any event.
According to CCEM, a common carrier must carry all goods offered
(citing Am. Trucking Assoc. v. Atchison, T. & S.F. Ry. Co., 387 U.S.
397, 406 (1967)). Finally, CCEM cites Stephenson v. Binford, 287 U.S.
251, 265-66 (1932), where the Supreme Court held that obligations that
are typical of common carriers can be imposed on contract motor
carriers.
CCEM further disagrees with EEI's argument that the enactment of
section 211 was a disavowal of any other Commission authority to order
transmission.
ELCON also disagrees with EEI's claim that the Energy Policy Act
undermines the Commission's pre-existing section 205 and 206 authority.
It states that the savings clause in section 212(e) of the FPA, as
amended, explicitly expresses Congress' intention not to undermine the
Commission's pre-existing authority and that the legislative history
contains nothing to suggest otherwise.
Similarly, in response to those who argue that section 211 is the
only source of authority for the Commission to order transmission, NIEP
argues that sections 211 and 212 serve purposes different from section
206. It says that the Commission's authority to order transmission in
the ``public interest'' under sections 211 and 212 is not synonymous
with its authority to order transmission as a remedy for undue
discrimination under section 206; the two standards are complementary
but distinct:
Although broadly applicable, the Commission's ability to order
wheeling under sections 211 and 212 is carefully limited by a number
of procedural provisions. Foremost among these is the requirement
that the wheeling may be ordered only upon a specific application
for transmission services. FERC's authority to act in the public
interest is thus confined to the individual case.
By contrast, FERC's remedial powers under Section 206 can be
exercised upon a finding of unjust, unreasonable or unduly
discriminatory or preferential practices. Once that finding has been
made, however, the form and substance of the remedy is left entirely
to the FERC's discretion. If FERC deems it necessary, FERC may adopt
generally applicable rules or practices as a countermeasure to
discriminatory acts, including ordering utilities to file generally
applicable transmission tariffs.\227\
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\227\ NIEP Reply Comments at 8.
NIEP also points out that the legislative history does not address
the Commission's authority to order transmission as a remedy for undue
discrimination. It challenges the
[[Page 21564]]
interpretation of the legislative history advanced by some
commenters.228
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\228\ NIEP explains that
(W)hile much has been made of the Senate report accompanying
S.2114, which subsequently became part of PURPA in 1978, that report
does not illustrate an intent to limit FERC's authority to remedy
undue discrimination under section 206. That report characterizes
the Supreme Court's decision in Otter Tail as holding that ``the
Federal Power Act leaves open a gap in its failure to assign the FPC
general authority to order wheeling in this situation * * *.'' The
``situation'' to which the Report refers is not discrimination,
however. Instead, the statement appears to make reference to
circumstances in which general public interest concerns, such as
reliability, efficiency and competition, are at stake. Thus, Senate
Report 2114 is simply not a limitation on the Commission's remedial
powers under Sections 206.
NIEP Reply Comments at 8-9 (citations omitted).
---------------------------------------------------------------------------
Next, NIEP defends the Commission's proposed findings that there is
generally undue discrimination in the provision of transmission
service. It notes that when an agency acts on an industry-wide basis,
the agency does not have to make a finding as to each particular case.
Finally, NIEP responds to those who argue that AGD is not on point.
It notes that the AGD court discussed electric cases and emphasizes the
court's statement that the NGA ``fairly bristles with concern for undue
discrimination''--a statement that is equally true of the FPA.
TDU Systems responds to the argument that Otter Tail is a broad
constraint on the Commission's authority to order transmission.229
At issue in that case, it argues, was the reach of the Sherman Act, not
of FPA sections 205 and 206. Similarly, it argues, the Florida Power
case is not on point, and the court there specifically said that it was
not deciding whether the Commission could have ordered wheeling as a
remedy for anticompetitive activities. Moreover, TDU Systems asserts
that EEI's use of a quote from a single Senator should carry no weight,
since it is a well-established principle of statutory construction that
such statements have little value. Finally, it points out that the AGD
court itself did not view Otter Tail or other electric precedent as
forbidding the Commission to order wheeling as a remedy for undue
discrimination.
---------------------------------------------------------------------------
\229\ See also Entergy.
---------------------------------------------------------------------------
Entergy asserts that Congress's refusal to require utilities to
provide transmission as common carriers or whenever it is in the public
interest was merely a decision not to give the Commission general
authority to order wheeling, without regard to undue discrimination.
Thus, the Otter Tail language concerning the absence of a common
carrier requirement does not demonstrate that Congress meant to limit
the Commission's authority to remedy undue discrimination.
ELCON disputes EEI's reading of NYSEG, noting that the NYSEG court
explicitly stated:
Nor do we suggest that the Commission is powerless to review a
wheeling agreement under section 206 without following the
requirements of sections 211 and 212.\230\)
---------------------------------------------------------------------------
\230\ ELCON Initial Comments at 7 (quoting NYSEG at 403).
TAPS discusses numerous cases, including the primary cases relied
upon by the Commission, and disposes of NYSEG by stating that it is no
longer good law, if it ever was.
Commission Conclusion
There can be no question that the Commission has the authority to
remedy undue discrimination. Sections 205 and 206 of the FPA mandate
that we ensure that, with respect to any transmission in interstate
commerce or any sale of electric energy for resale in interstate
commerce by a public utility, no person is subject to any undue
prejudice or disadvantage. Under these sections, we must determine
whether any rule, regulation, practice, or contract affecting rates for
such transmission or sale for resale is unduly discriminatory or
preferential, and we must disapprove those contracts and practices that
do not meet this standard. Our discretion is at its zenith in
fashioning remedies for undue discrimination.231
---------------------------------------------------------------------------
\231\ See, e.g.,- Niagara Mohawk Power Corporation v. FPC, 379
F.2d 153, 159 (D.C. Cir. 1967).
---------------------------------------------------------------------------
Some commenters, however, challenge our authority to order
industry-wide non-discriminatory open access as a remedy for the undue
discrimination we have found in the industry. As summarized above, they
essentially assert that we are prohibited by court precedent, the
legislative history of the FPA, and sections 211 and 212 of the FPA
from ordering wheeling as a remedy for undue discrimination. We
disagree and conclude that we have the authority--indeed, a
responsibility--to require non-discriminatory open access transmission
as a remedy for undue discrimination.
AGD and Legislative History
The court decision in Associated Gas Distributors v. FERC provides
powerful support for our ability to order industry-wide non-
discriminatory open access transmission in the electric industry as a
remedy for undue discrimination. As discussed in detail above, AGD,
which is the only decision to have addressed the Commission's authority
to remedy undue discrimination by requiring open access, upheld our
authority under section 5 of the NGA (the parallel to section 206 of
the FPA) to require open access in the natural gas industry. The
rationale supplied by the AGD court applies equally to the FPA and our
responsibility to eliminate undue discrimination in the electric
industry.
Those who challenge the Commission's legal authority to remedy
undue discrimination face the same difficulty that parties faced in
seeking to overturn open access in the natural gas industry--they ``can
point to no language in the (FPA) barring the Commission from imposing
common carrier status on (public utilities), and certainly none barring
it from imposing upon the (public utilities) a specific duty that
happens to be a typical or even core component of such status.'' \232\
Instead, as was unsuccessfully attempted in the AGD proceeding, they
seek to overcome the statutory silence primarily by means of
legislative history. However, as the AGD court explained, legislative
history is not even relevant, because
\232\ AGD, 824 F.2d at 997.
---------------------------------------------------------------------------
courts have no authority to enforce principles gleaned solely from
legislative history that has no statutory reference point.\233\
\233\ Id. (quoting IBEW, Local No. 474 v. NLRB, 814 F.2d 697,
712 (D.C. Cir. 1987) (emphasis deleted by court from original)).
---------------------------------------------------------------------------
Here, as the court found with respect to the NGA, the legislative
history of the FPA ``provides strong support only for the point that
Congress declined itself to impose common carrier status on (public
utilities) * * * It affords weak--almost invisible--support for the
idea that the Commission could under no circumstances whatsoever impose
obligations encompassing the core of a common carriage duty.'' \234\
---------------------------------------------------------------------------
\234\ Id. (emphasis added).
---------------------------------------------------------------------------
Commenters focus on the following statement in the AGD decision to
support the argument that, because Congress did not expressly reject
common carriage under the NGA, but did reject it under the FPA, a
different outcome in this proceeding is required:
we note that the legislative history of the two acts is, on this
point, materially different. In its deliberations on the bill that
ultimately emerged as the Federal Power Act, Congress considered and
rejected a provision that would have ``empowered the Federal Power
Commission to order wheeling if it found such action to be
`necessary or desirable in the public interest.' '' (citing Otter
Tail) (quoting S. 1725, 74th Cong., 1st Sess.). The evidence as to
the NGA (surveyed above) is less direct: it consists exclusively of
various occasions on which Congress did not adopt proposals actually
making the natural gas pipelines into common carriers.\235\
---------------------------------------------------------------------------
\235\ Id. at 998-99.
[[Page 21565]]
---------------------------------------------------------------------------
The above statement, however, does not preclude the AGD court's
decision on our broad authority to remedy undue discrimination in the
gas industry from applying equally in the electric industry. Clearly,
the court did not say that. As discussed below, we believe the
statement focuses on a distinction in the legislative histories that is
not meaningful.
First, whether or not a material difference exists in the
respective legislative histories of the NGA and FPA, the fact remains
that the crucial findings of the AGD court were that: (1) ``Congress
declined itself to impose common carrier status'' (emphasis added) and
(2) there is no ``support for the idea that the Commission could under
no circumstances whatsoever impose obligations encompassing the core of
a common carriage duty.'' \236\ These findings apply equally to the
FPA. Simply stated, statutory silence cannot be overcome by means of
legislative history--even if the legislative history in fact indicated
that Congress ``rejected'' legislative imposition of common carrier
status under the FPA, but ``did not adopt'' it under the NGA. In either
event, nothing in the statute or legislative history suggests that
Congress concluded that the Commission could under no circumstances
impose open access as a remedy to undue discrimination.
---------------------------------------------------------------------------
\236\ Id. at 997. We also note that the contract carriage
obligation we are imposing is easily distinguished from the common
carrier obligation Congress chose not to adopt. As discussed infra,
the common carrier provisions rejected by Congress would have
required transmission for ``any person'' upon reasonable request.
This would have included retail purchasers.
---------------------------------------------------------------------------
Moreover, the legislative history of the bills containing the FPA
and the NGA, taken as a whole, suggests that the distinction drawn in
AGD between the legislative histories of the NGA and the FPA is not
meaningful. The legislation that was to become the FPA originally
included provisions regulating both electric power and natural gas. As
originally proposed, the legislation contained identical common
carriage language for both public utilities and natural gas pipelines.
With respect to the FPA, the Supreme Court explained in Otter Tail
that
(a)s originally conceived, Part II would have included a ``common
carrier'' provision making it ``the duty of every public utility to
* * * transmit energy for any person upon reasonable request * *
*.'' In addition, it would have empowered the Federal Power
Commission to order wheeling if it found such action to be
``necessary or desirable in the public interest.'' H.R. 5423, 74th
Cong., 1st Sess.; S. 1725, 74th Cong. 1st Sess. These provisions
were eliminated to preserve ``the voluntary action of the
utilities.'' S.Rep. No. 621, 74th Cong., 1st Sess., 19.\237\
\237\ Otter Tail, 410 U.S. at 374.
---------------------------------------------------------------------------
The language paraphrased by the Supreme Court was from Title II of the
initial bill proposing the Public Utility Holding Company Act. The
entire sections from which the paraphrased language came are as
follows:
SEC. 202. (a) It shall be the duty of every public utility to
furnish energy to, exchange energy with, and transmit energy for any
person upon reasonable request therefor; and to furnish and maintain
such services and facilities as shall promote the safety, comfort,
and convenience of all its customers, employees, and the public, and
shall be in all respects adequate, efficient, and reasonable.
* * *
SEC. 203. (b) Whenever the Commission after notice and
opportunity for hearing finds such action necessary or desirable in
the public interest, it may by order direct a public utility to make
additions, extensions, repairs, or improvements to or changes in its
facilities, to establish physical connection with the facilities of
one or more other persons, to permit the use of its facilities by
one or more other persons, or to utilize the facilities of, sell
energy to, purchase energy from, transmit energy for, or exchange
energy with, one or more other persons. Where any such order affects
two or more persons, the Commission may prescribe the terms and
conditions of the arrangement to be made between such persons,
including the apportionment of cost between them and the
compensation or reimbursement reasonably due to any of them.\238\
\238\ H.R. 5423, 74th Cong., 1st Sess., 32 (emphasis added).
---------------------------------------------------------------------------
This initial
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
bill proposing the Public Utility Holding Company Act
also included a Title III that was intended to regulate the
transmission and sale of natural gas. Sections 303(a) and 304 of Title
III included the identical common carrier language paraphrased by the
Supreme Court and included in sections 202(a) and 203(b) of Title
II.\239\ After further deliberations, Congress rejected the above-
quoted language in Title II and eventually adopted a Title II that did
not include any common carrier language. On the other hand, Title III
(addressing regulation of natural gas) was not reported out of
committee, but reemerged in the next year.\240\ The bill that reemerged
did not contain the common carrier language that was in the original
Title III. However, as Congress had just debated the common carrier
issue in enacting electric power regulation, it is not surprising that
Congress did not engage in debating the very same issue in enacting
natural gas regulation.
---------------------------------------------------------------------------
\239\ Id. at 44.
\240\ In the debate on the subsequent bill to regulate natural
gas, Congressman Cole explained:
Mr. Chairman, the House should realize that the measure we are
dealing with today is of extreme importance, more so than the
attendance and the time taken in the discussion would seem to
indicate. It is the culmination of one of the most far-reaching,
intensive studies of the Federal Trade Commission I assume that that
Commission ever conducted, and last year found a place in not
identical language but very similar in the Rayburn bill, the famous
holding-company bill, as part 3 thereof. Our committee eliminated
part 3, as members will recall, and saved it for a separate measure
reported out as it was last year, which was not considered by the
House, but is here today in improved form.
81 Cong. Rec. H6724 (daily ed. July 1, 1937).
---------------------------------------------------------------------------
Because of the timing of the legislation involving the FPA and the
NGA and the logical nexus between the two acts, we conclude that there
is in fact no material difference as to this issue in the legislative
histories of the two acts. Both initially included identical common
carrier language, and the language was removed from both. As to both
acts, Congress chose not to impose common carrier obligations on the
electric or natural gas industries, but gave the Commission the
authority and responsibility to eliminate undue discrimination in both
industries. Consequently, as open access was found to be a proper
remedy for undue discrimination in the natural gas industry, it is also
a proper remedy for undue discrimination in the electric industry.
As the AGD court noted with respect to the Commission's powers and
duties under the NGA, Congress explicitly gave the Commission the
authority to eradicate undue discrimination under the FPA. That
explicit power and duty provided by Congress cannot be invalidated
solely on the ground that Congress chose not to impose statutory common
carrier status on public utilities or did not explicitly authorize the
Commission to do so.241 As the AGD court explained, this would
``turn [] statutory construction upside down, letting the failure to
grant a general power prevail over the affirmative grant of a specific
one.'' 242
---------------------------------------------------------------------------
\241\ AGD, 824 F.2d at 998.
\242\ Id.
---------------------------------------------------------------------------
Other Case Law
A number of commenters argue that the Commission misinterpreted the
other cases discussed in the NOPR with respect to our authority to
order non-discriminatory open access transmission. We disagree. As
demonstrated above, not one of the cases put forth by commenters holds
that we cannot remedy undue discrimination by requiring public
[[Page 21566]]
utilities to provide non-discriminatory open access
transmission.243
---------------------------------------------------------------------------
\243\ See FERC Stats. & Regs. at 33,053-56. We further note that
the AGD court did not discuss the NYSEG decision at all. Indeed, the
NYSEG case did not involve any allegations of undue discrimination
and any discussion of section 206 by the court was dictum.
---------------------------------------------------------------------------
AGD is the only case in which a court specifically addressed our
authority to order open access transmission as a remedy for undue
discrimination. Its favorable finding with respect to our action under
section 5 of the NGA directly supports our ordering non-discriminatory
open access transmission under section 206 of the FPA.
Authority to Act by Rule
We disagree with those commenters that assert that we may find and
remedy undue discrimination only through case-by-case adjudications and
are prohibited from making a generic determination of undue
discrimination through a rulemaking. First, there is no question that
it is within our discretion whether we act through rule or through
case-by-case adjudications.244 The AGD court specifically rejected
a similar argument that the Commission erred in requiring open access
transportation tariffs without first finding that each individual
pipeline's rates were unlawful. The AGD court held that ``(t)he
Commission is not required to make individual findings if it exercises
its Sec. 5 authority by means of a generic rule.'' 245
---------------------------------------------------------------------------
\244\ See, e.g., NLRB v. Bell Aerospace Company, 416 U.S. 267,
293 (1974) (citing SEC v. Chenery Corporation, 332 U.S. 194, 202-03
(1947). See also Heckler v. Campbell, 461 U.S. 458, 467 (1983) (even
where enabling statute requires a hearing to be held, agency may
rely on its rulemaking authority); Panhandle Eastern Pipeline
Company v. FERC, 907 F.2d 185, 187-88 (D.C. Cir. 1990). Under
section 403 of the DOE Act, 42 U.S.C. 7173, the Commission is
authorized at its discretion to initiate rulemaking proceedings.
\245\ AGD, 824 F.2d at 1008.
---------------------------------------------------------------------------
We have identified a fundamental generic problem in the electric
industry: owners, controllers and operators of monopoly transmission
facilities that also own power generation facilities have the incentive
to engage, and have engaged, in unduly discriminatory practices in the
provision of transmission services by denying to third parties
transmission services that are comparable to the transmission services
that they are providing, or are capable of providing, for their own
power sales and purchases. These practices drive up the price of
electricity and hurt consumers. Furthermore, the incentive to engage in
such practices is increasing significantly as competitive pressures
grow in the industry. It is within our discretion to conclude that a
generic rulemaking, not case-by-case adjudications, is the most
efficient approach to take to resolve the industry-wide problem facing
us.
b. Undue Discrimination/Anticompetitive Effects
Initial Comments
A number of commenters allege that the Commission has failed to
meet its burden of proving industry-wide discrimination.246 They
assert that the Commission has provided only a few unsubstantiated
allegations of discrimination, which do not represent the current
conditions in the electric industry, or that the Commission has not
shown that all electric utilities have unduly discriminated. Some
attack the NOPR's incorporation by reference of the unsubstantiated
allegations of discrimination set forth in a petition for rulemaking
filed on February 16, 1995 by the Coalition for a Competitive Electric
Market (CCEM).247
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\246\ E.g., EEI, Ohio Edison, PA Com, BG&E, NY Com, Minnesota
P&L, Carolina P&L.
\247\ E.g., EEI, BG&E.
---------------------------------------------------------------------------
EEI argues that the allegations of discrimination in the NOPR must
be considered in light of the fact that: (1) All tariffs currently on
file have been found by the Commission not to be discriminatory; (2)
more than 30 utilities have voluntarily filed open access tariffs,
which belies any assertion of widespread discrimination in the
industry; and (3) transmission disputes are rare, with only 19 section
211 proceedings having been filed in the last three years.248 EEI
concludes that the Commission's allegations of discrimination do not
rise to the level of ``extreme circumstances'' found by the court in
the natural gas industry in AGD.
---------------------------------------------------------------------------
\248\ See also Ohio Edison.
---------------------------------------------------------------------------
EEI adds that the Commission's proposal to act under section 206 is
itself discriminatory because it applies only to public utilities and
does not reach all transmission-owning utilities.249 If
reciprocity is designed to resolve this problem, EEI believes that
reciprocity should also be ``effective for public utilities.''
Furthermore, EEI argues that the failure of a public utility to provide
to others a service that it does not provide itself is not evidence of
discrimination, and that inclusion of such a provision actually results
in preferential treatment for transmission users.
---------------------------------------------------------------------------
\249\ See also SCE&G.
---------------------------------------------------------------------------
NE Public Power District alleges that the NOPR does not contain a
single reference to any actual discrimination or anticompetitive
conduct by any publicly owned utility.
Salt River asserts that the Commission is required to consider all
elements of an antitrust analysis before reaching a conclusion that
market power exists in the transmission system and that we have failed
to do so.250 It concludes that the NOPR ``constitutes an attempt
to legislate a remedy for an evil that has not been, and cannot be,
lawfully found to exist on a wholesale basis among utilities that own
and operate integrated generation and transmission systems.'' 251
---------------------------------------------------------------------------
\250\ Salt River Initial Comments at 5-6 (referencing an
attached legal memorandum of Donald A. Kaplan).
\251\ Salt River Initial Comments at 6.
---------------------------------------------------------------------------
PA Com argues that the Commission's request for examples of
discriminatory behavior is a ``tacit admission as to the paucity of
evidence of discriminatory practices by transmission owning
utilities.'' NY Com argues that the ``Commission's lack of a record
basis for its proposed findings is legally suspect because courts in
two cases have held that the Commission cannot proceed with open access
transmission tariffs absent record findings of specific anticompetitive
conduct.'' 252
---------------------------------------------------------------------------
\252\ NY Com Initial Comments at 16-18 (discussing FPL and
Cajun).
---------------------------------------------------------------------------
Finally, EEI claims that even if the Commission has proven its
allegations of discrimination, we have failed to meet the requirements
of section 206 of the FPA.253 According to EEI, the Commission
cannot find, without an adjudicatory hearing, that the rates on file
are unlawful and order replacement rates.254 The Commission's
proposed procedure would unlawfully place the burden of justifying
existing rates on the utilities.
---------------------------------------------------------------------------
\253\ See also Southern.
\254\ See also Southern.
---------------------------------------------------------------------------
Reply Comments
A number of commenters provide instances of discriminatory behavior
they have faced over the years. NCMPA describes difficulties it has
faced in dealing with CP&L, including a situation where CP&L allegedly
impeded NCMPA's use of transmission access through CP&L's control of
dispatching.255
---------------------------------------------------------------------------
\255\ We note that CP&L raised legal objections to our authority
to implement this rule.
---------------------------------------------------------------------------
AMP-Ohio alleges that Toledo Edison refused to transmit emergency
power on a buy-sell basis to certain AMP-Ohio members even though
Toledo Edison's system was not constrained. Instead, AMP-Ohio alleges,
Toledo Edison bought the power and resold it to AMP-Ohio at a higher
rate.
[[Page 21567]]
APPA challenges EEI's claim that there is no substantial evidence
of undue discrimination in transmission. It suggests that nineteen
instances of transmission disputes being filed since the Energy Policy
Act was enacted is ample evidence of undue discrimination. Moreover,
according to APPA, reported abuses are only the tip of the iceberg.
CCEM responds to the argument raised by EEI and others that there
is no showing of extreme circumstances of discrimination in the
electric industry such as the AGD court noted in the gas industry. It
says that these circumstances are present and gives numerous examples;
it does not identify the specific utilities because ``it is the
experience of * * * (our) members that nearly all transmission owners
retaliate * * *'' against anyone who complains. Moreover, in answer to
EEI's statement that transmission disputes are rare, CCEM states that
since most of the competition is in the short-term market, it has not
been worthwhile to file complaints. The examples provided by CCEM
include: (1) Refusal by a California public utility to offer firm
service; (2) refusal by control area utilities in Texas to offer
ancillary services to a power marketer, with the result that one of the
utilities won the bid, even though it did not have the lowest price;
(3) non-utilities in ERCOT being unable to compete to meet short-term
requests for economy energy because they were required to schedule by
noon of the preceding day, while utilities did not subject themselves
to such a scheduling requirement; (4) power pool or control area
information requirements, particularly in the northwest part of WSPP,
that force non-utilities to reveal commercially sensitive information;
the transportation operator has then revealed the information to its
own or its affiliate's sales arm, which ``steals'' the deal; (5) a
northeast power pool that refused to wheel out even though capacity was
available on the grounds that sending power out of the pool would drive
up prices in the pool (hoarding); (6) a power marketer that asked a
utility to provide transmission, whereupon the utility bought up
certain transmission capacity necessary for the marketer to reach its
buyer, thus blocking the path--this was possible because the utility
was able to locate the purchaser based on commercially sensitive
information the marketer had to give the utility when the marketer
asked for transmission; (7) a common contracting practice among
utilities restricting the use of interconnections to themselves,
particularly in the Southwest Power Pool, MAPP, and MAIN; (8) utilities
overstating the cost of improvements (gold-plating) and thus
discouraging service. CCEM also responds to each of EEI's criticisms of
CCEM's examples of undue discrimination submitted in its February 16,
1995 petition and argues that its examples of undue discrimination are
unrebutted.
Brownsville asserts that
while PUB [Brownsville] must pay multiple distance-based and
pancaked transmission rates to engage in transactions with the non-
ERCOT universe, El Paso Electric would have received transmission
payments from its merger partners while gaining free transmission
access to buy and sell within ERCOT. CSW presently walls other ERCOT
utilities off from participation in the Western Systems Power Pool,
while its ERCOT subsidiaries, CPL and WTU, share in the benefits of
their non-ERCOT affiliates' WSPP memberships via the preferential
terms of the CSW Operating Agreement. CSW treats its own inter-
affiliate central dispatch as having a higher priority than third-
party economy energy transactions, with the result that CPL not
infrequently crowds PUB out of the economy market. 256
\256\ Brownsville Reply Comments at 2-3 (emphasis in original).
---------------------------------------------------------------------------
Wisconsin Municipals states that its members have been fighting
transmission battles for years and sets forth five examples of the sort
of difficulties it has experienced in attempting to obtain transmission
rights. For example, it explains that Wisconsin public utilities have
resisted an effort by the state commission to achieve comparability of
use of transmission. Wisconsin Municipals also explains a situation
where ``if WPPI continued to purchase its power from WPSC, it would pay
WPSC $843,840 annually for transmission service: if it purchases power
off system from WP&L (one of WPSC's competitors), WPPI would pay WPSC
$1,774,224 for transmission service to the exact same load.''
TAPS sets forth additional examples of undue discrimination,
including refusals to wheel even in the face of Nuclear Regulatory
Commission (NRC) nuclear license conditions requiring wheeling, and
Northeast Utilities' refusal to provide transmission to a QF even
though it had indicated to the Commission that it would provide such
transmission in order to obtain Commission approval of its proposed
merger with Public Service Company of New Hampshire.
NIEP sets forth ten examples of undue discrimination that its
members have experienced in seeking access to transmission service at
reasonable terms and conditions.
Some commenters challenge these claims of undue discrimination. For
example, Carolina P&L responds to NCMPA #1's example of obstruction by
Duke in accommodating energy sales from the jointly owned Catawba
Plant. Carolina P&L explains that NCMPA #1's proposal ``would require
Duke to provide its own generation resources on behalf of NCMPA #1 in
order to support a bulk power sale when NCMPA #1's own resource
capacity and energy are not sufficient for the sale.'' Carolina P&L
argues that this is backstanding that goes beyond the scope of any
ancillary service the Commission has proposed and would be entirely
inappropriate ``to compel the Transmission Provider to sell power to
its Transmission Customer for resale on the bulk power market.''
Duke also responds to NCMPA #1's claim of discrimination and
asserts that NCMPA #1's claim is not relevant to the NOPR proceeding,
but is a specific contractual claim that should be pursued pursuant to
the terms of its contract.
Commission Conclusion
We conclude that unduly discriminatory and anticompetitive
practices exist today in the electric industry and, more importantly,
that such practices will increase as competitive pressures continue to
grow in the industry, unless the Commission acts now to prevent such
practices.257 It is in the economic self-interest of transmission
monopolists, particularly those with high-cost generation assets, to
deny transmission or to offer transmission on a basis that is inferior
to that which they provide themselves. The inherent characteristics of
monopolists make it inevitable that they will act in their own self-
interest to the detriment of others by refusing transmission and/or
providing inferior transmission to competitors in the bulk power
markets to favor their own generation, and it is our duty to eradicate
unduly discriminatory practices. As the AGD court stated: ``Agencies do
not need to conduct experiments in order to rely on the prediction that
an unsupported stone will fall.'' 258
---------------------------------------------------------------------------
\257\ While many public utilities have filed some form of open
access tariff (often in response to our proposed rule), we believe
that many of the remaining utilities will not voluntarily open their
systems absent a final rule. See also note 266.
\258\ AGD, 824 F.2d at 1008.
---------------------------------------------------------------------------
We set forth examples in the NOPR of undue discrimination that we
believe are occurring in the electric industry and invited commenters
to identify any discrimination that they may have experienced. In
response, commenters
[[Page 21568]]
presented numerous additional examples of undue discrimination, which
are summarized above, and we set forth below further examples of undue
discrimination that have been raised in cases before the Commission.
Many of the examples of discriminatory behavior that have been
brought to our attention do not name the specific utilities involved,
and many are allegations that are not proven. However, we do not
believe that this undermines our finding of unduly discriminatory
practices by transmission owners and controllers. We believe that it is
only natural that potential transmission customers with an interest in
participating in electric markets will be reluctant to name names for
fear of being shut out of those markets. CCEM, which identified a wide
array of discriminatory behavior its members have experienced,
explained that
(w)e do not identify the specific utilities in each example because
it is the experience of CCEM members that nearly all transmission
owners retaliate by cutting off all communications with anyone that
challenges or complains about the rates, terms or conditions at
which the owner offers access to its system. Inasmuch as most of the
competitive commerce in electric power today is in short-term
markets, it is typically not worth the effort of CCEM members or
other transmission-dependent entities to file a complaint with the
Commission's enforcement staff or in the courts in connection with a
transmission owner's discriminatory practices. The deal is lost well
before a complaint can be processed and ruled upon.\259\
\259\ CCEM Initial Comments at 18-19. See also NIEP Reply
Comments at 13 n.31.
---------------------------------------------------------------------------
Other examples of discriminatory behavior have also been raised in
proceedings before the Commission. As we explained in detail in the
NOPR, transmission-owning utilities have discriminated against others
seeking transmission access in a variety of ways, most often subtly and
indirectly.\260\ For example, delaying tactics have been used to
frustrate access. The history of Pacific Gas and Electric Company's
(PG&E) attempt to avoid its commitments made to the California owners
of the California-Oregon Transmission Project (COTP) is a prime
example. The owners had originally planned the COTP to have its
southern terminus at the Midway station with Southern California
Edison. PG&E convinced them to terminate the project instead at PG&E's
Tesla station and indicated that PG&E would provide transmission
service the rest of the way south to Midway. PG&E promised this service
in 1989 (in Principles). PG&E spent the next four years filing
substitute provisions for what it had promised in the Principles.\261\
Additional allegations of discriminatory behavior are set forth in
Appendix C, which includes allegations made under oath in proceedings
at the Commission and allegations made in pleadings and other documents
before the Commission.
---------------------------------------------------------------------------
\260\ FERC Stats. & Regs. at 33,072.
\261\ See Pacific Gas and Electric Company, 65 FERC para. 61,312
at 62,428-30 and n.22, remanded on other grounds, Pacific Gas &
Electric Company v. FERC, No. 94-70037 (9th Cir. June 23,
1994)(unpublished opinion), order on remand, 69 FERC 61,006 (1994).
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In addition, to date, the Commission has received 28 section 211
transmission requests.\262\ Applicants submit section 211 transmission
requests when the transmission provider refuses to provide the
requested transmission service. For example, American Municipal Power-
Ohio, Inc. (AMP-Ohio) requested Ohio Edison Company (Ohio Edison) to
establish additional delivery points to certain of AMP-Ohio's members
and to permit the addition of delivery points in the future upon AMP-
Ohio's request. Ohio Edison refused AMP-Ohio's request, claiming that
it was not a proper request under section 211 because it already
provided wholesale transmission to the municipal utilities at issue. In
a proposed order, the Commission disagreed with Ohio Edison and ordered
Ohio Edison to provide the requested additional delivery points and to
entertain future requests by AMP-Ohio for specific delivery
points.\263\
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\262\ A list of section 211 applications and the status of each
is attached as Appendix A.
\263\ American Municipal Power-Ohio, Inc. v. Ohio Edison
Company, 74 FERC para. 61,086 (1996).
---------------------------------------------------------------------------
Many of the examples of discriminatory actions we are seeing in the
electric industry are similar to those we saw in the gas industry.
Given our experience, we find that these examples of discriminatory
actions are credible and well-founded. Thus, we conclude that there is
more than sufficient reason to believe that transmission monopolists
currently engage in unduly discriminatory practices, and that they will
continue to engage in unduly discriminatory practices, unless we
fashion a remedy to eliminate their ability and incentive to do so. In
light of the competitive changes occurring in today's electric
industry, we believe that the only effective remedy is non-
discriminatory open access transmission, including functional
unbundling and OASIS requirements, and that it is within our statutory
authority to order that remedy.
Further, we disagree with the argument that we are limited to
applying a traditional antitrust analysis in determining whether market
power exists in the transmission system. While we must take antitrust
concerns into consideration in exercising our responsibilities under
the FPA, we are not an antitrust court, and our responsibilities are
not those of the Department of Justice.\264\ We have analyzed the
incentives and practices of monopoly transmission owners and
controllers in light of the statutory standards and directives of the
FPA and, based on our findings, have properly concluded that there is a
generic problem that must be remedied.
---------------------------------------------------------------------------
\264\ See, e.g., Gulf States Utilities Company v. FPC, 411 U.S.
747, 758-60 (1973); FPC v. Conway Corporation, 426 U.S. 271, 279
(1976); Northern Natural Gas Company v. FPC, 399 F.2d 953, 960 (D.C.
Cir. 1968).
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The Commission also recognizes, as some commenters suggest, that we
have, in the past, permitted utilities to file tariffs containing
restrictions on transmission service that we are now finding to be
unduly discriminatory in this rule and that we found unduly
discriminatory in cases since our decision in AEP. However, it is
entirely appropriate, and indeed necessary, that our application of the
FPA's undue discrimination standard evolve over time and adapt to the
changing circumstances in the industry. Our prior willingness to
tolerate the use of monopoly power over transmission to maintain and
aggregate the utility's market power over generation occurred in the
context of an industry structured largely as vertically integrated
regulated monopolies that supplied all facets of utility service--power
supply, transmission, and distribution--as a single monopoly service.
Competition generally was not meaningfully available as a means to
discipline prices and consumer interests were best served by improving
efficiencies of the integrated utilities, subject to cost-based
regulation.
Today, the circumstances of the industry are radically different.
As explained in detail in Section III, a series of significant
economic, regulatory, and technical changes in the power industry has
introduced the promise of competitively priced power supplies. The
profile of electric power suppliers has expanded to include not just
the power supply arms of traditional utilities, but also independent
power suppliers, affiliated utility power suppliers selling into
territories of other franchise utilities,
[[Page 21569]]
and power marketers.\265\ This offers the promise of an increasingly
competitive commodity market in electric power, in which significant
benefits to consumers can be achieved. In the context of an emerging
competitive market in generation, discriminatory practices that once
did not constitute undue discrimination must be reviewed to determine
whether they are being used to prevent the benefits of competition in
generation from being achieved. Here we find conclusively that they
are, and use our remedial authority to ensure that they can no longer
occur.\266\
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\265\ We note that there are now 14 power marketers that are
affiliated with public utilities.
\266\ We take note of EEI's comments that, at the time of the
comments, 30 utilities had filed open access tariffs. They argue,
therefore, that the rule is unnecessary. Since their comment was
filed, the number of utilities filing some form of an open access
tariff has risen to 106. However, while some of these tariffs are
based on the NOPR pro forma tariffs, many of these tariffs fall
significantly short of the tariff requirements of both the NOPR and
this Rule. Even if the tariffs met these requirements, the Rule is
still needed to complete the task of eliminating undue
discrimination by all public utilities and assuring, to the extent
possible, a nationwide open access transmission grid. Indeed, a
number of these tariffs were filed for the purposes of securing
authority to market power competitively. This underscores markedly
our fundamental conclusion that prior practices of using monopoly
power over transmission to preserve market power over electricity
sales has no place in today's industry and must be eliminated to get
the benefits of competition to the customers we are required to
protect under the FPA.
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c. Section 211
Comments
Various commenters contend that the enactment of section 211 in
essence either removed any authority the Commission might have had
under sections 205 and 206 or demonstrates that Congress did not
believe the Commission could order wheeling under those provisions.
These commenters assert that the legislative history of the FPA
indicates that Congress specifically rejected giving the Commission
authority to order wheeling under any circumstances.\267\ They further
contend that the legislative history of section 211 demonstrates that
Congress viewed the authority it granted in section 211 as a strictly
limited and entirely new authority for the Commission.\268\
Specifically, EEI states that the legislative history of the Energy
Policy Act confirms that the expanded authority provided under section
211 was not intended to grant the Commission blanket authority to order
wheeling, even as a remedy for anticompetitive conduct. Similarly,
Utilities For Improved Transition argues that the legislative history
shows that Congress specifically intended to preclude the Commission
from ordering tariffs of general applicability under any circumstances.
In addition, EEI points to testimony provided by a Commission staff
witness before the Subcommittee on Energy and Power of the House
Committee on Energy and Commerce in which EEI claims that ``she
suggested that an affirmative statement that the Commission had the
power to require wheeling on its own motion should be included,
possibly in section 211.'' EEI maintains that such suggestion was
rejected by Congress in favor of allowing the Commission to order
wheeling only upon application.
---------------------------------------------------------------------------
\267\ E.g., EEI, VA Com, Ohio Edison Southern, Utilities For
Improved Transition, BG&E.
\268\ See also NM Com.
---------------------------------------------------------------------------
Detroit Edison, asserting that Cajun stands for the proposition
that the agency must follow Congressionally mandated procedures, claims
that the Commission can order transmission only after going through the
procedures of section 211. Detroit Edison also argues that the
Commission should incorporate into the final rule the various
safeguards of section 211, such as the requirement that the utility
receive prior notice, the requirement that transmission service be in
the public interest, and the requirement that existing service not be
displaced. FL Com further asserts that it was Congressional intent in
the Energy Policy Act for wheeling to be ordered on a case-by-case
basis pursuant to section 211.\269\
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\269\ See also Salt River. Moreover, FL Com states that the
Commission should modify its hearing process to better accommodate
state PUC participation by: (1) Holding hearings in the affected
state; (2) teleconferencing; (3) making free transcripts available
to states; and (4) substantially deferring to a state when the state
commission has held a hearing on an issue in the case.
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EEI argues that the enactment of section 211 eliminated any
authority the Commission had under sections 205 and 206 to order
wheeling as a remedy for undue discrimination. It alleges that the
Commission failed to discuss the NYSEG case concerning the relationship
between section 211 and sections 205 and 206 in any meaningful way.
According to EEI, the NYSEG court concluded that section 211 ``was the
only appropriate vehicle under which the Commission could order NYSEG
to wheel power for the municipality.'' 270 EEI further resorts to
canons of statutory construction to conclude that ``section 211 must be
given effect as the more specific provision and must be interpreted to
limit the scope of sections 205 and 206.'' 271 In addition, EEI
asserts that ``Congress had an opportunity to reject the NYSEG court's
interpretation of the scope of sections 205, 206 and 211, but instead
amended section 211 in a manner that is consistent with the view that
mandatory wheeling is to be governed exclusively by section 211.''
Dayton P&L raises similar arguments. It notes the savings provision in
section 212(e), but says that Congress ``would have been more specific
if it understood that the Commission already had the authority to order
wheeling under FPA sections 205 and 206. * * *'' 272
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\270\ EEI quoted the following language from NYSEG:
Nor do we suggest that the Commission is powerless to review a
wheeling agreement under section 206 without following the
requirements of sections 211 and 212. If, after a hearing as
required by section 206, the Commission determines that a particular
rate, charge or condition is unreasonable, it can order a
modification. But where, as here, the modification amounts to an
order requiring wheeling, it must be preceded also by determination
in accordance with sections 211 and 212. Simply put, we will not
allow the Commission to do indirectly without compliance with the
statutory prerequisites, what it could not do directly without such
compliance. (citing Richmond Power & Light).
\271\ See also VA Com.
\272\ See also Carolina P&L.
---------------------------------------------------------------------------
Associated EC argues that the NOPR appears to exceed the
Commission's authority in that it proposes that ``wholesale buyers and
sellers have 'equal access to the transmission grid.' '' It asserts
that ``Section 211(a), however, makes mandatory transmission service
available only to '[a]ny electric utility, Federal power marketing
agency or any other person generating electric energy for sale for
resale.' '' 273
---------------------------------------------------------------------------
\273\ This argument is puzzling. First, section 211 does not
control to whom access must be provided under sections 205 and 206.
However, even if it did, Associated EC appears to misconstrue
eligibility under section 211. An electric utility as defined in the
FPA is any person or State agency (including any municipality) which
sells electric energy. The definition does not say that electric
energy must be re-sold at wholesale. Thus, an electric utility could
be a wholesale buyer of transmission used to transmit energy for
sale at either wholesale or retail.
---------------------------------------------------------------------------
NE Public Power District argues that sections 211 and 212 of the
FPA appear clearly to contemplate a case-by-case approach.274 NE
Public Power District adds that if the Commission believes sections 211
and 212 are inconsistent with the public interest, it can ask Congress
to modify those provisions. Allegheny adds that the Commission can
order wheeling only under sections 211 and 212 on a company-specific
basis and can use sections 205 and 206 only to evaluate the
reasonableness of terms and conditions of voluntarily filed agreements
or tariffs by public utilities.
---------------------------------------------------------------------------
\274\ See also Allegheny.
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Utilities For Improved Transition also claims that sections 211 and
212 override any authority the Commission might have had under sections
205 and
[[Page 21570]]
206 to order industry-wide open access. It cites the savings clause in
section 212(e) of the FPA as limiting the Commission's authority to
order transmission.275 Utilities For Improved Transition argues at
some length that the NOPR does not meet the procedural and substantive
standards of sections 211 and 212. It goes on to cite various passages
from the legislative history of the Energy Policy Act as supporting the
view that Congress intended to eliminate the Commission's authority to
order industry-wide open access as a remedy for undue discrimination.
According to Utilities For Improved Transition, these passages
``unmistakably show a clear legislative intent to preclude the
mandatory transmission that the Commission attempts here * * *.''
---------------------------------------------------------------------------
\275\ It states that
Section 212(e), however, provides that Sections 211 and 212
limit or impair the Commission's authority under ``other provisions
of law'' (a phrase including, obviously, Sections 205 and 206). On
the face of the statute--we say again for emphasis: on the face of
the statute--the Commission therefore does not have the authority to
order transmission service outside the provisions of Sections 211
and 212.
Utilities For Improved Transition Initial Comments at 51
(emphasis in original).
---------------------------------------------------------------------------
Commission Conclusion
We disagree with those commenters that argue that the Energy Policy
Act either eliminates our authority under section 206 to remedy undue
discrimination by requiring non-discriminatory open access transmission
or demonstrates that we never had any such authority. Nothing in
sections 211 and 212 or in the legislative history of these sections
indicates that Congress intended to eliminate the Commission's other,
broader authorities under the FPA. Indeed, section 212(e) specifically
provides:
SAVINGS PROVISIONS.--(1) No provision of section 210, 211, 214,
or this section shall be treated as requiring any person to utilize
the authority of any such section in lieu of any other authority of
law. Except as provided in section 210, 211, 214, or this section,
such sections shall not be construed as limiting or impairing any
authority of the Commission under any other provision of
law.276
\276\ 16 U.S.C 824k (emphasis added).
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Utilities For Improved Transition's argument that the ``Except as
provided'' clause limits or impairs the Commission's authority to order
transmission service under sections 205 and 206 would make the savings
provision meaningless. Moreover, such a reading would be entirely at
odds with the underlying purposes of the Energy Policy Act. It would be
ironic indeed to interpret the Energy Policy Act as eliminating our
long-standing, broad authority to remedy undue discrimination, given
the pro-competitive purpose of the statute.
The legislative history also provides no support for the arguments
that sections 211 and 212 remove or prove the non-existence of the
Commission's authority to remedy undue discrimination by requiring non-
discriminatory open access transmission. In fact, virtually every bit
of legislative history raised by commenters opposing the NOPR consists
of various statements by Senator Wallop, an opponent of expanding
transmission access under sections 211 and 212.277 Such
legislative history provides no insight into the meaning of a statute
and is given little or no weight by the courts.278
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\277\ In discussing the electricity provisions of the Energy
Policy Act, Senator Wallop declared:
It would be a mistake to take the presence of transmission
access provisions in the Conference Report as a sign of change in
position on my part or that of the Senate. I would have strongly
preferred PUHCA reform without any transmission access provisions,
as was the Senate position. However, in order to obtain the very
significant benefits of PUHCA reform contained in the Senate bill,
it was necessary to accept some of the House transmission access
provisions.
138 Cong. Rec. S17615 (daily ed. October 8, 1992).
\278\ See, e.g., Shell Oil Company v. Iowa Department of
Revenue, 488 U.S. 19, 29 (1988) (Shell). In Shell, the Court
declared:
This Court does not usually accord much weight to the statements
of a bill's opponents. ``[T]he fears and doubts of the opposition
are no authoritative guide to the construction of legislation.''
Gulf Offshore Co. v. Mobil Oil Corp., 453 U.S. 473, 483 (1981)
(quoting Schwegmann Bros. v. Calvert Distillers Corp., 341 U.S. 384,
394 (1951).
See also Sutherland Statutory Construction Sec. 48.16 at 366.
---------------------------------------------------------------------------
The only other legislative history that commenters put forth is the
testimony of a Commission staff witness, in 1992 hearings before the
Subcommittee on Energy and Power of the House Committee on Energy and
Commerce. According to EEI, the witness indicated that an affirmative
statement that the Commission could require wheeling on its own motion
``would be needed [in the Energy Policy Act] if Congress intends for
the Commission to be able to deal with transmission on its own motion
and thereby go further than simply dealing with industry proposals.''
EEI claims that this statement demonstrates that the expanded authority
in the Energy Policy Act ``was not intended to grant the Commission
blanket authority to order wheeling, even as a remedy for
anticompetitive conduct.''
EEI's argument is misleading and disingenuous. It takes the
witness's statements out of context, ignoring attendant testimony that
``there are strong legal arguments that the Commission's obligation to
protect against undue discrimination carries with it the authority to
impose transmission requirements as a remedy for undue preference or
discrimination,'' and the extensive legal argument, included in her
testimony, in favor of that position--an argument that closely
parallels the legal argument the Commission is relying on in this
proceeding.279 Indeed, in the face of such explicit testimony from
the staff of the agency required to implement the statute, had Congress
intended to limit the Commission's remedial authority under section 206
when it amended section 211, we believe it would have explicitly done
so in the language of the statute itself, or at least have indicated
its intent to do so in the Conference Report on the Energy Policy
Act.280
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\279\ Hearings on H.R. 1301, H.R. 1543, and H.R. 2224 before the
Subcommittee on Energy and Power of the House Committee on Energy
and Commerce, 102d Cong., 1st Sess. (May 1,2 and June 26, 1991),
Statement of Cynthia A. Marlette, Associate General Counsel, Federal
Energy Regulatory Commission, Report No. 102-60 at 60 and 61-70. See
also id. at 106 (``I believe that we have substantial authority
under the existing case law to mandate access where necessary to
remedy anticompetitive effects.'').
\280\ At the time Congress enacted amendments to FPA section
211, it was well aware that the Commission had unexplored
authorities under sections 205 and 206 of the FPA to compel
wheeling. The only explicit limitations it chose to impose on the
Commission's wheeling authorities were those contained in sections
212(g) and (h), which provide that no order ``under this Act'' may
be inconsistent with any State law governing retail marketing areas
of electric utilities (section 212(g)), or be conditioned upon or
require the transmission of electric energy directly to an ultimate
consumer (section 212(h)).
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C. Comparability
1. Eligibility to Receive Non-Discriminatory Open Access Transmission
In the NOPR, the Commission proposed to define who is eligible to
receive service under a non-discriminatory open access tariff as
follows:
A non-discriminatory open-access tariff must be available to any
entity that can request transmission services under section
211.281
\281\ FERC Stats. & Regs. para. 32,514 at 33,083 (footnote
omitted).
---------------------------------------------------------------------------
The Commission further explained that ``[u]nder section 211, any
electric utility, Federal power marketing agency, or any other person
generating electric energy for sale for resale may request transmission
services under section 211.'' 282
---------------------------------------------------------------------------
\282\ Id. at 33,083 n.195.
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[[Page 21571]]
Comments
PSNM believes that the NOPR properly defined customer eligibility.
NIEP, on the other hand, believes that the proposed definition is too
limited. It argues that the Commission should require public utilities
to make transmission service available to all entities engaged in
wholesale purchases or sales of power, not just to those ``generating''
power. Utility Working Group requests that the Commission clarify that
eligibility is dependent not only on being the type of entity set forth
in section 211, but on meeting the requirements of section 212(h)
(Prohibition on Mandatory Retail Wheeling and Sham Wholesale
Transactions) as well.283
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\283\ Section 212(h) (Prohibition on Mandatory Retail Wheeling
and Sham Wholesale Transactions).
---------------------------------------------------------------------------
We also received several comments related to the applicability of
the rule to foreign entities. Canada states that the requirements for
comparability and reciprocity should be implemented in a flexible
manner to permit Canadian utilities to have fair and competitive access
in the U.S. electricity market. Maritime requests that the Commission
require Canadian utilities who wish to participate in the U.S. market
to offer other utilities the same privileges they receive in the United
States. Southwestern argues that transmission to a foreign country is
in interstate commerce and that a utility should therefore accommodate
this type of transmission request under its open access tariff. El Paso
argues that the Commission does not have the authority to condition
access to foreign countries, but states that if the Commission
nevertheless exercises such authority it should do so on a case-by-case
basis. Destec asserts that
the posturing of Ontario Hydro before U.S. regulators pleading for
open access and non-discriminatory transmission treatment--even for
extra-territorial entities, should be met with a strong reply that
such provisions should also be afforded transmission dependent
entities on the Canadian side of the border. Ontario Hydro's
aggressive pursuit of U.S. market opportunities while simultaneously
blocking competitors through the control of their transmission
assets can not be ignored.
Commission Conclusion
In the Final Rule pro forma tariff the Commission has modified the
definition of ``eligible customer'' to address concerns that in some
respects the NOPR definition was too limited and in other respects it
was too broad. This includes amended language to clarify that any
entity engaged in wholesale purchases or sales of energy, not just
those ``generating'' electric power, is eligible. It also includes
clarification that entities that would violate section 212(h) of the
FPA (prohibition on Commission-mandated wheeling directly to an
ultimate consumer and sham wholesale transactions) are not eligible.
The language also has been modified to provide that foreign entities
that otherwise meet the eligibility criteria may obtain transmission
services. Further, it has been modified to provide for service to
retail customers in circumstances that do not violate FPA section
212(h).284
---------------------------------------------------------------------------
\284\ We emphasize that any transmission customer must follow
prudent utility practices so as to assure reliability.
---------------------------------------------------------------------------
Persons that would be eligible section 211 applicants also would be
eligible under the open access tariffs. Section 211 applicants may be
any electric utility, Federal power marketing agency, or any other
person generating electric energy for sale for resale.
Section 3(22) of the FPA, as amended by the Energy Policy Act,
defines ``electric utility'' to mean
any person or State agency (including any municipality) which sells
electric energy; such term includes the Tennessee Valley Authority,
but does not include any Federal power marketing agency.
Thus, as we have previously noted, municipal utilities are electric
utilities simply by the terms of the statute.285 In addition, we
have also found that cooperatives and marketers are electric utilities
as defined in the FPA.286 Other entities that fall within the
definition include IOUs, IPPs, APPs, and QFs that sell electric energy.
---------------------------------------------------------------------------
\285\ New Reporting Requirement Implementing Section 213(b) of
the Federal Power Act and Supporting Expanded Regulatory
Responsibility Under the Energy Policy Act of 1992, and conforming
and Other Changes to Form No. FERC-714, Order No. 558-A, 65 FERC
para. 61,324 at 62,451 n.12 (1993).
\286\ Order No. 558, FERC Stats. & Regs. para. 30,980 at 30,895-
96, reh'g denied, 65 FERC para. 61,324 (1993) (cooperatives are
electric utilities); AES Power, Inc., 69 FERC para. 61,345 at 62,297
(1995) (power marketer is an electric utility, i.e., a person
``which sells electric energy'').
---------------------------------------------------------------------------
We do not believe that entities that engage solely in brokering
should be eligible. Such brokers do not take title to electricity and
therefore do not engage in the sale of electric energy; nor do they
generate electric energy for sale for resale.287 Although such
brokers are not eligible under the tariffs, they will be able to
arrange deals because they will have access to the OASIS of all public
utilities and will be able to solicit information from the relevant
transmission service providers under the terms of the applicable
tariffs.
---------------------------------------------------------------------------
\287\ See, e.g., Citizens Energy Corporation, 35 FERC para.
61,198 at 61,452-53 (1986).
---------------------------------------------------------------------------
We clarify that foreign entities that otherwise meet the
eligibility criteria must be eligible to receive service under the non-
discriminatory open access transmission tariffs.288 We are making
this determination pursuant to our authority under section 206 of the
FPA to remedy undue discrimination. As we explained in the NOPR, market
power through the control of transmission can be used discriminatorily
to block competition. Customers in the United States should not be
denied access to cheaper supplies of electric energy, whether such
electric energy is from a domestic source or a foreign source. By
making non-discriminatory access available to foreign entities that
otherwise meet the eligibility criteria, we are assuring that customers
in the United States have access to as many potential suppliers as
possible. This should result in increased competition and lead to
customers paying the lowest possible prices for their electric energy
needs. To the extent that such an entity obtains access, however, we
emphasize that it would be subject to all of the terms and conditions
of the applicable open access tariff, including the requirement that it
provide reciprocal service.
---------------------------------------------------------------------------
\288\ In making this determination, we are not deciding whether
these entities are eligible entities under section 211(a) of the
FPA.
---------------------------------------------------------------------------
Finally, we have reconsidered our NOPR position that would have
limited eligibility to wholesale transmission customers. As we
explained in the NOPR, the Commission's jurisdiction extends to all
unbundled transmission in interstate commerce by public utilities. It
is irrelevant to the Commission's jurisdiction whether the customer
receiving the unbundled transmission service in interstate commerce is
a wholesale or retail customer. Thus, if a public utility voluntarily
offers unbundled retail access in interstate commerce or a state retail
access program results in unbundled retail access in interstate
commerce by a public utility, the affected retail customer must obtain
its unbundled transmission service under a non-discriminatory
transmission tariff on file with the Commission. Though the Commission
may approve a separate retail transmission tariff when some variation
is necessary or appropriate to meet local concerns,289 we
generally see no reason why retail transmission tariffs necessarily
must be different from wholesale transmission tariffs. For that reason,
we anticipate that in many
[[Page 21572]]
circumstances the same open access tariff that serves wholesale
customers will be equally appropriate for retail transmission
customers. Therefore, unless the Commission has specifically permitted
a separate retail tariff, eligible customers under the Final Rule pro
forma tariff must include unbundled retail customers.290 We
discuss this further in Section IV.I.
---------------------------------------------------------------------------
\289\ See Section IV.I.
\290\ The Commission has no authority to order retail
transmission directly to an ultimate consumer or to order ``sham''
wholesale transmission. See FPA section 212(h). However, if such
access occurs voluntarily or as a result of a state program, the
rates, terms, and conditions of the access are within our exclusive
jurisdiction if the service is provided by a public utility.
---------------------------------------------------------------------------
While the rates, terms, and conditions of all unbundled
transmission service will be subject to a Commission-authorized tariff,
we will, in appropriate circumstances, give deference to state
recommendations regarding rates, terms, and conditions for retail
transmission service or regarding the proper transmission cost
allocation to be used between retail and wholesale customers when state
recommendations are consistent with our open access policies. This is
also discussed further in Section IV.I.
Moreover, we are mindful of the fact that we are precluded under
section 212(h) from ordering or conditioning an order on a requirement
to provide wheeling directly to an ultimate consumer or sham wholesale
wheeling. We therefore clarify that our decision to eliminate the
wholesale customer eligibility requirement does not constitute a
requirement that a utility provide retail transmission service. Rather,
we make clear that if a utility chooses, or a state lawfully requires,
unbundled retail transmission service, such service should occur under
this tariff unless we specifically approve other terms.
2. Service That Must be Provided by Transmission Provider
In the NOPR, the Commission proposed that a public utility must
offer to provide any point-to-point or network transmission service
whether or not the utility provides itself that service:
The Commission therefore proposes that all public utilities must
offer both firm and non-firm point-to-point transmission service and
firm network transmission service on a non-discriminatory open
access basis in accord with the proposed rule and the attached
appendix tariffs. The Commission believes that a utility's tariff
must offer to provide any point-to-point transmission service and
network transmission service that customers need, even though the
utility may not provide itself the specific service
requested.291
---------------------------------------------------------------------------
\291\ FERC Stats. & Regs. para. 32,514 at 33,079.
---------------------------------------------------------------------------
Comments
EGA and SMUD agree that a transmission owner should offer any
transmission service it is able to provide, even if it does not use the
service itself.
Public Generating Pool, an association of consumer-owned electric
utilities, appears concerned that the Commission may interpret
comparability broadly to require a utility to offer the same service
provided by another utility or to offer service generally available in
a region. Thus, it recommends that a third party seeking more service
than a utility provides itself be required to resort to the section 211
process.
Commission Conclusion
Initially, we note that, with the possible exception of small
utilities (which may qualify for a waiver, see infra), we have seen no
evidence that public utilities are incapable of reasonably providing
the services required in the Final Rule pro forma tariff. Nor have we
seen evidence that utilities able to provide these services to
themselves are choosing to forego such services. In short, we are not
convinced that there is an appreciable difference, if any, among the
services required in the pro forma tariff, the services utilities are
able to provide, and the services they actually provide themselves.
To the extent these services do differ, however, we explicitly
adopt the proposal set forth in the NOPR. Thus, a public utility must
offer transmission services that it is reasonably capable of providing,
not just those services that it is currently providing to itself or
others. Because a public utility that is reasonably capable of
providing transmission services may provide itself such services at any
time it finds those services desirable, it is irrelevant that it may
not be using or providing that service today. Moreover, a public
utility must offer these transmission services whether or not other
utilities may be able to offer the same services and whether or not
such services are generally available in the region (waiver of these
requirements for small utilities is discussed in Section
IV.K.2.).292 However, if a customer seeks a customized service not
offered in an open access tariff, a customer may, barring successful
negotiation for such service, file a section 211 application.
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\292\ Requirements for ancillary services are discussed in
Section IV.D.
---------------------------------------------------------------------------
3. Who Must Provide Non-Discriminatory Open Access Transmission
In the NOPR, the Commission proposed to require all ``public
utilities'' owning and/or controlling facilities used for transmitting
electric energy in interstate commerce to file open access transmission
tariffs.293 We explained that we could not require all
``transmitting utilities'' to file open access tariffs under sections
205 and 206 because we do not have jurisdiction over non-public
utilities under these sections.
---------------------------------------------------------------------------
\293\ FERC Stats. & Regs. para. 32,514 at 33,049.
---------------------------------------------------------------------------
Comments
Several commenters argue that the open access requirement must be
applied to non-jurisdictional utilities that own interstate
transmission facilities.294 Power Marketing Association recognizes
that this raises difficult legal issues and suggests that the
Commission support legislation to expand the Commission's authority
over non-jurisdictional utilities. Minnesota P&L argues that if the
requirement is not applied to all entities that own transmission,
jurisdictional and non-jurisdictional entities owning joint
transmission facilities will be competitively disadvantaged due to
unequal pricing. Union Electric argues that unless the requirement is
extended to the 56 non-jurisdictional entities operating control areas,
discrimination in the wholesale power markets will increase.
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\294\ E.g., Minnesota P&L, Power Marketing Association.
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A number of municipal commenters assert that the NOPR overlooks
transmission assets jointly owned by jurisdictional and non-
jurisdictional utilities.295 They argue that agreements regarding
use of these assets often contain provisions prohibiting third-party
power transfers. They further argue that such provisions should be
nullified, and the joint owners should be required to develop equitable
methodologies to allocate wheeling revenues among themselves.
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\295\ E.g., Springfield.
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Several cooperatives urge the Commission to clarify that contracts
among their constituent cooperatives are not subject to any unbundling
of existing contracts.
Commission Conclusion
Our authority under sections 205 and 206 of the FPA permits us to
require only public utilities to file open access tariffs as a remedy
for undue discrimination. We have no authority
[[Page 21573]]
under those sections of the FPA to require non-public utilities to file
tariffs with the Commission.
However, we are concerned that if non-public utilities do not
provide access, there will remain a patchwork of ``open'' and
``closed'' transmission systems and the potential for distortions in
wholesale bulk power markets. We believe that certain mechanisms exist
that will help to alleviate these problems.
First, as we explained in the NOPR, broad application of section
211 will provide wider access to bulk power markets.296 Under
section 211, eligible entities may seek transmission service from
``transmitting utilities,'' which section 3(23) of the FPA defines as
``any electric utility, qualifying cogeneration facility, qualifying
small power production facility, or Federal power marketing agency
which owns or operates electric power transmission facilities which are
used for the sale of electric energy at wholesale.'' We believe that
section 211 provides us with authority to require the same quality of
transmission service as sections 205 and 206, though the procedural
path is more cumbersome. Thus, section 211 provides access to
transmission systems owned or operated by non-public utilities.297
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\296\ FERC Stats. & Regs. para. 32,514 at 33,050 and 33,092-93.
\297\ As discussed in the NOPR, sections 211 and 212 require
that applicants specify only rates, terms, and conditions of
service, not specify transactions. Thus, applicants can file
requests for tariffs to accommodate future, currently unspecified
transactions, similar to the open access tariffs required by this
Rule.
---------------------------------------------------------------------------
Second, as we explained in the NOPR, our reciprocity requirement is
designed to provide the widest possible use of the nationwide
transmission grid:
The purpose of this provision is to ensure that a public utility
offering transmission access to others can obtain similar service
from its transmission customers. It is important that public
utilities that are required to have on file tariffs be able to
obtain service from transmitting utilities that are not public
utilities, such as municipal power authorities or the federal power
marketing administrations that receive transmission service under a
public utility's tariff.298
\298\ FERC Stats. & Regs. para. 32,514 at 33,089.
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Finally, again as we explained in the NOPR, the formation of RTGs
should speed the development of competitive markets and involve more
non-public utilities in the provision of non-discriminatory open access
transmission.299 In approving RTGs, our policy has been to require
all members, whether or not they are public utilities, to offer
comparable transmission services at least to other members.
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\299\ Id. at 33,095.
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We recognize that these solutions are not perfect. However, given
the difficulties inherent in the statutory scheme, we believe they will
go a long way toward effectuating transmission access by non-public
utilities.
One further issue involving non-public utilities concerns jointly
owned transmission facilities. We will not allow public utilities that
jointly own interstate transmission facilities with non-jurisdictional
entities to escape the requirements of open access. We will require
each public utility that owns interstate transmission facilities
jointly with a non-jurisdictional entity to offer service over its
share of the joint facilities, even if the joint ownership contract
prohibits service to third parties. We urge such public utilities to
seek mutually agreeable revisions to their agreements to permit third-
party access over all, or at least their share, of the facilities. For
those joint ownership arrangements that include restrictions on the
usage of jointly owned transmission facilities by third parties, we
will require the public utilities, in a section 206 compliance filing,
to file with the Commission, by December 31, 1996, a proposed revision
(mutually agreeable or unilateral) to its contract with the non-
jurisdictional owner(s). This revision must be designed at a minimum to
permit third parties to use the public utility's share of the joint
facilities in accordance with this Rule and must provide for any needed
cost allocation procedures between the public utility and the non-
jurisdictional owner(s).
4. Reservation of Transmission Capacity by Transmission Customers
In the NOPR, the Commission set forth the information that a
requester of transmission service would have to submit with a service
request. We recognized that there may have to be a limit, for
competitive reasons, on the information required, but also recognized
the need to assure that no customer would reserve scarce capacity and
then hold it without using it.300 To avoid forcing transmission
customers to reveal unnecessary details of their purchase or sales
transactions, the Commission discussed several less restrictive
options: (1) Allow the transmission provider to use or sell the
capacity while it is unused, (2) have a pool that clears the short-term
market, and (3) require the customer to begin using the capacity within
some specified period or lose its reservation rights. The Commission
requested comments on these and other possible approaches.
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\300\ Id. at 33,090.
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Comments
Unused or Unneeded Transmission Capacity
Many commenters recommend a use-it-or-lose-it rule (i.e., a
transmission customer must use its reserved transmission capacity or
lose its rights to that capacity).301 Several commenters also
recommend a number of restrictions on capacity reservations to reduce
incentives to hoard or to cherry-pick (request to reserve firm capacity
only during peak hours of peak seasons) existing transmission capacity.
These include: (1) Allow requesters to reserve a place in the queue
with a right of first refusal over later competing requests; (2) impose
a take-or-pay charge on reservations and deny reservation holders the
right to revenue sharing if they do not schedule or assign their
rights; (3) limit the time period for reservations; (4) limit how far
in advance reservations may be made for both non-firm and firm
services; (5) maintain a price cap on the resale of transmission; (6)
require multi-year reservations to be for sequential periods; and (7)
require a nonrefundable fee for advance reservations of
service.302 Southwestern suggests that transmission tariffs
include a provision that prevents transmission customers and the
transmission provider from reserving and tying up firm transmission
capacity for speculative wholesale transactions.303
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\301\ E.g., Consumers Power, Northern States Power, PacifiCorp,
Oklahoma G&E, Allegheny Power, ELCON, Public Service Co of CO.
\302\ E.g., Northern States Power, VEPCO, Utilities For Improved
Transition, PacifiCorp, Arizona Public Service, Dairyland, Montaup,
Illinois Power, South Carolina E&G, Florida Power Corp, KU.
\303\ See also NRECA.
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On the other hand, PSNM believes that a use-it-or-lose-it approach
is inappropriate because any prudent utility that has reserved capacity
would seek to sell the service it is not using so as to recover some
portion of its fixed costs. Wisconsin P&L argues that a use-it-or-lose-
it approach would not work, would be difficult to administer, and may
be anticompetitive.304 Central Illinois Public Service asserts
that a reservation holder has little incentive to hoard capacity
because other customers can use the capacity on a non-firm basis during
times when a reservation holder does not schedule power. It warns that
[[Page 21574]]
giving the transmission operator the ability to schedule unused
capacity may result in undue influence and the exercise of market
power. CA Energy Com maintains that, while reassignment would help
prevent hoarding, it would not assure efficient use of the full
transmission network.
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\304\ Wisconsin P&L notes, however, that a possible exception
exists where a user could block the efficient transfer of power and
then market its own power at a premium price.
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Use of Pooling Arrangements To Prevent Improper Reservations
Allegheny Power contends that a pooling arrangement could provide
an incentive to hoarders to release capacity during a shortage. It
suggests that capacity could be auctioned within a pool of available
capacity. However, it acknowledges that an auction would be tantamount
to allowing the network owner to sell transmission service at
unregulated rates.
PacifiCorp does not believe that a pooling arrangement would
prevent capacity hoarding unless nonsequential reservations are
prohibited. ELCON contends that a use-it-or-lose-it rule would be
fairer and more effective than pooling.
Commission Conclusion
Upon further consideration, we conclude that firm transmission
customers, including network customers, should not lose their rights to
firm capacity simply because they do not use that capacity for certain
periods of time. Firm transmission customers that have reserved
capacity and paid a reservation charge generally do not use the entire
amount of reserved capacity at all times. This does not mean, however,
that they must permanently retu
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
rn the unused amount to the utility. In
the absence of evidence of hoarding or other anticompetitive practices,
we will not limit the amount of transmission capacity that a customer
may reserve. Firm transmission customers are in the best position to
know the levels of electric energy they will be transmitting and the
level of flexibility they need in carrying out their transmission
activities. Indeed, when they are not using their reserved capacity,
firm transmission customers remain obligated to pay the utility a
reservation charge that covers all of the utility's fixed costs
associated with the reserved capacity.305
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\305\ A reservation charge would assure that the utility fully
recovers its fixed costs associated with the transmission customer's
reserved transmission capacity.
---------------------------------------------------------------------------
Moreover, the possibility that a customer will reserve capacity and
then hold it without using or reassigning it is mitigated because the
utility is free to schedule and sell any unscheduled firm point-to-
point transmission capacity on a non-firm basis to any entity eligible
to receive such service under the utility's tariff. We also note that
it is in the economic self interest of reservation holders to make
available unused capacity to the market.306
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\306\ See Section IV.C.6.
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We recognize that situations could arise in which a customer
unlawfully withholds capacity. That is, a transmission customer could
retain capacity in a way that could have an anticompetitive effect. For
example, a transmission customer may reserve certain capacity simply to
prevent everyone else from using it and to make its own generation the
only alternative available to the market. However, as described above,
we believe that the incentives are such that parties are more likely to
release unneeded capacity and that a generic remedy is therefore
unnecessary. Any substantial allegations that indicate that a
transmission customer is withholding scarce capacity in a way that has
an anticompetitive effect would be addressed under section 206. If we
found such allegations to be true, we could order the customer to
return the capacity reservation right to the transmission operator.
This approach should allay concerns that a customer may reserve scarce
capacity and not use it, without forcing customers to demonstrate need
or to reveal details of individual transactions.
5. Reservation of Transmission Capacity for Future Use by Utility
Comments
EEI and many IOUs argue that native load and network transmission
customers should have first priority to existing capacity for their
reasonably forecasted load requirements because that capacity was
constructed to provide service to them and was paid for by
them.307 EEI contends that such priority ensures equity and
comparability based on past and future cost responsibility for the
system. Similarly, Florida Power Corp and PECO contend that third-party
customers should not be allowed to use transmission capacity that
native load customers would grow into within a reasonable planning
horizon.
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\307\ E.g., NYPP, Public Service E&G, Sierra Pacific Power, Ohio
Edison. Sierra Pacific Power asserts that a utility should be
permitted to retain capacity for native load use over the pertinent
planning period. El Paso adds that the Commission should allow
utilities the opportunity to reserve capacity for anticipated uses
that, although not firm, are necessary to maintain reliability.
---------------------------------------------------------------------------
Other commenters disagree, asserting that available transmission
capacity must be determined in the same manner for all customers and
that utilities should not be permitted to reserve capacity for their
own uses.308 NIEP argues that utilities should not be permitted to
lock up available transmission capacity over valuable transmission
paths and then require transmission requesters to pay for the cost of
incremental transmission upgrades. This would let the utility avoid
incremental transmission charges on its system. Oklahoma G&E argues
that existing available transmission capacity should be made available
until it is needed for native load growth. Utilicorp states that
transmission owners should not be permitted to set aside capacity for
sales or purchases of economy energy. CCEM argues that the centerpiece
of comparability is that all transmission customers, including the
merchant operations of the transmission owner, take service from
available capacity pursuant to the same tariffs. CCEM adds that
allowing utilities to reserve capacity based on forecasted retail and
network loads creates an incentive for them to over-forecast their load
to the detriment of all others. NRECA suggests that the need to
maintain reliability should not perpetuate transmission providers'
preferential treatment of their own transactions. It also recommends
that, during periods when facilities are constrained, access be
allocated based on a combination of past actual use and planned future
use.
---------------------------------------------------------------------------
\308\ E.g., NIEP, CCEM, Conservation Law Foundation.
---------------------------------------------------------------------------
Commission Conclusion
We conclude that public utilities may reserve existing transmission
capacity needed for native load growth and network transmission
customer load growth reasonably forecasted within the utility's current
planning horizon. However, any capacity that a public utility reserves
for future growth, but is not currently needed, must be posted on the
OASIS and made available to others through the capacity reassignment
requirements, until such time as it is actually needed and used.
In response to arguments raised by several commenters that existing
requirements customers should have future rights to existing capacity
beyond the terms of their contracts because of their historical use, as
discussed previously, we believe existing customers should have a right
of first refusal to capacity they previously used, if they are willing
to match the rate offered by another potential customer, up to the
transmission provider's maximum filed transmission rate at that time,
and to accept a contract term at
[[Page 21575]]
least as long as that offered by another potential customer.309
---------------------------------------------------------------------------
\309\ See Section IV.A.5.
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6. Capacity Reassignment
In the NOPR, the Commission proposed that a tariff must explicitly
permit reassignment of firm service entitlements.310 We explained
that reassignment of capacity rights could have a number of benefits:
(1) Helping transmission users manage financial risk, (2) reducing
transmission providers' market power by enabling transmission customers
to compete with them, and (3) improving capacity allocation when
capacity is constrained and some market participants value capacity
more than current capacity holders. We requested comments on whether
the current price cap on resale should be modified or eliminated and
whether the transmission services described in the NOPR are suitable
for reassignment.
---------------------------------------------------------------------------
\310\ FERC Stats. & Regs. para. 32,514 at 33,088.
---------------------------------------------------------------------------
Comments
General
Many commenters favor capacity reassignment and the development of
secondary markets.311 However, WP&L notes that reassignments
should not be permitted over constrained interfaces if the source or
destination of power changes, and LA DWP opposes unrestricted
reassignment because it could cause tax-exempt financing problems for
many public power utilities.
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\311\ E.g., PacifiCorp, DOJ, NIEP, ELCON, United Illuminating,
DOD, WP&L, FTC. OK Com and FL Com favor reassignment of capacity,
but express concerns that reliability not be affected.
---------------------------------------------------------------------------
Many IOUs argue that the same terms and conditions of service
applied to IOUs should be applied to resellers of transmission
services.312 Arizona Public Service, however, asserts that all
unused transmission rights should not be assignable, but should be made
available to others in a manner consistent with the contract supporting
the rights. It argues that a network user experiencing an off-system
network shutdown should be required during the outage to make available
to others the path from the point that the power enters the system to
its load. It also contends that firm transmission customers should be
required to post their unused rights on an EBB or RIN.
---------------------------------------------------------------------------
\312\ E.g., Northern States Power.
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Several commenters oppose mandatory reassignment of firm capacity
rights.313 NEPCO declares that if a customer is willing to pay for
its reserved capacity, it should not be forced to reassign unused
capacity. Nebraska Public Power District believes that mandatory
reassignment could cause problems for publicly-owned utilities. It
further asserts that in the gas industry the Commission did not allow
the unregulated reassignment regime it proposes for the electric
industry.
---------------------------------------------------------------------------
\313\ E.g., NEPCO, Nebraska Public Power District.
---------------------------------------------------------------------------
SoCal Edison argues that when a transmission customer resells
transmission capacity, it should not be released from its contractual
obligation to the transmission provider. It notes that under
traditional contract law, a party to a contract cannot escape its
obligations by delegating them to another.
Price Caps
Most commenters addressing this issue support retaining the
existing price cap on reassignments or resales.314 Generally,
these commenters believe that the price cap is necessary to prevent
customers from speculating or hoarding capacity in anticipation of its
value increasing. Public Service Co of CO believes that allowing
assignments of capacity at prices greater than cost could prevent a
transmission provider from offering firm capacity for legitimate long-
term transactions. TDU Systems states that a cap should remain until
the secondary market in the relevant geographic market has been shown
to be competitive. PA Com states that turning available capacity into a
spot market would tie up capacity that might otherwise be used on a
day-to-day basis and for emergencies. Still other commenters argue that
customers should not be allowed to sell the capacity for more than the
transmitting utility could charge.315 Allegheny argues that any
rule that allows resale of transmission capacity at a higher price than
the transmission provider can achieve is ``patently illogical and
probably illegal.'' Several utilities, including Allegheny and CSW,
contend that if resellers can market transmission services at market
rates, then transmission owners must be given the same opportunity.
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\314\ E.g., NRECA, Montana Power, PacifiCorp, NYSEG, PA Com,
Idaho, Public Service Co of CO, FPC, Entergy, TDU Systems, Duke,
Cajun, CVPSC, Oglethorpe, Minnesota DPS. FL Com argues that the
price of reassignment should be capped at the contract selling
price. WP&L argues that the price cap should be raised to the
maximum rate allowed in the tariff under which the user purchased
the original service.
\315\ See also Minnesota DPS.
---------------------------------------------------------------------------
Duquesne and United Illuminating argue that the price cap should be
modified so that third parties are allowed to resell capacity at the
higher of embedded costs or opportunity costs.316 Duquesne notes
that such a provision would be comparable to the option transmitting
utilities now have and would be economically efficient because it would
encourage the firm capacity owner with the lowest opportunity cost to
resell its capacity.
---------------------------------------------------------------------------
\316\ See also Midwest Commissions, SMUD, CCEM.
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A few commenters argue that the price cap should be
eliminated.317 IL Com claims that capacity will be made available
to the entity that values it most and that an uncapped resale market
cannot lead to more market power because an efficient secondary market
cannot be monopolized. Con Ed agrees that if the secondary market is
competitive, all entities should be allowed to sell at market-based
rates.318 CT DPUC argues that there should not be a price cap;
instead, it would prefer that those holding transmission rights not be
allowed to withhold use of any portion of their reserved transmission
capacity in the actual moment-by-moment operation of the grid.
---------------------------------------------------------------------------
\317\ E.g., IL Com, NEPCO, Consumers, American Wind.
\318\ If the market is not competitive, however, Con Ed
maintains that the cap should be retained for all entities.
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Creditworthiness Standards
Of those commenting on the appropriate creditworthiness standards
for replacement customers (assignees), all favor allowing the
transmission provider to use reasonable credit procedures to assure
that the replacement customer is financially sound.319 NYSEG
suggests that, at a minimum, the same creditworthiness criteria should
be applied to the replacement customer as are applied to the original
customer. Oglethorpe recommends that the assignee be required to commit
to comply with all customer obligations and to pay for any additional
costs resulting from the assignment.
---------------------------------------------------------------------------
\319\ E.g., PacifiCorp, NYSEG, Oglethorpe.
---------------------------------------------------------------------------
Liability for Payment
Commenters split on whether the original customer or the
replacement customer should be liable to the transmitting utility for
payment for the service. One group of commenters believes that the
original customer should remain liable for all costs and for the
performance of all obligations.320 Another group of commenters
believes that the original customer should be relieved of financial
responsibility, at least under certain circumstances.321 For
[[Page 21576]]
example, NYSEG asserts that the original customer should be relieved of
its obligations upon the execution of a new service agreement between
the new customer and the provider. TDU Systems contends that the
original customer should be relieved of future liability where the
replacement customer meets the transmission provider's creditworthiness
standards. Entergy argues that the original customer should remain
liable until all obligations are fulfilled.
---------------------------------------------------------------------------
\320\ E.g., Oglethorpe, NSP.
\321\ E.g., NYSEG, Entergy, TDU Systems, Turlock, American Wind.
---------------------------------------------------------------------------
Commission Conclusion
After reviewing the comments, we conclude that a public utility's
tariff must explicitly permit the voluntary reassignment of all or part
of a holder's firm transmission capacity rights 322 to any
eligible customer.323 Reassignment may be on a temporary or
permanent basis, and must be subject to the conditions and requirements
discussed below.
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\322\ The transmission provider has the same rights as any other
potential assignee to obtain capacity that is posted on an OASIS or
to negotiate with the assignor for any capacity the assignor seeks
to assign.
\323\ The public utility's tariff shall not preclude an assignor
from including a right of recall in its agreement with an assignee.
---------------------------------------------------------------------------
Allowing holders of firm transmission capacity rights to reassign
capacity will: (1) Help them manage the financial risks associated with
their long-term transmission commitments, (2) reduce the market power
of transmission providers by enabling customers to compete, and (3)
foster efficient capacity allocation. We offer below a number of
clarifications and further explanations in response to concerns raised
by commenters.
(1) Reassignable Transmission Services
We conclude that point-to-point transmission service, because it
sets forth clearly defined capacity rights, should be reassignable. As
for network transmission service, we conclude that there are no
specific capacity rights associated with such service, and thus,
network transmission service is not reassignable.
(2) Terms and Conditions of Reassignments
a. General
In effecting a reassignment, the assignor does not have to return
its capacity entitlement to the original transmission provider, but may
deal directly with an assignee without involvement of the transmission
provider. However, an assignee must meet the eligibility standard
established by this Rule and must comply with the reliability criteria
of the original transmission provider. Any such transaction must be
posted on the transmission provider's OASIS within a reasonable time
after its effective date. Alternatively, the assignor may, if it
wishes, request the transmission provider to effect a reassignment on
its behalf.324 In such a situation, the transmission provider must
immediately post the available capacity on its OASIS. The transmission
provider must assure that any revenues associated with the reassignment
are credited to the assignor.325
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\324\ The assignor may also request the transmission provider to
provide the billing and payment services for the reassignment. The
parties would negotiate terms for such an arrangement, including a
fee for the transmission provider. If an assignor is a public
utility, it will have to have on file with the Commission a rate
schedule governing reassigned capacity.
\325\ Any expenses that the public utility incurs in carrying
out the capacity assignment program would simply be included in its
cost of service.
---------------------------------------------------------------------------
b. Contractual Obligations
Assignors and assignees may contract directly with each other, but
the assignor will remain obligated to the transmission provider. This
obligation extends to any penalties or other charges incurred by the
assignee in its use of the reassigned capacity. The assignee will be
liable solely to the assignor, and should it not meet its obligations,
the assignor may cancel the assignment under their contract.
If the transmission provider and the original customer mutually
agree, we will permit alternatives to the above approach. For example,
the transmission provider could agree to relieve the original customer
of payment liability for the term of the reassignment and permit the
assignee to pay the provider directly.
In the case of a permanent reassignment, the transmission provider
should not unreasonably refuse to release the assignor from liability
if the assignee meets the transmission provider's creditworthiness
requirements as set forth in its tariff and agrees to pay the price the
assignor is obligated to pay the transmission provider.
c. Price Cap
We conclude that the rate for any capacity reassignment must be
capped by the highest of: (1) The original transmission rate charged to
the purchaser (assignor), (2) the transmission provider's maximum
stated firm transmission rate in effect at the time of the
reassignment, or (3) the assignor's own opportunity costs capped at the
cost of expansion (Price Cap). We remain convinced that we cannot lift
the Price Cap and permit reassignments at market-based rates. Based
upon the information available in this proceeding, we are unable to
determine that the market for reassigned capacity is sufficiently
competitive so that assignors will not be able to exert market power.
Thus, we will not permit an assignor to reassign capacity at a rate in
excess of the Price Cap. Assignees must agree, in contracting with the
assignor, that the firm transmission capacity they will use is subject
to the Price Cap.
7. Information Provided to Transmission Customers Comments
Many commenters argue that in an open access, competitive
environment, confidential and proprietary information should not be
made publicly available through a RIN.326
---------------------------------------------------------------------------
\326\ Similar arguments with respect to the information that
public utilities must provide to the Commission in standard reports
(e.g., Form No. 1) are addressed later in this Final Rule.
---------------------------------------------------------------------------
Several utilities assert that the existing reporting requirements
are sufficient to support the comparability requirements of the
proposed rule, with some modifications.327 They note that the
Commission's audit authority and complaint process will help enforce
comparability requirements.328 Central Illinois Public Service
states that, with the availability of pricing and transaction
information through the RIN, no further reporting requirements are
necessary. IL Com states that additional reporting should be required
only if clear evidence emerges of discriminatory use of the
transmission system. Dominion Resources adds that users have no need
for utility planning information and data on generator status and that
disclosure of such information would place owners at a competitive
disadvantage. VEPCO opposes the disclosure of any commercially
sensitive information to marketers, including the utility's power
marketing employees.
---------------------------------------------------------------------------
\327\ E.g., PacifiCorp, NYSEG, NSP.
\328\ See also PA Com.
---------------------------------------------------------------------------
On the other hand, several commenters argue that the information
submitted by public utilities may not be adequate. For example, APPA
argues that the Commission should scrutinize closely cost
functionalization by utilities to assure that plant in service is
properly booked. Others recommend that the Commission put in place a
monthly pass-through of transmission-related operating income for all
classes of customers receiving firm transmission service, rather than
rely on the current practice of reducing test year
[[Page 21577]]
cost of service by revenues booked to Accounts 456 and 447. Industrial
Energy Applications recommends that utilities be required to file
quarterly reports with the Commission that detail the transmission
services and the pricing of their off-system power supply transactions,
as an incentive to comply with the Commission's rule.
Commission Conclusion
We conclude that all necessary transmission information, as
detailed in the OASIS final rule, must be posted on an OASIS. With
respect to generation information, we will require, consistent with the
OASIS final rule, that information needed to verify opportunity/
redispatch costs be provided, on request, to the transmission customer
charged. We will not require this information, or any other generation
information,\329\ to be posted on an OASIS.\330\
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\329\ The prices of some ancillary services, which are posted on
the OASIS, are based on generation costs, however.
\330\ Because the Commission establishes many generation and all
transmission rates on a cost basis, the Commission also will
continue to need the information that it collects in Form No. 1 and
other standard forms from public utilities to assure that the rates
are just and reasonable. As we explain later in this Final Rule, the
information provided in those forms is public information that is
available to any transmission customer. However, because of the
competitive changes occurring in the electric industry, we recognize
that there may be a need to reexamine the information we collect
from public utilities through the Form No. 1.
---------------------------------------------------------------------------
8. Consequences of Functional Unbundling
a. Distribution Function
The NOPR proposed functional unbundling of wholesale generation and
wholesale transmission so that the public utility as a wholesale seller
could not gain an undue advantage from its transmission ownership. We
did not propose to further unbundle the retail transmission and
distribution functions from the wholesale transmission function.
Comments
A number of commenters assert that utilities should be required to
unbundle--either functionally or corporately--the distribution function
from the transmission function. ELCON argues that unbundling
distribution would help delineate state and Federal jurisdiction,
facilitate the establishment of transmission pricing, avoid cross-
subsidization, and prepare for the customer choice (retail wheeling)
programs that will be implemented by states in the future. It contends
that functional distinctions between wholesale and retail service
should be minimized.331
---------------------------------------------------------------------------
\331\ See also Environmental Action, Missouri Basin MPA, Texaco,
EGA, AEC & SMEPA.
---------------------------------------------------------------------------
Other commenters, however, oppose establishing a separate
distribution function. DOD asserts that the Commission can address any
problems that arise by enforcing the terms of open access tariffs and
that the Commission should not intrude into state ratemaking.\332\
---------------------------------------------------------------------------
\332\ See also TDU Systems, Public Service Co. of CO.
---------------------------------------------------------------------------
Various state commissions question the workability and desirability
of a functional test to determine the dividing line between retail
transmission and local distribution.333 CA Com recommends that, to
avoid jurisdictional uncertainty surrounding functional unbundling, the
Commission adopt a functional test for local distribution. Under this
test, vertically integrated utilities that chose to unbundle into
separate operating companies, including a local distribution company
that sells only at retail, could establish a workable bright line
between state and Federal authority without engaging in the arduous
task of differentiating transmission from distribution.
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\333\ E.g., NARUC, AZ Com, CT DPUC, OK Com, FL Com, NC Com, NM
Com.
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Certain IOUs echo the jurisdictional concerns raised by the state
commissions.334 They believe that the unbundling of the
distribution function would create significant jurisdictional problems.
Pacificorp also argues that unbundling of the distribution function
would create significant jurisdictional conflict with respect to cost
allocation.
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\334\ E.g., Com Ed, Citizens Utilities, PacifiCorp.
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Commission Conclusion
We conclude that the additional step of functionally unbundling the
distribution function from the transmission function is not necessary
at this time to ensure non-discriminatory open access transmission. Our
approach to assuring such open access has two broad requirements: (1)
Functional unbundling of transmission and generation (which includes
separately stated rates for generation, transmission, and ancillary
services, and a requirement that a transmission provider take service
under its own tariff), except for bundled retail service and (2) an
OASIS with standards of conduct. We believe that additional
requirements are not needed now. We further address in Section IV.I the
concerns raised regarding our proposed tests to distinguish
transmission and local distribution.
b. Retail Transmission Service
Comments
The majority of commenters addressing this issue believe that
unbundling retail service is unnecessary to establish a competitive
market and to achieve non-discriminatory open access
transmission.335 For example, PSNM argues that the Commission is
not as well situated as are state regulators to oversee and supervise
local reliability issues for retail customers. Central Illinois Public
Service argues that due to the nature of transmission facilities and
operations, it is not possible for the transmission provider to
discriminate between the provision of wholesale and retail firm
service. Several IOUs further contend that because the Commission is
specifically precluded from mandating retail wheeling and has no
authority over bundled retail service, the Commission cannot require
retail service to be provided.336
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\335\ E,g,, Allegheny Power, PacifiCorp, MidAmerican, PECO,
Public Service Co. of CO, Com Ed, NARUC, NRRI, MN DPS, ND Com, FL
Com.
\336\ E.g., Allegheny Power.
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In contrast, some commenters argue that functional unbundling must
apply to all transmission service in interstate commerce provided by
public utilities, including the transmission component of bundled
retail sales.337 They believe that this is necessary to achieve
comparability. For example, CCEM asserts that if the distribution
function is not unbundled, the result will be service under two
separate arrangements--an explicit wholesale transmission tariff filed
at the Commission and an implicit retail transmission tariff governed
by a state regulatory body. According to CCEM, failure to unbundle
retail transmission will allow transmitting utilities to manipulate how
they characterize and account for their own uses of transmission. ABATE
contends that the Commission, for efficiency reasons, should encourage
states to permit retail access. It asserts that the Commission must
adopt a policy that signals to states how rates, terms, and conditions
of retail service will be established; once a state sets such
parameters, the Commission should review them.
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\337\ E.g., CCEM, ABATE.
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Commission Conclusion
Although the unbundling of retail transmission and generation, as
well as wholesale transmission and generation, would be helpful in
achieving comparability, we do not believe it is necessary. In
addition, it raises numerous difficult jurisdictional issues
[[Page 21578]]
that we believe are more appropriately considered when the Commission
reviews unbundled retail transmission tariffs that may come before us
in the context of a state retail wheeling program. The Commission
therefore reaffirms its decision to require the unbundling only of
wholesale transmission from generation.338
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\338\ But see discussion of buy/sell transactions in Section
IV.I.
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c. Transmission Provider
1. Taking Service Under the Tariff
In the NOPR, we explained that a public utility must take
transmission services for all of its new wholesale sales and purchases
of energy under the same tariff of general applicability under which
others take service.339
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\339\ FERC Stats. & Regs. para. 32,514 at 33,080.
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Comments
A number of commenters argue that utilities should be required to
take all of the transmission for their own use under their
tariff.340 CCEM asserts that a transmission owner should have to
schedule, at arm's length, its retail transmission uses and pay posted
rates into a separate account; otherwise the capacity might be
overforecast at no cost.
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\340\ E.g., Michigan Systems, Cleveland, Municipal Energy Agency
Nebraska, Missouri Basin MPA, TAPS, Wisconsin Municipals, LG&E,
NIEP, CCEM.
---------------------------------------------------------------------------
PECO requests that the Commission clarify that the requirement that
a transmission provider take service under its own transmission tariffs
does not apply to: (1) Retail service, (2) existing wholesale
contracts, and (3) pooling arrangements. UNITIL claims that the
requirement for a transmission provider to take service under its own
tariff and to post its own tariff rate should not apply to pool
transactions where a single pool-wide rate is applied.
A number of IOUs contend that it is not necessary for the
transmission provider to take service under the network tariff because
both the transmission provider and the network customers cannot use the
tariff to make off-system sales. LILCO states that it is appropriate to
distinguish between a transmission owner's use of its transmission
system to make: (1) Wholesale bulk power sales; and (2) off-system
purchases to serve its native load retail customers. LILCO contends
that in the second situation it should not be required to take
transmission service under its own open access tariffs.
EGA argues that transmission owners should be required to take
transmission service under open access tariffs for both wholesale off-
system sales and purchases. It maintains that, as retail competition
increases, utilities will eventually have to take retail service under
their own tariffs. Power Marketing Association believes that
comparability can be achieved only if transmission service provided in
connection with coordination transactions is unbundled and the
transmission provider takes such transmission service under its tariff.
Consumers Power also claims that there is an inconsistency between
the NOPR text, the tariffs, and the proposed regulatory language
regarding whether the requirement for a utility to take service under
its own tariff applies only to new wholesale transactions.
Commission Conclusion
We conclude that public utilities must take all transmission
services for wholesale sales under new requirements contracts and new
coordination contracts under the same tariff used by others (eligible
customers).\341\ For sales and purchases under existing bilateral
economy energy coordination agreements, we will give an extension until
December 31, 1996, for public utilities to take transmission service
under the same tariff used by others.\342\ As further discussed in
Section IV.F., we will also give an extension of time to December 31,
1996, for certain existing power pooling and other multi-lateral
coordination agreements to comply with this requirement. This will
ensure that utilities live by their own rules for wholesale
transactions and that we can achieve non-discriminatory open access
transmission. In the case of a public utility buying or selling at
wholesale, the public utility must take service under the same tariff
under which other wholesale sellers and buyers take service.
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\341\ With the exception of certain contracts and agreements
executed on or before 60 days after publication of the Final Rule in
the Federal Register, the regulation we are adopting requires that
public utilities take service under their open access tariff for
wholesale sales or purchases of electric energy and unbundled retail
sales of electric energy, effective on the date the public utility
engages in such transactions.
\342\ As discussed in Section IV.F., the Commission will not
impose this requirement on existing bilateral non-economy
coordination agreements, but persons may file complaints that such
agreements need to be modified.
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2. Accounting Treatment
In the NOPR, we did not address any accounting aspects of our
proposed rule.
Comments
IOUs generally object to a requirement that they pay themselves for
their use of the transmission system.343 NEPCO claims that it is a
general principle of accounting that an enterprise cannot recognize and
record revenues to itself. NEPCO suggests that, to ensure that
utilities' financial statements are not misleading, this aspect of
functional unbundling can and should be accomplished through the
ratemaking process, rather than by requiring utilities to actually
charge themselves revenues for taking transmission services.344
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\343\ E.g., EEI, Con Ed, VEPCO.
\344\ See also NEPCO.
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Atlantic City Electric states that the added costs of properly
administering and accounting for these transactions separately will
increase prices to ultimate consumers. It contends that ensuring that
operators do not give undue preference to transactions of the
transmission provider makes it unnecessary for a utility to charge
itself.
CSW argues that some of the provisions of the tariffs were
specifically designed for third parties and do not make sense as
applied to the transmission provider (e.g., signing service agreements
and running credit checks).345
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\345\ See also Florida Power Corp.
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Most IOUs suggest that a revenue credit mechanism be used to
account for a transmission provider's use of its system. Florida Power
Corp states that revenue credits should be equal to the utility's
posted rates for transmission service multiplied by the amount of
capacity reserved and/or energy transmitted by the utility.
Otter Tail proposes a revenue credit that allocates revenues based
on use under the tariff of the utility's transmission investment and
credits these revenues against the firm load customers' accounts.
Duke asserts that the transmission provider should maintain records
reflecting transmission for its own transactions under the tariff and
develop appropriate revenue credits for transmission rates. It also
believes that all firm users of the transmission system should receive
credits for all non-firm uses.
Allegheny Power states that the crediting of non-firm revenues to
network customers would have to be done on an after-the-fact basis when
their loads would be known. However, it believes that revenue crediting
should occur only if the firm service customer has retained the utility
to remarket the customer's unused capacity.
Cajun proposes that all transmission revenues in excess of those
implicitly included in the development of the transmission rates,
including those that the utility has charged itself, be credited
[[Page 21579]]
back to the network service transmission customers on a load ratio
share basis. If transmission service rates are formula rates that are
recalculated annually, Cajun proposes that excess transmission revenues
be used to offset the recalculated revenue requirement. If the rates
are not formula rates, Cajun states that an explicit tracker with
monthly crediting to the network customer must be used.
To avoid cross-subsidization between affiliates and third parties,
NRECA suggests that transmission revenues ``paid'' by a utility's
generation function to its transmission function be credited back to
the utility's nonaffiliated customers, and that any rate discounts
extended to the generation function by the transmission function be
filed with the Commission with a full explanation of why the discount
was extended together with a showing that the discount was made
available to all other similarly situated customers.
APPA contends that the Commission's current system of revenue
crediting could give transmission owners an unfair competitive
advantage by allowing them to use the revenue credit to subsidize the
price at which they sell power. It argues that transmission owners
should pay the actual price of transmission rather than booking a
revenue credit as an offset to the cost of transmission service.
TAPS and Wisconsin Municipals argue that an essential element of
true comparability is the ongoing pass-through to network customers of
a load ratio share of transmission revenues generated by third-party
and the transmission provider's off-system uses of the transmission
system.
Houston L&P suggests that the revenue crediting mechanism proposed
in the NOPR could be established to recognize the utility's
transmission service revenue and expenses in non-third-party wheeling
transactions by reclassifying a portion of its revenue equal to the
cost of transmission services provided to itself during such
transactions. This mechanism would not reclassify expense accounts, but
would distinguish that transmission portion of the total transaction's
revenue that was associated with covering the cost of transmission
service, using the rates charged in similar third-party transactions.
PacifiCorp contends that the Commission should enforce the
requirement that utilities account for revenues they pay themselves
through the commission's audit powers and through complaint
proceedings. It specifically recommends that each transmitting utility
be required to indicate, in its Form No. 1 under Account 456, the
megawatts and revenues associated with its firm and non-firm off-system
sales.346
---------------------------------------------------------------------------
\346\ If the utility is not required to file a Form No. 1,
PacifiCorp states that it should be required to file similar
information annually.
---------------------------------------------------------------------------
MT Com states that the embedded costs that the Commission
functionalizes for jurisdictional purposes should be carefully
reconciled with plant balances used to calculate other costs of
service.
CCEM wants each transmission provider to charge and book revenues
into separate accounts for (1) service provided to itself and off-
system sales and third-party sales under the tariffs, (2) impact study
costs that the provider performs for itself or an affiliate, and (3)
ancillary service revenues, net of out-of-pocket expenses the
transmission owner provides itself or an affiliate.
Arizona Public Service recommends that any revenue crediting or
booking be prospective only and that enforcement occur through the
Commission's periodic audits and a utility's rate cases.
Many IOUs argue that there should be no obligation to credit non-
firm transmission revenues to customers who are not using their firm
capacity.347 PacifiCorp contends that all non-firm revenues should
be credited against total annual revenue requirements, resulting in
lower rates to all customers. Wisconsin P&L maintains that non-firm
sales revenue should be shared with all network customers.
---------------------------------------------------------------------------
\347\ E.g., Consumers Power, Northern States Power, PacifiCorp,
Allegheny Power.
---------------------------------------------------------------------------
Otter Tail argues that non-firm transactions between existing
utilities to support and achieve real-time system optimization should
be permitted without charge to the transmission owner. CSW asserts that
no credits should be made for the non-firm secondary service under the
point-to-point tariff and that off-system purchases for native load
should not result in a revenue credit.
Southwestern suggests that the Commission not require the crediting
of a transmission component associated with off-system purchases by the
public utility. Southwestern argues that a credit would interfere with
a utility's ability to buy the most economic energy for its native load
customers. It also argues that requiring a credit is not comparable to
what network customers pay. NEPCO points out that crediting
transmission associated with purchases would require native load
customers to pay the costs of the utility's purchasing off-system power
while network customers do not have to pay a separate point-to-point
charge for their off-system purchases. Southwestern claims that the
crediting requirement would double-charge the transmitting utility and
its native load customers because a utility's off-system purchases
directly relate to the load it serves, and that load already is
reflected in the transmission rate calculation. Southwestern also
claims that it is unclear from the NOPR whether the Commission
considers sales from the renewal of existing wholesale requirements
contracts as being subject to crediting. It argues that transmission
related to these sales should not be subject to the crediting
requirement because this is service to native load customers.
Brazos opposes imputing revenues associated with a utility's own
use of its transmission system because this will artificially increase
the cost of power and deny consumers the benefits of economy energy
sales made at market-based prices.
Commission Conclusion
While we used the word ``accounting'' in the NOPR, the real issue
is assuring that utilities bear the costs associated with their own
uses of the system in a manner comparable to how they charge others.
Accordingly, this is a rate issue, not an accounting issue. However, we
direct utilities to account for all uses of the transmission system and
to demonstrate that all customers (including the transmission
provider's native load) bear the cost responsibility associated with
their respective uses.348
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\348\ Additional guidance on this subject is in Section
IV.G.4.g.(2)(a).
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D. Ancillary Services
In the NOPR, the Commission stated that several ancillary services
are needed to provide basic transmission service to a customer. These
services range from actions taken to effect the transaction (such as
scheduling and dispatching services) to services that are necessary to
maintain the integrity of the transmission system during a transaction
(such as load following and reactive power support). Other ancillary
services are needed to correct for the effects associated with
undertaking a transaction (such as energy imbalance service).
We proposed six ancillary services to be offered in an open access
transmission tariff, which we called (1) scheduling and dispatching
services, (2) load following service, (3) energy imbalance service, (4)
system protection service, (5) reactive power/voltage control service,
and (6) loss compensation service. We requested
[[Page 21580]]
comments on all aspects of ancillary services, including whether the
identified ancillary services are appropriately defined, whether other
services should be included, and how these services should be supplied.
Commenters identified a number of other services that may be
provided as part of interconnected operations. After considering the
comments, we conclude that the following six ancillary services must be
included in an open access transmission tariff:
(1) Scheduling, System Control and Dispatch Service;
(2) Reactive Supply and Voltage Control from Generation Sources
Service;
(3) Regulation and Frequency Response Service;
(4) Energy Imbalance Service;
(5) Operating Reserve--Spinning Reserve Service; and
(6) Operating Reserve--Supplemental Reserve Service.
A description of these services and our reasons for designating
them as ancillary services are included in section 1 below. We also
discuss in that section our rationale for excluding other services from
the list of ancillary services that must be included in an open access
transmission tariff. In section 2 below, we discuss which of the six
ancillary services the transmission provider must provide or offer to
provide to transmission customers, and which the transmission customer
must purchase from the transmission provider. These requirements are
summarized as follows:
(1) Scheduling, System Control and Dispatch Service (Transmission
Provider must provide and Transmission Customer must purchase from
Transmission Provider);
(2) Reactive Supply and Voltage Control from Generation Sources
Service (Transmission Provider must provide and Transmission Customer
must purchase from Transmission Provider);
(3) Regulation and Frequency Response Service (Transmission
Provider must offer to provide only to Transmission Customer serving
load in Transmission Provider's control area and Transmission Customer
must acquire, but may do so from Transmission Provider, a third party
or self supply);
(4) Energy Imbalance Service (Transmission Provider must offer to
provide only to Transmission Customer serving load in Transmission
Provider's control area and Transmission Customer must acquire, but may
do so from Transmission Provider, a third party or self supply);
(5) Operating Reserve--Spinning Reserve Service (Transmission
Provider must offer to provide only to Transmission Customer serving
load in Transmission Provider's control area and Transmission Customer
must acquire, but may do so from Transmission Provider, a third party
or self supply); and
(6) Operating Reserve--Supplemental Reserve Service (Transmission
Provider must offer to provide only to Transmission Customer serving
load in Transmission Provider's control area and Transmission Customer
must acquire, but may do so from Transmission Provider, a third party
or self supply).
Our requirement that these six ancillary services be included in an
open access transmission tariff does not preclude the transmission
provider from offering voluntarily to provide other interconnected
operations services to the transmission customer along with the supply
of basic transmission service and ancillary services.349
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\349\ Of course, public utilities would have to have a rate
schedule on file to provide other jurisdictional interconnected
operations services.
---------------------------------------------------------------------------
1. Definitions and Descriptions
Comments
Commenters generally agree that some ancillary services are needed
for transmission of power. Some commenters, however, argue for a
different name or description for the ancillary services we proposed in
the NOPR. Others argue for a more extensive list of services.
EEI believes that the term ``ancillary'' is a confusing description
because the services are integral to providing transmission service.
NERC, PSE&G, and others claim that ancillary services are not, as the
term ``ancillary'' implies, subordinate or auxiliary to the
transmission of power; rather such services are conjunctive and
required to allow reliable operation of an electric system. BG&E and
others contend that ancillary services should be defined as services
for control area operation,350 and not as services provided by an
individual, noncontrol area utility. NERC proposes, and many IOU
commenters support, an alternative name for these services,
``Interconnected Operations Services.'' NERC contends that the
alternative name better reflects the fact that the services are needed
in the broader context of allowing control areas, transmission
customers, and other operating entities to operate reliably and
equitably.
---------------------------------------------------------------------------
\350\ A control area is part of an interconnected power system
with a common generation control system. It may contain one or
several utilities. The operator of the control area is responsible
for balancing generation and load and for maintaining reliable
system operation.
---------------------------------------------------------------------------
Some commenters propose a greater number of ancillary services.
They argue that the services we proposed can be broken down into more
discrete functions. A number of commenters provide rather lengthy lists
of possible ancillary services to supplement those identified in the
NOPR.351
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\351\ E.g., Oak Ridge, Houston L&P, Carolina P&L, NYPP.
---------------------------------------------------------------------------
NERC identifies twelve services, which it groups into three broad
categories: interchange scheduling services, generation services, and
transmission services. NERC's proposed interconnected operations
services are:
(a) interchange scheduling services:
(1) System control and dispatch services; and
(2) Accounting;
(b) generation services:
(1) Regulation service;
(2) Energy imbalance service;
(3) Frequency response service;
(4) Backup supply service;
(5) Operating reserve service: spinning reserve and supplemental
reserve services;
(6) Real power loss service;
(7) Reactive supply (from generation resources) and voltage control
service; and
(8) Restoration service; and
(c) Transmission services:
(1) Facilities use; and
(2) Reactive supply (from transmission resources).
NERC also identifies dynamic scheduling as a unique type of
dispatch service that control areas must have responsibility over to
ensure reliability.
Houston L&P proposes a substitute list of twenty services. NYPP
proposes a substitute list of thirty-eight ``unbundled components for
transmission service,'' which include twelve generation-related
services and twenty-six operations-related services. Oak Ridge
recommends that the Commission consider using seven ancillary services,
which closely conform to the six services described in the
NOPR.352 Although Oak Ridge identifies several additional
ancillary services, it recommends that these services not be included
in the list of services to be required because they cannot be measured
or because the cost
[[Page 21581]]
of metering and billing outweighs the cost of these services.
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\352\ Oak Ridge originally identified nineteen ancillary
services, which included a recommended separation of the six NOPR
ancillary services into twelve services and seven additional new
services.
---------------------------------------------------------------------------
Commission Conclusion
We will adopt NERC's recommendations for definitions and
descriptions with modifications. Starting with NERC's Interconnected
Operations Services, we identify some of these as ancillary services
that must be offered with basic transmission service under an open
access transmission tariff.353 The definitions developed by NERC
for the individual services reflect the current position of a broad
spectrum of experts on the subject of interconnected operations.
Adoption of NERC's terminology will provide a more universally accepted
set of definitions of services. We will retain the term ``ancillary
services,'' which will refer to those interconnected operations
services that we will require transmission providers to include in an
open access transmission tariff.
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\353\ NERC indicates that the list of services is a work in
progress and therefore may not be a complete list. NERC has formed
an independent Interconnected Operations Services Working Group
(Working Group). The Working Group includes representatives with a
broad range of industry interests (transmission-dependent, partial
requirements, IPP, transmission-owning, public power). We encourage
this effort and will consider future changes to the list of
ancillary services or their descriptions to reflect the further
development of concepts in this area.
---------------------------------------------------------------------------
The interconnected operations services identified by NERC
incorporate all of the ancillary services proposed in the NOPR. We
believe, however, that several of the individual services identified by
NERC do not warrant classification as unbundled ancillary services due
to the small cost involved (e.g., accounting). NERC also has identified
services that, while capable of being provided in the context of
integrated operations, are more appropriately provided for in a
separate service agreement or other contractual arrangement (e.g.,
dynamic scheduling, loss compensation service). NERC and others have
attempted to identify all interconnected operation services that could
be provided by a control area. The thoroughness of the comments
received on this issue has been invaluable to the Commission's
deliberations.
We will require that an open access transmission tariff include the
six ancillary services that we have identified as necessary for the
transmission provider to offer to transmission customers. These are
needed to accomplish transmission service while maintaining reliability
within and among control areas affected by the transmission service.
Other interconnected operations services, such as loss compensation
service, may be provided by the transmission provider or third parties
to facilitate a particular transaction or operating arrangement. We
will not require other interconnected operations services as part of an
open access transmission tariff. If a transmission provider supplies
such services voluntarily, they may be added to a customer's service
agreement with the transmission provider.
As mentioned, we will adopt NERC's definitions with modifications,
and we name and describe the six ancillary services below. After each
service name, we list in parenthesis the service name in the NOPR that
most closely corresponds to the service defined. In the discussion, we
explain whether and how we modified NERC's term.
a. The Six Ancillary Services
(1) Scheduling, System Control and Dispatch Service (in the NOPR:
Scheduling and Dispatching Service)
Comments
NERC proposes a System Control and Dispatch Service, which provides
for (i) interchange schedule confirmation and implementation with other
control areas, including intermediary control areas that are providing
transmission service, and (ii) actions to ensure operational security
during the interchange transaction. A transmission customer may
schedule interchange with another control area operator or with another
entity inside another control area; however, the control area operators
are responsible for confirming and implementing the interchange into or
out of their respective areas on behalf of the transmission customer.
NERC also proposes a separate Accounting Service, which provides
for energy accounting and billing services associated with interchange.
Accounting Service would be provided by the operator of the control
area in which the transmission service takes place.
Commission Conclusion
We adopt ``Scheduling, System Control and Dispatch'' as the name
for an ancillary service. It substitutes for the NOPR's Scheduling and
Dispatching Service.
The name is NERC's recommendation with two modifications. First, we
include the term ``scheduling'' in the name of this service because a
control area operator/transmission provider must take on the function
of scheduling on behalf of customers. Second, we will not require
Accounting as a separate ancillary service. The purpose of separating
accounting as a stand-alone service would be to allow customers to take
it separately from scheduling and system control. However, we believe
that accounting for scheduling, system control and dispatch is not
separable from these other functions and that accounting costs are
likely to be small. Therefore, accounting does not warrant separate
service status. The cost of accounting for these services should be
included in the cost of Scheduling, System Control and Dispatch
Service.
(2) Reactive Supply and Voltage Control From Generation Sources Service
(Formerly Reactive Power/Voltage Control Service)
Comments
A number of commenters explain that reactive power and voltage
control service is integrally related to the reliable operation of the
transmission system. These commenters also note that reactive power and
voltage support must be supplied at the location where it is
needed.354 It cannot be provided by a distant supplier.355
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\354\ See, e.g., APPA.
\355\ E.g., EEI, NERC, NYSEG, FPL, NSP.
---------------------------------------------------------------------------
NERC indicates that reactive supply is necessary to maintain the
proper transmission line voltage for the transaction. NERC states that
reactive supply is provided from both generation resources and
transmission facilities (e.g., capacitors), and lists its provision as
two services, distinguished by the facilities that supply them.356
NERC further distinguishes reactive supply service based on the source
of the need for the service: (1) Reactive supply needed to support the
voltage of the transmission system and (2) reactive supply needed to
correct for the reactive portion of the customer's load at the delivery
point.
---------------------------------------------------------------------------
\356\ See also APPA.
---------------------------------------------------------------------------
Commission Conclusion
We adopt ``Reactive Supply and Voltage Control from Generation
Sources'' as the name for an ancillary service. It substitutes for the
NOPR's Reactive Power/Voltage Control Service.
We accept NERC's identification of two ways of supplying reactive
power and controlling voltage. One is to install facilities, usually
capacitors, as part of the transmission system. We will consider the
cost of these facilities as part of the cost of basic transmission
service. Providing reactive power and voltage control in this way is
not a separate ancillary service.
The second is to use generating facilities to supply reactive power
and voltage control. This use is the service
[[Page 21582]]
named here, which must be unbundled from basic transmission service.
We note, however, that customers have the ability to reduce (but
not eliminate completely) the reactive supply and voltage control needs
and costs that their transactions impose on the transmission provider's
system. For example, customers who control generating units equipped
with automatic voltage control equipment can use those units to respond
to local voltage requirements and thereby reduce a portion of the
reactive power requirements associated with their transaction.357
---------------------------------------------------------------------------
\357\ The ability to reduce reactive power requirements will be
affected by the location and operating capabilities of the
generator. Any arrangement for the customer to self-supply a portion
of reactive supply should be specified in the transmission
customer's service agreement with the transmission provider.
---------------------------------------------------------------------------
In addition, transmission customers that serve loads can minimize
the reactive power demands that they impose on the transmission system
by maintaining a high power factor at their delivery points. A poor
power factor at a customer's delivery point creates a need for either
transmission reactive facilities (i.e., capacitors) or local generator-
supplied voltage support.358
---------------------------------------------------------------------------
\358\ Transmission providers may propose delivery point power
factor standards, including additional (penalty) charges for failure
to maintain specified power factors, in service agreements with
customers. We will evaluate the reasonableness of any such proposals
by public utilities to determine whether they conform to prudent
utility practices and are comparable to requirements imposed by the
utility on other customers, including the utility's own requirements
customers, and are otherwise just and reasonable.
---------------------------------------------------------------------------
However, these transmission customer actions do not eliminate
entirely the need for generator-supplied reactive power. The
transmission provider must provide at least some reactive power from
generation sources. For this reason, and because a transmission
customer has the ability to affect the amount of reactive supply
required, we will require that reactive supply and voltage control
service be offered as a discrete service, and to the extent feasible,
charged for on the basis of the amount required.359
---------------------------------------------------------------------------
\359\ Separation of reactive supply and voltage control from
basic transmission service also may contribute to the development of
a competitive market for such service if technology or industry
changes result in improved ability to measure the reactive power
needs of individual transmission customers or the ability to supply
reactive supply from more distant sources. We recognize that these
capabilities may not be fully developed at present and the ability
to distinguish the reactive power needs of individual customers may
be limited at first to generator control and power factor
correction.
---------------------------------------------------------------------------
(3) Regulation and Frequency Response Service (in the NOPR: Load
Following Service)
Comments
Someone must supply extra generating capacity, called regulating
margin, to follow the moment-to-moment variations in the load located
in a control area. Following load variations is necessary to maintain
scheduled interconnection frequency at sixty cycles per second (60 Hz).
NERC and others support the need for someone to provide load
following service to have generation follow a transmission customer's
load changes; someone must supply power to meet any difference between
a customer's actual and scheduled generation. Usually, the control area
operator provides this service, but it is possible for a customer to
arrange for someone else to follow its variations in load.
Many commenters indicate that the industry commonly refers to this
service as ``Regulation Service.'' 360
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\360\ E.g., NERC, EEI, Florida Power Corp.
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Also, NERC proposes that Frequency Response Service be identified
as a related but distinct service. NERC indicates that all control
areas are expected to have generation and control equipment to respond
automatically to frequency deviations in their networks.
Commission Conclusion
We adopt ``Regulation and Frequency Response'' as the name of an
ancillary service. It substitutes for the NOPR's Load Following
Service. This name conforms to the terminology recommended by NERC.
We conclude that Regulation Service and Frequency Response Service
are the same services that make up the Load Following Service
referenced in the NOPR. While the services provided by Regulation
Service and Frequency Response Service are different, they are
complementary services that are made available using the same
equipment. For this reason, we believe that Frequency Response Service
and Regulation Service should not be offered separately, but should be
offered as part of one service.
(4) Energy Imbalance Service (the Same in the NOPR)
Comments
Many commenters explain that Energy Imbalance Service, as proposed
in the NOPR, is necessary when transmission service is provided in a
control area that contains the load being served.361 Energy
Imbalance Service supplies any hourly mismatch between a transmission
customer's energy supply and the load being serving in the control
area. That is, this service makes up for any net mismatch over an hour
between the scheduled delivery of energy and the actual load that the
energy serves in the control area. In contrast, Regulation and
Frequency Response Service corrects for instantaneous variations
between the customer's resources and load, even if over an hour these
variations even out and require no net energy to be supplied.
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\361\ E.g., NERC, EEI.
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Commission Conclusion
We will adopt ``Energy Imbalance'' as the name for an ancillary
service. This is the same name proposed in the NOPR. NERC's description
is the same as the service proposed in the NOPR.
(5) Operating Reserve--Spinning Reserve Service and
(6) Operating Reserve--Supplemental Reserve Service (in the NOPR These
Two Were Formerly System Protection Service)
Comments
Many commenters express confusion regarding the NOPR term ``system
protection.'' They indicate that the term ``system protection,'' is
described in the NOPR as furnishing operating reserve, but has another
meaning in the industry.362
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\362\ E.g., EEI, Florida Power Corp, TVA, Wollenberg.
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Operating reserve is extra generation available to serve load in
case there is an unplanned event such as loss of generation. Generation
held for operating reserve should be located near the load, typically
in the same control area. Operating reserve amounts are set by the
region, subregion, or a reserve sharing group in which the transmission
customer's load is electrically located.
NERC and other commenters recommend the commonly-used name,
``operating reserve,'' for this service. NERC also indicates that there
are two types of operating reserve: spinning reserve and supplemental
reserve.
Spinning reserve is provided by generating units that are on-line
and loaded at less than maximum output. They are available to serve
load immediately in an unexpected contingency, such as an unplanned
outage of a generating unit.
Supplemental reserve is also generating capacity that can be used
to respond to contingency situations. Supplemental reserve, however, is
not available instantaneously, but rather within a short period
(usually ten
[[Page 21583]]
minutes). Supplemental operating reserve is provided by generating
units that are on-line but unloaded, by quick-start generation, and by
customer-interrupted load, i.e., curtailing load by negotiated
agreement with a customer to correct an imbalance between generation
and load rather than increasing generation output.
Commission Conclusion
We adopt Operating Reserve--Spinning Reserve Service and Operating
Reserve--Supplemental Reserve Service as the names of two related, but
distinct, ancillary services. They substitute for a single ancillary
service in the NOPR, System Protection Service. The names conform to
the terminology recommended by NERC. We distinguish them because these
services may be subject to different reliability requirements; the
resources that supply each service may not be the same; and the two
services may be provided by different suppliers.
b. Other Services Discussed in the NOPR
Commenters discussed whether two other services that were discussed
in the NOPR should be designated as ancillary services.363
Although we do not designate these as ancillary services for purposes
of this Rule, we discuss the names and descriptions here so that we can
discuss our policy regarding these services.
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\363\ In addition, NERC designates ``facilities use service'' as
an interconnected operations service. We note that the facilities
use service described by NERC is simply basic transmission service,
which must be provided under an open access tariff. We do not
consider facilities use service to be an ancillary service.
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(1) Real Power Loss Service (in the NOPR: Loss Compensation Service)
In the NOPR, we proposed that Loss Compensation be an ancillary
service.
Comments
NERC recommends the term, ``Real Power Loss,'' to refer to energy
consumed in transmission, much of it by resistance heating o
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
f the lines
and transformers. Many parties, including NERC, comment that there are
a number of ways to compensate the transmission provider for the losses
that occur in providing transmission service. They indicate that real
power loss service can be obtained from a variety of sources, such as
the power supplier, the customer, a third-party, the transmission
provider, or another control area. Also, the loss is commonly accounted
for by a transmission customer receiving less energy at the point of
delivery than it provides to the transmission provider at the point of
receipt. The difference between delivered and received energy can be
set equal to the energy lost in transmission.
Commission Conclusion
We adopt the term ``Real Power Loss'' as the name of this
interconnected operations service. It substitutes for the Loss
Compensation service described in the NOPR. This name conforms to the
terminology recommended by NERC.
Although proposed as an ancillary service in the NOPR, we will not
require that Real Power Loss be included as an ancillary service in an
open access transmission tariff. It is not necessary to require the
transmission provider to supply energy losses to the transmission to
ensure comparable transmission access. Real Power Loss is more
appropriately an interconnected operations service that transmission
providers may offer voluntarily to provide to transmission customers.
It is not necessary for the transmission provider to supply Real
Power Loss to effect a transmission service transaction. The
transmission provider is not uniquely situated to provide Real Power
Loss service to its customers, nor does it have a comparative advantage
over anyone in providing such a service. Indeed, to require the
transmission provider to provide this service would effectively
obligate the transmission provider to engage in a sale of power when
such a sale is not needed to effect the transmission service
transaction.
As noted in the comments, customers have several options to cover
losses that occur when electricity moves across transmission
facilities.364 The availability of open access permits the
customer to obtain energy losses from many regional suppliers.
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\364\ See, e.g., Portland, APPA, PacifiCorp, EEI.
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Although we will not require the transmission provider to supply
Real Power Loss to the transmission customer nor require the customer
to purchase it from the transmission provider, the customer must make
provision for Real Power Loss. It cannot take basic transmission
service without such a provision. A customer seeking transmission
service must bring to the transaction sufficient energy and capacity to
replace the losses associated with its intended transaction.365
Consequently, we will require that the transmission customer's service
agreement with the transmission provider identify the party responsible
for supplying real power loss. In addition, we will require that the
transmission provider indicate, either in its tariff or on its OASIS,
what the energy and capacity loss factors would be for any transmission
service it may provide so that potential customers will know the amount
of losses to replace.
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\365\ If a transmission provider does not charge for
transmission used to supply losses for its own wholesale power sales
and purchases, it may not charge others. If it charges others, it
must charge for its own uses.
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(2) Dynamic Scheduling (the Same in the NOPR)
In the NOPR's discussion of Scheduling and Dispatch Service, we
pointed out that dynamic scheduling is possible in some regions. We
asked for comments on whether we should require dynamic scheduling as
an ancillary service, given the complexity of the service.
Comments
Most commenters would not have us require Dynamic Scheduling as an
ancillary service.366 Dynamic scheduling provides the metering,
telemetering, computer software, hardware, communications, engineering,
and administration required to allow remote generators to follow
closely the moment-to-moment variations of a local load. In effect,
dynamic scheduling electronically moves load out of the control area in
which it is physically located and into another control area.
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\366\ E.g., Detroit Edison, El Paso, FPL, Minnesota P&L, NIPSCO.
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Commission Conclusion
We adopt the name Dynamic Scheduling Service, but we will not
designate it as an ancillary service that must be included in an open
access transmission tariff.
In the NOPR, we noted that Dynamic Scheduling could be used in a
transmission transaction if it is technically feasible to do so without
adversely affecting reliability. We did not propose in the NOPR that
Dynamic Scheduling be named an ancillary service. Although Dynamic
Scheduling is closely related to Scheduling, System Control and
Dispatch Service, it is a special service that is used only
infrequently in the industry. It uses advanced technology and requires
a great level of coordination. Each Dynamic Scheduling application has
unique costs for special telemetry and control equipment, making it
difficult to post a standard price for the service.
Consequently, we will not require that the transmission provider
offer Dynamic Scheduling Service to a transmission customer, although
it may do so voluntarily. If the customer wants to
[[Page 21584]]
purchase this service from a third party, the transmission provider
should make a good faith effort to accommodate the necessary
arrangements between the customer and the third party for metering and
communication facilities.
c. Other Services Not Discussed in the NOPR
Comments
Some commenters identified several other services that were not
discussed in the NOPR, which they recommend we require to be provided
as ancillary services.367 Examples are emergency power,
supplemental power, and inadvertent power.
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\367\ E.g., NERC, Carolina P&L, Oak Ridge, Houston L&P.
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Commission Conclusion
We believe that these other services generally refer to either (1)
generation services that are not related to providing transmission or
(2) a subpart of a service discussed above, the cost of which is not
easily separable from the other service. Consequently, we will not name
any of these services as an ancillary service that a transmission
provider will be required to offer separately under an open access
transmission tariff. However, generation-related services may be
offered voluntarily to the transmission customer.
We discuss below two of these proposed generation-related ancillary
services, which NERC included among its proposed interconnected
operations services.
(i) Backup Supply Service
Comments
NERC explains that Backup Supply is electric generating capacity
and energy that is provided to the transmission customer as needed (1)
to replace the loss of its generation sources and (2) to cover that
portion of the customer's load that exceeds its generation supply for
more than a short time. NERC notes that Backup Supply Service is a
long-term service, which distinguishes it from Operating Reserve
Service and Energy Imbalance Service. Backup Supply service replaces
temporary use of operating reserves; it serves load after operating
reserves are returned to standby mode to maintain operating reserves at
required levels. Backup Supply may last for hours, weeks, or longer.
NERC indicates that a transmission customer could reduce its need for
backup supply service by using interruptible load control or active
demand-side management control, or both.
Commission Conclusion
We accept the term ``Backup Supply'' as the name for this
interconnected operations service, but we will not require this service
as an ancillary service under an open access transmission tariff.
Backup Supply Service is not required for comparable open access
transmission service.
Backup Supply Service is an alternative source of generation that a
customer can use in the event its primary generation source becomes
unavailable for more than a few minutes. Although we believe that the
two short-term operating reserve services (spinning and supplemental)
are necessary to support transmission, we conclude that long-term
service is not necessary. Backup Supply is a generation service that
may reasonably be viewed as the responsibility of the transmission
customer, who may contract for backup service or curtail load.
We will impose no obligation on the transmission provider to
provide power to the customer for a time longer than specified in the
tariff for the customer's own backup power supply to be made available.
The transmission provider is obligated to protect against emergencies
for a short time; it has no obligation to furnish replacement power on
a long-term basis if the customer loses its source of supply. The
transmission provider has no obligation to provide power for the weeks
necessary for unit maintenance, for example.
The transmission provider is not uniquely situated to provide
Backup Supply Service to its transmission customers, nor does it have a
comparative advantage over others in providing such service. Moreover,
as Backup Supply Service may require substantial amounts of generation
capability, it is inappropriate to require the transmission provider to
assume significant generation responsibilities as we functionally
unbundle transmission from generation.
Although the transmission provider will not be required to offer
this service to transmission customers, it may offer voluntarily to
provide Backup Supply Service to its transmission customers. Any
arrangements for the supply of such service by the transmission
provider should be specified in the customer's service agreement.
(ii) Restoration Service
Comments
NERC states that Restoration Service provides facilities and
procedures to enable (1) a transmission provider to restore its system
and (2) a transmission customer to start its generating units or
restore its loads if local power is unavailable. Other commenters refer
to Restoration Service as Blackstart Service, which may be provided by
the operator of the host control area, another control area operator,
or another generation supplier.368
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\368\ E.g., Atlantic City, Oak Ridge.
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According to NERC, close coordination with the host control area
operator is absolutely necessary during system restoration operations.
Under current industry practice, each control area operator is
responsible for implementing a restoration plan in coordination with
non-control area utilities as well other power producers. Many large
generating units require startup power to restart after being out of
service. Startup power may be provided, for example, by self-contained
diesel engine generator sets located at a generating plant. If electric
power is not available from the grid, some and perhaps many plants must
obtain the necessary power from their auxiliary generators to restart
plants and return the grid voltage to the proper level. Other
generators without blackstart capability may rely on power from the
grid to restart, once the grid is energized by others. NERC notes,
however, that it may be inappropriate to rely completely on power from
the grid for restart power because power from the grid may be
unavailable or insufficient. Consequently, at least some power plants
must have internal auxiliary power sources.
Commission Conclusion
We accept the term ``Restoration'' as the name for this
interconnected operations service. We will not require the transmission
provider to offer Restoration Service as a separate ancillary service
in an open access transmission tariff.
Comments on Restoration Service appear to describe two services,
blackstart service and planning for system restoration. Presumably,
each utility and power producer will do its part through voluntary
coordination and self-interest to ensure a reliable and adequate source
of startup power for its generating units. We will not require a
transmission provider to provide blackstart capability to transmission
customers. Generators without blackstart capability can instead
purchase blackstart power from any power supplier connected to the grid
at an appropriate power price, if such service is available after a
contingency is corrected.
[[Page 21585]]
The obligation to plan for restoration capability is a system
control area function that rests with the transmission provider and the
operator of the control area in which the transmission provider is
located. The transmission provider (or its associated control area
operator) generally makes arrangements with enough generators to
provide the system with this capability at strategic locations on the
transmission system. Thus, restoration planning is intrinsic to the
transmission provider's basic transmission service and included in its
cost.
2. Obligations of Transmission Providers and Transmission Customers
With Respect to Ancillary Services
In the NOPR, the Commission proposed that public utilities required
to file open access transmission tariffs also be required to provide
unbundled ancillary services to transmission customers. Although the
NOPR included a list of ancillary services to be offered by
transmission providers, the NOPR did not indicate whether a customer
must take basic transmission service from the transmission provider to
be eligible to require the transmission provider to supply ancillary
services. Comments on these issues are summarized below.\369\
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\369\ Some commenters suggest that transmission providers be
required to provide, or transmission customers be required to
purchase or self-supply, certain services other than the six
ancillary services that we will require to be included in an open
access transmission tariff. Because we will not require the
transmission provider to offer any services other than basic
transmission service and the six ancillary services, comments on
requirements to provide or take other services are not included in
the summary.
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Comments
Several commenters \370\ distinguish generation-related ancillary
services from others. Generation-related services are those that
require the provider to have extra generating capacity or to provide
electric energy. The remaining ancillary services are called
transmission-related services or control area services. Transmission-
related services would involve, for example, voltage support from
transmission facilities. An example of a control area service is system
control and dispatch. Commenters do not agree on how each service
should be classified.
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\370\ E.g., NERC, Tallahassee, IL Com.
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Many commenters state that only control area operators should be
allowed to offer certain ancillary services, such as scheduling, system
control and dispatch.\371\ They believe that otherwise reliability
might suffer.
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\371\ E.g., BG&E, Minnesota P&L, Florida Power Corp.
---------------------------------------------------------------------------
Minnesota P&L states that certain ancillary services (e.g. reactive
power from generators, load following, frequency control) should be
provided exclusively by the operator of the control area where the load
resides.\372\ Minnesota P&L indicates that obtaining these services
externally could jeopardize reliability. Several commenters claim that
a control area operator must provide the scheduling, system control and
dispatch service and reactive power supply service (except in cases
where the customer's load is very close to the generating source).\373\
Numerous commenters indicate that load following (now called Regulation
and Frequency Response Service) generally is provided only by a control
area operator.\374\
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\372\ See also Florida Power Corp and Montana Power.
\373\ E.g., Carolina P&L, Texas Utilities, NERC, PSE&G.
\374\ E.g., SCE&G, Montana Power, NIPSCO, EEI, PacifiCorp. EEI
and PacifiCorp indicate that dynamic scheduling of load following
service is an exception to the general practice of the control area
operator providing load following service.
---------------------------------------------------------------------------
EEI and other commenters state that energy imbalance service must
be provided by either the control area operator or some other entity
that is in the control area where the customer's load is located and
has real-time response capability.\375\ NYSEG points out that
transmission providers generally are also control area operators and
thus automatically provide energy imbalance service to maintain
interchange flows and control area reliability. For this reason, NYSEG
believes it is important that this service remain a responsibility of
the transmission provider.
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\375\ E.g., Montana Power, TDU Systems.
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SC Public Service Authority contends that ancillary services can be
provided only by an entity large enough to operate at a NERC regional
scale. It states that ancillary services protocols must be established
regionally to support regional transmission services.
Other commenters disagree. They argue that all the generation-
related ancillary services identified in the NOPR can be obtained from
sources other than the transmission provider.\376\ American Wind
believes the ability of a transmission customer to self-supply
ancillary services or purchase them from a third party will help to
curb inflated prices for such services. Southwest TDU Group also claims
that permitting entities outside the transmission provider's control
area to provide ancillary services will enhance competition and reduce
the need for Commission oversight of charges for ancillary services.
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\376\ E.g., Tallahassee, Wisconsin Municipals, IL Com.
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A majority of commenters support the view that the transmission-
providing public utility should provide ancillary services. Many
commenters do not discuss the services individually but present their
views generally on the provision of ancillary services. Missouri-Kansas
Industrials and CCEM support a requirement that utilities make
ancillary services available through a tariff. They argue that, from a
customer's point-of-view, it is extremely critical that a transmission
provider be required to furnish these services under a regulated,
nondiscriminatory, cost-based tariff format. NIEP argues that, until a
fully competitive market for ancillary services develops, transmitting
utilities should be obligated to provide or arrange for any and all of
the NOPR ancillary services, to the extent that the transmission
customer desires such services. Direct Service Industries emphasizes
that a transmission provider should be required to provide any
ancillary service that it is capable of supplying. Direct Service
Industries and Utilities For Improved Transition claim that open access
tariffs should state clearly that the transmission provider must secure
ancillary services for a transmission customer if the transmission
provider is not able to provide these services itself. Large Public
Power Council contends that, during the transition to a competitive
market for generation-related ancillary services, transmission
providers should be required to provide all ancillary services related
to generation that existing customers now take on a bundled basis. OH
Com notes that transmission owners, by virtue of their position as
transmission owners, are necessarily the providers of last resort for
certain ancillary services. OH Com therefore believes that only
transmission providers should provide ancillary services.
Several non-IOU, transmission-owning commenters, however, urge that
the Commission not require transmission providers to provide ancillary
services that they cannot physically supply, i.e., if they lack
sufficient generation, lack control area facilities, or have slow-
responding generating units.\377\ NRECA and TDU Systems also state that
many cooperatives and transmission
[[Page 21586]]
dependent systems presently obtain ancillary services from control area
utilities under specific contract terms. Consequently, if their member
systems are asked to provide transmission service, they may not be able
to take on the obligation to secure ancillary services under their
existing contracts for transmission customers. Soyland and Pacific
Northwest Coop argue that a transmission provider should not be
required to supply services that it does not provide to its native
load.
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\377\ E.g., OVEC, OG&E, Memphis, Nebraska Public Power, TDU
Systems, TANC, San Francisco, Brazos.
---------------------------------------------------------------------------
Most IOU commenters and others oppose a requirement that the
transmission provider be obligated to provide generation-related
ancillary services. They offer the following reasons: (1) The need for
such services differs from one transaction to the next; (2) a
transmission provider is neither uniquely qualified to provide these
services, nor is it essential that such provider be the one providing
these services in order to effect a transaction; (3) until it is
demonstrated that these services cannot be obtained from a source other
than the transmission provider, it is inappropriate to require
transmission providers to supply such services; and (4) a transmission
provider should have no residual obligation as a provider of last
resort to plan its system to have generating resources available for
the supply of ancillary services.\378\ IL Com also contends that
utilities should not be required to provide generation-related
ancillary services under general transmission service tariffs if such
services can be obtained from the bulk power market.
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\378\ E.g., PSNM, Atlantic City, Centerior, UWG, Texas
Utilities, Entergy, LG&E, Montana Power, FPL, United Illuminating,
Large Public Power Council, Christensen.
---------------------------------------------------------------------------
Other IOU commenters argue that there is a fundamental
inconsistency between an obligation to provide or obtain ancillary
services for customers and the NOPR's unbundling requirement. For
example, BG&E claims that it is inconsistent to require the traditional
vertically integrated utility to functionally unbundle and also to
remain responsible for providing at cost-based rates what should be
competitively-priced generation services. Florida P&L and other IOU
commenters argue that providing generation-related ancillary services
effectively imposes the load-serving obligation of the transmission
customer on the transmission provider.
However, some IOU commenters contend that the transmission provider
or its agent should be required to provide certain ancillary
services.\379\ NIPSCO and PacifiCorp believe that load following (now
called Regulation and Frequency Response Service) should be provided
only by the transmitting utility, especially if the customer's load and
resources are located in the control area operated by the transmitting
utility. EEI contends that a third-party generator should have the
opportunity to provide regulation service if it resides in the
transmission provider's control area and coordinates its actions with
the control area operator.
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\379\ E.g., NIPSCO, PacifiCorp, Orange & Rockland, Allegheny,
NYSEG, EEI.
---------------------------------------------------------------------------
IN Com and NY Com recommend that the Commission provide flexibility
in assessing responsibility for the supply of ancillary services. MN
DPS recommends that an individual transmission provider should not be
required to file an individual tariff for ancillary services if it is a
member of an RTG whose tariffs adequately cover the same services.
EEI contends that a control area utility should not be required to
provide ancillary services to a third party outside its control area.
EEI also argues that, if the transmission provider is not a control
area, it should not be required to procure ancillary services from a
control area on behalf of a third party seeking service over its
system. Rather, the third party should be responsible for procuring the
ancillary services it needs. Other IOU commenters argue that the
responsibility to acquire ancillary services belongs to the
transmission customer, not the transmission provider.380
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\380\ E.g., BG&E.
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Many IOU commenters express concern that ancillary services be
offered and taken on a symmetrical basis, i.e., if transmission
providers are uniquely situated to provide the service, customers
should likewise be required to take and pay for the service from such
transmission providers.\381\ BG&E claims that it is patently unfair to
give third-party users the option not to purchase ancillary services
that the transmission provider must offer. BG&E argues that, if
transmission providers have an obligation to provide ancillary
services, equity dictates that transmission customers have a
corresponding obligation to take those services or compensate
transmission providers for the costs associated with the unused
capabilities. United Illuminating argues that the requirement to
provide service without a corresponding obligation to purchase service
unfairly burdens the transmission provider and skews competition in
favor of transmission customers.
---------------------------------------------------------------------------
\381\ E.g., CSW, BG&E, ConEd, United Illuminating, Ohio Edison,
Atlantic City, Centerior, SoCal Edison, Duke, EEI.
---------------------------------------------------------------------------
Other non-IOU commenters oppose a symmetric obligation to provide
and purchase particular ancillary services.\382\ Ontario Hydro and
others claim that the customer should decide on a case-by-case basis
which ancillary services it needs to purchase.
---------------------------------------------------------------------------
\382\ E.g., RUS, TDU Systems, DE Muni.
---------------------------------------------------------------------------
BPA and BG&E assert that transmission providers should be able to
require that the party receiving the power, which may not be the
transmission customer, be responsible for acquiring ancillary services.
This would allow the transmission provider to establish the appropriate
contractual arrangements with the party that is actually receiving the
energy and avoid shifting responsibility to a party that is merely
arranging the transmission service.
A number of IOU commenters express concern that customers may
``lean'' on a transmission provider's system for ancillary services.
That is, they worry that the transmission customer may not purchase an
ancillary service but nevertheless rely on the transmission provider to
provide it. Commenters propose various remedies to address this
concern. NIEP, Dayton P&L and others argue that the Commission should
require that, as a prerequisite to basic transmission service, the
transmission customer has either arranged to obtain ancillary services
from the transmission provider or has demonstrated it has an
arrangement with an alternative supplier that is reliable and
sufficient to satisfy the ancillary service needs associated with the
transmission service transaction. NYPP believes that, if the customer's
method of providing ancillary services does not meet the standards of
the transmission provider, the transmission provider should be able to
require that the transmission customer find another ancillary service
supplier or purchase the service directly from the transmission
provider at its tariff rates.\383\ EEI proposes that penalties be
permitted as a backstop if the market cannot resolve the ``leaning''
problem. VEPCO suggests that utilities should have the option to
require customers to maintain backup supply reserves.
---------------------------------------------------------------------------
\383\ See also NYSEG, Ohio Edison.
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Commission Conclusion
The NOPR proposed that six ancillary services be included in an
open access transmission tariff. Some commenters interpret the NOPR to
require that transmission providers make a ``universal'' offer of
unbundled ancillary
[[Page 21587]]
services, i.e., an offer to any transmission customer regardless of
location and whether the transmission customer would also be taking
basic transmission service from the supplier of ancillary
services.\384\ Such interpretation is incorrect; it goes beyond what is
required for comparability. These services are required to be provided
only to customers taking basic transmission service. However,
transmission providers may offer these services on a voluntary basis to
other customers if technology permits.
---------------------------------------------------------------------------
\384\ E.g., PSNM, Atlantic City, Centerior, Texas Utilities,
Entergy, FPL, Utility Working Group.
---------------------------------------------------------------------------
Transmission through or out of a control area requires fewer
ancillary services from the operator of the control area than
transmission within or into a control area to serve loads in the
control area. If the requested transmission service transaction
involves more than one control area, i.e., the receipt point and
delivery point of transmission service are located in different control
areas, certain ancillary services will be needed only in the control
area where the transmission customer's load is located.
We will distinguish two groups or categories of ancillary services:
(1) Services that we will require the transmission provider to provide
to all its basic transmission customers, and (2) services that we will
require the transmission provider to offer to provide only to
transmission customers serving load in the provider's control area. The
first group is comprised of (i) Scheduling, System Control and Dispatch
and (ii) Reactive Supply and Voltage Control from Generation Services.
The second group is comprised of (i) Regulation and Frequency Response,
(ii) Energy Imbalance, (iii) Operating Reserve--Spinning, and (iv)
Operating Reserve--Supplemental.
With respect to the first group of ancillary services, we conclude
that the transmission provider that operates a control area is uniquely
positioned to provide these services. Thus, as stated above, we will
require the transmission provider that operates a control area to
provide these ancillary services. We will also require that the
transmission customer purchase these services from the transmission
provider, as explained in the next section.
With respect to the second group of ancillary services, we conclude
that the transmission provider is not always uniquely positioned to
provide these services, although in many cases it may be the only
practical source. Thus, we will require the transmission provider to
offer to provide the ancillary services in the second group to
transmission customers serving load in the transmission provider's
control area. We also will require the transmission customer serving
load in the transmission provider's area to acquire these services, but
it may do so from the transmission provider, a third party or self-
supply. These ancillary services must be provided by someone if the
system is to be operated reliably; the customer may not decline the
transmission provider's offer of ancillary services unless it
demonstrates that it has acquired the services from another source. The
transmission provider may require the customer to decide which of these
ancillary services it will purchase from the transmission provider when
it applies for basic transmission service.
If the transmission provider is a public utility providing basic
transmission service but is not a control area operator, it may be
unable to provide some or all of the ancillary services we require
without substantial investment. In this case, we will allow the
transmission provider to fulfill its obligation to provide, or offer to
provide, ancillary services by acting as the customer's agent. We will
require the transmission provider to offer to act as agent for the
transmission customer to secure these services from the control area
operator.385 The customer may have the transmission provider act
as agent or may secure the ancillary services directly from the control
area operator. As stated above, the customer may also secure the second
group of ancillary service from a third party or by self-supply.
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\385\ The requirement to offer to act as agent is in lieu of the
requirement for the transmission provider to supply the ancillary
service to the transmission customer. Many commenters asked that we
not require the transmission provider to acquire the capacity to
provide ancillary services that it does not provide for itself but
acquires from its control area operator. E.g., EEI, NRECA, BPA, TDU
Systems.
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If the transmission provider is a public utility that is not a
control area operator, but its control area operator is a public
utility, the control area operator must offer to provide all ancillary
services to any transmission customer that takes transmission service
over facilities in its control area whether or not the control area
operator owns or controls the facilities used to provide the basic
transmission service.386
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\386\ If the transmission provider is a control area operator
but not a public utility, we can order transmission services only
upon application, pursuant to section 211 and 212 of the FPA.
However, the provision of transmission services by non-public
utilities would be necessary to satisfy the reciprocity condition in
public utilities' open access transmission tariffs.
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We discuss the requirement to supply and purchase each ancillary
service individually below.
a. Ancillary Services Required To Be Provided by Transmission Provider
for All of Its Transmission Customers
(1) Scheduling, System Control and Dispatch Service
We conclude that this service is necessary to the provision of
basic transmission service within every control area. As NERC and other
commenters point out, Scheduling, System Control and Dispatch Service
can be provided only by the operator of the control area in which the
transmission facilities used are located.387 This is because the
service is to schedule the movement of power through, out of, within,
or into the control area.
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\387\ E.g., Carolina P&L, Texas Utilities, PSE&G.
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(2) Reactive Supply and Voltage Control Service From Generation Sources
We conclude that this service is necessary to the provision of
basic transmission service within every control area. Because reactive
power cannot be transmitted for significant distances, the local
transmission provider has to supply reactive power from generation
sources. It is often uniquely situated to supply reactive power. The
transmission provider or the operator of the control area in which the
provider is located cannot avoid supplying it to the transmission
customer, and the transmission customer cannot avoid taking at least
some of this service from the transmission provider. Although a
customer is required to take this ancillary service from the
transmission provider or control area operator, it may reduce the
charge for this service to the extent it can reduce its requirement for
reactive power supply.
b. Ancillary Services Required To Be Offered Only to Transmission
Customers Serving Loads in the Transmission Provider's Control Area
(1) Regulation and Frequency Response
Regulation and Frequency Response Service is not required for
transmission out of or through the transmission provider's control
area. We conclude that this service must be offered only for
transmission within or into the transmission provider's control area to
serve load in the area. Customers may be able to satisfy the regulation
service obligation by providing generation with
[[Page 21588]]
automatic generation control capabilities to the control area in which
the load resides. Dynamic scheduling may also be used to electronically
``move'' a remote generating unit into the appropriate control area.
For customers to take advantage of these developments, a transmission
provider is required to identify the regulating margin requirements for
transmission customers serving loads in its control area and develop
procedures by which customers can avoid or reduce such requirements.
(2) Energy Imbalance
We conclude that Energy Imbalance service must be offered for
transmission within and into the transmission provider's control area
to serve load in the area.
Energy imbalance represents the deviation between the scheduled and
actual delivery of energy to a load in the local control area over a
single hour. A transmission customer can reduce or eliminate the need
for energy imbalance service in several ways. A customer can avoid
taking energy imbalance service if it controls generation with load-
following capabilities located in the control area. The Final Rule pro
forma tariff allows unlimited changes before the hour at no additional
charge to a customer's hourly schedule of energy deliveries to the
control area. By changing its schedule more frequently (based on
updated load information, for example), a customer can reduce or avoid
energy imbalance charges. Other customer options to reduce or avoid
energy imbalance charges include (i) establishing the load as a
separate control area island within the transmission provider's control
area with its own generation and load and (ii) removing the customer's
load from the transmission provider's control area through dynamic
scheduling.388
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\388\ Some of these options (e.g., establishing a separate
control area), while technically feasible, may be too costly or
otherwise inadvisable.
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(3) Operating Reserve--Spinning
(4) Operating Reserve--Supplemental
We conclude that Operating Reserve--Spinning and Operating
Reserve--Supplemental must be offered for transmission within and into
the transmission provider's control area to serve load in the control
area. Reserves should be located near load in case of unplanned
unavailability of generating units serving load in the control area. We
will permit transmission providers to rely upon prevailing regional
practices to set reserve criteria. Transmission providers are required
to facilitate efforts by customers to meet Operating Reserve
obligations with their own generating resources or from third-party
sources if they can satisfy the regional criteria.
If a customer uses either type of operating reserve, it must
expeditiously replace the reserve with backup power to reestablish
required minimum reserve levels.
3. Unbundling and Bundling Ancillary Services
a. Services That Can Be Bundled With Transmission Service
In the NOPR, the Commission proposed that transmission providers
should be required to offer ancillary services as discrete services,
unbundled from basic transmission service.
Comments
While most commenters support the approach to unbundling the
ancillary services proposed in the NOPR, a number of commenters argue
that, for technical and administrative reasons, certain services should
be bundled with basic transmission service. For example, some
commenters assert that Reactive Supply and Voltage Support service
should be bundled with basic transmission service.\389\ They argue that
this service is integrally related to the operation of the transmission
system, that it must be provided at or near the point of need, and that
its costs are difficult to isolate and account for.\390\ Other
commenters argue that scheduling and dispatch service, for similar
reasons, should be bundled with basic transmission service.\391\
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\389\ E.g., Carolina P&L, NYSEG, FPL, NSP, WP&L, Orange &
Rockland, Arizona, Salt River, SC Public Service Authority, Brazos,
NY Com.
\390\ See, e.g., Carolina P&L Initial Comments at 56.
\391\ See, e.g., CCEM, Carolina P&L, NYSEG, CINergy.
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A few commenters suggest that other services could be bundled with
the basic transmission service. For example, NYSEG identifies energy
imbalance service as a candidate for bundling. EEI identifies frequency
regulation and NYMEX identifies frequency control as services that
could be bundled with basic transmission service.
Some commenters believe that the Commission should allow utilities
to file transmission tariffs that bundle all necessary transmission and
ancillary services, at least as an interim measure.\392\
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\392\ E.g., UT Com, Washington and Oregon Energy Offices, WA
Com.
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On the other hand, other commenters believe that a greater level of
unbundling of transmission and ancillary services is necessary to
facilitate the development of competitive markets and to ensure that
transmission customers are able to purchase only the services they
require.\393\ Dayton P&L believes that all ancillary services should be
offered as discrete services with separate prices. Texas Utilities
asserts that generation-related ancillary services should be unbundled
and separately priced.
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\393\ E.g., Direct Service Industries, Mt. Hope Hydro.
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Commission Conclusion
Although commenters raise valid concerns, they do not provide a
compelling reason to require that our six ancillary services be bundled
with basic transmission service. We have, however, changed the proposal
in the NOPR to clarify that reactive supply and voltage support from
transmission resources is part of basic transmission service.
Unbundling ancillary services will promote competition and
efficiency in their supply. Because most generation-based ancillary
services potentially can be provided by many of the generators
connected to the transmission system, some customers may be able to
provide or procure such services more economically than the
transmission provider can. Once they are unbundled, a more competitive
market may emerge to supply such services.
Also, unbundling makes possible a more equitable distribution of
costs. Because customers that take similar amounts of transmission
service may require different amounts of some ancillary services,
bundling these services with basic transmission service would result in
some customers having to take and pay for more or less of an ancillary
service than they use. For these reasons, the Commission concludes that
the six required ancillary services should not be bundled with basic
transmission service.
With respect to the specific question of whether Reactive Supply
and Voltage Control from Generation Sources should be bundled with
basic transmission service, we believe that this service should remain
unbundled because, as explained above, transmission customers have some
ability to effect how much of this service they need and a third party
may be able to supply some portion of a customer's reactive power
requirements.
b. Services That May Be Offered and Sold as a Package
The NOPR indicated that ancillary services must be offered
separately from one another but did not indicate if the
[[Page 21589]]
transmission provider may also offer a package of ancillary services.
Comments
Several commenters support giving customers the option either to
purchase ancillary services as separate and distinct services or to
purchase a package of services from the transmission provider.394
Others, such as Tallahassee, recommend that utilities be prohibited
from bundling the purchase of one service with another so that a
transmission customer cannot rely on the transmission provider for just
one or a few of the ancillary services.
---------------------------------------------------------------------------
\394\ E.g., Direct Service Industries, Mt. Hope Hydro, ELCON, PA
Com.
---------------------------------------------------------------------------
EEI and ELCON argue that the Commission should permit customers the
option to request that transmission providers offer packages of
selected ancillary services.395 They and other commenters express
a concern that efficiencies can be lost under a policy that precludes
combining ancillary services.
---------------------------------------------------------------------------
\395\ EEI Initial Comments at V-4; ELCON Initial Comments at 21.
---------------------------------------------------------------------------
Commission Conclusion
We conclude that a transmission provider must offer and price the
individual ancillary services separately. It may not tie the purchase
of one to the purchase of another.
However, we will allow a transmission provider to assemble packages
of ancillary services (not bundled with basic transmission service)
that can be offered at rates that are less than the total of individual
charges for the services if purchased separately. It may also offer
rate discounts on any ancillary service. If a rate discount is offered
to the transmission owner itself or to an affiliate of the transmission
owner, the same discount must be offered to non-affiliates, as well. In
addition, discounts offered to non-affiliates must be on a basis that
is not unduly discriminatory. All discounts must be posted on the
transmission provider's OASIS.
4. Reassignment of Ancillary Services
In the NOPR, the Commission noted that ancillary services may not
be suitable for reassignment and requested comments on this issue.
Comments
Commenters express divided views on the reassignment issue. Some
IOU commenters believe that, subject to technical limitations,
ancillary services could be reassigned.396 Other commenters,
including many IOUs, oppose reassignment because they believe it is
impractical.397 In particular, PacifiCorp claims that the
customer-specific nature of generation-related ancillary services
prevents such services from being reassigned.
---------------------------------------------------------------------------
\396\ E.g., WP&L, NYSEG.
\397\ E.g., Consumers, PacifiCorp, Carolina P&L, PSNM, Salt
River, PA Com, TDU Systems.
---------------------------------------------------------------------------
TDU Systems argue that transmission customers that must pay for
ancillary services they do not need should be able to resell them to
someone else.398 Mt. Hope Hydro claims that, if a bulk power
transaction and the associated transmission service can be reassigned,
it is reasonable that the ancillary services used to support the
transaction also should be reassigned, particularly if the same
facilities and contract path are used.399
---------------------------------------------------------------------------
\398\ TDU Systems Initial Comments at 87.
\399\ Mt. Hope Hydro Initial Comments at 17.
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Commission Conclusion
We conclude that transmission customers will be allowed to reassign
ancillary services along with the reassignment of basic transmission
service. The Commission believes that a policy of transmission capacity
reassignment may not be possible unless the ancillary services used to
support the transmission are also reassignable.
5. Pricing of Ancillary Services
In the NOPR, we asked for comments on ancillary service pricing and
proposed specific ancillary services prices in the Stage One
implementation rates. Many commenters commented on the Stage One rates.
There is no Stage One in the Final Rule.
Comments
Many commenters state that ancillary services are difficult to
price. They suggest diverse pricing approaches. IN Com notes that,
because utilities and regulatory commissions have no experience with
pricing unbundled ancillary services, the process needs to evolve but
the goal should be to encourage market pricing in competitive markets.
Air Liquide believes the best pricing policy should be negotiated
bilateral agreements, provided market power is mitigated.
Other commenters express concern about how pricing proposed in the
NOPR would affect the development and operation of competitive
ancillary services markets. Industrial Energy Applications notes that
low price caps on generation-related services, such as supplying
losses, imbalance energy, operating reserve and backup power, which can
be provided from many sources, inhibit competitive market development.
There is little incentive for other providers to invest in facilities
to provide these services. Dayton P&L and others contend that the
Commission should not require transmission providers to provide
generation-based ancillary services at cost-based rates and then allow
third parties to resell such services at market-based rates. PacifiCorp
expresses concern that the NOPR's pricing proposal would be overly
restrictive in the emerging competitive market for generation-related
ancillary services.
Many commenters argue that cost-based price caps are appropriate
for ancillary services if there are no alternative suppliers or until
competitive markets develop.400 CAMU suggests that the
comparability standard is not met if market rates exceed the costs of
providing ancillary services. Allegheny, Ohio Edison and Atlantic City
support cost-based pricing for Reactive Power/Voltage Control. Ohio
Edison recommends cost-based pricing for frequency regulation, and
Atlantic City recommends it for scheduling and dispatch.
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\400\ E.g., Utilities For Improved Transition, Idaho, CINergy,
Direct Service Industries, Mt. Hope Hydro, ABATE, TDU Systems,
Missouri-Kansas Industrials, Washington and Oregon Energy Offices,
IN Com.
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Several commenters suggest that the Commission require cost-based
rates for ancillary services where no source other than the
transmission provider exists and market-based rates for generation-
related ancillary services if competition exists.401 Washington
and Oregon Energy Offices recommend that, before permitting market-
based rates, at least two other non-affiliated parties should be able
to offer a nearly identical ancillary service and that the Commission
should use the same standards for allowing market-based rates for
ancillary services that it has used for wholesale power sales. Mt. Hope
Hydro argues that vertically integrated utilities should be permitted
to charge cost-based rates that are limited to no more than the market
price for ancillary services. It also contends that companies whose
generation facilities are not supported by captive retail or
transmission customers should be authorized to sell at market-based
prices.
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\401\ E.g., PJM, Texas Utilities, Entergy, Carolina P&L.
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The vast majority of commenters from all interest groups who
address market-based pricing for ancillary services agree that market-
based pricing is appropriate for ancillary services where competitive
market conditions exist. However, commenters disagree over whether a
[[Page 21590]]
competitive market for ancillary services currently exists.
In determining the extent of competition, many commenters
distinguish between ancillary services that are (1) generation-related
and (2) transmission-related. Commenters disagree over whether the
Commission can declare generation-related ancillary services to be
competitive on a generic basis. Many commenters contend that
transmission-related ancillary services are not available in a
competitive market; consequently, they agree that prices for such
services should be cost-based.
Commission Conclusion
We will consider ancillary services rate proposals on a case-by-
case basis.
In response to comments,402 we offer here some general
guidance on ancillary services pricing principles.
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\402\ Many commenters were particularly concerned that rates for
energy losses, a NOPR ancillary service, should be market-based. We
need not address this concern in this Rule, however, because we will
not require Real Power Losses to be offered as an ancillary service.
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(1) Ancillary service rates should be unbundled from the
transmission provider's rates for basic transmission service, even
though such services are a necessary adjunct to basic transmission
service.
(2) The fact that we have authorized a utility to sell wholesale
power at market-based rates does not mean we have authorized the
utility to sell ancillary services at market-based rates.
(3) In the absence of a demonstration that the seller does not have
market power in such services, rates for ancillary services should be
cost-based and established as price caps, from which transmission
providers may offer a discount to reflect cost variations or to match
rates available from any third party. If a rate discount is offered to
the transmission owner itself or to an affiliate of the transmission
owner, the same discounted rate must be offered to non-affiliates, as
well. In addition, discounts offered to non-affiliates must be on a
basis that is not unduly discriminatory. All discounts must be posted
on the transmission provider's OASIS.
(4) The amount of each ancillary service that the customer must
purchase, self-supply, or otherwise procure must be readily determined
from the transmission provider's tariff and comparable to the
obligations to which the transmission provider itself is subject. The
provider must take ancillary services for its own wholesale
transmission under its own tariff.
(5) The location and characteristics of a customer's loads and
generation resources may affect significantly the level of ancillary
service costs incurred by the transmission provider. Ancillary service
rates and billing units should reflect these customer characteristics
to the extent practicable.
6. Accounting for Ancillary Services
Comments
Some commenters suggest that there may be a need for revising the
Uniform System of Accounts to track better the costs of providing
discrete ancillary services. Other commenters believe that ancillary
services are transmission-type services and suggested that the costs of
generation-provided ancillary services be refunctionalized from power
production expense to transmission expense.
Oak Ridge asserts that a primary goal of those interested in
restructuring the electricity industry should be to identify clearly
the different functions that are today buried within the vertically
integrated utility and bundled into one price. Oak Ridge, however,
indicates that achieving this ideal of identifying unbundled services
at appropriate prices will be difficult because of utility accounting
practices.
EEI asserts that since the current Uniform System of Accounts was
designed to track costs incurred to provide bundled wholesale service,
it does not track the discrete costs incurred to provide ancillary
services. Therefore, according to EEI, a major update is needed to
support the pricing of discrete ancillary services.
ConEd states that ancillary services are integral and essential
elements of providing transmission services. It notes that,
historically, due to the vertical integration of utilities, those
services have been bundled with the other services provided and the
costs associated with providing ancillary services have not been
specifically defined. ConEd claims that to a large degree, this is due
to the fact that utility accounting mechanisms were not established
with the intention of identifying the costs for ancillary services.
UI asserts that if transmission customers are to be charged for
certain ancillary services, it may be necessary to refunctionalize
certain specific costs items from generation to transmission. UI points
out that some of the reactive power to support system voltages and to
provide transmission services, for example, is supplied from the
variable reactive output of the generators. It states that these costs,
to the extent they can be identified with the provision of transmission
service, should be refunctionalized to the transmission account.
However, UI states it may not be possible to develop a unit cost for
specific transactions. Thus, UI states it may be more appropriate to
roll these costs into the embedded transmission rate and allocate them
among the various users of the transmission system.
Commission Conclusion
To ensure comparable transmission access a Transmission Provider is
obligated to offer or arrange to provide certain ancillary services to
the Transmission Customer. Also, the Transmission Provider may offer to
provide other ancillary services to the Transmission Customer. A
Transmission Customer is obligated to purchase certain ancillary
services from the Transmission Provider.
Generation resources provide certain ancillary services, while
transmission resources provide other ancillary services. Consequently,
the costs of providing certain ancillary services are recorded in the
utility's power production expense accounts, while others are recorded
in the utility's transmission expense accounts.
Currently, the Uniform System of Accounts requires that costs
incurred in providing ancillary services be recorded as power
production or transmission expense depending upon which resource the
utility uses to supply the service. At this time, we are not convinced
that the amounts involved or the difficulty associated with measuring
the cost of ancillary services warrants a departure from our present
accounting requirements. We will specify, however, that revenues a
Transmission Provider receives from providing ancillary services must
be recorded by type of service in Account 447, Sales for Resale, or
Account 456, Other Electric Revenues, as appropriate.
E. Real-Time Information Networks
In the Open Access NOPR, the Commission determined that in order to
remedy undue discrimination, a utility must functionally unbundle its
wholesale services, and that among the things required by functional
unbundling is that the utility, when buying or selling power, rely upon
the same electronic network that its transmission customers rely upon
to obtain transmission information. Accordingly, the Commission
accompanied its issuance of the Open Access NOPR with issuance of a
notice of technical conference that initiated a proceeding in Docket
No. RM95-9-000
[[Page 21591]]
to consider whether Real-Time Information Networks (RINS) or some other
option would be the best means to ensure that potential customers of
transmission services have access to the information necessary to
obtain open access transmission service on a non-discriminatory
basis.403
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\403\ See Real-Time Information Networks, Notice of Technical
Conference and Request for Comments, 60 FR 17726 (April 7, 1995).
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The Commission affirms its conclusion that in order to remedy undue
discrimination in the provision of transmission services it is
necessary to have non-discriminatory access to transmission
information, and that an electronic information system and standards of
conduct are necessary to meet this objective. Therefore, we issue, in
conjunction with this Final Rule, a final rule adding a new Part 37
that requires the creation of a basic OASIS and standards of
conduct.404
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\404\ In Phase II, we will continue to develop the requirements
for fully functional OASIS. We expect to issue a final rule on Phase
II OASIS requirements sometime in 1997.
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The Phase I OASIS rules require each public utility (or its agent),
as defined in section 201(e) of the Federal Power Act, 16 U.S.C.
824(e), that owns, controls, or operates facilities used for the
transmission of electric energy in interstate commerce to develop and/
or participate in an OASIS. The Phase I OASIS rules describe what
information must be provided on the OASIS during Phase I and how OASIS
must be implemented.
In addition, the new Part 37 contains a code of conduct applicable
to all transmission providing public utilities. The code of conduct is
designed to ensure that preferential access to information about
wholesale transmission prices and availability is not available to
employees of the public utility engaged in wholesale marketing
functions or to employees of certain of the public utility's
affiliates.
F. Coordination Arrangements: Power Pools, Public Utility Holding
Companies, Bilateral Coordination Arrangements, and Independent System
Operators
Comments
Timing of Reformation
Many marketers, IPPs, and other nonmembers of pools request that
the Commission immediately apply unbundling and transmission tariff
requirements to all new transactions under existing pooling agreements.
APPA states that the Commission should not deal with power pools as a
``follow-on activity'' because treatment of pools is an integral step
in achieving transmission comparability. AEC contends that until pools
publish open access tariffs, the Commission should permit applications
for section 211 transmission orders from one or more applicants
directed to multiple respondents.
Existing pools generally urge the Commission to allow time for the
pools to propose alternative structures or agreements which would meet
the objectives of the final rule. EEI states that the rule may create
problems for power pools that will not be examined or understood by the
Commission and the public until the Commission's pooling inquiry is
completed; it requests that the pooling inquiry be completed before a
final rule is issued. Duke recommends that implementation of open
access transmission services by power pools be addressed in a separate
proceeding because implementation of open access for power pools raises
complex issues.
EGA, among others, argues that new transactions under existing
pooling agreements should not be grandfathered, but rather should be
required to meet the functional unbundling requirements of the final
rule. Some pool members argue that pool transactions are largely not
wholesale transactions. For example, PECO (a member of PJM) requests
the Commission to clarify that the delivery of pooled generation to
pool members' native load is not a ``wholesale purchase'' of power and
thus would not require taking transmission service under one's own open
access transmission tariff. Another member of PJM, BG&E, interprets the
proposed rule to require all PJM economy trades to be firm point-to-
point services; it claims that such a requirement ``jeopardizes the
continued viability of the pool.''
System-Wide Tariffs
Virtually all commenters on power pool issues state that the tariff
requirements should not be applied directly to individual utilities who
are members of ``tight'' power pools. ELCON, CCEM, and others argue
that the pro forma tariff requirement should be applied directly to
``tight'' or ``single system'' power pools to avoid discriminatory
``pancaking'' of transmission rates. However, Duke argues that where
there are both multiple owners and operators, as in ``loose'' pools, it
is appropriate to have individual tariffs unless the pool members agree
otherwise. DOE recommends a power pool file a single pool-wide tariff
to offset problems associated with joint ownership or control of
transmission. CT DPUC recommends that the Commission provide guidance
for transmission access and pricing (so as to avoid needless disruption
of present methods).
Flexible Treatment
Most commenters on power pools support recognizing regional
differences among power pools and urge flexibility. PSE&G (a member of
PJM) states that open access tariffs must be specially crafted to deal
with power pool members. NYPP and PJM state that they are considering
innovations and urge that their efforts not be stifled by any final
rule. CSW proposes a region-wide pricing model based on power flows.
NPPD, a member of the Mid-Continent Area Power Pool (MAPP), says MAPP
is considering adopting the megawatt-mile approach to transmission
pricing. SoCal Edison states that California utilities are developing a
market-based power pool and that it is crucial for the final rule to be
flexible to permit innovations throughout the country.
ELCON and power marketers, however, argue for uniformity and point
out the difficulties of moving power from system to system where each
system has varying standards or ``pool rules.'' These commenters
support uniform application of the terms and conditions in the pro
forma tariffs to create a national standard.
NEPOOL emphasizes that since pools remain voluntary, the imposition
of rules that are not acceptable to pool members simply increases the
likelihood that members will withdraw and pools will disintegrate. For
this reason, NEPOOL states that solutions to enhance competition
(within a tight pool setting) are best identified through the consensus
of pool members, which requires both time and flexibility on the part
of the Commission.
DE, DC, NJ and MD Coms emphasizes its concern that a one-size-fits-
all open-access policy, while perhaps benefiting subsets of individual
suppliers and purchasers, may not be the best solution for the millions
of retail customers who currently rely on power pools.405 It wants
the Commission to be aware that the individual commissions have begun a
formal dialog among each other and with the PJM utilities to discuss
possible regional solutions to transitional competitive issues.
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\405\ E.g., DE Com, DC Com, NJ Com, MD Com.
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Open Membership
NIEP and CCEM argue that the competitive playing field cannot be
level unless nonmembers receive certain
[[Page 21592]]
power pool services on terms comparable to those for pool members.
Members of pools state that ``return in kind'' transactions are
efficient, but that such transactions are not appropriate for those
entities that are not similarly situated to vertically integrated
utilities.
EEI maintains that those seeking the benefits of pool membership
must accept the burdens imposed on existing pool members (otherwise,
they would have an advantage, not comparability). EEI believes that new
pool participants can negotiate and ``buy into'' the pool resources.
Many commenters claim that unbundling certain power pool services to
accommodate open access will solve the problem.
MidAmerican states that if the Commission grants nonmembers access
to pool transmission service, the Commission should allow a period of
at least four years for pools to restructure and refile rate schedules
to avoid the inequitable results which the Commission's requirements
will impose on pool members.
MidAmerican contends that the Commission should authorize pool
members to unilaterally withdraw from their pools if any restructuring
or revision of rate schedules is unacceptable to the member.
Holding Companies
Allegheny, Southern, and other holding companies argue that
coordination agreements among subsidiaries of a utility holding company
system do not constitute a power pool and should not be subject to any
obligations the Commission may place on power pools.
Bilateral Coordination Agreements
Ohio Edison requests clarification that the Commission is not
requiring new wholesale coordination transactions to be under the open
access tariffs; they may be continued under existing coordination
agreements. It stresses the importance of such agreements in making
economy and emergency transactions.
A number of commenters agree that existing coordination contracts
should not be abrogated or modified, and that transactions under these
existing contracts should not be governed by the provisions of the pro
forma tariffs.406 These commenters generally argue that existing
coordination agreements should not be abrogated or amended by the final
rule because: (1) They were not negotiated in the environment
envisioned by the NOPR; (2) coordination sales are beneficial to
consumers and ratepayers (and thus it would not be in the public
interest to curtail them); and (3) the termination of coordination
agreements, which in some cases have been in place for years and are
tailored to parties' peculiar circumstances, could cause severe
hardships in certain regions (especially with regard to scheduling and
curtailment).
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\406\ E.g., Central Louisiana, Dayton P&L, LPPC, MEAG, Missouri
Basin Group, Montana-Dakota Utilities, Nebraska Public Power
District, Ohio Edison, PSNM.
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PSNM contends that such agreements are the result of mutually
beneficial bargaining. LPPC and MEAG argue that current contracts
negotiated among parties provide cost savings to consumers, which may
be foregone if existing contracts are modified. Central Louisiana
suggests that the pro forma tariff provisions should be flexible enough
to achieve comparability if applied to both existing and new
coordination agreements.
Some commenters argue that there may be cases where it is
inappropriate to modify existing coordination agreements to satisfy the
requirements of the rule. They assert that coordination agreements
providing for emergency transactions,407 reliability,408 and
resource efficiency gains 409 need special attention. However,
Soyland believes that existing agreements need to be reviewed if there
is substantial increase in wholesale power market transactions, at the
customer's option. TDU Systems argues that coordination contracts
supporting system reliability should be honored and given scheduling
and curtailment preference. TDU Systems contends that any amendments
should be at the parties' discretion rather than by Commission mandate.
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\407\ E.g., Arizona, Ohio Edison.
\408\ E.g., Soyland, NRECA.
\409\ E.g., APPA.
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Several commenters suggest that the proposed rule is unclear about
whether only existing transactions under agreements already approved by
the Commission will be exempt from functional unbundling, or whether
the proposed rule also would exempt (or grandfather) new transactions
entered into pursuant to existing approved contracts.410 Other
commenters recommend that the Commission clarify that its policy on
unbundling ap
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
plies to all new transactions, whether pursuant to new or
existing agreements.411 ConEd and KCPL request clarification that
purchases made to satisfy retail service are not subject to the
requirements of the pro forma tariffs.
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\410\ E.g., APPA, CCEM, EGA.
\411\ E.g., APPA, CCEM, LG&E, EGA.
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CCEM argues that all coordination transactions, including new
transactions under existing agreements, should be unbundled to ensure
that transmission providers are implementing the posted transmission
rate. CINergy contends that the comparability standard should be
applied to existing coordination agreements, including buy-resell
agreements, to mitigate any unfair bulk power market advantages.
Functional unbundling would ensure that a utility includes an EBB-
posted transmission rate in the transaction charge. CINergy and Power
Marketing Association recommend that the Commission use its authority
under section 206 to require all utilities to file amendments to their
existing coordination agreements providing for transmission service to
be taken pursuant to the parties' open access transmission tariffs.
Power Marketing Association further recommends that the Commission
establish expedited procedures to address the situation arising from
conflicting pro forma tariffs and existing coordination provisions.
Tallahassee also believes that the comparability standard should be
applied to existing coordination agreements, but Tallahassee recommends
that the Commission establish a transition period to allow for
renegotiation among parties rather than imposing modifications to
existing agreements. Renegotiation would provide an opportunity to
retain previously bargained-for benefits. Detroit Edison also contends
that many of the existing coordination agreements do not provide for
the services required under the pro forma tariffs. Like Tallahassee,
Detroit Edison recommends that the Commission allow sufficient time for
parties to renegotiate existing agreements. CINergy suggests a three-
year transition period.
Coordination Pricing Practices
EEI and PJM disagree with the Commission's assertion that current
coordination pricing is no longer just and reasonable in the absence of
an open access tariff. Ohio Edison and PA Com question the basis of the
Commission's preliminary conclusion that current coordination pricing
is no longer justified in the absence of a seller's tariff offer of
non-discriminatory open access transmission services. PA Com asserts
that the Commission's underlying assumption of general lack of
transmission access by wholesale customers has not been established as
fact in the proposed rule.
[[Page 21593]]
MN DPS supports current coordination pricing methods provided that
utilities have executed open-access tariffs. Missouri Basin Group
argues that, if increased market competition materializes through open
access, utilities will decreasingly rely on current coordination
pricing if it no longer produces the most beneficial outcome. Missouri
Basin Group recommends the Commission simply allow utilities to choose
a pricing method even if a utility opts for a less beneficial outcome.
Nebraska Public Power District also urges the Commission to avoid
mandating coordination pricing methods. Nebraska Public Power District
is concerned that this may impede establishing RTGs where such pricing
is by mutual agreement and subject to ADR procedures.
Several commenters agree that current coordination pricing may no
longer be appropriate in an open access regime.412 FL Com believes
that current coordination pricing should be replaced by market-based
rates if open access transmission service is imposed by the Commission.
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\412\ E.g., Arizona, CINergy, Consumers Power, EEI, PJM.
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Commission Conclusion
The term ``coordination'' is applied to a wide variety of wholesale
power sales agreements within the industry, including interchange,
interconnection, pooling, and other agreements. Broadly speaking, any
non-requirements power sales agreement can be considered to be a
coordination agreement.413
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\413\ For example, a 30-year contract to supply 50 MW of power
can be considered to be a coordination arrangement because it is not
a contract to meet all of the buyer's power requirements.
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The Final Rule's general requirement for non-discriminatory
transmission access and pricing by public utilities, and its specific
requirement that public utilities unbundle their transmission rates and
take transmission service under their own tariffs, apply to all public
utilities' wholesale sales and purchases of electric energy, including
coordination transactions. The Commission has determined that certain
existing wholesale coordination arrangements and agreements must be
modified to ensure that necessary transmission services for such
arrangements and agreements are taken under open access transmission
tariffs and thus that such arrangements and agreements are not unduly
discriminatory. Below we discuss how and when various types of
coordination agreements will need to be modified, and when public
utility parties to coordination agreements must begin to trade power
under those agreements using transmission service obtained under the
same open access transmission tariff available to non-parties.
Coordination arrangements, and the agreements governing them, vary
widely. They range from relatively simple bilateral arrangements to
complex tight power pools. Our discussion addresses four broad
categories of arrangements and accompanying agreements: ``tight'' power
pools, ``loose'' power pools, public utility holding company
arrangements, and bilateral coordination arrangements. For purposes of
implementing the non-discriminatory, open access requirements of the
Final Rule, we are dividing bilateral coordination agreements into two
general categories: bilateral economy energy agreements and other
bilateral coordination agreements. Economy energy agreements typically
provide for short-term economy trading ``if, as, and when available''
and are generally driven by the buyer and seller's generation costs.
They do not require either the seller or the buyer to engage in a
particular transaction. Other coordination agreements are typically
longer term or open-ended. Some may involve joint ownership or joint
planning of generation.414 Others may provide joint operation of
facilities so that the parties can coordinate their maintenance
schedules or provide one another with emergency service. These longer-
term coordination agreements are distinguished from short-term economy
trading agreements in that the parties have undertaken a contractual
obligation to operate their facilities so as to support one another
under the conditions specified in the arrangements.
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\414\ Agreements dealing with joint ownership or operation of
transmission facilities are discussed at Section IV.C.3.
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As noted in the NOPR, power pools, in contrast to most bilateral
arrangements, present complex issues that may require special
implementation requirements.415 This is because these arrangements
may involve agreements containing an intricate set of rights,
obligations, and considerations among the members of a pool. We provide
for implementation requirements herein that vary depending upon the
type of ``pooling'' arrangement involved.
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\415\ The Commission did not define what it meant by ``power
pools'' in the NOPR discussion. We use the term power pool in a very
broad context here and have generally characterized three broad
types of arrangements that represent some form of pooling: ``tight
pools'', ``loose'' pools and other multilateral coordination
arrangements, and holding companies. Even between the categories of
tight and loose pools, however, there is no bright dividing line.
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The Commission has concluded that in order to adequately remedy the
undue discrimination in transmission access and pricing by public
utilities that are members of power pools or other coordination
arrangements, such public utilities must remove preferential
transmission access and pricing provisions from agreements governing
their transactions. The filing of open access tariffs by the public
utility members of a power pool is not enough to cure undue
discrimination in transmission if those public utilities can continue
to trade with a selective group within a power pool that
discriminatorily excludes others from becoming a member and that
provides preferential intra-pool transmission rights and rates. The
same holds true of certain bilateral arrangements that allow
preferential transmission pricing or access. These arrangements and
agreements need to be changed. We expect such arrangements and
agreements to be modified by the dates indicated in this Rule. However,
if necessary, we will institute section 206 proceedings against public
utilities that do not make such filings.
The Commission's technical conferences on power pools, ISOs, and
pro forma tariffs made clear to us the need to articulate guidance in
this Rule on the restructuring or modification of unduly discriminatory
coordination arrangements--particularly tight power pools.\416\ They
also made clear that members of tight power pools, in particular, need
time to make the necessary modifications to these arrangements. We
recognize that members of some power pools are already in the process
of formulating voluntary modifications to pooling agreements to be
filed with the Commission (e.g., PJM, NYPP, NEPOOL). Therefore, we will
provide adequate time for these filings as well as guidance to changes
that need to be made.
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\416\ A technical conference on pro forma tariffs was held on
October 27, 1995. A technical conference on power pools was held on
December 5 and 6, 1995 and a follow-up technical conference on ISOs
and power pools was held on January 24, 1996.
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In addition, although we do not at this time find it necessary to
require power pools to form an independent system operator in order to
remedy undue discrimination, we believe ISOs may prove to be an
effective means for
[[Page 21594]]
accomplishing comparable access.\417\ We recognize that several
utilities are exploring the possibility of forming ISOs. For example,
discussions are ongoing in California, PJM, NYPP, and the Midwest.
Therefore, because of the industry's interest (which we share) in the
concept of an ISO and the potential for an ISO to provide non-
discriminatory transmission services to all market participants, we
will provide guidance in this section on minimum ISO characteristics.
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\417\ The DOJ and DOE suggested that the Commission examine
operational unbundling as a way of enforcing comparability in
transmission service. DOJ and DOE believe that functional unbundling
may not be adequate to ensure comparability and so have recommended
that some form of operational unbundling be required. While we
believe that requiring this is premature, we note that an ISO is one
way to achieve operational unbundling and we encourage the voluntary
development of ISOs.
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1. Tight Power Pools
For purposes of this Rule, the tight power pools are: New York
Power Pool (NYPP), New England Power Pool (NEPOOL), Pennsylvania-New
Jersey-Maryland Interconnection (PJM), and the Michigan Electric
Coordinated Systems (MECS).
Public utilities who are members of a tight pool must file, within
60 days of publication of the Final Rule in the Federal Register,
either: (1) An individual Final Rule pro forma tariff; or (2) a joint
pool-wide Final Rule pro forma tariff. They are not required to take
service for pool transactions under the tariff that is filed within 60
days. However, they will be required to file a joint pool-wide Final
Rule pro forma tariff no later than December 31, 1996, and must begin
to take service under that tariff for all pool transactions no later
than December 31, 1996. The purpose of this extension is to allow
sufficient time for tight pools to amend their pooling agreements and
to restructure their operations to conform to the requirements of the
Final Rule. We also believe that the additional time is necessary to
preserve efficient trading arrangements during the restructuring
period.
The Commission therefore will require that the public utility
members of tight pools file reformed power pooling agreements no later
than December 31, 1996. The reformed power pool agreements should
establish open, non-discriminatory membership provisions (including
establishment of an ISO, if that is a pool's preferred method of
remedying undue discrimination) and modify any provisions that are
unduly discriminatory or preferential. The membership provision must
allow any bulk power market participant to join, regardless of the type
of entity, affiliation, or geographic location.
If the reformed agreement allows members to make transmission
commitments or contributions in exchange for the discounted
transmission rates, the pool may file a transmission tariff that
contains an access fee for non-transmission owning members or non-
members, justified solely on the basis of transmission-related costs.
Alternatively, the pool could make available a transmission rate that
is structured the same as the discounted rate (e.g., non-pancaked) but
with a higher rate that is justified on the basis of transmission-
related costs borne (or contributed) by the pool members. However, any
such access fee or higher rate must be justified solely on the basis of
transmission costs and cannot be tied to the costs of any other
agreement among the pool members (e.g., generation reserve sharing).
2. Loose Pools
For purposes of the Final Rule, a loose pool is any multi-lateral
(more than 2 public utilities) arrangement, many of which contain
discounted and/or special transmission arrangements. Examples are MAPP,
Inland Power Pool, and the MOKAN pool. Other entities may qualify to be
treated as a loose pool if they can show that they meet the definition
above.
Public utilities within a loose pool must file, within 60 days of
publication of the Final Rule in the Federal Register, either: (1) An
individual Final Rule pro forma tariff; or (2) a pool-wide Final Rule
pro forma tariff. They are not required to take service for pool
transactions under the tariff that is filed within 60 days. However,
they will be required to file a joint pool-wide Final Rule pro forma
tariff no later than December 31, 1996, and must begin to take service
under that tariff for all pool transactions no later than December 31,
1996. The purpose of this extension is to allow sufficient time for
loose pools to amend their agreements and to restructure their
operations to conform to the requirements of the Final Rule. We also
believe that the additional time is necessary to preserve efficient
trading arrangements during the restructuring period.
The Commission therefore will require that the public utility
members of loose pools file reformed power pooling agreements no later
than December 31, 1996. They also must file a joint pool-wide tariff no
later than December 31, 1996. The reformed power pool agreements should
establish open, non-discriminatory membership provisions and modify any
provisions that are unduly discriminatory or preferential. The
membership provision must allow any bulk power market participant to
join, regardless of the type of entity, affiliation, or geographic
location.
The Commission recognizes that loose pools typically do not operate
as a single control area and that operational unbundling, perhaps
through an ISO, might not be readily attainable at this time.
Nonetheless, we encourage the members of loose pools to explore the
advantages of the ISO concept.
If the reformed agreement allows members to make transmission
commitments or contributions in exchange for discounted transmission
rates, the pool may file a transmission tariff that contains an access
fee for non-transmission owning members or non-members, justified
solely on the basis of transmission-related costs. Alternatively, the
pool could make available a transmission rate that is structured the
same as the discounted rate (e.g., non-pancaked) but with a higher rate
that is justified on the basis of transmission-related costs borne (or
contributed) by the pool members. However, any such access fee or
higher rate must be justified solely on the basis of transmission costs
and cannot be tied to the costs of any other agreement among the pool
members (e.g., generation reserve sharing).
3. Public Utility Holding Companies
Public utility members of registered and exempt holding companies
that are also members of tight or loose pools are subject to the tight
and loose pool requirements set forth above. The remaining holding
company public utility members, with the exception of the Central and
South West (CSW) System, are required to file a single system-wide
Final Rule pro forma tariff permitting transmission service across the
entire holding company system at a single price within 60 days of
publication of the Final Rule in the Federal Register (service
companies may, of course, file on behalf of their public utility
affiliates). As discussed below, CSW presents special circumstances.
The CSW System is comprised of four operating public utilities. Two
of those utilities, Southwestern Electric Power Company (SWEPCO) and
Public Service Company of Oklahoma (PSO) operate in the Southwest Power
Pool (SPP). The other two, West Texas Utilities Company (West Texas)
and Central Power and Light Company (CP&L), operate in the Electric
Reliability
[[Page 21595]]
Council of Texas (ERCOT). SWEPCO and PSO exchange power with West Texas
and CP&L through two high voltage, direct current interconnections (the
North and East Interconnections).418
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\418\ The North and East Interconnections were ordered by the
Commission pursuant to sections 210, 211 and 212 of the Federal
Power Act. See Central Power and Light Company, et al., 17 FERC
para. 61,078 (1981), order on reh'g, 18 FERC para. 61,100 (1982); 40
FERC para. 61,077 (1987).
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Pursuant to the Commission orders concerning the North and East
Interconnections, CP&L, West Texas, SWEPCO, and PSO have on file what
are referred to as the ``to or from and over tariffs.'' 419 Those
tariffs apply only to transmission service that involves the delivery
of power and energy to or from and over the North and East
Interconnections.420 The tariffs do not apply to the transmission
of power for CSW subsidiaries other than the operating companies. The
tariffs in many respects are different from the Final Rule pro forma
tariff and do not provide comparable services. Moreover, the pricing
provided in the ``to or from and over'' tariffs is different from the
pricing set forth in the Texas Commission's final open access
rule.421
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\419\ Houston Lighting and Power Company (HL&P) and Texas
Utilities Electric Company (TU) also have on file ``to or from and
over tariffs'' pursuant to the Commission orders.
\420\ See, e.g., CP&L and West Texas Interpool Transmission
Service Tariff, Sec. 4.1.
\421\ Compare 21 TEX REG 1397, LEXIS, mimeo at 18 (adopting
hybrid pricing scheme with 70% of transmission rate based on
regional postage stamp method and 30% based on the vector-absolute
megawatt-mile method) with Id. at Article III.
We note that the Texas Commission concluded that the ERCOT
portion of the costs of the North and East Interconnections ``should
be included in the cost of service, when the owners of the
(Interconnections) amend the FERC tariffs for the use of the
(Interconnections) to provide equal access to other utilities. 21
TEX REG, LEXIS, mimeo at 24.
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Given these special circumstances, we believe it appropriate to
give CSW the opportunity to propose a solution to achieving
comparability for the CSW system. Accordingly, we direct the public
utility subsidiaries of CSW to consult with the Texas, Arkansas,
Oklahoma and Louisiana Commissions and to file not later than December
31, 1996 a system tariff that will provide comparable service to all
wholesale users on the CSW System,422 regardless of whether they
take transmission service wholly within ERCOT or the SPP, or take
transmission service between the reliability councils over the North
and East Interconnections.423
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\422\ It may be appropriate to have different rates for
transmission service wholly within ERCOT or the SPP, and for service
between the reliability councils. However, the same rates, terms,
and conditions applicable for third parties should also be
applicable to the CSW System's wholesale transmission requirements.
\423\ We recognize that this action may require amendment to the
Commission's orders under FPA sections 210, 211, and 212, ordering
the North and East Interconnections. In this regard, it should be
clearly understood that the Commission's action in requiring
comparable service by the CSW System is not in any way intended to
result in public utility status to any ERCOT participants that are
not public utilities--e.g., HL&P and TU. See 16 U.S.C. 824(b)(2).
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The Commission will give public utilities that are members of
holding companies an extension of the requirement to take service under
the system tariff for wholesale trades between and among the public
utility operating companies within the holding company system. This
extension is until December 31, 1996--the same extension we are
granting to power pools. At that point, the public utility operating
companies will be required to take service under the Final Rule pro
forma tariff for wholesale trades among themselves. In addition, it may
be necessary for registered holding companies to reform their holding
company equalization agreement to recognize the non-discriminatory
terms and conditions of transmission service required under the Final
Rule pro forma tariff.
4. Bilateral Coordination Arrangements
Any bilateral wholesale coordination agreement executed after the
effective date of this Rule will be subject to the functional
unbundling and open access requirements set forth in this Rule. With
regard to existing bilateral agreements, however, the diversity of the
types of agreements currently on file presents special implementation
problems. The Commission is particularly concerned with future economy
energy transactions that may occur pursuant to existing umbrella-type
coordination agreements. Accordingly, we shall require all bilateral
economy energy coordination contracts executed before the effective
date of this Rule to be modified to require unbundling of any economy
energy transaction occurring after December 31, 1996. All non-economy
energy bilateral coordination contracts executed before the effective
date of this Rule will be permitted to continue in effect, but will be
subject to complaints filed under section 206 of the FPA. Under those
procedures, the rates, terms, and conditions of individual coordination
contracts may be challenged as unduly discriminatory or otherwise
unlawful.
To compute the unbundled coordination compliance rate, the utility
must subtract the corresponding transmission unit charge in its open
access tariff from the existing coordination rate ceiling. For example,
if a utility has a coordination rate ceiling for hourly service of
incremental cost plus 15 mills/kWh and a transmission tariff rate for
hourly service of 3 mills/kWh, it shall revise the coordination rate
ceiling to incremental cost plus 12 mills/kWh. The Commission cautions
that the compliance filing will be strictly limited to removing the
current transmission tariff price from the coordination price and will
not be a medium for otherwise revising the residual coordination sales
price.
The transmission rate for the coordination transactions may be at
or below the tariff rate. However, if a utility's transmission operator
offers a discounted transmission rate to the utility's wholesale
marketing department or an affiliate for the purposes of coordination
transactions, the same discounted rate must be offered to others for
trades with any party to the coordination agreement. In addition,
discounts offered to non-affiliates must be on a basis that is not
unduly discriminatory.424 This may require parties to file
modifications of the coordination arrangements.
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\424\ All discounts must be posted on the transmission
provider's OASIS.
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ISO Principles
The Commission recognizes that some utilities are exploring the
concept of an Independent System Operator and that the tight power
pools are considering restructuring proposals that involve an ISO.
While the Commission is not requiring any utility to form an ISO at
this time, we wish to encourage the formation of properly-structured
ISOs. To this end, we believe it is important to give the industry some
guidance on ISOs at this time. Accordingly, we here set out certain
principles that will be used in assessing ISO proposals that may be
submitted to the Commission in the future.
These principles are applicable only to ISOs that would be control
area operators, including any ISO established in the restructuring of
power pools. We recognize that some utilities are exploring concepts
that do not involve full operational control of the grid. Without in
any way prejudging the merits of such arrangements, the following
principles do not apply to independent administrators or coordinators
that lack operational control. We do not have enough information at
this time to offer guidance about such entities, but
[[Page 21596]]
recognize that they could perform a useful role in a restructured
industry.
Because an ISO will be a public utility subject to our
jurisdiction,425 the ISO's operating standards and procedures must
be approved by the Commission. In addition, a properly constituted ISO
is a means by which public utilities can comply with the Commission's
non-discriminatory transmission tariff requirements. The principles for
ISOs are:
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\425\ A public utility is any person that owns or operates
facilities used for the transmission of electric energy in
interstate commerce or the sale of electric energy at wholesale in
interstate commerce. An ISO will operate facilities used for the
transmission of electric energy in interstate commerce and thus will
be subject to the Open Access and OASIS rules.
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1. The ISO's governance should be structured in a fair and non-
discriminatory manner. The primary purpose of an ISO is to ensure fair
and non-discriminatory access to transmission services and ancillary
services for all users of the system. As such, an ISO should be
independent of any individual market participant or any one class of
participants (e.g., transmission owners or end-users). A governance
structure that includes fair representation of all types of users of
the system would help ensure that the ISO formulates policies, operates
the system, and resolves disputes in a fair and non-discriminatory
manner. The ISO's rules of governance, however, should prevent control,
and appearance of control, of decision-making by any class of
participants.
2. An ISO and its employees should have no financial interest in
the economic performance of any power market participant. An ISO should
adopt and enforce strict conflict of interest standards. To be truly
independent, an ISO cannot be owned by any market participant. We
recognize that transmission owners need to be able to hold the ISO
accountable in its fiduciary role, but should not be able to dictate
day-to-day operational matters. Employees of the ISO should also be
financially independent of market participants. We recognize, however,
that a short transition period (we believe 6 months would be adequate)
will be needed for employees of a newly formed ISO to sever all ties
with former transmission owners and to make appropriate arrangements
for pension plans, health programs and so on. In addition, an ISO
should not undertake any contractual arrangement with generation or
transmission owners or transmission users that is not at arm's length.
In order to ensure independence, a strict conflict of interest standard
should be adopted and enforced.
3. An ISO should provide open access to the transmission system and
all services under its control at non-pancaked rates pursuant to a
single, unbundled, grid-wide tariff that applies to all eligible users
in a non-discriminatory manner. An ISO should be responsible for
ensuring that all users have non-discriminatory access to the
transmission system and all services under ISO control. The portion of
the transmission grid operated by a single ISO should be as large as
possible, consistent with the agreement of market participants, and the
ISO should schedule all transmission on the portion of the grid it
controls. An ISO should have clear tariffs for services that neither
favor nor disfavor any user or class of users.
4. An ISO should have the primary responsibility in ensuring short-
term reliability of grid operations. Its role in this responsibility
should be well-defined and comply with applicable standards set by NERC
and the regional reliability council. Reliability and security of the
transmission system are critical functions for a system operator. As
part of this responsibility an ISO should oversee all maintenance of
the transmission facilities under its control, including any day-to-day
maintenance contracted to be performed by others. An ISO may also have
a role with respect to reliability planning. In any case, the ISO
should be responsible for ensuring that services (for all users,
including new users) can be provided reliably, and for developing and
implementing policies related to curtailment to ensure the on-going
reliability and security of the system.
5. An ISO should have control over the operation of interconnected
transmission facilities within its region. An ISO is an operator of a
designated set of transmission facilities.
6. An ISO should identify constraints on the system and be able to
take operational actions to relieve those constraints within the
trading rules established by the governing body. These rules should
promote efficient trading. A key function of an ISO will be to
accommodate transactions made in a free and competitive market while
remaining at arm's length from those transactions. The ISO may need to
exercise some level of operational control over generation facilities
in order to regulate and balance the power system, especially when
transmission constraints limit trading over interfaces in some
circumstances. It is important that the ISO's operational control be
exercised in accordance with the trading rules established by the
governing body. The trading rules should promote efficiency in the
marketplace. In addition, we would expect that an ISO would provide, or
cause to be provided, the ancillary services described in this Rule.
7. The ISO should have appropriate incentives for efficient
management and administration and should procure the services needed
for such management and administration in an open competitive market.
Management and administration of the ISO should be carried out in an
efficient manner. In addition to personnel and administrative
functions, an ISO could perform certain operational functions, such as:
determination of appropriate system expansions, transmission
maintenance, administering transmission contracts, operation of a
settlements system, and operation of an energy auction. The ISO should
use competitive procurement, to the extent possible, for all services
provided by the ISO that are needed to operate the system. All
procedures and protocols should be publicly available.
8. An ISO's transmission and ancillary services pricing policies
should promote the efficient use of and investment in generation,
transmission, and consumption. An ISO or an RTG of which the ISO is a
member should conduct such studies as may be necessary to identify
operational problems or appropriate expansions. Appropriate price
signals are essential to achieve efficient investment in generation and
transmission and consumption of energy. The pricing policies pursued by
the ISO should reflect a number of attributes, including affording non-
discriminatory access to services, ensuring cost recovery for
transmission owners and those providing ancillary services, ensuring
reliability and stability of the system and providing efficient price
signals of the costs of using the transmission grid. In particular, the
Commission would consider transmission pricing proposals for addressing
network congestion that are consistent with our Transmission Pricing
Policy Statement. In addition, an ISO should conduct such studies and
coordinate with market participants including RTGs, as may be necessary
to identify transmission constraints on its system, loop flow impacts
between its system and neighboring systems, and other factors that
might affect system operation or expansion.
9. An ISO should make transmission system information publicly
available on a timely basis via an electronic information network
consistent with the Commission's requirements. A free-flow
[[Page 21597]]
of information between the ISO and market participants is required for
an ISO to perform its functions and for market participants to
efficiently participate in the market. At a minimum, information on
system operation, conditions, available capacity and constraints, and
all contracts or other service arrangements of the ISO should be made
publicly available. This information should be made available on an
OASIS operated by the ISO.
10. An ISO should develop mechanisms to coordinate with neighboring
control areas. An ISO will be required to coordinate power scheduling
with other entities operating transmission systems. Such coordination
is necessary to ensure provision of transmission services that cross
system boundaries and to ensure reliability and stability of the
systems. The mechanisms by which ISOs and other transmission operators
coordinate can be left to those parties to determine.
11. An ISO should establish an ADR process to resolve disputes in
the first instance. An ISO should provide for a voluntary dispute
resolution process that allows parties to resolve technical, financial,
and other issues without resort to filing complaints at the Commission.
We would encourage the ISO to establish rules and procedures to
implement alternative dispute resolution processes.
G. Pro Forma Tariff
In the NOPR, the Commission stated that--
all utilities use their own systems in two basic ways: to provide
themselves point-to-point transmission service that supports
coordination sales, and to provide themselves network transmission
service that supports the economic dispatch of their own generation
units and purchased power resources (integrating their resources to
meet their internal loads). 426
\426\ FERC Stats. & Regs. para. 32,514 at 33,079.
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Accordingly, the Commission proposed two pro forma tariffs in
Appendices B and C of the NOPR: One for point-to-point service and one
for network service. Our goal was to encourage the development of
competitive bulk power markets by ensuring that all participants would
be able to secure transmission services on a non-discriminatory basis.
We attempted in the NOPR pro forma tariffs to articulate the minimally
acceptable terms and conditions of service for point-to-point and
network transmission service that were required to ensure non-
discriminatory transmission service.427 We explained that, for the
most part, specific pricing provisions were omitted. We asked for
comments on whether these tariffs provided a good basis for defining
the minimum acceptable non-price terms and conditions of
service.428
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\427\ Id. at 33,092.
\428\ On October 27, 1995, the Commission's staff sponsored a
technical conference on the pro forma tariffs.
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Subsequently, in a June 28, 1995 order, we encouraged public
utilities to file open access transmission tariffs as soon as
possible.429 Tariffs with terms and conditions of service
substantively similar to the NOPR pro forma tariffs would become
effective without a refund condition, assuming there were no other
concerns, e.g., rate issues. We also indicated that these tariffs would
be subject to revision based on the Final Rule.
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\429\ American Electric Power Service Corporation, et al., 71
FERC para. 61,393, modified, 72 FERC para. 61,287 (1995).
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Unified Pro Forma Tariff
The Commission received many comments on both the point-to-point
and network tariffs. Many commenters suggested improvements to the
proposed tariffs. Others took issue with how to reconcile various
aspects of service under the two tariffs (e.g., cost allocation,
service priority, customer rights and obligations). As discussed below,
the Commission has attempted to address these concerns in developing
tariff requirements for the Final Rule. Importantly, while the
Commission has retained point-to-point transmission service and network
transmission service as distinct services, the requirements for the two
services are now in a single pro forma tariff.430 The Final Rule
pro forma tariff eliminates many of the differences between the two
NOPR pro forma tariffs, provides a unified set of definitions, and
consolidates certain common requirements such as the obligation to
provide ancillary services. The general terms and conditions of
transmission service specified in the Final Rule pro forma tariff
should be familiar to all utilities, particularly those that have
voluntarily filed open access tariffs based on the NOPR pro forma
tariffs.
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\430\ The Final Rule pro forma tariff is attached as Appendix D.
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The Commission believes that the modified, single pro forma tariff,
in conjunction with the other requirements, is sufficient to remedy
undue discrimination in the provision of transmission services.
However, we note that in an accompanying notice of proposed rulemaking
in Docket No. RM96-11-000, we are seeking comments on whether a
different form of open access tariff--one based solely on a capacity
reservation system--might better accommodate competitive changes
occurring in the industry while ensuring that all wholesale
transmission service is provided in a fair and non-discriminatory
manner.
We address below the comments received on the NOPR tariff and the
specific modifications we have made in the Final Rule pro forma tariff.
1. Tariff Provisions That Affect The Pricing Mechanism
a. Non-Price Terms and Conditions
Comments
Utilities For Improved Transition argues that any generic
imposition of detailed tariffs on the electric industry will stifle the
evolution of the industry. Rather, it asserts, utilities that supply
transmission service should be permitted to apply general principles of
comparability in their company-specific tariffs, using terms and
conditions of service based on their own particular circumstances and
those of their customers.
Utility Working Group wants the final rule to allow utilities to
depart from the pricing method implicitly contained in the NOPR pro
forma tariffs. It argues that the final rule should recognize that some
terms and conditions may not make sense in the context of innovative
pricing proposals.
DOE thinks that it is proper to base the tariffs on a familiar and
simple pricing method. However, DOE suggests that, in the future, the
Commission carefully assess the workability of the contract path model
in a competitive bulk power market. DOE suggests that spot or real-time
pricing should be considered.
Numerous commenters contend that the NOPR pro forma tariffs are
based upon the contract path, embedded cost methodology. According to
EEI and other IOU commenters, conforming changes may be needed to
various terms and conditions of the tariffs to implement pricing
methodologies that are not based upon contract path. These commenters
argue that any flow-based model would necessitate different non-price
terms and conditions. The commenters generally recognize the technical
difficulties of implementing a flow-based model.431 These
commenters assert that the NOPR pro forma tariffs, as written, are not
independent of pricing.
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\431\ Additional comments concerning transition to flow-based
pricing are summarized in Section IV.A.6.
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EGA criticizes the assumption underlying the contract path
approach,
[[Page 21598]]
i.e., that the capacities of individual transmission paths can be
determined independently and made available to third parties. EGA notes
that, in light of the competitive implications associated with
transmission pricing, some utilities may propose other non-price terms
and conditions suitable for other pricing methods, including power-
flow-based tariffs. EGA expresses concern that the pro forma tariffs
will be the only type of tariff allowed. EGA believes that the
Commission should follow its transmission pricing policy guidelines and
not impose a special burden on parties proposing tariffs that differ
from the final rule pro forma tariffs, including non-price terms that
support alternative pricing methods.
Some commenters also interpret the lack of reference to opportunity
cost and incremental cost in the NOPR pro forma tariffs as a rejection
of their use.432
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\432\ E.g., BPA, Utilities For Improved Transition, PG&E, Duke.
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Commission Conclusion
We agree that non-price terms and conditions cannot be designed
independent of pricing and cost recovery. As discussed in detail below,
the Final Rule pro forma tariff is intended to initiate open access,
with non-price terms and conditions based on the contract path model of
power flows and embedded cost ratemaking. It is designed based on the
practices and procedures currently used by virtually all public
utilities and complements the large number of tariffs already filed
with the Commission. The Final Rule pro forma tariff is not intended to
signal a preference for contract path/embedded cost pricing for the
future. We recognize that the industry, in response to changes in
institutions, competitive pressure, and technological innovations, is
evolving rapidly. For example, various forms of flow-based pricing are
beginning to be considered in conjunction with electronic transmission
information systems. We seek to encourage this process and will in the
future entertain non-discriminatory tariff innovations to accommodate
new pricing proposals.433
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\433\ We further clarify that, contrary to some commenters'
interpretation, the Final Rule pro forma tariff is in no way a
rejection of opportunity or incremental cost pricing.
---------------------------------------------------------------------------
In response to various comments, we are revising certain non-price
terms and conditions where suggested changes either improve the tariff
services or reconcile tariff inconsistencies. The nature of these
tariff revisions does not appear to have serious cost consequences. The
mandated changes are generally compatible with the rate proposals
already filed by many public utilities. As discussed in Section IV.H.,
those utilities will not be required to file corresponding rate changes
due to our mandated tariff changes to non-price terms and conditions,
although they will be permitted to do so.
The Final Rule pro forma tariff includes specific terms and
conditions rather than general principles. By initially requiring a
standardized tariff,434 we intend to foster broad access across
multiple systems under standardized terms and conditions. However, in
response to concerns raised by certain commenters, the tariff provides
for certain deviations where it can be demonstrated that unique
practices in a geographic region require modifications to the Final
Rule pro forma tariff provisions. Accordingly, where applicable, the
tariff permits the use of alternative non-price terms or conditions
that are reasonable, generally accepted in the region, and consistently
adhered to by the transmission provider.
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\434\ As noted in Section IV.H., public utilities may propose
variations that are consistent with or superior to the terms and
conditions in the Final Rule pro forma tariff.
---------------------------------------------------------------------------
Finally, we will allow utilities to propose a single cost
allocation method for network and point-to-point transmission services.
These principles, as well as other modifications and clarifications to
the NOPR pro forma tariffs, are discussed in detail below.
b. Load Ratio Sharing Allocation Mechanism for Network Service
Comments
Some commenters believe that load ratio cost allocation is
appropriate for network service.\435\ Other commenters argue that load
ratio cost allocation is inappropriate, but disagree on the
alternative. They offer a variety of other cost allocation and pricing
methods.
---------------------------------------------------------------------------
\435\ E.g., PSNM, WP&L.
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The most frequent comment is that network and point-to-point
services should be priced on the same basis. Florida Power Corp wants
network contract demand to be offered and priced on a 12 CP basis.\436\
ConEd and Duke argue that their systems are built and designed to meet
a single peak; therefore, they contend that network service costs
should be allocated with a load ratio calculation based on annual
system peak rather than 12 CP. PSE&G claims that load ratio cost
allocation works only if the customer has its own generation. Many
commenters propose that ``behind the meter'' generation and load be
eliminated from the network load ratio calculation.\437\
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\436\ Florida Power Corp's contract demand proposal would allow
a network customer to nominate less than its full load for
transmission service.
\437\ E.g., Cajun, NRECA.
---------------------------------------------------------------------------
CINergy notes that the transmission provider's monthly load ratio
calculation includes its long-term off-system firm service. It proposes
that off-system sales be eliminated from the load ratio calculation to
enable the transmission provider to offer discounts on long-term
service. Alternatively, CINergy proposes that the revenues from these
long-term off-system sales be shared with network customers based on
their load ratio.
Atlantic City and Allegheny contend that cost allocation for
network service should also reflect customers' relative energy use
(i.e., not just customers' coincident demand). Consequently, these
commenters propose that cost allocation consider the network customer's
actual load factor. Allegheny also proposes adding a minimum revenue
provision to the load ratio method to recognize cost responsibility for
non-peak use. Allegheny further proposes to include an increasing
return on equity as available transmission capacity decreases. EEI
proposes that cost allocation be based on a customer's non-coincident
peak demand.
Lower Colorado River Authority proposes using load flow studies to
determine planned use during the system peak with MW-mile billing
units. It believes that this pricing method should be used for all
transmission service to ensure comparable transmission pricing.
Oklahoma G&E wants cost allocation to be based on the impacted MW-mile
method, or alternatively, to determine embedded cost by voltage level.
Centerior proposes the use of actual transfer capability instead of
contract path capability in determining cost responsibility.
Orange & Rockland recommends some form of a ``poolco'' approach
using locational marginal cost pricing. DOE also recommends using
location-specific spot pricing (a form of marginal cost) for operating
and congestion costs.
Public Generating Pool believes that load ratio share pricing is
unworkable in the Pacific Northwest, in part because generation is
generally located outside of the control area directly served by
parties in the Northwest, and in part because BPA, which does not have
a typical service territory, dominates the regional transmission
market. Seattle states that cost allocation based solely on demand is
inappropriate for systems
[[Page 21599]]
that consist predominantly of hydro generation.\438\
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\438\ Additional comments concerning the Pacific Northwest are
summarized in Section IV.K.
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AEC & SMEPA and NRECA are concerned about pancaked rates for
network service that is provided to load served by more than one
network tariff. Other commenters advocate use of some form of regional
pricing.\439\ American Wind proposes the use of a complex seasonal
calculation, which appears to benefit wind energy. NY Com and Missouri-
Kansas Industrials also express a preference for seasonal pricing
models.
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\439\ E.g., OH Coops, Municipal Energy Agency Nebraska, UT Com.
---------------------------------------------------------------------------
Commission Conclusion
We conclude that the load ratio allocation method of pricing
network service continues to be reasonable for purposes of initiating
open access transmission. Network service permits a transmission
customer to integrate and economically dispatch its resources to serve
its load in a manner comparable to the way that the transmission
provider uses the transmission system to integrate its generating
resources to serve its native load. Because network service is load
based, it is reasonable to allocate costs on the basis of load for
purposes of pricing network service. This method is familiar to all
utilities, is based on readily available data, and will quickly advance
the industry on the path to non-discrimination. We are reaffirming the
use of a twelve monthly coincident peak (12 CP) allocation method
because we believe the majority of utilities plan their systems to meet
their twelve monthly peaks. Utilities that plan their systems to meet
an annual system peak (e.g., ConEd and Duke) are free to file another
method if they demonstrate that it reflects their transmission system
planning. Moreover, we recognize that alternative allocation proposals
may have merit and welcome their submittal by utilities in future rate
applications. They will be evaluated on a case-by-case basis and
decided on their merits.
As to the concerns raised by AEC & SMEPA and NRECA about pancaked
rates for network service provided to load served by more than one
network service provider, we have stated that if a customer wishes to
exclude a particular load at discrete points of delivery from its load
ratio share of the allocated cost of the transmission provider's
integrated system, it may do so.\440\ Customers that elect to do so,
however, must seek alternative transmission service for any such load
that has not been designated as network load for network service. This
option is also available to customers with load served by ``behind the
meter'' generation that seek to eliminate the load from their network
load ratio calculation.
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\440\ Florida Municipal Power Agency v. Florida Power & Light
Company, 74 FERC para. 61,006 (1996), reh'g pending.
---------------------------------------------------------------------------
As noted, the most frequent comment is that the network and point-
to-point services should be priced on a similar basis. This concern is
addressed in the next section.
c. Annual System Peak Pricing for Flexible Point-to-Point Service
Comments
Commenters express concern that, if annual system peak capability
is used to determine rates for point-to-point service and 12 CP is used
to allocate costs for network service, point-to-point service may be
underpriced relative to network service.\441\ Therefore, many
commenters propose pricing both services on the same basis.
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\441\ Under the annual system peak method, system costs are
allocated on the basis of each customer's contribution to the
utility's annual system peak. Under the 12 CP method, system costs
are allocated based on the average of the customer's usage at the
time of the utility's 12 monthly system peaks.
---------------------------------------------------------------------------
EEI argues that flexible point-to-point service provides a premium
service at a discount price. Therefore, EEI would increase the price
unless the Commission either (1) eliminates the flexibility or (2)
allows network customers to make non-firm sales at no additional
charge. It recommends use of 12 CP for pricing both network and point-
to-point service, but would credit point-to-point revenues to the cost
of service for network and native load to avoid over-collection from
contract demand point-to-point users. Alternatively, EEI contends that
point-to-point service could use annual system peak capability pricing
with a ratchet,\442\ although EEI believes that 12 CP reflects the
premium nature of long-term transmission. Under this alternative
method, EEI notes that long-term non-flexible point-to-point service
would use annual system peak pricing, while short-term service should
be based on ``up to'' (ceiling) rates. In essence, EEI proposes a two-
tier point-to-point service, with the first tier (flexible service) of
equal priority in all respects to network service.\443\ Ohio Edison
also claims that, as proposed, flexible point-to-point service is a
more valuable service than network service because it would be priced
lower than network service. To correct for this difference, Ohio Edison
would impose a separate rate for point-to-point non-firm use.
---------------------------------------------------------------------------
\442\ A ratchet is a billing provision that imposes minimum
payment obligations on utility customers.
\443\ See also Centerior, SCE&G, Detroit Edison.
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According to NRECA, unless the same measure of demand is included
in the calculation of network and point-to-point charges, actual
revenue from these two firm services will be greater than the actual
cost of service. FL Com believes that flexible point-to-point service
allows a transmission customer to engage in network economy
transactions without incurring a full network charge, thus gaining an
advantage over the transmission provider. Atlantic City recommends that
the Commission either (1) eliminate the flexibility of point-to-point
service or (2) price such service on a 12 CP basis. It claims that the
use of an annual system peak capability creates a higher value service
at a lower cost than network service. Based on its 1994 system data,
Atlantic City claims that there is a 33 percent difference in rates
between network and point-to-point services. Atlantic City also opposes
the requirement to offer point-to-point service on an hourly basis,
claiming that, unlike the point-to-point service customer, native load
and network service customers are responsible for system investment
year-round. Atlantic City also argues that point-to-point customers
should pay for all non-firm use, i.e., the Commission should eliminate
the flexible nature of firm point-to-point service. PSE&G argues that
point-to-point service should be used only for through-flow or out-flow
transactions with all other transactions treated as network service.
Thus, according to PSE&G, point-to-point service would not need
flexibility.
If an annual system peak capability is used, Oklahoma G&E would
redefine point-to-point service to eliminate the flexibility. FPL
recommends either eliminating the flexibility to nominate secondary
receipt and delivery points and receive non-firm service between them
or pricing point-to-point service as premium service (i.e., at a higher
price than network service). Florida Power Corp claims that flexibility
should be associated with network service, not point-to-point service.
It also argues that revenues from point-to-point service should be
credited against total transmission costs. It would similarly exclude
point-to-point demands from the derivation of the network rate. Utility
Working Group claims that if flexible point-to-point service is
retained, such service should be priced at a higher (unspecified) rate
or the non-firm secondary use should be separately priced. It believes
that all users should
[[Page 21600]]
pay for non-firm use, or if there is no additional charge under the
point-to-point tariff, network customers and the transmission provider
should be treated equally. SMUD argues that a user who does not want
flexibility should have an option to elect a lower-priced non-flexible
point-to-point service.
Commission Conclusion
We agree that pricing both services on a consistent basis may be
appropriate. Consequently, we will allow a transmission provider to
propose a formula rate that assigns costs consistently to firm point-
to-point and network services. While not requiring the use of any
particular rate methodology, we will no longer summarily reject a firm
point-to-point transmission rate developed by using the average of the
12 monthly system peaks.
Our previous rationale for not using the average of the twelve-
monthly peaks as a denominator in the development of non-customer
specific transmission rates was enunciated in Southern Company
Services, Inc., 61 FERC para. 61,339 (1992) (Southern). In Southern,
the Commission was concerned that establishing a system-wide, non-
customer specific transmission service rate that did not appropriately
account for diversity 444 among various transmission customers
might result in the over-recovery of revenues for point-to-point
service. Inherent in our ruling in Southern was the understanding that
once a sufficient pattern of customer usage under the tariff was
established, the company was free to file a customer-specific rate
using the average of the 12 monthly system peaks for cost allocation.
We still believe that it is appropriate for utilities to use a
customer-specific allocated cost of service 445 to account for
diversity, but based on the changed circumstances since Southern (which
we discuss below) we will now permit an alternative.
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\444\ In this context, diversity occurs when a customer's peak
demand is not coincident with the transmission provider's system
peak demand.
\445\ The use of this rate design is particularly applicable
where customers who were taking bundled service convert to
transmission-only service under the point-to-point tariff and
ensures that transmission costs are allocated to point-to-point
customers and network customers in a consistent manner.
---------------------------------------------------------------------------
We also note that the circumstances in Southern are distinguishable
from those now present in the industry. Southern proposed a rigid,
inflexible firm point-to-point transmission service where the customer
paid separately for each delivery and receipt point combination. The
only flexibility permitted was to use alternative receipt and delivery
points on a non-firm basis at no additional charge. As the name
implies, the flexible nature of the point-to-point transmission service
proposed in the NOPR is more akin to the service provided to native
load and network service customers. Contrary to what was proposed in
Southern, point-to-point service does not require separate charges for
each firm service receipt and delivery point combination. Rather,
customers pay on the basis of the higher of the total delivery points
or total receipt point combination. Flexible point-to-point
transmission customers continue to be able to access alternative
receipt and delivery points on a non-firm basis without additional
charges (as long as they remain within their capacity reservation). In
addition, firm point-to-point customers can reassign and resell unused
portions of their reserved firm capacity to third parties. With
flexible firm and non-firm point-to-point transmission service, the
transmission provider must make firm point-to-point transmission
capacity available to the customer regardless of its load
characteristics or use.
For these reasons, we will allow all firm transmission rates,
including those for flexible point-to-point service, to be based on
adjusted system monthly peak loads. The adjusted system monthly peak
loads consist of the transmission provider's total monthly firm peak
load minus the monthly coincident peaks associated with all firm point-
to-point service customers plus the monthly contract demand
reservations for all firm point-to-point service.
The flexibility and reassignment rights of this transmission
service require the transmission provider to hold the firm contract
capacity available regardless of the customer's own load
characteristics or its actual use. In other words, a transmission
provider's obligation to plan for, and its ability to use, a
transmission customer's reserved capacity is clearly defined by that
customer's contract reservation. For these reasons, it is appropriate
to consider a firm reservation as the equivalent of a load for cost
allocation and planning purposes.
In order to prevent over-recovery of costs for those who use this
approach, we will require transmission providers to include firm point-
to-point capacity reservations in the derivation of their load ratio
calculations for billings under network service. In addition, revenue
from non-firm services should continue to be reflected as a revenue
credit in the derivation of firm transmission tariff rates. The
combination of allocating costs to firm point-to-point service and the
use of a revenue credit for non-firm service will satisfy the
requirements of a conforming rate proposal enunciated in our
Transmission Pricing Policy Statement.446
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\446\ FERC Stats. & Regs. para. 31,005 (1994).
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d. Opportunity Cost Pricing
(1) Recovery of Opportunity Costs
Comments
EEI and IOUs generally support the notion that transmission
customers should pay some form of opportunity cost when transmission is
constrained and request that the final rule clearly define redispatch
and opportunity costs. These commenters generally agree that the final
rule should codify these terms consistent with recent Commission orders
addressing opportunity costs.
Duke requests that the final rule clarify that the transmission
customer should pay all the opportunity costs associated with modified
dispatch. Centerior argues that redispatch costs include consideration
of parallel flows and scheduled deliveries, which, according to
Centerior, cause redispatch costs to be incurred.
Florida Power Corp and NYSEG state that redispatch costs should be
either rolled in or charged on an incremental basis, consistent with
the Commission's ``or'' pricing policy. Florida Power Corp recommends
that an opportunity cost recovery provision be added to the ``Rates and
Charges'' sections of the tariffs. NYSEG recommends that the tariffs
implement the Commission's recent ruling in Florida Power & Light
Company, 66 FERC para. 61,227 (1994), allowing lost opportunity costs
to be recalculated annually. NYSEG believes that: (1) Redispatch costs
should be collected for any period in which the transmission customer
causes a constraint, including the period of time it takes to construct
incremental facilities necessary to alleviate the constraint; (2)
network customers should be responsible for any opportunity costs
incurred as a result of their non-firm use of the system if such costs
rise to a level above their load ratio share of system costs; and (3)
point-to-point customers should be responsible for any opportunity
costs incurred as a result of their non-firm use of the transmission
provider's system up to their reserved firm entitlement.
Ohio Edison believes that, given the unique nature of network
service, it is inappropriate to require network service customers to
incur redispatch costs in order to create additional capacity. PECO
requests that the final rule clearly indicate (1) from whose
perspective
[[Page 21601]]
``least cost'' redispatch is judged and (2) that the ``least cost''
redispatch obligation is subordinate to reliability.
Concerned that transmission providers could manipulate the
calculation of redispatch charges to increase profits, NRECA proposes
that transmission providers develop formal redispatch protocols that
would be provided to all customers. NRECA argues that all information
necessary to calculate redispatch costs should be made available on the
RIN. Customers assessed redispatch charges should be provided with all
the necessary information to evaluate such charges, including full
audit rights. NRECA, Cajun, and PacifiCorp object to the inclusion of
``lost opportunity'' costs in redispatch charges. NRECA proposes that
only actual non-firm sales or purchases should be included in the
calculation of opportunity costs.
United Illuminating and Seattle state that all opportunity costs
should be assessed to short-term and non-firm transmission service
customers that cause the transmission provider to redispatch its
generation to unload a constrained transmission line. According to
United Illuminating, it is not appropriate to roll opportunity costs
into the rates charged other transmission users because existing users
do not have the choice to pay the opportunity costs or to allow their
transaction to be curtailed.
UtiliCorp, on the other hand, states that all ``out of rate''
uneconomic dispatch costs should be rolled in and recovered from all
users of the transmission system. UtiliCorp argues that directly
assessing these costs to a particular customer would unfairly penalize
a customer who could not gain access to a system until after the
tariffs take effect.
CCEM argues that only lost opportunity costs associated with the
loss of firm purchases or sales should be recoverable. CCEM also
believes that the transmission provider should calculate the redispatch
costs in advance and transmission customers should be able to opt out
of redispatch if costs rise above a certain level.
Commission Conclusion
We will retain redispatch provisions in the Final Rule pro forma
tariff, but clarify that redispatch is required only if it can be
achieved while maintaining reliable operation of the transmission
system in accordance with prudent utility practice.
We find that the recovery of redispatch cost requires that: (1) A
formal redispatch protocol must be developed and made available to all
customers; and (2) all information necessary to calculate redispatch
costs should be made available to the customer for audit.
As discussed in the Section IV.H., the Commission is according
substantial flexibility to public utilities to propose appropriate
pricing terms, including opportunity cost pricing, in their compliance
tariff. However, as with any compliance filing, the rates proposed must
meet the standards for conforming proposals in the Transmission Pricing
Policy Statement.
In Northeast Utilities and Penelec, we fully explained our
rationale for allowing utilities to charge opportunity costs.447
We concluded that a public utility is entitled to full compensation for
all ``legitimate'' and ``verifiable'' costs it incurs to provide firm
transmission service.448 We explained that where a utility can
demonstrate that additional opportunity costs are incurred as a direct
result of providing transmission service, our pricing principles would
permit recovery of those costs. The Commission further explained in the
Transmission Pricing Policy Statement that when transmission capacity
is constrained and a utility does not expand capacity, we have allowed
the utility to charge transmission customers the higher of embedded
costs or legitimate and verifiable opportunity costs, but not the sum
of the two (i.e., ``or'' pricing is permitted; ``and'' pricing is not).
The opportunity costs are capped by incremental expansion
costs.449
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\447\ Northeast Utilities Service Company (Northeast Utilities),
56 FERC para. 61,269 (1991), order on reh'g, 58 FERC para. 61,070,
reh'g denied, 59 FERC para. 61,042 (1992), order granting motion to
vacate and dismissing request for rehearing, 59 FERC para. 61,089
(1992), aff'd in relevant part and remanded in part, Northeast
Utilities Service Company v. FERC, 993 F.2d 937 (1st Cir. 1993);
Pennsylvania Electric Company (Penelec), 58 FERC para. 61,278 at
62,871-75, reh'g denied, 60 FERC para. 61,034 (1992), affd,
Pennsylvania Electric Company v. FERC, 11 F.3d 207 (D.C. Cir. 1993).
\448\ Penelec, 58 FERC at 61,872; 60 FERC para. 61,034 at 61,126
(1992).
\449\ FERC Stats. & Regs. para. 31,005 at 31,138.
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Transmission providers proposing to recover opportunity costs must
adhere to the following requirements:
(1) A fully developed formula describing the derivation of
opportunity costs must be attached as an appendix to their proposed
tariff.
(2) Proposals must address how they will be consistent with
comparability.
(3) All information necessary to calculate and verify opportunity
costs must be made available to the transmission customer.
(2) Fuel Adjustment Clause Treatment for Redispatch Costs
If the transmission provider proposes to separately collect
redispatch costs on a direct assignment basis from a specific
transmission customer, we will require that the transmission provider
credit these revenues to the cost of fuel and purchased power expense
included in its wholesale fuel adjustment clause.
e. Expansion Costs
Comments
ELCON argues that direct assignment of 100% of the costs of
expanding a constrained transmission system to a particular customer is
unfair. NY Energy Buyers believes that the costs of expanding the
transmission system should be shared among all customers seeking
transmission service. Alternatively, NY Energy Buyers states that if
direct assignment of system expansions is adopted, such costs should be
payable both by new wholesale customers and by new retail load.
According to NY Energy Buyers, it would be preferable for the utility
to treat all requesters during a given period as making one request for
a large increment of capacity, with all requesters paying the same
average
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
incremental cost. New native load also should be considered to
be a requester of transmission capacity and allocated an appropriate
share of any expansion costs.
CA Energy Co believes that incremental pricing will discriminate
against all later competitors by charging higher rates. It advocates
rolled-in pricing with the requirement that all users requesting system
expansion commit to service for a term that will cover their
proportionate expansion cost assignments.
FPL proposes that costs associated with normal load growth and the
repair and/or replacement of older facilities be rolled in with the
other embedded transmission costs and shared on a load ratio basis.
However, it believes that transmission expansions associated with the
addition of a new resource should be separately assigned.
On the other hand, Orange & Rockland maintains that unless
expansion costs are directly assigned, an unfair subsidization will
occur. According to PECO, transmission customers should be assigned
costs for system upgrades under both the network and point-to-point
tariffs. Consumers Power claims that the network tariff is unclear
about which facilities are directly assignable, and proposes that all
costs that exceed the
[[Page 21602]]
embedded average cost qualify for direct assignment.
SMUD requests that the final rule clarify that if a transmission
customer invests in incremental facilities, it will be entitled to
ownership-like rights to the capacity addition.
In order to avoid possible argument over the necessity and cost of
system expansions for a particular transmission request, NIEP requests
that the final rule require utilities to use a ``least-cost'' approach
to transmission expansion that includes comparable transmission
expansion practices for all wholesale customers.
According to Duke, the concern that the transmission provider's
retail customers will retain an advantage by having expansion costs
placed on third parties is misplaced. Duke argues that, under ``or''
pricing, the issue of who is responsible for expansion costs would
still arise. It contends that the Commission will have to decide on a
case-by-case basis whether expansion costs are incurred for the benefit
of a specific party or are part of overall network costs. Duke
generally supports the current ``or'' pricing policy.
Citing the Commission's Transmission Pricing Policy Statement, FL
Com supports the flexibility of charging both embedded cost and
incremental cost transmission rates, i.e., ``and'' pricing. It argues
that, because of the dynamic and interconnected nature of the
transmission system, tariff customers causing expansion costs should be
held responsible for both the incremental cost of the addition and some
portion of the existing transmission system needed to support the
addition. FL Com states that the comparability standard is at odds with
the Commission's non-conforming transmission pricing policy,
particularly with respect to ``and'' pricing.
Commission Conclusion
Under the Final Rule pro forma tariff, we will allow transmission
providers to propose any method of collecting expansion costs that is
consistent with our transmission pricing policy. We disagree with
ELCON's assertion that directly assigning the costs for expanding a
constrained transmission system is necessarily unfair. As we stated in
Northeast Utilities, if the cost of expansion is directly attributable
to a customer's request for transmission service and the expansion
would not be undertaken ``but for'' that customer's request, then it is
reasonable to assign the cost of expansion to that customer. If we were
not to allow the direct assignment of expansion costs to the customer
causing the expansion, then other customers would subsidize the new
customer's use of the transmission system. We continue to believe that
``or'' pricing sends the proper price signal to customers and promotes
efficiency. Under the tariff, any assignment of future expansion costs
must meet the standards for conforming proposals in the Transmission
Pricing Policy Statement. Recovering expansion cost based upon ``and''
pricing will not be allowed.
Any request to recover future expansion costs will require a
separate section 205 filing. The Commission will evaluate, on a case-
by-case basis, who is responsible for expansion costs in those filings
and whether direct assignment of those costs is appropriate.
f. Credit for Customers' Transmission Facilities
Comments
Most commenters agree that the Commission must clearly define when
a network customer's transmission facilities warrant a credit from the
transmission provider. Several commenters state that customers must
bear the burden of demonstrating that their facilities are used by and
useful to the transmission provider, provide direct benefits, and
support the operation of the transmission system.450 EEI cautions
against providing a credit for facilities that may be integrated with,
but of no effective benefit to, the operation of the bulk power system.
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\450\ E.g., EEI, Consumers Power.
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The costs associated with customer-owned facilities that are used
by the transmission provider should, in PECO's opinion, be recovered
from the transmission provider under the customer's own transmission
tariff.
FPL cautions that the position of certain parties that transmission
facilities warrant a credit if they would have been included in the
transmission provider's rates could produce absurd results. It claims
that it could actually end up paying a network customer with
substantial transmission investment for the right to provide that
customer service. FPL contends that it will receive absolutely no
service from its network customers because FPL would not need, nor
could it use, any of the customers' transmission facilities to
integrate FPL's loads and resources. FPL argues that crediting under
the so called ``rate base'' test obligates the transmission provider to
purchase a load-ratio share of the customer's transmission facilities.
FPL states that, under network service, the transmission provider and
the network customer will not create a single system.
AEP recommends that a network customer receive a credit if its
transmission facilities meet the following criteria: (1) At points of
interconnection, there must be a through-flow of power from the network
customer's system to the transmission provider's system under normal
operating conditions; and (2) the customer's facilities must: (a)
Increase the transfer capability of an interface on the transmission
provider's system; (b) provide an alternative path for power flows
during transmission facility outages, thus increasing the reliability
or stability of the combined system; or (c) otherwise satisfy the
transmission provider's planning criteria for the installation of
network facilities.
WP&L argues for a broader standard and states that a transmission
customer should be entitled to a credit if the transmission owner would
have installed similar facilities to provide service for its own native
load under similar circumstances. Florida Power Corp states that the
credit for each facility should be determined on a case-by-case basis.
PacifiCorp argues that a utility may take advantage of the
transmission credit and shift major transmission investment onto
another transmitting utility and its transmission customers by simply
becoming a network customer. PacifiCorp claims that such a situation
may, for example, exist for BPA as a transmitting utility. According to
PacifiCorp, preliminary studies indicate at least one potential network
customer may be entitled to a transmission credit which would exceed
that customer's charges for BPA's network integration service.
APPA, Blue Ridge, and Cajun maintain that a customer's facilities
should be evaluated on a basis comparable to the facilities included in
the rates of transmission providers in a region. APPA argues that a
claim that the transmission customer's facilities do not benefit the
transmission system must be weighed against the fact that some
facilities included in the transmission provider's rate base may not
directly benefit the transmission customer. Cajun advocates setting
clear standards for the identification of customer-owned transmission
facilities eligible for crediting and clear guidelines for determining
the amount of the credit.
SMUD not only supports the credit under the network tariff, but
also would extend the credit to facilities used to complete a
transaction under the transmission provider's point-to-point tariff.
[[Page 21603]]
Commission Conclusion
Because of the diverse concerns raised by the commenters, we are
unable to resolve on the basis of this record the extent to which, or
under what circumstances, cost credits related to customer-owned
facilities would be appropriate under an open-access transmission
tariff. We conclude that such credits are more appropriately addressed
on a case-by-case basis, where individual claims for credits may be
evaluated against a specific set of facts.
We stress that while certain facilities may warrant some form of
cost credit, the mere fact that transmission customers may own
transmission facilities is not a guaranteed entitlement to such a
credit. The presumption of many commenters that a customer's
subscription to transmission service somehow transforms the provider's
and customer's systems into an expanded integrated whole to the mutual
benefit of both is not a valid one. As we ruled in Florida Municipal
Power Agency v. Florida Power & Light Company (FMPA), it must be
demonstrated that a transmission customer's transmission facilities are
integrated with the transmission system of the transmission provider.
Specifically, we stated that:
The integration of facilities into the plans or operations of a
transmitting utility is the proper test for cost recognition in such
cases. The mere fact that a section 211 requestor has previously
constructed facilities is not sufficient to establish a right to
credits.451
\451\ 74 FERC para. 61,006 at 61,010 (1996), reh'g pending.
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The fact that a transmission customer's facilities may be
interconnected with a transmission provider's system does not prove
that the two systems comprise an integrated whole such that the
transmission provider is able to provide transmission service to itself
or other transmission customers over those facilities--a key
requirement of integration.452 We also note that consistent with
our ruling in FMPA, if a customer wishes not to integrate certain loads
and resources, and thereby exclude them from their load ratio share of
the allocated cost of the integrated system, it may do so. Customers
that elect to do so, however, should recognize that they may need to
secure alternative transmission arrangements such as point-to-point
transmission service on an as-available basis in order to utilize those
resources for reserves.
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\452\ We caution all transmission providers that while our
discussion here addresses the requirements necessary for a
customer's transmission facilities to become eligible for a credit,
the principles of comparability compel us to apply the same standard
to the transmission provider's facilities for rate determination
purposes.
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Where disputes over credits for customer-owned transmission
facilities arise, we encourage all parties to first pursue alternative
means to resolve their differences rather than seek formal resolution
at the Commission. In any event, the Commission anticipates that
disputes over the appropriate level of transmission facility credits
should not preclude transmission customers from initiating service
under the tariff. Where the parties are unable to reach agreement on
the appropriate credit for customer-owned transmission facilities, the
parties may make an appropriate filing with the Commission.
g. Ceiling Rate for Non-Firm Point-to-Point Service
Comments
Commenters generally support a ceiling rate for non-firm
transmission service, capped at the firm rate.453 Others request
clarification as to whether the point-to-point tariff rates are fixed
or are ceiling rates. Central Illinois Public Service's major concern
is that, if the rates are fixed, the tariffs may result in higher
prices for capacity and energy than those currently allowed for bundled
service.
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\453\ E.g., Duke, SCE&G, AEP, FPL.
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NYSEG argues that unequal pricing is a natural phenomenon of the
open marketplace and requests assurance that offering transmission
service at prices below a cost-based ceiling rate will not expose a
transmission provider to claims of undue discrimination.
AEC & SMEPA opposes using the firm rate as the cap for non-firm
transmission service. It states that, given the substantially lower
quality of non-firm service (with no obligation to plan for such
service), no cost-of-service principle justifies charging rates for
non-firm service as high as the rate for firm service.
EGA and NRECA state that any discounts from the maximum firm rate
must be uniform, transparent, readily understood, and posted on a RIN.
According to CCEM and NRECA, the transmitting utility must have
nondiscriminatory discount practices and must contemporaneously offer
discounts to transmission customers at the same time and on the same
basis as discounts for internal sales operations or affiliates.
Commission Conclusion
We believe that it is important to continue to allow pricing
flexibility. In accordance with the Commission's current policies, the
rate for non-firm point-to-point transmission service may reflect
opportunity costs. Any provisions for opportunity cost pricing for non-
firm service must meet the requirements already discussed. If a utility
chooses to adopt opportunity cost pricing, the non-firm rate is
effectively capped by the availability of firm service and is not
subject to a separately-stated price cap. If a utility chooses not to
adopt opportunity cost pricing, the non-firm rate is capped at the firm
rate. We also wish to ensure that non-firm transmission service is
priced in a nondiscriminatory fashion. Accordingly, if a transmission
provider offers a rate discount to its affiliate, or if the
transmission provider attributes a discounted rate to its own
transactions, the same discounted rate must also be offered at the same
time to non-affiliates on the same transmission path and on all
unconstrained transmission paths. We will further require that any
affiliate discounts from the maximum firm rate must be transparent,
readily understandable, and posted on the transmission provider's OASIS
in advance so that all eligible customers have an equal opportunity to
purchase non-firm transmission at the discounted rate.454 In
addition, discounts offered to non-affiliates must be on a basis that
is not unduly discriminatory and must be reported on the OASIS within
24 hours of when available transmission capability (ATC) is adjusted in
response to the transaction. As discussed in the RIN section,
information, including the price for all non-firm transaction
discounts, must be posted on the OASIS to ensure comparability.
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\454\ The same requirements will apply to discounts from firm
transmission service. Similarly, if a transmission provider offers
an affiliate a discount for ancillary services, or attributes a
discounted ancillary service rate to its own transactions, it must
offer at the same time the same discounted rate to all eligible
customers. Discounted ancillary services rates must be posted on the
OASIS pursuant to new Part 37 of the Commission's regulations.
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2. Priority for Obtaining Service
Comments
The term ``priority'' is used in the comments in several senses.
The intent of the comment depends on which kind of ``priority'' is
intended. In general, there are comments about the order in which
parties can obtain new service, which we call ``reservation priority,''
and there are comments about the order in which parties lose service
they already have, which we call ``curtailment priority.'' Commenters
may establish different reservation priorities for various services,
such as network, off-system sales, firm, ability to reserve a portion
of new transmission
[[Page 21604]]
capacity to be constructed, and so on. Curtailment priorities also
differ with the type of service. However, many commenters assert that
certain parties should or should not have ``priority'' without
distinguishing the kind of priority or type of service for which
priority is intended.
a. Reservation Priority for Existing Firm Service Customers
Comments
Many IOUs, state commissions, and cooperatives strongly believe
that native load should have priority to reserve transmission capacity
under the tariffs.
EEI suggests that existing and future allocations of transmission
capacity must be based on proper transmission pricing or, in its
absence, priority of service. According to EEI, retail and existing
wholesale requirements service should have the highest priority for use
of transmission capacity, followed by long-term point-to-point service.
Dayton P&L supports a continued preference for native load growth
because native load customers have borne the majority of the costs of
the transmission system. Detroit Edison, EEI, and Florida Power Corp
claim that, because native load and network customers pay higher rates
during all hours, such customers should have higher priority for
service requests than others requesting transmission service. These
commenters also claim that the transmission provider should be able to
reserve firm capacity for native load and network service customers.
Similarly, NARUC wants wholesale and retail native load customers
to be held harmless from functional unbundling of wholesale
transmission services. Because these customers have borne the vast
majority of the costs of the utility's transmission facilities, NARUC
argues that priority of service, quality of service, and allocation of
joint and common costs to native load customers should not be affected
by the transition to an open access transmission regime.
PA Com does not share the Commission's concern that a transmission
provider may discriminate against a third party transmission customer
vis-a-vis native load. It finds nothing impermissible in this sort of
discrimination, arguing that the interconnected system was financed by,
designed for, and built to serve native load.
NRECA explains that most transmission customers that seek network
service will already be receiving similar service (albeit in a bundled
form) from their transmission providers. It argues that these customers
should receive the same priority of service as the transmission
provider's native load customers for as long as they continue to take
network service, whether under a current bundled wholesale supply
contract, a private transmission contract, or a network tariff.455
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\455\ See also American Forest & Paper, AMP-Ohio.
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East Kentucky requests that the final rule clarify that member
distribution cooperatives of G&Ts will have priority over third parties
in the use of the G&T's existing transmission facilities. TVA comments
that native load customers and emergency service to neighboring systems
should have a higher service priority than transmission services sold
to third parties (where an alternative power supply is available to the
third party).
Commission Conclusion
We reiterate that we are not requiring the transmission provider to
unbundle transmission service to its retail native load nor are we
requiring that bundled retail service be taken under the terms of the
Final Rule pro forma tariff. However, the amount of transmission
capacity available to wholesale and unbundled retail customers under
the Final Rule pro forma tariff is clearly affected by the amount of
transmission capacity that the transmission provider reserves for the
use of its native load customers and the future load growth of those
customers. The transmission provider may reserve in its calculation of
ATC transmission capacity necessary to accommodate native load growth
reasonably forecasted in its planning horizon. However, the
transmission provider is obligated to provide transmission service to
others under the Final Rule pro forma tariff out of capacity reserved
for native load growth up to the time the capacity is actually needed
for such future needs. Furthermore, as we explained previously, while
existing wholesale customers do not have any ownership-like rights to
the capacity they used during the term of their contract, they will
have a right of first refusal to that capacity after the expiration of
their contracts or when their contracts become subject to renewal or
rollover.456
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\456\ See discussion in Section IV.A.5.
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b. Reservation Priority for Firm Point-to-Point and Network Service
Comments
A number of commenters argue that all firm service should not be
treated equally. These commenters argue that the price of the service
should determine the priority that the service receives. A large number
of IOUs and potential network customers (existing requirements
customers) argue that in light of the pricing implicit in the NOPR,
(i.e., 12 CP for network versus annual system peak for point-to-point)
network service should have priority over point-to-point service
(because, all other things being equal, the price for network service
will be higher).
BG&E believes that a customer receiving service priority equal to
native load and network customers should pay comparable rates. Thus,
BG&E argues that either flexible firm point-to point service should be
priced the same as network service, or point-to-point service should
have a lesser priority than native load and network service customers
if point-to-point service is priced lower than network service.
DE Muni believes that native load and network customers must have
priority access to interfaces (particularly where they are constrained)
after system reliability concerns have been satisfied. The same
argument is advanced by commenters concerning long-term service versus
short-term service. Public Generating Pool argues that long-term
service should always have priority over short-term service because
long-term customers contribute more towards fixed-cost recovery than do
short-term customers.
Cajun objects to having its service and service to its customers,
which it characterizes as network service, receive the same priority as
firm point-to-point service customers who take service for periods as
short as one hour. Cajun points out that it, as well as other network
and native load customers, have been paying and will be paying for the
transmission facilities in place to serve their needs for many years.
According to Cajun, the transient firm point-to-point customer should
not have equal standing. Cajun suggests, however, that a long-term firm
point-to-point customer taking service for ten years or more should
have service priority equal to native load and network service
customers.
SC Public Service Authority argues that the availability of short-
term firm service with a priority equal to long-term service would
provide a means for short-term customers to obtain the advantages of
long-term firm service at a much lower total cost. As a result, it
argues that a few point-to-point customers would opt for long-term firm
service, and the burden of the residual costs of the transmission
system would fall on network customers.
EEI claims that priority for point-to-point service should be on a
continuum of firmness, with reservation (as well as
[[Page 21605]]
curtailment) priority based upon duration of service and specific
negotiated terms. EEI proposes that the point-to-point tariff be
modified to provide a first-tier category of flexible point-to-point
transmission service that is comparable in priority, price, length, and
terms of service to network service. EEI believes that this
modification will resolve the problems that are associated with
establishing priorities between network service and point-to-point
service if the Commission retains different CP cost allocation methods
for each service.
On the other hand, CCEM, a group of power marketers, supports the
concept that all firm service should be treated equally, regardless of
the term or the nature of service.
Commission Conclusion
An essential element of non-discriminatory transmission access is
the right of transmission customers to reserve and purchase
transmission service that is of the same quality as that used by the
transmission provider in serving its wholesale requirements customers
and retail load. Thus, we reject the proposal of some commenters that
transmission providers need not provide firm point-to-point service
that is of the same ``firmness'' as the transmission provider's service
to native load. However, the fact that both network service and point-
to-point service are provided on an equally firm basis does not mean
that both types of service must be priced or reserved in the same
manner.
The comments about reservation priorities for firm services boil
down to two concerns. First, due to the differences in pricing firm
point-to-point service and network service implicit in the NOPR (i.e.,
twelve-monthly CP pricing for network versus annual system peak for
point-to-point), some commenters believe that network service should
have priority over point-to-point service. Second, some commenters
maintain that according firm, short-term point-to-point service a
priority equal to long-term service provides a means for short-term
customers to avoid making a fair contribution to the long-term costs of
the system.
With respect to the first concern, we have eliminated the
differences in pricing by permitting utilities to adopt point-to-point
reservations as the customer load. As discussed above, for purposes of
the Final Rule pro forma tariff, utilities are free to propose a single
cost allocation method for the two services.
The second area of concern arises because of the first-come first-
served reservation priority in the NOPR point-to-point tariff. The
Commission recognizes that the tariffs, as proposed in the NOPR,
provide the opportunity for a customer to reserve certain valuable
rights (e.g., the right to short-term firm service during peak periods)
while avoiding in part the long-term costs of the system (perhaps by
relying on non-firm service during lengthy off-peak periods when there
is a substantially reduced chance of interruption). However, the
Commission has a countervailing concern that the transmission provider
should not be able to withhold valuable transmission capacity from
potential customers if that capacity is not being used by those who are
paying for the long-term costs of the system.
Accordingly, the Final Rule pro forma tariff provides a mechanism
to address this concern while safeguarding the rights of potential
customers to obtain access to unused capacity. The tariff provides that
reservations for short-term firm point-to-point service (less than one
year) will be conditional until one day before the commencement of
daily service, one week before the commencement of weekly service, and
one month before the commencement of monthly service. These conditional
reservations may be displaced by competing requests for longer-term
firm point-to-point service. For example, a reservation for daily firm
point-to-point service could be displaced by a request for weekly firm
point-to-point service during an overlapping period. Before the
applicable reservation deadline, a holder of a conditional firm point-
to-point reservation would have the right of first refusal to match any
longer-term firm point-to-point reservation before being displaced.
After the deadline, the reservation becomes unconditional, and the
service would be entitled to the same priorities as any long-term
point-to-point or network firm service.457
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\457\ The service itself, as opposed to reservations, is subject
to the curtailment provisions discussed below.
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The Final Rule pro forma tariff does not propose point-to-point or
network service with various degrees of firmness beyond the simple
categories of firm and non-firm. When a customer requests firm
transmission service, reservation priorities are established based
first on availability, and in the event the system is constrained,
based on duration of the underlying firm service request; customers may
choose the ``firmness'' of service they want by electing to take non-
firm service, or by reserving and paying for firm service. We have not
included any degrees of firmness in the Final Rule pro forma tariff
because having intermediate categories of firmness under point-to-point
or network service would, we believe, unnecessarily complicate the
priority system. However, utilities are free to propose and fully
support different reservation priority provisions for firm service in
subsequent rate filings as long as those provisions are not unduly
discriminatory, fully comply with the principles of comparability, and
are priced appropriately.
c. Reservation Priorities for Non-Firm Service
Comments
IOUs, state commissions, and potential network customers tend to
support the service reservation priorities for non-firm service set
forth in the NOPR pro forma tariffs (i.e., transmission service by
network customers for economy purchases to serve network load has a
higher priority than non-firm point-to-point service, which has a
higher priority than a firm point-to-point customer using transmission
service at secondary points of receipt and delivery). However, because
network customers pay a higher rate than point-to-point customers,
these commenters argue that network customers should be permitted to
use their off-peak load ratio share of the transmission system to make
off-system sales. Many commenters argue that point-to-point customers
can use their secondary service for both purchases and sales; thus,
they believe it is discriminatory to limit network customers to
purchases at secondary points.
Commenters that are opposed to the service reservation priority
scheme in the NOPR pro forma tariffs argue that transmission providers
will discriminate against third party users in favor of their native
load economy purchases. These commenters argue that all non-firm
service should have equal priority.
Other commenters, such as CINergy, would base priority on the
duration of service. CINergy claims that this method would eliminate
what it claims is an advantage (over network) given in the NOPR to
point-to-point service in making short-term purchases. TVA notes that
it establishes priority for non-firm service based on duration of
service requested, with customers in each service category receiving
priorities based on the rate they wish to pay.
Some commenters believe that the transmission price should affect
the
[[Page 21606]]
priority of customers to obtain non-firm transmission capacity.458
However, other commenters argue that this seems to be precluded by the
NOPR pro forma tariffs' service priority provisions.
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\458\ E.g., Duke, Orange & Rockland.
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Although PSE&G believes that the NOPR pro forma tariffs suggest a
first-come, first-served allocation method for capacity in excess of
that needed for firm transmission service, it proposes a fixed period
of time for all potential users to submit bids for service (e.g., one
week prior for monthly service), allowing the bid price to determine
priority (i.e., the higher bid prices receive service priority over
lower bid prices). According to PSE&G, customers could bid an ``up to''
rate subject to a price floor, with all revenues flowed back to firm
service customers. TVA also advocates departing from the first-come,
first-served approach for allocating some uses of the transmission
system, claiming that price is an effective means to establish priority
for non-firm and short-term firm services.
Utility Wind Interest Group requests that non-firm service used for
transmitting renewable resources be given a higher priority than non-
firm service used for transmitting conventional resources because
renewable resources cannot store their fuel supply.
Commission Conclusion
We continue to believe that network economy purchases should have a
reservation priority over non-firm point-to-point and secondary point-
to-point uses of the transmission system. Network transmission
customers are obliged to pay all of the costs of the transmission
system without regard to the resources from which energy is scheduled.
Therefore, it is appropriate that the transmission associated with a
network customer's economy purchases (i.e., transmission that is used
to substitute one resource for another on an as-available basis) enjoys
a higher priority than non-firm point-to-point transmission service.
Regarding the reservation priority for non-firm service under
point-to-point service, we will adopt a reservation priority based upon
duration of non-firm service, with price acting as a tie-breaker for
competing service requests of an equal duration. If there is
insufficient transmission capacity to accommodate all non-firm
transmission requests, the reservation of longer duration should
displace the shorter. For example, a reservation for a month of non-
firm service will displace a reservation for a week of non-firm
service. Also, a reservation for a week will displace a reservation for
a day, which will displace a reservation for an hour of non-firm
service. If a customer requests non-firm and later another customer
requests longer-term non-firm service before either term of service
begins, the first customer to request service has the right of first
refusal to change its request to the longer term of service. A firm
point-to-point customer's use of transmission service at secondary
points of receipt and delivery will continue to have the lowest
reservation priority.
3. Curtailment Provisions
a. Pro-Rata Curtailment Provisions
Comments
A large number of IOUs that are control area operators argue for
discretion to curtail the transaction that most effectively relieves
the constraint, in lieu of mandatory pro-rata curtailments, which they
argue are inappropriate and not cost effective.
Other commenters that do not support pro-rata curtailment argue
that preference should be given to native load or existing customers
because these customers have paid the majority of the costs of the
transmission system. A large number of customers note that their
existing contracts contain ``enhanced'' curtailment priorities (i.e.,
service to others will be curtailed before service to customers with
such curtailment priority) due to the large capital outlays made by
them in connection with their service.\459\
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\459\ E.g., TANC, Turlock, SMUD.
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Public Generating Pool believes that the proposed curtailment
provisions may not be flexible enough for transactions in the
Northwest. It argues that hydro spill should be avoided, and suggests
that transactions from federal and/or non-federal hydroelectric
generation facilities should not be curtailed pro rata with other
transactions that do not rely on such facilities. Public Generating
Pool urges that regional agreements (e.g., regional transmission group
agreements) that would achieve this goal should be given deference.
Other commenters support pro-rata curtailments for firm
service.460 PSNM states that this has been its operating practice
in the past, and PSNM expects to continue such an approach in the
future.
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\460\ E.g., PSNM and Nebraska Public Power District.
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Power marketer commenters generally support the pro-rata
curtailment adding that a standardized curtailment priority applied
nationally would provide greater open access and eliminate
discriminatory curtailments.
Commenting on a related subject, EEI maintains that the network
tariff provision for termination of service in the event a customer
fails to curtail load 461 may not be realistic for service to a
Transmission Dependent Utility. EEI suggests that the Commission
supplement this provision with a substantial penalty provision, coupled
with an indemnification requirement.
---------------------------------------------------------------------------
\461\ Proposed Pro Forma Network tariff section 9.7--System
Reliability.
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Commission Conclusion
It was not our intent in the NOPR to require all transactions to be
curtailed on a pro-rata basis regardless of whether the transaction
relieves a constraint. We intended to permit curtailments of
transactions that substantially relieve a constraint.462 We
intended and continue to believe that curtailment on a pro-rata basis
is appropriate for curtailing the transactions that substantially
relieve the constraint. In order to allay the concerns of the
commenters addressing this issue, we are clarifying the curtailment
provision of the tariff to explicitly allow the transmission provider
discretion to curtail the services, whether firm or non-firm, that
substantially relieve the constraint. Of course, any curtailment must
be made on a non-discriminatory basis, including curtailment of the
transmission provider's own use of the transmission system. Customers
that believe the curtailment policy is administered unfairly may file a
section 206 complaint at the Commission.
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\462\ The Final Rule pro forma tariff contains language allowing
the transmission provider the discretion to interrupt firm
transmission service in an emergency or other unforeseen condition
in a manner suggested by these commenters. Section 11.6, Curtailment
of Firm Service, of the Final Rule pro forma tariff provides:
However, the Transmission Provider reserves the right to
interrupt, in whole or in part, firm Transmission Service provided
under this Tariff when, in the Transmission Provider's sole
discretion, an emergency or other unforeseen condition impairs or
degrades the reliability of its transmission system.
The reference to curtailments being allocated on a proportional
(pro rata) basis addresses situations where multiple transactions
could be curtailed to relieve a constraint.
---------------------------------------------------------------------------
Concerning the request of certain Pacific Northwest commenters, we
would consider granting deference to an alternative curtailment method
to avoid hydro spill if such a regional practice is generally accepted
and adhered to across the region, as discussed further in Section IV.K.
Finally, we agree with EEI's observation that terminating network
[[Page 21607]]
service under the tariff to a transmission dependent utility that fails
to curtail load as required may not be appropriate. As a result, we
clarify that under network and point-to-point service, the transmission
provider may propose a rate treatment (penalty provision) to apply in
the event a customer fails to curtail load as required under the Final
Rule pro forma tariff. Such proposals will be evaluated on a case-by-
case basis on compliance.
b. Curtailment Provisions for Non-Firm Service
Comments
A number of commenters seek clarification of the curtailment
provision for non-firm service under the two tariffs. They note that
economy purchases by the network customer are accorded a higher
curtailment priority than non-firm service under the point-to-point
tariff. However, under the point-to-point tariff there is no
acknowledgement of this higher priority for network service.
Curtailments for non-firm transmission service under the point-to-point
tariff are simply based upon duration of service, without reference to
a higher priority for network economy purchases.
A number of commenters, including Industrial Energy Applications,
suggest that a price-based curtailment queue for non-firm transmission
will facilitate economy energy deals in highly competitive wholesale
power supply markets and allow the parties to directly address delivery
risk through the pricing mechanism.
Blue Ridge argues that the final rule should provide equal
curtailment priority for all types of non-firm transmission service.
Utilities For Improved Transition argues that network customers should
be able to transmit non-firm power imports under the network tariff
with the same curtailment priority that is assigned to all other firm
network uses of the transmission system.
A number of commenters note that the tariffs allow non-firm service
to be interrupted only for emergency or reliability reasons or to
provide firm service. These commenters contend that, under this
requirement, curtailment of non-firm service is unlikely.463 As a
result, they believe that non-firm service is elevated to firm service.
To remedy this situation, these commenters argue that transmission
providers should have the ability to curtail non-firm service for any
economic reason.
---------------------------------------------------------------------------
\463\ E.g., Florida Power & Light Company, Southern California
Edison Company.
---------------------------------------------------------------------------
Commission Conclusion
We have clarified in the Final Rule pro forma tariff that a network
customer's economy purchases have a higher curtailment priority than
non-firm point-to-point transmission service.
A higher curtailment priority should be provided to network economy
energy purchases for the reasons stated in AES Power, Inc..464 In
that case, we recognized that the network transmission customer has
already ``paid'' for the transmission of its economy purchases (i.e.,
transmission that is used to substitute one resource for another on an
as available basis) through its payment of a load ratio share of the
system.
---------------------------------------------------------------------------
\464\ 69 FERC para. 61,145 at 62,300 (1994) (proposed order), 74
FERC para. 61,220 (1996) (final order).
---------------------------------------------------------------------------
Many commenters oppose the point-to-point service provision
allowing non-firm service to be interrupted only for emergency or
reliability reasons or to provide firm service. Upon further
consideration, we agree that this provision is too narrow. Accordingly,
the Final Rule pro forma tariff is revised to allow the transmission
provider to curtail non-firm service for reliability reasons or
economic reasons (i.e., in order to accommodate (1) a request for firm
transmission service, (2) a request for non-firm service of greater
duration, (3) a request for non-firm transmission service of equal
duration with a higher price, or (4) transmission service for economy
purchases by network customers from non-designated resources.).
However, all curtailments must continue to be made on a non-
discriminatory basis including curtailments of the transmission
provider's own non-firm uses of the transmission system under the
tariff. A firm point-to-point customer's use of transmission service at
secondary points of receipt and delivery will continue to have the
lowest curtailment priority.
4. Specific Tariff Provisions
a. Network and Point-to-Point Customers' Uses of the System
Comments
Generally, transmission providers argue that the tariffs give too
much flexibility to customers, while transmission customers argue that
even more flexibility is required. The arguments are generally tied to
pricing rather than technical problems with providing any level of
service.
A common transmission provider argument is that the proposed firm
point-to-point tariff provides a premium service comparable to network
service, but at a lower rate. It has been suggested that either the
flexibility to use non-firm service at secondary points of receipt and/
or delivery at no additional charge under the point-to-point tariff be
eliminated or that point-to-point customers should pay a premium price
for such flexibility.465 Transmission providers generally argue
that flexible point-to-point service puts the transmission owner and
the network customer at a competitive disadvantage. They assert that
the point-to-point customer is able to use non-firm transmission to
reach secondary receipt and delivery points for both sales and
purchases, but the network customer may use only non-firm transmission
to reach secondary points for purchases. Thus, they argue, the flexible
point-to-point users can sell non-firm power with a small or even no
transmission component (because the underlying transmission is
effectively free). Electric Consumers Alliance and Cajun believe that
the owner and network customer competing for that sale should not be
charged for the identical transaction. Absent a change to the point-to-
point tariff, a number of transmission providers and state commissions
(including Midwest Commissions) argue that to provide balance to the
tariffs, the network tariff should permit the network customers to have
non-firm transmission to secondary receipt and delivery points at no
additional charge for both purchases and sales within its load-ratio
transmission entitlement. Utilities For Improved Transition refers to
this proposed network tariff modification as ``headroom.''
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\465\ E.g., EEI, Utility Working Group, SoCal Edison.
---------------------------------------------------------------------------
CCEM opposes the headroom concept, arguing that ``free'' use of
capacity will give transmission providers an unfair competitive
advantage. CCEM also cites Order No. 636 in support of its position.
Conversely, a number of customer groups believe the point-to-point
tariff should be made more flexible by broadly defining the concept of
points of receipt and delivery. They argue that all points of
connection between the transmitting utility and the purchasing utility
should be treated as a single point of delivery (POD) or point of
receipt (POR).466 In this manner, a customer would not have to pay
for every point of receipt or point of delivery, but could select a
contract demand level of service. The customer could then use the
service at multiple
[[Page 21608]]
points without incurring separate reservation charges for each point.
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\466\ E.g., Arkansas Cities, NRECA.
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A number of commenters contend that the Commission should not force
specific tariffs on public utilities in the Pacific Northwest due to
their unique status.467 In particular, NWRTA recommends that the
final rule recognize that the Pacific Northwest's integrated
transmission system, including large components owned by non-public
utilities, was constructed to support a unique region-wide
hydroelectric-dependent generating system. NWRTA recommends that the
final rule be sufficiently flexible to accommodate these unique
characteristics without prejudicing the interests of users or providers
of transmission services.
---------------------------------------------------------------------------
\467\ E.g., Public Power Council, Washington Water Power, NWRTA.
---------------------------------------------------------------------------
Similarly, Public Generating Pool states that the NOPR pro forma
network tariff departs from the status quo arrangements in the
Northwest and is generally unworkable because generation is usually
remote from the control area serving the network load and because BPA,
which does not have a typical service territory, dominates the regional
transmission market. Public Generating Pool suggests that the
Commission require, and the region develop, a ``generation
integration'' transmission tariff that would offer network-type service
to a source or sources of generation unbundled from the ``network
services'' designed to integrate load. Similar contract demand network
tariffs have already been proposed by some IOUs.
Commission Conclusion
We will not allow network customers to make off-system sales within
the load-ratio transmission entitlement at no additional charge.
Commenters have raised no new arguments to persuade us to do so. The
primary purpose of network service is to integrate resources to serve
loads. Use of transmission by network customers for non-firm economy
purchases, which are used to displace firm network resources, must be
accorded a higher priority than non-firm point-to-point service and
secondary point-to-point service under the tariff. Off-system sales
transactions, which are sales other than those to serve a network
customer's native load, must be made using point-to-point service. They
can be made on either a firm or non-firm basis.
A large number of transmission providers support the ``headroom''
concept, arguing that without it the flexible point-to-point service
puts them at a competitive disadvantage. This would be true if a
utility serving load were required to use network service exclusively.
However, we do not require any utility to take network service to
integrate resources and loads. If any transmission user (including the
public utility) prefers to take flexible point-to-point
service,468 they are free to do so. Any point-to-point customer
may take advantage of the secondary, non-firm flexibility provided
under point-to-point service equally, on an as-available basis.
---------------------------------------------------------------------------
\468\ See Florida Municipal Power Agency v. Florida Power &
Light Company, 74 FERC para. 61,006 at 61,013 and n.70 (1996).
---------------------------------------------------------------------------
b. Minimum and Maximum Service Periods
Comments
Commenters raise issues regarding the minimum term of one hour for
firm point-to-point service. Their concerns center on price and
priority. Transmission providers point out that their native load
customers pay the fixed cost of the transmission system every hour of
the year. They argue that comparability is not achieved by permitting
others to have service for one hour with equal priority to native load
and other long-term customers. Others worry that the one-hour minimum
term will: (1) Promote the selective use of the transmission system;
(2) impair the ability of a utility to plan its system; and (3)
adversely impact longer term transactions.
Tallahassee and KY Com are concerned that one-hour firm service may
encourage speculative advance requests for service during the system
peak day (Cajun refers to this as cream skimming). These commenters
express concern that such requests could displace other valid
transactions or constrain a corridor or interface to the detriment of
network service or native load customers. Tallahassee proposes a one-
day minimum term for firm service.469
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\469\ See also VEPCO, CSW, NYSEG, WP&L.
---------------------------------------------------------------------------
East Kentucky is concerned that users of the transmission system
could, under the Commission's proposed open-access rule, purchase
short-term firm service during peak months in lieu of annual firm
service to reduce expenses associated with the purchase of firm
transmission service. By buying short-term firm service only during the
peak months, an entity can significantly reduce its transmission
expenses by purchasing non-firm service during off-peak months when the
available transmission capacity far exceeds the demand on the
transmission system. For this reason, some commenters request that
short-term firm service be priced to generate revenues over the peak
months equal to the charge for annual firm service.
Duke argues that, because all curtailments are equal, the addition
of each one hour firm transaction will lower the reliability profile of
native load customers and other customers with long-term commitments.
It suggests that different classes of services be established that
offer transmission customers the flexibility to obtain an intermediate
level of transmission service (between native load firm and non-firm)
for transactions of shorter duration.
On the other hand, some TDUs and power marketers support the one-
hour minimum term. TAPS argues that transmission providers should not
be permitted to restrict the availability of hourly, daily or weekly
transmission service at reasonable prices, as some transmission
providers have proposed in open access cases. Brazos supports a minimum
duration of service equal to the minimum scheduling period of the
transmission owner. Turning to the maximum term of service, Chugach
objects to the imprecise requirement that transmission service be
offered for a term equal to the life of a particular generation
resource. Chugach, joined by VEPCO, suggests that the Commission
require transmitting utilities to offer five-year terms (with longer
contract terms by negotiated agreement).
Although BPA supports eliminating arbitrary term limitations and
facilitating long-term resource commitments, it is concerned that the
Commission's failure to specify a maximum term for firm transmission
service (particularly where no specific resource is being wheeled)
requires transmitting utilities to effectively sell off their
transmission capacity to third parties. In BPA's view, such a
requirement goes well beyond the intent of the Energy Policy Act.
PSE&G argues that the term limit for firm transmission service
should be consistent with the transmission provider's planning horizon
(e.g., for PSE&G, 10 years), which will ensure comparability of firm
third party customers with native load. According to ConEd, failure to
specify a maximum term for service creates uncertainty for planning
purposes. PECO believes that utilities should have the right to limit
the term of service to either: (1) The expected useful life of
facilities used in providing service; or (2) the term of permits and
land rights needed for those facilities.
[[Page 21609]]
Commission Conclusion
We will adopt a one-day minimum term for firm point-to-point
service. The one-day minimum term for firm point-to-point service,
along with modifications to the procedures for requesting firm point-
to-point service, will moot a number of reliability concerns and
allegations about possible ``cream-skimming.'' As discussed supra, firm
service requests with longer durations of service will have bumping
rights over shorter term firm service requests. Also, the one-day
minimum will not disadvantage anyone because the transmission provider
will be subject to the same one-day term for its firm point-to-point
uses of the transmission system. Because of the longer-term nature of
network service, it will be subject to a one-year minimum term.
We will not specify a maximum term for either point-to-point or
network transmission service. However, we recognize the concerns raised
by commenters that a commitment of uncertain duration makes planning
difficult. Therefore, we will modify the tariff to require that an
application for transmission service specify the length of service
being requested. This will provide the transmission provider with the
certainty it needs for planning and the transmission customer with the
flexibility to request the service it needs.
c. Amount of Designated Network Resources
Comments
The NOPR pro forma network tariff specifies that a customer may
designate only those resources that the customer owns or has committed
to purchase pursuant to an executed contract. Transmission providers
argue that there is a need for some limitation on the resources that
network customers can designate to serve their loads. Otherwise, they
assert, a utility would be required to incur costs (planning,
constructing, and operating its transmission system) that are out of
proportion to the customer's load and its share of the utility's cost
of service. However, EEI, VEPCO, and Utilities For Improved Transition
believe that the Commission's proposal to use a purchase obligation
standard is too narrow, inflexible, and susceptible to manipulation.
These IOU commenters argue that it could include very short-term
obligations and contingent obligations to purchase. EEI suggests that
the Commission should establish a minimum term so that a customer could
not designate resources for which it has only a one-month contract. The
principal problem VEPCO sees is that purchase obligations may not be
clear. According to VEPCO, a transmission customer may claim an
obligation when it has no substantial payment obligation and thus no
economic deterrent to designating that purchase obligation as a
potential resource to serve its loads. It alleges that the result is
that the transmitting utility can be forced to tie up transmission
capacity for service from a resource that may have little probability
of being used; consequently, less capacity will be available for other
uses. VEPCO further argues that, since upgrade costs are typically
rolled in, the customer may not have a strong incentive to minimize
transmission construction. EEI argues for system-specific limits based
on capacity needs to serve the network loads reliably. Alternatively,
if the ``own'' or ``purchase'' provision is to be used, EEI contends
that the customer should be required to have a significant and ongoing
obligation to purchase power (e.g., minimum one-year contracts that
impose obligations on a first-call basis).
These IOUs also recommend that the Commission not decide on a
single way to limit network resources. They note that proposals based
on percentage limits (e.g., 125%) subject to exceptions for reliability
concerns may be a reasonable approach. According to these IOUs, the
Commission should permit flexibility to develop not unduly
discriminatory provisions until experience suggests which are the best
ways to satisfy the objective. To prevent over-designating network
resources, Missouri-Kansas Industrials suggest placing a limit of 200%
of the subscriber's load.
Arkansas Cities supports limiting the definition of network
resources to those that the customer owns or contracts for. It argues
that this reasonably accommodates the planning process. Arkansas Cities
argues that any type of percentage adder would unreasonably restrict
the process.
ELCON states that virtually any issue regarding the nature of
network service can be resolved by reference to the price of such
service. According to ELCON, if a transmission customer seeks to
incorporate unlimited (i.e., unspecified) generation sources into its
network load, the customer should pay a higher rate than a network
customer that can identify a need for service to/from specified
generating units.
A related issue is how interface capacity should be allocated
between network customers and the transmission provider. IOUs generally
argue that interface capacity should be allocated based upon the load
ratio of the customers. Tariff customers generally argue that there
should be no restriction on the amount of interface capacity that they
may designate.
Commission Conclusion
We do not believe that a superior alternative has been suggested to
our purchase obligation for limiting network resources. Accordingly, we
will not change the limitation on the amount of resources a network
customer may designate. A transmission provider taking network service
to serve network load under the tariff also is required to designate
its resources and is subject to the same limitations required of any
other network customer.
Limiting the amount of resources to those that the customer owns or
commits to purchase will protect a utility from having to incur costs
that are out of proportion to the customer's load. The transmission
provider's concern that the purchase limitation will result in
excessive network resources is unfounded. A transmission customer, like
a transmission provider, has an incentive not to oversubscribe its
capacity requirements because the cost of excessive reserve margins
will be prohibitive. Requiring a strict percentage limitation could
distort the planning process by limiting the size of resource additions
a transmission customer may undertake. Allowing discretionary
exceptions to the percentage limit will inevitably lead to disputes and
claims of discrimination.
With respect to the allocation of interface capacity under network
service, we clarify that a customer is not limited to a load ratio
percentage of available transmission capacity at every interface. A
customer may designate a single interface or any combination of
interface capacity to serve its entire load, provided that the
designation does not exceed its total load.
d. Eligibility Requirements
Under the NOPR pro forma tariffs, the transmission provider and
anyone who can file a section 211 request is eligible to request
service.
Comments
In general, most commenters agree with the eligibility
requirements. However, several IOUs argue that the tariffs should be
modified specifically to preclude the use of the tariffs for retail
wheeling.470
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\470\ E.g., El Paso, Southern, NSP.
---------------------------------------------------------------------------
NIEP believes the eligibility provision should include all entities
that not only generate power themselves, but also purchase power
generated by others for
[[Page 21610]]
resale, including municipalities, federal entities with rights to
purchase, and other entities with load but no generation resources.
Power Marketing Association and others argue that the network
tariff should be modified to specifically allow service to marketers.
PacifiCorp argues that independent owners of generation resources
should not be allowed to acquire network integration service directly.
It suggests that, if the eligible utility does not have a load in the
control area, the service sought is to accommodate off-system sales,
which is a point-to-point service.
Commission Conclusion
As we previously explained, a non-discriminatory open access
transmission tariff must be made available, at a minimum, to any entity
that can request transmission services under section 211 and to foreign
entities.471 Eligibility to take service is further discussed in
Section IV.C.1.
---------------------------------------------------------------------------
\471\ See discussion in Section IV.C.1.
---------------------------------------------------------------------------
e. Two-Year Notice of Termination Provision
Comments
Ohio Edison, Utilities For Improved Transition, LA DWP, and VEPCO
believe that point-to-point transmission customers should not be
allowed to terminate transmission service prior to the end of their
contract term, especially in light of their reassignment rights. For
network service, VEPCO, Florida Power Corp, Utilities For Improved
Transition, and Duke believe that the notice of termination period
should be at least five years, to coincide with the utility's
construction horizon. In particular, VEPCO wants transmission customers
terminating service prior to the end of the contract term to pay for
network upgrades constructed for their benefit that would be stranded
due to early termination of service.
CCEM supports a six-month notice of termination as appropriate for
a term of service of one year or greater; any longer notice period
would unduly limit a transmission customer's purchasing options.
NYSEG and EEI want the flexibility to negotiate a reasonable,
mutually agreeable notice of termination period to recognize such
things as the term of the contract and the amount of service at issue.
LEPA, VT DPS, and NorAm believe that written notice of termination
should not be required for transactions of two years or less.
Commission Conclusion
We will delete the notice of termination provision from the tariff.
We believe that commenters have raised a number of valid concerns about
including the notice of termination provision. In particular, the
notice of termination will have no effect on short-term service of less
than two years. In addition, the two-year notice provision does not
coincide with either a transmission provider's planning or construction
horizon. Because we are eliminating the notice of termination provision
from the tariff, transmission service will have to be reserved and paid
for over the length of the contract term. Of course, by eliminating
this tariff provision, we are not precluding parties from negotiating
mutually agreeable terms for early termination on a case-specific
basis. However, we note that point-to-point customers are able, under
the reassignment provision, to resell unused transmission capacity.
f. Reciprocity Provision
In the NOPR, the Commission explained that it was requiring a
reciprocity provision in the non-discriminatory open access
transmission tariffs so that public utilities offering transmission
access to others would be able to receive service from transmitting
utilities that are not public utilities (e.g., municipal power
authorities and federal power marketing administrations that receive
service under a public utility's tariff).
Comments
Reciprocity Requirement
The vast majority of the jurisdictional IOUs commenting on this
issue favor a reciprocity requirement. In contrast, the non-
jurisdictional transmission customers (primarily publicly-owned
entities and cooperatives) generally oppose such a requirement. The few
state commissions commenting on this issue generally support the stated
goal of the reciprocity requirement, but question our legal authority
to require it.472 The few IPP and power marketer commenters that
address this issue do not object to reciprocity if it does not apply to
non-transmission owners.473
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\472\ E.g., IL Com, KY Com, VT DPS, GA Com.
\473\ E.g., CCEM, CA Energy Co.
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Several commenters believe that all transmission-owning utilities,
whether public or investor-owned, must be required to provide open
access service for a truly competitive wholesale power market to be
realized.474 Sierra states that specific legislation by Congress
and/or state lawmakers may be necessary to ensure that currently non-
public utilities comply with the Commission's open access requirements.
---------------------------------------------------------------------------
\474\ E.g., Sierra, MidAmerican, Tucson Power.
---------------------------------------------------------------------------
A number of commenters maintain that the Commission should enforce
reciprocity by allowing public utilities to deny transmission service
to non-public utility transmitting entities when reciprocal
transmission service is not offered.475
---------------------------------------------------------------------------
\475\ E.g., Puget, Sierra, NSP.
---------------------------------------------------------------------------
Phelps Dodge and Otter Tail believe that non-public utility
transmitting entities will continue their existing bundled service
contracts indefinitely to avoid complying with the reciprocity
requirement. Therefore, to promote transmission access through
reciprocity, Phelps Dodge and Otter Tail suggest requiring the
unbundling of existing contracts by a date certain to convert such
contracts to transmission service agreements under the transmission
provider's open access tariff.
A number of commenters argue that the Commission's only legal
authority to impose a reciprocity requirement on non-public utilities
is that provided by section 211 of the FPA.476 Large Public Power
and others suggest that mandating reciprocity is not necessary because
the stated goals of the reciprocity requirement can be met by voluntary
transmission access and through section 211 filings.
---------------------------------------------------------------------------
\476\ E.g., NRECA, Omaha Public Power District, Dairyland, AEC &
SMEPA, PA Com, IL Com, TDU Systems.
---------------------------------------------------------------------------
Many commenters do not oppose reciprocity if it is modified to
incorporate the protections present in sections 211 and 212 and the
benefits available under sections 205 and 206.477 TDU Systems
explains that section 211 contains a number of protections, e.g.,
transmitting utilities cannot be required to provide transmission
service if such service impairs their ability to provide reliable
service, disrupts existing contracts with entities seeking service, or
is inconsistent with state law regarding retail marketing areas. It
also notes that section 212 contains rate provisions that protect a
non-public utility transmission provider from being forced to provide
electric service at a non-compensatory rate. Seminole EC argues that,
without section 205/206 rights, non-public utilities cannot adjust
their tariffs or challenge tariff provisions that they believe should
not apply to them.
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\477\ E.g., NRECA, SC Public Service Authority, Seminole EC, TDU
Systems.
---------------------------------------------------------------------------
Several commenters also suggest that, without sections 211, 212,
and 205 rights and protections, reciprocity
[[Page 21611]]
provisions allow the transmission provider to deny transmission based
on its own determination of the transmission customer's attempt to
comply with reciprocity, which SC Public Service Authority contends is
letting the ``fox guard the henhouse.'' TAPS states that in no event
should the claimed lack of reciprocity constitute grounds for refusal
to offer a service agreement, or unilateral denial, delay or
termination of service. TAPS, and other cooperative, municipal, and
public power commenters suggest that some procedure must be developed
to bring reciprocity disputes before the Commission. Wisconsin
Municipals argues that this provision should be modified, claiming that
a customer's receipt of a revenue credit for transmission facilities it
contributes to the transmission provider's system should satisfy the
reciprocity requirement.
Rather than filing tariffs with the Commission, Dairyland suggests
allowing cooperatives that are not public utilities to file a
compliance transmission tariff with the Rural Utilities Service (RUS)
as it relates to the issue of reciprocity, thereby affording non-
jurisdictional cooperative utilities rights and privileges similar to
those afforded jurisdictional utilities.
Application of Reciprocity Requirement
Several commenters argue that reciprocity should apply to both the
seller and purchaser engaged in a transaction under an open access
tariff to ensure that: (1) Transmission customers cannot avoid their
reciprocity obligation by requesting service through an agent that owns
no transmission facilities; (2) a generator cannot take transmission
service in order to sell power to a non-jurisdictional entity, thereby
allowing the non-jurisdictional entity to escape the reciprocity
provision, and (3) a buyer cannot take service in order to purchase
power from a non-jurisdictional entity, thereby allowing the entity to
escape the reciprocity requirement. 478
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\478\ E.g., EEI, Consumers Power, Montana-Dakota Utilities, CSW,
Duke, BPA.
---------------------------------------------------------------------------
Entergy also is concerned that reciprocity can be evaded through
the use of power marketers. Therefore, Entergy proposes that, if the
transmission customer is neither the producer, transmitter, nor
distributor of the power and energy to be transmitted, but instead act
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
s
as a marketer, the marketer must designate an electric utility that
either produces, transmits, or distributes such power and energy as
being subject to the requirement to provide comparable service.
CCEM and NIEP support the reciprocity provision because they apply
only to transmission owners. CCEM and NIEP contend that non-
transmission-owning customers should not be required to procure
transmission capacity or hire a proxy solely to meet a reciprocity
requirement.
In contrast, CA Energy Co insists that the reciprocity provisions
of the proposed tariffs must be amended to clarify that IPPs can obtain
access even if the IPPs own no transmission assets. CA Energy Co argues
that the Commission must exempt IPPs from the reciprocity requirement
if IPPs are to be assured equal access and thus remain effective
competitors.
Publicly-Owned Entities
Publicly-owned entities argue that they differ from IOUs and cannot
provide completely reciprocal services. 479 LPPC identifies a
number of differences between publicly-owned utilities and IOUs, such
as: the publicly-owned utilities' use of tax-exempt debt, which could
be jeopardized if they are required to make their transmission systems
available for private use; restrictions on the rate-setting methods
publicly-owned utilities can use; and statutory restrictions on the
services publicly-owned utilities can offer. 480 LPPC asks that
the reciprocity provision be dropped or changed to recognize these
differences. 481 It argues that the purposes of the NOPR are met
by transmission tariffs voluntarily offered by its members that
generally meet the standard of open access.
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\479\ E.g., Blue Ridge, SMUD, LPPC, Salt River, Oglethorpe.
\480\ See also Omaha PPD, Salt River, MEAG, TAPS.
\481\ See also Omaha PPD.
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NE Public Power District notes that to the extent that the
Commission requires cost-based rates, the Commission must recognize
that publicly-owned utilities do not establish rates in the same manner
as IOUs; for example, NE Public Power District does not include
depreciation or return on equity as costs in its rates, nor does it pay
federal income taxes. It suggests that the Commission should not apply
a one-size-fits-all approach to pricing transmission service, should
consider the special circumstances of publicly-owned utilities in
exercising its authority under section 212, and should give publicly-
owned utilities the opportunity for an evidentiary hearing before
requiring them to adopt rate-setting conventions that are appropriate
for public utilities.482
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\482\ See also Heartland.
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CAMU asserts that the tax-exempt financing of government bodies may
be jeopardized due to limitations on the private use of facilities that
are financed through tax exempt bonds.483 It suggests that a
solution may be to impute the cost of capital based on the average cost
of all area utilities. Wisconsin Municipals says that the Commission
should seek an opinion from the IRS regarding whether reciprocal use
would jeopardize tax-exempt status; if it is determined it would, the
owner of the transmission facilities should be allowed to recover any
increased costs associated with the loss of tax-exempt status.484
---------------------------------------------------------------------------
\483\ See also Wisconsin Municipals, Omaha PPD, Salt River,
MEAG, MMEWC, NE Public Power District.
\484\ See also TAPS.
---------------------------------------------------------------------------
DE Muni is concerned that a utility may ``impose'' the open access
tariffs on a non-public utility customer such as a municipal system and
then demand reciprocal access to that customer's transmission
facilities to serve the municipal's retail customers.
San Francisco argues that there is no legal authority in the FPA or
case law to impose the open access requirement on non-public utility
entities. Moreover, San Francisco is concerned that the reciprocity
requirement may impair its ability to deliver its own power pursuant to
the requirements of the Raker Act.
Salt River opposes the reciprocity provision because it could
``administratively vest discriminatory market power in FERC
jurisdictional public utilities.'' Salt River further argues that
``duly adopted open access transmission tariffs or rate schedules of
publicly-owned utilities should be presumed to satisfy FERC's
reciprocity requirement, and the legislative action of the publicly-
owned utility's ratemaking body should be given deference in a dispute
brought before FERC relating to the tariff or rate schedule.''
Public Generating Pool argues that a non-public utility
transmission customer should not have to provide the same service a
public utility provides. It argues that a publicly-owned entity may
lack the resources to provide the high level of service a public
utility can provide.
Tallahassee seeks clarification that reciprocity does not mean that
investor-owned utilities can require municipal utilities to offer
services that are identical to those offered by the
[[Page 21612]]
investor-owned utilities. It argues that it is not practical to require
small utilities to provide all of the services bigger utilities provide
and that legal obligations imposed on municipal utilities may interfere
with their ability to provide certain types of open access provisions.
Tallahassee concludes that reciprocity should be equated with
comparability (the transmission user must offer service that is
comparable to the service it offers to itself).
TANC asks for clarification and suggests various changes to the
reciprocity provision. It asks whether the reciprocity requirement will
apply to it, since it is part owner of a transmission facility (the
California Oregon Transmission Project (COTP)) but has contractually
dedicated its entitlement to use of this facility to its members. It
argues that if the requirement does apply, its obligation should be
limited to the member's share of TANC's entitlement. TANC also asks
whether when it receives transmission service on behalf of a member,
that member's non-COTP transmission facilities must be made available
to the transmission provider. If that is the case, TANC asks what
voltage level of facilities must TANC and its members make available?
TANC believes that if a TANC member independently requests transmission
service from a utility, that member would be obligated to make
reciprocal service available to the utility on the share of the COTP
that member ``controls'' through TANC's entitlement. TANC argues that
neither TANC and its members nor TANC and its COTP co-owners should be
treated as ``affiliates'' under the proposed reciprocity provision. It
argues that the comparable service tariff it must provide as a member
of the Western Regional Transmission Association should satisfy the
reciprocity requirement.
TANC also asks for clarification as to how the reciprocity
provision would be administered. A non-public utility cannot file a
tariff with the Commission, so presumably it and the public utility
from which it wants transmission service would negotiate; if, however,
the public utility does not agree that reciprocal service is being
offered, it will deny access to its transmission facilities, and the
non-public utility would have to come to the Commission to resolve the
dispute. SC Public Service Authority expresses a similar concern. It
argues that the reciprocity provision will prevent non-public utilities
from obtaining comparable access. The public utility from which the
non-public utility wants access will be able to delay access by
claiming that the reciprocity provision is not satisfied. Even the
possibility of such a delay may discourage customers from contracting
with non-public utilities. SC Public Service Authority suggests that
this problem can be fixed by allowing non-public utilities to file
comparable access tariffs with the Commission.
NE Public Power District asserts that while government-owned
utilities are subject to limited regulation under sections 211-213 of
the FPA, ``that limited grant of jurisdiction cannot be transmuted into
amenability of state- and municipally owned utilities to the sort of
detailed regulation that the NOPR would impose through requiring
insertion of so-called 'reciprocity' clauses in the transmission
tariffs of jurisdictional public utilities, by inviting the filing of
'class' Sec. 211 applications, or by making adherence to the rules
emerging from the NOPR proceeding an automatic requirement for
utilities that are subject to a section 211 application.''
NE Public Power District explains that it has pending before the
Commission a proceeding in which it has taken the position that it is
not subject to the Commission's jurisdiction. (citing Docket No. TX95-
3-000).485 NE Public Power District also argues that it would be
unconstitutional under the Tenth Amendment and the Guarantee Clause of
the United States Constitution for the Commission to assert
jurisdiction. It further argues that the proposed regulations would
constitute an unfunded Federal mandate within the meaning of the
Unfunded Mandates Reform Act of 1995 and that the Commission has not
followed the requirements of that Act.
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\485\ We note that the application in Docket No. TX95-3-000 by
Municipal Energy Agency of Nebraska was withdrawn on November 16,
1995.
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NE Public Power District explains that under Nebraska law it is
prohibited from granting or conveying to any private entity any
interest or control of any of its property or facilities, and section
211 does not authorize the Commission to order wheeling for an end-user
or to replace a contractual wholesale sale. Thus, it argues that the
Commission does not have authority to use mandatory reciprocity clauses
to obtain compliance with a policy it has no right to impose directly.
(citing Sunray and AGD). NE Public Power District also questions
whether the Commission may lawfully declare exclusive-use provisions
invalid under the Sierra-Mobile doctrine without conducting a
proceeding under section 206 with regard to each specific facility and
making the necessary findings.
Salt River responds to complaints that public power entities have a
competitive advantage, due to subsidies and preferences, over investor-
owned utilities:
This Commission is not the appropriate forum and this proceeding
is not the appropriate proceeding to consider the investor-owned
utilities' ``level playing field'' complaint as it relates to public
power, and the Commission should reject any suggestion that it do
so.486
\486\ Salt River Reply Comments at 2. See also NCMPA.
---------------------------------------------------------------------------
Cleveland urges the Commission not to address in the NOPR
proceeding either congressional policy as reflected in the tax laws or
the propriety of other long-standing federal statutes in considering
complaints that publicly-owned entities receive subsidies from the
government that IOUs do not. It points to three tax breaks available to
IOUs: (1) Investment tax credits; (2) deferred taxes resulting from
different book and tax depreciation; and (3) use of tax-exempt
financing in certain circumstances.
NRECA/APPA argues that the Commission should not, as requested by
EEI, address alleged ``undue'' subsidies received by consumer-owned
utilities and delve into such subsidy issues as municipal financing
policy, rural electrification and development policies, and the merits
of privatizing the federal power marketing administration. NRECA/APPA
alleges that these are complex issues that are within the domain of
other federal agencies.
G&T and Distribution Cooperatives
NRECA explains that under Dairyland Power Cooperative,487 the
Commission does not have jurisdiction over cooperatives that have REA/
RUS loans.488 NRECA further explains that rural electric
cooperatives are exempt from federal taxation only if 85 percent of
their revenues are derived from their members and open access could
jeopardize their tax relief.489 RUS notes that while the Energy
Policy Act expanded the Commission's authority to order transmission
access, it did not
[[Page 21613]]
amend the Rural Electrification Act (RE Act) so as to curtail the
plenary powers of RUS to carry out a program of rural electrification.
---------------------------------------------------------------------------
\487\ 37 FPC 12, 37 FPC 495 (1967), aff'd sub nom. Salt River
Project v. FPC, 391 F.2d 470 (D.C. Cir.), cert. denied, 393 U.S. 857
(1968).
\488\ See also Basin EC, Big Rivers EC (citing Golden Spread, 39
FERC para. 61,322, reh'g denied, 40 FERC para. 61,348 (1987)), RUS
(asserting that RUS has exclusive authority over rural power
cooperatives that have RUS loans).
\489\ See also McKenzie EC, NW Iowa Cooperative, TDU Systems,
RUS (asserting that if cooperative voluntarily gives up its tax
exempt status, the Commission should allow the related tax expense
to be included in the rates charged to the non-member customers
only), Brazos, Tri-State G&T, TAPS.
---------------------------------------------------------------------------
Citing various cases, Brazos says that the Commission must be
mindful of the purposes of the RE Act and, if available transmission on
Brazos is taken for use by third parties, ``a question remains as to
the capacity of the remaining portions of the system to function with
`decent service and at decent rates.' '' 490
---------------------------------------------------------------------------
\490\ Brazos Initial Comments at 6.
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Various rural electric cooperatives state that the Commission must
recognize that consumer-owned electric utilities are very different
from investor-owned utilities.491 Mor-Gran-Sou EC is concerned
that the final rule will have a detrimental impact on rural areas, just
as it believes deregulation of the banking industry, airline industry
and telecommunications industry has had.
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\491\ E.g., NW Iowa Cooperative, TDU Systems, Big Rivers EC,
Mor-Gran-Sou EC, San Luis Valley REC, Tri-County EC; see also RUS,
MEAG, Brazos.
---------------------------------------------------------------------------
Many cooperatives request that the term ``affiliates'' be defined:
(1) To apply only to corporate ``affiliates'' over which the
transmission customer exercises legal control; and (2) to exclude the
distribution cooperative members of a generation and transmission (G&T)
cooperative.492 Seminole EC explains that a G&T is a cooperative
formed by a group of distribution cooperatives; therefore, a G&T has no
legal powers to require action by its member cooperatives. In fact,
according to Seminole EC, the distribution cooperatives govern the G&T.
---------------------------------------------------------------------------
\492\ E.g., NRECA, Cajun, AEC & SMEPA, Seminole EC, TDU Systems.
---------------------------------------------------------------------------
Similarly, TDU Systems notes that the term ``affiliates'' could be
construed to apply to a joint action agency and its municipal and
cooperative members. TDU Systems point out that a joint action agency,
itself a creature of statute, may not have the power to require its
members to provide transmission service.
AEC & SMEPA contends that including the transmission customer's
affiliates in the reciprocity obligation is broader than the obligation
of the transmission provider, which does not include transmission
service by the provider's affiliates. AEC & SMEPA suggests that either:
(1) The transmission provider's affiliates should be included in the
basic obligation to provide transmission service; or (2) the
reciprocity provision should delete the reference to affiliates of the
transmission customer.
NRECA comments that it is unclear whether ``facilities owned or
controlled by the transmission customer'' include transmission
contracts. NRECA believes that transmission contracts cannot be
included in this definition, at least as applied to ``transmitting
utilities'' under sections 211 and 212.
Transmission Provider
Seminole EC questions whether the requirement to offer ``open
access'' service requires reciprocal service to be provided solely to
the transmission provider or an open access tariff available to any and
all qualified applicants. Seminole EC and NRECA request that the
Commission adopt the former interpretation in the final rule.
In contrast, Tucson Power and Phelps Dodge believe that, if a non-
public utility transmitting entity chooses to take service under any
open access tariff, such access should be conditioned on its own
agreement to provide comparable service to all eligible customers under
an open access tariff.
Tucson Power believes that, without such access to all eligible
customers, reciprocity will fail to achieve true ``comparability.''
Tucson Power explains that reciprocal transmission service would appear
to be limited by the terms of the specific original request for
transmission. For example, Tucson Power fears that a non-jurisdictional
entity requesting 25 MW of point-to-point firm service could argue that
its reciprocal transmission obligation is limited to the same 25 MW of
point-to-point firm service for an equivalent duration. Tucson Power
argues that such a limitation on providing reciprocal service would
prove useless. Further, Tucson Power believes that reciprocity should
be interpreted to require a non-public utility entity to expand or
upgrade facilities to meet the transmission requests of all eligible
entities and should contain the same pricing provisions as applied in
this proceeding for jurisdictional utilities.
Seminole EC questions whether the reciprocity requirement to
provide ``comparable'' service to the transmission provider simply
means offering the same kind of service to the transmission provider
that the transmission customer receives (i.e., network, firm point-to-
point, or non-firm).
NRECA claims that the reciprocity requirement should not be
construed to impose on non-public utilities an unreasonable obligation
to build. Seminole EC adds that an unreasonable obligation to build
could effectively preclude requests for tariff service; the
transmission customer could be better off litigating a section 211
request rather than accepting the obligation to undertake a massive
construction program.
Commission Conclusion
We conclude that it is appropriate to require a reciprocity
provision in the Final Rule pro forma tariff. This provision would be
applicable to all customers, including non-public utility entities such
as municipally-owned entities and RUS cooperatives, that own, control
or operate interstate transmission facilities and that take service
under the open access tariff, and any affiliates of the customer that
own, control or operate interstate transmission facilities. Any public
utility that offers non-discriminatory open access transmission for the
benefit of customers should be able to obtain the same non-
discriminatory access in return.
In the NOPR, we explained that the reciprocity provision would
``requir(e) any user or agent of the user of the tariff that owns and/
or controls transmission facilities to provide non-discriminatory
access to the tariff provider.'' 493 We wish to clarify that, in
stating that a user must provide non-discriminatory access to the
tariff provider, we intend that reciprocal service be limited to the
transmission provider. However, in situations in which a non-public
utility is a member of an RTG or a power pool, it also would have to
provide service to the other members of the RTG or power pool. We do
not believe it is appropriate to expand the reciprocity condition
beyond these situations at this time because, as discussed further
below, the IRS currently is evaluating its tax-exempt financing
regulations in light of competitive changes in the industry.
---------------------------------------------------------------------------
\493\ FERC Stat. & Regs. at 33,050.
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We are aware that many non-public utilities are very willing to
offer reciprocal access, and that some are willing to provide access to
all eligible customers through an open access tariff. However, they are
fearful that a public utility may deny service based simply on a claim
that the open access tariff offered by a non-public utility is not
satisfactory. To assist these non-public utilities, we have developed a
voluntary safe harbor procedure that should alleviate these concerns.
Under this procedure, non-public utilities would be allowed to submit
to the Commission a transmission tariff and a request for declaratory
order that the tariff meets the Commission's comparability (non-
discrimination) standards. We would post these requests on the
Commission Issuance Posting System (CIPS) and would provide them with
an NJ (non-
[[Page 21614]]
jurisdictional) docket designation. If we find that a tariff contains
terms and conditions that substantially conform or are superior to
those in the Final Rule pro forma tariff, we would deem it an
acceptable reciprocity tariff and would require public utilities to
provide open access service to that particular non-public
utility.494 In order to find that a non-public utility's tariff is
consistent with our comparability standards, we would need sufficient
information to conclude that the non-public utility's rate is
comparable to the rate it charges others. In addition, once we find
that a tariff is an acceptable reciprocity tariff, an applicant in a
section 211 case against a non-public utility would have the burden of
proof to show why service to the applicant under the same terms as the
reciprocity tariff is not sufficient and why a section 211 order should
be granted.
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\494\ Public utilities would also be required to provide service
during the pendency of any request for declaratory order. Otherwise,
public utilities could continue to delay providing service.
---------------------------------------------------------------------------
The safe harbor procedures that we have outlined above would be
purely voluntary for non-public utilities. The procedures are intended
to provide non-public utilities an opportunity to confirm that they are
willing to provide comparable transmission service. If, however, a non-
public utility chooses not to seek a Commission determination that its
tariff meets the Commission's comparability standards, a public utility
could refuse to provide open access transmission service only if such
denial is based on a good faith assertion that the non-public utility
has not met the Commission's reciprocity requirements.
In addition to the safe harbor procedures, we note that a non-
public utility that is a member of an RTG can meet our comparability
standards through the RTG, and can provide an open access tariff that
meets our comparability standards by filing a tariff with the
administrator of the RTG.495 Similarly, a non-public utility that
is a member of a power pool could meet our comparability standard if
the power pool adopts a joint pool-wide open access tariff.
---------------------------------------------------------------------------
\495\ See, e.g., Southwest Regional Transmission Association, 73
FERC para. 61,147 at 61,414 (1995).
---------------------------------------------------------------------------
Some commenters have challenged the Commission's jurisdiction to
require any non-public utility that takes jurisdictional service to
provide reciprocal non-discriminatory transmission services and to
unbundle its rates. We are not requiring non-public utilities to
provide transmission access. Instead, we are conditioning the use of
open access services on an agreement to offer open access services in
return. Non-public utilities can choose not to take service under
public utility open access tariffs and can instead seek voluntary
service from the public utility on a bilateral basis.
In response to arguments raised by publicly-owned utilities and
cooperatives, we are not prepared to revise or eliminate the
reciprocity condition. Our reason is simple and compelling. We are
undertaking this Rule and imposing significant responsibilities on
public utilities to ensure the Nation's transmission grid is open and
available to customers seeking access to the increasingly competitive
commodity market for electricity. While we do not have the authority to
require non-public utilities to make their systems generally available,
we do have the ability, and the obligation, to ensure that open access
transmission is as widely available as possible and that this Rule does
not result in a competitive disadvantage to public utilities. Non-
public utilities, whether they are selling power from their own
generation facilities or reselling purchased power, have the ability to
foreclose their customers' access to alternative power sources, and to
take advantage of new markets in the traditional service territories of
other utilities. While we do not take issue with the rights these non-
public utilities may have under other laws, we will not permit them
open access to jurisdictional transmission without offering comparable
service in return. We believe the reciprocity requirement strikes an
appropriate balance by limiting its application to circumstances in
which the non-public utility seeks to take advantage of open access on
a public utility's system. However, we recognize that Congress has
determined that certain entities in the bulk power market can utilize
tax-exempt financing by issuing bonds that do not constitute ``private
activity bonds'' 496 or by financing facilities with ``local
furnishing'' bonds.497 In both circumstances, Congress has
entrusted the Internal Revenue Service (IRS) with the responsibility
for implementation and for determining what uses of the facilities are
consistent with maintaining tax-exempt status for bonds used to finance
such facilities. It is not our purpose to disturb Congress's and the
IRS's determinations with respect to tax-exempt financing.
---------------------------------------------------------------------------
\496\ See 26 U.S.C. 141.
\497\ See 26 U.S.C. 142.
---------------------------------------------------------------------------
We are encouraged that the IRS is presently reconsidering its
private activity bond regulations in light of, among other things, the
changing circumstances in the electric industry, including this
proceeding.498 We are hopeful that the IRS in its rulemaking will,
to the maximum extent possible, remove regulatory impediments that
limit the ability of industry participants to provide reciprocal open
access service. Until that occurs, however, we believe we must ensure
that the reciprocity requirement will not be used to defeat tax-exempt
financing authorized by the Congress. Therefore, we clarify that
reciprocal service will not be required if providing such service would
jeopardize the tax-exempt status of the transmission customer's (or its
corporate affiliates') bonds used to finance such transmission
facilities.499 If a non-public utility has sought a declaratory
order on a voluntarily-filed tariff, we request that it identify the
services, if any, that it cannot provide without jeopardizing the tax-
exempt status of its financing.500
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\498\ Definition of Private Activity Bonds, 59 FR 67658
(December 30, 1994), Proposed Rules (to be codified at 26 CFR pt.
1).
\499\ The same would be true in the case of a G&T cooperative
that is a tax-exempt entity under section 501(c)(12) of the Internal
Revenue Code (26 U.S.C. 501(c)(12)) that would risk loss of tax-
exempt status if more than 15 percent of its revenues are derived
from business with non-members. We clarify that reciprocal service
will not be required if providing such service would jeopardize the
G&T cooperative's tax-exempt status.
\500\ A tariff offered by a non-public utility transmission
provider to satisfy the reciprocity requirement may include a
provision permitting the transmission provider to refuse service if
providing such service would jeopardize its tax-exempt status or the
tax-exempt status of its bonds. The non-public utility could file a
declaration to this effect in an NJ docket.
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We believe, given the fact that the IRS is currently examining
these issues, that our policy in this regard is appropriate for the
time being. After the IRS acts, we will reexamine our policy to ensure
that the reciprocity requirement is applied broadly to achieve open
access without jeopardizing tax-exempt financing.
With respect to local furnishing bonds, which are available to a
handful of public utilities, we note that Congress, in section 1919 of
the Energy Policy Act, amended section 142(f) of the Internal Revenue
Code to provide that a facility shall not be treated as failing to meet
the local furnishing requirement by reason of transmission services
ordered by the Commission under section 211 of the FPA if ``the portion
of the cost of the facility financed with tax-exempt bonds is not
greater than the portion of the cost of the facility which is allocable
to the local furnishing of electric energy.'' 501 San Diego G&E
has included in its existing transmission tariff a provision
[[Page 21615]]
that provides that, if it appears that the provision of transmission
service would jeopardize the tax-exempt status of any local furnishing
bonds used to finance its facilities, San Diego G&E will not contest
the issuance of an order under section 211 of the FPA requiring the
provision of such service, and will, within 10 days of receiving a
written request by the applicant, file with the Commission a written
waiver of its rights to a request for service under section 213(a) of
the FPA and to the issuance of a proposed order under section
212(c).502 We believe such a provision is necessary and
appropriate so that any local furnishing bonds that may exist do not
interfere with the effective operation of an open access transmission
regime. Accordingly, we will require any public utility that is subject
to the Open Access Rule that has financed transmission facilities with
local furnishing bonds to include in its tariff a similar
provision.503
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\501\ 26 U.S.C. 142(f)(2)(A).
\502\ See San Diego Gas & Electric Company, Docket No. ER96-43-
000, Pro-Forma Point-to-Point Transmission Service Tariff, section
4.6(d); Network Transmission Service Tariff, section 4.7(d).
\503\ See Appendix D, Pro Form Open Access Transmission Tariff,
Section 5.
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In addition, in response to arguments raised by cooperatives and
joint action agencies, we agree to limit the reciprocity requirement to
corporate affiliates. If a G&T cooperative seeks open access
transmission service from the transmission provider, then only the G&T
cooperative, and not its member distribution cooperatives, would be
required to offer transmission service. However, if a member
distribution cooperative itself receives transmission service from the
transmission provider, then it (but not its G&T cooperative) must offer
reciprocal transmission service over its interstate transmission
facilities.
Finally, a non-public utility, for good cause shown, may file a
request for waiver of all or part of the reciprocity requirement. We
would apply the same criteria we will use to determine whether to grant
a waiver of all or part of the Final Rule's requirements for public
utilities that request waiver.
The reciprocity requirement will also apply to any entity that
owns, controls or operates transmission facilities that uses a marketer
or other intermediary to obtain access. For example, if a municipal
purchases power from a marketer that also arranges for the transmission
of the power through a public utility open access tariff to the
municipal, the municipal would need to meet our reciprocity
requirements. We point out here that we have established a procedure,
set out in Section IV.K.2., for small public utilities to request a
waiver from some or all of the requirements of the Rule. We would apply
the same criteria to waive the reciprocity condition for small non-
public utilities.
g. Miscellaneous Tariff Modifications
(1) Ancillary Services
The pro forma tariff, attached as Appendix D, incorporates
conforming revisions consistent with the determinations discussed in
Section IV.D.
(2) Clarification of Accounting Issues
Comments
A number of commenters generally assert that, as presently
configured, the Commission's Uniform System of Accounts does not
support the proposed stranded cost and open access policies set forth
in the NOPR. They urge the Commission to open a separate docket to
address these accounting issues and bring together all parties to
properly resolve them. More specifically, commenters ask whether
certain of the requirements outlined in the NOPR pro forma tariffs
would require changes to the Uniform System of Accounts. In particular,
commenters are concerned that the recording of costs and revenues
related to ancillary services, facilities studies, and system impact
studies would require the creation of new accounts under the Uniform
System of Accounts. In addition, commenters raise questions about the
procedures transmission providers would have to follow for recording
the costs for their own use of the system. Commenters also indicate
that the Commission's accounting requirements may not be adequate to
provide fully for the recognition of stranded costs as contemplated in
the NOPR.
Commission Conclusion
The Final Rule will result in significant changes in the way public
utilities conduct business. This will create needs for financial
information that are different from those that the Commission and
others found necessary in the past. The Commission believes that the
accounting guidance discussed infra will be sufficient to provide the
financial information needed for regulatory purposes in light of this
Rule. Therefore, we will not institute a separate proceeding to propose
changes to our Uniform System of Accounts at the present time. We
recognize, however, that the industry is in an early stage of
transition to an environment in which truly comparable transmission
services will be provided to all wholesale users. If, after gaining
additional experience, it becomes apparent that more guidance is
needed, additional guidance can be provided at that time through
issuance of accounting interpretations, guidance letters, or a notice
of proposed rulemaking to change our accounting regulations.
Many of the accounting concerns expressed by commenters were
addressed in the Chief Accountant's January 26, 1996 guidance letter.
We offer the following additional clarifications on the Final Rule pro
forma tariff requirements and certain other accounting issues related
to the Final Rule.
(a) Transmission Provider's Use of Its System (Charging Yourself)
The purpose of functional unbundling is to separate the
transmission component of all new transactions occurring under the
Final Rule pro forma tariff, thereby assisting in the verification of a
transmission provider's compliance with the comparability requirement.
For example, if a transmission provider makes an off-system power sale,
functional unbundling requires that the revenues received from that
third-party customer be unbundled into specific transmission and
production components. The transmission component of the revenues would
be the product of the amount of transmission capacity used in making
the sale and the applicable rate. With respect to off-system sales, the
transmission provider would look to operating revenue accounts those
revenues received from the customer to whom it made the off-system
sale. We will require that the transmission service component and
energy component of those revenues be recorded in separate subaccounts
of Account 447, Sales for Resale.
(b) Facilities and System Impact Studies
Comparability mandates that to the extent a transmission provider
charges transmission customers for the costs of performing specific
facilities or system impact studies related to a service request, the
transmission provider also must separately record the costs associated
with specific studies undertaken on behalf of its own native load
customers, or, for example, for making an off-system sale. Utilities
choosing this method of recovering the cost of specific studies must
keep detailed expense records pertaining to each specific study. We
will require utilities to record the cost of such studies that are
properly includable in the determination of net income for the
[[Page 21616]]
period in a separate subaccount of Account 566, Miscellaneous
Transmission Expenses. We note, however, that not all studies performed
by a transmission provider will benefit only a single customer. To the
extent a transmission provider performs a system impact study that is
useful in providing service to all transmission customers, the costs
should be allocated to all customers.
(c) Ancillary Services
To ensure comparable transmission access a transmission provider is
obligated to provide, or offer to provide, certain ancillary services
to the transmission customer. Also, the transmission provider may offer
to provide other ancillary services to the transmission customer, as
discussed in Section IV.D. A transmission customer is obligated to
purchase certain ancillary services from the transmission provider.
Generation resources provide certain ancillary services, while
transmission resources provide other ancillary services. Consequently,
the costs of providing certain ancillary services are recorded in the
transmission provider's power production expense accounts,504
while others are recorded in the transmission provider's transmission
expense accounts.
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\504\ This discussion applies to vertically integrated
transmission providers. It may not apply, for example, to a
transmission-only company or an independent system operator.
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Some commenters suggest that there may be a need for revising the
Uniform System of Accounts to better track the costs of providing
discrete ancillary services. Other commenters believe that ancillary
services are transmission-type services and suggested that the costs of
generation-provided ancillary services be refunctionalized from power
production expense to transmission expense.
Currently, the Uniform System of Accounts requires that costs
incurred in providing ancillary services are recorded as power
production or transmission expense depending upon which resource the
transmission provider uses to supply the service. At this time, we are
not convinced that the amounts involved or the difficulty associated
with measuring the cost of ancillary services warrants a departure from
our present accounting requirements. However, in calculating separate
rates for specific ancillary services utilities must maintain
sufficient records and cost support for the derivation of the rates.
Additionally, we will specify that the revenues a Transmission Provider
receives from providing ancillary services must be recorded by type of
service in Account 447, Sales for Resale, or Account 456, Other
Electric Revenues, as appropriate.
(3) Liability and Indemnification
Comments
A number of commenters addressed the liability and indemnification
provisions of the proposed pro forma tariffs. Duke argues that the
proposed language confuses and conflates the limitation on the
Transmission Provider's and Customer's rights against each other if a
force majeure event occurs, and the requirement of indemnification
against claims by third parties.
EEI argues that the proposed indemnification provision is
inappropriate because it applies both ways, that is, the Transmission
Provider and Customer indemnify each other against third party claims
arising on their own systems. EEI suggests that the provision, as
written, could result in the utility being required to indemnify the
customer against damages incurred if, for example, an individual pried
open a transformer to steal materials and in the process was
electrocuted. This concern was also voiced by Consolidated Edison,
NYSEG, and Virginia Electric and Power Company. Consumer Power suggests
that the best answer to this issue may be to leave the issue of
allocation of risk to the contracting parties, to be resolved by
negotiation when a Service Agreement is drawn up.
The Coalition for a Competitive Market, on the other hand, argues
that the indemnification provision, as proposed, provides too much of a
limitation of the Transmission Provider's liability, requiring gross
negligence rather than simple negligence before the Transmission
Provider can be held liable for damages to third parties arising from
the Transmission Provider's actions.
Commission Conclusion
We agree with the commenters that these risk allocation provisions
must be carefully drafted so that transmission providers and customers
can accurately assess and account for their respective risks. The
indemnification provision has now been broken into two parts. The first
part is a force majeure provision which provides that neither the
transmission provider nor the customer will be in default if a force
majeure event occurs, but also provides that both the transmission
provider and customer will take all reasonable steps to comply with the
tariff despite the occurrence of a force majeure event. This protection
against unexpected and unpredictable events is appropriately made
available to both the transmission provider and transmission customer.
The second portion of the provision provides for indemnification
against third party claims arising from the performance of obligations
under the tariff. We have limited the indemnification portion of the
provision so that it is now only the transmission customer who
indemnifies the transmission provider from the claims of third parties.
The customer is taking service from the transmission provider and may
appropriately be asked to bear the risks of third-party suits arising
from the provision of service to the customer under the tariff. We find
that this new indemnification provision would be too strict if it
required customers to indemnify transmission providers even in cases
where the transmission provider is negligent. See Pacific Interstate
Offshore Company, 62 FERC para. 61,260 at 62,733-34 (requiring
amendment of indemnification provisions that required indemnification
except in cases of ``gross negligence''). Accordingly, the revised
provision provides that the customer will not be required to indemnify
the transmission provider in the case of negligence or intentional
wrongdoing by the transmission provider.
(4) Miscellaneous Clarifications
(a) Electronic Format
In the NOPR, we proposed that public utilities making Stage Two
filings be required, in addition to the requirements specified in Part
35, to file copies of such filings on a diskette in ASCII format. We
will now require that public utilities, in addition to complying with
the requirements of Part 35, submit a complete electronic version of
all transmission tariffs and service agreements in a word processor
format, with the diskette labeled as to the format (including version)
used, initially and each time changes are filed. After the initial
compliance filing, utilities proposing changes to the Final Rule pro
forma tariff terms and conditions must provide a detailed list of
changes and, to the extent practicable, provide an electronic version
that reflects changes in redline/strikeout format.
(b) Administrative Changes
A number of commenters request tariff modifications of an
administrative nature. We have adopted many of these recommendations.
Due to the nature of these changes, we feel that no further
[[Page 21617]]
explanation is necessary. The tariff modifications include the
following:
Part I--Common Service Provisions
Description
Added definition for Curtailment.
Modified definition for Good Utility Practice.
Added definition for Interruption.
Added definition for Load Shedding
Added definition for Long-Term Firm Point-to-Point
Transmission Service.
Added definition for Third-Party Sale.
Modified provision for Interest on Unpaid Balances to
include amounts placed in escrow.
Modified provision for Customer Default to not require
termination of service.
Deleted contradictory language from the provision for
Rights Under the Federal Power Act.
Deleted references to Valid Request throughout the tariff.
Part II--Point-To-Point Transmission Service
Description
Added language that multiple generating units at one site
are considered one point of receipt.
Changed the time to file an unexecuted service agreement
from 10 days to 30 days.
Changed the time to execute a service agreement from 30
days to 15 days.
Deleted charge for scheduling changes.
Deleted redundant language on study agreements.
Changed standards for estimates from binding to good
faith.
Clarified that schedules of energy submitted to the
delivering party will equal the schedules of energy submitted by the
receiving party unless reduced for losses.
Clarified that the term of non-firm point-to-point
transmission service need not expire before the customer may submit
another application for service.
Added language for rate treatment in the instance when a
customer uses more non-firm point-to-point transmission service than it
has reserved.
Clarified Deposit provision to permit return of deposit at
expiration of service agreement rather than crediting the deposit
against unspecified customer obligations under the tariff.
Clarified provision for Yearly Extensions for Commencement
of Service.
Clarified provision for Reservation of Non-Firm Point-to-
Point Transmission Service.
Modified provision for customer Power Factor to permit
mutually agreeable alternatives to maintaining a specified power
factor.
Part III--Network Integration Transmission Service
Description
Deleted redundant Direct Assignment provision.
Added language to clarify that a transmission customer
does not have to use the transmission provider's point-to-point
transmission service if the sales to non-designated loads do not use
the transmission provider's system.
Modified Transmission Customer Redispatch Obligation to
limit the redispatch obligation to reliability reasons.
Deleted Member System requirement from network service.
Deleted redundant General Conditions.
Added provision to return application if customer does not
remedy deficiency.
Deleted redundant language for designating new network
resources.
Deleted redundant language for connecting new member
systems.
Deleted redundant language for new interconnection points.
Added a 60 day period for initial applications consistent
with the point-to-point service provision. (If applications during this
period exceed available capacity, they are considered simultaneous
requests and service will be decided based on a lottery.)
Modified System Impact Study provision.
Added 30 day turnaround for Facilities Study Agreement and
changed estimates from binding to good faith.
Deleted redundant language for adding new network
resources.
Added language for rate treatment in the instance when a
customer fails to curtail or shed load.
Deleted redundant language from Network Operating
Committee.
H. Implementation
The Commission proposed in the NOPR a two-stage implementation
process that would apply to all transmission-owning public utilities
that do not have non-discriminatory open access transmission tariffs on
file on the effective date of the final rule. As proposed in the NOPR,
public utilities already in compliance with the rule would not be
subject to the two-stage process.
In Stage One, the Commission proposed to put into effect tariffs
for network and point-to-point services, which include ancillary
transmission services. These tariffs would specify the minimum terms
and conditions of service needed to eliminate undue discrimination, and
were proposed to be effective 60 days after the effective date of the
final rule. Because the proposed pro forma tariffs did not contain
specific rates, the Commission proposed to itself establish, for each
affected public utility, just and reasonable rates for network service,
point-to-point service, and six identified ancillary services. These
rates were to be incorporated into each utility's tariffs.
In Stage Two, which was to begin 61 days after the effective date
of the final rule, parties would have been allowed to propose changes
to the rates, terms, and conditions for service under utilities'
transmission tariffs pursuant to sections 205 and 206 of the FPA.
Comments
The commenters are split on the two-stage implementation procedure
proposed in the NOPR. Commenters in favor of the proposed procedure
believe that a two-stage process is necessary to put basic open access
tariffs in place without delay.505 Florida Power Corp and NIEP
state that a longer implementation procedure would create a
discriminatory situation for utilities that have filed open access
tariffs versus those that have not. Other commenters, however, contend
that the proposed Stage One rates would be just and reasonable only as
an interim measure; therefore, the period during which such rates are
effective should be limited.506
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\505\ E.g., ABATE, CO Com, DOE, Florida Power Corp, IBM, IL Com,
MN DPS, Industrial Energy Applications, Missouri-Kansas Industrials,
NIEP, ND Com, PG&E, PSNM, SBA, SC Public Service Authority, TDU
Systems.
\506\ E.g., SC Public Service Authority.
---------------------------------------------------------------------------
Those commenters that oppose the two-stage implementation process
do so for a variety of reasons.507 Many transmission customers
believe that Stage One rates will be much higher than the rates they
pay now. Several commenters warn that the implementation plan may not
be practical if the Commission is inundated with filings at the
beginning of Stage Two.508 Some commenters expressing concerns
about transmission pricing policy believe that in the NOPR the
Commission intended to establish the Stage One rate method as its own
[[Page 21618]]
official pricing policy, while other commenters argue that the Stage
One rates demonstrate that broad pricing policy reform is needed as
part of an open access rule.
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\507\ E.g., Dayton, Carolina P&L, Citizens Utilities, Montana
Power, Oglethorpe, OK Com, Seattle, Seminole EC, St. Joseph,
Turlock, WA Com.
\508\ E.g., Christensen, Seminole EC.
---------------------------------------------------------------------------
Some commenters express concern about the timing of Stage One.
Carolina P&L complains that the proposed implementation date is far too
aggressive and proposes a one-year delay between the final rule and its
implementation. Montana Power states that Stage One tariffs cannot be
implemented in 60 days if any sort of functional unbundling is
required. It insists that utilities should be given, at a minimum, 180
days in which to hire and train new employees and to install new
equipment. Dayton P&L believes that Stage One tariffs should not be
imposed until experience is gained with voluntarily-filed open access
tariffs, but recommends further development of the tariffs for guidance
purposes. It also requests that the Commission delay implementation of
mandatory open access transmission until meaningful appellate review
has taken place. Seattle suggests that the rate determination methods
be phased in, so that the forced filing of transmission tariffs does
not cause immediate and major shifts in cost allocation between old and
new customers.
A few commenters express concern about the applicability of the
implementation process. EEI and Consumers Power state that utilities
that have already filed open access tariffs should have the option to
use the two-stage implementation procedure so that they can obtain the
terms and conditions of the NOPR tariffs without having to make a full-
blown rate case filing.
Citizens Utilities asks that small distribution public utilities be
exempt from Stage One if such entities can demonstrate that they do not
use their own transmission systems to provide network service.
Alternatively, it asks that application of Stage One to small public
utilities be deferred until 60 days after they receive a section 211
request. Oglethorpe states that the proposed method of Stage One
pricing is not appropriate for electric cooperatives that receive
financing from the Rural Utilities Service (formerly the Rural
Electrification Administration).
Commission Conclusion
In light of the many concerns raised regarding the proposed
implementation process, the need to have adequate open access tariffs
on file for all public utilities as soon as possible, the large number
of utilities that have already filed some form of open access tariffs,
and the desire to give public utilities flexibility to propose their
own rates to be used in conjunction with the minimum non-rate terms and
conditions necessary to ensure comparable service, we have decided to
modify our proposed procedures. The details of the revised procedures
are discussed below. In addition, special implementation requirements
for coordination arrangements (power pools, public utility holding
companies, and bilateral coordination arrangements) are discussed in
Section IV.F.
The Revised Procedures
Implementation of the Rule will vary slightly for those public
utilities that tendered for filing open access tariffs before the date
of issuance of this Rule (including newly-tendered applications that
have not been accepted for filing before the issuance of this rule) and
those public utilities that did not tender open access tariffs before
the issuance of this Rule. The former group is hereinafter referred to
as Group 1 public utilities, while the latter group is referred to as
Group 2 public utilities.
1. Group 1 Public Utilities
Group 1 public utilities will be required, within 60 days following
publication of the Final Rule in the Federal Register, to make section
206 compliance filings that contain the non-rate terms and conditions
set forth in the Final Rule pro forma tariff and identify any terms and
conditions that reflect regional practices, as discussed below.
Attached as Appendix E to this Rule is a list of Group 1 public
utilities.
As to rates, we note that a transmission tariff rate is already in
effect for all Group 1 public utilities, except for the few with
recently-tendered applications that have not yet been accepted for
filing. Most of these rates have been suspended, accepted for filing,
set for hearing, and made subject to refund. Some have been accepted
outright. Still others are the product of rate settlements.
We anticipate that our mandated changes in non-rate terms and
conditions are compatible with the rate proposals already filed by
Group 1 public utilities. Consequently, we are not going to divert the
industry's resources by mandating any rate changes to fine-tune these
interim tariffs. Should, however, a Group 1 public utility determine
that certain rate changes are necessitated by the revised non-rate
terms and conditions, it may file a new rate proposal under FPA section
205. Such filings must be ``conforming'' 509 under the
Transmission Pricing Policy Statement and must be made no later than 60
days after publication of the Final Rule in the Federal Register.
Intervenors may raise any concerns with the filings within 15 days
after such filings.510 We hereby impose a blanket suspension for
any filings by Group 1 public utilities proposing rate changes
necessitated by the new non-rate terms and conditions. These rates will
go into effect, subject to refund, 60 days after publication of this
Rule in the Federal Register (the same day on which the non-rate terms
and conditions of the Final Rule pro forma tariff go into
effect).511
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\509\ As described in the Transmission Pricing Policy Statement,
a ``conforming'' proposal is one that meets the traditional revenue
requirement and reflects comparability. FERC Stats. & Regs. para.
31,005 at 31,141.
\510\ Given the brief comment period on the compliance filings,
we will require public utilities to serve copies of their compliance
filings (via overnight delivery) on: all participants in their
current open access rate proceedings (if applicable); all customers
that have taken wholesale transmission service from the utility
after the date of issuance of the Open Access NOPR; and the state
agencies that regulate public utilities in the states of those
participants and customers.
\511\ The Commission retains the right to reject such rates or
to set them for hearing.
---------------------------------------------------------------------------
If the Final Rule tariff's non-rate terms and conditions do not in
the opinion of the utility necessitate a change in current rates, then
the current rates will continue in effect under whatever refund
conditions, if any, now apply to those rates.
2. Group 2 Public Utilities
Group 2 public utilities will be treated the same as Group 1 public
utilities with regard to non-rate terms and conditions, but will be
treated slightly differently from Group 1 as to rates, since Group 2
utilities have not filed any proposed rates. We will require these
utilities to either: (i) Within 60 days following publication of the
Final Rule in the Federal Register, make section 206 compliance filings
that contain the non-rate terms and conditions set forth in the Final
Rule pro forma tariff and identify any terms and conditions that
reflect regional practices, as discussed below; and (ii) within 60 days
following publication of the Final Rule in the Federal Register, make
section 205 filings to propose rates for the services provided for in
the tariff, including ancillary services; or (iii) make a ``good
faith'' request for waiver. The rates must meet the standards for
conforming proposals in the Commission's Transmission Pricing Policy
Statement and comply with the guidance concerning ancillary services
set forth in this order. Attached to this
[[Page 21619]]
Rule as Appendix F is a list of Group 2 public utilities.
Intervenors may raise any concerns with these filings within 15
days after the filing.512 We hereby impose a blanket suspension
for all such rate filings; they will go into effect, subject to refund,
60 days after the publication of this Rule in the Federal Register (the
same day on which the terms and conditions of the compliance tariffs go
into effect).513
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\512\ Group 2 public utilities must serve a copy of their
filings (via overnight delivery) on all customers that have taken
wholesale transmission service from them since March 29, 1995 (the
date of issuance of the Open Access NOPR) and on the state agencies
that regulate public utilities in the states where those customers
are located.
\513\ But see note 510, supra.
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3. Clarification Regarding Terms and Conditions Reflecting Regional
Practices
We have built a degree of flexibility into the tariffs to
accommodate regional and other differences. Certain non-rate Final Rule
pro forma tariff provisions specifically allow utilities either to
follow the terms of the provision or to use alternatives that are
reasonable, generally accepted in the region, and consistently adhered
to by the transmission provider (e.g., time deadlines for scheduling
changes, time deadlines for determining available capacity). In
addition, other tariff provisions require utilities to follow Good
Utility Practice. The definition of ``Good Utility Practice,''
contained in Section 1.14 of the Final Rule pro forma tariff, states
that it ``is not intended to be limited to the optimum practice,
method, or act to the exclusion of all others, but rather to be
acceptable practices, methods or acts generally accepted in the
region.'' Thus, where public utilities are permitted to follow regional
practices, and elect to do so within 60 days of the date of publication
of the Final Rule in the Federal Register, they should identify the
regional practices in their compliance tariff filings.
4. Future Filings
We recognize that there may be circumstances in which a public
utility believes that the Final Rule pro forma tariff does not provide
sufficient flexibility or that the utility can propose superior non-
rate terms and conditions. Thus, once the compliance tariff and
conforming rates go into effect, which will be 60 days after
publication of this Rule in the Federal Register, a public utility
(either Group 1 or Group 2) may file pursuant to section 205 a tariff
with terms and conditions that differ from those set forth in this
Rule, provided that it: (1) Serves a copy of its filing on all
wholesale customers for whom it has provided transmission service since
March 29, 1995 (the date of the Open Access NOPR) and on the state
agencies that regulate public utilities in the states where those
customers are located; (2) identifies all deviations from its
compliance tariff in its letter of transmittal; (3) provides, to the
extent practical, a redlined version of the tariff; and (4)
demonstrates that such terms and conditions are consistent with, or
superior to, those in the compliance tariff. However, it may not seek
to litigate fundamental terms and conditions set forth in the Final
Rule.514 In addition, the public utility may file whatever rates
it believes are appropriate, consistent with the Transmission Pricing
Policy Statement.
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\514\ As we stated in our ``Further Guidance Order,'' American
Electric Power Service Corp., 71 FERC para. 61,393, 62,539-40, order
on rehearing, 72 FERC para. 61,287, order on rehearing, 74 FERC
para. 61,013 (1995), all tariffs need not be ``cookie-cutter''
copies of the Final Rule tariff. Thus, under our new procedure,
ultimately a tariff may go beyond the minimum elements in the Final
Rule pro forma tariff or may account for regional, local, or system-
specific factors. The tariffs that go into effect 60 days after
publication of this Rule in the Federal Register will be identical
to the Final Rule pro forma tariff; however, public utilities then
will be free to file under section 205 to revise the tariffs, and
customers will be free to pursue changes under section 206.
---------------------------------------------------------------------------
5. Waiver
Finally, as noted above, several commenters propose that public
utilities that own few transmission facilities be granted waiver, or
that application of the Rule to such utilities be deferred until 60
days after they receive a section 211 request. As discussed more fully
in Section IV.K.2., we find that it is reasonable to permit certain
public utilities for good cause shown to file, within 60 days after
this Rule is published in the Federal Register, requests for waiver
from some or all of the requirements of this Rule. The filing of a
request in good faith for a waiver from the requirement to file an open
access tariff will eliminate the requirement that such public utility
make a compliance filing unless thereafter ordered by the Commission to
do so. It will not, however, exempt such public utility from providing,
upon request, transmission services consistent with the requirements of
the Final Rule.
I. Federal and State Jurisdiction: Transmission/Local Distribution.
In the original Stranded Cost NOPR, the Commission clarified that it
has exclusive jurisdiction over unbundled retail transmission in
interstate commerce by public utilities: it found that the Commission
has exclusive jurisdiction over the rates, terms, and conditions of
unbundled retail transmission in interstate commerce by public
utilities, up to the point of local distribution. In the Open Access
NOPR, the Commission reaffirmed this jurisdictional determination
515 and also addressed the distinction between transmission and
local distribution. The Commission stated three reasons for expressing
its views on the distinction between Commission-jurisdictional
transmission in interstate commerce and state-jurisdictional local
distribution, in the context of unbundled retail wheeling by public
utilities.516 First, facilities that can be used for wholesale
transmission in interstate commerce by a public utility would be
subject to the Commission's open access requirements. Second, states
have authority to address retail stranded costs and stranded benefits
through their jurisdiction over facilities used in local distribution.
Third, as the structure of the industry continues to change
dramatically, utilities need to know which regulator has jurisdiction
over which facilities and services in order to meet state and federal
filing requirements. Accordingly, the NOPR set forth our jurisdictional
analysis and several technical factors, for determining what
constitutes ``facilities used in local distribution.''
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\515\ That determination included the situation in which a
former bundled retail customer may need unbundled wheeling services
from its previous public utility generation supplier, as well as
unbundled wheeling from one or more intervening public utilities, in
order to reach a distant generation supplier. In that scenario, the
Commission would have jurisdiction over all of the transmission
facilities used for the unbundled wheeling provided by the
intervening public utilities. The NOPR also noted that the
Commission would not have jurisdiction over the rates for the sale
of generation by the distant supplier because the transaction would
be a retail sale. FERC Stats. & Regs. para. 32,514 at 33,144.
\516\ The term ``wheeling'' is intended to cover any delivery of
electric energy from a supplier to a purchaser, i.e., transmission,
distribution, and/or local distribution. The Commission also has
jurisdiction to order wholesale transmission services in either
interstate or intrastate commerce by transmitting utilities that are
not also public utilities. See Tex-La Electric Cooperative of Texas,
Inc., 67 FERC para. 61,019 (1994), reh'g pending.
---------------------------------------------------------------------------
For unbundled wholesale wheeling, the NOPR proposed to apply a
functional test, i.e., whether the entity to whom the power is
delivered is a lawful reseller. For unbundled retail wheeling, the NOPR
proposed to apply a combination functional-technical test that would
take into account technical characteristics of the facilities used for
the wheeling. The Commission proposed seven indicators of local
distribution to be evaluated on a case-by-case basis:
[[Page 21620]]
(1) Local distribution facilities are normally in close proximity
to retail customers.
(2) Local distribution facilities are primarily radial in
character.
(3) Power flows into local distribution systems; it rarely, if
ever, flows out.
(4) When power enters a local distribution system, it is not
reconsigned or transported on to some other market.
(5) Power entering a local distribution system is consumed in a
comparatively restricted geographical area.
(6) Meters are based at the transmission/local distribution
interface to measure flows into the local distribution system.
(7) Local distribution systems will be of reduced voltage.517
---------------------------------------------------------------------------
\517\ FERC Stats. & Regs. para.32,514 at 33,145.
---------------------------------------------------------------------------
The NOPR concluded that the application of these tests will enable
states to address stranded costs by imposing an exit fee on departing
retail customers, or including an adder in the retail customers' local
distribution rates.518
---------------------------------------------------------------------------
\518\ Id. at 33, 144-45.
---------------------------------------------------------------------------
In the NOPR, the Commission also addressed buy-sell transactions in
which an end user arranges for the purchase of generation from a third-
party supplier and a public utility transmits that energy in interstate
commerce and re-sells it as part of a ``nominal'' bundled retail sale
to the end user. We explained that the retail sale is actually the
functional equivalent of two unbundled sales (one transmission and the
other the sale of power) and that we have exclusive jurisdiction over
the voluntary sale by public utilities of unbundled transmission at
retail in interstate commerce.519
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\519\ As discussed infra, there also would be a component of
local distribution in such a transaction that would be subject to
state jurisdiction.
---------------------------------------------------------------------------
Comments
Several commenters support the Commission's proposed jurisdictional
demarcation.520 San Diego G&E states that the Commission correctly
proposed to look at both functional factors (such as whether the
service is retail or wholesale) and technical factors (such as
voltage). PG&E states that the NOPR's functional/technical test is
preferable to a bright line voltage test.
---------------------------------------------------------------------------
\520\ E.g., PG&E, Wisconsin Coalition, Com Ed.
---------------------------------------------------------------------------
Consumers Power states that the Commission has exclusive
jurisdiction over all wheeling on an interconnected interstate
transmission grid. It suggests that the Commission and the states act
through a joint board or hearing to resolve jurisdictional differences
and develop a bright line test.
PSE&G and PG&E express concern that if retail wheeling is
implemented, there may be loopholes that would enable customers to
evade state jurisdiction and thus avoid paying stranded costs. For
example, PSE&G is concerned that a retail customer may request
transmission service only and a state commission will be unable to
attach a retail stranded cost surcharge to that customer. PG&E proposes
adding another indicator to the functional/technical test--a final tap
to a retail customer--to ensure that ``high-voltage'' retail customers
do not evade the state's reach. Moreover, to ensure that retail
customers cannot escape state jurisdiction, PG&E recommends that the
Commission state, as a matter of policy, that ``all retail customers
taking retail transmission service from their host utility by
definition take service over local distribution facilities.''
CINergy agrees with the Commission that a distinction between
transmission and local distribution is important, but emphasizes the
practical need for clarity on a timely basis. To achieve certainty,
CINergy proposes that the Commission allow public utilities to file,
under section 205, classifications of their facilities as transmission
or local distribution. CCEM endorses CINergy's proposal. Although NARUC
disagrees that the Commission has jurisdiction over unbundled retail
transmission, if the Commission reaffirms the NOPR regarding its
jurisdiction, then NARUC supports CINergy's proposal.
PSE&G strongly supports the Commission's proposed case-by-case
methodology for determining whether facilities should be classified as
transmission or local distribution. SoCal Edison argues that since a
utility may have difficulty determining which of its facilities are
transmission and which are local distribution, utilities and states
should be able to ask the Commission to classify a particular facility.
Portland and Orange & Rockland suggest that the Commission provide a
forum to resolve disputes over the correct classification of particular
facilities.
Ohio Edison states that the Commission should assume jurisdiction
o
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
ver unbundled retail transmission, but only where a state has required
this unbundling. It also believes that the Commission should assert
jurisdiction over the ancillary services necessary to provide this
jurisdictional service.
NYSEG argues that the Commission lacks jurisdiction over the
transmission component of bundled retail service. On the other hand,
NYSEG argues that the statute, legislative history, and case law reveal
that the Commission has jurisdiction over unbundled retail wheeling
from source to load, since it is transmission in interstate commerce.
NYSEG argues that the ``local distribution'' exception to the
Commission's jurisdiction applies only to bundled sales of power at
retail.
Several state commissions assert that states have rate authority
over all facilities used to provide retail service.521 IL Com
argues that states have rate authority over all facilities used to
provide retail service, regardless of whether the NOPR would classify
these facilities as transmission or local distribution.
---------------------------------------------------------------------------
\521\ E.g., NM Com, NC Com, AZ Com.
---------------------------------------------------------------------------
MI Com, citing Connecticut Light & Power Company v. Federal Power
Commission, 324 U.S. 515 (1945) (CL&P), and Arkansas Electric
Cooperative v. Arkansas Public Service Commission, 461 U.S. 375, 393-94
(1983), contends that states have plenary jurisdiction over all aspects
of retail service, including retail access and unbundled retail
transmission service. It asserts that the Commission's effort to expand
federal jurisdiction into transmission in connection with retail sales
is without statutory justification.
Legal Environmental Assistance argues that the NOPR creates
confusion about, and may intrude onto, state jurisdiction. NYMEX argues
that when a state orders retail wheeling, the state should have
jurisdiction over that transmission-only service.
Oklahoma G&E, citing CL&P and United States v. California Public
Utilities Commission, 345 U.S. 295, 316 (1953), asserts that the
Commission failed to explain that the term ``transmission in interstate
commerce'' could have different meanings depending on the factual
context in which the term is applied. It argues that ``transmission in
interstate commerce'' means the movement, in bulk, of electric energy
flowing in interstate commerce, as opposed to the movement of electric
energy that has been subdivided for delivery to consumers.
Oklahoma G&E further argues that ``[t]he distinction between
interconnected operation and radial operation corresponds precisely to
this distinction between activities that have potential interstate
effects and those that might have interstate effects but are a matter
of primarily local concern.'' 522 Oklahoma G&E also disagrees that
the transportation of electric energy sold at wholesale necessarily
constitutes transmission in interstate commerce. It argues that the
Commission has
[[Page 21621]]
misapplied case precedent and, by focusing on the level of the
associated power sale, the Commission has misunderstood what
constitutes a functional distinction between transmission in interstate
commerce and local distribution.
---------------------------------------------------------------------------
\522\ Oklahoma G&E Initial Comments at 16.
---------------------------------------------------------------------------
NY Com asserts that the grant of jurisdiction to the Commission
over wholesale power transactions in interstate commerce under section
201 of the FPA does not reduce the states' authority over local
distribution (citing CL&P and Federal Power Commission v. Florida Power
& Light Company, 404 U.S. 453, 467 (1972)). NY Com argues that the
NOPR's assertion of exclusive jurisdiction over all facilities used to
deliver electricity for resale, even those traditionally regarded as
local distribution, violates Congress' assignment of local electric
distribution to the states. It takes issue with the Commission's list
of factors and says that states and the Commission should agree on a
definition that preserves the traditional classification of local
distribution facilities. According to NY Com, such definition should
focus on the functional characteristics of local electric systems--
i.e., electricity flows into a comparatively restricted geographic area
and does not flow back out of that area, and the power is consumed in
that area.
NY IOUs argue that the Commission has jurisdiction over unbundled,
but not bundled retail wheeling. It says that other factors, including
the indicators listed in the NOPR, are irrelevant, and that even long-
distance interstate transmission is under state jurisdiction as long as
it is bundled with a retail sale. According to NY IOUs, this is the
plain meaning of the FPA; resort to legislative history is unnecessary.
NY IOUs bases this view on section 201(a), which says that federal
regulation extends only to matters not subject to state regulation. NY
IOUs says that the only matters subject to state regulation were
bundled retail sales, and that since transmission was part of the
bundle, Congress intended transmission to stay under state authority as
long as it is part of that bundle. It also cites section 201(b), which
sets forth exceptions from Commission jurisdiction, and section 201(c),
which defines ``transmission in interstate commerce'' and thus also
controls the definition of transmission in intrastate commerce.
Finally, NY IOUs argues that the legislative history supports its view,
as does the case law.
Central Louisiana believes that the costs of requiring a
transmission provider to take unbundled transmission service for both
wholesale and retail purposes would far exceed any benefits. In this
regard, Central Louisiana says that states clearly have jurisdiction
over bundled retail transmission charges and that the proposed approach
could not be implemented without states giving up jurisdiction or the
passage of new federal legislation.
MN DPS disagrees on legal and policy grounds with the Commission's
assertion of jurisdiction over unbundled retail transmission
services.523 It maintains that the Commission's arguments do not
negate the language of the FPA specifying that regulation of retail
sales of electric energy is reserved to the states. MN DPS argues that
the Commission's arguments in support of its position are not on point
because the issue is state authority to set rates for retail sales, not
interstate commerce. Further, it declares that jurisdiction over a
service does not change simply because it is priced differently.
---------------------------------------------------------------------------
\523\ See also OH Com.
---------------------------------------------------------------------------
Several commenters argue that unbundled pricing should not expand
the Commission's jurisdiction.524 NARUC argues that the NOPR did
not explain why the Commission's authority attaches only to unbundled
retail transmission service, why unbundling is jurisdictionally
significant, and how transmission of electricity to end users differs
from unbundled interstate transmission of natural gas by local
distribution companies, which is subject to state regulation. Thus,
NARUC urges the Commission not to claim jurisdiction over unbundled
retail transmission services.
---------------------------------------------------------------------------
\524\ E.g., DOD, NM Com, KY Com, ABATE.
---------------------------------------------------------------------------
NARUC also argues that the Commission's test for distinguishing
between transmission and local distribution is not a bright line as
discussed in Federal Power Commission v. Southern California Edison
Company, 376 U.S. 205 (1964) (Colton). NARUC concludes that when a
state determines to enable a retail customer to purchase power from a
third-party provider, that state retains the authority to regulate the
delivery service provided by the utility.
IL Com asserts that the test should be whether the utility function
over which the Commission seeks to exercise jurisdiction is one which
falls within the Attleboro gap.525 It argues that the Commission
has no legal authority to prescribe conditions under which a public
utility may provide transmission service within its own service
territory to its own retail customers. IL Com concedes that the court
cases cited by the Commission can be interpreted to support widely
disparate legal and policy positions, but argues that those cases
resolved questions of Commission jurisdiction in circumstances where
wholesale sales of electric power were being examined and not
circumstances where retail sales are being considered. It contends that
the question of whether the Commission should exercise jurisdiction
over all transmission in retail wheeling has never been addressed
before and requires a careful examination of the underlying purposes of
Congress in enacting the FPA. IL Com explains that transmission by an
Illinois utility of power to a retail consumer within its own service
territory is not subject to Commission jurisdiction because that
transmission was never within the Attleboro gap and has always been
regulated by states.
---------------------------------------------------------------------------
\525\ See Public Utilities Commission v. Attleboro Steam &
Electric Company, 273 U.S. 83 (1927).
---------------------------------------------------------------------------
OK Com recommends that the Commission apply to the electric
industry the same policy that it has adopted concerning its regulation
of the gas industry and leave unbundled retail service regulation to
state authorities.
WI Com argues that if a utility offers unbundled retail access,
jurisdiction over transmission services should continue to be based
upon the historical demarcation between wholesale and retail
transactions. KY Com argues that Congress did not intend, by
authorizing wholesale wheeling in the Energy Policy Act, to change the
longstanding division of jurisdiction between the Commission and the
states. It claims that the NOPR ignores the limitation in the FPA that
the Commission has no jurisdiction over retail sales service. NV Com
cites several cases noting the states' historical authority to regulate
retail rates.
IA Com proposes a definition of local distribution and transmission
that would preserve the jurisdictional status quo and does not put a
state commission in the position of losing authority over certain
elements of a retail transaction should it allow retail wheeling. IA
Com's proposed definition is as follows:
Distribution--Service provided by a utility directly connected
to an ultimate consumer of electricity is a distribution service
with respect to electric energy delivered to that consumer.
Transmission--Service provided by a utility with respect to
electric energy to be delivered to an ultimate consumer through
another utility is a transmission service.526
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\526\ IA Com Initial Comments at 4.
Montana Power states that a reasonable way to give effect to the
``local distribution'' exemption is to define ``local distribution'' as
a bundled retail sale, even if interstate facilities are used.
[[Page 21622]]
Several commenters criticized the NOPR's functional/physical
indicators. PA Com disagrees with the Commission's discussion of the
FPA's legislative history and asserts that the FPA does not address the
issue of what constitutes local distribution. PA Com contends that the
issue was resolved by the Supreme Court in CL&P in a manner contrary to
the Commission's technical-functional test and that the NOPR minimized
CL&P. NM Com asserts that the proposed engineering and functional
elements for determining the status of local distribution facilities
fail to account for the governmental or legalistic test requirement of
the FPA as identified in CL&P.
KY Com concludes that a physical definition of distribution
facilities, based on objective criteria, is consistent with the FPA and
is necessary to provide a clean line of demarcation.
CO Com argues that Congress used a transactional test rather than a
functional test and that Congress intended all retail transactions to
be under state jurisdiction. According to CO Com, there is concurrent
jurisdiction over unbundled transmission in interstate commerce to an
end-user. Moreover, CO Com asserts that unbundled intrastate
transmission to a wholesale purchaser is under state jurisdiction
(citing section 201(b)(1)). Finally, CO Com argues that the state has
authority over unbundled transmission in intrastate commerce to an end-
user when the transmission-providing utility, end-user, and generator
are all within the same state.
Other commenters prefer a functional test. Natural Resources
Defense, DOE, and Sustainable Energy Policy generally agree that a line
needs to be drawn between transmission and local distribution but
believe that the Commission's test is unnecessarily cumbersome or may
lead to legal uncertainty, at least within the context of stranded
benefits. Instead, Natural Resources Defense proposes the following
functional test, which is based on end-use service:
The Federal Power Act does not affect state regulators'
jurisdiction to apply distribution charges--either volume-based or
fixed--to electricity that is used by any utility customer to
provide end-use services (as distinguished from electricity that is
purchased for resale to end-use customers).527
---------------------------------------------------------------------------
\527\ Natural Resources Defense Initial Comments at 3.
Sustainable Energy Policy endorses Natural Resources Defense's
position. DOE suggests that a functional definition of local
distribution (i.e., electricity provided for end-use service) may be
the best way to avoid legal uncertainty.
EPA argues that the Commission's proposed physical definition may
encourage gaming to avoid stranded costs and costs associated with
public policy goals such as energy efficiency, renewable energy
development and R&D funding, and a physical definition assumes that
power flows into, and not out of, distribution systems, which would not
allow for distributed generation (e.g., fuel cells). Thus, EPA urges
the Commission to adopt a functional definition that ``local
distribution occurs whenever electricity is provided by a utility for
end-use service.'' Alternatively, EPA suggests that the Commission add
a provision to its approach that ``the provision of electricity for
end-use service generally involves local distribution.'' Sustainable
Energy Policy suggests a non-bypassable charge levied on all users of
the distribution system. It endorses the policy formulation set forth
by Natural Resources Defense in its initial comments. Reynolds wants to
ensure that there is always at least concurrent state jurisdiction over
lines used to serve end-use customers, since only states can order
retail wheeling.
Detroit Edison argues that state/federal jurisdictional issues
should be resolved by focusing on the use of the facilities. It says
that facilities that are used to distribute a utility's own power to
its own local customers should be subject to state regulation, while
the use of facilities for wholesale power transactions or wholesale or
retail transmission in interstate commerce should be under federal
regulation.
Mountain States Petroleum Assoc argues that the Commission should
use a functional test based on state boundaries: if a line is in more
than one state, there is Commission jurisdiction; if a line is entirely
within one state, there is state jurisdiction.
MD Com states that it believes that the Commission's proposed
indicators for determining where to draw the line are adequate, but
adds that it does not concede the Commission's assertion of
jurisdiction over unbundled retail transmission.
Some commenters suggest that implementation of the NOPR's tests
could have adverse consequences. NH Com objects to the NOPR's specific
tests; for example, if the Commission asserts jurisdiction over
facilities because they are not radial, New Hampshire's policy of
encouraging looping rather than radial lines would have the ironic
effect of destroying state jurisdiction. NJ BPU states that there may
be situations when the NOPR factors would not produce the proper
result. It requests that the final rule recognize the need for case-by-
case flexibility in determining where federal jurisdiction ends, so
that the Commission and the states can work cooperatively.
NRRI argues that the NOPR's test could make siting of new
transmission lines more difficult because states have in the past
required native load customers to pay that part of the transmission-
related revenue requirement that is not covered by unbundled
transmission service. NRRI contends that, if the Commission asserts
jurisdiction over all unbundled transmission service and if there is a
firm point-to-point service capacity right that has value and is
reassignable, then state commissions might eliminate portions of the
transmission systems subject to capacity rights from rate base. NRRI is
also concerned that the NOPR's transmission/local distribution test
could create a price squeeze between bundled and unbundled retail
transmission rates.
IN Com argues that the NOPR's view of jurisdiction would discourage
retail wheeling. It says that states will be reluctant to order
wheeling if the result is that they lose jurisdiction over the
previously rolled-in transmission aspect of the service. It suggests
that the Commission use negotiated rulemaking to address jurisdictional
issues.
Several commenters suggest alternative approaches to jurisdictional
line-drawing. NV Com suggests that the Commission consider federal and
state jurisdiction over transmission by using ``network'' and ``non-
network'' concepts:
The ``network'' concept for regulation recognizes that there is
an interstate network of electric facilities used to link generation
with loads. The operation of that network is indifferent to whether
the electrical flows are retail or wholesale flows. Conceptually,
events on the network could fall under federal jurisdiction. Where
facilities provide essential service for the delivery of power, but
do not substantially affect the electrical flows on the network, the
facilities fall outside the network and would remain within the
traditional domain of the state commission. As a consequence the
delineation of federal and state jurisdiction evolves from the
recognition of the events and where they occur as opposed to a rigid
consideration of the physical properties of the facilities
involved.528
---------------------------------------------------------------------------
\528\ NV Com Reply Comments at 3.
NV Com further explains that the determination of what is a network
event would require a case-by-case examination.
[[Page 21623]]
OH Com asserts that Congress intends there to be a bright line
between state and federal jurisdiction and that the Commission has
failed to provide such a bright line. OH Com proposes the use of retail
marketing areas to provide the bright line--the jurisdictional line
would be at the point at which power enters the retail marketing area
of the entity delivering the power to the retail customer. OH Com cites
section 212(g) of the FPA, as amended by the Energy Policy Act, which
provides that the Commission cannot issue any order under the FPA
inconsistent with state law governing retail marketing areas.
Under OH Com's proposal, the Commission would have jurisdiction
over the wheeling-out and wheeling-through components of retail
wheeling and the state would have jurisdiction over the wheeling-in
component due to its local nature. OH Com concludes that the
Commission's approach ``fails to meet the legal standard FERC must
consider, and is inconsistent with the `savings clause' and legitimacy
of `retail marketing areas' as discussed in the amended FPA.'' 529
OH Com also explains that the Commission's approach ``is wreaking havoc
on the state's ability to develop an interruptible buy-through
arrangement to provide an increased competitive option for its retail
customers.'' 530 OH Com further encourages the use of mutual
deference to promote Congress' intent in mandating a system of federal/
state cooperation. In support, OH Com cites federal and state
enforcement of telecommunications laws. NRRI also suggests that the
jurisdictional line be drawn at the retail marketing area.
---------------------------------------------------------------------------
\529\ Sections 212(g) and 212(h) of the FPA.
\530\ We note that since OH Com filed its comments, it approved
an interruptible buy-through plan. See Interruptible Electric
Service Guidelines, Case No. 95-866-EL-UNC, __ PUR 4th __ (Ohio PUC
Feb. 15, 1996). See also Central Illinois Light Company, Docket No.
ER96-1075-000, 75 FERC para. ______ (1996) (accepting amendment to
open access transmission tariffs that expands service eligibility to
accommodate participation in experimental retail wheeling pilot
program approved by the Illinois Commerce Commission); Illinois
Power Company, Docket No. ER96-1285-000, 75 FERC para. ______
(1996); cf. Illinois Power Company, __ PUR4th __, No. 95-0494
(Illinois Commerce Commission Mar. 13, 1996) (offering retail direct
access service providing transmission and ancillary services using
the rates, terms, and conditions of Illinois Power's open access
tariff on file with the Commission); recently introduced legislation
in Rhode Island, H.B. 8124, the Utility Restructuring Act of 1996.
---------------------------------------------------------------------------
DC Com argues that the NOPR test is too difficult to administer and
will create problems in determining the rate base at the state level.
It suggests that the Commission should have jurisdiction over
transmission from the source to the boundary of the ``home'' utility
that delivers the power to the customer, with state jurisdiction over
all aspects of the transmission service within that utility's franchise
territory. AZ Com also expresses doubts that the NOPR's test is
workable.
Several commenters propose that the Commission and state
authorities address the jurisdictional issue jointly. SBA characterizes
the Commission's proposed demarcation line as ``laudable but
misguided.'' 531 SBA recommends that a federal/state board be
established to resolve the transmission/local distribution dilemma,
similar to what Congress did for allocating costs between interstate
and intrastate communications. SBA explains that the problem in the
communications industry was the impossibility of allocating a portion
of a single copper wire to interstate or intrastate service.
---------------------------------------------------------------------------
\531\ SBA Initial Comments at 36.
---------------------------------------------------------------------------
AZ Com notes that even if the Commission is correct, the FPA
clearly does not preempt a state from concluding that retail
transmission or other direct access programs should be implemented in
that state. AZ Com suggests that there may be concurrent jurisdiction
and that mutually agreed-upon principles should be implemented to
determine which jurisdiction should be given deference.
MD Com states that in determining the status of particular
facilities, the Commission should give substantial weight to
determinations made by states. ABATE states that the Commission could
initially defer to states with respect to the determination of rates,
terms, and conditions, while maintaining the right to review and
overturn the state determination.
If the Commission maintains its position concerning jurisdiction,
NARUC argues that the Commission should not implement its multi-factor
test, but should enter into discussions with state commissions to
develop workable alternatives. NH Com argues that pricing the retail
part of a transaction, even if it involves use of the transmission
system, should be subject only to state jurisdiction. NH Com wants to
create a mechanism by which state and federal regulators combine their
efforts in cooperative regulation; it suggests several alternatives
such as state/federal agreements for shared jurisdiction.
KY Com and NRRI object to the statement in the NOPR that retail
buy-through service is really transmission service (subject to the
Commission's jurisdiction) plus a sale of generation at retail (subject
to state jurisdiction). From a policy standpoint, KY Com argues that
the Commission's approach creates a powerful disincentive for a state
to embark on changes that otherwise might foster a more competitive
environment. NRRI argues that the Commission's approach may violate
sections 212(g) and 212(h).
IL Com is concerned that industrial customers who get direct access
may attempt to evade state jurisdiction, and thus avoid retail stranded
cost charges, by bypassing facilities such as radial lines. It contends
that retail wheeling rate surcharges would be a more effective means of
recovering retail stranded costs if states were allowed to apply them
to unbundled transmission and local distribution rates, not just the
local distribution component of such rates.
NC Com asserts that ``[a] significant cottage industry may well
arise solely to convert retail customers into wholesale customers,
thereby subverting the intent of Congress as expressly set forth in
EPACT.'' 532 If the Commission does not adopt NARUC's proposal,
NARUC asserts that the Commission's functional test should not permit
an end user to bypass the distribution service provided by the utility.
It urges the Commission to assure that there will be some facility
involved in the transaction that will be defined as providing a local
distribution service.
---------------------------------------------------------------------------
\532\ NC Com Initial Comments at 7.
---------------------------------------------------------------------------
NARUC also requests that the following sentence be added to
proposed 18 CFR 35.27:
Nothing in this part limits the authority of a State commission
in accordance with State law (1) to allow or disallow the inclusion
of the costs of electric energy purchased at wholesale in retail
rates subject to such State commission's jurisdiction, (2) to
establish competitive procedures for the acquisition of such
electric energy, or (3) to establish non-discriminatory fees for the
delivery of such electric energy to retail consumers for purposes
established in accordance with State law.(533)
\533\ NARUC Reply Comments at 15-16.
---------------------------------------------------------------------------
Duke is concerned about the potential for regulatory gaps, which
could lead to costs not being recovered from either federal or state
jurisdiction. Duke is also concerned that where facilities are used for
both wholesale and retail transactions, costs might not be recovered if
federal and state regulators use different methods of cost allocation.
In response to the NOPR's proposal for functional
unbundling,534 CA Com agrees that it is important to draw a
distinction between transmission and local distribution and that a
bright line is not possible, but suggests that corporate or functional
unbundling
[[Page 21624]]
might provide a means to establish a workable bright line without
relying on the more qualitative approach proposed in the NOPR. Arizona
argues that rather than unbundling transmission for retail purposes,
each utility should establish a distribution function that would obtain
transmission on behalf of retail customers, taking service under the
utility's tariff. Arizona states that this would simplify the
allocation of transmission costs, since all transmission costs would be
under the Commission's jurisdiction. Arizona argues that the Commission
should permit the utility to recover the distribution rate approved by
the state. According to Arizona, this would create a bright line
between state and federal jurisdiction.
---------------------------------------------------------------------------
\534\ FERC Stats. & Regs. para. 32,514 at 33,080-83.
---------------------------------------------------------------------------
TX Com argues that the proposed test would not be applicable to
intrastate utilities in Texas because they do not operate in interstate
commerce. Thus, it asserts that it should continue to regulate Electric
Reliability Council of Texas (ERCOT) transmission and distribution
service and deal with stranded cost issues that arise in connection
with any retail wheeling initiatives.
Several commenters object to the Commission's proposal to assert
jurisdiction over transactions that are buy-sell transactions in name
only.535 AEP argues that the Commission should avoid an
unnecessary conflict over state/federal jurisdiction that may be caused
by the NOPR's statement that buy-sell transactions are in fact
transmission subject to Commission jurisdiction. It suggests that the
Commission attempt to reach agreement with the states on this matter or
ask Congress for any necessary statutory change. Citizens Utilities
also argues that the Commission should not unbundle the interstate
transmission aspect of buy-sell transactions. It says that, unlike the
analogous gas contracts, buy-sell arrangements on the electric side are
not an end run around clear federal jurisdiction. Further, it argues
that it would be very difficult to define those buy-sell transactions
that truly belong under federal jurisdiction.
---------------------------------------------------------------------------
\535\ See id. at 33,082.
---------------------------------------------------------------------------
IL Com also objects to the NOPR's characterization of buy-sell
transactions. It argues that the fact that a transaction becomes
unbundled does not suddenly make part of it under federal jurisdiction.
Nucor argues that there is no need for the Commission to resolve this
issue now; it suggests that the buy-sell arrangement is only
tangentially related to open access. It argues that each buy-sell
transaction will have to be addressed individually.
UT Com seeks clarification as to what the Commission means by buy-
sell arrangements:
we currently authorize interruptible ``buy-through'' contracts,
through which a retail customer, taking service subject to
interruption for either economic or technical reasons, can opt to
``buy-through'' an interruption. The public utility purchases energy
on behalf of the customer and sells it at cost to the customer. In
our opinion, such transactions are not an example of a buy-sell
transaction within the meaning of the proposed rule.536
---------------------------------------------------------------------------
\536\ UT Com Initial Comments at 4-5.
DOD objects to the statement in the NOPR that ``buy-sell''
transactions are not really bundled retail service. It says that this
view will discourage the development of innovative state programs, such
as direct access programs. NYSEG also argues that buy-sell transactions
are not under the Commission's jurisdiction. It argues that these
transactions are unlike buy-sell transactions on the gas side, where
the Commission asserted jurisdiction to prevent LDCs from circumventing
the nondiscrimination standard it imposed on the release of capacity.
---------------------------------------------------------------------------
NYSEG says:
In contrast to its regulation of gas buy-sells, if the
Commission regulates electric buy-sell transactions it would forego
regulation of a transaction in which the Commission has a
significant interest (i.e., access to the upstream seller's
transmission), to regulate a transaction in which the Commission has
virtually no interest (i.e., access to the distributing utility's
system). Electric utilities must serve each retail customer
irrespective of whether the customer takes traditional bundled
service or retail buy-sell service. Unlike excess upstream gas
pipeline capacity, the capacity on the local utility's electric
system would not be allocated to another customer in a FERC
jurisdictional transaction absent the electric buy-sell transaction.
Electric buy-sell transactions are not designed so as to manipulate
the assignment of upstream transmission capacity. Consequently, the
impetus for FERC to reclassify gas buy-sell transactions as capacity
assignments is not present in the electric context.537
---------------------------------------------------------------------------
\537\ NYSEG Initial Comments at 48 (footnote omitted).
NYSEG argues that there are only two possible grounds for the
Commission's assertion of jurisdiction over electric buy-sell
transactions: either (1) the sale for resale by the supplier is really
a sale at retail to the end user, and the resale by the local utility
is really unbundled retail wheeling; or (2) the Commission has
jurisdiction over transmission service that is part of bundled retail
service. It claims that the second ground is invalid because the
transmission aspect of bundled retail service is distribution. It also
claims that the first ground is invalid because it assumes that the
sale by the supplier to the local utility is not a sale for resale even
---------------------------------------------------------------------------
though the contract says that it is. NYSEG states:
The logical outcome would be that FERC would not have
jurisdiction over the sale by the supplier to the utility, including
transmission by that supplier because it would be a bundled retail
sale. This is because, if the commission holds the resale to be a
retail wheel, then it would have to find that the sale by the
supplier is a retail sale to the end user. The Commission cannot at
once regulate the sale for resale and the ``retail transmission
service.'' The Commission would regulate the transmission rates of
the local franchise utility, although it would not regulate the
access to such transmission service--a matter FERC leaves to state
regulators. In the process, FERC would abandon the ability to
regulate access to the supplier's bundled ``retail power sale and
transmission service,'' a transaction that FERC arguably has an
interest in regulating.538
---------------------------------------------------------------------------
\538\ NYSEG Initial Comments at 50.
Finally, NYSEG argues that if the Commission insists on asserting
jurisdiction, it should at least grandfather existing contracts.
UT Industrials state that where there is a state barrier to a buy-
sell transaction, the Commission should allow the utility to file a
tariff with the Commission that would permit the utility to complete a
voluntary buy-sell transaction as the NOPR proposes. However, it
contends that when a state regulatory authority is authorized to, and
has approved buy-sell transactions, it is not necessary for the
Commission to become involved. It urges the Commission to allow such
transactions to take place free of Commission regulation.
Commission Conclusion
In the discussion below, the Commission addresses the following
jurisdictional issues raised in the prior NOPRs:
a. Does the Commission have jurisdiction over unbundled
transmission in interstate commerce by a public utility when such
transmission is used to transport electric energy that is sold to an
end user?
b. If so, what facilities are jurisdictional to the Commission
in a situation involving the unbundled delivery in interstate
commerce by a public utility of electric energy from a third-party
supplier to an end user?
c. What facilities are jurisdictional to the Commission in a
situation involving the unbundled delivery in interstate commerce by
a public utility of electric energy from a third-party supplier to a
purchaser who will then re-sell the energy to an end user?
[[Page 21625]]
d. What procedures are appropriate for making jurisdictional
determinations?
In addition, the Commission addresses concerns raised by state
regulators which indicate that competition and open access are
perceived as threatening the traditional regulatory functions of state
commissions. The Federal Power Act differentiates between state and
federal regulation of electric power. As we discuss below, the
Commission believes that any change in state or federal jurisdiction
over physical transmission assets and related costs will not affect the
traditional tasks of state and federal regulators.
The wide range of jurisdictional interpretations and proposals in
the comments reflects the fact that the legislative history of the FPA
and case law interpreting federal/state jurisdiction under that Act and
the Natural Gas Act grew out of a market structure in which electricity
and transmission generally were bought and sold on a bundled basis. As
a result, most transactions included either a retail or wholesale sale
of electric energy and jurisdictional lines were drawn on the basis of
this sale. Thus, the cases simply do not resolve dispositively these
jurisdictional issues when they arise in the context of the market
structures and unbundled transactions being contemplated in today's
electric industry. However, after reviewing the extensive analysis of
the FPA, legislative history, and case law contained in both our
initial Stranded Cost NOPR and in our Open Access NOPR, and the
comments received on that analysis, we continue to believe that we were
correct in asserting jurisdiction over the transmission component of an
unbundled interstate retail wheeling transaction. We therefore reaffirm
our conclusion. We also reaffirm and clarify our determinations
regarding the tests to be used to determine what constitute Commission-
jurisdictional transmission facilities and what constitute state-
jurisdictional local distribution facilities in situations involving
unbundled wholesale wheeling and unbundled retail wheeling.539
---------------------------------------------------------------------------
\539\ Not only do we conclude that our determinations are
legally supportable under the case law, but we believe it is
imperative to provide guidance to public utilities and state
regulators as to our position on where the jurisdictional boundaries
lie.
---------------------------------------------------------------------------
At the same time, the Commission strongly supports the efforts of
states to pursue pro-competitive policies. We recognize that
jurisdictional issues raise overlapping Federal and state policy
concerns that call for heightened cooperation among federal and state
regulators. As discussed below, where states unbundle retail sales, we
will give deference to their determinations as to which facilities are
transmission and which are local distribution, provided that the
states, in making such determinations, apply the seven criteria
discussed in the NOPR and reaffirmed below. In addition, we clarify our
view that there is an element of local distribution service in any
unbundled retail transaction, and further clarify other aspects of our
jurisdictional ruling to preserve state jurisdiction over matters that
are of local concern and will remain subject to state jurisdiction if
retail unbundling occurs.
We first address our legal determination that if unbundled retail
transmission in interstate commerce occurs voluntarily by a public
utility or as a result of a state retail access program, this
Commission has exclusive jurisdiction over the rates, terms, and
conditions of such transmission. No commenter has raised cases or
legislative history not previously considered in our prior NOPRs, and
we will not repeat here our full legal analysis of this issue.540
However, we find compelling the fact that section 201 of the FPA, on
its face, gives the Commission jurisdiction over transmission in
interstate commerce (by public utilities) without
qualification.541 Unlike our jurisdiction over sales of electric
energy, which section 201 of the FPA specifically limits to sales at
wholesale, the statute does not limit our transmission jurisdiction
over public utilities to wholesale transmission.
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\540\ The Commission's complete legal analysis on this issue,
and on the related issue of what facilities are Commission-
jurisdictional transmission facilities, and what are state
jurisdictional local distribution facilities, are contained in
Appendix G to this Rule.
\541\ Section 201(b)(1) specifically exempts from Commission
jurisdiction facilities used for transmission in intrastate commerce
and transmission of electric energy consumed wholly by the
transmitter. As a result, we have no jurisdiction over retail
wheeling that occurs in Alaska, Hawaii and the Electric Reliability
Council (ERCOT) portion of Texas since transactions in those areas
are intrastate.
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In response to those commenters (including NARUC) who argue that
the Commission did not explain why its authority attaches only to
unbundled, but not bundled, retail transmission in interstate commerce
by public utilities, we believe that when transmission is sold at
retail as part and parcel of the delivered product called electric
energy, the transaction is a sale of electric energy at retail. Under
the FPA, the Commission's jurisdiction over sales of electric energy
extends only to wholesale sales. However, when a retail transaction is
broken into two products that are sold separately (perhaps by two
different suppliers: an electric energy supplier and a transmission
supplier), we believe the jurisdictional lines change. In this
situation, the state clearly retains jurisdiction over the sale of the
power. However, the unbundled transmission service involves only the
provision of ``transmission in interstate commerce'' which, under the
FPA, is exclusively within the jurisdiction of the Commission.
Therefore, when a bundled retail sale is unbundled and becomes separate
transmission and power sales transactions, the resulting transmission
transaction falls within the Federal sphere of regulation.
In asserting jurisdiction over unbundled retail transmission in
interstate commerce by public utilities, the Commission in no way is
asserting jurisdiction to order retail transmission directly to an
ultimate consumer. Section 212(h) of the FPA clearly prohibits us from
doing so. In addition, as stated in both the initial Stranded Cost NOPR
and the Open Access NOPR, we do not address whether states have
authority to order retail wheeling in interstate commerce. The
Commission's assertion of jurisdiction is that if retail transmission
in interstate commerce by a public utility occurs voluntarily or as a
result of a state retail wheeling program, the Commission has exclusive
jurisdiction over the rates, terms, and conditions of such transmission
and public utilities offering such transmission must comply with the
FPA by filing proposed rate schedules under section 205.
The Commission clarifies that nothing in this jurisdictional
determination changes historical state franchise areas or interferes
with state laws governing retail marketing areas of electric utilities.
Section 212(g) of the FPA prohibits Commission orders that would be
inconsistent with such laws. However, we reject arguments made by some
of the commenters that section 212(g) could somehow be construed to
give states authority over the rates, terms, and conditions of
unbundled interstate transmission within retail marketing
areas.542 While our
[[Page 21626]]
jurisdiction cannot affect whether and to whom a retail electric
service territory (marketing area) is to be granted by the state, and
whether such grant is exclusive or non-exclusive, neither can state
jurisdiction affect this Commission's exclusivejurisdiction over
transmission in interstate commerce by public utilities.
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\542\ The legislative history of FPA section 212(g) and its
predecessor, former section 211(c)(3), indicates that the provision
was focused on not interfering with state laws governing retail
service territories and not permitting Commission wheeling orders
``for purposes of sale by a utility to an ultimate consumer who is
within the service territory of another utility (other than the
applicant) where such territory is established by or under State
law, rule, or decision.'' See H.R. Conf. Rep. No. 1750, 95th Cong.,
2d Sess. 92 (1978), reprinted in 1978 U.S. Code Cong. & Ad. News
7797, 7826. Nothing on the face of section 212(g) or the legislative
history of either the Energy Policy Act or PURPA indicates that the
provision in any way affects the Commission's authority over rates,
terms, and conditions of transmission in interstate commerce by
public utilities.
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In response to several of the commenters, we further clarify that
the Commission's jurisdiction over the rates, terms, and conditions of
unbundled retail transmission is no broader than our authority over
transmission used for wholesale transactions, and will not affect
matters otherwise left to the states by Congress.543 The Federal
Power Act recognizes that retail marketing areas are governed by state
law. Moreover, we believe that states have authority over the service
of delivering electric energy to end users. In exercising this
authority, state regulatory commissions and state legislatures have
traditionally developed social and environmental programs suited to the
circumstances of their states. State regulation of most power
production and virtually all distribution and consumption of electric
energy is clearly distinguishable from this Commission's responsibility
to ensure open and non-discriminatory interstate transmission service.
Nothing adopted by the Commission today, including its interpretation
of its authority over retail transmission or how the separate
distribution and transmission functions and assets are discerned when
retail service is unbundled, is inconsistent with traditional state
regulatory authority in this area.
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\543\ Among other things, Congress left to the States authority
to regulate generation and transmission siting. See FPA sections
201(b) and 211(d)(1); section 731 of the Energy Policy Act.
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The Commission reiterates its strong interest in preventing any
balkanization of the interstate power market. Although the Commission
believes its Final Rule will accommodate retail competition, if it is
offered voluntarily by a utility or ordered by a state, our policies
relate only to the bulk power market and not traditional state
regulation of the retail market.544
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\544\ This Final Rule will not affect or encroach upon state
authority in such traditional areas as the authority over local
service issues, including reliability of local service;
administration of integrated resource planning and utility buy-side
and demand-side decisions, including DSM; authority over utility
generation and resource portfolios; and authority to impose non-
bypassable distribution or retail stranded cost charges.
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NARUC has requested that the Commission specifically clarify in
Sec. 35.27 of its proposed rules 545 that nothing in our final
rule limits the authority of a state commission ``to allow or disallow
the inclusion of the costs of electric energy purchased at wholesale in
retail rates subject to such State commission jurisdiction.'' We will
adopt NARUC's proposal with modification, but add it as a separate
subsection. The Final Rule adopts a new Sec. 35.27(b) as follows:
\545\ Section 35.27 of the proposed rules provided that any
public utility seeking authorization to engage in sales for resale
at market-based rates shall not be required to demonstrate any lack
of market power in generation with respect to sales from capacity
first placed in service on or after 30 days from the date of
publication of the Final Rule in the Federal Register. FERC Stats. &
Regs. para. 32,514 at 33,154.
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Nothing in this part (i) shall be construed as preempting or
affecting any jurisdiction a state commission or other state
authority may have under applicable state and federal law, or (ii)
limits the authority of a state commission in accordance with state
and federal law to establish (a) competitive procedures for the
acquisition of electric energy, including demand-side management,
purchased at wholesale, or (b) non-discriminatory fees for the
distribution of such electric energy to retail consumers for
purposes established in accordance with state law.
With respect to the Commission's adoption of the Open Access NOPR's
functional/technical tests for determining what facilities are
Commission-jurisdictional facilities used for transmission in
interstate commerce and what facilities are state-jurisdictional local
distribution facilities, the case law supports a bright line for
unbundled wholesale transmission, i.e., transmission of electric energy
that is being sold for resale. This is consistent with the bright line
drawn by Congress to fill the Attleboro gap for regulating wholesale
sales of electric energy. The case law also supports a bright line with
respect to retail transmission by intervening utilities, i.e.,
transmission by those utilities between the new retail generation
supplier and the public utility that previously provided bundled retail
service to the end user. However, despite many commenters' arguments to
the contrary, we cannot divine such a bright line for unbundled retail
transmission by the public utility that previously provided bundled
retail service to the end user. In fact, the limited case law,
including CL&P and Colton, supports a case-by-case
determination.546 Accordingly, we believe our technical test, with
its seven indicators, will permit reasoned factual determinations in
individual cases.
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\546\ As noted, the Commission's detailed legal analysis is
contained in Appendix G. We are particularly persuaded by the
Supreme Court's statement that whether facilities are used in local
distribution is a question of fact to be decided by the Commission
as an original matter. See CL&P, 515 U.S. at 534-35.
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Although we are unable to draw the bright line for local
distribution facilities that many commenters would like, we believe it
is important to make two clarifications regarding local distribution in
the context of retail wheeling. First, even when our technical test for
local distribution facilities identifies no local distribution
facilities for a specific transaction, we believe that states have
authority over the service of delivering electric energy to end users.
Second, through their jurisdiction over retail delivery services,
states have authority not only to assess stranded costs but also to
assess charges for stranded benefits, such as low-income assistance and
demand-side management. Because their authority is over services, not
just the facilities, states can assign stranded costs and benefits
based on usage (kWh), demand (kW), or any combination or method they
find appropriate. They do not have to assign them to specific
facilities.547
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\547\ As noted above, states retain authority over state
integrated resource planning, utility resource portfolios, and
utility buy-side and demand-side decisions.
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Thus, while we believe in most cases there will be identifiable
local distribution facilities subject to state jurisdiction, we also
believe that even where there are no identifiable local distribution
facilities, states nevertheless have jurisdiction in all circumstances
over the service of delivering energy to end users. Under this
interpretation of state/federal jurisdiction, customers have no
incentive to structure a purchase so as to avoid using identifiable
local distribution facilities in order to bypass state jurisdiction and
thus avoid being assessed charges for stranded costs and benefits.
Based on concerns raised by state commissions as well as some
utilities, we have further determined that it is appropriate to provide
deference to state commission recommendations regarding certain
transmission/local distribution matters that arise when retail wheeling
occurs. We also believe it is important to develop mechanisms to avoid
regulatory conflict and to help provide certainty to utilities as to
which regulator has jurisdiction over which facilities. These are
discussed below.
[[Page 21627]]
Determining where to draw the jurisdictional line for facilities
used in unbundled retail wheeling transactions will involve case-
specific determinations that evaluate the seven local distribution
indicators that we are adopting. We believe that the Commission should
take advantage of state regulatory authorities' knowledge and expertise
concerning the facilities of the utilities that they regulate.
Therefore, in instances of unbundled retail wheeling that occurs as a
result of a state retail access program, we will defer to
recommendations by state regulatory authorities concerning where to
draw the jurisdictional line under the Commission's technical test for
local distribution facilities, and how to allocate costs for such
facilities to be included in rates, provided that such recommendations
are consistent with the essential elements of the Final Rule.548
Moreover, we recognize that in some cases the Commission's seven
technical factors may not be fully dispositive and that states may find
other technical factors that may be relevant. We will consider
jurisdictional recommendations by states that take into account other
technical factors that the state believes are appropriate in light of
historical uses of particular facilities.
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\548\ In order to give such deference, we expect state
regulators to specifically evaluate the seven indicators and any
other relevant facts and to make recommendations consistent with the
essential elements of the Rule.
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Some commenters have asked the Commission to provide a forum to
prevent or resolve disputes over the correct classification of
facilities as transmission or local distribution. As a means of
facilitating jurisdictional line-drawing, we will entertain proposals
by public utilities, filed under section 205 of the FPA, containing
classifications and/or cost allocations for transmission and local
distribution facilities. However, as a prerequisite to filing
transmission/local distribution facility classifications and/or cost
allocations with the Commission, utilities must consult with their
state regulatory authorities. If the utility's classifications and/or
cost allocations are supported by the state regulatory authorities and
are consistent with the principles established in the Final Rule, the
Commission will defer to such classifications and/or cost
allocations.549 We encourage public utilities and their state
regulatory authorities to attempt to agree to utility-specific
classifications and allocations that the utility may file at the
Commission.
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\549\ This should also alleviate some concerns about the
potential for costs not being accounted for if the Commission and a
state commission use different methods of allocating costs.
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A number of commenters have asked the Commission to defer to state
commission recommendations or decisions regarding rates, terms and
conditions of unbundled retail transmission in interstate commerce by
public utilities. Some have suggested that we set broad guidelines for
such rates, terms, and conditions, and then allow states to actually
implement the guidelines. While the Commission cannot simply turn over
its jurisdiction for the states to implement, we understand the
concerns raised by many state regulators and believe that deference to
state commissions with regard to rates, terms, and conditions may be
appropriate in some circumstances, as discussed below.
As we determined in the NOPR, when unbundled retail wheeling in
interstate commerce occurs, the transaction has two components for
jurisdictional purposes--a transmission component and a local
distribution component. The Commission has jurisdiction over facilities
used for the transmission component of the transaction, and the state
has jurisdiction over facilities used for the local distribution
component.550 Thus, the rates, terms and conditions of unbundled
retail transmission by a public utility must be filed at the
Commission. When this occurs, we will generally expect unbundled retail
wheeling customers to take service under the same FERC tariff that
applies to wholesale customers. However, if the unbundled retail
wheeling occurs as part of a state retail access program, it may be
appropriate to have a separate retail transmission tariff 551 to
accommodate the design and special needs of such programs. In such
situations, the Commission will defer to state requests for variations
from the FERC wholesale tariff to meet these local concerns, so long as
the separate retail tariff is consistent with the Commission's open
access policies and comparability principles reflected in the tariff
prescribed by this Final Rule. In addition, rates must be consistent
with our Transmission Pricing Policy Statement, and the guidance herein
concerning ancillary services.552
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\550\ As discussed above, even if there were instances where no
local distribution facilities are used, we believe states have
authority over the service of delivering electric energy to end
users.
\551\ I.e., the tariff would be different from the tariff that
applies to wholesale customers. Such tariff would still be filed
with the Commission under FPA section 205.
\552\ In applying the principles of the Final Rule to retail
transmission tariffs, the Commission clearly cannot order retail
wheeling directly to an ultimate consumer. See FPA section 212(h).
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A final jurisdictional issue raised in the Open Access NOPR
concerns buy-sell transactions. We remain concerned, just as we were
with buy-sell arrangements in the gas industry, that buy-sell
arrangements can be used by parties to obfuscate the true transactions
taking place and thereby allow parties to circumvent Commission
regulation of transmission in interstate commerce. Thus, we reaffirm
our conclusion that we have jurisdiction over the interstate
transmission component of transactions in which an end user arranges
for the purchase of generation from a third-party. However, we
recognize that there is a wide range of programs and transactions that
might or might not fall within this category. We will address these on
a case-by-case basis.
In summary, the Commission reaffirms and clarifies its prior
jurisdictional conclusions and tests for determining the demarcation
between federal and state jurisdiction over transmission in interstate
commerce and local distribution. We have attempted to address these
issues in a way that provides for flexibility and recognition of
legitimate state concerns. With regard to retail services, we recognize
the states' concerns that the unbundling of retail transactions would
result in changes from what historically has been regulated by the
states (principally, the rates of transmission assets previously
included in retail rate base). However, the decision to provide
unbundled retail wheeling is not the Commission's to make because we
have no authority to order transmission directly to an ultimate
consumer. In addition, even if a retail access program occurs, we do
not believe the unbundling of retail transactions will radically change
fundamental state authorities, including authority to regulate the vast
majority of generation asset costs, the siting and maintenance of
generation facilities and transmission lines, and decisions regarding
retail service territories. Further, the Commission intends to be
respectful of state objectives so long as they do not balkanize
interstate transmission of power or conflict with our interstate open
access policies. As the electric industry and state regulatory
authorities continue to develop new competitive market structures and
consider retail wheeling programs, we believe that the tests and
mechanisms we have provided in this Rule will accommodate both Federal
and state interests and will help provide jurisdictional certainty to
market participants.
[[Page 21628]]
J. Stranded Costs
1. Justification for Allowing Recovery of Stranded Costs
In the Supplemental Stranded Cost NOPR, the Commission noted that
the Open Access Rule would give a utility's historical wholesale
customers greatly enhanced opportunities to reach new
suppliers.553 This would affect the way in which utilities have
recovered costs under the traditional regulatory system that, on the
one hand, imposed an obligation to serve,554 and, on the other
hand, permitted recovery of all prudently incurred costs. We noted that
if customers leave their utilities' generation systems without paying a
share of these costs, the costs will become stranded unless they can be
recovered from other customers. The Commission stated in the NOPR that
we must address the costs of the transition to a competitive industry
by allowing utilities to recover their legitimate, prudent and
verifiable stranded costs simultaneously with any final rule we adopt
requiring open access transmission.555
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\553\ FERC Stats. & Regs. para. 32,514 at 33,095.
\554\ The Supplemental Stranded Cost NOPR described such an
obligation as explicit at retail and arguably implicit at wholesale.
FERC Stats. & Regs. para. 32,514 at 33,101.
\555\ Id. at 33,095-96, 33,101.
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Comments
Virtually all of the investor-owned utility commenters as well as
commenters representing state commissions and other constituencies
support the NOPR's premise that stranded costs can be created when a
customer switches suppliers. They endorse the proposal to allow the
recovery of legitimate and verifiable stranded costs.556 Numerous
commenters also support the Commission's proposal to link stranded cost
recovery with open access tariffs. These commenters agree that the
recovery of stranded costs is critical to the successful transition of
the industry to an open transmission access, competitive
industry.557 Commenters such as EEI and NU submit that open access
and stranded cost recovery should be implemented simultaneously; that
unbundled transmission service should not be required until a stranded
cost recovery mechanism is in place. Some commenters propose that if
the full recovery of stranded costs is disallowed as a result of
rehearing or judicial review, utilities that have filed open access
transmission tariffs should be permitted to withdraw them, or the
Commission should otherwise reconsider its rule on open access
transmission in light of such a reversal.558
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\556\ See, e.g., EEI, Atlantic City, Arizona, Carolina P&L,
Centerior, Central Hudson, Detroit Edison, Duke, Duquesne, Entergy,
Florida Power Corp, El Paso, Houston, NIPSCO, NU, Oklahoma G&E,
Otter Tail, PG&E, Puget, Southern, San Diego G&E, SCE&G, SoCal
Edison, Montana, Montana-Dakota Utilities, NSP, Utilities For
Improved Transition, NC Com, PA Com, Electric Consumers Alliance,
American National Power, NE Public Power District, MEAG, OH Coops,
Seattle, NY Energy Buyers, SBA, TVA, Utility Workers Union, Big
Rivers EC, Central EC, Citizens Lehman, NGSA, AGA, Montaup, NIEP.
\557\ See, e.g., EEI, Coalition for Economic Competition, EGA,
CINergy, Electric Consumers Alliance, Atlantic City, Com Ed,
Consumers Power, Dayton P&L, Dominion, Duke, El Paso, NEPCO, NIMO,
NIPSCO, Ohio Edison, Florida Power Corp, PECO, Pennsylvania P&L,
PSNM, Public Service Co of CO, Southern, SCE&G, VEPCO, Texas
Utilities, DOE, CA Energy Com, CO Com, PA Com, NE Public Power
District, SMUD, Brazos, Sunflower, PJM, Utility Workers Union,
Utility Investors Analysts, Nuclear Energy Institute, SoCal Gas,
AGA, Utility Shareholders, LPPC. Although DOD agrees that addressing
stranded costs is a critical part of the transition to a more
competitive industry, it submits that there is nothing in the Open
Access NOPR that should affect the treatment of stranded costs
because the Open Access NOPR would not change the contracts that
govern existing wholesale transactions. It argues that the
Commission will have ample opportunity to decide these matters
before the present wholesale long-term contracts expire.
\558\ E.g., Utilities For Improved Transition, PECO, Utility
Workers Union, Dayton P&L.
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Commenters representing the financial community reiterate their
strong support for the full recovery of stranded costs, noting that the
prospect of not recovering stranded costs could erode a utility's
ability to attract capital which, in turn, could impede the long-term
goal of achieving competitive wholesale markets.559 Several
commenters also argue that stranded cost recovery is economically
efficient and is necessary to ensure parity among competitors and to
avoid uneconomic bypass.560
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\559\ Utility Investors Analysts, Utility Shareholders.
\560\ See, e.g., EEI, SCE&G, Montana, Com Ed.
---------------------------------------------------------------------------
The commenters that oppose allowing utilities to recover legitimate
and verifiable stranded costs repeat many of the arguments that were
raised in response to the initial Stranded Cost NOPR. For example, a
number of commenters argue that the risk that a utility could lose
customers (and thereby incur stranded costs) is not a new phenomenon
created by regulatory and statutory initiatives that utilities could
not have anticipated.561 Some commenters argue that there was
never an implied obligation to serve at wholesale.562 According to
TDU Systems, monopoly power, not regulatory obligation, has kept
wholesale customers captive over the years.
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\561\ E.g., TAPS, IN Industrials, Air Liquide, Texas
Industrials, Detroit Edison Customers, AMP-Ohio.
\562\ E.g., TDU Systems, Competitive Enterprise.
---------------------------------------------------------------------------
Other commenters argue that allowing the recovery of stranded costs
would make it uneconomic for customers to seek alternative sources of
power and that the prospect of liability for and protracted litigation
over stranded cost claims would create paralyzing uncertainty for
customers, uncertainty that may dissuade them from taking advantage of
new opportunities in the wholesale power market.563 Some
commenters also argue that stranded cost recovery would be a
disincentive to efficient operation by affording the greatest
protection to utilities that made the worst investment
decisions.564
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\563\ See, e.g., Missouri Joint Commission, Omaha PPD, American
Forest & Paper, TAPS, AMP-Ohio, Kansas Commission, VA Com, Nucor,
Torco, IPALCO, DE Muni, Municipal Energy Agency Nebraska, Air
Liquide, Arkansas Cities, Detroit Edison Customers, Cleveland,
Texas-New Mexico, Blue Ridge, Suffolk County, NM Industrials, PA
Munis, Caparo, ABATE, NRRI, Building Owners, Alma, WEPCO, Total
Petroleum. SC Public Service Authority asserts that the Commission
has not adequately addressed the anticompetitive potential of exit
fees and the potential shifting of losses from high-cost to low-cost
producers. It says that the Commission should renotice any further
proposal that it develops to permit a reasoned analysis of
anticompetitive concerns.
\564\ E.g., TAPS, AMP-Ohio, IPALCO, Suffolk County, Competitive
Enterprise, NY Energy Buyers, Supervised Housing, Central Illinois
Light, WP&L, SC Public Service Authority, KS Com.
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Commenters also argue that the scope of the proposed rule is
overbroad; that stranded cost recovery should be allowed, if at all, on
a case-by-case basis; that there should be no presumption that every
utility will experience stranded costs; and that utilities should not
be allowed to recover 100 percent of prudently incurred stranded
costs.565
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\565\ E.g., Alma, IPALCO, Suffolk County, CO Consumers Counsel,
Arkansas Cities, Central Illinois Light, NY AG, NASUCA, VA Com, NY
Energy Buyers, UT Industrials, NM Industrials, NJ Ratepayer
Advocate, WEPCO, IN Industrials, ABATE, AZ Com.
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Several commenters suggest that there is no factual basis for the
stranded cost rule, citing a lack of evidence of a wholesale stranded
cost problem.566 TDU Systems refers to a Resource Data
International study that shows that, of $114 billion in potential
investor-owned utility stranded investment, only $10.4 billion is
associated with wholesale transactions.567 Others submit that the
[[Page 21629]]
Commission should obtain more current data concerning the magnitude of
potential stranded cost recovery before issuing the final rule.568
In reference to the statement in the Supplemental NOPR that the
Commission will continue to gather information on the magnitude of
potential stranded costs,569 DE Muni states that the Commission
must commit to making public all the data it obtains so that all can
evaluate the impact of the recovery of stranded costs on an ongoing
basis.
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\566\ E.g., ELCON, TDU Systems, Texas-New Mexico, Central
Illinois Light.
\567\ However, Utilities for Improved Transition refers to a
report by Moody's Investor Service estimating that the stranded
costs of the Nation's 114 largest electric utilities under open
access transmission will be $135 billion in the next ten years (13
to 14 times greater than the costs stranded by the introduction of
open access transportation of natural gas). It notes that this
estimate covers costs stranded by transmission in interstate
commerce of both wholesale and retail power, and submits that both
types of costs are relevant to this proceeding because of the
Commission's jurisdiction over the transmission rates for wheeling
to both wholesale and retail customers.
\568\ E.g., Central Illinois Light, Utility Workers Union,
Alcoa.
\569\ See FERC Stats. & Regs. para. 32,514 at 33,105.
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NRRI submits that the Commission has drawn the wrong conclusion
from its natural gas industry experience. According to NRRI, pipelines
were ``caught in an unusual transition'' by changes caused by Congress
and the Commission. In the case of the electric industry, NRRI submits
that although there are uneconomic wholesale power contracts, the
Commission is not responsible for this situation.570
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\570\ According to NRRI, the Commission did not ``berate''
electric utility management to sign uneconomic contracts in the
manner that NRRI contends the Commission and Congress ``berated''
pipeline management. NRRI Initial Comments at 6. NRRI also objects
that the proposed rule is a departure from what occurred in other
deregulated industries (where no stranded cost recovery was allowed)
and that the Commission should provide a fuller explanation as to
why it believes allowing utilities full recovery of legitimate and
verifiable stranded costs is the correct course of action.
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Several commenters suggest that the Commission condition a
utility's ability to recover stranded costs upon the utility agreeing
to take certain actions (such as reducing environ
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
mental effects
571 or ensuring the payment of costs that are stranded if the
utility commences direct service to an end-use customer that was
previously a wholesale customer of a transmission dependent utility
572 ), or agreeing to refrain from certain actions (such as
seeking unilaterally to terminate or modify IPP contracts).573
CCEM proposes that open access, conversion rights, and divestiture
should each be a precondition to a utility's eligibility for any
stranded cost recovery. VT DPS submits that, if the Commission adopts a
stranded cost rule, it should limit utility stranded cost claims to
those cases where the utility can demonstrate that its costs have been
rendered unrecoverable as a direct result of the final rule.574
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\571\ E.g., Legal Environmental Assistance, Conservation Law
Foundation.
\572\ E.g., TDU Systems.
\573\ E.g., EGA, LG&E. EGA and LG&E further argue that if a
utility is able to abrogate a QF contract, a QF should be entitled
to recover its costs based upon the same equities of reliance upon
governmental approvals, changed regulatory regimes, and reasonable
expectation.
\574\ VT DPS argues that under Order No. 636, the Commission
allowed recovery of costs that would be rendered ``unrecoverable''
because the costs would not be incurred to provide transportation
service and because there would be no wholesale load from which to
recover the costs. It suggests that when a utility loses wholesale
load or a municipality establishes a new distribution system, the
utility's costs are not necessarily rendered unrecoverable.
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A number of commenters object that the proposed rule contains no
provisions for non-transmission-owning utilities to collect stranded
costs.575 Illinois Municipal Electric Agency asks the Commission
to consider providing a forum for municipals to recover stranded costs
from their customers under the same guidelines as investor-owned
utilities. Recognizing that the FPA gives the Commission no general
jurisdiction over municipalities for purposes of rate
regulation,576 Illinois Municipal Electric Agency argues that the
FPA nevertheless does not prevent the Commission from providing a forum
for municipalities that may experience stranded costs as a result of
new federal regulations. NE Public Power District, RUS, and rural
electric cooperative commenters object that the NOPR gives public
utilities a greater chance than other transmitting utilities to recover
stranded costs from departing customers by offering public utilities
two avenues of recovery (an exit fee under a power sales contract or a
transmission surcharge) but offering other transmitting utilities only
one avenue (a transmission surcharge).577
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\575\ E.g., PA Munis, Missouri Joint Commission, TAPS, Municipal
Energy Agency Nebraska.
\576\ But see FPA section 212(a), 16 U.S.C. 824k(a).
\577\ RUS objects that, at the same time, an RUS-financed
cooperative that is a transmitting utility would be required to
provide reciprocal open access to its public utility supplier, which
is also its customer and its competitor.
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PA Munis objects that the Commission's proposal to impose stranded
costs only on wholesale requirements customers (and not on other
wholesale customers) is unduly discriminatory and counter to the goals
of the Open Access NOPR. It submits that the Commission's proposal, by
subjecting a wholesale requirements customer to increased transmission
rates for stranded costs not levied on other wholesale customers, is
indistinguishable in substance from the pre-Order 436 plan held to be
discriminatory in Maryland People's Counsel v. FERC.578
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\578\ 761 F.2d 768 (D.C. Cir. 1985).
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ELCON and others 579 urge the Commission to clarify that
stranded costs do not arise when a customer leaves a system because its
plant becomes uneconomic or the customer wishes to co-generate or self-
generate. They note that ``[t]hese alternatives have always existed and
do not arise from new opportunities for wholesale and retail
wheeling.'' 580
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\579\ E.g., VA Com, DE Muni, LG&E, Mountain States Petroleum
Assoc.
\580\ ELCON July 25, 1995 Comments at 6.
---------------------------------------------------------------------------
Commission Conclusion
We reaffirm our preliminary determination that the recovery of
legitimate, prudent and verifiable stranded costs should be allowed.
Having considered the arguments raised by the commenters that oppose
stranded cost recovery, we continue to believe that utilities that
entered into contracts to make wholesale requirements sales under an
entirely different regulatory regime should have an opportunity to
recover stranded costs that occur as a result of customers leaving the
utilities' generation systems through Commission-jurisdictional open
access tariffs or FPA section 211 orders,581 in order to reach
other power suppliers. As we indicated in the Supplemental Stranded
Cost NOPR, we do not believe that utilities that made large capital
expenditures or long-term contractual commitments to buy power years
ago should now be held responsible for failing to foresee the actions
this Commission would take to alter the use of their transmission
systems in response to the fundamental changes that are taking place in
the industry.582 We will not ignore the effects of recent
significant statutory and regulatory changes on the past investment
decisions of utilities.583 While, as some commenters point out,
there has always been some risk that a utility would lose a particular
customer, in the past that risk was smaller. It was not unreasonable
for the utility to plan to continue serving the needs of its wholesale
requirements customers and retail customers, and for those customers to
expect the utility to plan to meet future customer needs. With the new
open access, the risk of losing a
[[Page 21630]]
customer is radically increased. If a former wholesale requirements
customer or a former retail customer uses the new open access to reach
a new supplier, we believe that the utility is entitled to recover
legitimate, prudent and verifiable costs that it incurred under the
prior regulatory regime to serve that customer.584
---------------------------------------------------------------------------
\581\ Hereafter referred to collectively as the ``new open
access'' or ``open access transmission.''
\582\ FERC Stats. & Regs. para. 32,514 at 33,101-02.
\583\ Contrary to NRRI's claim, and as explained in the NOPR
(see, e.g., FERC Stats. & Regs. para. 32,514 at 33,063-68), the
electric industry's transition to a more competitive market is
driven in large part by statutory and regulatory changes beyond the
utilities' control.
\584\ As a result, the opportunity for wholesale stranded cost
recovery under this Rule is limited to utilities that provided sales
of generation and transmission under wholesale requirements
contracts, and to utilities that provided service to retail
customers that convert to wholesale customer status, and that face
the potential inability to recover costs when their customers are
able to reach new suppliers through open access transmission.
---------------------------------------------------------------------------
We learned from our experience with natural gas that, as both a
legal and a policy matter, we cannot ignore these costs. During the
1980s and early 1990s, the Commission undertook a series of actions
that contributed to the impetus for restructuring of the gas pipeline
industry. The introduction of competitive forces in the natural gas
supply market as a result of the Natural Gas Policy Act of 1978
585 and the subsequent restructuring of the natural gas industry
left many pipelines holding uneconomic take-or-pay contracts with gas
producers. When the Commission initially declined to take direct action
to alleviate that burden, the U.S. Court of Appeals for the District of
Columbia Circuit faulted the Commission for failing to do so.586
The court noted that pipelines were ``caught in an unusual transition''
as a result of regulatory changes beyond their control.587
---------------------------------------------------------------------------
\585\ 15 U.S.C. 3301 et seq.
\586\ AGD, 824 F.2d at 1021.
\587\ Id. at 1027.
---------------------------------------------------------------------------
As we stated in the Supplemental NOPR, the court's reasoning in the
gas context applies to the current move to a competitive bulk power
industry. Indeed, because the Commission failed to deal with the take-
or-pay situation in the gas context, the court invalidated the
Commission's first open access rule for gas pipelines. Once again, we
are faced with an industry transition in which there is the possibility
that certain utilities will be left with large unrecoverable costs or
that those costs will be unfairly shifted to other (remaining)
customers. That is why we must directly and timely address the costs of
the transition by allowing utilities to seek recovery of legitimate,
prudent and verifiable stranded costs. At the same time, however, this
Rule will not insulate a utility from the normal risks of competition,
such as self-generation, cogeneration, or industrial plant closure,
that do not arise from the new availability of non-discriminatory open
access transmission. Any such costs would not constitute stranded costs
for purposes of this Rule.
We are issuing the Stranded Cost Final Rule simultaneously with the
Open Access Final Rule because we believe that the recovery of
legitimate, prudent and verifiable stranded costs is critical to the
successful transition of the electric industry to a competitive, open
access environment. We believe that our decision today will be upheld
by the courts. While the D.C. Circuit is still considering the various
appeals of Order No. 636,588 it has already upheld, in at least
two instances, our ultimate decision to allow the recovery of costs
stranded in the transition to a competitive natural gas
industry.589 As a result, we reject the suggestions of some
commenters that a utility's obligation to comply with the provisions of
the Open Access Final Rule should be conditioned upon final court
approval of the Stranded Cost Final Rule. We also decline otherwise to
condition a utility's ability to recover its stranded costs. As
described in greater detail in Section IV.J.8, if a utility can make
the necessary evidentiary showings, it will be eligible for stranded
cost recovery.
---------------------------------------------------------------------------
\588\ Pipeline Service Obligations and Revisions to Regulations
Governing Self-Implementing Transportation Under Part 284 of the
Commission's Regulations; and Regulation of Natural Gas Pipelines
After Partial Wellhead Decontrol, Order No. 636, 57 FR 13267 (April
16, 1992), FERC Stats. & Regs. para. 30,939 (1992), order on reh'g,
Order No. 636-A, 57 FR 36128 (August 12, 1992), FERC Stats. & Regs.
para. 30,950 (1992); order on reh'g, Order No. 636-B, 57 FR 57911
(December 8, 1992), 61 FERC para. 61,272 (1993), reh'g denied, 62
FERC para. 61,007 (1993), appeal pending United Distribution
Companies, et al., v. FERC, No. 92-1485, et al., (D.C. Cir. Oral
Argument Held Feb. 21, 1996).
\589\ See, e.g., Public Utilities Commission of the State of
California v. FERC, 988 F.2d 154, 166 (D.C. Cir. 1993) (``FERC, with
the backing of this court, has been at pains to permit pipelines to
recover these (take-or-pay) costs, which have accumulated less
through mismanagement or miscalculation by the pipelines than
through an otherwise beneficial transition to competitive gas
markets.''); Western Resources, Inc. v. FERC, 72 F.3d 147 (D.C. Cir.
1995).
---------------------------------------------------------------------------
With regard to the magnitude of potential wholesale stranded costs,
as the Supplemental Stranded Cost NOPR recognizes, the level may be
small relative to that of retail stranded costs. Nevertheless,
wholesale costs may be stranded as a result of open access
transmission. Because the significance of such costs to the utilities
that would face them may be great (and the prospect of not recovering
such costs could erode utilities' ability to attract capital and be
very detrimental to a diverse array of utility shareholders), we
believe that we have a responsibility to allow for the recovery of such
costs.
We disagree with the commenters who contend that this Rule would
discriminate against certain segments of the industry, such as non-
transmission-owning utilities (who would not be allowed to collect
stranded costs) or wholesale requirements customers (who would be
subject to stranded cost charges while other wholesale customers would
not). These commenters misconstrue the purpose of this Rule and the
nature of the stranded costs for which this Rule would allow recovery.
This rule is designed to address a new and specific problem: The fact
that a utility that historically has supplied bundled generation and
transmission services to a wholesale requirements customer and incurred
costs to meet reasonably expected customer demand may experience
stranded costs when its customer is able to reach a new generation
supplier due to the availability of open access transmission. This rule
proposes a solution to that problem by allowing the recovery of
legitimate, prudent and verifiable costs incurred by a utility to
provide service to a wholesale requirements customer that subsequently
becomes, in whole or in part, an unbundled wholesale transmission
services customer of the utility. The opportunity for extra-contractual
wholesale stranded cost recovery is allowed for only a discrete set of
requirements contracts for which the utility can demonstrate that it
had a reasonable expectation of continuing service, as well as for
retail-turned-wholesale situations in which the utility satisfies the
necessary evidentiary criteria. Thus, the fundamental premise of this
rule--namely, that a utility should have an opportunity to recover
reasonably-incurred costs that arise because open access use of the
utility's transmission system enables a generation customer to shop for
power--would not apply to a non-transmission-owning utility that, by
definition, has no transmission by which its generation customer can
escape to another supplier.
The same historical relationship discussed above, including the
expectation of continued service, justifies imposing the stranded costs
covered by this rule on wholesale requirements customers only (not on
non-requirements customers that contract separately for transmission
services to deliver their purchased power). Requirements customers
historically were long-term customers who typically did not expect to
take service from other suppliers. Utilities thus assumed they would
continue
[[Page 21631]]
serving these customers and may have made significant investments based
on that long-term expectation. In contrast, utilities did not (and do
not today) generally make investments for short-term economy-type
transactions. Rather, such transactions were entered into only when the
utility temporarily had available capacity or energy that could be
provided to the buyer at a price lower than the buyer's decremental
cost. The utility was not obligated in any way--either explicitly or
implicitly--to provide for the needs of non-requirements customers.
Because coordination transactions were not the cause of stranded
investment decisions, it would be inappropriate to allocate such costs
to non-requirements customers.
Further, although some commenters object that the Rule would give
public utilities a greater opportunity than other transmitting
utilities to recover stranded costs, our jurisdiction over transmitting
utilities that are not also public utilities is limited. If the selling
utility under an existing contract is a transmitting utility that is
not also a public utility, its wholesale requirements contracts are not
subject to this Commission's jurisdiction. Thus, we can allow such a
transmitting utility to recover stranded costs only through Commission-
jurisdictional transmission rates under sections 211 and 212 of the
FPA. Nevertheless, in the context of a specific section 211 case, we
would expect to apply similar principles to the extent possible to
assure full stranded cost recovery. We also encourage such transmitting
utilities to negotiate mutually agreeable stranded cost provisions with
their customers.
2. Cajun Electric Power Cooperative, Inc. v. FERC 590
---------------------------------------------------------------------------
\590\ 28 F.3d 173 (D.C. Cir. 1994) (Cajun).
---------------------------------------------------------------------------
In the Supplemental Stranded Cost NOPR, the Commission made a
preliminary finding that the Cajun court decision does not bar the
recovery of stranded costs as proposed in the NOPR and set forth our
reasoning in support of that finding.591
---------------------------------------------------------------------------
\591\ FERC Stats. & Regs. para. 32,514 at 33,105-06.
---------------------------------------------------------------------------
Comments
Various commenters contend that the proposal to permit recovery of
stranded costs at all, or particularly through transmission rates of
departing customers, fails to address the Cajun court's
concerns.592 These commenters repeat many of the same arguments
previously raised in this proceeding, which we have already addressed.
Some commenters argue that including generation-based stranded costs in
transmission rates is an anticompetitive tying arrangement and that
Cajun compels the Commission to abandon this aspect of its stranded
cost proposal or, at a minimum, to explain how the chosen method of
recovery differs from that remanded in Cajun.593
---------------------------------------------------------------------------
\592\ E.g., APPA, ABATE, ELCON, Central Illinois Light, IL Com,
VT DPS.
\593\ See, e.g., ELCON, American Forest & Paper, MMWEC, Cajun,
IL Com, PA Com, VT DPS, Education, DE Muni, IN Industrials, Texas-
New Mexico, Las Cruces, Blue Ridge, Suffolk County, Total Petroleum,
NM Industrials, PA Munis.
---------------------------------------------------------------------------
Several commenters 594 question whether the NOPR's stranded
cost provisions would undermine the ``meaningful'' access to
alternative suppliers referenced by the Cajun court.595 For
example, Arkansas Cities asserts that the Commission has failed to
address whether a transmitting utility retains market power over
transmission even after imposition of an open access tariff. It
contends that this question is vital to determining whether imposition
of stranded costs would interfere with a wholesale transmission
customer's meaningful access to other power suppliers.
---------------------------------------------------------------------------
\594\ E.g., Arkansas Cities, PA Munis, NM Industrials.
\595\ See Cajun, 28 F.3d at 179.
---------------------------------------------------------------------------
Some commenters also submit that the proposed procedures for a
customer to obtain an estimate of its stranded cost liability are
inadequate because they do not ameliorate the uncertainty confronting
the customer, which was a concern of the court in Cajun. They suggest
that a customer would still face the prospect of litigation concerning
whether a proposed stranded cost charge is appropriate.596
---------------------------------------------------------------------------
\596\ See, e.g., Suffolk County, Arkansas Cities, Education.
---------------------------------------------------------------------------
Other commenters argue that Cajun requires a trial-type evidentiary
hearing before stranded costs may be recovered. They question whether
the Commission's generic proposals on open access and the Commission's
statements about the need to recover stranded costs are
adequate.597 ELCON references the Cajun court's statement that
``if the Commission is wrong at the outset concerning the possibility
of legitimate stranded investment cost, it is not fair or reasonable to
create such a mechanism for recovery.'' 598 ELCON submits that the
factual record does not demonstrate any significant wholesale stranded
cost problem and, as a result, a final rule allowing recovery of such
costs would not be ``fair or reasonable.''
---------------------------------------------------------------------------
\597\ E.g., PA Com, NY Com, RUS.
\598\ Cajun, 28 F.3d at 179 (emphasis in original).
---------------------------------------------------------------------------
Many other commenters, in contrast, believe that the NOPR is
distinguishable from the case that was before the court in Cajun and
that the Commission has fully addressed the Cajun court's concerns.
According to the Coalition for Economic Competition, this proceeding is
very different from the Cajun proceeding because the proposed rule
would not automatically permit utilities to charge market-based rates.
The Coalition for Economic Competition states that in the absence of
generic market-based rate authorization, there is no basis in Cajun for
barring the recovery of stranded investment in transmission
tariffs.599
---------------------------------------------------------------------------
\599\ SC Public Service Authority notes this distinction as well
(Initial Comments at 78): ``In Cajun, the court was not criticizing
the recovery of stranded assets as an abstract matter, but
specifically as an integral part of a set of tariffs designed to
justify market-based rates on the basis that the open access tariff
adequately mitigated market power despite the provision permitting
recovery of stranded assets.'' It suggests that if the Commission
decides to allow utilities to recover stranded costs from departing
customers, any utility recovering such costs should not be allowed
to charge market-based rates.
---------------------------------------------------------------------------
A number of commenters agree with the Commission that the Cajun
court was concerned with the need for a more complete explanation of
the basis for stranded cost recovery and the mechanism selected for
such recovery. These commenters believe that the NOPR provides both the
evidentiary record for addressing these concerns on a generic basis and
the opportunity for all participants to present evidence and
arguments.600
---------------------------------------------------------------------------
\600\ See, e.g., EEI, NEPCO, Centerior, Electric Consumers
Alliance, Southern.
---------------------------------------------------------------------------
Noting the Cajun court's concern as to whether the wholesale
customer in that case had ``meaningful'' access to alternative
suppliers, a number of commenters agree that the Commission, through
the open access provisions of the NOPR, is in fact providing wholesale
customers meaningful, reasonable access to alternative
suppliers.601
---------------------------------------------------------------------------
\601\ E.g., Omaha PPD, Com Ed, Florida Power Corp. Com Ed also
submits that the argument by the petitioners in Cajun that ``there
really is no such thing as stranded investment, only a failure to
compete'' ignored the circumstances under which the investments were
made. It states that electric utilities did not incur the costs of
generation facilities (and long-term fuel and power supply
contracts) because they were less efficient competitors, but to
satisfy their obligation in a fully-regulated market to provide
service to all who request it.
---------------------------------------------------------------------------
As evidence that the Cajun court was concerned with inadequate
explanation and procedures and did not find that stranded costs could
never be justified, several commenters point out that the Cajun court
did not mention the D.C. Circuit's landmark decision in AGD, which
strongly supports stranded cost
[[Page 21632]]
recovery.602 For example, Coalition for Economic Competition
suggests that construing Cajun to hold that stranded cost recovery is
always anticompetitive would be at odds with AGD and other decisions
that have upheld the Commission's policy of allowing recovery of the
costs of the transition to competitive markets.603
---------------------------------------------------------------------------
\602\ See, e.g., Com Ed, Coalition for Economic Competition,
NYSEG, Entergy.
\603\ See, e.g., K N Energy, Inc., 968 F.2d 1295 at 1301 (D.C.
Cir. 1992), Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 874 (D.C.
Cir. 1993).
---------------------------------------------------------------------------
Numerous commenters also support the Commission's conclusion that
stranded cost recovery through transmission rates is not a tying
arrangement.604 Among other things, these commenters argue that a
tying claim requires that the defendant force the sale of a separate
product with the sale of a product over which it has market power, and
that here there is no second product being tied to transmission.
Several commenters also suggest that, in any event, stranded cost
recovery as proposed in the NOPR would be considered a legitimate
business justification under the antitrust laws.605 Com Ed
explains that the Commission, as part of its effort to enhance
competition in generation by opening up the transmission network, is
avoiding placing on utilities the entire burden of the stranded costs
resulting from their past regulatory obligations; it is not permitting
utilities to maintain a monopoly of power sales.
---------------------------------------------------------------------------
\604\ E.g., EEI, Com Ed, Consumers Power, SoCal Edison, Salt
River, Entergy.
\605\ See State of Illinois ex rel. Burris v. Panhandle Eastern
Pipe Line Co., 935 F.2d 1469, 1483 (7th Cir. 1991), cert. denied,
502 U.S. 1094 (1992) (pipeline's refusal to transport gas that an
LDC customer purchased from another supplier was ``genuinely and
reasonably motivated by the need to limit its potential take-or-pay
liability, not by a desire to maintain its monopoly position by
excluding competition in the sale of natural gas''); City of Chanute
v. Williams Natural Gas Company, 743 F. Supp. 1437 (D. Kan.), aff'd,
955 F.2d 641 (7th Cir. 1990) (pipeline's refusal to transport third-
party gas was motivated by legitimate business concerns, including
desire to prevent take-or-pay liability, not by an anticompetitive
motive).
---------------------------------------------------------------------------
Commission Conclusion
We reaffirm that we do not interpret the Cajun court decision as
barring the recovery of stranded costs. The court in that case did not
bar stranded cost recovery, as some commenters suggest; it instead
found that the Commission had not provided adequate proceedings and had
not fully explained its decision. The Commission had failed to hold an
evidentiary hearing concerning whether the inclusion of a stranded cost
recovery provision in a particular utility's transmission tariff, along
with other provisions in the tariff, resulted in the adequate
mitigation of Entergy's market power so as to justify market-based
rates. The court also found that the Commission had failed to explain
adequately its approval of the stranded cost provision, among other
provisions. In contrast, as discussed below, we have addressed in this
consolidated proceeding (the Stranded Cost NOPR, the Supplemental
Stranded Cost NOPR, the Open Access NOPR, and the Open Access/Stranded
Cost Final Rule) all of the Cajun court's concerns.
Our interpretation of Cajun is bolstered by a recent opinion of the
Court of Appeals for the D.C. Circuit (the same circuit that decided
Cajun) that confirms the validity of Commission imposed stranded cost
recovery mechanisms in the transition to competitive markets. In
Western Resources, Inc. v. FERC,606 the court affirmed the
Commission's decision to allow the recovery of costs stranded in the
transition of the natural gas industry to a competitive market.607
We believe that, by this decision, the court has again affirmed the
Commission's ability to allow stranded cost recovery, as long as we
follow adequate procedures and explain our decision.608
---------------------------------------------------------------------------
\606\ 72 F.3d 147 (D.C. Cir. 1995).
\607\ Id. at 152.
\608\ As we noted in the Supplemental NOPR, the same court had
earlier instructed the Commission in the AGD case that the
Commission must consider the transition costs borne by regulated
utilities when the Commission changes the regulatory rules of the
game. FERC Stats. & Regs. para. 32,514 at 33,106.
---------------------------------------------------------------------------
We are providing in this proceeding the evidentiary record to
support our decision to allow the recovery of legitimate, prudent and
verifiable stranded costs on a generic basis. We also are ensuring the
``meaningful'' access to alternative suppliers that was identified as a
concern of the Cajun court. The Open Access Final Rule is designed to
attack one essential element of market power--namely, control over
transmission access. The standard we are adopting for transmission
service is far stricter than the standard we used at the time Cajun was
decided; we now require non-discriminatory open access transmission, as
well as a code of conduct and non-discriminatory sharing of
transmission information (OASIS). The collective effect of these
actions is that public utilities that own, control or operate
interstate transmission facilities will not be able to favor their own
generation and will have to compete on an equal basis with other
suppliers.609 All public utilities that own, control or operate
facilities used for transmitting electric energy in interstate commerce
will have tariffs on file that offer to any eligible customer any
transmission services that the public utility could provide to itself,
and under comparable terms and conditions.
---------------------------------------------------------------------------
\609\ Id. at 33,065-67.
---------------------------------------------------------------------------
We note that the Cajun court identified several provisions in
Entergy's proposed tariff as potentially restraining competition:
Entergy's retention of sole discretion to determine the amount of
transmission capability available for its competitors' use; 610
the point-to-point service limitation; 611 the failure to impose
reasonable time limits on Entergy's response to requests for
transmission service; 612 and Entergy's reservation of the right
to cancel service in certain instances,613 even where a customer
had paid for transmission system modifications.614 These types of
provisions, which have the potential to restrain competition, will not
be allowed under the Open Access Rule. On the contrary, the Final Rule
pro forma tariff contains terms and conditions to ensure the provision
of non-discriminatory transmission service. In addition, the
requirements that a public utility take service under its own tariff,
adopt a non-discriminatory transmission information network, and
separate power marketing and transmission functions further ensure non-
discrimination and remove constraints to fair competition. Thus, the
nondiscriminatory open access
[[Page 21633]]
transmission that is the hallmark of this Rule is designed to ensure
meaningful access to alternative suppliers and goes far beyond that
which was offered in the transmission tariff that was under review in
Cajun.
---------------------------------------------------------------------------
\610\ In contrast to the tariff under review in Cajun, the Final
Rule pro forma tariff provides that available transmission
capability (ATC) must be calculated and posted on the transmission
provider's Open Access Same-time Information System (OASIS) pursuant
to new Part 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEM AND
STANDARDS OF CONDUCT FOR PUBLIC UTILITIES of the Commission's
regulations. Section 37.6 provides in pertinent part that along with
posting its ATC on its OASIS node, a public utility must make all
data used in the calculation publicly available, on request. Section
37.4 provides that employees of the public utility and any affiliate
that are engaged in merchant functions are prohibited from having
preferential access to any transmission-related information.
Additionally, the regulations provide auditing and monitoring
procedures to safeguard against discriminatory practices.
\611\ In contrast to the tariff under review in Cajun, the Final
Rule pro forma tariff requires the provision of point-to-point and
network service.
\612\ In contrast to the tariff under review in Cajun, the Final
Rule pro forma tariff requires reasonable time limits for responses
to transmission requests. Specifically, Section 17.5 provides that a
transmission provider must respond to a request for firm service as
soon as practicable, but not later than thirty days after the date
of receipt of a completed application.
\613\ In contrast to the tariff under review in Cajun, the Final
Rule pro forma tariff does not allow firm transmission service to be
cancelled after the service has been commenced. However, Section 7.3
of the Final Rule pro forma tariff does provide that in the event of
a customer default, the transmission provider may, in accordance
with Commission policy, file and initiate a proceeding with the
Commission to terminate service.
\614\ Cajun, 28 F.3d at 179-80.
---------------------------------------------------------------------------
We also have addressed the Cajun court's concern over the method of
recovery. In that case, Entergy proposed to include a charge in the
departing customer's transmission rate to recover its stranded
investment costs. The court said that this might constitute an
anticompetitive tying arrangement.615 As we explained in the
Supplemental NOPR, the stranded cost recovery procedure we prescribe in
this Rule is a transitional mechanism only that is intended to enable
utilities to recover costs prudently incurred under a different
regulatory regime. The purpose and effect of the stranded cost recovery
mechanism that we approve in this Rule is to facilitate the transition
to competitive wholesale power markets. Although we recognized in the
Supplemental NOPR that stranded cost recovery may delay some of the
benefits of competitive bulk power markets for some customers, such
transition costs must nevertheless be addressed at an early stage if we
are to fulfill our regulatory responsibilities in moving to competitive
markets. The stranded cost recovery mechanism that we direct here is a
necessary step to achieve pro-competitive results. In the long term,
the Commission's rule will result in more competitive prices and lower
rates for consumers.
---------------------------------------------------------------------------
\615\ Notably, the court stated: ``This is, in essence, a tying
arrangement, (citation omitted), and it might be fine if the purpose
of the arrangement were not to cabin Entergy's market power.'' Id.
at 177-78 (emphasis added).
---------------------------------------------------------------------------
The Commission's approach also is consistent with the traditional
regulatory concept of cost causation. We do not believe it is an
illegal tying arrangement to hold a customer accountable for the
consequences of leaving an incumbent supplier if, under our rules, the
incumbent supplier must show a reasonable expectation of continuing
service before it can recover stranded costs from the customer.
Further, in response to the Cajun court's concern that the
Commission had failed in that case to explain adequately its approval
of the stranded cost provision and other provisions, we have provided
in this proceeding a detailed explanation of the fundamental industry
and regulatory changes that have given rise to the potential for
stranded costs; the transitional nature of stranded costs; the critical
need to deal with these costs in order to reach more competitive
wholesale markets; and the consumer benefits that will result from
competitive generation markets. We also have provided a detailed
explanation of the terms and conditions in the Final Rule pro forma
tariff that will meet the non-discriminatory open access service
requirement.
Several commenters (and the Cajun court) express concern for the
need to provide as much certainty as possible for departing customers
concerning their potential stranded cost obligation. Without some
certainty, customers may be unable to shop for alternative suppliers.
In response to these concerns, we have modified the stranded cost
recovery mechanism to include a formula for calculating a departing
customer's potential stranded cost obligation. As discussed in greater
detail in Section IV.J.9, the revenues lost formula is designed to
provide certainty for departing customers and to create incentives for
the parties to address stranded cost claims between themselves without
resort to litigation.
We conclude that we have fully explained our decision to allow the
recovery of legitimate, prudent and verifiable costs that are stranded
in the transition to competitive wholesale bulk power markets. We also
have provided ample opportunity for all concerned to present arguments
and evidence on the issue. Further, we have significantly strengthened
our open access requirements to ensure mitigation of transmission
market power. Thus, we have fully addressed the concerns of the Cajun
court.
3. Responsibility for Wholesale Stranded Costs (Whether To Adopt Direct
Assignment to Departing Customers)
In the Supplemental Stranded Cost NOPR, the Commission made a
preliminary finding that direct assignment of stranded costs to the
departing wholesale generation customer is the appropriate method for
recovery of such costs.616
---------------------------------------------------------------------------
\616\ FERC Stats. & Regs. para.32,514 at 33,108.
---------------------------------------------------------------------------
Comments
Numerous parties representing all constituencies support direct
assignment of stranded costs to the departing generation
customer.617 These commenters argue, among other things, that
direct assignment is consistent with the cost causation principle and
preferable to increasing the delivered price of electricity to a whole
region through the imposition of a wires charge, and that recovery of
stranded costs from remaining customers would not be in the public
interest. Several state commenters seek assurance from the Commission
that native load customers will be held harmless from stranded costs
resulting from other customers leaving the system.618 KY Com
submits that the possible results of a broader assessment of stranded
costs, with the related uncertainty of its impact on the utilities'
cost of capital, is more problematic in the long run than the
possibility that the direct assignment of stranded costs would deter
customers from shopping for power.
---------------------------------------------------------------------------
\617\ See, e.g., EEI, Atlantic City, Arizona, Carolina P&L,
Centerior, Com Ed, Duke, HP&L, Duquesne, Florida Power Corp, Omaha
PPD, Alcoa, AEC & SMEPA, BG&E, Central Electric, Detroit Edison, El
Paso, Montana-Dakota Utilities, Ohio Edison, PECO, PSNM, Southern,
Sierra, SoCal Edison, Tucson Power, Utilities For Improved
Transition, Cajun, NRECA, EGA, Electric Consumers Alliance, FL Com,
PA Com, Knoxville, Salt River, KY Com, ND Com, California DWR, LA
DWP, TVA, Utility Investors Analysts, Texas Utilities, LG&E, Utility
Shareholders.
\618\ E.g., NC Com, UT Com, NJ Ratepayer Advocate.
---------------------------------------------------------------------------
Although TAPS opposes stranded cost recovery in general, it submits
that, if the Commission decides to allow recovery, the Commission
should directly assign stranded costs and not spread them across the
board to all transmission users.
Several commenters also oppose any allocation of stranded cost
liability to shareholders.619
---------------------------------------------------------------------------
\619\ E.g., SCE&G, Com Ed, Ky Com, NC Com. SCE&G states that the
Commission misinterpreted its previous comments by suggesting in the
Supplemental NOPR that SCE&G believed shareholders should bear part
of the costs.
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Some commenters state that direct assignment of stranded costs
sends the correct pricing signals during the transition to a
competitive regime. For example, Electric Consumers Alliance states
that a wholesale customer should be able to obtain power elsewhere, but
that the motive to do so should not be to escape responsibility for
sunk investments made on its behalf. El Paso submits that failure to
make the departing generation customer liable for stranded cost
recovery would create a ``first-off'' incentive; the customers that
leave the system first would not suffer from higher future rates
designed to recover prudently incurred costs from the reduced base of
remaining customers.
Some commenters support direct assignment but oppose recovery of
stranded costs through transmission rates. These commenters prefer an
exit fee or lump-sum approach that would reflect cost causation in an
unbundled fashion.620 DOJ maintains that a
[[Page 21634]]
transmission adder is analogous to an excise tax and that the excise
tax approach would distort pricing signals and customers' decisions on
the use of electric power. It submits that the lump-sum approach, on
the other hand, would establish a fixed, sunk liability that would not
depend upon how much transmission service the departing customer takes
in the future.621
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\620\ E.g., Texas Utilities, DOJ.
\621\ In its reply comments, Utility Working Group disputes
DOJ's arguments that a transmission adder is analogous to an excise
tax and would distort competition. It argues that DOJ's claim of
price distortion ignores the fact that the costs that would be
associated with a transmission adder consist of a portion of the
previous wholesale power price--the markup above the utility's
marginal cost that had regulatory approval. Utility Working Group
says that because the utility's price and its competitor's price
will contain this same charge for the utility's sunk and regulatory
costs (the difference between the utility's regulated rate and its
incremental cost), they will compete on the basis of their
respective incremental costs. It also suggests that transmission
adders can be designed on a lump-sum basis so that they are not tied
to the amount of electricity purchased.
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Other commenters oppose direct assignment as being inconsistent
with wholesale competition.622 They argue that placing all of the
responsibility for stranded costs on departing generation customers
would discourage customers from switching to other generation providers
and would thereby inhibit competition.623 Some commenters also
assert that departing generation customers are not the sole ``cause''
of stranded costs.624 VT DPS contends that direct assignment
cannot be reconciled with the Commission's refusal to allow the
imposition of exit fees by gas pipelines when their wholesale customers
depart.625
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\622\ E.g., ELCON, NYMEX, IL Industrials, Missouri-Kansas
Industrials, Philip Morris, Fertilizer Institute, Coalition on
Federal-State Issues.
\623\ Some commenters also oppose the Commission's proposal to
allow the recovery of generation-related costs through transmission
rates as being in contravention of cost-causation principles (e.g.,
VT DPS) or in violation of section 212(a) of the FPA, which they
contend limits cost recovery to transmission-related costs (e.g., IL
Industrials, Las Cruces).
\624\ E.g., ELCON, IL Industrials, NY Energy Buyers, TX
Industrials, Missouri-Kansas Industrials, Caparo, IBM, PA Munis,
Education. For example, Caparo submits that business decisions by
incumbent utilities are the cause of stranded costs.
\625\ In support of this proposition, the VT DPS cites
Transwestern Pipeline Co., 44 FERC para.61,164 at 61,536 (1988); El
Paso Natural Gas Co., 47 FERC para.61,108 at 61,314 (1989); El Paso
Natural Gas Co., 72 FERC para.61,083 (1995). It also contends that
the Commission recently treated a notice provision in an El Paso
contract as a conclusive, rather than a rebuttable, presumption. VT
DPS cites other differences between the Commission's treatment of
the natural gas and the electric utility industries. It notes that
the Commission has not proposed to allow existing wholesale electric
customers to get out of their contracts early, as it did in the gas
area.
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Some commenters support spreading the burden of stranded costs
broadly among departing customers, shareholders, and remaining
wholesale customers on the basis that it would be equitable for all
industry stakeholders to share both the benefits and the costs of the
transition to competition.626
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\626\ E.g., ELCON, IN Industrials, Reynolds, Philip Morris,
ABATE, Missouri-Kansas Industrials, Aluminum.
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Others support spreading the costs to all customers through, for
example, a meter charge to all utilities (to be passed on to
customers), a one-time charge across the total market base, an access
fee on the transmission system, or a component of transmission
rates.627 Nordhaus proposes a uniform national tax on all
customers, at a rate that declines over time in a predetermined manner.
He submits that this approach would remove ``gaming'' between utilities
and potential exiters, would ensure that the stranded costs are not
disproportionately loaded on price-sensitive demanders (that is,
exiting customers), and would gradually disappear over time in a
predictable fashion, thereby increasing the predictability of the new
market.
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\627\ See, e.g., American National Power, NIEP, NSP, SBA,
Coalition on Federal-State Issues, Pennsylvania P&L, Consolidated
Natural Gas, Nordhaus, PA Munis. Consumers Power states that it does
not oppose direct assignment, but asks that the final rule not
preclude utilities from proposing alternative recovery mechanisms,
including those that assess stranded costs on all transmission
customers as part of the transmission rate. It suggests that
utilities should not be precluded from showing that there may be
countervailing reasons to assess stranded costs broadly among all
transmission customers (e.g., where the costs assignable to a
particular customer or group of customers may be so high as to
create a dispute as to the propriety of direct assignment).
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PA Munis disputes the Commission's assertion in the Supplemental
Stranded Cost NOPR that there is no compelling reason to assess costs
broadly. It argues that a broad-based recovery mechanism that
distributes uneconomic stranded costs to all power users would minimize
the competition-inhibiting aspects of the Commission's proposed
surcharge on departing generation customers. In a similar fashion, NSP
states that across-the-board recovery from all users of the grid would
recognize the societal benefits to be achieved from the transition to a
competitive bulk power market and would reflect precedent set during
the move to competition in the natural gas and telephone industries. It
submits that the cost per service unit would be lower than exit fees
assigned to particular customers and would eliminate the need for
detailing stranded cost exposure for each customer contemplating
leaving the system.
FTC submits that some investments that now appear as stranded costs
may have been intended to benefit customers over a wider area than a
single utility. It suggests that national regional assessment methods
could recover stranded costs undertaken to benefit these wider groups
of customers.
We also received comments suggesting that less than full recovery
of stranded costs should be allowed. A number of commenters urge the
Commission to require some shareholder liability for stranded cost
recovery to give utilities an incentive to mitigate.628 Several of
these commenters assert that utility shareholders should be required to
pay a portion of any stranded costs (such as 25-50 percent) because at
least some of the responsibility for stranded costs lies with poor
business decisions by utility management.629 Occidental Chemical
proposes that the Commission grant utilities a ``presumption of
prudence'' in return for requiring them to absorb a minimum of 25
percent (up to 50 percent) of stranded costs, citing as support the
Commission's precedent in the natural gas industry.
---------------------------------------------------------------------------
\628\ See, e.g., American Forest & Paper, Torco, Philip Morris,
DE Muni, MT Com, IL Com, KS Com, Fertilizer Institute, Caparo, Las
Cruces, IN Com, PA Munis, San Francisco, NRRI, Competitive
Enterprise, ELCON, IN Industrials, UT Industrials, NY Energy Buyers,
ABATE, CA Energy Co, Caparo, Education, Reynolds.
\629\ See, e.g., Fertilizer Institute, Caparo, DE Muni, PA
Munis, MT Com, San Francisco, ELCON, IN Industrials, NY Energy
Buyers.
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Commission Conclusion
We reaffirm our decision that direct assignment of stranded costs
to the departing wholesale generation customer through either an exit
fee 630 or a surcharge on transmission is the appropriate method
for recovery of such costs. We believe it is appropriate that the
departing generation customer, and not the remaining generation or
transmission customers (or shareholders), bear its fair share of the
legitimate and prudent obligations that the utility undertook on that
customer's behalf.
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\630\ As used in this Rule, ``exit fee'' refers to the charge
that will be payable by a departing generation customer upon the
termination of its requirements contract with a utility (if the
utility is able to demonstrate that it reasonably expected to
continue serving the customer beyond the term of the contract),
whether payable in a lump-sum payment or an amortization of a lump-
sum payment. (The same charge also can be paid as a surcharge on the
customer's transmission rate.)
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In reaching this decision, we have carefully weighed the arguments
supporting direct assignment of stranded costs against those supporting
a more broad-based approach, such as spreading stranded costs to all
transmission users of a utility's system.
[[Page 21635]]
Recognizing that each approach has advantages and disadvantages, we
conclude that, on balance, direct assignment is the preferable approach
for both legal and policy reasons.
One of the main reasons to adopt direct assignment of stranded
costs is that direct assignment is consistent with the well-established
principle of cost causation, namely, that the party who has caused a
cost to be incurred should pay it. Direct assignment of stranded costs
to departing generation customers is particularly appropriate given the
nature of the stranded cost recovery mechanism contained in this Rule,
which links the incurrence of stranded costs to the decision of a
particular generation customer to use open access transmission to leave
the utility's generation system and shop for power, and which bases the
prospect of stranded cost recovery on the utility's ability to
demonstrate that it incurred costs with the reasonable expectation that
the customer would remain on its generation system.
A broad-based approach, in contrast, would violate the cost
causation principle by shifting costs to customers (such as
transmission users of the utility's system) that had no responsibility
for stranding the costs in the first place. In addition, if the
Commission were to adopt a broad-based approach, it would have to
determine whether to base the transmission surcharge on all users of a
utility's transmission system on a one-time, up-front estimate of
stranded costs (that is, each utility claiming stranded costs would
make a one-time, comprehensive determination of stranded costs for the
utility as a whole) or on an as-realized basis (the surcharge would be
based on actual customer departures and would be adjusted each time a
customer departs). Each option would have disadvantages that are not
present in the direct cost causation approach we are adopting.
For example, a major disadvantage of an up-front, broad-based
transmission surcharge is that it in effect would charge customers for
costs before the costs are incurred (i.e., before customers have even
decided to leave the utility's generation system) and could charge for
costs that may never be incurred (e.g., some customers may decide to
stay on the utility's system as requirements customers). The other
option, a broad-based transmission surcharge that would be adjusted as
customers leave the utility's system, also has disadvantages. While
this option might recover stranded costs that are closer to the actual
amount incurred by the utility, it could produce variability in
transmission rates every time stranded costs from a newly-departed
customer are included in the transmission surcharge and, in turn, could
possibly hamper efficient power supply choices and efficient generator
location decisions. These disadvantages are not present in the direct
assignment approach.
Direct assignment will result in a more accurate determination of a
utility's stranded costs than would an up-front, broad-based
transmission surcharge. This is because the stranded cost for any
customer is finally determined only if that customer actually leaves a
utility. Moreover, there is no stranded cost unless the then-current
market price of power for the period that the utility reasonably
expected to continue serving the customer is below the utility's cost.
Thus, because the circumstances of each departing customer will be
known, the amount of any stranded cost liability can be determined with
reasonable accuracy. Further, if a customer does not leave the utility
or leaves at some future time when the utility's costs are competitive,
the issue need not be addressed.
On this basis, the direct assignment approach is more suited to the
recovery of stranded costs as defined in this Rule (including the
reasonable expectation standard and open access transmission causation
requirement) than is a broad-based approach. We expect that a utility
would have difficulty estimating in advance all of its stranded costs
for purposes of an up-front, broad-based transmission surcharge. In the
face of this uncertainty, the utility's best strategy likely would be
to try to recover through the broad-based surcharge as much of its
uneconomic assets as possible by claiming that all of its wholesale
customers are likely to depart and to leave large stranded costs. In
this regard, the broad-based approach would provide an incentive for a
utility to try to recover the costs of all of its uneconomic assets
whether or not they were prudently incurred. This is in contrast to
what this Rule provides, which is for recovery of only those
legitimate, prudent and verifiable costs that were incurred on behalf
of a specific customer based on a reasonable expectation that the
utility would continue to serve the customer and that are stranded when
the customer departs the utility's generation system by using the
utility's open access transmission.
The direct assignment approach also can be readily applied to both
wholesale and retail-turned-wholesale departing customers. It also can
be adapted for retail customers. Further, it works for costs stranded
by a section 211 order requiring either a public utility, or a
transmitting utility that is not also a public utility, to provide
transmission service. However, this is not the case for a broad-based
approach, particularly an up-front, broad-based approach. Assuming that
a principal motivation for an up-front, broad-based approach would be
to recover all of a utility's stranded costs as quickly as possible,
retail-turned-wholesale stranded costs nevertheless are not susceptible
of being collected on an up-front basis. It is not possible to make a
realistic up-front estimate of costs stranded by municipalizations that
may occur in the future. Thus, even if we were to adopt an up-front,
broad-based approach for recovering costs that are stranded when
wholesale requirements customers use their former supplier's
transmission system to reach a new supplier, retail-turned-wholesale
stranded costs would have to be identified as they occur and the
stranded cost surcharge on transmission users adjusted accordingly.
Similarly, the broad-based approach is not easily adaptable to
transmitting utilities that are not also public utilities. It is
doubtful that, in establishing the rate for a section 211 applicant,
the Commission could also set transmission surcharges for customers
that were not section 211 applicants; this is what a broad-based
approach, in effect, would require us to do.
Direct assignment by means of an exit fee or a transmission
surcharge that is not dependent on any subsequent power or transmission
purchases by the customer is also an economically efficient way to
collected stranded costs. The customer may make a lump-sum stranded
cost payment, amortize the lump-sum payment, or spread the payment as a
surcharge in addition to its transmission rate. The total amount of
stranded costs that the directly-assigned customer ultimately pays
would not depend on how much transmission service it takes and thus
would not influence the customer's subsequent transmission purchase
decisions.
With a broad-based surcharge (which could be demand- or usage-
based), on the other hand, the surcharge for transmission users would
depend on how much transmission service the users take. A broad-based
approach also would be inefficient as it would raise the price of
transmission service for all customers, thereby potentially cutting off
some beneficial power trading that would otherwise occur for all
unbundled transmission customers. The surcharge also could convert some
profitable existing power purchase contracts into unprofitable
contracts. In
[[Page 21636]]
addition, it could reduce economy trading because the surcharge would
be added to the price of economy transmission. In this manner, a broad-
based surcharge would constitute a cross-subsidy that could distort the
market.
We recognize that direct assignment is not without its potential
drawbacks. For example, when compared to an up-front, broad-based
transmission surcharge approach, direct assignment may entail a longer
stranded cost recovery period. The transition period for stranded cost
recovery under a direct assignment approach would depend on the length
of the remaining terms of the wholesale requirements contracts for
which this Rule provides an opportunity for recovery (contracts
executed on or before July 11, 1994 that do not contain an exit fee or
explicit stranded cost provision).
On the other hand, a broad-based approach could identify and
recover stranded costs earlier than the direct assignment approach;
recovery of stranded costs for all of a utility's wholesale
requirements customers could begin as soon as the utility's up-front
stranded cost amount for departing wholesale customers is determined
(through litigation or settlement). However, this potential advantage
of a broad-based approach (the shorter transition period) is outweighed
by what we believe to be a serious infirmity, namely, the possibility
that the broad-based transmission surcharge could end up including
costs that have not yet been incurred and may never be incurred.
In addition, another potential drawback to the direct assignment
approach is that the departing generation customer may see little or no
savings in the short-term by switching power suppliers once its
stranded cost exit fee is added to its lower power price from a new
supplier. Direct assignment may leave the customer uncertain about the
benefits of shopping for power because of the customer's potential
stranded cost liability and, in turn, may bias the customer toward
staying with its existing power supplier.631
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\631\ To counteract this potential disadvantage, we have
provided procedures in this Rule, including a formula that the
utility is to use to calculate a departing generation customer's
stranded cost obligation, that allow a customer considering
switching power suppliers to request a stranded cost determination
from the utility at any time before the expiration of the customer's
wholesale requirements contract. See Section IV.J.9.
---------------------------------------------------------------------------
In the case of a broad-based approach, in contrast, much of the
customer's direct assignment stranded costs are spread to others
through a transmission surcharge. As a result, the departing generation
customer's power cost savings may more than offset the customer's
stranded cost transmission surcharge. The customer may therefore see
earlier power cost savings if a broad-based approach were
adopted.632 Once again, however, we believe that this potential
benefit to a broad-based approach is outweighed by a significant
countervailing disadvantage. In particular, the potential power cost
savings to the departing generation customer would be realized only by
shifting costs (that are directly attributable to the departing
generation customer) to the other users of the utility's transmission
system. We believe that this negative aspect of a broad-based
approach--its violation of the cost causation principle--is too great a
price to pay for allowing a departing generation customer to realize
power cost savings as early as possible.
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\632\ In addition, because the customer would already know its
stranded cost transmission surcharge, it presumably would have some
certainty as to the costs of shopping for power. However, the
stranded cost surcharge in its transmission rates subsequently may
be adjusted upward if the utility providing transmission becomes
eligible to recover retail-turned-wholesale stranded costs. Also, if
the broad-based stranded cost surcharge is adjusted on an as-
realized basis, the potential departing generation customer's
surcharge may increase as a result of other customers leaving the
utility's system.
---------------------------------------------------------------------------
Thus, we recognize that under direct assignment, it is possible
that some customers may not be able to afford to leave as soon as they
would like. This in turn could mean that lower cost suppliers would not
be able to make sales to those customers as soon as they would like.
However, this would occur only during a transition period, and it would
ensure that, consistent with strict cost causation principles, the
burden of these transition costs is not unfairly spread to other
customers. Once the existing uneconomic assets and contracts are behind
us, all wholesale customers will be better able to shop for power and
reap the long-term benefits of competitive supply markets.
Although this direct assignment approach is different from the
approach taken in the natural gas industry, we believe that the
difference is justified. The transition of the electric industry to an
open transmission access, competitive industry (including our proposal
to allow an opportunity for extra-contractual recovery of stranded
costs associated with a discrete set of wholesale requirements
contracts) is different in a number of respects from the natural gas
industry's transition to open access transportation service by
interstate natural gas pipelines. The gas industry underwent a long
period of open access transition, starting with Order No. 436 in 1985
and culminating with Order No. 636 in 1992. In the gas context, prior
to addressing potential stranded costs, the Commission in Order No. 436
allowed customers receiving bundled gas sales and transportation
service from a pipeline the option to convert to transportation-only
service, or to reduce their contract demand for gas service, before the
termination of their contracts with the pipeline.633 As a result,
most of the former bundled customers of the pipeline had already
departed the pipeline's sales service before the Commission addressed
the recovery of take-or-pay costs in Order Nos. 500 and 528. In
addition, by the time that the Commission addressed the remaining
transition costs in Order No. 636, the commodity or wellhead natural
gas market was already competitive and the majority of gas was already
being sold on an unbundled basis.
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\633\ As discussed in Section IV.A.5, we are not providing for a
similar conversion right in this Rule.
---------------------------------------------------------------------------
Thus, changes in the natural gas industry had progressed to such a
point (i.e., the departure of customers from bundled sales) that it was
not possible for the Commission to use a strict cost causation
approach. We noted in the Supplemental Stranded Cost NOPR that
Many natural gas customers had already left their historical
pipeline suppliers' systems. Others had converted from sales and
transportation customers to transportation-only customers. Others
were in a transition stage having had opportunities to lower their
contract demands or otherwise become partial service customers.
Significant take-or-pay and other costs had accumulated.634
---------------------------------------------------------------------------
\634\ FERC Stats. & Regs. para.32,514 at 33,108.
---------------------------------------------------------------------------
Under those circumstances, the Commission determined that it was
appropriate to spread the majority of the remaining transition costs
associated with take-or-pay and other supply contracts to all customers
(both existing and new) using the interstate natural gas transportation
system. Moreover, because of the changes in contractual relationships
that had already occurred among pipelines and their customers, it was
no longer possible for the Commission to follow a strict cost causation
approach to recovering take-or-pay costs. The Commission-prescribed
remedy for the recovery of transition costs in the natural gas industry
thus was tailored to fit the needs of that industry given the stage of
development at the time.
However, such a broad-based approach to recovery of natural gas
transition costs was an exception to the
[[Page 21637]]
time-honored principle that rates should reflect cost causation, and
because of this it was necessary for the Commission to justify its
departure from that principle. As the court said in K N Energy v. FERC,
635 ``[i]t has been this Commission's long standing policy that
rates must be cost supported. Properly designed rates should produce
revenues from each class of customers which match, as closely as
practicable, the costs to serve each class or individual customer.'' In
that case, the court found the Commission's departure from cost-
causation justified ``given the unusual circumstances surrounding the
take-or-pay problem, and the limited nature--both in time and scope--of
the Commission's departure from the cost-causation principle.''
636 It continues to be Commission policy to follow the cost-
causation principle to the extent possible.
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\635\ 968 F.2d 1295, 1300-01 (D.C. Cir. 1992) (quoting Alabama
Electric Cooperative, Inc. v. FERC, 684 F.2d 20, 27 (D.C. Cir. 1982)
(emphasis in original).
\636\ Id. at 1301. See also Public Utilities Commission of State
of California v. FERC, 988 F.2d 154, 169 (D.C. Cir. 1993).
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The factors described above are not present in the electric
industry. At this time, the vast majority of customers remain on their
bundled suppliers' systems and generation is not yet fully competitive.
Because the situation facing the electric industry today is different
from that which the natural gas industry faced, the Commission must
tailor its approach differently. In the case of the electric industry
today, we have the opportunity to address the stranded cost recovery
issue up front, before customers leave their suppliers' systems. We
thus are able to use the cost causation approach that has been
fundamental to our regulation since 1935.637
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\637\ Moreover, as we explained in the Supplemental Stranded
Cost NOPR, the shifting of generation costs to transmission rates
does not violate Commission policy where, as here, the customer that
caused the costs to be incurred and stranded will continue to pay
those costs. As we indicated, the only difference is that in some
instances the customer will pay the costs through an adder to its
transmission rate instead of through a generation rate. See FERC
Stats. & Regs. para.32,514 at 33,108 n.269.
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The Commission disagrees with commenters' arguments that we cannot
impose an exit fee to recover stranded costs because we did not do so
in the gas context. As discussed in Section IV.J.9, this Rule
establishes procedures for providing a potential departing generation
customer advance notice (before it leaves its existing supplier) of the
stranded cost charge (whether it is to be paid as an exit fee or a
transmission surcharge) that will be applied if the customer decides to
buy power elsewhere. In the natural gas context, in contrast, the
Commission has prohibited pipelines from developing and charging an
``exit fee'' after a customer had implemented its gas purchase
decision, noting that otherwise, the customer would not know in advance
the full cost consequences of its nomination decision.638 The
``exit fee'' that the Commission rejected in El Paso Natural Gas
Company 639 is also factually distinguishable from the ``exit
fee'' discussed in this rule. In that case, the Commission rejected a
pipeline's attempt post-restructuring to impose an ``exit fee'' on firm
transportation-only customers (that were converted sales customers) who
in the future elect either to terminate their firm transportation
service upon expiration of the service agreement, or to reduce their
firm transportation services level by more than 10 percent pursuant to
an existing contractual reduction right. Such a scenario is quite
different from the limited opportunity for stranded cost recovery
provided in this Rule, which is based on a utility's reasonable
expectation of continuing generation service to a bundled (sales and
transmission) requirements customer.
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\638\ See, e.g., Transwestern Pipeline Company, 43 FERC
para.61,240 at 61,654, order on rehearing, 44 FERC para.61,164 at
61,536 (1988), relevant petitions for review dismissed as moot,
Transwestern Pipeline Company v. FERC, 897 F.2d 570, 575-76 (D.C.
Cir. 1990); El Paso Natural Gas Company, 47 FERC para.61,108 at
61,314 (1989).
\639\ 72 FERC para.61,083 (1995). Further, VT DPS misinterprets
the Commission's reference to the NOPR in that case. The Commission
did not treat a notice of termination provision in El Paso's
contract as a conclusive presumption that El Paso had no reasonable
expectation of continuing to serve certain customers, as VT DPS
contends. The Commission merely stated that ``[e]ven if the rules
proposed in [the Supplemental Stranded Cost] NOPR were applied here,
El Paso would have difficulty justifying the exit fee proposed in
light of the existence of the notice of termination provision in the
contract.'' 72 FERC at 61,441.
----------------------------------------------------
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
-----------------------
We also will decline to require a utility seeking stranded cost
recovery to shoulder a portion of its stranded costs. Such a
requirement would be a major deviation from the traditional principle
that a utility should have a reasonable opportunity to recover its
prudently incurred costs.640 Although the Commission allowed such
an approach with regard to a natural gas pipeline's take-or-pay
costs,641 we did so only as an extraordinary measure given the
nature of the take-or-pay problem and the prevailing environment at
that time. We returned to traditional principles when, in issuing Order
No. 636, we authorized pipelines to recover all of their prudently
incurred gas supply realignment costs (the costs pipelines incur in
realigning, renegotiating, or terminating their portfolio of gas supply
contracts to adjust to their sales customers' decisions to exercise
their unilateral right under the rule to reduce or end their commodity
purchase obligations to the pipelines). 642 In the case of the
open access transmission required by this Rule, we believe that a
utility is entitled to an opportunity to recover all legitimate,
prudent and verifiable costs incurred by the utility when the
availability of open access transmission enables a requirements
customer to reach a new generation supplier.
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\640\ See, e.g., Maryland v. Louisiana, 451 U.S. 725, 748
(1981); Office of Consumers' Counsel v. FERC, 914 F.2d 292 (D.C.
1990); National Fuel Gas Supply Corporation v. FERC, 900 F.2d 340,
342, 347-51 (D.C. Cir. 1990).
\641\ In Order No. 500, the Commission provided that if
pipelines absorbed from 25 to 50 percent of their take-or-pay
settlement costs, they could recover an equal amount from their firm
sales customers in the form of fixed charges. Any balance could be
recovered in the form of a commodity rate surcharge or a volumetric
surcharge on total pipeline throughput. Order No. 500, FERC Stats. &
Regs. para.30,761 at 30,787 (1987). See also Order No. 528, 53 FERC
para.61,163 at 61,597 (1990). Moreover, we offered pipelines an
important quid pro quo for absorbing take-or-pay costs under Order
Nos. 500 and 528--a special presumption that they had been prudent
in incurring their take-or-pay liabilities.
\642\ Order No. 636, FERC Stats. & Regs. para.30,939 at 30,461.
---------------------------------------------------------------------------
Although the alternatives of either spreading the stranded costs to
all transmission users or requiring the utility shareholders to share
the costs with departing customers might enable a wholesale customer to
leave sooner than would the direct assignment approach, the departing
customer would be able to do so only at the expense of others who had
no responsibility for causing the legitimate, prudent and verifiable
costs to be incurred. Although we departed from strict cost causation
principles in the gas context and required a broad spreading of the
costs given the particular circumstances presented by the gas
industry's transition to open access, we ultimately returned to the
more traditional approach of allowing utilities to recover all of their
prudently incurred transition costs in Order No. 636. At this juncture
in the evolution of competition in the electric industry we need not
make such a departure from cost causation principles; utilities can
identify and seek to charge the customers who caused the costs to be
incurred in the first place, before those customers leave the utility's
generation system. Accordingly, we believe that a broader spreading of
the costs to entities who are not responsible for the incurrence of
[[Page 21638]]
the stranded costs would not be equitable.
4. Recovery of Stranded Costs Associated With New Wholesale
Requirements Contracts
In the Supplemental Stranded Cost NOPR, the Commission
preliminarily concluded that future wholesale contracts must explicitly
address the obligations of the seller and buyer, including the seller's
obligation to continue to serve the buyer, if any, and the buyer's
obligation, if any, if it changes suppliers. We stated that utilities
will be allowed stranded cost recovery associated with ``new''
wholesale requirements contracts (executed after July 11, 1994) only if
explicit stranded cost provisions are contained in the contract. We
indicated that recovery of wholesale stranded costs associated with any
such new contract will not be allowed unless such recovery is provided
for in the contract.643 We also stated that a contract that is
extended or renegotiated for an effective date after July 11, 1994
becomes a ``new'' contract for which stranded cost recovery will be
allowed only if explicitly provided for in the contract.644
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\643\ FERC Stats. & Regs. para. 32,514 at 33,110.
\644\ Id. at 33,118.
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We also stated that it is not appropriate to impose on a wholesale
requirements supplier a regulatory obligation to continue to serve its
existing requirements customer beyond the end of the contract term. We
proposed to retain the Sec. 35.15 prior notice of termination filing
requirement only for: (i) All contracts required to be filed under
sections 205 and 206 of the FPA that were executed before the effective
date of the Final Rule pro forma tariffs; and (ii) any unexecuted
contracts that were filed before the effective date of the Final Rule
pro forma tariffs. With regard to any power sales contract executed on
or after that date, we proposed to no longer require prior notice of
termination under Sec. 35.15, but to require (for administrative
reasons) written notification of the termination of such contract
within 30 days after termination takes place. We requested comments on
whether this proposal should also be applied to transmission
contracts.645
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\645\ Id. and nn. 273, 274.
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Comments
Numerous commenters support our preliminary conclusion that new
wholesale requirements contracts should explicitly address the
obligations of the seller and buyer and that it is not appropriate to
impose on wholesale requirements suppliers a regulatory obligation to
continue to serve their existing requirements customers beyond the end
of the contract term.646 However, Arkansas Cities expresses
concern that this could undermine obligations to serve that have been
included in certain contracts with utilities. It asks the Commission to
state that, unless a utility has undertaken an obligation to serve via
contract, there is no obligation to serve beyond the contract term.
Arkansas Cities asks the Commission to clarify that contracts
establishing an obligation to serve will be enforced.
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\646\ E.g., PA Com, FL Com, PSNM, Southern, NC Com, Duke, Public
Service Co of CO, SoCal Edison, PacifiCorp, Carolina P&L, NYSEG.
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Several other commenters argue that if a wholesale customer elects
to switch suppliers, the previous supplier should be under no
obligation to take the customer back onto its system at embedded cost
rates.647 Sierra asks the Commission to endorse a host utility's
ability to insist on protective contract provisions before
reestablishing service, including a predetermined period (such as five
years--a commonly-used planning period) before the customer could seek
to leave the system again.
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\647\ E.g., Sunflower, Sierra, Public Service Co of CO, Duke.
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A number of commenters support the Commission's proposal to
eliminate the prior notice of termination requirement for power sales
contracts executed after the date on which the final rule pro forma
tariffs become effective.648 Southern states that, because of the
opportunities for power purchasers that will exist after the proposed
rules take effect, the Commission also should eliminate Sec. 35.15 as
it applies to old contracts.
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\648\ E.g., EEI, NYSEG, Southern, PA Com, SoCal Edison,
Pacificorp, El Paso.
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Several commenters support eliminating the Sec. 35.15 filing
requirement for transmission contracts as well.649 This change is
needed, some assert, to provide certainty in commercial arrangements in
the more competitive environment and as a matter of fairness. CSW
suggests that all Sec. 35.15 filing requirements for existing contracts
(wholesale and transmission contracts) be phased out over three years
and that only contracts that expire within three years after the final
rule should be subject to the requirement to file a notice of
termination.
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\649\ E.g., EEI, Public Service Co of CO, PA Com, Entergy,
Florida Power Corp.
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Nevertheless, several other commenters oppose the Commission's
proposal to no longer require prior notice of termination for power
sales contracts executed on or after the effective date of the generic
tariffs.650 TDU Systems opposes elimination of Sec. 35.15 as
tantamount to a finding that termination of all contracts is just and
reasonable. TDU Systems and NRECA submit that the market power
exercised by supplying utilities will not disappear the instant the
rule becomes final and that it may be possible for a utility to
exercise monopoly power even with regard to ``new'' contracts. They
propose that if the Commission nevertheless decides to allow contract
termination under Sec. 35.15, the Commission should require a public
utility to pay ``stranded benefit'' costs to former wholesale power
customers if the customers show that they had a reasonable expectation
that the power sales would continue past the end of the agreement at
the prior rate.
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\650\ E.g., TDU Systems, NRECA, TAPS, Redding, Southwest TDU
Group. VT DPS sees no urgent need for elimination of the Sec. 35.15
requirement or for automatic termination of sales service under a
wholesale contract of more than three years duration. However, it
supports pregranted authorization of service termination upon
expiration of sales contracts with terms of less than three years.
Among other things, it submits that the pregranted authority to
terminate short-term service would relieve the utility of a planning
uncertainty and allow it to maximize use of uncommitted transmission
capacity.
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Several commenters also oppose eliminating the Sec. 35.15 filing
requirement for transmission contracts.651 FL Com asserts that
because the Commission has imposed an obligation to serve for
transmission service, Sec. 35.15 should be retained for new and
existing transmission contracts.
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\651\ TAPS, TDU Systems, FL Com, MMWEC.
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Commission Conclusion
We reaffirm our preliminary determination that future wholesale
requirements contracts should explicitly address the mutual obligations
of the seller and buyer, including the seller's obligation to continue
to serve the buyer, if any, and the buyer's obligation, if any, if it
changes suppliers. As we indicated in the Supplemental Stranded Cost
NOPR, now that utilities have been placed on explicit notice that the
risk of losing customers through increased wholesale competition must
be addressed through contractual means only, they must address stranded
cost issues when negotiating new contracts or be held strictly
accountable for the failure to do so.
We accordingly will allow recovery of wholesale stranded costs
associated with any new requirements contract
[[Page 21639]]
(executed after July 11, 1994) only if explicit stranded cost
provisions are contained in the contract. By ``explicit stranded cost
provision'' (for contracts executed after July 11, 1994) we mean a
provision that identifies the specific amount of stranded cost
liability of the customer(s) and a specific method for calculating the
stranded cost charge or rate. For purposes of requirements contracts
executed after July 11, 1994 but before the date on which this Final
Rule is published in the Federal Register, however, we clarify that a
provision that specifically reserved the right to seek stranded cost
recovery consistent with what the Commission permits in this Rule
(without identifying the specific amount of stranded cost liability of
the customer(s) and calculation method) nevertheless will be deemed an
``explicit stranded cost provision.'' However, a provision in a
requirements contract executed after July 11, 1994 but before the date
on which this Final Rule is published in the Federal Register that
merely postpones the issue of stranded cost recovery without
specifically providing for such recovery will not be considered an
``explicit stranded cost provision.'' After the date on which this
Final Rule is published in the Federal Register, a provision must
identify the specific amount of stranded cost liability of the
customer(s) and a specific method for calculating the stranded cost
charge or rate in order to constitute an ``explicit stranded cost
provision.''
We reaffirm that a requirements contract that is extended or
renegotiated for an effective date after July 11, 1994 becomes a
``new'' requirements contract for which stranded cost recovery will be
allowed only if explicitly provided for in the contract.
We also reaffirm our preliminary determination not to impose a
regulatory obligation on wholesale requirements suppliers to continue
to serve their existing requirements customers beyond the end of the
contract term. The only exception to this would be if the customer
decides to remain a requirements customer for the period for which the
Commission finds that the supplying utility reasonably expected to
continue serving the customer. In such a case, the supplying utility
will be obligated to offer continuing service to the requirements
customer for the period the utility reasonably expected to continue
serving the customer.
A requirements customer will be responsible for planning to meet
its power needs beyond the end of the contract term by either building
its own generation, signing a new power sales contract with its
existing supplier, or contracting with new suppliers in conjunction
with obtaining transmission service under its existing supplier's open
access transmission tariff or another utility's transmission system. In
so holding, it is not our intent to undermine any obligations
specifically contained in a contract. Thus, if a contract explicitly
establishes an obligation to serve beyond the end of the contract term,
such a contractually-imposed obligation to serve (as distinguished from
a regulatory obligation to serve) would be enforceable as a term of the
contract. If a wholesale customer that switches suppliers later seeks
to reestablish service with its former supplier, it will be up to the
parties to negotiate their respective obligations.
We also reaffirm our preliminary determination to no longer require
prior notice of termination under Sec. 35.15 for any power sales
contract executed on or after the effective date of the Final Rule pro
forma tariff (but to require written notification of the termination of
such contract within 30 days after termination takes places). This
determination goes hand-in-hand with our determination (discussed
above) not to impose a regulatory obligation on wholesale requirements
suppliers to continue to serve their existing requirements customers
beyond the end of the contract term.652 We clarify, however, that
this decision applies only to a power sales contract that is to
terminate by its own terms (such as on the contract's expiration date).
We have revised Sec. 35.15 accordingly. We will, however, continue to
require prior notice of cancellation or termination for any power sales
contract that is proposed to be cancelled or terminated for a reason
other than by the contract's own terms (such as a self-help provision
related to, for example, a billing dispute), regardless of when the
contract was executed. We also will continue to require prior notice of
the proposed termination of any power sales contract executed before
the effective date of the Final Rule pro forma tariff (even if the
contract is to terminate by its own terms) as well as any unexecuted
power sales contract that was filed before that date.
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\652\ Although several commenters have asked the Commission to
retain the prior notice of termination filing requirement due to
concern that a utility nevertheless may be able to exercise
generation market power with regard to a ``new'' wholesale
requirements contract, we do not believe that retention of that
provision is necessary to address these commenters' concerns.
Instead, any party claiming to be aggrieved by a utility's alleged
abuse of generation market power under a wholesale requirements
contract can file a complaint with the Commission under section 206
of the FPA.
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Further, we will retain the Sec. 35.15 filing requirement for all
transmission contracts. The reason for retaining the Sec. 35.15
requirement for transmission contracts is that transmission will
continue to be provided under conditions of potential market power, and
the Commission must be assured that transmission owners are not
exerting market power in termination of transmission contracts. In
addition, this filing requirement will provide the customer an
opportunity to notify the Commission if the termination terms are
disputed or if the customer was not given adequate opportunity to
exercise its limited right of first refusal under the Final Rule (see
Section IV.A.5).
5. Recovery of Stranded Costs Associated With Existing Wholesale
Requirements Contracts
In the Supplemental Stranded Cost NOPR, the Commission reaffirmed
its proposal to permit the recovery of legitimate, prudent and
verifiable stranded costs for a discrete set of ``existing'' wholesale
requirements contracts (executed on or before July 11, 1994)--those
that do not already contain exit fees or other explicit stranded cost
provisions. We encouraged the parties to such contracts to renegotiate
them to address stranded costs. In the case of existing contracts that
already contain an exit fee or explicit stranded cost provision,
however, we proposed to reject a unilateral stranded cost amendment;
that is, we stated we would reject an amendment unless the contract
permits renegotiation of the existing stranded cost provision or the
parties to the contract mutually agree to renegotiate the
contract.653 In so doing, we proposed to drop the three year
mandatory negotiation period suggested in the initial Stranded Cost
NOPR.654
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\653\ FERC Stats. & Regs. para. 32,514 at 33,113.
\654\ We invited comments on this proposal. Id. at 33,115.
---------------------------------------------------------------------------
If an existing requirements contract does not contain an exit fee
or other explicit stranded cost provision (and is not renegotiated to
add such a provision), we proposed that before the expiration of the
contract: (1) A public utility or its customer may file a proposed
stranded cost amendment to the contract under section 205 or 206; or
(2) a public utility or transmitting utility may file a proposal to
recover stranded costs associated with any such existing contract
through its transmission rates for a customer that uses the utility's
transmission system to reach another generation supplier.
[[Page 21640]]
In the Supplemental Stranded Cost NOPR, we reaffirmed our proposal
in the initial Stranded Cost NOPR that, even if the contract contains
an explicit Mobile-Sierra 655 provision, it is in the public
interest to permit public utilities to seek unilateral amendments to
add stranded cost provisions if the contracts do not in essence forbid
such recovery by containing exit fees or other explicit stranded cost
provisions.656 Under these circumstances, if neither of the
parties seeks and obtains acceptance or approval of a stranded cost
amendment, we propose to permit the public utility to seek recovery of
stranded costs through its wholesale transmission rates.
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\655\ See United Gas Pipeline Company v. Mobile Gas Service
Corporation, 350 U.S. 332 (1956); FPC v. Sierra Pacific Power
Company, 350 U.S. 348 (1956).
\656\ FERC Stats. & Regs. para. 32,514 at 33,113-14. We noted
that under the Mobile-Sierra doctrine, a customer may waive its
right to challenge the contract and/or the utility may waive its
right to make unilateral rate changes. However, the parties may not
waive the indefeasible right of the Commission to alter rates that
are contrary to the public interest. Id. at 33,111.
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We also proposed procedures for providing an existing wholesale
requirements customer advance notice of how the utility would propose
to calculate costs that the utility claims would be stranded by the
customer's departure.657
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\657\ Id. at 33,114-15.
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Comments
a. July 11, 1994 Cut-Off Date
A number of commenters ask the Commission to reconsider the July
11, 1994 cut-off date for distinguishing between ``existing'' and
``new'' requirements contracts. Some commenters 658 support
October 24, 1992 (the date of passage of the Energy Policy Act) as the
cut-off date on the basis that anyone entering into a wholesale
requirements contract after that date should have recognized the
greatly increased possibility of the customer terminating or not
renewing the contract.
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\658\ E.g., ELCON, TAPS, Alcoa, Utilicorp.
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Other commenters 659 support a later date for defining ``new''
requirements contracts, such as the date on which the final rule open
access tariffs become effective. Utilities For Improved Transition
argues that the Commission cannot retroactively adopt the July 11, 1994
cut-off date, but must wait until the final rule is issued before
setting the date after which requirements contracts must contain
stranded cost provisions in order for stranded cost recovery to be
allowed.
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\659\ E.g., Utilities For Improved Transition, Atlantic City.
---------------------------------------------------------------------------
Commenters representing electric cooperatives also oppose the July
11, 1994 cut-off date.660 They contend that RUS borrowers were not
free to negotiate stranded cost amendments to wholesale power contracts
as soon as the Commission warned them to do so because their wholesale
power contracts are mandated both as to form and substance by the
RUS.661
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\660\ E.g., Basin, Tri-County EC, NW Iowa Cooperative, Baker EC,
Big Horn EC, Black Hills EC, Bon Homme Yankton EC, Carbon Power,
Central EC, Douglas EC, East River EC, Ida County REC, James Valley
EC, Lincoln-Union EC, McKenzie EC, North Dakota RECs, Oahe EC,
Oliver-Mercer EC, Panhandle Coop, Rushmore EC, San Luis Valley EC,
Slope EC, Spink EC, Turner-Hutchinson EC, Traverse EC, Union County
EC, West River EC, Whetstone Valley EC, Woodbury County REC,
Yellowstone Valley EC.
\661\ Basin indicates that all such contracts for the sale of
more than 1,000 kW and any amendments thereto must be specifically
approved by the RUS.
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PA Munis asks the Commission to treat certain contracts that were
executed before July 11, 1994 (but not approved by the Commission until
after that date) as ``new'' contracts. PA Munis argues that the
utility, after issuance of the initial NOPR, could have withdrawn its
filing of the contract and sought to negotiate an exit fee at that
time. It submits that the utility's failure to do so would justify a
finding by the Commission that contracts approved after July 11, 1994
be treated similarly to contracts executed after that date.
b. Stranded Cost Recovery for Existing Requirements Contracts
A number of commenters express support for the Commission's
proposal to permit modification of existing requirements contracts that
do not already contain exit fees or other explicit stranded cost
provisions.662 NEPCO states its interpretation that the NOPR does
not consider notice provisions to be ``explicit stranded cost
provisions;'' it argues that the presence of a notice provision in a
contract, while bearing on the supplier's ability to demonstrate the
duration of its reasonable expectation of continued service, should not
foreclose the amendment of a wholesale contract to add an exit fee or
similar payment provision. Several other commenters ask the Commission
to clarify that contracts that contain notice provisions and that
preclude recovery for termination or reduction of service (but that do
not necessarily use the terms ``exit fee'' or ``stranded cost''), or
that expressly provide that stranded costs shall not be charged, cannot
be reopened for a stranded cost claim.663
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\662\ E.g., EEI, PSNM, AEP, Consumers Power. Consumers Power
suggests that the language of proposed Sec. 35.26(c)(1)(iv) be
modified to recite the Commission's public interest finding.
\663\ E.g., Concord, Chugach, ME Consumer-Owned Utilities.
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A number of other commenters oppose the Commission's proposal to
permit amendment of wholesale requirements contracts that do not
address stranded cost recovery, for reasons previously raised in this
proceeding.664 They argue, among other things, that contracts
should stand on their own. RUS asserts that the integrity of its
Federal loan program is to a large extent predicated on honoring the
long-term requirements wholesale power contracts between G&Ts and their
distribution members.
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\664\ E.g., Utilicorp, AMP-Ohio, Environmental Action, DE Muni,
Arkansas Cities, Direct Service Industries, PA Munis, ABATE, APPA.
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Several commenters also challenge the Commission's proposed
determination that it is in the public interest to permit utilities to
seek unilateral amendments to add stranded cost provisions to
requirements contracts. These commenters argue that the NOPR's
assumptions concerning the financial stability of public utilities are
unsupported and thus do not meet the burden of proof required for the
public interest finding under the Mobile-Sierra doctrine. They urge the
Commission to require a utility-specific finding of imminent financial
jeopardy before overriding a Mobile-Sierra contract.665
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\665\ See, e.g., American Forest & Paper, VT DPS, PA Munis,
ABATE, ELCON, APPA, Environmental Action.
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ELCON argues that the recent Northeast Utilities Service Company v.
FERC 666 case reaffirms the traditional high threshold for
overriding Mobile-Sierra clauses in the ``classic Mobile-Sierra
situation'' in which one of the parties seeks modification of a
contract that has already been reviewed and approved by the Commission.
It submits that a utility seeking to add a stranded cost provision to
an existing contract would fall within the ``classic situation.'' ELCON
also argues that the First Circuit strongly implied that to satisfy
Mobile-Sierra, the Commission must identify specifically those aspects
of a contract that are contrary to the public interest and why. On this
basis, ELCON argues that the case supports its position that a utility-
specific finding of imminent financial jeopardy is necessary to
override an existing Mobile-Sierra contract.667
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\666\ 55 F.3d 686 (1st Cir. 1995) (Northeast Utilities).
\667\ PA Munis argues that Northeast Utilities provides no
support for the Commission's proposed Mobile-Sierra finding because
Northeast Utilities involved the effect of disputed contractual
terms on third parties, not the alleged financial effect on the
utility. It argues that the court found that the Commission had
adequately explained how the disputed contractual terms may harm
third parties to the contract (which PA Munis says the Commission
has failed to do here). PA Munis also submits that the court went
out of its way to emphasize the narrow scope of its order affirming
the Commission.
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[[Page 21641]]
Some commenters argue that if utilities are to be granted industry-
wide Mobile-Sierra relief, then the Commission should give wholesale
customers the reciprocal right to convert their wholesale power
contracts to transmission-only service.668 However, EEI contends
that the Commission is barred by section 211(c)(2) of the FPA from
ordering wheeling where a customer is taking service under a contract
or under a rate tariff on file with the Commission.
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\668\ E.g., ELCON, CCEM, VT DPS, OK Com, TDU Systems, LG&E,
ABATE, Portland, Utilicorp, TAPS.
---------------------------------------------------------------------------
Several commenters ask the Commission to require renegotiation of
the notice and/or term of all existing contracts with long lead-time
cancellation provisions in order to allow all wholesale customers
access to the market at the same time.669 They submit that
customers with short notice provisions will be the first to enjoy the
benefits of open access and will have an effective ``first right of
refusal'' of the most economical transmission paths and low cost
suppliers, putting customers with long lead-time cancellations at a
competitive disadvantage.
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\669\ E.g., Knoxville, Memphis.
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c. Transition Period
A number of commenters support the Commission's proposal not to
mandate a three-year time limit for renegotiation of existing wholesale
requirements contracts. They note that existing contracts have unique
characteristics and complexities that affect the time required to
renegotiate the contract bilaterally, to file a unilateral amendment
with the Commission, or to file for stranded cost recovery through
transmission rates.670
---------------------------------------------------------------------------
\670\ E.g., EEI, Florida Power Corp, PA Com, WP&L, Consumers
Power, FL Com, TVA, SoCal Edison, Texas Utilities.
---------------------------------------------------------------------------
On the other hand, some commenters object that the proposal to
replace the previously proposed three-year window with an opportunity
to raise stranded cost claims throughout the existing contract term
creates a virtually unlimited transition period.671 For example,
ELCON asserts that because the NOPR would allow utilities to seek
amendment of an existing contract any time prior to its expiration,
stranded cost issues could extend through the life of existing
facilities (30 years or more). Portland suggests that the Commission
set a schedule now for proceedings to determine transmission costs and
stranded costs for each utility with wholesale requirements customers.
---------------------------------------------------------------------------
\671\ E.g., TAPS, TDU Systems, DOD, ELCON, APPA.
---------------------------------------------------------------------------
Commenters propose various limits to the period within which
stranded cost recovery could be raised, such as: (i) Three to five
years; 672 (ii) the lesser of three years from the effective date
of the final rule or the remaining term of the contract; 673 (iii)
one year from the effective date of the final rule; 674 and (iv)
December 31, 1998 (20 years after PURPA).675
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\672\ E.g., Sierra, Central Illinois Light, NY Energy Buyers,
American Forest & Paper, WEPCO, EGA. Education proposes either a
transition period that ends five years after the effective date of
the final rule or a phase-out of the utility's authority to recover
stranded costs from departing customers by gradually reducing (for
instance, over a ten year period from the date of the final rule)
the percentage of stranded costs that the utility could recover.
\673\ E.g., TAPS, Missouri Joint Commission.
\674\ E.g., TDU Systems.
\675\ E.g., DOD, ABATE.
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Commission Conclusion
a. July 11, 1994 Contract Cut-Off Date
We reaffirm our proposal to permit the recovery of legitimate,
prudent and verifiable stranded costs for ``existing'' wholesale
requirements contracts (executed on or before July 11, 1994) that do
not already contain exit fees or other explicit stranded cost
provisions. We believe that July 11, 1994--the date on which the
initial Stranded Cost NOPR was published and, thus, on which the
industry was put on notice of the proposal to disallow prospectively
extra-contractual recovery of stranded costs--is the appropriate date
for distinguishing ``existing'' requirements contracts from ``new''
requirements contracts. Because all parties were put on notice in the
initial Stranded Cost NOPR that July 11, 1994 would be the operable
date for the ``existing''/``new'' contract distinction, utilities that
executed requirements contracts after that date could have had no
reasonable expectation that they would be permitted to recover any
costs extra-contractually.
Moreover, because the costs at issue are extra-contractual costs,
the Commission's notice to all parties that contracts executed after
July 11, 1994 will be enforced by their terms as far as stranded cost
recovery is concerned does not constitute ``retroactive rulemaking.''
Contrary to UFIT's contention, the Commission is not ``requir[ing]''
utilities to include stranded cost recovery provisions in all contracts
executed after July 11, 1994.676 The Commission has merely put all
parties on notice that the opportunity for extra-contractual stranded
cost recovery (which will be allowed on a prospective basis upon the
effective date of the Rule) will not be available for any requirements
contracts executed after July 11, 1994. The parties to requirements
contracts executed after July 11, 1994 have been free to provide for
stranded cost recovery in the contract, or not.677 The point is
that, for requirements contracts executed after the cut-off date,
stranded cost recovery will be governed solely by the terms of the
contract.
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\676\ See UFIT Initial Comments at 34. Moreover, the cases that
UFIT cites, in which the Commission rejected parties' efforts to
devise rates based on methods or formulas contained in proposed
rules, are inapposite. By establishing the July 11, 1994 cutoff
date, the Commission is not ``fix(ing) rates under section 206'' or
otherwise making ``a Section 206 `determination,' '' as UFIT
suggests. Id. at 35, 36. The Commission has not proposed a change in
the way that utilities compute their rates; it has simply put all
parties on notice of the limited nature and opportunity for extra-
contractual stranded cost recovery.
\677\ In response to the commenters representing electric
cooperatives that object to the July 11, 1994 cut-off date, we do
not believe that the requirement that RUS borrowers obtain RUS
approval of their contracts necessarily prevents such borrowers from
addressing stranded cost recovery in contracts executed after July
11, 1994.
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b. Stranded Cost Recovery for Existing Requirements Contracts
We reaffirm that we will permit utilities to seek recovery of
stranded costs for a limited set of existing wholesale requirements
contracts, namely, those that do not already contain exit fees or other
explicit stranded cost provisions.678 If an existing requirements
contract includes an explicit provision for payment of stranded costs
or an exit fee, we will assume that the parties intended the contract
to cover the contingency of the buyer leaving the system. We will
reject a stranded cost amendment to such a contract, unless the
contract permits renegotiation of the existing stranded cost provision
or the parties to the contract mutually agree to a new stranded cost
provision. Similarly, we will reject a stranded cost amendment to an
existing requirements contract if the contract prohibits stranded cost
recovery (or precludes recovery for termination or reduction of
service) or
[[Page 21642]]
prohibits renegotiation of an existing stranded cost or exit fee
provision, unless the parties to the contract mutually agree to a new
stranded cost provision.679
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\678\ We confirm that a notice of termination provision by
itself (that is, one that does not also provide for or preclude
recovery of stranded costs by the seller upon termination of the
contract) is not an ``explicit'' stranded cost provision; however,
as discussed in Section IV.J.8, the presence of a notice provision
creates a rebuttable presumption that the utility had no reasonable
expectation of continuing to serve the customer.
\679\ In the case of an existing wholesale requirements contract
that does not contain an exit fee or other explicit stranded cost
provision but does contain a notice provision, once a customer gives
notice according to the terms of the contract that it will no longer
purchase all or a part of its requirements from the selling utility,
we would not allow the utility to amend the contract to add a
stranded cost provision. However, in such a case, the utility could
seek to recover stranded costs through its rates for transmission
services to the customer. As discussed in Section IV.J.8, the
utility would have to rebut the presumption that, based on the
presence of the notice provision, it had no reasonable expectation
of continuing to serve the customer.
---------------------------------------------------------------------------
We reaffirm our desire that utilities attempt to renegotiate with
their customers existing requirements contracts that do not contain
exit fees or other explicit stranded cost provisions. If the parties
negotiate a stranded cost provision and the seller is A public utility,
the utility must file the provision with the Commission as an amendment
to the existing requirements contract.
If an existing requirements contract does not contain an exit fee
or other explicit stranded cost provision (and is not renegotiated to
add such a provision), before the expiration of the contract: (1) a
public utility or its customer may file a proposed stranded cost
amendment to the contract under section 205 or 206; or (2) a public
utility in a section 205 proceeding, or a transmitting utility in a
section 211 proceeding, may file a proposal to recover stranded costs
associated with any such existing contract through its transmission
rates for a customer that uses the utility's transmission system to
reach another generation supplier.
We thus reaffirm that if an existing requirements contract is not
renegotiated, and the contract permits the seller and/or buyer to seek
an amendment to the contract, the authorized party may seek an
amendment to add a stranded cost provision. We also adopt our
preliminary finding that, even if an existing requirements contract
contains an explicit Mobile-Sierra provision, it is in the public
interest to permit the public utility to seek a unilateral amendment to
add stranded cost provisions if the contract does not already contain
exit fees or other explicit stranded cost provisions. In the initial
Stranded Cost NOPR, we identified two ways in which a failure to permit
public utilities to address stranded costs could harm third parties,
and thereby harm the public interest:
First, the inability to seek recovery of stranded costs could
impair the financial ability of a utility to continue to provide
reliable service. This will depend on the magnitude of stranded
costs and the prospect or lack thereof for recovering such costs
from ratepayers. The prospect of not recovering from ratepayers
significant amounts of stranded costs could seriously erode a
utility's access to capital markets, or could drive the utility's
cost of capital to unprecedented levels. This high cost of capital
could precipitate other customers leaving the system which, in turn,
could cause others to leave. Such a spiral could be difficult to
stop once begun. Second, if some customers are permitted to leave
their suppliers without paying for stranded costs, this may cause an
excessive burden on the remaining customers who, for whatever
reason, cannot leave and therefore may have to bear those
costs.680
\680\ FERC Stats. & Regs. para. 32,507 at 32,870.
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The financial community commenters confirm our views in this
regard. As they note, a utility's access to financial markets is
essential to the continued provision of safe and reliable electric
service to customers. However, the prospect of a utility not recovering
stranded costs could erode a utility's ability to attract capital and
thus imperil its continued financial stability.681 As these and
other commenters agree, the recovery of stranded costs is critical to
the successful transition to more competitive markets.
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\681\ See Utility Investors Analysts, Initial Comments at 2-3;
Utility Shareholders, Initial Comments at 2-4.
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Moreover, our determination that it is in the public interest to
give public utilities a limited opportunity to propose contract changes
unilaterally to address stranded costs if their contracts do not
already explicitly do so satisfies the public interest standard of the
Mobile-Sierra doctrine as recently interpreted by the Northeast
Utilities court. In that case, the court affirmed an order of the
Commission on remand modifying a contract under the Mobile-Sierra
public interest standard.682 As the court explained, the Mobile-
Sierra doctrine ``represents the Supreme Court's attempt to strike a
balance between private contractual rights and the regulatory power to
modify contracts when necessary to protect the public interest.''
683 The court noted that when the Commission is considering
whether a contract rate is too low, protective action by the Commission
in the public interest is justified ``where the rate might impair the
financial ability of the utility to continue to supply electricity,
force electricity consumers to bear an excessive burden, or be unduly
discriminatory.'' 684
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\682\ The court concluded that the Commission ``gave thoughtful
consideration to the public interest.'' 55 F.3d at 693.
\683\ Id. at 689.
\684\ Id. at 690.
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The court also explained that ``the most attractive case for
affording additional protection [under the public interest standard],
despite the presence of a contract, is where the protection is intended
to safeguard the interests of third parties * * *.' '' 685 It
stated that the Mobile-Sierra doctrine allows the Commission to modify
the terms of a private contract ``when third parties are threatened by
possible `undu[e] discrimination' or the imposition of an `excessive
burden.' '' 686 The court found that the Commission had met the
public interest standard by showing how the contract could harm third
parties.687
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\685\ Id. at 691, citing Northeast Utilities Service Company v.
FERC, 993 F.2d 937, 961 (1st Cir. 1993).
\686\ Northeast Utilities, 55 F.3d at 691. The court
distinguished the facts of that case from other Mobile-Sierra cases.
It noted that ``[t]he issue here is not whether one party to a rate
contract filed with FERC can effect a rate change unilaterally, but
the standard to be used by FERC in examining electric power
contracts filed with it.'' Id. at 690-91. It also noted that the
contract provisions under review were not low-rate issues in the
context of Mobile and Sierra. We recognize that whether a contract
should be modified to add a stranded cost provision could be viewed
as one party to a contract seeking to effect a unilateral rate
change, or as a low-rate issue (i.e., whether the utility's rates
would be insufficient without stranded cost recovery). However,
parties are being permitted to make such unilateral filings only
after a generic finding by the Commission that the public interest
likely would be jeopardized if utilities are not permitted to make a
case-specific showing that recovery should be allowed. We believe
that Northeast Utilities provides valuable guidance concerning
application of the public interest standard where, as here, a
failure to allow limited contract modification may harm the public
interest by harming third parties.
\687\ The court found that the Commission had met the public
interest standard ``by explaining how the disputed contractual terms
may harm third parties to the contract. * * * For example, the
Commission found the automatic rate-of-return-on-equity adjustment
provision unacceptable because third parties may ultimately bear the
burden of a rate component that does not reflect actual capital
market conditions. Likewise, the `blank check' given owners of the
power plant to determine the decommissioning costs for themselves
under New Hampshire law is impermissible because it may be cashed at
the expense of non-parties to the contract.'' Id. at 692 (emphasis
in original). The court rejected the argument that the public
interest standard is ``practically insurmountable'' in all
circumstances. It noted, among other things, ``that neither Mobile
nor Sierra stated or intimated that the `public interest' doctrine
was `practically insurmountable.' '' Id. at 691.
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Consistent with the holding in Northeast Utilities, and contrary to
the positions of some commenters, we have demonstrated how ``third
parties may ultimately bear the burden'' 688 if public utilities
with Mobile-Sierra contracts are not given any opportunity to propose
contract changes to address stranded costs. If the Commission fails to
give a
[[Page 21643]]
public utility this opportunity, and the utility's financial ability to
continue the provision of safe and reliable service is impaired, third
parties (customers relying on the public utility for their electric
service) will be placed at risk. Similarly, if the Commission fails to
give a public utility the opportunity to directly assign costs to the
customers on whose behalf they were incurred, and some of the utility's
customers leave the utility's generation system for that of another
supplier without paying such costs, third parties (the utility's
remaining customers) will be harmed by having to bear the costs that
were not incurred to serve them and that are stranded by the other
customers' departures via open access transmission. Moreover, we
believe that protective action in the public interest is particularly
necessary where, as here, a utility's rates could become insufficient
because of fundamental changes in the industry that largely result from
legislative or regulatory changes that could not be anticipated.
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\688\ Id. at 692 (emphasis in original).
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Further, notwithstanding the arguments of some commenters
supporting a case-by-case (as opposed to a generic) public interest
finding, we believe it appropriate that our public interest finding be
made on a generic basis given the fact that, by this Rule, we are
requiring full open access that could significantly affect historical
relationships among traditional utilities and their customers and the
ability of utilities to recover prudently incurred costs. We also
emphasize that we are not eliminating the need for case-by-case
demonstrations that stranded cost recovery should be allowed. Our
public interest finding is that utilities be permitted to seek extra-
contractual recovery of stranded costs in certain defined
circumstances. Utilities seeking recovery of stranded costs will have
the burden, on a case-by-case basis, of showing they had a reasonable
expectation of continuing to serve the departing generation customer.
In summary, we emphasize the limited nature of our Mobile-Sierra
public interest finding. First, our holding applies only to wholesale
requirements contracts executed on or before July 11, 1994 that do not
contain an exit fee or other explicit stranded cost provision. Thus, we
will not permit modification of any contract that addresses the
stranded cost issue explicitly, unless the contract specifically
permits such modifications. Instead, we are simply examining
requirements contracts that do not clearly address the issue in the
context of the traditional regulatory regime under which they were
signed--a regulatory environment in which it was assumed as a matter of
course that the great majority of requirements customers would stay
with their original suppliers and that these suppliers had a
concomitant obligation to plan to supply these customers' continuing
needs.
Second, although we have decided on a generic basis that it is in
the public interest to permit public utilities with Mobile-Sierra
contracts to make unilateral filings, we are not automatically
approving any amendment that a particular utility might file. As we
stated in the initial Stranded Cost NOPR, if a public utility
unilaterally files a proposed stranded cost amendment under either
section 205 or 206 of the FPA, this does not necessarily mean that the
Commission ultimately will find it appropriate to allow such
amendment.689 In addition, customers with Mobile-Sierra contracts
that do not explicitly address stranded costs may also file complaints
under section 206 of the FPA to propose to address stranded costs in
existing requirements contracts. The Commission will analyze any
proposed stranded cost amendment to a Mobile-Sierra contract, whether
proposed by the utility or by its customer, based on the particular
circumstances surrounding that contract. Thus, the case-by-case
findings that some commenters seek will, in effect, be made when the
Commission determines whether to approve a proposed stranded cost
amendment to a particular contract.
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\689\ FERC Stats. & Regs. para. 32,507 at 32,871.
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As discussed in Section IV.A (Scope), the Commission has concluded
that although current conditions in the wholesale power market do not
warrant the generic modification of requirements contracts, nonetheless
the modification of certain requirements contracts on a case-by-case
basis may be appropriate. We have concluded further that, even if
customers under such contracts are bound by so-called Mobile-Sierra
clauses, they nonetheless ought to have the opportunity to demonstrate
that their contracts no longer are just and reasonable.
We have found that it would be against the public interest to
permit a Mobile-Sierra clause in an existing wholesale requirements
contract to preclude the parties to such a contract from the
opportunity to realize the benefits of the competitive wholesale power
markets. For purposes of this finding, the Commission defines existing
requirements contracts as contracts executed on or before July 11,
1994.690 By operation of this finding, a party to a requirements
contract containing a Mobile-Sierra clause no longer will have the
burden of establishing independently that it is in the public interest
to permit the modification of such contract. The party, however, still
will have the burden of establishing that such contract no longer is
just and reasonable and therefore ought to be modified.
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\690\ This is consistent with the definition of existing
requirements contracts we have used for purposes of stranded cost
recovery.
---------------------------------------------------------------------------
This finding complements the Commission's finding that,
notwithstanding a Mobile-Sierra clause in an existing requirements
contract, it is in the public interest to permit amendments to add
stranded cost provisions to such contracts if the public utility
proposing the amendment can meet the evidentiary requirements of this
Rule. The Commission's complementary Mobile-Sierra findings are not
mutually exclusive. Any contract modification approved under this
section shall provide for the utility's recovery of any costs stranded
consistent with the contract modification. The stranded costs must be
prudently incurred, legitimate and verifiable. Further, the Commission
has concluded that if a customer is permitted to argue for modification
of existing contracts that are less favorable to it than other
generation alternatives, then the utility should be able to seek
modification of contracts that may be beneficial to the customer.
The Commission believes that the most productive way to analyze
contract modification issues is to consider simultaneously both the
selling public utility's claims, if any, that it had a reasonable
expectation of continuing to serve the customer beyond the term of the
contract and the customer's claim, if any, that the contract no longer
is just and reasonable and therefore ought to be modified. Thus, if the
selling public utility intends to claim stranded costs, it must present
that claim in any section 206 proceeding brought by the customer to
shorten or terminate the contract. Similarly, if the customer intends
to claim that the notice or termination provision of its existing
requirements contract is unjust and unreasonable, it must present that
claim in any proceeding brought by the selling public utility to seek
recovery of stranded costs. This will promote administrative efficiency
and will permit the Commission to consider how the contracting parties'
claims bear on one another.
[[Page 21644]]
The Commission does not take contract modification lightly. Whether
a utility is seeking a contract amendment to permit stranded cost
recovery based on expectations beyond the stated term of the contract,
or a customer is seeking to shorten or eliminate the term of an
existing contract, we believe that each have a heavy burden in
demonstrating that the contract ought to be modified. Still, we believe
that given the industry circumstances now facing us, both selling
utilities and their customers ought to have an opportunity to make the
case that their existing requirements contracts ought to be modified.
By providing both buyers and sellers this opportunity, the Commission
attempts to strike a reasonable balance of the interests of all market
participants. The Commission expects that many of the arguments
presented by buyers and sellers in such proceedings will be fact
specific.
c. Transition Period
We reaffirm our proposal to allow a public utility or its customer
to file a proposed stranded cost amendment, or to allow a public
utility or transmitting utility to file a proposal to recover stranded
costs through a departing generation customer's transmission rates, at
any time prior to the expiration of the contract. There is no uniform
time remaining on requirements contracts executed on or before July 11,
1994. Any limitation on the period in which parties could propose
amendments covering stranded costs (e.g., 3 years) would thus unequally
affect market participants. Those with long terms remaining on their
contracts could object that immediately addressing the issue would not
be cost effective. For example, a utility with a long remaining term
(e.g., 20 years) might not even seek stranded cost recovery depending
on the competitive value of its assets near the end of the contract
term.691 However, such a utility would invariably seek to preserve
its option to seek stranded cost recovery if its failure to do so
within a short period resulted in a waiver of its right to do so.
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\691\ The value of its assets could vary over time as new
technologies emerge, fuel costs fluctuate, or environmental
requirements change.
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6. Recovery of Stranded Costs Caused by Retail-Turned-Wholesale
Customers
In the Supplemental Stranded Cost NOPR, we stated that both this
Commission and state commissions have the legal authority to address
stranded costs that result from retail customers becoming wholesale
customers who then obtain transmission under the open access
tariffs.692 We proposed that this Commission should be the primary
forum for addressing the recovery of stranded costs caused by retail-
turned-wholesale customers. We explained that if a retail customer
becomes a legitimate wholesale customer (such as through
municipalization), it becomes eligible to use the non-discriminatory
open access tariffs:
\692\ FERC Stats. & Regs. para. 32,514 at 33,127.
---------------------------------------------------------------------------
If costs are stranded as a result of this wholesale transmission
access, we believe that these costs should be viewed as `wholesale
stranded costs.' But for the ability of the new wholesale entity to
reach another generation supplier through the FERC-filed open access
transmission tariff, such costs would not be stranded.693
\693\ Id. at 33,128.
---------------------------------------------------------------------------
We accordingly proposed to define ``wholesale stranded costs'' to
include stranded costs resulting from unbundled transmission for newly-
created wholesale customers and sought comments on this definition.
We proposed to require the same evidentiary demonstration for
recovery as that required if recovery were sought from a wholesale
requirements customer. We reaffirmed our proposal in the initial
Stranded Cost NOPR that a utility will have to show that the stranded
costs are not more than the net revenues that the retail-turned-
wholesale customer would have contributed to the utility had it
remained a retail customer of the utility, and that the utility has
taken and will take reasonable steps to mitigate stranded costs. We
further proposed to deduct any recovery that a state has permitted from
departing retail-turned-wholesale customers from the legitimate
stranded costs of which we will allow recovery. In addition, we
proposed to apply the same procedures for obtaining an estimate of
maximum stranded cost exposure without mitigation to retail customers
contemplating becoming wholesale transmission customers as those
proposed for wholesale customers.694
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\694\ Id.
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Comments
Some commenters contend that stranded costs that result when a
retail customer becomes a wholesale customer should be left to the
states as a matter of law and comity.695 These commenters argue,
among other things, that because the facilities used to provide retail
service to these retail customers were subject to state jurisdiction
and were included in retail rate base when the service was rendered,
the state is the appropriate entity to determine the extent to which
those customers should compensate the utility for the stranding of
these costs. According to ELCON, ``(a) retail customer's new found
access to the wholesale market does not provide FERC with authority
over costs that originated with the local distribution function.''
696
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\695\ E.g., NARUC, ELCON, TAPS, NASUCA, N.Y. Mayors, NY
Industrials, American Iron & Steel, Missouri Joint Commission, Omaha
PPD, MI Com, NY Com, NJ BPU, VT DPS, OK Com, IN Com, UT Com, WA Com,
Environmental Action, IN Industrials, LA DWP, Seattle, CAMU, Las
Cruces, UT Industrials, Suffolk County, NM Industrials, CO Consumers
Counsel.
\696\ ELCON Comments, dated July 25, 1995, at 41.
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Commenters assert that stranded costs resulting from the creation
of new wholesale entities will occur as a result of state or local
decisionmaking.697 A number of commenters contend that in states
where the state commission has control over municipalization, the
Commission has no authority to provide for the recovery of stranded
costs due to municipalization.698 IL Com asserts that the
Commission lacks authority over retail-turned-wholesale stranded costs,
even in the absence of any explicit statutory authority for state
commissions to address such costs. FL Com argues that the Commission
should address the recovery of these stranded costs only upon petition
from a state public utility commission.
---------------------------------------------------------------------------
\697\ E.g., MD Com, MI Com, LA DWP, Las Cruces. For example, MD
Com states that while open access transmission may make
municipalization more attractive, it ultimately is MD Com's approval
that makes municipalization possible in Maryland.
\698\ E.g., MD Com, Las Cruces, Caparo, Coalition on Federal-
State Issues, IN Com, MI Com, Iowa Board.
---------------------------------------------------------------------------
According to some commenters, the availability of open access
transmission tariffs does not convert the character of the costs of
stranded generation that was built to serve retail customers from
retail to wholesale.699 CA Com argues that this reasoning could
require the Commission to act as the primary forum for stranded costs
resulting from retail wheeling if the Commission's jurisdiction over
retail transmission is upheld. It argues that in such a case, there
also would be a relationship between the Commission-jurisdictional
transmission and stranded costs.
---------------------------------------------------------------------------
\699\ E.g., IL Com, CA Com, Midwest Commissions, CO Consumers
Counsel.
---------------------------------------------------------------------------
Some commenters also submit that the potential for retail customers
to become wholesale customers has existed since the beginning of the
industry and that utilities have had ample opportunity to adjust to
this risk.700 A number of commenters submit
[[Page 21645]]
that state commissions are in a better position than the Commission to
address the recovery of costs that were incurred to serve retail
customers and to take into consideration local concerns.701
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\700\ E.g., LA DWP, Ohio Manufacturers, MMWEC, American Iron &
Steel, UT Industrials, MI Com, NY Industrials, WA Com, Caparo.
\701\ E.g., American Iron & Steel, MD Com, LA DWP, Suffolk
County, MI Com, NJ BPU, N.Y. Mayors. NASUCA cites practical problems
posed by the Commission's proposal to assume jurisdiction over
stranded costs resulting from municipalization, such as how the
Commission would transfer the revenues extracted from the retail-
turned-wholesale customer to a non-wholesale, locally-franchised
entity.
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NARUC recognizes that a ``practical regulatory gap may exist that
prevents [state commission] consideration of recovery of * * *
potentially stranded costs'' in certain instances ``such as
municipalization and cooperatives, where retail customers become
wholesale customers under a FERC-approved open access tariff, [and]
costs of the utility which served the customer at retail may become
stranded.'' 702 NARUC proposes that the affected states and the
Commission collaboratively develop mechanisms (which may involve
amendments to the FPA, state statutes, or both) to eliminate these
regulatory gaps.
---------------------------------------------------------------------------
\702\ NARUC Initial Comments at 18-19.
---------------------------------------------------------------------------
Some commenters object that the Commission's proposal to be the
primary forum for recovery of stranded costs caused by retail-turned-
wholesale customers would make municipalization more expensive and
therefore would discourage municipalities from seeking alternative
sources of electricity.703 Some argue that different treatment of
stranded costs between federal and state authorities may lead to forum-
shopping as a primary determinant in the decision to
municipalize.704
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\703\ E.g., N.Y. Mayors, NIEP, Wing Group, VT DPS, NY
Industrials, American Iron & Steel, Environmental Action, IN
Industrials, Las Cruces, Caparo, UT Industrials.
\704\ E.g., IN Com.
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A number of commenters also suggest that the NOPR is inconsistent
with prior Commission treatment of municipalization because the
Commission has historically promoted franchise competition between
municipalities and utilities and has never before suggested that
utilities could ``penalize'' municipalization decisions through
generation cost add-ons to transmission rates.705 VT DPS states:
``By the Commission's logic, there would never have been an Otter Tail
case. If Otter Tail could have made a stranded cost claim against the
municipal utility Elbow Lake planned to create, Otter Tail would never
have needed to refuse to wheel.'' 706
---------------------------------------------------------------------------
\705\ E.g., VT DPS, American Iron & Steel. American Forest &
Paper states that allowing stranded cost recovery in the event of
municipalization would be inconsistent with the Commission's actions
in the natural gas industry, where the Commission has encouraged
competition at the retail level (through competitive bypass rather
than franchise competition) and has not imposed transition charges
or exit fees on converting customers.
\706\ VT DPS Initial Comments at 49; see also American Iron &
Steel, NY Industrials, Caparo.
---------------------------------------------------------------------------
Suffolk County states that the Commission already considered
stranded costs in the context of retail-turned-wholesale customers in
United Illuminating Company,707 where the Commission required
United Illuminating to remove a provision in its proposed transmission
tariff that would have allowed it to recover stranded costs associated
with former retail loads served by new municipal systems. Suffolk
County states that the Commission made clear that stranded cost
matters, including those caused by municipalization, properly would be
raised before state regulatory authorities. It objects that the Open
Access NOPR ignores this case. Suffolk County also submits that the
Commission's adoption of the settlement approved by the Massachusetts
DPU in the Massachusetts Bay Transportation Authority case should serve
as an example of proper jurisdictional deference with respect to local
issues.708
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\707\ 63 FERC para. 61,212 (1993), reh'g denied, 64 FERC para.
61,087 (1993).
\708\ See Massachusetts Electric Company, 68 FERC para. 61,101
(1994); Letter Order dated March 3, 1995, Docket No. ER94-129-000
(approving settlement).
---------------------------------------------------------------------------
However, many other commenters support the Commission's proposal to
be the primary forum for retail-turned-wholesale stranded
costs.709 These commenters submit, among other things, that the
Commission's jurisdiction over such costs is clear.710 Coalition
for Economic Competition states that when a utility's costs are
stranded through the availability of Commission-jurisdictional
transmission service, the Commission must address those costs. It
argues that commenters opposing the Commission's jurisdiction fail to
analyze the Commission's duty to establish just and reasonable rates
for Commission-jurisdictional transmission service.
---------------------------------------------------------------------------
\709\ E.g., EEI, PSE&G, Centerior, Com Ed, Consumers Power,
Detroit Edison, Duke, El Paso, Entergy, LILCO, Minnesota Power,
Montana-Dakota Utilities, NYSEG, PECO, PG&E, PSNM, Southern,
Utilities For Improved Transition, Allegheny, OH Com, Utilicorp, PA
Com, WI Com, Coalition for Economic Competition, Central Louisiana,
United Illuminating, Utility Investors Analysts, Nuclear Energy
Institute, Utility Shareholders.
\710\ E.g., Consumers Power, Coalition for Economic Competition,
Utilities For Improved Transition.
---------------------------------------------------------------------------
A number of commenters support the Commission's proposal to address
retail-turned-wholesale stranded costs on the basis that many state
commissions either lack authority to address costs that are stranded
because of expanding or newly-created municipal systems, or have failed
to address such costs.711 El Paso adds that any protection offered
by state judicial condemnation proceedings does not obviate the need
for the Commission's involvement in this issue, noting that
condemnation awards may not provide full stranded investment recovery
under the Commission's standards. In addition, El Paso suggests that
municipalization may occur through means other than condemnation of the
distribution systems of electric utilities, such as when a municipality
constructs its own, duplicative distribution facilities.
---------------------------------------------------------------------------
\711\ E.g., Detroit Edison, Minnesota Power, El Paso, LILCO,
Centerior, PG&E. PG&E urges a clarification in the rule so that the
Commission would address retail-turned-wholesale stranded costs only
if the state commission either lacks jurisdiction over municipal
utilities, or, if it has jurisdiction, declines to address stranded
costs. Where a state commission possesses jurisdiction over
municipal entities and provides a utility with stranded cost
recovery from former retail customers that have municipalized, PG&E
proposes that such action should be final and not subject to
Commission review. Other commenters, such as El Paso, ask the
Commission to establish itself as the forum of last resort when
states do not provide for full recovery of stranded costs.
---------------------------------------------------------------------------
Several commenters also indicate that by forthrightly addressing
this issue, the Commission has removed a cloud of uncertainty that
would have taken years to resolve through litigation.712 El Paso
states that the proposed rule is needed because utilities may be
subject to stranded costs resulting from municipalization in two
separate state jurisdictions.
---------------------------------------------------------------------------
\712\ E.g., Coalition for Economic Competition, El Paso.
---------------------
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
------------------------------------------------------
In response to the argument that stranded costs are exclusively
subject to state jurisdiction, SoCal Edison asserts that whether the
costs are retail or wholesale is irrelevant because the issue is how
and where these costs should be recovered. According to SoCal Edison,
if the Commission finds that these costs are just and reasonable costs
associated with providing open access transmission service, the
Commission may allow utilities to recover them in Commission-regulated
rates.
Coalition for Economic Competition notes that while utilities are
aware of state laws allowing municipalities to condemn electric
facilities and to form utilities, in recent decades, it has not
happened on most systems. Moreover, it argues that merely being on
notice that municipalization is a possibility does not relieve
utilities of their state-imposed obligation to serve all
[[Page 21646]]
customers in their franchise areas. It asserts that utilities had to
continue to invest in plant to satisfy their duty to serve. In
addition, it submits that utilities had a reasonable expectation that
they would continue to serve retail load because, among other things,
state regulators set long amortization periods of 30-40 years for
depreciation rates.
Some commenters state that the Commission also should ensure that
stranded costs are recovered when a municipal utility annexes territory
served by another utility or otherwise expands its service
territory.713 A number of commenters also urge the Commission to
ensure recovery of costs that are stranded if a municipal utility or a
newly-formed wholesale or municipal utility physically interconnects to
another utility or builds new transmission or distribution facilities
to the municipal system.714
---------------------------------------------------------------------------
\713\ E.g., EEI, Minnesota Power, Centerior, Public Service Co
of CO, SoCal Edison, Coalition for Economic Competition. PG&E asks
that we allow utilities to seek recovery at the Commission for
stranded costs attributable to former retail customers that have
become customers of existing public agencies or municipal utilities
where such costs cannot be collected at the state level.
\714\ E.g., Centerior, Coalition for Economic Competition, PG&E.
Coalition for Economic Competition proposes that the Commission
accept just and reasonable regional stranded cost recovery
mechanisms in such situations to enable regional transmission
associations (whether through pool and interpool arrangements or
regional transmission groups) to collect through Commission-filed
rate schedules from interconnected utilities charges equal to the
costs otherwise stranded as a result of Commission-jurisdictional
service realignments.
---------------------------------------------------------------------------
Several commenters believe that close coordination between the
Commission and state regulators as to the calculation of stranded costs
is important in the case of municipalization.715 A number of state
commissions suggest that the Commission allow the states to set the
level of retail-turned-wholesale stranded costs to be recovered in
wholesale transmission rates set by the Commission.716 They submit
that this approach would respect state interests in controlling the
rate impact of stranded costs, while allowing the Commission to design
cost recovery, and would address the needs of industrial customers and
other stakeholders by providing a forum before state regulators who
will be more aware of their particular needs. Further, they contend
that this approach would prevent relitigation of issues, minimize
forum-shopping, and prevent legitimate and verifiable costs from
falling through the cracks or being double-recovered.717 NY
Industrials asks the Commission to clarify that utilities will not be
allowed to seek cost recovery at both the Commission and state
commissions.
---------------------------------------------------------------------------
\715\ E.g., SoCal Edison, OH Com, NY Com, MI Com, Coalition on
Federal-State Issues.
\716\ E.g., MI Com, NY Com, Ohio Com.
\717\ PG&E proposes a similar approach, noting that if there are
differences in the stranded cost method used by the Commission and
the states, an incentive may remain for retail customers to
municipalize merely to take advantage of more favorable stranded
cost treatment at the Commission.
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Commission Conclusion
We reaffirm our preliminary determination that this Commission
should be the primary forum for addressing the recovery of stranded
costs caused by retail-turned-wholesale customers. If such a customer
is able to reach a new generation supplier because of the new open
access (through the use of a FERC-filed open access transmission tariff
or through transmission services ordered pursuant to section 211 of the
FPA), we believe that any costs stranded as a result of this wholesale
transmission access should be viewed as ``wholesale stranded costs.''
Such costs would not be stranded but for the action of this Commission
(either through a mandatory FPA section 205-206 open access tariff or
an order under FPA section 211) in permitting the new wholesale entity
to become an unbundled transmission services customer of the utility
and thereby to obtain power from a new supplier.718 There is a
clear nexus between the FERC-jurisdictional transmission access
requirement and the exposure to non-recovery of prudently incurred
costs. In these circumstances, we believe that this Commission should
be the primary forum for addressing recovery of such costs. To avoid
forum-shopping and duplicative litigation of the issue, we expect
parties to raise claims before this Commission in the first
instance.719
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\718\ Costs that are exposed to nonrecovery when a retail
customer or a newly-created wholesale power sales customer ceases to
purchase power from the utility and does not use the utility's
transmission system to reach a new generation supplier (e.g.,
through self-generation or use of another utility's transmission
system) do not meet the definition of ``wholesale stranded costs''
for which this rule provides an opportunity for recovery. Such costs
are outside the scope of this rule because such costs would not be
stranded as a result of the new open access. See Section IV.J.12.
\719\ We recognize that we took a different approach to retail-
turned-wholesale stranded cost recovery in United Illuminating,
where we suggested that state and local regulatory authorities or
the courts should be able to provide an adequate forum to address
retail franchise matters, including recovery of stranded costs
caused by municipalization, but said we would consider revisiting
the question if United Illuminating could demonstrate the lack of a
forum. 63 FERC at 62,583-84. Since the issuance of that decision,
however, we have had an opportunity to re-analyze the nature of the
stranded cost problem in cases where a retail customer becomes a
wholesale customer, including the potential that there might not be
a state regulatory forum for recovery of such costs. In these
circumstances, we have determined that where such costs are stranded
as a result of wholesale open access transmission, these costs
should be viewed as wholesale stranded costs and this Commission
should be the primary forum for addressing their recovery.
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Some commenters have asked us also to be the primary forum for
stranded cost recovery in situations in which an existing municipal
utility annexes territory served by another utility or otherwise
expands its service territory. We decline to do so because in these
situations there is no direct nexus between the FERC-jurisdictional
transmission access requirement and the exposure to non-recovery of
prudently incurred costs. The risk of an existing municipal utility
expanding its territory was a risk prior to the Energy Policy Act and
prior to any open access requirement.
Nevertheless, we are concerned that there may be circumstances in
which customers and/or utilities could attempt, through indirect use of
open access transmission, to circumvent the ability of any regulatory
commission--either this Commission or state commissions--to address
recovery of stranded costs.720 We reserve the right to address
such situations on a case-by-case basis.
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\720\ The CA Com has asked that, ``(t)o the extent of FERC's
authority, it should assume jurisdiction to fulfill a backstop role
in case retail customers evade a state-determined transition charge
by becoming retail customers of an entity not subject to the state
regulatory commission's jurisdiction. In assuming jurisdiction, the
Commission should defer to the state commission's determination and
allocation of stranded costs for the departing retail customer.'' CA
Com March 18, 1996 Response to Supplemental Comments of PG&E.
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As we indicated in the Supplemental Stranded Cost NOPR, if the
state has permitted any recovery from departing retail-turned-wholesale
customers (for example, if it imposed an exit fee prior to, or as a
condition of, creating the wholesale entity), that amount will not, in
fact, be stranded, and we will deduct that amount from the legitimate
stranded costs for which we will allow recovery.
As discussed in Sections IV.J.8-IV.J.9, we will require the same
evidentiary demonstration for recovery of stranded costs from a retail-
turned-wholesale customer, and will apply the same procedures for
determining stranded cost obligation, as that required in the case of a
wholesale requirements customer.
[[Page 21647]]
7. Recovery of Stranded Costs Caused by Retail Wheeling
In the Supplemental Stranded Cost NOPR, we stated that both this
Commission and state commissions have the legal authority to address
stranded costs that result from retail customers who obtain retail
wheeling from public utilities in order to reach a different
generation supplier.721 Because the vast majority of commenters
urged the Commission not to assume responsibility for retail
stranded costs, except in certain circumstances, we preliminarily
concluded that it is appropriate to leave it to state regulatory
authorities to deal with any stranded costs occasioned by retail
wheeling. We proposed to entertain requests to recover stranded
costs caused by retail wheeling only when the state regulatory
authority does not have authority under state law to address
stranded costs at the time when the retail wheeling is
required.722 In so doing, we preliminarily accepted the view
that stranded costs caused by retail wheeling are primarily a matter
of local or state concern and thus, with the limited exception
discussed above, generally must be recovered through retail charges.
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\721\ As discussed in Section IV.I, the Commission's authority
to address retail stranded costs derives from its jurisdiction over
the rates, terms and conditions of unbundled transmission in
interstate commerce used by retail customers that obtain retail
wheeling. The states' authority derives from state jurisdiction over
local distribution facilities and over the service of delivering
electric energy to end users, and from the authority to impose,
among other things, retail exit fees and surcharges on local
distribution rates.
\722\ We proposed to require the same evidentiary demonstration
for recovery of stranded costs from a retail customer that obtains
retail wheeling as that required in the case of a wholesale
requirements customer. We also reaffirmed our proposal in the
initial Stranded Cost NOPR that a utility will have to show that the
stranded costs are not more than the net revenues that the retail
customer would have contributed to the utility had it remained a
retail customer of the utility, and that the utility has taken and
will take reasonable steps to mitigate stranded costs. FERC Stats. &
Regs. para. 32,514 at 33,128.
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We noted that the states have a number of mechanisms for addressing
stranded costs caused by retail wheeling, one of which is a surcharge
to state-jurisdictional rates for local distribution.\723\ We
encouraged the states to use the mechanisms available to them to
address stranded costs.724 We also noted that the states may use
their jurisdiction over local distribution facilities to address
``stranded benefits,'' such as environmental benefits associated with
conservation, load management, and other demand side management
programs.725
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\723\ As we noted in the Supplemental NOPR, a state may require
payment of an exit fee before a franchise customer is permitted to
obtain unbundled retail wheeling. If local distribution facilities
are used by a retail wheeling customer, the state may allow recovery
of stranded costs through rates for use of such local distribution
facilities. In addition, as discussed in Section IV.I, because we
believe that states have authority over the service of delivering
electric energy to end users, not merely the local distribution
facilities themselves, state authorities can assign stranded costs
and benefits through a local distribution service charge, and may do
so based on usage (kWh), demand (kW), or any combination or method
they find appropriate. If a state decides not to take any of these
routes, it may consider whether to allow recovery of stranded costs
from remaining retail customers or whether shareholders should bear
all or part of those costs. Id. at 33,129.
\724\ Id. at 33,129-30.
\725\ Id. at 33,098 n. 230.
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Comments
A number of commenters support the Commission's proposal for
addressing stranded costs caused by retail wheeling.726
---------------------------------------------------------------------------
\726\ E.g., Utilicorp, Houston L&P, PG&E, Freedom Energy Co, WI
Com.
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Other commenters urge the Commission to take a greater role in
retail stranded cost recovery and to entertain requests to recover
stranded costs as a backstop where: (1) State regulatory authorities
have the authority to address stranded costs but either choose not to
exercise that authority or fail to permit full stranded cost recovery;
727 or (2) the state commission's authority is unclear.728
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\727\ E.g., EEI, EGA, Coalition for Economic Competition,
Utilities for Improved Transition, Atlantic City, Arizona,
Centerior, Com Ed, Detroit Edison, El Paso, LILCO, NU, NSP, NYSEG,
United Illuminating, BG&E, Sierra, Southern, UT Industrials, NRECA.
NRECA argues that unless the Commission addresses stranded costs
caused by retail wheeling where a state commission lacks authority,
or has authority but decides not to exercise it, there could be a
jurisdictional gap into which many rural electric cooperatives could
fall.
\728\ E.g., CSW.
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Commenters that support a greater Commission backstop role argue,
among other things, that because the Commission has exclusive
ratemaking jurisdiction over any stranded cost charges imposed ``for or
in connection with'' interstate transmission service by public
utilities, the Commission has an obligation to regulate the recovery of
stranded costs from interstate retail transmission customers.729 A
number of these commenters argue that the determining factor is who has
the jurisdiction to review the rates for the service, not who has the
jurisdiction to order the service.730 They explain that the
Commission has jurisdiction over generating facilities and associated
costs to the extent appropriate to establish just and reasonable rates
for jurisdictional services. They disagree with other commenters who
argue that only the jurisdiction under whose authority the costs were
incurred and initially recovered should have authority to order
recovery of stranded costs.731
---------------------------------------------------------------------------
\729\ E.g., EEI, Illinois Power, PSNM, Entergy, Nuclear Energy
Institute, Coalition for Economic Competition.
\730\ E.g., Coalition for Economic Competition, Illinois Power,
Utilities for Improved Transition, EEI.
\731\ EEI notes, for example, that as use of electrical
facilities shifts between retail and wholesale, jurisdiction over
the rates to recover the allocated cost of service shifts between
state commissions and this Commission, and that the regulatory
authority is determined by the nature of the transactions and the
classification of the customer, not the jurisdiction under which the
costs originally arose.
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These commenters contend that the Commission cannot abdicate its
regulatory responsibilities by either deferring to the state
commissions or otherwise failing to independently address the
issue.732 EEI and the Coalition for Economic Competition refer to
``a long line of cases (where) the courts have held that where a
federal regulatory agency * * * is charged with implementing a
statutory framework, that agency is without authority to deviate from
or abdicate its statutory responsibilities.'' 733 According to
Coalition for Economic Competition, for example, the Commission could
satisfy its obligation to address stranded costs that arise from retail
wheeling by allowing states to determine retail stranded cost charges
in the first instance; to the extent that the state allows full
recovery, Coalition for Economic Competition submits that the
Commission's obligation would be satisfied.
---------------------------------------------------------------------------
\732\ E.g., Illinois Power, Utilities For Improved Transition,
EEI, Coalition for Economic Competition.
\733\ EEI Initial Comments at IV-13; see also Coalition for
Economic Competition Initial Comments at 23-31.
---------------------------------------------------------------------------
EEI asserts that it would be unduly discriminatory and preferential
for the Commission to refuse to address all stranded costs arising from
retail wheeling. According to EEI, the same arguments that support the
Commission's decision to address costs that are stranded where retail
load municipalizes and where the state regulatory authority, at the
time retail wheeling is required, lacks authority to act, apply with
equal force to all other retail stranded costs. EEI submits that the
nexus in these cases is that Commission-jurisdictional transmission
service is the means by which the costs are stranded.\734\
---------------------------------------------------------------------------
\734\ See also SoCal Edison.
---------------------------------------------------------------------------
Utility Working Group argues that the NOPR inappropriately
characterizes the Commission's jurisdiction over retail stranded costs
and that this could later be used against the Commission's exercise of
its full authority. According to Utility Working Group, the NOPR
depicts the Commission's jurisdiction as
[[Page 21648]]
being derived from state law (in other words, the Commission will act
where state regulatory authorities have no authority over retail
stranded costs and will not act where state regulatory authorities have
such authority). If the Commission desires to afford substantial
deference to the states regarding retail stranded costs, Utility
Working Group contends that the final rule should reflect that policy
determination; however, the rule should not confuse policy with
jurisdiction by purporting to place limits on, or attempting to waive,
the Commission's jurisdiction over such costs.
Entergy asserts that the Commission's jurisdiction over multi-state
utilities provides further support for our jurisdiction over retail
stranded costs in certain contexts. Entergy states that most of the
eleven multi-state registered holding company systems have some form of
Commission-jurisdictional agreement that allocates production and
transmission costs among the systems' affiliated operating companies.
It asserts that these agreements by their very nature allocate costs
among jurisdictions (that is, between states). Many of these agreements
equalize the cost of generating reserves among affiliated operating
companies, and such reserve equalization formulas can shift retail
stranded costs among states unless the Commission provides a regulatory
forum to address cost-shifting. Citing Middle South Energy,735 and
City of New Orleans v. FERC,736 Entergy submits that the
Commission cannot sit on the sidelines when it comes to stranded retail
costs on the Entergy system. According to Entergy, Commission and
judicial precedent place on the Commission the responsibility to ensure
that federally-approved costs and cost allocations are not undermined
by state action.
---------------------------------------------------------------------------
\735\ Opinion 234, 31 FERC para. 61,305, on reh'g, 32 FERC para.
61,425 (1985).
\736\ 875 F.2d 903 (D.C. Cir. 1989), cert. denied sub nom.
Mississippi v. FERC, 494 U.S. 1078 (1990).
---------------------------------------------------------------------------
Commenters also express concern that it will not be possible to be
sure that a state regulatory authority has authority over retail
stranded costs until after years of litigation. If the Commission waits
for the resolution of challenges to state authority and a court holds
that the state regulatory authority is without authority, these
commenters assert that the bar on retroactive ratemaking could leave
the states and the Commission without a remedy to compensate utilities
for stranded costs.\737\ A number of commenters suggest that while the
states should be allowed to set retail wheeling stranded cost charges
in the first instance, the Commission should accept filings to preserve
a utility's ability to recover retail stranded costs from the time the
customer departs if the state-authorized charges are not upheld in
court. They submit that this would put customers on notice of the
potential for Commission action and thereby avoid the retroactivity
problem.738
---------------------------------------------------------------------------
\737\ E.g., NU, Coalition for Economic Competition, Illinois
Power, EEI.
\738\ E.g., NEPCO, EEI, Coalition for Economic Competition,
Entergy.
---------------------------------------------------------------------------
Some commenters express concern that if the Commission does not
take more decisive action on retail wheeling stranded costs, the result
will be wasteful litigation that will discourage competition by causing
financial uncertainty and higher financing costs for investor-owned
utilities and higher rates for consumers.739 Coalition for
Economic Competition also asserts that stranded cost charges would be
greatest at the start of a retail wheeling program, thereby making the
years during which the state-authorized charges are subject to appeal
more important for recovery purposes.
---------------------------------------------------------------------------
\739\ E.g., LILCO, Coalition for Economic Competition.
---------------------------------------------------------------------------
A number of commenters support Commission-established uniform
standards for, and uniform recovery of, costs stranded as a result of
open access to the interstate transmission system.740 They argue
that disparate state treatment of stranded costs would be economically
inefficient and discriminatory and would burden interstate
commerce.741 Several commenters support state involvement in the
establishment of uniform standards.742
---------------------------------------------------------------------------
\740\ E.g., NU, NSP, Illinois Power, Coalition for Economic
competition, PSE&G, Utilities For Improved Transition, Philip
Morris, EEI.
\741\ Freedom Energy Co. rejects this argument on the basis that
state regulation has never been wholly consistent and yet utilities
have not asked for federal unification of state ratemaking policies
or resolution of differences.
\742\ E.g., PSNM, GA Com, Omaha PPD, Illinois Power.
---------------------------------------------------------------------------
In contrast to the commenters that support a greater Commission
role in retail stranded cost recovery, NARUC and a number of other
commenters oppose any Commission involvement in retail stranded
costs.743 These commenters contend, among other things, that the
Commission lacks authority over these costs. Even if the Commission
could assert such jurisdiction, they argue that as a policy matter it
would be inappropriate for the Commission to delve into complicated
legal and policy issues governed by varying state regulatory regimes.
---------------------------------------------------------------------------
\743\ E.g., CA Com, MD Com, VA Com, IN Com, NH Com, NV Com, NY
Com, OH Com, FL Com, AZ Com, TX Com, ELCON, NY Industrials, NY AG,
NY Consumer Protection, MA DPU, Iowa Board, IN Industrials, Texas
Industrials, NM Industrials, Reynolds, NYMEX, Legal Environmental
Assistance, CO Consumers Counsel, NJ Ratepayer Advocate, IBM, ME
Industrials, Jay, WEPCO, NH General Court.
---------------------------------------------------------------------------
According to some of these commenters,744 section 201(a) of
the FPA precludes an exercise of federal jurisdiction over retail
stranded cost recovery because the Commission's jurisdiction extends
``only to those matters which are not subject to regulation by the
States.'' 745 NM Industrials argues that a lack of state
commission authority is an affirmative state determination, either by
act or omission, that stranded costs must be dealt with in a particular
manner. It submits that the Commission also lacks authority over retail
stranded costs when states either decide not to address such costs or,
in the Commission's opinion, grant insufficient recovery of stranded
costs. NM Industrials asserts that the language of the FPA and its
legislative history indicate that Congress wanted to preclude
Commission jurisdiction in those areas where states could exercise
effective control, and that this limitation covers all matters which
are or can be regulated by the states, including the recovery of
stranded investment. NM Industrials also suggests that assertion of
Commission jurisdiction would violate the provision of section 212 of
the FPA that prohibits the Commission from interfering with the states'
authority over the transmission of energy directly to an ultimate
consumer.746
---------------------------------------------------------------------------
\744\ E.g., NARUC, ELCON, NY Industrials, NM Industrials, NV
Com.
\745\ 16 U.S.C. 824(a).
\746\ See also Freedom Energy Co. Reply Comments.
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Other commenters argue that the Commission's proposed treatment of
retail stranded costs infringes on the states' jurisdiction over the
allocation of costs that were under their jurisdiction when the costs
were incurred. According to these commenters, the question of whether
these costs should be recovered from other retail ratepayers,
eliminated as excess capacity, or billed in some fashion to the
customer now receiving wheeling service are purely questions of state
ratemaking law.747 Some commenters assert that, as a matter of
policy, the Commission should stay out of retail stranded costs because
only the states have sufficient knowledge and expertise regarding
utility planning, investment,
[[Page 21649]]
and forecasting to address these costs adequately.748
---------------------------------------------------------------------------
\747\ E.g., ELCON, PA Com, NY Industrials, ND Com, VA Com, NM
Com.
\748\ E.g., OH Com, NY Industrials, NM Com, IN Com, WA Com, NV
Com, NY Com, Suffolk County, NY AG, Tonko, PA Industrials, NH
General Court.
---------------------------------------------------------------------------
Commenters also express concern that the possibility of Commission
involvement in retail stranded cost recovery will encourage forum-
shopping whenever state commission action is unfavorable, even when
states have procedures to deal with stranded costs. They argue that the
result would be endless litigation over where federal jurisdiction ends
and where state jurisdiction begins. They suggest that if a state fails
to address retail stranded cost recovery, the issue should be addressed
in court or in state legislatures.749 OH Com contends that a
Commission policy that does not recognize states' authority over retail
stranded costs would be a disincentive for states to permit retail
wheeling.
---------------------------------------------------------------------------
\749\ E.g., OH Com, PA Com, NM Com, CA Com, Blue Ridge.
---------------------------------------------------------------------------
A number of commenters argue that recovery of retail stranded costs
is not directly implicated by any Commission or Congressional action--
that most such costs would be created by retail wheeling, which is not
the subject of the Commission's open access initiatives--and thus need
not be dealt with as part of the final rule.750
---------------------------------------------------------------------------
\750\ E.g., Nucor, AEC & SMEPA.
---------------------------------------------------------------------------
Commenters seek a number of clarifications concerning the
Commission's position on, and the procedures for, retail stranded cost
recovery. A number of commenters ask the Commission to clarify the
states' role with respect to retail stranded cost recovery.751
Others address the type of evidence required to establish that the
state regulatory authority lacks authority to address stranded costs
when retail wheeling is required.752
---------------------------------------------------------------------------
\751\ E.g., NY Industrials, EGA, NJ BPU, Coalition on Federal-
State Issues.
\752\ E.g., Iowa Board, Nevada Commission, CCEM; see also NE
Public Power District.
---------------------------------------------------------------------------
Several commenters express concern that customers receiving retail
wheeling not be able to evade state stranded cost charges.753 IL
Com says that the Commission's proposal for determining whether
facilities are state-jurisdictional ``local distribution'' facilities
or Commission-jurisdictional ``transmission'' facilities in interstate
commerce may not always provide a state with the opportunity to recover
retail stranded costs through distribution rate surcharges. It says
that the Commission does not offer any assurances that the case-by-case
application of the proposed ``functional-technical test'' will result
in a finding that ``local distribution'' facilities are used in all
retail wheeling scenarios. PG&E asks the Commission to provide that all
retail customers that opt for direct transmission access by definition
take service over local distribution facilities and therefore may be
subjected to a state-determined distribution rate that includes
stranded cost surcharges.
---------------------------------------------------------------------------
\753\ E.g., IL Com, PG&E, Public Service Co of CO.
---------------------------------------------------------------------------
A number of commenters ask the Commission to clarify that, in
issuing the final rule, the Commission is not endorsing (either
implicitly or explicitly) retail wheeling.754
---------------------------------------------------------------------------
\754\ E.g., NRECA, Wisconsin EC, EEI, PECO, Missouri Basin
Group.
---------------------------------------------------------------------------
Several commenters express concern that stranded costs may arise in
one state jurisdiction and be shifted to another.755 For example,
MT Com says that an analysis confined to a state's boundaries may
reveal no stranded costs, but that such costs may indirectly arise
because of common pool revenue recovery mechanisms, which may be the
largest source of stranded costs for some utilities. Entergy raises a
similar concern in the context of holding company or other multi-state
situations. It argues that denial of retail stranded cost recovery by a
state regulatory authority could harm customers in other states.
Entergy proposes that, while state regulators should be given the
opportunity in the first instance to assure that stranded costs are
recovered and are not shifted to other states, the Commission should
allow utilities to file retail wheeling tariffs with the Commission to
preserve the right to seek recovery from the Commission.
---------------------------------------------------------------------------
\755\ E.g., MT Com, Entergy.
---------------------------------------------------------------------------
Several commenters oppose Entergy's proposal.756 Among other
things, they argue that the FPA does not authorize the Commission to
act as an appellate court over retail regulators. They assert that, in
the case of a multi-state holding company system, it is the Commission-
jurisdictional intra-system agreement (not a state's decision as to
recovery of retail stranded costs) that determines the allocation of
costs at wholesale among the affiliates. Several of these commenters
suggest that if the holding company believes that, as a result of a
state's disallowance of costs in retail rate base, the cost allocations
under an intra-system agreement are unduly discriminatory, the holding
company could propose to amend the agreement.757
---------------------------------------------------------------------------
\756\ E.g., NARUC, Entergy Retail Regulators, MS Com, Al Com.
\757\ E.g., NARUC, MS Com.
---------------------------------------------------------------------------
A number of commenters also express concern that services that
investor-owned utilities provide to promote energy efficiency and
conservation and to assist low-income residents and the elderly be
continued.758 NW Conservation Act Coalition suggests that the
Commission should condition stranded cost recovery upon a showing by
the utility that allowing recovery will not strand such social
benefits.759
---------------------------------------------------------------------------
\758\ E.g., Homelessness Alliance, Black Mayors, National
Women's Caucus, Vann, La Raza.
\759\ NARUC and OH Com assert that, in determining whether a
wholesale transmission transaction is a ``sham,'' the Commission
should consider a retail customer's intent to bypass responsibility
for supporting social programs.
---------------------------------------------------------------------------
Various commenters endorse the use by state regulators of a
distribution charge or other fee imposed on electricity consumption to
address stranded social benefits.760 NARUC and OH Com express
concern that the Commission, by claiming authority over unbundled
retail transmission services, may make it difficult for states to use
non-bypassable ``wires charges'' or ``access fees'' to require all
customer classes to support such programs.761 NARUC asks the
Commission to ensure that any jurisdiction we exercise over unbundled
transmission services does not legally or practically foreclose the
ability of individual states to fund such programs.762 LILCO, as
part of its argument that the Commission should provide a complete
backstop for stranded cost recovery resulting from retail wheeling,
urges the Commission to establish retail wheeling rates that provide
for full recovery of any stranded costs, including stranded social
benefits,
[[Page 21650]]
that are unrecovered after state stranded cost determinations.
---------------------------------------------------------------------------
\760\ E.g., Natural Resources Defense, NW Conservation Act
Coalition, Seattle, FTC, Northeast States for Coordinated Air Use
Management, NARUC, OH Com. CO Com agrees that states should have the
option to fund such programs through the imposition of surcharges on
any form of electric service used to benefit retail customers,
including surcharges on retail transmission rates. Seattle proposes
either a simple fee on kWhs or a differential fee based on the type
of resource and its environmental affects. DOE urges the Commission
to work with state regulators to ensure that states have the ability
to recover stranded retail costs and benefits in a way that prevents
cost-shifting, forum-shopping, and uneconomic bypass (including
bypass of stranded benefits).
\761\ CO Com notes that the NOPR proposes to limit states to
funding mechanisms that can be implemented solely at the local
distribution level, presumably through the use of a surcharge on
distribution facilities or so-called ``fee at the meter'' or the use
of a local distribution system revenue decoupling mechanism. It
suggests that neither of these options may be legally or practically
feasible in many states for a wide variety of reasons (but does not
expand on these reasons).
\762\ Natural Resources Defense proposes that the Commission
adopt the following language: ``The FPA does not affect state
regulators' jurisdiction to apply distribution charges--either
volume-based or fixed--to electricity that is used by any utility
customer to provide end-use services (as distinguished from
electricity that is purchased for resale to end-use customers).''
Natural Resources Defense Initial Comments at 3.
---------------------------------------------------------------------------
Commission Conclusion
We believe that both this Commission and the states have the legal
authority to address stranded costs that result when retail customers
obtain retail wheeling in order to reach a different generation
supplier, and that utilities are entitled, from both a legal and a
policy perspective, to an opportunity to recover all of their prudently
incurred costs. This Commission's authority to address retail stranded
costs is based on our jurisdiction over the rates, terms, and
conditions of unbundled retail transmission in interstate commerce. The
authority of state commissions to address retail stranded costs is
based on their jurisdiction over local distribution facilities and the
service of delivering electric energy to end users. However, because it
is a state decision to permit or require the retail wheeling that
causes retail stranded costs to occur, we will leave it to state
regulatory authorities to deal with any stranded costs occasioned by
retail wheeling. The only circumstance in which we will entertain
requests to recover stranded costs caused by retail wheeling is when
the state regulatory authority 763 does not have authority under
state law to address stranded costs when the retail wheeling is
required.
---------------------------------------------------------------------------
\763\ ``State regulatory authority'' has the same meaning as
provided in section 3(21) of the FPA.
---------------------------------------------------------------------------
Commenters that describe our action as an unlawful abdication or
delegation of authority misconstrue the nature of our decision to leave
retail stranded costs (with a limited exception) to state regulatory
authorities.764 We have not ``abdicated'' or ``delegated'' to
state regulatory authorities our jurisdiction over the rates, terms,
and conditions of retail transmission in interstate commerce; if retail
transmission in interstate commerce by a public utility occurs, public
utilities offering such transmission must comply with the FPA by filing
proposed rate schedules under section 205. Instead, we have made a
policy determination that the recovery of retail stranded costs--an
issue over which either this Commission or state commissions could
exercise authority by virtue of their jurisdiction over retail
transmission in interstate commerce and over local distribution
facilities and services, respectively--is primarily a matter of local
or state concern that should be left with the state commissions.
However, if the state regulatory authority does not have authority
under state law to address stranded costs when the retail wheeling is
required, then we will entertain requests to recover such
costs.765
---------------------------------------------------------------------------
\764\ We reject the arguments of EEI and Coalition for Economic
Competition that the Commission made findings in the initial
stranded cost NOPR that ``inexorably'' lead to the conclusion that
Commission action providing full recovery of retail stranded costs
is required. Their reliance on Williams Natural Gas Company v. FERC,
872 F.2d 438 (D.C. Cir. 1989), appeal after remand, 943 F.2d 1320
(D.C. Cir. 1991) (Williams), is simply misplaced. Williams involved
a rulemaking that was terminated by the Commission. The court stated
that the Commission, ``having expressed these tentative views (that
the incentive price for tight formation gas would disserve the
public interest) and having solicited comments on the issue, was not
free to terminate the rulemaking'' without providing a satisfactory
explanation. 872 F.2d at 446, 450. Here, in contrast, we are issuing
a Final Rule that reaffirms in many respects preliminary findings
proposed in both the initial and Supplemental Stranded Cost NOPRs.
Although the conclusion we reach based on those findings may be
different than that which some commenters advocate, we have fully
explained the basis for our decision.
\765\ In these circumstances, the cases cited by commenters to
support the proposition that an agency is not authorized to abdicate
its statutory responsibilities or to delegate to parties and
intervenors regulatory responsibilities (such as preparation of an
environmental impact statement) are factually distinguishable and
inapposite. See, e.g., FPC v. Texaco, 417 U.S. 380, 394 (1974)
(Commission cannot exempt small-producer rates from compliance with
just and reasonable standard); United States v. City of Detroit, 720
F.2d 443, 451 (6th Cir. 1983) (district court inappropriately
implied waiver of EPA statutory duty under Title II of the Federal
Water Pollution Prevention and Control Act); State of Idaho v. ICC,
35 F.3d 585, 595-96 (D.C. Cir. 1994) (an agency cannot abdicate its
NEPA responsibilities in favor of the regulated party).
---------------------------------------------------------------------------
Because we have accepted the view that stranded costs caused by
retail wheeling are primarily a matter of local or state concern, we
will not allow the states to use the interstate transmission grid as a
vehicle for passing through any retail stranded costs, with the
following limited exception. If the state regulatory authority does not
have authority under state law when the retail wheeling is required to
resolve the retail stranded cost issue, we will permit a utility to
seek a customer-specific surcharge to be added to an unbundled
transmission rate.
We believe that most states have a number of mechanisms for
addressing stranded costs caused by retail wheeling.766 In
addition, as further discussed in Section IV.I, we are defining in this
rule ``facilities used in local distribution'' under section 201(b)(1)
of the FPA. Rates for services using such facilities to make a retail
sale are state-jurisdictional, and states will be free to impose
stranded costs caused by retail wheeling on facilities or services used
in local distribution. States may also use their jurisdiction over
local distribution facilities or services to recover so-called stranded
benefits. This rule is not intended to preempt any existing state
authority to assess a stranded cost or stranded benefits charge on a
retail customer that obtains retail wheeling. Moreover, since the
charge is state jurisdictional, it is of no moment to our
responsibilities under the FPA as to whether such charges are volume-
based (kWh), demand-based (kW), or customer-based (fixed).
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\766\ As discussed in the Supplemental NOPR (FERC Stats. & Regs.
para. 32,514 at 33,129-30), these mechanisms include requiring an
exit fee before a franchise customer is permitted to obtain
unbundled retail wheeling and imposing a surcharge on local
distribution rates. Commenters identified several other possible
mechanisms in response to the initial Stranded Cost NOPR.
---------------------------------------------------------------------------
We believe that our approach to retail wheeling stranded costs
represents an appropriate balance between federal and state interests.
This approach ensures that the rates for transmission in interstate
commerce by public utilities (except in a narrow circumstance) will not
be burdened by retail costs. It also helps to ensure that one state
will not be able to impose costs stranded by its ordering of retail
wheeling 767 on customers in another state.768 In a holding
company or other multi-state situation, we recognize that denial of
retail stranded cost recovery by a state regulatory authority could,
through operation of the reserve equalization formula in a Commission-
jurisdictional intra-system agreement, inappropriately shift the
disallowed costs to affiliated operating companies in other states. The
Commission is concerned about this potential for cost-shifting. We
would not wish to see an intra-system agreement used as a means for one
jurisdiction to shift to other jurisdictions retail stranded costs for
which it would otherwise be responsible under that agreement. However,
we will deal with such situations if they arise pursuant to public
utility filings under section 205 or complaints under section 206.
Thus, the need to amend a jurisdictional agreement to prevent retail
stranded costs from being shifted to customers in other states will be
addressed on a case-by-case basis. We encourage the affected state
commissions in such situations to seek a mutually agreeable approach to
this potential problem. If such a consensus solution resulted in a
filing to modify a jurisdictional agreement, we would accord such a
proposal deference, particularly if other interested parties support
the filing. In the event that the state commissions and
[[Page 21651]]
other interested parties cannot reach consensus that would prevent cost
shifting, the Commission would ultimately have to resolve the
appropriate treatment of such stranded costs.
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\767\ As we stated in the Supplemental NOPR, we do not address
whether states have the lawful authority to order retail wheeling in
interstate commerce. Id. at 33,098 at n.228. In addition, we are
neither endorsing nor discouraging retail wheeling.
\768\ See id. at 33,098, 33,127-28.
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Should a situation arise in which a state regulatory authority
concludes that it has no ability to address retail stranded costs, or
the appropriate state courts ultimately determine that a state
regulatory authority does not have authority to impose retail stranded
costs, a utility may seek recovery here through its Commission-
jurisdictional retail transmission rates of costs stranded as of the
date of the customer's departure. Because all parties are put on notice
by this Rule of the potential for recovery through Commission-
jurisdictional retail transmission rates should state commission-
authorized retail wheeling charges be invalidated, such recovery (if
allowed) would not be retroactive ratemaking.769
---------------------------------------------------------------------------
\769\ See Public Utilities Commission of the State of California
v. FERC, 988 F.2d 154, 163-66 (D.C. Cir. 1993).
---------------------------------------------------------------------------
8. Evidentiary Demonstration Necessary--Reasonable Expectation Standard
In the Supplemental Stranded Cost NOPR, the Commission made a
preliminary determination that a public utility or transmitting utility
seeking to recover stranded costs must demonstrate that it had a
reasonable expectation of continuing to serve a customer. We indicated
that the existence of a notice of termination provision in a wholesale
requirements contract creates a rebuttable presumption that the utility
had no reasonable expectation of serving the customer beyond the period
provided for in the notice provision.770 We proposed not to adopt
a minimum notice period for purposes of applying the rebuttable
presumption. This was because whether a utility has a reasonable
expectation of continuing to serve a customer, and for how long,
including whether there is sufficient evidence to rebut the presumption
that no such expectation existed beyond the notice provision in the
contract, will depend on the facts of each case.
---------------------------------------------------------------------------
\770\ FERC Stats. & Regs. para. 32,514 at 33,117.
---------------------------------------------------------------------------
We sought further comment concerning whether the reasonable
expectation standard should apply if a utility has been making
wholesale requirements sales to a customer in a non-contiguous service
territory and where, in order to make such a sale possible,
transmission service has been rendered by an intervening utility. We
asked whether the Commission should take this as conclusive evidence
that the customer had a choice of wholesale suppliers and, therefore,
that the seller had no reasonable expectation that the contract would
be extended. We further asked should we choose to provide the seller
with an opportunity to prove that it had a reasonable expectation, what
weight should be given to the fact that transmission service was
rendered by the intervening utility. If the seller establishes that it
had a reasonable expectation, and the former wholesale customer does
not take unbundled transmission service from the former seller, we
asked what if any means ought to be available for the collection of
stranded costs.771
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\771\ Id. at 33,118.
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We also proposed to require the same evidentiary demonstration for
recovery of stranded costs from a retail-turned-wholesale customer or a
retail customer that obtains retail wheeling as that required when a
wholesale requirements customer leaves a utility's system. We proposed
that the utility must demonstrate that it incurred stranded costs based
on a reasonable expectation that the customer would continue to receive
bundled retail services. We anticipated that the reasonable expectation
test would be easily met in those instances in which state law awards
exclusive service territories and imposes a mandatory obligation to
serve. We requested comments on these proposals.772
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\772\ Id. at 33,128.
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Comments
a. Rebuttable Presumption
Some commenters oppose treating a notice provision as a rebuttable
presumption that the utility had no reasonable expectation of
continuing to serve a customer. Commenters representing the financial
community (Utility Shareholders and Utility Investors Analysts), for
example, state that investment in generation and other costs incurred
in providing utility service have not been tied to notice provisions.
Based on the use of notice provisions in the past, and their infrequent
use for termination, they state that the financial community has not
viewed notice provisions as a determinant of the financial basis of
investment in the industry.
Other commenters also argue that the Commission interprets the
intent behind termination notice provisions too narrowly. These
commenters submit that the Commission should examine on a case-by-case
basis whether a notice provision demonstrates a sufficient meeting of
the minds between the parties that there was no reasonable expectation
that the contract would be extended.773 TVA notes that the
existence of a notice provision in its contracts in no way implies that
continued service would not be expected.
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\773\ E.g., Carolina P&L, CSW, Duke, Utilities for Improved
Transition, Montaup, TVA, MidAmerican. MidAmerican states that, for
years, utilities have entered into wholesale contracts containing
termination notice provisions and, for years, customers have renewed
and renegotiated those contracts. Duke agrees that more important
indications of the utility's reasonable expectation of continuing to
serve the customer can be found where the service has been included
in the IRP process or the contract has been repeatedly renewed.
Orange & Rockland proposes that there be a rebuttable presumption of
recovery for long-standing (at least 10 years) contracts between
utility affiliates on the basis that the existence of a long-
standing relationship is of greater significance than a notice
provision.
---------------------------------------------------------------------------
A number of commenters 774 note that some utilities have
``evergreen'' contracts that remain in effect indefinitely unless
either party gives notice that it intends to terminate the contract.
They argue that, with no date certain for termination, the provider of
bundled service must proceed on the assumption that it will have to
meet its contract obligations on a continued basis. CSW recommends that
the Commission limit the rebuttable presumption standard to contracts
that contain a fixed contract termination date. IN Com suggests that
where a contract contains an evergreen provision, the Commission should
consider how often the contract has been automatically renewed and the
length of the notice period.
---------------------------------------------------------------------------
\774\ E.g., CSW, IN Com.
---------------------------------------------------------------------------
A number of commenters suggest that the following factors should be
conclusive proof of a reasonable expectation (or sufficient to
conclusively rebut the presumption of no reasonable expectation): (1)
An obligation under statute, certificate of public convenience and
necessity, order or otherwise, granted to the utility to provide
service to the area that includes the customer; (2) participation by
the customer in regulatory proceedings that defer the utility's
complete recovery of the costs associated with existing investment to a
later period; or (3) service under a wholesale rate that averaged the
cost of all of a utility's generation resources, both long-term and
short-term.775 Utilities For Improved Transition maintains that a
customer whose rates were based on the totality of a utility's
resources, including those with long life expectancies,
[[Page 21652]]
cannot claim that the governing expectation was that the utility would
serve the customer only for a period of one to three years.
---------------------------------------------------------------------------
\775\ E.g., El Paso, Utilities For Improved Transition.
---------------------------------------------------------------------------
Other commenters, in contrast, assert that the rebuttable
presumption does not go far enough. These commenters submit that a
notice of termination provision should create a conclusive presumption
that a utility had no reasonable expectation of continuing to serve a
customer beyond the notice period.\776\ Some commenters \777\ also
support a conclusive presumption of no reasonable expectation where one
or more of the following grounds are present: (1) An explicit
termination provision, regardless of the length of the pre-termination
notice period; (2) an explicit provision for decreasing service or
switching to partial requirements service; (3) a pre-existing
transmission tariff or transmission service schedule; (4) NRC license
conditions providing for transmission service or pooling rights;
778 (5) a municipal joint action agency or G&T cooperative with
authority to supply the wholesale load in question; (6) a fixed-term
contract; (7) membership in a power pool that provides access to
regional markets; (8) a contract entered into after passage of the
Energy Policy Act; or (9) other evidence of an ability to seek
alternative suppliers. Several of these commenters, such as TAPS and
Detroit Edison Customers, submit that a conclusive, irrebuttable
presumption would decrease the number of disputes over stranded cost
issues.
---------------------------------------------------------------------------
\776\ See, e.g., ELCON, NRECA, APPA, American Forest & Paper,
Central Montana EC, Municipal Energy Agency Nebraska, Arkansas
Cities, Direct Service Industries, Atlantic City, TDU Systems,
Fertilizer Institute, LG&E, ABATE, Oglethorpe.
\777\ E.g., TAPS, Missouri Joint Commission, Detroit Edison
Customers, LEPA, APPA, Cleveland.
\778\ According to LEPA, the normal set of NRC license
conditions included an explicit wheeling commitment and many of the
license conditions clearly referenced the possibility that the
wheeling commitment would lead to the loss of customers to whom the
utility had been selling bulk power supply as well as retail power.
LEPA submits that acceptance of such license conditions should have
ended any reasonable expectation that a utility might have had of
continuing to serve a full requirements customer, wholesale or
retail, after the termination of its contract.
---------------------------------------------------------------------------
Several comments were submitted concerning the examples listed in
the NOPR that the Commission suggested, depending on all of the facts
and circumstances, could establish a reasonable expectation that a
contract would be extended. These examples include lack of access to
alternative suppliers, repeated contract renewals, failure of a
customer to object to the imposition of construction-work-in-progress,
or communications between supplier and customer concerning including
the customer's load in system planning.779 Some commenters argue
that evidence of this type should not be enough to rebut the
presumption (or to overcome a summary judgment motion based on the
presumption) of no reasonable expectation for contracts with notice
provisions.780 ELCON objects to using a customer's lack of
alternative supply as evidence of a continued service obligation; it
submits that the historic lack of supply alternatives has been caused
by undue exercise of market power and should not be rewarded.781
Las Cruces suggests that if lack of opposition to construction-work-in-
progress evidences a reasonable expectation of continued service,
continuous opposition should evidence a reasonable expectation that the
customer will depart a system at the earliest possible date. With
regard to the Commission's suggestion that communications with the
customer on the customer's future plans could establish reasonable
expectation, Direct Service Industries submits that no claimed reliance
should be deemed reasonable unless the seller obtained express
assurances from the customer that the customer intended to continue to
purchase power from the seller beyond its current contract.
---------------------------------------------------------------------------
\779\ See FERC Stats. & Regs. para. 32,514 at 33,117.
\780\ E.g., TAPS, Phelps Dodge. Phelps Dodge suggests that
evidence of past contract renewals, by itself, should not serve to
rebut the presumption that the utility has no reasonable expectation
of contract renewal in the future.
\781\ In contrast, EEI believes that lack of access to
alternative suppliers can be evidence that a utility reasonably
expected to continue to serve a customer.
---------------------------------------------------------------------------
We also received comments on the time at which the reasonable
expectation had to exist. TAPS urges that the Commission should focus
on whether a utility had a reasonable expectation of continued service
when it entered into the most recent execution, renewal or amendment of
the power supply contract.782 PSE&G, on the other hand, argues
that the focus of the Commission's review should be whether, at the
time of incurring or obligating itself to incur the cost of serving a
customer, the utility had a reasonable expectation of serving that
customer for its planning horizon.
---------------------------------------------------------------------------
\782\ If the investment now alleged to be stranded was incurred
after the most recent amendment or extension to the contract, TAPS
would focus the reasonable expectation review on such later date.
---------------------------------------------------------------------------
b. Application of Reasonable Expectation Standard to Non-Contiguous
Service Territory
Some commenters discuss the situation in which a utility has been
making wholesale requirements sales to a customer in a non-contiguous
service territory and, in order to make such a sale possible,
transmission service has been rendered by an intervening utility. They
argue that this situation presents conclusive evidence that the
customer had a choice of wholesale suppliers and, therefore, that the
seller had no reasonable expectation that the contract would be
extended.783 Direct Service Industries submits that if a customer
has power supply options that do not rely on access to the selling
utility's transmission system, the selling utility could have had no
reasonable expectations other than those expressly created by contract.
NM Industrials submits that allowing recovery of stranded costs in this
situation would also constitute retroactive ratemaking in violation of
Arkansas Louisiana Gas Company v. Hall.784 It argues that by
assessing stranded costs at the close of a contract's term against
customers that do not even need a generating utility's transmission
services to leave its system, the Commission would retroactively alter
the terms and conditions of the rates for generation negotiated between
the parties and approved by the Commission.
---------------------------------------------------------------------------
\783\ E.g., IL Com, Utilicorp, PSG&E, NM Industrials.
\784\ 453 U.S. 571 (1981).
---------------------------------------------------------------------------
Other commenters submit that in these circumstances the Commission
should give the supplier the opportunity to prove that it had a
reasonable expectation that it would continue to serve the
customer.785 ELCON and WP&L state that the reasonable expectation
standard should be satisfied (or not) by reference to the parties'
existing contract, regardless of whether the customer is in a
contiguous service territory.
---------------------------------------------------------------------------
\785\ E.g., Florida Power Corp, Consumers Power, FL Com, TDU
Systems.
---------------------------------------------------------------------------
Utility Investors Analysts asserts that a seller will always have a
reasonable expectation that a business relationship can be continued
with a current customer and that the better presumption would be that
the contract will be extended unless evidence to the contrary exists.
[[Page 21653]]
c. Application of Reasonable Expectation Standard to Retail-Turned-
Wholesale Customers or To Retail Wheeling
A number of commenters support the Commission's proposal to apply
the reasonable expectation standard in these cases.786 PA Com
submits that the case-by-case analysis contemplated by the Commission
for establishing a utility's reasonable expectation of continuing to
serve a wholesale requirements customer should also apply in the case
of a retail-turned-wholesale customer or a retail customer that obtains
retail wheeling.
---------------------------------------------------------------------------
\786\ E.g., PA Com, Com Ed, CSW, United Illuminating, UFIT,
PSNM, TDU Systems.
---------------------------------------------------------------------------
Some commenters believe that the reasonable expectation test would
be easily met in those instances in which state law awards exclusive
service territories and imposes an obligation to serve.787 Some
contend that the reasonable expectation standard should be presumed met
in these circumstances because state law obligates a utility to serve
all retail customers. A number of commenters assert that such a
presumption would obviate the need for case-by-case showings concerning
the expectations of each utility and the nature of each
franchise.788 At a minimum, several commenters propose that the
Commission adopt a rebuttable presumption that utilities had an
obligation to serve retail customers and therefore that the reasonable
expectation test is met in a retail-turned-wholesale customer scenario
or in the case of costs stranded as a result of retail
wheeling.789
---------------------------------------------------------------------------
\787\ E.g., Com Ed, Central and Southwest, United Illuminating,
Utilities For Improved Transition, Utility Investors Analysts,
Utility Shareholders.
\788\ E.g., EEI, Minnesota Power, PECO, Puget, Centerior,
Florida Power Corp, FL Com, Southern, SoCal Edison, NEPCO, Consumers
Power, Coalition for Economic Competition. NEPCO asserts that the
Supplemental Stranded Cost NOPR does not cite any comments or
evidence casting doubt on the Commission's initial proposal (in the
initial Stranded Cost NOPR) not to apply the reasonable expectation
test to retail-turned-wholesale or retail customers that obtain
retail wheeling on the basis that utilities operating under an
obligation to serve at retail necessarily have an entitlement to
recover the costs prudently incurred in fulfillment of that
obligation.
\789\ E.g., EEI, Detroit Edison, Centerior, Consumers Power,
Ohio Edison.
---------------------------------------------------------------------------
On the other hand, a number of commenters argue that there is no
basis for a utility to reasonably expect that it will continue to serve
a particular customer in states where franchises are non-
exclusive.790 Several of these commenters argue that a utility
operating under a non-exclusive franchise is faced with the ever-
present prospect that the communities it serves may build their own
systems.791
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\790\ E.g., Wing Group, Alma, Total Petroleum, Cleveland, ABATE,
N.Y. Mayors, CAMU, Suffolk County.
\791\ E.g., Wing Group, Total Petroleum, ABATE, CAMU, NY Mayors.
Proposals advanced by commenters to address non-exclusive franchises
include suggestions that the Commission: summarily reject claims to
recover retail stranded costs where the utility has a non-exclusive
franchise and historically has been subject to retail competition
(e.g., Cleveland); apply a rebuttable presumption that a utility had
no reasonable expectation of continued service where a municipal
franchise is expiring and the municipality has put the retail
supplier on notice that the municipality may seek an alternative
source of power supply (e.g., Las Cruces); or provide that no
stranded cost claim will be entertained absent a showing, by
reference to applicable state law, that the utility had an exclusive
service franchise obligation or was otherwise subject to an
obligation to serve the customer that is departing its system (e.g.,
Phelps Dodge).
---------------------------------------------------------------------------
Other commenters oppose the suggestion that the reasonable
expectation test cannot be met where a franchise is non-exclusive or
has terminated.792 They argue that a utility's obligation to serve
retail customers arises under state laws independent of the franchise.
SoCal Edison explains that in states such as California, a franchise is
nothing more than the source of a utility's right to use the city's
streets, poles, rights of way, etc., and that a utility's duty to serve
extends to all customers within its certificated service territories
and not simply to those areas in which it has a franchise.
---------------------------------------------------------------------------
\792\ E.g., Utility Working Group, SoCal Edison, Florida Power
Corp, PG&E. Referring to the Commission's statement that it expects
the reasonable expectation test to be easily met in those instances
in which state law awards exclusive territories and imposes a
mandatory obligation to serve, Utility Working Group asks the
Commission to make clear in the final rule that it did not intend by
that example that utilities with non-exclusive service territories
would be presumed to fail the reasonable expectation test. According
to Utility Working Group, the focus of the test must be on the
utility's obligation to serve, which may be separate from any
franchise arrangements.
---------------------------------------------------------------------------
Commission Conclusion
We reaffirm that a utility seeking to recover stranded costs must
demonstrate that it had a reasonable expectation of continuing to serve
a customer. Whether a utility had a reasonable expectation of
continuing to serve a customer, and for how long, will be determined on
a case-by-case basis, and will depend on all of the facts and
circumstances.793
---------------------------------------------------------------------------
\793\ The examples that the Commission provided in the
Supplemental NOPR of possible ways to establish reasonable
expectation were not intended to be dispositive of the issue. As we
make clear in this Rule, whether a particular utility had a
reasonable expectation that a contract would be extended will depend
on all of the facts and circumstances.
---------------------------------------------------------------------------
Further, we will apply the reasonable expectation standard in those
cases where a utility has been making wholesale requirements sales to a
customer in a non-contiguous service territory and, in order to make
such a sale possible, transmission service has been rendered by an
intervening utility. We believe it is appropriate to give the utility
an opportunity to prove that it had a reasonable expectation of
contract renewal in circumstances in which the remote customer becomes
an unbundled transmission services customer of the former
supplier.794
---------------------------------------------------------------------------
\794\ However, if the remote customer does not use the former
supplying utility's open access tariff to reach the new supplier,
there would be no ``wholesale stranded costs'' as that term is
defined in this Rule. In this situation, we would not allow extra-
contractual recovery of stranded costs. Thus, there would be no need
to address reasonable expectation. See Section IV.J.12.
---------------------------------------------------------------------------
We also reaffirm our determination that the existence of a notice
provision in a contract creates a rebuttable presumption that the
utility had no reasonable expectation of serving the customer beyond
the specified period. Whether or not a contract contains an
``evergreen'' or other automatic renewal provision will be a factor to
be considered in determining whether the presumption of no reasonable
expectation is rebutted in a particular case.
We will not adopt a minimum notice period for purposes of applying
the reasonable expectation rebuttable presumption. Whether a utility
had a reasonable expectation of continuing to serve a customer,
including whether there is sufficient evidence to rebut the presumption
that no such expectation existed beyond the notice provisions in a
contract, will depend on the facts of each case.
In addition, we reaffirm our preliminary determination to apply the
reasonable expectation standard to retail-turned-wholesale customers.
In this scenario, before the Commission will permit a utility to
recover stranded costs, the utility must demonstrate that it incurred
such costs based on a reasonable expectation that the retail-turned-
wholesale customer would continue to receive bundled retail service.
Whether the state law awards exclusive service territories and imposes
a mandatory obligation to serve would be among the factors to be
considered in determining whether the reasonable expectation test is
met in a particular case.795
---------------------------------------------------------------------
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
------
\795\ The same procedures would apply to retail customers that
obtain retail wheeling.
---------------------------------------------------------------------------
We further note that we are not addressing in this Rule who will
bear the stranded costs caused by a departing generation customer if
the Commission finds that the utility had no reasonable expectation of
continuing to serve that
[[Page 21654]]
customer. As we suggested in the initial Stranded Cost NOPR,796 we
anticipate that, in such a case, a public utility will seek in
subsequent requirements rate cases to have the costs reallocated among
the remaining customers on its system. However, we will not prejudge
that issue here.
---------------------------------------------------------------------------
\796\ FERC Stats. & Regs. para. 32,507 at 32,872.
---------------------------------------------------------------------------
9. Calculation of Recoverable Stranded Costs
In the Supplemental Stranded Cost NOPR, the Commission proposed
that the determination of recoverable stranded costs be based on a
``revenues lost'' approach. Under this approach, stranded costs are
calculated by subtracting the competitive market value of the power the
customer would have purchased from the revenues that the customer would
have paid had it stayed on the utility's generation system. We cited
several benefits that we believe a ``revenues lost'' approach offers
over a hypothetical cost-of-service approach, including avoidance of an
asset-by-asset review, minimization of cost allocation procedures, and
ease of application.797
---------------------------------------------------------------------------
\797\ Id. at 33,121.
---------------------------------------------------------------------------
We sought comments on how to calculate what the utility's revenue
stream would have been had the customer continued service. We also
sought comments on how to calculate the revenues that the utility would
receive in a competitive market for the stranded assets. This included
whether we should require the utility to track the actual selling price
of the power over time or require the utility to use an up-front
approach (such as an estimate of the forecasted market value of the
power for the period during which the customer would have taken
service). We asked whether we should allow prices in futures markets or
forward markets to be used in an up-front approach, assuming such
financial instruments become available.798
---------------------------------------------------------------------------
\798\ Id.
---------------------------------------------------------------------------
We suggested that the revenues lost approach automatically takes
account of mitigation measures because it reduces the amount of
stranded costs recoverable by a utility by the market price of the
power that the customer no longer takes. We noted that this is
particularly so if mitigation is reflected through a one-time, up-front
estimate of the future market value of the power and is not trued up
over time. We sought comments regarding implementation of a mitigation
requirement. If mitigation is trued up over time, we asked how the
Commission should ensure that the utility takes all reasonable steps to
mitigate its own costs so as to minimize what the customer would have
paid. We also asked how the Commission should ensure that the utility
does its best to sell the power at its highest possible value. In
addition, we asked whether there are other mitigation measures that
should be taken into account (such as efficiency improvements that a
utility would have undertaken regardless of whether the particular
customer continued to take power under its contract, or cost savings
resulting from the buy-out of a fuel contract made possible by the
customer's departure).799
---------------------------------------------------------------------------
\799\ Id. at 33,123. We also asked how revenues received as a
result of mitigation measures should be reflected in the
determination of the amount of recoverable stranded costs; what
special accounts, if any, should be created to track revenue
liability for specific customers, revenues from mitigation measures,
and other revenues received by the utility that offset the stranded
cost liability; whether any adjustment should be permitted to the
revenues that the utility claims will be realized in a competitive
market for its stranded assets, and if so, how often and under what
circumstances. Further, we sought comments on whether there are
special costs that warrant some special consideration in the
determination of stranded cost liability under a revenues lost
approach, and if so, how they should be treated. Id. at 33,121-22.
---------------------------------------------------------------------------
With regard to determining how long a utility could have reasonably
expected to keep a generation customer (which we will call the
``reasonable expectation period''), we preliminarily found that a one-
size-fits-all approach is not appropriate. We sought further comment
with respect to whether the Commission ought to establish presumptions
or, in the alternative, absolute limits on a customer's maximum
liability when a utility establishes that it had a reasonable
expectation that the contract would be extended. We inquired whether it
would be appropriate to pick an outer limit equal to the revenues that
the utility would lose during the length of one additional contract
extension period, or during the length of the utility's planning
horizon. We also asked what other events or criteria might be used to
establish either presumptions or absolute limits on the reasonable
expectation period.800
---------------------------------------------------------------------------
\800\ Id. at 33,122.
---------------------------------------------------------------------------
In addition, we proposed procedures for providing a customer
advance notice of how the utility would propose to calculate costs that
the utility claims would be stranded by the customer's
departure.801 We invited comments on these procedures.802
---------------------------------------------------------------------------
\801\ Id. at 33,114-15.
\802\ Id. at 33,115.
---------------------------------------------------------------------------
Comments
a. Revenues Lost Approach
Numerous commenters, including almost all investor-owned utility
commenters, support the revenues lost approach for calculating stranded
costs.803 Among other things, commenters maintain that the
revenues lost approach is fair, reliable, and less complicated than the
asset-by-asset approach. As discussed below, while some of these
commenters support an ``up-front'' determination of stranded costs with
no subsequent adjustments, others prefer use of a true-up mechanism
whereby a customer's responsibility for stranded costs is adjusted to
the extent that the actual competitive market value is different from
the estimated market value used to determine the customer's up-front
stranded cost charge.
---------------------------------------------------------------------------
\803\ E.g., Centerior, NYSEG, Florida Power Corp, Houston L&P,
NIMO, Orange & Rockland, Com Ed, PSE&G, EEI, PECO, Texas Utilities,
PG&E, SoCal Edison, Dayton P&L, El Paso, IL Com, United
Illuminating, Nuclear Energy Institute.
---------------------------------------------------------------------------
Other commenters, on the other hand, oppose the revenues lost
approach.804 Some commenters state that the revenues lost approach
provides no incentive to mitigate stranded costs because, by permitting
a utility to recoup from a departing generation customer the difference
between the contract price and a power resale price, the utility
receives the same total revenues regardless of whether the customer
stays or leaves and regardless of whether the utility effectively
mitigates stranded costs.805 Others maintain that the revenues
lost approach is imprecise.806 Referencing the problems associated
with avoided cost projections used in setting QF rates under PURPA,
some of these commenters submit that the revenues lost approach also
requires significant assumptions (regarding projected revenue streams,
service levels, and generic market value forecasts).807 Among the
other criticisms of the revenues lost approach that are raised by
commenters are that it leads to over-recovery of stranded
costs,808 is
[[Page 21655]]
anticompetitive,809 and that it leads to cost shifting.810
NARUC and TDU Systems also maintain that it is likely that assets
stranded by a customer's departure from the utility's generation system
will be used to serve new customers but that the revenues lost approach
offers no method of accounting for such ``unstranding'' of assets.
---------------------------------------------------------------------------
\804\ E.g., LG&E, TAPS, TDU Systems, ABATE, Blue Ridge, NY
Energy Buyers, WP&L, PA Com, KY Com, American National Power, ELCON,
Texaco, UT Com, NARUC, NIEP, DE Muni, Reynolds, Knoxville, Alma,
APPA, NY Industrials, IL Industrials, SC Public Service Authority,
Caparo, American Forest & Paper.
\805\ E.g., NIEP, DE Muni and TDU Systems.
\806\ E.g., SC Public Service Authority, ABATE, NY Energy
Buyers, NARUC, ELCON, American Forest and Paper, APPA.
\807\ E.g., NARUC, NYSEG.
\808\ E.g., NRECA, NIEP, TDU Systems.
\809\ E.g., TDU Systems, Blue Ridge, NY Energy Buyers.
\810\ E.g., UT Com.
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A number of commenters request clarification of the stranded cost
formula contained in the NOPR, including specific instructions
regarding how to calculate the revenues the customer would have paid
the utility had it remained a customer and the competitive market value
of the power the customer would have purchased.811 Some of these
commenters suggest that the stranded cost issue will be more
contentious if the final rule does not provide greater detail.812
Several commenters request that the Commission issue a detailed list of
recoverable costs.813 A number of commenters propose detailed
alternatives to, or variations of, the revenues lost approach.814
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\811\ E.g., Utility Investors Analysts, Public Power Council,
Atlantic City, EEI, PA Com, NYSEG, Central Montana EC, Nebraska
Public Power District, LG&E ABATE.
\812\ Several commenters (Illinois Power, Oklahoma G&E, and
Utility Investors Analysts) suggest that the Commission hold a
technical conference to discuss how best to define the calculation
of the formula components.
\813\ Central Montana EC and NY Energy Buyers.
\814\ See EEI, Electronic Data Systems, Knoxville, NIMO, NYSEG,
NY Energy Buyers, Reynolds.
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Numerous commenters urge the Commission to be flexible and not
overly prescriptive regarding the calculation of the formula
components.815 These commenters generally recommend that the
Commission judge each stranded cost proposal on a case-by-case
basis.816
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\815\ E.g., Nuclear Energy Institute, EEI, Consumers Power, PA
Com, Oklahoma G&E, Portland, Knoxville, MidAmerican, Seattle, Salt
River, Washington and Oregon Energy Offices, SMUD, Caparo.
\816\ Some commenters (e.g., Alma, Freedom Energy) oppose such
flexibility. Alma maintains that clarity of rules is needed to
provide participants in the competitive market as much certainty as
possible about stranded cost charges likely to be recovered before
they engage in alternative transactions. Freedom Energy similarly
supports across-the-board or generic standards, as opposed to a
case-by-case approach.
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Definition and Calculation of Revenue Stream
Some commenters maintain that the revenue stream component should
be calculated based on the present rates paid by the customer.817
These commenters state that because present rates have been approved by
various commissions, the costs have been shown to be legitimate,
prudent, and verifiable.
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\817\ E.g., Centerior, Com Ed, Duke, Entergy, Florida Power
Corp, Utility Investors Analysts, CA Energy Co, CSW.
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Other commenters oppose the use of current rates to calculate the
utility's revenue stream. WP&L believes that the use of current rates
would be overly generous and recommends capping the revenue measure at
a regional average rate rather than a utility-specific rate. A number
of other commenters argue that the effects of competition should be
factored into the revenue stream by using the rates for capacity and
energy actually offered or available in the utility's marketplace, such
as incentive and special rates, not just the tariff rates to a
particular customer.818 Several commenters support removal of rate
of return-related revenues associated with stranded assets, including
risk premiums that are designed to compensate for potential nonrecovery
of stranded costs.819 EEI, in contrast, opposes any disallowance
of rate of return-related revenues on the grounds that such a
disallowance would violate the constitutional bar against the taking of
private property without just compensation. Electronic Data Systems
recommends calculation of the revenue stream using projected rates that
include the effects of future rate increases.
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\818\ E.g., Alma, ABATE, DOD, TDU Systems, ELCON.
\819\ E.g., NRECA, CA Energy Co, ABATE, DOD.
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The Commission requested comments on what categories of costs, in
addition to investment costs, should be eligible for stranded cost
recovery. In response, many commenters support the inclusion in the
revenue stream calculation of additional costs, termed ``special''
costs, that may not be currently reflected in the rates paid by the
departing customers, but that were incurred to provide service to these
customers.820 ``Special'' costs include: (1) Nuclear
decommissioning costs; (2) environmental obligations existing at the
time of the customer's departure; (3) purchased power contracts; (4)
buyouts and buydowns of purchased power contracts; and (5) all
regulatory assets, including deferred costs of generating assets for
which regulators have promised recovery, deferred taxes, transition
costs for post-employment benefits other than pensions, and contingent
liability.
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\820\ E.g., EEI and various investor-owned utilities, Nuclear
Energy Institute, NC Com, Legal Environmental Assistance, EPA,
Utilities for Improved Transition, PA Com.
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Other commenters oppose the inclusion of ``special'' costs in the
calculation of the revenue stream.821 TAPS questions how a
customer can be held responsible for a cost that, by definition, it was
never under a contractual obligation to pay. WP&L states that
suppliers' rates should already reflect reasonable estimates of
decommissioning costs and, therefore, no additional recovery is
warranted.
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\821\ E.g., TAPS, WP&L, UT Industrials, UtiliCorp, American
Forest & Paper.
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Some commenters argue that the calculation of stranded costs should
include social costs, such as demand side management, environmental
costs, low income assistance costs, and costs associated with the
management of fish and wildlife.822
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\822\ E.g., DC Com, Sustainable Energy Policy, Washington and
Oregon Energy Offices.
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NARUC states that the Commission should not preempt the ability of
states to establish competitively neutral programs, such as DSM and
energy efficiency, environmental mitigation, and R&D.
Various commenters state that any determination of stranded costs
should take into account all offsetting benefits realized by the
transmission provider upon a customer's departure.823 Some
commenters describe these costs as ``stranded benefits.'' 824
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\823\ E.g., AEC & SMEPA, Electronic Data Systems, Freedom Energy
Co, LG&E, American National Power, EGA, Entergy, AMP Ohio, TDU
Systems, TAPS, Las Cruces.
\824\ TDU Systems proposes that the Commission allow for the
recovery of stranded benefits in one of two ways: (1) Require direct
payment of stranded benefits to a wholesale purchaser whose contract
is terminated; or (2) allow a party to continue to receive power at
cost-based rates for a period sufficient for the purchaser to be
``transitioned'' into a competitive market.
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Most commenters favor the removal of avoided variable costs from
the calculation of stranded costs on the basis that only fixed costs
are truly stranded.
Some commenters support prioritizing stranded cost
recovery.825 These commenters argue that stranded costs should be
categorized and ranked by the degree of responsibility that utilities
had for their incurrence. Utilities would be allowed the greatest
percentage of recovery for those stranded costs over which they had the
least control.
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\825\ E.g., ELCON, NY Energy Buyers, SMUD, Caparo.
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Definition and Calculation of the Competitive Market Value
There generally was no consensus among the commenters concerning
how
[[Page 21656]]
to determine the revenues a utility would receive in a competitive
market for the stranded assets, that is, the competitive market
value.826 Proposals for calculating competitive market value
include using: (1) The marginal cost of the released capacity; (2) the
long-run marginal cost of the most competitive incremental generation
replacement technology; (3) the marginal cost of requirements service;
(4) a combination of the marginal costs of the utility, alternative
suppliers, and others; (5) the cost of a combined cycle combustion
turbine; (6) the price paid by the departing generation customer; (7)
the highest price available in the market; and (8) auctions. In
addition, to the extent that a futures market is sufficiently well-
developed when the Commission issues a final rule, several commenters
believe that futures market prices could be used as an estimate of
market value.827
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\826\ E.g., Centerior, Duke, Entergy, Com Ed, Houston L&P,
Florida Power Corp, Carolina P&L, NRRI, WP&L, DOE, CSW, UtiliCorp,
LG&E, FL Com.
\827\ E.g., WP&L, DOD, Duke, PSNM, ABATE, Houston L&P. The
Commission notes that the New York Mercantile Exchange only recently
began trading in electricity futures and that such trading was
limited to two delivery points located within the Western
Interconnection.
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MT Com contrasts the effect of using short-term nonfirm prices
instead of long-term firm prices as the competitive market value. It
states that if short-term nonfirm prices are used, the stranded cost
estimate would be higher, because the market price of short-term
nonfirm power is lower than both the market price of long-term firm
power and the embedded cost price.
Some commenters express concern regarding the difficulty of
determining the market value of the displaced capacity under the
revenues lost approach.828 Among other things, commenters note
that because a competitive market does not yet exist, the market price
cannot be calculated in advance. For this reason, several commenters
support an after-the-fact determination of market value.829
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\828\ E.g., MI Com, NSP, NY Energy Buyers, KS Com.
\829\ E.g., KS Com, NY Energy Buyers.
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Snapshot Approach vs. True-Ups
Commenters are split on whether the revenues lost approach should
use a one-time snapshot approach 830 or whether true-ups should be
required or allowed.831 The primary rationale offered in support
of a snapshot approach is certainty; 832 the primary rationale
offered in support of true-ups is accuracy.
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\830\ Commenters that support a one-time, up-front approach
include FL Com, Dayton P&L, Portland, DE Muni.
\831\ Commenters that support true-ups include ELCON, NYSEG, MN
DPS, Reynolds, TAPS, NIMO, DOE, Electric Consumers Alliance, Com Ed,
United Illuminating, SoCal Edison.
\832\ DE Muni urges rejection of true-ups on the basis that
true-ups represent guaranteed recovery of 100 percent of stranded
costs.
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Commenters that support true-ups note the inaccuracy associated
with long-term avoided cost estimates contained in PURPA-mandated QF
contracts and maintain that the projections required by the revenues
lost approach will produce similarly disastrous results if true-ups are
not permitted. As a component of the true-up calculation, some
commenters favor inclusion of revenues associated with future load
growth of remaining customers.833 According to Electronic Data
Systems, if these revenues are not included in a true-up calculation,
the utility could over- or under-collect stranded costs, depending on
whether and what type of load growth is anticipated. CA Energy Co and
American National Power recommend consideration of load growth of
remaining customers as a mitigating factor because the load increases
of these customers allow the sale of the stranded capacity. CSW, on the
other hand, opposes using the future load growth of remaining customers
as a mitigation device. CSW states that the benefits of growth on the
former supplier's system should flow to the customers who remain
customers of that system. Ohio Ed agrees, except where the customer
proves that the utility has deferred or cancelled capacity resource
additions in response to departing customers.
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\833\ E.g., Electronic Data Systems, Alma, American National
Power, CA Energy Co, NARUC, NRECA.
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Other commenters suggest that the Commission should not prescribe
one method over the other.834 EGA, for example, states that
customers should have the choice of paying either a projected fixed
amount or a charge that is periodically trued up.
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\834\ E.g., Atlantic City Electric, EGA, Conservation Law
Foundation.
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Mitigation
A number of commenters agree that the revenues lost approach
effectively encompasses mitigation.\835\ Others argue that mitigation
should (or could) be accomplished through divestiture of assets or
capacity auctions.\836\ LG&E states that a utility requesting recovery
of stranded costs should be required to auction that portion of its
system to the highest bidder. The difference between the auction price
and the depreciated value of the auctioned assets could be used to
determine stranded costs. However, LG&E does not advocate complete
recovery of this difference; rather, it argues that this amount could
be used as a starting point.
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\835\ E.g., Utility Investors Analysts, Duke, PSE&G, Com Ed,
United Illuminating, Entergy.
\836\ E.g., NIEP, LG&E, TDU Systems, EGA, NY Energy Buyers,
ELCON, American National Power.
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Several commenters argue that the revenues lost approach can
produce anticompetitive results if capacity auctions or divestiture are
not required.\837\ A number of these commenters contend that utilities
that recover significant stranded costs (while still maintaining
control over the stranded capacity) can use the freed capacity to make
sales in the market at subsidized prices. They maintain that these
utilities do not have to worry about recovery of fixed costs because
those costs are recovered by the stranded cost charge. According to
these commenters, utilities can then remarket (or ``dump'') stranded
capacity at artificially low prices (made possible by the subsidy from
the stranded cost recovery) and thereby gain a competitive advantage in
other transactions.\838\ If the utilities are permitted to remarket the
displaced capacity, CA Energy Co states that market-sensitive floor
prices should be set to prevent utilities from reselling power from
stranded assets at artificially low prices.
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\837\ E.g., LG&E, Allegheny, TDU Systems, EGA, AMP Ohio, CA
Energy Co, WP&L, Torco.
\838\ CA Energy Co maintains that an anticompetitive intent
could be hidden by the argument that power must be dumped to
mitigate stranded costs. It thus submits that, even without
intending to do so, a utility could cripple competition by
depressing market rates to artificially low levels.
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Suggestions as to how to prevent such anticompetitive consequences
include allowing the customer to own or control the residual asset or
amount of stranded capacity equivalent to the lost revenues. According
to EGA, the customer could market the capacity it would have had to pay
for through stranded cost charges and thus prevent the utility from
remarketing the capacity after it has been paid stranded costs.
Several commenters take a harder line and would require suppliers
seeking stranded cost recovery to offer for sale to the departing
customer a ``slice'' of their system.\839\ TDU Systems states that the
purchase of an undivided slice of the system is superior to divestiture
of a specific asset because the utility cannot keep the wheat and leave
the purchaser with the chaff. TDU Systems would also make purchase
rights to the system assignable. According to TDU
[[Page 21657]]
Systems, this mitigation scheme is the only possible way to justify the
revenues lost approach. TDU Systems argues that this proposal would
inflict no harm on the utility, which would be fully compensated for
the stranded assets. It also suggests that the ability to purchase a
slice of the supplier's system would serve as an important bargaining
tool in stranded cost negotiations, which would help level the playing
field among the parties.
---------------------------------------------------------------------------
\839\ E.g., TDU Systems, Arkansas EC.
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Other mitigation proposals include: (i) Requiring each utility to
prepare a mitigation plan under the supervision of an independent
expert that must be approved by the parties or by the Commission before
stranded cost recovery is permitted; \840\ (ii) requiring a utility to
report annually for a five-year period its mitigation activities and to
identify its stranded costs yet to be recovered; \841\ and (iii)
setting the market value of the displaced capacity at a high level
(thereby reducing the stranded cost charge) to provide a mitigation
incentive.\842\ A number of commenters support customer-controlled
mitigation, arguing, among other things, that the entity responsible
for paying stranded costs has the best incentive to mitigate them.\843\
Others support some form of utility sharing of stranded costs to give
utilities an incentive to mitigate stranded costs.\844\
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\840\ See, e.g., CA Energy Co.
\841\ See, e.g., PSNM.
\842\ See WP&L.
\843\ E.g., EEI, PA Com, AMP Ohio, TAPS.
\844\ E.g., ABATE, Fertilizer Institute, IL Com, KS Com, San
Francisco, UT Industrials, ELCON, CA Energy Co, MT Com, Caparo, WA
Com, Education, NRRI, NY Energy Buyers, Reynolds, DOD, DC Com.
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b. Reasonable Expectation Period (Period of Expected Continued Service)
Numerous commenters oppose setting absolute limits on the period
over which a customer's liability for stranded costs would be
determined.\845\ They suggest instead that the Commission should apply
the facts of each case, including the facts used to prove a reasonable
expectation of continued service, to its determination of a reasonable
expectation period. Among the factors commenters propose for
consideration are: the utility's planning horizon; the average
remaining life of the utility's generating facilities or a specific
number of years that coincides with the duration of a utility-specific
stranded cost recovery plan; utility projected load growth; dedicated
facility construction lead times; estimated time to market stranded
assets; the lesser of the utility's need date for new generation or the
cross-over date when the market generation price is expected to equal a
customer's embedded cost less other charges and compensation; and the
period for which estimated revenues exceed market values. Commenters
representing the financial community \846\ oppose limiting cost
recovery from the departing generation customer based on the term of
the contract. They argue that it was reasonable for a utility to expect
to continue to serve a customer, or customers who would take its place,
through the life of the assets; otherwise, the asset could not have
been financed in the first place.
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\845\ See, e.g., Florida Power Corp, Central and South West, Com
Ed, EEI, Montana, PECO, Minnesota DPS, NIMO, NSP, SoCal Edison, PA
Com, Central Louisiana, Utility Investors Analysts, Salt River,
Orange & Rockland.
\846\ E.g., Utility Investors Analysts and Utility Shareholders.
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A number of other commenters urge the Commission to prescribe
limits on a customer's maximum liability.\847\ Some commenters believe
that the utility's planning horizon is the reasonable expectation
period.\848\ PSE&G states that since utilities invested and incurred
costs to serve customers based on the planning horizon, the planning
horizon is the only logical period. Other commenters propose that the
reasonable expectation period be limited to one contract extension
period, or to the shortest of: (i) One additional contract renewal
period; (ii) the utility's planning horizon; (iii) the period it would/
does take for load growth on the seller's system to absorb the lost
load; or (iv) the contractual notice period.\849\ Other suggested
limits include the weighted average remaining life of all generating
assets; \850\ the in-service date of the utility's next avoidable
generating unit or purchased power contract that is projected to have a
capacity factor comparable to the departing generation customer's load
factor minus a one-time mitigation effort; \851\ and a rebuttable
presumption that two years is the maximum time for a utility reasonably
to expect to receive revenue from tariff sales or ``open-ended''
contracts.\852\
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\847\ E.g., NIEP, TAPS, Allegheny, Central Montana, Municipal
Energy Agency Nebraska, PSNM, ABATE, ELCON, PSE&G, UtiliCorp.
\848\ E.g., PSE&G, PSNM, ELCON, Oklahoma G&E, Duke. Oklahoma G&E
supports use of the utility's planning cycle for retail stranded
costs and use of the contract term for wholesale stranded costs.
Duke states that the Commission should permit the customer and the
transmission provider to establish the compensation period at
something less than the maximum period.
\849\ E.g., UtiliCorp, WP&L, Missouri Joint Commission, TAPS,
Municipal Energy Agency Nebraska, TDU Systems.
\850\ E.g., Carolina P&L.
\851\ E.g., FL Com.
\852\ E.g., UT Industrials.
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Other commenters propose recovery periods that range from three to
five years (e.g., Central Montana EC),\853\ five years (e.g., Public
Power Council), and eight years (e.g., Allegheny).\854\
---------------------------------------------------------------------------
\853\ Central Montana describes as ``excessive'' the recovery
period offered to it by Montana. Central Montana states that it gave
notice under a five-year notice provision and that Montana responded
with a stranded cost demand extending 14 years after notice of
termination (nine years from the date service would terminate).
\854\ Allegheny would exempt three types of stranded costs from
such a limit: (1) Those due to PURPA power purchases (it submits
that these were federally-mandated rather than profit-motivated
business decisions); (2) those due to regulatory assets (such as
deferred taxes); and (3) those due to municipalization. In addition,
it favors establishing a rebuttable presumption that these special
costs are eligible for stranded cost recovery.
---------------------------------------------------------------------------
GA Com and AZ Com state that stranded cost recovery should not go
on indefinitely. GA Com states that stranded costs should be collected
for a sufficient period of time to ensure full recovery and
indifference on the part of the utilities' remaining native load
customers. AZ Com states that a specific termination period will also
create an incentive for utilities to mitigate stranded costs.
c. Proposed Stranded Cost Recovery Procedures
Several commenters \855\ urge the Commission to be flexible in
evaluating proposed mechanisms for recovery of stranded costs,
including the payment method, noting that an approach suitable to one
utility and its customers may not be suitable to another. They say that
utilities within a region might find a mechanism that meets their
region's unique characteristics.
---------------------------------------------------------------------------
\855\ E.g., EEI, Centerior, PECO, Houston L&P, Salt River.
---------------------------------------------------------------------------
Some commenters oppose certain aspects of the procedures proposed
in the NOPR. For example, TAPS objects that the NOPR procedure aimed at
providing advance notice to the customer of its potential stranded cost
obligation resembles the procedure rejected in Cajun. It says that
``the customer will likely be forced to spend significant time and
resources `litigat[ing] to determine the price of a product(,)' thereby
`introduc[ing] deal-killing transactional costs and uncertainties.' ''
(citing Cajun, 28 F.3d at 179). TAPS proposes that the seller be
required to produce a stranded cost estimate that reflects a good
faith, reasonable estimate of the likely impact of mitigation and that
sellers making excessive and unsupported stranded cost claims be
penalized. At a minimum, it argues that the seller should be held
responsible for the costs
[[Page 21658]]
reasonably expended by the buyer to litigate the stranded cost claim.
DE Muni asserts that if filing a complaint to redress grievances
related to the recovery of stranded costs is to be a meaningful remedy,
the final rule should set a time limit within which the complaint must
be resolved.
A number of commenters offer modifications to the recovery
procedures set forth in the NOPR, including: (1) Extending a utility's
response time for providing stranded cost liability estimates from 30
days to at least 60 days; \856\ (2) requiring a utility to provide to
each wholesale customer within six months of the effective date of the
final rule: (a) The formula that the utility proposes to use to
calculate the customer's maximum possible stranded cost exposure
without mitigation; and (b) an actual calculation of the customer's
stranded cost exposure assuming the customer left the utility's system
six months after the effective date of the final rule; \857\ (3)
allowing customers that desire to litigate their stranded cost
liability to do so in a forum in which all litigating customers
participate; \858\ (4) requiring utilities to disclose their estimated
transition cost liabilities (and the nature of those liabilities)
before the effective date of the final rule to permit a realistic
evaluation of the scope of the transition cost problem and possibly
facilitate resolution of some disputes by settlement; \859\ (5)
requiring any utility seeking stranded cost recovery to provide a list
of the stranded facilities to the departing generation customer and
offer that customer an equity position in those facilities in return
for payment of stranded costs, thereby enabling the departing customer
to recover some of its stranded costs payment when any of the
facilities becomes useful again; \860\ (6) requiring a ``good faith
request'' for an estimate of stranded costs based on an expected date
of departure from the providing utility's system and mitigation efforts
expected to be undertaken by the utility; \861\ and (7) requiring
documented evidence that a utility made a good faith attempt to settle
with a departing generation customer before the utility is given the
opportunity to recover stranded costs.\862\
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\856\ E.g., Entergy.
\857\ E.g., Associated Power.
\858\ E.g., Associated Power.
\859\ E.g., Texaco.
\860\ E.g., Heartland.
\861\ E.g., PSNM, ELCON.
\862\ E.g., ELCON.
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Commission Conclusion
We reaffirm our proposal that the determination of recoverable
stranded costs should be based on the ``revenues lost'' approach. We
find that the revenues lost approach is the fairest and most efficient
way to balance the competing interests of those involved.
After careful consideration of the comments submitted, we have
decided to adopt the following formula for calculating a departing
generation customer's stranded cost obligation (SCO), on a present
value basis, under a revenues lost approach:
SCO=(RSE-CMVE x L
where:
RSE=Revenue Stream Estimate--average annual revenues from the departing
generation customer over the three years prior to the customer's
departure (with the variable cost component of the revenues clearly
identified), less the average transmission-related revenues that the
host utility would have recovered from the departing generation
customer over the same three years under its new wholesale transmission
tariff.\863\
---------------------------------------------------------------------------
\863\ In the case of a retail-turned-wholesale customer,
subtraction of distribution system-related costs may also be
appropriate.
---------------------------------------------------------------------------
CMVE=Competitive Market Value Estimate--determined in one of two ways,
at the customer's option: Option (1)--the utility's estimate of the
average annual revenues (over the reasonable expectation period ``L''
discussed below) that it can receive by selling the released capacity
and associated energy, based on a market analysis performed by the
utility; or Option (2)--the average annual cost to the customer of
replacement capacity and associated energy, based on the customer's
contractual commitment with its new supplier(s).
L=Length of Obligation (reasonable expectation period)--refers to the
period of time the utility could have reasonably expected to continue
to serve the departing generation customer. We reaffirm that we do not
believe that a one-size-fits-all approach is appropriate for
determining the length of a customer's obligation. If the parties
cannot reach agreement as to the length of the customer's obligation,
this period is to be determined through litigation as a part of the
threshold issue of whether the utility had a reasonable expectation of
continuing to serve the customer.
Application of the foregoing formula and collection of the
resulting stranded costs are subject to the following conditions:
1. Cap on SCO. The quantity (RSE-CMVE) can be no greater than the
average annual contribution to fixed power supply costs (defined as RSE
less variable costs) that would have been made by the departing
generation customer had it remained a customer.
2. Changes in Customer Revenues. If the customer's rates (or
contract demand amounts, if relevant) changed during the three-year
period prior to the termination of its existing requirements contract,
then the RSE should be calculated using the customer's most recent 12
months of revenue.
3. CMVE Option 2 Conditions. Option 2 (a CMVE equal to the average
cost to the customer of replacement capacity and associated energy)
would be available to a customer whose alternative purchase(s) runs
concurrent with L, or, if longer than L, contains rates that do not
fluctuate over the duration of the contract. The customer would be
required to demonstrate (at the time it chooses this option) that the
replacement capacity contract(s) is for service equivalent to the
released capacity (that is, firm power for a period at least equal to
L), and must also clearly identify the rates to be paid for the
replacement service.
4. Payment Options. The method and term of payment should be
negotiated, but is ultimately left to the customer's discretion.
Possible payment options include a lump-sum payment, an amortization of
a lump-sum payment over a reasonable period of time, or a surcharge on
the customer's transmission rate.
5. Applicability. The formula is designed for determining stranded
costs associated with departing wholesale generation customers and for
retail-turned-wholesale customers.864
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\864\ The formula is not to be used for recovering stranded
costs associated with retail wheeling. We believe the formula is
unworkable in this scenario because one of its key elements--the
option for a customer to market or broker the utility's power--may
not be practicable for retail customers. Therefore, stranded costs
associated with retail wheeling will be determined on a case-by-case
basis.
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6. Marketing/Brokering Option. The Commission will allow the
customer, at its sole discretion, a choice to market the released
capacity and associated energy (or to contract with a marketer for such
service). Alternatively, the customer may choose to broker the released
capacity and associated energy (or to contract with a broker).865
---------------------------------------------------------------------------
\865\ The customer may also decide to remain a requirements
customer for L. If the customer elects to remain a requirements
customer, the utility will be obligated to continue service to the
customer for the duration of L.
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[[Page 21659]]
7. Released Capacity and Associated Energy. A utility requesting
stranded cost recovery must indicate the amount of system capacity and
the amount of associated energy released by the departing generation
customer and used in the revenues lost calculation. This will allow the
departing generation customer to fairly consider exercising a choice to
market or broker the released capacity and associated energy.
The formula balances a number of goals, including: (1) Ensuring
full recovery of legitimate, prudent and verifiable stranded costs; (2)
requiring the utility to mitigate stranded costs; (3) providing
certainty for departing generation customers; and (4) creating
incentives for the parties to renegotiate their existing requirements
contracts or otherwise settle stranded cost claims without resort to
litigation.
Contrary to the objections of some commenters that the revenues
lost approach creates no incentive to mitigate stranded costs, the
formula automatically encompasses mitigation by reducing the departing
generation customer's stranded cost obligation by the competitive
market value of the released capacity and associated energy. Further,
the option provided in the formula for a customer to market or broker
the released capacity and associated energy protects the customer from
a utility trying to overrecover stranded costs by estimating a low
value for the released capacity and associated energy and thereby
provides the customer some assurance that stranded costs will be
minimized. Specifically, if a customer believes the utility's
competitive market value estimate (CMVE) is too low, it can market or
broker the released capacity and associated energy and reduce its
stranded cost obligation.866 We accordingly will not impose a
separate mitigation obligation on the utility above that which is
already subsumed in the revenues lost approach. In addition, a utility
will continue to be subject to an ongoing prudence obligation to sell
excess capacity off-system and/or to dispose of uneconomic assets.
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\866\ This option also addresses the concerns of commenters
that, by failing to require auctions or divestiture of stranded
capacity, the Rule would allow a utility recovering stranded costs
to sell the freed capacity at subsidized prices, thereby gaining a
competitive advantage in other transactions. If the customer avails
itself of this option, the utility would no longer control the
released capacity.
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We recognize that some commenters oppose the revenues lost approach
as imprecise. However, any ratemaking method that relies on estimates
will be subject to forecasting error. Moreover, in direct response to
commenter concerns, we have gone to great lengths in this rule to
provide specificity with respect to the calculation of the components
of the formula. We believe that use of the formula will narrow the
scope of disputes over the calculation of stranded costs, lend
precision to the stranded cost amount it produces, and provide
certainty to departing generation customers with respect to their
stranded cost obligations.
Calculation of the Revenue Stream Estimate (RSE)
The RSE component of the formula is based on revenues paid by the
departing generation customer during the last three years of its
contract or retail service. We believe that the use of ``present''
revenues in the calculation of the revenue stream has numerous
advantages over other approaches advocated. The use of present revenues
eliminates disputes over estimates of future revenues, thereby adding
certainty to the calculation. It also eliminates the need for a
detailed listing of includable costs, relying instead on the assumption
that present rates include all of the utility's costs of providing
service. Further, the rates that produce present revenues have been
approved by regulators, which strongly suggests that the costs included
in them are prudent, legitimate and verifiable.867
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\867\ The present rates, whether established by settlement or
otherwise, have been found to be just and reasonable. In other
words, they are neither confiscatory nor exorbitant.
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We reject the suggestion by commenters that a utility be required
to calculate the revenue stream using any lower rate being offered by
the utility for service comparable to that being taken by the customer
when the customer departs the utility's generation system. A revenue
stream calculated in this manner could deny a utility the opportunity
to fully recover its stranded costs or could shift costs to other
customers, a result we find unacceptable. Similarly, the elimination of
return-related revenues from the revenue stream effectively would
require shareholders to absorb stranded costs, which is contrary to our
determination that a utility is entitled to an opportunity to fully
recover legitimate, prudent and verifiable stranded costs.
Calculation of the Competitive Market Value Estimate (CMVE)
We recognize the difficulty associated with estimating the
competitive market value of the capacity and associated energy not
purchased by the departing generation customer. However, we believe
that an up-front estimate, which provides flexibility to the utility
and a measure of certainty to customers, is superior to other
proposals, provided the right mix of incentives and options is included
in the formula.
A utility requesting stranded cost recovery must estimate CMVE
based on a market analysis, with all assumptions and work papers made
available to the departing generation customer. This provides a utility
with the flexibility to choose the methodology that it feels produces
the best estimate of the competitive market value of the released
capacity and associated energy. We note that numerous proposals for
calculating competitive market value were made in the comments. The
Commission believes that the flexibility provided by the formula we
adopt in this Rule permits the filing utility to avail itself of many
of these recommendations.
At the same time, a utility may have an incentive to underestimate
CMVE and thereby increase the stranded costs charge. To address this
issue, the formula contains several features designed to create an
incentive to produce a good faith estimate of stranded costs and to
safeguard customers if a utility fails to do so. For example, the
formula provides a departing generation customer with the option to
market or broker the released capacity and associated energy if it
believes the utility's estimate is too low. If the marketing option is
chosen, the customer would buy the released capacity from the utility
at the utility's market value estimate. The associated energy would be
purchased at the utility's average system variable cost. The customer
would then resell the released capacity and energy and keep the
resulting revenues. If the revenues it receives are greater than the
utility's market value estimate, the customer will have reduced its
stranded cost obligation. If the customer chooses the brokering option
and the released capacity and associated energy are purchased by a
third-party for more than the utility's market value estimate, the
difference between the average annual revenues produced by the sale and
the utility's CMVE estimate will be used to lower the customer's
stranded cost obligation. The utility may be required to show in a
compliance filing that it has reduced the customer's stranded cost
obligation under such circumstances.
If the customer chooses CMVE Option 2 and meets its conditions,
CMVE will be set at the average price that the customer pays its new
supplier. The customer will test the market and choose the best deal
available. Hence,
[[Page 21660]]
the price the customer pays its alternative supplier is arguably a more
accurate measure of the competitive market value of the capacity and
associated energy not taken from the host utility. Whether to exercise
Option 2 resides solely with the customer.
We further note that the sale of all or part of a utility's
generating assets could be used as a method to determine competitive
market value of such assets. Under the theory that an asset sale price
reflects the highest value for the utility's assets, the Commission
would presume that the competitive market value established under an
open asset sale (i.e., an offer to sell assets to any taker) would
fully satisfy the utility's responsibility to minimize stranded costs.
If a stranded cost claim involves divestiture of assets, the amount of
stranded costs associated with those assets would be the book value
less the sale price. The Commission would determine the appropriate
stranded cost charge based on the facts presented.
Snapshot Approach Versus True-Ups
The revenues lost formula is based on a one-time snapshot approach.
We favor this approach over the true-up approach because it creates
certainty and will produce reasonably accurate results. True-ups, on
the other hand, while theoretically more accurate, require periodic
recalculation of stranded costs, which creates ongoing uncertainty and
disputes. In addition, true-ups will result in additional transaction
costs. We believe that an approach that provides certainty and
establishes cost responsibility up front is best for what is
fundamentally a transition issue.
Implementation Procedures 868
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\868\ These procedures apply to a potential departing generation
customer who is an existing wholesale requirements customer of a
public utility, or a retail customer of a public utility who is
contemplating becoming a wholesale transmission customer (such as
through municipalization). They may be used at the option of the
potential departing generation customer. An existing wholesale
requirements customer may use the procedures in conjunction with, or
in lieu of, a complaint under section 206 to amend its existing
requirements contract to add an explicit stranded cost provision, as
discussed in Section IV.J.5.
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In the Supplemental Stranded Cost NOPR, we proposed procedures to
provide a potential departing generation customer with advance notice
of how the utility would propose to calculate costs that the utility
claims would be stranded by the customer's departure.869 These
procedures are modified as follows to incorporate the findings made in
this rule:
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\869\ FERC Stats. & Regs. para. 32,514 at 33,114-15; 33,128-29.
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(1) A customer may, at any time before the termination date
specified in its existing wholesale requirements contract,870
request the public utility to provide an estimate of the customer's
stranded cost obligation based on the revenues lost formula contained
in this Rule,871 as of the date set forth in the customer's
request. The customer should specify in its request, to the extent
possible, pursuant to its rights under its power sales requirements
contract with the seller,872 the date on which the customer is
considering substituting alternative generation for the requirements
purchase and the amount of the substitute generation. Any remaining
generation requirements to be purchased from the existing supplier
after this date should be clearly indicated. The customer may seek
further information on how the stranded cost charge would vary as a
result of choosing different dates or different amounts of substitute
purchases. The customer also should indicate its preferred payment
method, such as a lump-sum payment, an amortization of a lump-sum
payment, or a surcharge (such as monthly or annual) on the customer's
transmission rate.
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\870\ If the customer is a retail customer contemplating
becoming a wholesale transmission customer, it may at any time
request the public utility to provide an estimate of its stranded
cost obligation.
\871\ Because the formula reduces a customer's stranded cost
obligation by the competitive market value of the capacity and
associated energy that would be released by the customer's
departure, we will not adopt the proposal in the Supplemental
Stranded Cost NOPR to allow a potential departing customer to
receive an estimate of the customer's ``maximum possible stranded
cost exposure without mitigation.'' Requiring the utility to provide
an estimate that reflects the competitive market value of the
capacity and associated energy to be released will better enable the
customer to assess its supply options.
\872\ If the customer is a retail customer contemplating
becoming a wholesale transmission customer, it should specify in its
request, to the extent possible, the date on which the customer is
considering becoming a wholesale transmission customer of the
utility and the amount of generation, if any, it will continue to
purchase from its existing supplier.
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(2) The utility shall, within thirty days of receipt of the
request, or other mutually agreed-upon period, provide the customer
with an estimate of the customer's stranded cost obligation. The
response shall include: (i) Estimates of RSE, CMVE, and L according to
the revenues lost formula and based on the information supplied by the
customer; (ii) supporting detail (including the underlying market
analysis that forms the basis for the CMVE estimate) indicating how
each element in the formula is derived to enable the customer to
understand the basis for each element; (iii) a detailed rationale
justifying the basis for the utility's reasonable expectation of
continuing to serve the customer beyond the termination date in the
contract; 873 (iv) an estimate of the amount of released capacity
and the amount of associated energy that would result from the
customer's departure, based on the information supplied by the
customer, including detailed support for the amount of the released
capacity and the amount of associated energy, and the market value of
each, for each year of the reasonable expectation period, and how those
amounts are consistent with the RSE and CMVE estimates; and (v) the
utility's proposal for any contract amendment needed to implement the
customer's payment of stranded costs (the proposed modification should
also reflect the customer's chosen payment method).
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\873\ If the customer is a retail customer contemplating
becoming a wholesale transmission customer, the utility should
provide a detailed rationale justifying the basis for its reasonable
expectation of continuing to provide the customer bundled retail
service.
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(3) If the customer believes that: (i) The utility has failed to
establish that it had a reasonable expectation of continuing to serve
the customer beyond the contract term; 874 (ii) the proposed
stranded cost charge (or any of the elements used to compute it) is
unreasonable; (iii) the amount of released capacity and the amount of
associated energy assumed to be sold is unreasonable; or (iv) the
utility's proposal for any contract amendment needed to implement the
customer's payment of stranded costs is unreasonable, the customer will
have thirty days in which to respond to the utility explaining why it
disagrees. The Commission expects parties to attempt to resolve any
disputed issues.
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\874\ Subsection (i) above also would apply to a retail customer
contemplating becoming a wholesale transmission customer if the
customer believes that the utility has failed to establish that it
had a reasonable expectation of continuing to provide the customer
bundled retail service.
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(4) If the parties are unable to resolve the matter using the
procedures in (1)-(3) above, the customer may either: (a) File a
petition for declaratory order, or a section 206 filing seeking to
amend an existing requirements contract, to seek a Commission
determination as to whether: (i) The utility has met the reasonable
expectation standard; (ii) the proposed stranded cost charge satisfies
the other evidentiary standards set forth in this Rule; (iii) the
amount of released capacity and the amount of associated energy
proposed by the utility is reasonable; or (iv) the utility's proposal
for any contract amendment needed to implement the customer's payment
of
[[Page 21661]]
stranded costs is reasonable; or (b) wait until the proposed stranded
cost charge is filed by the utility under section 205 of the FPA, and
contest it at that time.875 In either case, because estimates of
RSE and CMVE may change over time, any estimate of stranded costs
provided by a utility to a customer will not be considered binding
prior to any filing by either party with the Commission. However, any
stranded cost estimate filed by the utility in a section 205 or 206
proceeding, or in response to a petition for a declaratory order, shall
be considered to be a binding estimate of the customer's maximum
stranded cost obligation for purposes of litigation. Similarly, any
estimate of stranded cost obligation filed by a customer in a petition
for declaratory order or a section 205 or 206 proceeding shall be
considered to be a binding estimate of the customer's minimum stranded
cost obligation for purposes of litigation.876 Estimates of
stranded cost obligation that are filed by either party with the
Commission shall include the information, including the supporting
detail, identified in (2) above.
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\875\ As discussed above, retail customers contemplating
becoming wholesale transmission customers may use the same
procedures. As also discussed above, customers under existing
requirements contracts with public utilities have the option of
making a filing under section 206 seeking to amend the contract to
add an explicit stranded cost provision, without having to go
through these procedures.
\876\ Although estimates by the utility or the customer may be
binding for purposes of litigation, this does not mean that the
parties may not settle at any time on another amount.
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(5) If a utility intends to file for stranded cost recovery from a
customer through either a stranded cost amendment to its existing
contract or a surcharge on transmission rates, it must file its
stranded cost estimate no later than 120 days prior to the end of the
customer's contract term. The filing shall include the information,
including the supporting detail, set forth in (2) above. The customer,
of course, may contest the contents of such a filing.877
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\877\ A customer requesting a section 211 order for transmission
services from a transmitting utility also may incur a stranded cost
obligation. Any estimate of stranded cost obligation resulting from
the requested transmission services should be included as part of
the utility's good faith response to the customer's request for
transmission services. See 18 CFR 2.20. Because the Commission will
apply the revenues lost formula to any request for stranded cost
recovery as a part of its determination of the appropriate charge
for transmission services ordered in a section 211 proceeding, we
encourage non-public utilities to use the revenues lost formula to
estimate a customer's stranded cost obligation.
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Conditions of the Marketing/Brokering Option
A customer may choose to market or broker a portion or all of the
released capacity and associated energy identified by the utility in
its stranded cost estimate (or to contract with a marketing/brokering
agent). Importantly, by exercising the marketing or brokering option,
the customer does not relinquish its right to contest any aspect of the
utility's stranded cost estimate, including whether the utility is
entitled to recover stranded costs for the period that the customer has
agreed to market or broker any released capacity and associated energy.
To implement this option, a customer must inform the utility in writing
of its decision no later than 30 days after the utility files its
estimate of stranded costs for the customer with the Commission. Before
marketing or brokering of the released capacity and associated energy
can begin, the utility and customer must execute an agreement
identifying, at a minimum, the amount of capacity and associated energy
the customer is entitled to schedule, the price of capacity and
associated energy, and the duration of the customer's marketing/
brokering of the released capacity and associated energy. Parties are
encouraged to settle disputes over these and any other marketing/
brokering implementation issues. The negotiations should be guided by
the principle that the utility must allow the customer to market or
broker the released capacity and associated energy under terms and
conditions comparable to those for a utility resale of the capacity and
associated energy to a third party. If agreement over marketing or
brokering cannot be reached, the parties may seek to include the issue
as a part of a proceeding initiated at the Commission with respect to
the utility's stranded cost estimate for the customer.878 Upon
issuance of an order resolving the disputed issues, the customer may
reevaluate its decision to exercise the marketing/brokering option. The
customer also may choose to market or broker any released capacity and
associated energy not being marketed or brokered under an earlier
agreement with the utility. A customer must notify the utility in
writing within 30 days of issuance of the Commission's order resolving
the disputed issues whether the customer will market or broker a
portion or all of the capacity and energy associated with stranded
costs allowed by the Commission.
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\878\ Because litigation of stranded costs may extend beyond the
date of the customer's departure, the customer may also file a
petition for a declaratory order requesting expedited resolution of
marketing or brokering implementation issues.
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Payment for Released Capacity and Associated Energy Under the Marketing
Option
If the customer chooses to market released capacity and associated
energy, it shall pay the utility's estimate of the competitive market
value of the capacity, or, if the marketing option is exercised after a
Commission order, it shall pay the competitive market value amount as
determined by Commission order. In addition, for all energy scheduled
to be delivered, the customer shall pay the utility's average system
variable costs. The customer may also choose to market only a portion
of the released capacity and/or for a shorter period. In this
situation, the customer will also pay the competitive market value for
the released capacity plus the utility's average system energy costs.
The customer's liability for payment of stranded costs is unaffected by
its decision to market released capacity and associated energy.879
In addition, to the extent that the customer chooses to market a
portion or all of the capacity alleged by the utility to be stranded, a
final determination with respect to the customer's stranded cost
obligation will not affect any prior marketing agreement.
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\879\ If the customer can market the released capacity and
associated energy for a higher price than the customer paid for it,
the customer effectively reduces its stranded cost obligation, i.e.,
the incremental revenue received offsets a portion of the customer's
stranded cost payment to the utility.
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Payment for Stranded Costs Under the Brokering Option
If the customer chooses to broker a portion or all of the released
capacity and associated energy, any revenue received from such
brokering activity shall be used to offset the utility's estimate of
the competitive market value of the brokered capacity and associated
energy.880 Once a brokering agreement is executed between the
customer and the utility, if the customer's brokering efforts fail to
produce a buyer within 60 days of the date of that agreement, the
customer shall relinquish all rights to broker the released capacity
and associated energy and will pay stranded costs as determined by the
formula.
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\880\ For example, if the customer brokers any released capacity
and associated energy for a higher price than the utility's
estimated competitive market value of that capacity and energy, the
difference between the utility's estimate and the brokered price
will be used to increase the utility's CMVE component of the
stranded cost calculation, thereby reducing the customer's stranded
cost obligation.
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[[Page 21662]]
10. Stranded Costs in the Context of Voluntary Restructuring
In the Supplemental Stranded Cost NOPR, we noted that the
functional unbundling of wholesale services does not require corporate
unbundling (such as disposition of assets to a non-affiliate, or
establishing a separate corporate affiliate to manage a utility's
transmission assets). At the same time, we indicated that some
utilities may ultimately choose some form of corporate
unbundling.881 We reaffirm in this Final Rule that we are willing
to consider case-specific proposals for dealing with stranded costs in
the context of any restructuring proceedings that may be instituted by
individual utilities.
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\881\ FERC Stats. & Regs. para.32,514 at 33,132.
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11. Accounting Treatment for Stranded Costs Comments
A number of commenters ask the Commission to provide accounting
treatment guidance as part of its procedures for implementing its
policies on stranded costs and their recovery.882
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\882\ See, e.g., EEI, NSP, LILCO, Central Hudson, Deloitte &
Touche, Centerior.
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NSP states that the Commission will need to provide appropriate
accounting guidance for the final stranded cost recovery methodology,
including accounting for any portion of stranded cost recovery
representing capital costs, the effect of any interperiod differences
between the stranded cost calculations and the authorized recovery
period, and the effects of differences between book and income
implications of the stranded cost recovery mechanism. NSP also asserts
that, in addressing the accounting implications of the final rule, the
Commission must consider the requirements of the Financial Accounting
Standards Board (FASB) Statement of Financial Accounting Standards No.
121, ``Impairment of Long-Lived Assets'' (SFAS No 121).
NASUCA states that one of the Commission's stated goals in
providing stranded cost recovery is to protect against cost shifting.
NASUCA argues that the Commission should adopt an accounting rule that
assures that any federal resolution of wholesale stranded costs does
not impose any cost shifting to captive customers.
EEI and Centerior argue that the Uniform System of Accounts as
presently configured does not support the Commission's proposed
policies on stranded cost recovery. Further, EEI states that even with
the revenues lost approach, which EEI supports, utilities will still
have to account for their assets on a class-of-asset by class-of-asset
basis. EEI argues that this is necessary to ensure that the costs of
the assets are expensed in the proper accounting period. EEI states
that one of the basic principles of financial accounting is that
expenses should be matched with the related revenues.
Commission Conclusion
As discussed in Section IV.J.3, this rule adopts a direct
assignment approach for the recovery of stranded costs from departing
generation customers. Under the revenues lost approach, stranded cost
recovery is limited to the departing generation customer's contribution
to fixed costs that the utility otherwise would not recover because of
the customer's departure.
We recognize that there are certain similarities between the
financial reporting objectives of SFAS No. 121 and the determination of
stranded costs. However, there are also important differences between
SFAS No. 121 and our approach to stranded costs. The revenues lost
approach does not
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
attempt to identify specific uneconomic assets and is
not limited to only long-lived assets. Instead, it uses a formulary
methodology that encompasses all fixed costs of providing service.
From a financial accounting standpoint, our approach to stranded
costs creates the potential for a mismatch between the periods in which
the stranded costs are charged to expense and any revenues provided for
their recovery are included in net income determinations. This is
because the earning process entitling a utility to the benefits of
stranded cost recovery and thereby requiring the recognition of revenue
may be completed prior to the time that the stranded costs must be
charged to expense under generally accepted cost recognition criteria.
This circumstance in a cost-based regulated environment creates the
undesirable potential for double recovery of the same cost, cost
shifting, and inappropriate financial reporting.
In order to avoid this potential, utilities shall not recognize
revenues intended to provide for recovery of stranded costs from
wholesale requirements customers prior to the time that the stranded
costs are charged to expense, unless prior Commission approval to do so
has been obtained. Absent Commission approval, utilities shall defer
such amounts in Account 253, Other Deferred Credits, and amortize them
to Account 456, Other Electric Revenues, consistent with the period the
related costs are charged to expense. Also, we will require a utility
to submit its proposed accounting for stranded costs and related
revenues as part of its rate filing requesting recovery of stranded
costs under section 205 of the FPA.
12. Definitions, Application, and Summary
In the Supplemental Stranded Cost NOPR, the Commission described
proposed amendments to our regulations to establish filing requirements
for public utilities and transmitting utilities that seek stranded cost
recovery. We proposed to define ``wholesale stranded cost'' as ``any
legitimate, prudent and verifiable cost incurred by a public utility or
a transmitting utility to provide service to: (i) A wholesale
requirements customer that subsequently becomes, in whole or in part,
an unbundled wholesale transmission services customer of such public
utility or transmitting utility, or (ii) a retail customer, or a newly
created wholesale power sales customer, that subsequently becomes, in
whole or in part, an unbundled wholesale transmission services customer
of such public utility or transmitting utility.'' We sought comments on
whether this definition should encompass the situation where a
wholesale requirements customer ceases to purchase power from the
utility that had been making wholesale requirements sales to such
customer without becoming an unbundled transmission services customer
of that utility.883
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\883\ FERC Stats. & Regs. para. 32,514 at 33,115.
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Comments
We received numerous comments both supporting and opposing
revisions to the proposed definition of wholesale stranded
costs.884 Several commenters oppose broadening the definition to
include costs stranded by customers that do not become unbundled
transmission service customers of the former supplier.885 For
example, EGA argues that the loss of an industrial customer that
chooses to self-generate or the loss of a requirements customer as a
result of a newly-created municipal system that interconnects with a
transmitting utility that is not the customer's former supplier could
have happened at any time. EGA states that revenues lost as a result of
either
[[Page 21663]]
scenario have nothing to do with regulatory reforms and should not be
considered ``stranded'' costs.
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\884\ EEI asks the Commission to expand the definition of
stranded costs to account for the case where the Commission has
proposed to address purely retail stranded costs (that is, where a
state regulatory authority does not have authority to address
stranded costs at the time that retail wheeling is required).
However, the regulations will contain a definition of ``retail
stranded costs'' to account for this case. See Sec. 35.26(b)(5) of
the Final Rule.
\885\ E.g., EGA, Direct Service Industries, Memphis.
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Other commenters disagree.886 Puget asserts that permitting
departing generation customers to avoid paying stranded costs if they
do not take unbundled transmission from their former suppliers would
create an incentive for departing customers (or their new electric
suppliers) to build unneeded and uneconomic new transmission lines.
Puget says that it also could be a disincentive to engage in regional
transmission planning and coordination because the existence of new
transmission facilities needed to achieve regional reliability and
efficiency may increase the likelihood that departing generation
customers could import their power supplies over those new facilities
and avoid paying the utility's stranded costs.887
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\886\ E.g., Atlantic City, Carolina P&L, Consumers Power,
Minnesota Power, Knoxville, Alma, Florida Power Corp, El Paso,
Central Louisiana, Southern, WP&L, FL Com, Utility Investors
Analysts, Florida Power Corp, El Paso, Central Louisiana, TDU
Systems, NW Conservation Act Coalition, Puget, NU, EEI.
\887\ Several commenters also ask the Commission to expand the
definition of wholesale stranded cost to include the situation where
a wholesale supplier loses wholesale load as a result of a
requirements customer's loss of retail load because of retail
wheeling, municipalization or retail taps from another utility's
system. E.g., Utilities For Improved Transition, Montaup, SC Public
Service Authority. In addition, a number of commenters ask the
Commission to treat the members of a single G&T cooperative system
as a single economic unit and to revise the definition of wholesale
stranded costs to allow a transmitting G&T cooperative (the arm of
the cooperative system that provides the transmission) to recover
the costs stranded when a retail customer of one of its member
distribution cooperatives takes advantage of the open access
environment by becoming a wholesale entity. E.g., Big Rivers EC,
NRECA, Tri-County EC, TDU Systems.
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Some of these commenters propose using an exit fee to collect
stranded costs from a customer that does not take unbundled
transmission from its former supplier, since a transmission surcharge
is not available in this circumstance.888 Other methods proposed
include: (1) Conditioning Commission approval of the transmission rates
or wholesale power rates charged by the transmission-providing utility
upon the inclusion of a surcharge to recover the former supplier's
stranded costs or upon the transmission-providing utility otherwise
agreeing to guarantee the payment of the stranded costs or act as
billing agent for the former supplier; 889 (2) authorizing the
former supplier to levy a stranded cost charge on the transmission-
providing utility (if that utility is interconnected with and has
transmission contracts with the former supplier); (3) if a retail
customer becomes annexed to a municipal utility and does not take
unbundled transmission services from its former supplier, permitting
recovery of stranded costs from the municipal utility through its
jurisdictional transmission rates; or (4) requiring a public utility
providing transmission service for a customer that has left its former
supplier to agree, as a condition to recovery of its own stranded
costs, to ensure the payment of any stranded costs incurred by the
former supplier.890
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\888\ E.g., Carolina P&L, NU, Florida Power Corp, PSNM,
Southern, Mountain States Petroleum Assoc, FL Com.
\889\ In its reply comments, Memphis Light objects to the
proposal that the Commission condition approval of all new power
contracts for those customers that leave a utility's system without
using the transmission services of the original utility upon the
inclusion of a provision to recover the stranded cost for the
previous power supplier. It argues that this proposal could result
in nonrecovery from some customers because wholesale customers faced
with such a provision would pursue non-jurisdictional contracts and/
or generate within the confines of their own systems.
\890\ E.g., EEI, El Paso, NU, Atlantic City, PG&E, Coalition for
Economic Competition, NW Conservation Act Coalition, Puget, NRECA,
Cajun, East Kentucky, FL Com, Associated EC, Utilities For Improved
Transition, TDU Systems, TVA.
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Commenters also address the use of the terms ``legitimate, prudent,
and verifiable'' in the definitions of wholesale and retail stranded
costs. Several commenters suggest that the Commission's use of the word
``prudent'' could imply that utilities have to relitigate the prudence
of costs that the Commission and state commissions have already
approved; these commenters believe that utilities should not have to
relitigate prudence.891 Some argue that once a regulatory agency
(state or federal) has allowed recovery of the costs in rates, or
promised future recovery, utilities should not have to undergo a second
regulatory review to recover those costs if they become
stranded.892
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\891\ E.g., EEI, NSP, Arizona, United Illuminating, Entergy,
SCG&E, PECO, NRECA.
\892\ E.g., EEI, Centerior, NSP, SCG&E, PECO, Tucson Power,
Arizona.
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Commenters recommend that the Commission address this situation by:
Striking the word ``prudent'' from the definition or specifying that
the prudence requirement is satisfied by previous regulatory
authorization; 893 dropping the terms ``legitimate, prudent and
verifiable'' from the definition and using instead ``allowed,''
``accepted,'' or ``allowable''; 894 or adding ``or approved by
state commission'' after the words ``legitimate, prudent and
verifiable'' in the definitions of both wholesale and retail stranded
costs.895
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\893\ E.g., PECO, Entergy.
\894\ E.g., EEI, SCG&E, Carolina P&L.
\895\ E.g., Atlantic City. EEI also proposes that at the time of
filing of a stranded cost recovery charge (whether as an amendment
to a contract or a surcharge to a transmission rate), the Commission
limit its inquiry to the issue of the stranded cost charge rather
than allowing all aspects of a rate or contract to be opened up. EEI
states that this is what the Commission did in the natural gas
context, where it permitted limited rate filing cases under section
4 of the NGA.
---------------------------------------------------------------------------
Other commenters oppose these proposals, suggesting that the
prudence analysis for stranded cost purposes may involve questions of
prudence different from those that arise in a ratemaking
context.896 DE Muni objects that replacing ``legitimate, prudent
and verifiable'' with ``allowed, accepted, or allowable'' could enable
a utility to recover costs that the utility may not be able to prove
were prudent, legitimate, and verifiable.
---------------------------------------------------------------------------
\896\ E.g., Alcoa, Cleveland.
---------------------------------------------------------------------------
A number of commenters submit that ``legitimate, prudent and
verifiable'' costs should not include the costs of uneconomic plants or
costs resulting from utilities' independent business decisions (as
distinguished from costs the utility was forced by regulation to
incur).897
---------------------------------------------------------------------------
\897\ E.g., Mountain States Petroleum Assoc, Caparo, Torco.
---------------------------------------------------------------------------
Several other commenters address the rule's application to
wholesale requirements customers.898 AMP-Ohio asks the Commission
to clarify that the reference to ``wholesale requirements customer'' is
to a full requirements customer, not a partial requirements customer.
It says that no transmission provider should have any reasonable
expectation of continuing to serve loads of partial requirements
customers. TAPS suggests that references to ``new wholesale
requirements contract'' in proposed Sec. 35.26(c)(1) should be
conformed to the defined term ``new contract'' in proposed
Sec. 35.26(b)(7). In addition, it suggests that the Commission clarify
the regulations by clearly foreclosing stranded cost claims for ``new
contracts'' without express exit fees, instead of simply failing to
provide for such recovery.
---------------------------------------------------------------------------
\898\ E.g., AMP-Ohio, PA Munis, TAPS.
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Commission Conclusion
We will retain the definition of ``wholesale stranded cost''
proposed in the Supplemental Stranded Cost NOPR.899 We believe it
would be inappropriate to expand the definition to include the
situation where a
[[Page 21664]]
wholesale requirements customer 900 (or a retail-turned-wholesale
customer) ceases to purchase power from the utility without using the
transmission services of that utility.901 Any costs that the
utility might incur as a result of the loss of the requirements
customer in this scenario would be outside the scope of this Rule. The
premise of this Rule is that, where a customer uses the new open access
to obtain power from a new generation supplier, the customer must pay
the costs that were incurred on its behalf under the prior regulatory
regime. However, if a customer leaves its utility supplier by
exercising power supply options (such as access to another utility's
transmission system or self-generation) that do not rely on access to
the former seller's transmission, there is no nexus to the new open
access rules.902 If a customer is able to obtain power from a new
supplier by using the transmission system of another utility, it is
likely that the customer could have made these arrangements in the
absence of the new open access rules. The new transmission provider
would have had little incentive to deny transmission services to the
customer in order to protect an existing power supply arrangement,
since it was not the customer's power supplier in the first place.
Indeed, it is likely that the neighboring utility would have a positive
incentive to provide the transmission service in order to increase its
revenues. This incentive is unchanged by open access transmission.
---------------------------------------------------------------------------
\899\ For the reasons articulated below, we accordingly will
reject the various revisions to the definition that were proposed by
commenters.
\900\ ``Wholesale requirements contract'' is defined as ``a
contract under which a public utility or transmitting utility
provides any portion of a customer's bundled wholesale power
requirements'' (emphasis added). Thus, a ``wholesale requirements
customer'' for purposes of the Rule can be either a full or a
partial requirements customer. We reject AMP-Ohio's suggestion that
the Commission make a blanket finding that a utility could not have
had a reasonable expectation of continuing to serve a partial
requirements customer. For example, a partial requirements customer
may have met part of its needs with its own generation but because
it could not build more of its own generation locally it had to
depend on the utility for the remainder of its needs in the absence
of the new open access. Also, a partial requirements customer may
have been able to reach alternative suppliers for only a portion of
its requirements due to transmission constraints. If this were the
case, the partial requirements supplier may well have had a
reasonable expectation of continuing to serve the balance of the
customer's load.
\901\ The definition of ``retail stranded cost'' contains a
similar requirement (i.e., the retail customer must become, in whole
or in part, an unbundled retail transmission services customer of
the public utility or transmitting utility from which the customer
previously received bundled retail services). We will retain it for
the same reasons discussed above.
\902\ As we have said, this Rule is not intended to insulate a
utility from the normal risks of competition.
---------------------------------------------------------------------------
Some commenters have asked us to eliminate the term ``prudent''
from the definition of stranded costs. We will not do so; we will
retain the requirement that stranded costs be ``legitimate, prudent and
verifiable.'' A determination that a utility had a reasonable
expectation of continuing to serve a customer would not, in all
circumstances, mean that costs incurred by the utility were prudent.
Prudence of costs, depending upon the facts in a specific case, may
include different things: e.g., prudence in operation and maintenance
of a plant; prudence in continuing to own a plant when cheaper
alternatives become available; prudence in entering into purchased
power contracts, or continuing such contracts when buy-outs or buy-
downs of the contracts would result in savings. The Commission
therefore cannot make a blanket assumption that all claimed stranded
costs will have been prudently incurred. However, we clarify that we do
not intend to relitigate the prudence of costs previously
recovered.903
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\903\ As the Commission has previously indicated, however, in
the case of formula rates, approval of a formula rate constitutes
approval of the formula, and not the underlying costs. See, e.g.,
New England Power Company, et al., 72 FERC para.61,148 at 61,761
(1995); Boston Edison Company, Opinion No. 376, 61 FERC para.61,026
at 61,145 (1992).
---------------------------------------------------------------------------
Thus, this Rule will permit a public utility or transmitting
utility to seek recovery of wholesale stranded costs as follows. First,
for stranded costs associated with new wholesale requirements contracts
(that is, any wholesale requirements contract executed after July 11,
1994), the regulations will allow recovery of stranded costs only if
the contract contains an explicit stranded cost provision that permits
recovery. By ``explicit stranded cost provision'' we mean a provision
that identifies the specific amount of stranded cost liability of the
customer(s) and a specific method for calculating the stranded cost
charge or rate.. We clarify that provisions in requirements contracts
executed after July 11, 1994 but before the date on which this Final
Rule is published in the Federal Register that explicitly reserved the
right to stranded cost recovery pending the outcome of this Rule will
be deemed ``explicit stranded cost provisions.'' However, provisions in
requirements contracts executed after July 11, 1994 but before the date
on which this Final Rule is published in the Federal Register that
postpone the issue of stranded cost recovery without specifically
providing for recovery of stranded costs will not be considered
``explicit stranded cost provisions.''
Second, for existing wholesale requirements contracts (that is, any
wholesale requirements contract executed on or before July 11, 1994), a
utility may not recover stranded costs if recovery is explicitly
prohibited by the contract (including associated settlements) or by any
power sales or transmission tariff on file with the Commission.
Third, for existing wholesale requirements contracts that do not
address stranded costs through exit fee or other explicit stranded cost
provisions, a public utility may seek recovery of stranded costs only
as follows: (1) If the parties to the existing contract renegotiate the
contract and file a mutually agreeable amendment dealing with stranded
costs, and the Commission accepts or approves the amendment; (2) if
either or both parties seeks an amendment to the existing contract
under sections 205 or 206 of the FPA, before the contract expires, and
the Commission accepts or approves an amendment permitting stranded
cost recovery; or (3) if the public utility files a request, before the
contract expires, to recover stranded costs through a departing
generation customer's transmission rates under FPA sections 205-206 or
211-212.
Fourth, if the selling utility under an existing wholesale
requirements contract is a transmitting utility but not also a public
utility, and the contract does not address stranded costs through an
explicit exit fee or other stranded cost provision, the transmitting
utility may seek to recover stranded costs through a surcharge to a
departing generation customer's transmission rates under FPA sections
211-212. Such utility may not seek recovery of stranded costs through a
section 211-212 transmission rate if the existing requirements contract
does contain an explicit exit fee or other stranded cost provision.
Fifth, for a retail-turned-wholesale customer, a public utility or
transmitting utility may file a request to recover stranded costs from
the newly-created wholesale customer through that customer's
transmission rates under FPA sections 205-206 or 211-212.
Sixth, for customers who obtain retail wheeling, a public utility
or transmitting utility may seek recovery through Commission-
jurisdictional transmission rates only if the state regulatory
authority had no authority under state law to address stranded costs
when retail wheeling is required.
[[Page 21665]]
K. Other
1. Information Reporting Requirements for Public Utilities
In the NOPR, the Commission did not propose any changes to its
information filing requirements for public utilities.
Comments
Many IOUs argue that the current information filing requirements
competitively disadvantage traditional public utilities and unfairly
benefit sellers, such as power marketers, that are not required to
provide comparable information.904 They urge the Commission to
eliminate the requirement for public disclosure of competitively
sensitive, proprietary, or otherwise confidential Form No. 1 data. They
contend that requiring such disclosure only from traditional public
utilities harms such public utilities and compromises the development
of efficient competition. Illinois Power asks the Commission to review
all information that utilities must file, including EIA 860, EIA 767,
and FERC Form No. 715.
---------------------------------------------------------------------------
\904\ E.g., NIPSCO, Illinois Power, Centerior, Ohio Edison, EEI.
---------------------------------------------------------------------------
A number of commenters believe that some type of information
requirement must also be placed on non-public utility entities.905
PacifiCorp suggests that the Commission should require transmitting
utilities that do not file a Form No. 1 to file similar information
annually with the Commission. Ohio Edison asserts that the Commission
should extend its use of the reciprocity concept to require the filing
of operating data with the Commission. Further, if non-public utility
entities are not required to disclose certain information, Ohio Edison
asserts that all public utilities that have received approval to sell
power at market-based rates, including traditional utilities, should
also be free from having to disclose such information.
---------------------------------------------------------------------------
\905\ E.g., NSP, Ohio Edison.
---------------------------------------------------------------------------
Arizona argues that enforcing comparability vis-a-vis non-public
utility transmitting utilities would seem to invite jurisdictional
challenge. Thus, it would support legislation to broaden the
Commission's jurisdiction.906
---------------------------------------------------------------------------
\906\ See also Minnesota P&L.
---------------------------------------------------------------------------
Commission Conclusion
We will not adopt the suggestion made by a number of commenters
that we now eliminate the public disclosure of allegedly competitively
sensitive, proprietary, or otherwise confidential data submitted to the
Commission on Form No. 1, as well as on other Commission forms. The
information that we collect from public utilities is necessary to carry
out our jurisdictional responsibilities and is used, among other
things, to evaluate the reasonableness of cost-based rates subject to
our jurisdiction and the operation of power markets.907 Moreover,
as we explained in ConEd,
\907\ See, e.g., Consolidated Edison Company of New York, Inc.
and Central Hudson Gas & Electric Corp., 72 FERC para. 61,184 at
61,891 (1995) (ConEd).
---------------------------------------------------------------------------
[R]eports required to be submitted by Commission rule and
necessary for the Commission's jurisdictional activities are
considered public information. 18 CFR 388.106. In addition, the
Commission has long required jurisdictional utilities to submit Form
1 data on a form that states on its cover that the Commission does
not consider the material to be confidential.908
\908\ 72 FERC at 61,891.
---------------------------------------------------------------------------
We are sensitive to the lack of symmetry in the generation
information we require from traditional public utilities, particularly
those that have market-based rate authority, and the generation
information we require from other public utilities (e.g., public
utility marketers) authorized to sell at market-based rates.909
However, the record in this proceeding is insufficiently developed for
us to make and support a well-informed decision requiring a different
reporting scheme, particularly given the industry's current rapid pace
of change. Also, we are not persuaded that the burdens borne by
traditional public utilities (primarily annual reports submitted months
after-the-fact) are impairing the competitiveness of these utilities so
much that we must act hastily now, instead of deferring a decision to a
more appropriate proceeding. Moreover, we are required to regulate the
rates of public utilities and, although we are moving toward greater
reliance on market-based generation rates, we continue to regulate
generation on a cost basis for most traditional public utilities,
particularly rates for sales from existing generation. To assure that
these rates are just and reasonable, we, as well as the customers of
public utilities, need the more detailed information our regulations
require public utilities to submit.
---------------------------------------------------------------------------
\909\ We note that public utility marketers are required to file
quarterly transaction reports so that the Commission can monitor the
reasonableness of their charges and their ability to exercise market
power. See Heartland Energy Services, Inc., 68 FERC para. 61,223 at
62,065-66 (1994). Unlike traditional public utilities, marketers do
not use cost-based rates. Approval of the generation rates of non-
jurisdictional transmitting utilities is not subject to our
jurisdiction.
---------------------------------------------------------------------------
Accordingly, at this time, we will not change our information
reporting requirements. As the industry becomes more competitive, we
will monitor our reporting requirements to make sure that they are
needed, fair to all segments of the industry, and consistent with the
workings of a competitive environment.
2. Small Utilities
In the NOPR, we did not address whether special provisions were
needed for small public utilities and small transmission customers
because of the possible burden of unbundling, open access tariffs, and
the OASIS requirement.
Comments
A number of commenters assert that the unbundling requirement poses
significant problems for smaller public utilities and that small
utilities should not be subject to the same requirements as larger
utilities.910 St. Joseph notes that in small utilities one system
operator typically runs the system operations center. Functional
unbundling, it asserts, would require the addition of another operator
for each shift at great cost to the small utility. Central Hudson
estimates that unbundling would result in an approximately 10 percent
increase in the wholesale price, putting small utilities at a
competitive disadvantage.
---------------------------------------------------------------------------
\910\ E.g., Central Hudson, Central Illinois Light, CVPSC,
Citizens Utilities, East Kentucky, IPALCO, Montana-Dakota Utilities,
Seattle, St. Joseph, Tallahassee, VT DPS.
---------------------------------------------------------------------------
Several commenters assert that many small utilities enjoy little or
no transmission market power because their systems tend to be in
parallel with large systems and are bypassed as a result. They say that
customers prefer to deal with one large regional utility rather than
pay pancaked transmission rates for service through two or more small
utilities.
Citizens Utilities argues that some systems are radial spurs of
much larger systems and merely serve to link points of interconnection.
It claims that a network tariff is not applicable in such a case and
that it is unlikely that third parties would request service over such
small or isolated systems. It recommends that if a utility is basically
a spur system and faces little present or future demand for third-party
service, the Commission should either relax the open access
requirements or defer them until a section 211 request is submitted.
East Kentucky proposes that the Commission exempt not-for-profit
utilities from the requirement to separate the functions related to
operation and marketing, since small G&T cooperatives exist solely to
serve the needs of their owner-member distribution cooperatives.
[[Page 21666]]
VT DPS suggests that waiver of marketing and transmission personnel
separation requirements may be appropriate in the case of smaller
utilities that do not operate control areas. St. Joseph proposes that
the Commission establish a threshold level based on system demand of
1000 MW, below which unbundling of wholesale transmission functions
from other dispatching functions would not be required. Alternatively,
St. Joseph proposes an exemption from unbundling where the utility can
demonstrate that it has no market power and that unbundling would not
materially improve the level of competition in the generating market.
Central Hudson believes that the Commission should allow the
development of a short form tariff or else defer the functional
unbundling requirement for smaller utilities and use the section 211
process in the interim to provide flexibility for these utilities.
Oregon Trail EC, a small rural electric, public utility
cooperative, requests that the Commission revise proposed Sec. 35.28 of
its regulations to provide that the generic open access transmission
requirements apply only to public utilities that operate facilities
used for the transmission of electric energy in interstate commerce. It
explains that it owns one transmission line that it leases to BPA,
which operates the line as part of its integrated transmission network.
Thus, Oregon Trail EC states that it cannot meet the requirements of
the open access rule. It also points out that the Commission exempted
Oregon Trail EC and other similarly situated utilities from the
transmission reporting requirements of Form No. 715 because they did
not engage in transmission planning.
ALCOA suggests that the default tariffs for smaller utilities with
transmission systems unlikely to be used by others should not become
effective automatically. Rather, the default tariffs should become
effective only when service is requested. Citizens Utilities suggests
that relaxed tariff requirements be established for small utilities
with insignificant demand for transmission service.
BG&E believes that a utility using its system on a network basis
for economic dispatch should not be required to file a network service
tariff if there is no customer to take the service. It suggests that if
municipalization were to occur, the Commission could then require the
utility to file, within 60 days, a network service tariff to serve the
new municipal.
Commission Conclusion
We are sympathetic to the array of concerns raised by small public
utilities and small transmission customers. The regulations we are
adopting include waiver provisions under which public utilities and
transmission customers, and non-public utility entities seeking
exemption from the reciprocity condition, may file requests for waivers
from all or part of the Commission's regulations or for special
treatment.911 However, it is difficult to imagine any circumstance
that would justify waiving the requirements of this Rule for any public
utility that is also a control area operator.
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\911\ Non-public utility entities could request that the
Commission find that they can satisfy the reciprocity condition
without meeting all or some of the requirements that public
utilities must meet. The requests could encompass a wide variety of
circumstances. For example, a non-public utility could agree to
offer comparable transmission services but not wish to have an OASIS
or separate transmission personnel from wholesale marketing
personnel due to the cost of doing so. The Commission could find
that the entity nevertheless satisfied the reciprocity condition.
---------------------------------------------------------------------------
We recognize, for example, that it might be a financial burden on
small public utilities to unbundle generation from transmission, follow
standards of conduct that separate transmission personnel from
wholesale marketing personnel, and maintain an OASIS. These
requirements may be particularly burdensome for small public utilities
that own no generation and buy at wholesale on a radial transmission
line from another utility's grid. In addition, if a small public
utility's service territory is part of another utility's control area,
the small public utility should be permitted to make a showing that it
should be exempt from all or some of the Rule. In this circumstance, we
will consider granting a waiver if the utility can show that: (1) It
does not own transmission facilities, (2) it has turned control of its
facilities over to someone else (such as the control area operator) who
complies with the rule as its agent, or (3) no one is likely to ask to
use its facilities (e.g., because they are radial lines), and it
commits to file an open access tariff within 60 days of a request to
use its facilities and to comply with the rule in all other ways.
Because the possible scenarios under which small entities may seek
waivers from the Final Rule are diverse, they are not susceptible to
resolution on a generic basis and we will require applications and
fact-specific determinations in each instance. We note here that any
waivers that we may grant depend upon the facts presented in each case.
If the circumstances that give rise to the exemption change, the waiver
may no longer be appropriate. For example, a radial line today could
very easily become part of a network tomorrow and a portion of a grid
that no one is interested in using today could become an important
transmission link tomorrow, especially if retail access is allowed.
In addition, we will apply the same standards to any entity seeking
a waiver. This includes public utilities seeking waiver of some or all
of the requirements of the rule, as well as non-public utilities
seeking waiver of the reciprocity provisions contained in the pro forma
open access tariff. Thus, we would not apply the open access
reciprocity provision to small non-public utilities that are not
control area operators and either do not own or control transmission or
have transmission that no one is likely to ask to use. They would not
have to provide an open access tariff, establish an OASIS, or separate
operators of transmission from wholesale purchasers in order to satisfy
the reciprocity condition for obtaining transmission service. However,
they will have to apply for this waiver and demonstrate that they
qualify for the waiver.
3. Regional Transmission Groups
In the NOPR, we again expressed our support for the voluntary
formation of regional transmission groups (RTGs).912 We also
explained that the potential benefits of RTGs would not be undermined
by the rules proposed in the NOPR.
---------------------------------------------------------------------------
\912\ FERC Stats. & Regs. para. 32,514 at 33,095.
---------------------------------------------------------------------------
a. Incentives for RTGs to Form and Resolve Regional Transmission Issues
Comments
A number of commenters urge the Commission to provide incentives
for the formation of RTGs within two years of the adoption of the final
rule.913 Several commenters argue that the Commission should
encourage a regional approach to transmission issues by expanding the
role of RTGs.914 Com Ed also claims that contract path pricing
problems probably will need to be resolved at the regional level.
---------------------------------------------------------------------------
\913\ E.g., AMP-Ohio, Missouri Joint Commission, MT Com, WEPCO,
Nebraska Public Power District, Texas-New Mexico.
\914\ E.g., WEPCO, Portland, WA Com.
---------------------------------------------------------------------------
Sierra Pacific Power, which views open access as the major benefit
of RTGs, questions the need to provide incentives for the development
of RTGs once open access is implemented. However, it does see that RTGs
may help promote open access with non-public utility entities, who have
shown
[[Page 21667]]
an increased interest in joining RTGs. American Wind and MT Com request
that the Commission adopt policies that will encourage a close working
relationship between RTGs and state authorities.
Otter Tail contends that the final Rule should stop short of
establishing any conditions on the formation, governance, or functions
of RTGs, arguing that such issues are complex and outside the scope of
the NOPR. ALCOA and Missouri Joint Commission encourage the Commission
to make certain that its policy regarding RTGs is not implemented in a
manner that conflicts with the new open access regime.
Commission Conclusion
We continue to support the development of RTGs and encourage the
formation of regional tariffs.915 In our Policy Statement
Regarding Regional Transmission Groups, we first explained our support
for such voluntary associations.916 We again explained our support
in the NOPR:
\915\ If an RTG is not a corporate person, each utility member
of the RTG may file the same or complementary tariffs.
\916\ 58 FR 41626 (August 5, 1993), FERC Stats. & Regs.,
Regulations Preambles para. 30,976 (RTG Policy Statement).
---------------------------------------------------------------------------
We believe that RTGs can speed the development of competitive
markets, increase the efficiency of the operation of transmission
systems, provide a framework for coordination of regional planning
of the system and reduce the administrative burden on the Commission
and on members of RTGs by providing for voluntary resolution of
disputes.917
\917\ FERC Stats. & Regs. para. 32,514 at 33,095.
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To further encourage the development of RTGs, we will accept
regional open access transmission tariffs developed by RTGs that are
consistent with the objectives of this Rule. This should make it easier
for all parties in a region to coordinate their activities.
b. Deference to RTGs To Develop Regional Tariffs and Prices
Comments
A number of commenters urge the Commission to give considerable
deference to RTGs on such issues as the formulation of pricing methods
and RTG member duties.918 Nebraska Public Power District requests
that the Commission consider permitting a megawatt-mile pricing
mechanism for MAPP. NWRTA urges the Commission to define clearly how
much deference it will accord to RTGs and explicitly grant deference to
RTGs on such matters as dispute resolution and decisionmaking
processes. It also asks that the Commission honor the reciprocity
provisions related to Canadian participation that are contained in the
NWRTA agreement. Nevada Power requests the Commission to accept, as not
unduly discriminatory, RTG open access tariffs that reflect the
members' specific terms and conditions so long as the tariffs satisfy
the substantive requirements of the final rule. It proposes that such
tariffs be allowed to become effective without hearing or refund
obligation.
---------------------------------------------------------------------------
\918\ E.g., UT Com, ID Com, LA DWP, Nebraska Public Power
District, Salt River, Nevada Power. See also NEPCO, United
Illuminating, Utility Working Group.
---------------------------------------------------------------------------
Texas-New Mexico, while encouraging deference to RTGs in general,
argues that deference must be conditioned upon a requirement that the
RTG provide not only equal access but also terms and conditions of
service that are comparable to what a customer could otherwise obtain
under the final Rule tariff or under section 211 of the FPA.
Southwest TDU Group contends that RTGs should not be given
deference, and RTG filings should be subject to the same standards and
scrutiny as non-RTG filings.
Commission Conclusion
As we explained in the RTG Policy Statement, we intend to give
deference to the planning, dispute resolution, and decisionmaking
processes of an RTG. With respect to pricing proposals submitted by
RTGs, we believe that RTGs may be able to develop solutions to such
problems as loop flows through innovative flow-based pricing
methodologies. As we stated in the Transmission Pricing Policy
Statement, we will afford considerable deference to an RTG.
4. Pacific Northwest
Comments
Commenters in the Pacific Northwest ask the Commission to be
flexible in reviewing tariffs that are based on regional practices, and
that differ from the final Rule tariff as a result. Public Generating
Pool urges the Commission to recognize that the Northwest's
transmission system has been developed and is operated to support the
region's coordinated power system. That is, it wants all hydro spill to
be treated equally with no preference between federal and non-federal
power. Also, it asserts that firm available transmission capacity in
the Northwest must be worked out by the NWRTA RTG to account for the
contingent operation of generation to avoid hydro spill.
Similarly, other commenters note that the Northwest's integrated
transmission system was constructed to support a unique regionwide
hydroelectric-dependent generating system and that flexibility is
needed to accommodate the characteristics of the system.
WA Com argues that imposition of a uniform national tariff would
not reflect the region's specific system characteristics or operating
practices. It argues that the final Rule could impede rather than
promote efficient competition in the Northwest. It believes that the
Commission should defer to RTGs for defining and implementing wholesale
transmission access terms and conditions at the regional level.
The Washington and Oregon Energy Offices, while supporting the
adoption of regional practices, argues that uniform transmission
principles should apply for all transmitting entities in the region.
They argue that dispatch decisions are complicated by flood control,
salmon passage, navigation, irrigation, and other constraints. Puget
requests that the Commission give each transmitting utility the
flexibility to file tariffs that fit unique or unusual circumstances
and allow for regional market differences.
Because the terms and conditions offered by the smaller
transmission owners in the Northwest are determined by the terms and
conditions offered by Bonneville, Pacific Northwest Coop argues that
the terms and conditions for wholesale power transmission, ancillary
services, and RINs should be deferred until BPA's 1996 rate case is
resolved and until appropriate regional and national systems and
protocols are developed.
Commission Conclusion
As we explained with respect to RTGs, we encourage the filing of
regional open access transmission tariffs.919 The Final Rule pro
forma tariff contains provisions allowing utilities to modify tariff
terms to reflect prevailing regional practices. This should permit
entities in the Pacific Northwest to address unique circumstances that
exist in the Pacific Northwest and to incorporate prevailing regional
practices (e.g., treatment of hydropower generation in the priority of
dispatch) into their open access transmission tariffs.920 This
should also encourage
[[Page 21668]]
other regional solutions, such as the development of regional ISOs, to
transmission problems.
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\919\ Also, as we explained with respect to RTGs, we will review
pricing proposals in regional tariffs pursuant to our Transmission
Pricing Policy Statement.
\920\ This Rule will not resolve disputes over federal hydro
preference policies or over the agreements incorporated in the
Northwest Power Planning Act.
---------------------------------------------------------------------------
In addition, although we will put the Final Rule pro forma tariff
(which already allow for certain provisions consistent with regional
practices) into effect for all public utilities 60 days after
publication of this Rule in the Federal Register, utilities may file
regional tariffs or propose deviations in the pro forma tariff based on
additional regional needs to be effective at any time thereafter. Such
proposals, however, will have to be consistent with the requirements of
the Final Rule and be reasonable, generally accepted in the region and
consistently adhered to by the transmission provider. Further, we will
not permit entities in a region to claim different sets of prevailing
regional practices.
5. Power Marketing Agencies
a. Bonneville Power Administration (BPA)
Comments
Washington Water Power explains that for open access transmission
to be fully realized in the Pacific Northwest there must be federal
legislation to remove the monopoly protections of federally generated
power. Until then, Washington Water Power suggests certain mitigating
measures that would increase competition in the Pacific Northwest. It
also urges the Commission to take BPA's special characteristics into
account in issuing the final rule.
Public Power Council encourages the Commission to make broad use of
section 211 to mandate transmission access to ensure that BPA continues
to provide comparable open access transmission.921
---------------------------------------------------------------------------
\921\ See also Puget, Portland, Reynolds.
---------------------------------------------------------------------------
Public Generating Pool argues that the extent to which BPA's
tariffs are allowed to deviate from the rule should be governed by the
technical characteristics of the system and not by BPA's
status.922
---------------------------------------------------------------------------
\922\ See also Public Power Council.
---------------------------------------------------------------------------
Direct Service Industries argues that the non-discrimination
standard is made applicable to BPA by section 212(i) and that the
Commission has the authority to review all BPA rates under the
Northwest Power Act (citing Pacific Northwest Electric Power Planning
and Conservation Act, section 7(a), 16 U.S.C. 839e(a)). It also argues
that functional unbundling is particularly important for BPA because of
BPA's market power and relative freedom from regulation. Clark also
argues that the Commission should require BPA to meet the comparability
standard. It alleges that BPA refuses to provide comparable service. It
asserts that the Commission has authority to remedy the problem under
the Energy Policy Act amendments to section 212, which Clark states
gives the Commission authority over BPA's transmission practices. Clark
also notes that BPA is a member of WRTA and, as such, must provide
comparable service.
Pacific Northwest Coop argues that many of the issues presented in
this rulemaking are currently being contested in the BPA rate case in
Docket Nos. WP-96/TR-96 and TC-96. It says that the Commission should
defer application of the rule to Pacific Northwest Coop and all of
BPA's customers until conclusion of the rate case.
Washington and Oregon Energy Offices asserts that it would be
proper for the Commission ``to impose similar transmission price
structures upon Bonneville under section 211 orders as it will for
jurisdictional [public] utilities under sections 205, 206, and the
NOPR.''
With respect to stranded costs, BPA notes that it may be necessary
to tailor a stranded cost policy for BPA that addresses the goals of
open access and wholesale stranded cost recovery in a manner consistent
with BPA's unique circumstances. BPA asks the Commission to defer
consideration of its stranded investment and related cost recovery
issues until it makes a rate filing with the Commission.923 It
further argues that the rule should not address whether and how BPA
stranded costs might be recovered in transmission rates approved by the
Commission under authority other than sections 211 and 212. Clark
argues that the Commission's stranded cost recovery policy is
inapplicable to BPA.
---------------------------------------------------------------------------
\923\ See also Snohomish, NPPC, W&O, Public Power Council,
Washington and Oregon Energy Offices, Direct Service Industries.
---------------------------------------------------------------------------
NW Conservation Act Coalition makes the following suggestions: (1)
The Commission should grant BPA the authority to levy exit fees on
customers who are terminating service and who do not use BPA's
transmission system for their new power transaction; (2) any affected
person should be allowed to petition the Commission for review of BPA's
rates for inadequate or inappropriate mitigation of its stranded
benefits; (3) the rule should insist upon a requirement that open
access and stranded cost recovery be permitted only if the entities
involved can show there will be no lessening of support for public
purposes; and (4) the Commission should clarify that the Direct Service
Industries customers are retail customers and that they will be subject
to recovery of stranded costs and benefits.
Commission Conclusion
BPA is not a public utility under section 201(e) of the FPA and,
thus, is not subject to the requirements of this Rule to put the Final
Rule pro forma tariff into effect. However, there are three
circumstances under which the Commission may review BPA's transmission
access and pricing policies. First, BPA could file an open access
tariff and accompanying rates for review and confirmation under section
7 of the Pacific Northwest Electric Power Planning and Conservation Act
(Northwest Power Act) 924 and at that time could ask the
Commission to find that its tariff meets the Commission's open access
policies. Second, BPA is a transmitting utility subject to a request
for mandatory transmission services under section 211 of the FPA.
Transmission required of BPA under section 211 would have to be
consistent with the requirements imposed on BPA under its organic
statutes, the Northwest Power Act, and the Federal Columbia River
Transmission System Act.925 Third, if BPA receives open access
transmission from a public utility, it is subject to the reciprocity
provision contained in the utility's Final Rule pro forma tariff. If
BPA seeks to comply with the reciprocity provision, it could use the
declaratory order procedures we have provided in this rule for non-
public utility transmission providers. Finally, we note that BPA has
agreed to provide open access as a member of two RTGs approved by this
Commission.
---------------------------------------------------------------------------
\924\ 16 U.S.C. 839-839h.
\925\ 16 U.S.C. 838-838j.
---------------------------------------------------------------------------
With respect to stranded costs, BPA has asked us to clarify that
the Stranded Cost Rule does not address whether and how BPA stranded
costs might be recovered in transmission rates approved by the
Commission under authority other than sections 211 and 212 of the FPA
(namely, section 7 of the Northwest Power Act). We clarify that this
rule addresses only stranded costs recovered by public utilities under
the FPA and transmitting utilities (including BPA) that are subject to
mandatory transmission requests under FPA section 211. It does not
address stranded cost recovery by BPA under the Northwest Power Act.
[[Page 21669]]
b. Other Power Marketing Agencies
Comments
SEPA requests that the final rule assure that SEPA can receive
network transmission service when necessary. It also indicates that it
has 58 customers that receive less than one MW of power, but that the
NOPR pro forma point-to-point tariff contains a one MW minimum
scheduling requirement. Thus, it requests that the final rule allow
some flexibility with respect to this requirement so that it can carry
forward its marketing program.
DOE notes that the Western Area and Southwestern Area Power
Administrations have pledged to offer transmission services that are
comparable to those required of public utilities to the extent not
otherwise prohibited by law.
Commission Conclusion
Federal power marketing agencies (PMAs) are not public utilities as
defined under section 201(e) of the FPA and, thus, are not required by
this rule to file non-discriminatory open access transmission
tariffs.926 However, to the extent a PMA receives open access
transmission service from a public utility, it is subject to the
reciprocity provisions in the utility's pro forma tariff.927 If a
PMA seeks to comply with the reciprocity provision, it can file a
proposed tariff and seek a declaratory ruling.
---------------------------------------------------------------------------
\926\ PMAs, however, are transmitting utilities subject to
requests for mandatory transmission services under section 211 of
the FPA.
\927\ See Section IV.G.4.f.
---------------------------------------------------------------------------
With respect to SEPA's concern that the proposed point-to-point
tariff has a one MW minimum scheduling requirement, but many of its
customers have loads of less than one MW, we clarify that the Final
Rule pro forma tariff will allow SEPA to continue to schedule service
for these customers. Under SEPA's current transmission arrangements, it
is allowed to aggregate loads within a single control area that are
less than one MW individually, but jointly are more than one MW, to
meet the requirement at an interface. The revised language in the Final
Rule tariff permits this practice to continue. We also clarify that
SEPA, as a seller of power to multiple purchasers inside several
control areas, is eligible to receive network service.
6. Tennessee Valley Authority
Comments
TVA is concerned that the final rule may place TVA at a
disadvantage because its opportunities to participate in the
electricity market outside the TVA area are so severely limited by
statute. It explains that it is restricted from directly participating
in the new competitive landscape except through limited power exchange
opportunities with a few neighboring systems. It urges the Commission
to recognize these circumstances in the final rule. TVA is also
concerned that its regional customers may face stranded costs because
its ability to mitigate those costs by making replacement sales to new
customers is limited.
Commission Conclusion
TVA is not a public utility under section 201(e) of the FPA and,
thus, is not required to file a non-discriminatory open access
transmission tariff under this rule.928. However, if TVA receives
open access transmission service from a public utility, it is subject
to the reciprocity provision in the utility's pro forma tariff. If TVA
seeks to comply with reciprocity, it may avail itself of the
Commission's reciprocity safe harbor approach, through a declaratory
ruling, if it is fearful that a public utility may deny it service
simply on a claim that TVA's non-discriminatory open access tariff is
not satisfactory.929 The details of this safe harbor procedure are
set forth in Section IV.G.4.f.
---------------------------------------------------------------------------
\928\ TVA, however, is a transmitting utility subject to
requests for mandatory transmission services under section 211 of
the FPA.
\929\ We recognize that sections 212(f)(1) and 212(j) of the
FPA, as amended by the Energy Policy Act, limit the applicability of
section 211 to TVA, but conclude that this limitation in no way
affects our application of the reciprocity requirement to TVA.
Limitations on TVA's authority to market power are not the product
of this rule but rather of TVA's enabling legislation. Thus, it is
for Congress to decide whether TVA should be permitted greater
marketing authority. As noted in our earlier discussion of
reciprocity, TVA is not being required to file an open access
tariff. Rather it is being precluded from taking advantage of
benefits available under this rule without providing comparable use
of its system to others.
---------------------------------------------------------------------------
7. Hydroelectric Power
Comments
Non-Firm Transactions
ID Com believes that the NOPR unfairly discriminates against hydro-
based utilities. It argues that utilities that rely heavily on
hydropower need to engage in non-firm market transactions that depend
on water levels; e.g., during low water years, a utility must have
access to the transmission system to make non-firm, off-system
purchases. It asserts that the NOPR treats non-firm sales and purchases
as subordinate to firm transactions and does not allow the utility to
reserve capacity for its critical, but non-firm, transactions. ID Com
also asserts that the NOPR would, in effect, strand the utility's
investment in the production plant being used to generate power for the
non-firm sales.
Idaho complains that the NOPR unfairly allows a customer to buy and
reserve firm transmission rights surplus to its needs, but does not
permit a utility to do the same. It explains that this problem is
particularly acute for hydro utilities and argues that they must be
allowed to reserve at tariff rates at least a portion of available
transmission capacity for firm and non-firm wholesale transactions. In
the alternative, Idaho asserts that the transmission owner should not
be required to provide point-to-point service for transmission uses
other than from demonstrated firm obligations.
Commission's Licensing Practices
National Hydropower argues that in light of the NOPR the Commission
should reexamine the manner in which it exercises its FPA Part I
authority with respect to (1) economic feasibility determinations, (2)
section 10(a) findings, (3) determinations of section 10(j)
recommendations, and (4) section 13. For example, it states that the
NOPR suggests that all future electric resource selection decisions
should be based exclusively on short-run marginal cost comparisons.
Because, it asserts, hydroelectric power provides many public interest
benefits not susceptible to precise quantification, the Commission
should clarify how non-price factors are to be considered in a post-
final rule wholesale electric marketplace.
Commission Conclusion
Non-Firm Transactions
As we explained above with respect to the Pacific Northwest, we
will permit entities to incorporate prevailing regional practices
(e.g., treatment of hydropower generation in the priority of dispatch)
into regional open access transmission tariffs. This should permit
entities in a region to resolve concerns over the scheduling of non-
firm hydropower. In addition, if a utility and its customers can agree
on the scheduling of non-firm hydropower and the disruption of firm
transactions, we would permit that resolution to be incorporated into
the utility's tariff. Utilities are permitted to consider seasonal
variations in hydropower availability in the determination of Available
Transmission Capacity to be posted on the OASIS.
Commission's Licensing Practices
The issues raised by National Hydropower with respect to our
[[Page 21670]]
hydroelectric licensing practices are beyond the scope of this
rulemaking. Indeed, National Hydropower has already raised its concerns
in a petition to the Commission to revise our hydroelectric licensing
procedures, filed on July 10, 1995. That is the proper proceeding in
which to address our hydroelectric licensing practices.
8. Residential Customers
Comments
Several commenters are concerned that the rule may undermine the
financial position of public utilities so that they will not be able to
provide many of the programs that benefit low-income residents (e.g.,
assistance to low-income and elderly consumers, weatherization and
energy conservation programs, and payment of taxes that provide many
city services).930
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\930\ E.g., Urban League, Latin League, Black Mayors,
Homelessness Alliance, National Women's Caucus, La Raza.
---------------------------------------------------------------------------
La Raza is concerned that the rule will permit large preferred
customers to opt out of the regulated structure, leaving behind a
smaller and less affluent base to support the long-term investments
made under the previous regulatory environment.
Home Builders is concerned that utilities may compensate for
reduced profits under the proposed rule by raising infrastructure
charges and hookup fees for new homes, thus reducing new home sales.
State and City Supervised Housing for Equity in Electric Rates
states that publicly supervised housing is uniquely qualified to obtain
open access electricity from wholesale markets, and that the Commission
should adopt policies that bring competitive benefits to residents of
such housing.
Commission Conclusion
While some residential consumers may be apprehensive about the
changes that this rule may have on the electric industry, we are
convinced that the changes we are proposing for wholesale markets will
benefit them. As wholesale transmission open access becomes a reality,
residential consumers should reap the benefits of more competitive bulk
power markets and associated lower costs. This rule does not require
retail transmission access for retail customers of any size. Moreover,
this rule does not require any changes in programs such as assistance
to low-income and elderly consumers and weatherization and energy
conservation. As discussed in Section IV.I, those programs are under
the jurisdiction of the individual states, and will remain under their
jurisdiction. Indeed, this rule contains several safeguards to maintain
the ability of states to impose conditions on retail access, such as
conditions that help to protect residential customers from becoming the
residual payer of stranded costs.
V. Environmental Statement
This section reviews and adopts the final environmental impact
statement (FEIS) prepared by the Commission staff in connection with
this rule. It identifies the alternatives considered by the agency in
reaching its decision; analyzes and considers whether and to what
extent the chosen alternative--adoption of this rule--is likely to
result in environmental harm; evaluates alternatives and suggestions
for mitigating environmental harm from the rule, if any; and states the
Commission's decision.
Summary
A. The Environmental Impact Statement
The Commission decided to prepare an environmental impact statement
(EIS) evaluating the environmental consequences that could result from
adoption of this rule. We did so largely in response to the claims of
several commenters, including the Environmental Protection Agency
(EPA), who charge that the rule will have significant adverse
environmental effects.
Although a number of issues were raised, by far the most prominent
concern arises from the theory that competitive market conditions
created by the rule will provide an advantage to power suppliers who
produce power from coal-fired facilities that are not subject to
stringent environmental controls on nitrogen oxides (NOX)
emissions.931 Under this theory, these facilities, located
primarily in the Midwest and South, will, as a result of the rule,
generate more power and emit more NOX, which will contribute to
ozone formation. The ozone could add to pollution both in those regions
and more significantly in the Northeast, to which area such pollutants
could be transported. Those who propound this theory argue that it is
the responsibility of the Commission, using its authority under the
Federal Power Act, to effect environmental controls that will mitigate
what they predict will be significant increases in NOX emissions
associated with this rule.
---------------------------------------------------------------------------
\931\ References throughout the Environmental Statement are to
emissions from the electric industry, and not to emissions from all
sources.
---------------------------------------------------------------------------
The staff prepared an FEIS based upon computer modeling simulations
of power generation patterns and NOX emissions likely to occur as
a result of the rule. Staff used widely accepted models for studying
economic conditions in power markets and simulating emissions of
NOX and other pollutants. These models took into account a variety
of different assumptions concerning significant factors such as coal
and natural gas prices and other competitive conditions. These factors
are critical because increased use of coal-fired generation tends to
increase NOX emissions, while increased use of gas-fired
generation is environmentally more benign.
The examination in the FEIS of the environmental effects that are
likely to result from implementing the rule is based on an analytic
framework that was shaped by comments received in the scoping process
and on the DEIS. The study was revised to reflect the frozen efficiency
reference case assumptions requested by EPA and other commenters. This
was done to ensure full disclosure of possible environmental impacts
even though the Commission disagrees that use of these assumptions is
appropriate.
It has been observed in the context of agency preparation of an
environmental study that ``(t)he NEPA process involves an almost
endless series of judgment calls.'' 932 That is particularly true
where, as here, the agency undertakes to examine the impacts of a
proposed regulatory program. In designing an effective assessment of
the environmental impacts of the rule, the Commission had to make a
number of judgments as to the type and the scope of studies necessary
to analyze the proposals sufficiently. Commenters also raised many
issues related to the design of the study. For example, the Center for
Clean Air Policy contends that the Commission should model a range of
mitigation policies; the Missouri Department of Natural Resources
contends that the impact of the rule on generation may be locally
intense and that these effects should have been studied; and other
commenters sought to have the Commission examine different database or
modeling assumptions.
---------------------------------------------------------------------------
\932\ Coalition on Sensible Transportation, Inc. v. Dole, 826
F.2d 60, 66 (D.C. Cir. 1987). The Court added that ``[i]t is of
course always possible to explore a subject more deeply and to
discuss it more thoroughly. The line-drawing decisions necessitated
by this fact of life are vested in the agencies, not the courts.''
Id.
---------------------------------------------------------------------------
For these and similar matters we exercised our judgment as to the
appropriate manner in which to treat the issue. For example, we
determined not to model a range of mitigation
[[Page 21671]]
policies because we did not find that the impacts of the rule require
the Commission to adopt or implement a plan of mitigation. It would
have been extremely difficult, if not impossible, to examine the many
varied local impacts that could be expected across the Nation in
response to the Rule. We made judgments as to the appropriate database
and modeling assumptions to use--in some cases, those assumptions were
shaped or changed by comments we received.
In short, many competing considerations came into play during the
design of the complex analysis used to examine the environmental
effects of the rule. We exercised our judgment, for example, based on
consideration of whether matters are within the scope of the rule, the
most appropriate way to study the effects of the proposal, and whether
the issues raised were relevant to a consideration of the environmental
effects of the rule. The Commission's response to issues raised by
commenters is reflected in the response to comments set forth in
Appendix J of the FEIS. We conclude that the FEIS reflects the
appropriate consideration of these and many similar issues.
B. Major Issues
Some comments on the draft environmental impact statement (DEIS),
as well as earlier comments in response to Commission scoping
inquiries, raise two major areas of objection to the Commission's
analysis. First, commenters claim that in determining what NOX
emission levels would be in the future with the adoption of the rule,
the Commission did not compare the emissions levels associated with the
rule against the appropriate base case. They argue that the Commission
should have analyzed and compared the impacts of the rule to a ``no-
action'' alternative that assumes that the Commission abandons all its
open access policies, not just this rule. Some commenters, including
EPA, go even further, suggesting that the Commission compare emission
levels projected to result from the rule against a ``frozen
efficiency'' case in which other major factors--factors that would
increase industry efficiency independent of the Rule--do not occur.
Such factors include adoption of pro-competitive state policies and
actions by utilities to undertake mutually beneficial voluntary
transactions that do not require the use of open access tariffs
mandated under this rule. Commenters who advocate either a different
``no-action'' alternative or the frozen efficiency case expect that
studies using those assumptions will show that the rule will cause
significantly greater NOX emissions than shown in the
DEIS.933
---------------------------------------------------------------------------
\933\ See Section V, Discussion, Subsection C.
---------------------------------------------------------------------------
Assuming these results, these commenters raise their second major
area of concern, which is mitigating the presumed effects of the rule.
These arguments vary somewhat but share a common theme: That the
Commission has a responsibility, either as a legal or public policy
matter, to mitigate what they expect to be the significant
environmental impact associated with the rule. They suggest various
mitigation schemes, including a FERC-administered NOX emission
allowance program along the lines of the sulfur dioxide (SO2)
program enacted by Congress and administered by the EPA under the Clean
Air Act. Other proposals would have the Commission condition the right
of a seller to use an open access tariff on certification that the
source of the power sold is in compliance with (as yet undetermined)
emissions limitations. Another proposal would have the Commission
impose a charge on emissions to be paid by utilities to a fund
established by the Commission. The added cost to the utilities would
work to account for, or ``internalize'', the external costs of
emissions.
Commenters advocating Commission-administered mitigation argue that
the mechanisms under current law for regulating NOX emissions are
cumbersome and slow, and that the Commission should not (some argue,
may not) go forward with the rule unless it puts in place environmental
regulatory mechanisms that prevent further increases in NOX
emissions.
Various legal theories are advanced as a basis for Commission
environmental regulation under the Federal Power Ac
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
t. Some argue that
the conditioning authority under the Federal Power Act is sufficient to
enable us to fashion comprehensive controls on emissions from utility
generators because there is a direct causal nexus between power trading
(which we regulate) and generation (which we do not). Others argue that
such authority lies in the use of our power to impose requirements on
utilities ``in the public interest'', enhanced by the National
Environmental Policy Act. Others argue that, in remedying undue
discrimination, we must correct competitive advantages arising from
Congressional decisions to exempt certain kinds of generation
facilities from some Clean Air Act regulation.
C. Commission Conclusions
After reviewing the comments and the additional studies conducted
by staff in response to the comments, the Commission adopts the
findings in the FEIS.
First, the findings show that, without the rule, NOX emissions
are expected to decline until at least the year 2000. Thereafter, again
without the rule, NOX emissions are expected to increase steadily
through the year 2010 (the end of the FEIS study period). The extent of
the decrease and the increase will largely be determined by the
relative prices of natural gas and coal, the two main fuels used to
generate electric power in most regions.934
---------------------------------------------------------------------------
\934\ Generally, a relative advantage for coal is likely to
increase environmental impacts while a relative advantage for
natural gas is likely to create modest environmental benefits.
---------------------------------------------------------------------------
In reaching this conclusion, the FEIS used two ``base'' cases. In
one (the ``High-Price-Differential Base Case''), natural gas was
assumed to become substantially more expensive compared with coal than
it is today. In the other (the ``Constant-Price-Differential Base
Case''), natural gas was assumed to maintain essentially the same price
relative to coal that has existed for the last ten years. The two cases
describe the range of emissions due to fuel price uncertainty without
the rule and demonstrate the overall trends of decreases until 2000 and
increases thereafter.
Second, the FEIS finds that the rule will not in any significant
respect affect these overall trends.
The potential impact of the rule was studied initially under two
scenarios.935 In one (the ``Competition-Favors-Gas Scenario''),
the rule is assumed to result in efficiency gains in the electric
industry that would tend to favor natural gas as a fuel. In this
scenario the effect of the rule is slightly beneficial. Total NOX
emissions are reduced overall by about two percent nationwide from the
base cases. In the other (the ``Competition-Favors-Coal Scenario''),
the rule is assumed to result in efficiency gains in the electric
industry that would tend to favor coal as a fuel. In this scenario the
effect is again slight, showing approximately a one percent increase in
NOX emissions nationwide from the base cases. In both scenarios,
however, the rule does not have an overall effect on NOX emission
trends.
---------------------------------------------------------------------------
\935\ A third scenario considered improved conditions for the
transmission system only. This scenario showed very small effects
from the rule and is not addressed further here.
---------------------------------------------------------------------------
Stated differently, under any case studied, with or without the
rule, there will be an overall net decrease in NOX
[[Page 21672]]
emissions through the year 2000.936 Thereafter, NOX emissions
begin to increase. The rule does not materially affect either the
decline prior to 2000 or the increase thereafter.
---------------------------------------------------------------------------
\936\ These results are set forth graphically and in tabular
form in the FEIS at pp. ES-3 and ES-13. They are also reproduced in
Appendix H.
---------------------------------------------------------------------------
Based on these findings the Commission concludes that a
comprehensive, Commission-imposed mitigation scheme to address the
environmental consequences of the rule is not appropriate. If
competition favors gas, the effects are beneficial and mitigation is
unnecessary. If competitive conditions favor coal through the year
2010, and NOX emissions increase slightly as a result of the rule,
these minor effects would be effectively mitigated as a part of a
comprehensive NOX cap and trading allowance scheme developed by
EPA in cooperation with the Ozone Transport Assessment Group (OTAG) and
administered by EPA and state environmental regulators under the
clearly established authority of the Clean Air Act.
Further, the Commission believes that staff has selected the
appropriate ``no-action'' alternative. An alternative that requires the
Commission to reverse all its other open access policies is simply not
a ``no-action'' alternative. To the contrary, it would require decisive
action running counter to the direction from the Congress in the Energy
Policy Act and the needs of the marketplace and electricity consumers.
However, to ensure that the effects of the rule were analyzed
fully, the FEIS did study a reference case based on the ``frozen
efficiency'' case proffered by EPA and the Department of Energy
(DOE).937 Although, as described below, we believe this case to be
highly unlikely, the results show that, even under this scenario, the
impacts of the rule are not great and do not vary significantly from
those projected by staff under the other assumptions.
---------------------------------------------------------------------------
\937\ Although DOE agreed with EPA's request that we analyze the
frozen efficiency case as a reference case, DOE believes that the
DEIS selected the appropriate base case. DOE also argues that the
mitigation of any adverse consequences from the rule should be
addressed by EPA under the Clean Air Act or by the Congress.
---------------------------------------------------------------------------
In one case requested by EPA, staff studied a combination of
assumptions most likely to show significant increases in emissions
associated with the rule; the case included EPA's frozen efficiency
scenario, coupled with the ``Competition-Favors-Coal'' assumptions.
Other cases requested by EPA posit dramatic increases in transmission
capacity (that we find highly unlikely). Even this combination of
assumptions--geared to demonstrate the greatest impact the rule might
have on increased NOX emissions--produced little in the way of
environmental consequences associated with the rule. Under these
extreme (and unlikely) conditions, there would still be a net decrease
in NOX emissions until at least the year 2000, albeit a smaller
decrease than in the base cases. Comparing projections of emissions for
the same years, emissions would be higher than the base cases only by
two percent in 2000 and three percent in 2005.938 It is only in
the year 2010, assuming these improbable scenarios, that NOX
emissions associated with the rule would be higher than the base case
by even five percent.939
---------------------------------------------------------------------------
\938\ FEIS Table 6-10 at p. 6-17.
\939\ Id.
---------------------------------------------------------------------------
Based on these studies, including the EPA reference case, the
Commission endorses the staff findings that the rule will affect air
quality slightly, if at all, and that the environmental impacts are as
likely to be beneficial as negative. This is true even under scenarios
contrived to maximize emissions associated with the rule under
circumstances that this Commission believes to be highly unlikely.
Importantly, this is also true in the near- to mid-term. Until the
year 2010, even the worst case (the frozen efficiency case) produces
results very similar to those produced using assumptions the Commission
believes to be reasonable. In short, the rule will not produce an
``ozone cloud'' coming across the Appalachians to threaten the
Northeast on the day the rule goes into effect. Assuming that any
environmental impacts occur, they are years in the future and may well
be beneficial. As a result, calls for Commission mitigation, and in
particular for interim mitigation to ``fill the gap'' until programs
under the Clean Air Act can be adopted, are unnecessary and
disproportionate to the possible effects of the rule.
We also endorse the staff view that it is neither within our
statutory authority nor appropriate as a matter of policy to fashion
from the FPA a comprehensive clean air regulatory program to address
NOX emissions. As described below, we believe that the mitigation
proposals proffered in comments exceed our statutory authority to
regulate rates, terms and conditions of sales of electric energy and
transmission of electric energy in interstate commerce. We are, in
essence and by law, economic regulators. While we have an obligation
under NEPA to take the environmental consequences of our actions into
account in fashioning our decision--and we have done so--NEPA grants us
no new regulatory powers. While NEPA extends our general obligation to
engage in reasoned decisionmaking to include the consideration of
possible environmental consequences of our actions, it compels no
particular substantive result.
Though our conditioning authority under sections 205 and 206 of the
FPA is broad, our actions under it are confined to the subject matter
of our jurisdiction. That subject matter excludes the physical aspects
of generation and transmission. Our actions must derive from and
advance our statutory mandate to protect consumers by establishing
utility rates and business practices that are just, reasonable, and not
unduly discriminatory or preferential. These authorities, however broad
they are with respect to economic matters, are not unbounded; they may
not be used to ``fill in the gaps'' of regulatory programs that, by
law, are not our own.
Moreover, even if it were possible to tease from the FPA some
implicit authority to regulate NOX emissions from utility
generators, it is not feasible for this Commission to develop and
implement such a program. The mitigation schemes presented in comments
are filled with unknowns and complexities that are best resolved by
those charged with administration of the Nation's environmental laws.
In some cases, the mitigation schemes are based on a model of utility
transactions that is fundamentally at odds with the purposes of the
rule. For example, several proposals would require the Commission to
establish whether emissions from certain units or systems contribute to
ozone noncompliance elsewhere, perhaps hundreds of miles away. Other
proposals would require the Commission to establish baseline standards
for emissions; generating units with emissions above that level would
be required to adopt mitigation measures. The technical difficulties
associated with these proposals are evident on their face. While
resolving these issues is necessary to establish an effective NOX
regulatory program, the Commission does not possess the requisite
expertise to establish baseline NOX emission levels and address
the difficult technical and policy issues that are presented in
regulating NOX emissions. EPA is the agency with jurisdiction over
and experience with such matters. Although efforts are underway to
resolve these issues within the framework of the Clean Air Act, all air
regulators agree that much work still needs to be done.
[[Page 21673]]
Other proposals would require the Commission to track generation
that is used for wholesale versus retail sales. However, for example,
use of holding company corporate structures, as well as emerging market
structures, would make it extremely difficult, if not impossible to
distinguish between retail and wholesale transactions. In addition,
such measures are inconsistent with the goals of the rule (and the
Energy Policy Act) to eliminate time-consuming, inefficient
transaction-based approvals that impede open access and to promote
entry of sellers into bulk power markets on a competitive basis.
Moreover, any such program implemented by this Commission could
well undercut the existing regulatory scheme crafted by Congress under
the Clean Air Act, as amended. In particular, we are being asked
essentially to rework the legislative decisions made by Congress
regarding certain coal-fired generators. Those decisions are at the
heart of the 1990 Clean Air Act compromise. The only means Congress has
made available for addressing these problems under current law are in
the Clean Air Act. If these means prove insufficient to address the
NOX problem overall, the case for change must be presented to the
Congress.
Although we have concluded that NOX emissions problems are
most effectively addressed by clean air regulations within the
framework of the Clean Air Act, we do recognize that the question of
NOX emissions is a very important one. Our FEIS documents that,
with or without this rule, NOX emissions from all sources are
expected to increase over time. This will present a significant
environmental issue for the Northeast, which is already struggling to
reach current NOX reduction standards, as well as for other
regions of the country that are being called on to participate in an
inter-regional solution to the NOX problem. As the EPA rightly
recognizes, attempting to frame an appropriate solution with the tools
currently available is a tough job. We therefore understand why those
concerned would try to enlist this Commission in an effort to solve
this problem with regulatory mechanisms other than those set out in the
Clean Air Act. We also understand why even the prospect of exacerbating
that problem would ignite the kind of controversy reflected in the
comments to this rule, and why, in response, those who have gained
Congressional exemptions from certain regulations wish not to have
those benefits undermined. At the same time, we understand, and have
great sympathy with, the many commenters who have suggested that the
economic benefits of this rule to consumers should not be suppressed or
delayed by this difficult, ongoing debate.
Our FEIS clearly demonstrates that this rule is not the appropriate
vehicle for resolving this very important debate. We believe that our
study makes a significant contribution nonetheless. We have added
significantly to the understanding of the problem and have established
a viable, current baseline for assessing future industry trends. This
baseline should serve air regulators well in analyzing overall NOX
emissions in the future.940 We have resolved some important
questions about the role of open access and have established clearly
the influence of energy prices on NOX emissions in the future.
---------------------------------------------------------------------------
\940\ For example, the data we used to project future industry
generation and fuel use update by several years the data relied upon
by EPA in its Regulatory Impact Analysis used as a basis for its
recently proposed NOX rule, entitled ``Acid Rain Program;
Nitrogen Oxides Emission Reduction Program.'' 61 FR 1442 (1996). We
believe the data developed in the FEIS will make a useful
contribution to EPA's effort.
---------------------------------------------------------------------------
Our study also supports the view held by many commenters that the
appropriate regulatory mechanisms for addressing the NOX problem
overall, including emissions from electric utility generating plants,
is a NOX emissions cap and allowance trading scheme along the
lines of that developed by the Congress under the Clean Air Act for
SO2 emissions. As staff suggests, even if there are slight
environmental impacts associated with the rule, they are better and
more effectively addressed as a part of a comprehensive NOX
regulatory program. While Congress did not enact such a scheme for
NOX, it did, as described below, empower the EPA to establish such
a program. The EPA is the only federal agency with clear authority and
expertise to address this problem. It should do so.
The FEIS also identifies the importance of OTAG to the development
of a fair and effective NOX regulatory program. OTAG, which
includes representatives from all affected states, is currently at work
developing the analytic basis needed for a regional consensus solution
to the NOX problem. OTAG is also evaluating possible solutions,
including an allowance trading scheme. We believe that OTAG's efforts
are to be applauded, and we encourage the EPA and all interested
parties to work with OTAG to address this issue of national concern.
Discussion
A. Compliance With NEPA Requirements
1. Background
The Commission issued a NOPR in this proceeding on March 29, 1995.
In doing so, we concluded that promulgating the proposed Rule would not
represent a major federal action having a significant adverse impact on
the human environment and that the proposed Rule fell within the
categorical exemption provided in the Commission's regulations for
electric rate filings submitted by public utilities under sections 205
and 206 of the FPA.941 Subsequently, the Commission determined
that, despite the availability of the categorical exclusion, it would
nonetheless prepare an environmental analysis. On July 12, 1995, the
Commission directed staff to prepare an EIS to assess the environmental
impacts of the proposed Rule. That notice requested comments on
environmental issues and scheduled a scoping meeting for September 8,
1995.942
---------------------------------------------------------------------------
\941\ 18 CFR 380.4(a)(15).
\942\ 60 FR 36752 (1995).
---------------------------------------------------------------------------
A Notice of Availability of the DEIS was published in the Federal
Register on November 27, 1995.943 The DEIS evaluated several
potential alternatives and mitigation measures as summarized below.
---------------------------------------------------------------------------
\943\ 60 FR 58304 (1995).
---------------------------------------------------------------------------
A Notice of Availability of the FEIS was published in the Federal
Register on April 19, 1996.944
---------------------------------------------------------------------------
\944\ 61 Fed.Reg. 17,296 (1996).
---------------------------------------------------------------------------
2. General Requirements
Section 102 of NEPA, 42 U.S.C. 4332, requires that federal agencies
prepare an EIS on proposals for major federal actions significantly
affecting the quality of the human environment. The objective is to
build into the agency decisionmaking process careful consideration of
environmental aspects of proposed actions, including the evaluation of
reasonable alternatives. Although we believe a categorical exclusion to
be available,945 the Commission has performed this EIS to ensure
that this Rule is promulgated with the benefit of careful consideration
of its environmental aspects.
---------------------------------------------------------------------------
\945\ See 40 CFR 1507.3 (1995); 18 CFR 380.4 (1995).
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3. Alternatives
The consideration an agency must give in an EIS to alternatives to
its proposed action is bounded by a number of factors, including
notions of feasibility, whether basic changes would
[[Page 21674]]
be required to the statutes and policies of other agencies, and the
extent to which the proposal would result in significant impacts. The
United States Supreme Court (Supreme Court or Court) stated what is
required in an EIS with regard to alternatives in Vermont Yankee
Nuclear Power Corp. v. NRDC, 435 U.S. 519, 551 (1978): ``(A)s should be
obvious even upon a moment's reflection, the term `alternatives' is not
self-defining. To make an impact statement something more than an
exercise in frivolous boilerplate the concept of alternatives must be
bounded by some notion of feasibility.'' 946 In this regard, the
Supreme Court quoted Natural Resources Defense Council v. Morton, 458
F.2d 827, 837-38 (D.C.Cir. 1972), with approval as follows:
---------------------------------------------------------------------------
\946\ Vermont Yankee, 435 U.S. at 551.
---------------------------------------------------------------------------
There is reason for concluding that NEPA was not meant to
require detailed discussion of the environmental effects of
``alternatives'' put forward in comments when those effects cannot
be readily ascertained and the alternatives are deemed only remote
and speculative possibilities, in view of basic changes required in
statutes and policies of other agencies--making them available, if
at all, only after protracted debate and litigation not meaningfully
compatible with the time-frame of the needs to which the underlying
proposal is addressed.
The Supreme Court went on to discuss the concept of ``feasibility'',
stating that:
Common sense also teaches us that the ``detailed statement of
alternatives'' cannot be found wanting simply because the agency
failed to include every alternative device and thought conceivable
by the mind of man. Time and resources are simply too limited to
hold that an impact statement fails because the agency failed to
ferret out every possible alternative, regardless of how uncommon or
unknown that alternative may have been at the time the project was
approved.947
---------------------------------------------------------------------------
\947\ Id.
---------------------------------------------------------------------------
Thus, an EIS must discuss the alternatives that are feasible and
briefly discuss the reasons others were eliminated. There is no minimum
number of alternatives that must be discussed.948 An agency's
consideration of alternatives is adequate if it considers an
appropriate range of alternatives--it does not have to consider every
available alternative.949
---------------------------------------------------------------------------
\948\ Laguna Greenbelt, Inc. v. DOT, 42 F.3d 517, 524-25 (9th
Cir. 1994).
\949\ Resources Limited, Inc. v. Robertson, 35 F.3d 1300, 1307
(9th Cir. 1993).
---------------------------------------------------------------------------
The range of alternatives that must be considered in the EIS need
not extend beyond those reasonably related to the purposes of the
project.950 An agency is entitled to identify some parameters and
criteria related to the proposal for generating alternatives to which
it would devote serious consideration. Without such criteria, an agency
could generate countless alternatives.951 Alternatives that are
unlikely to be implemented need not be considered, nor must an agency
consider alternatives that are infeasible, ineffective, or inconsistent
with basic policy objectives.952 In this sense, central to
evaluating practicable alternatives is the determination of a project's
purpose.953
---------------------------------------------------------------------------
\950\ Id.
\951\ Id.
\952\ Id.
\953\ National Wildlife Federation v. Whistler, 27 F.3d 1341,
1345 (8th Cir. 1994).
---------------------------------------------------------------------------
Furthermore, the range of alternatives that reasonably must be
considered decreases as the environmental impact of a project becomes
less and less substantial. If a proposal would have minimal
environmental effect, the range of alternatives that must be considered
is narrow. It would be an anomaly to require that an agency search for
more environmentally sound alternatives to a project that it has
determined will have no significant environmental effects.954
Moreover, feasible alternatives may be rejected if they present unique
problems or cause extraordinary costs and community disruption.955
---------------------------------------------------------------------------
\954\ Missouri Mining, Inc. v. ICC, 33 F.3d 980, 984 (8th Cir.
1994).
\955\ Communities, Inc. v. Busey, 956 F.2d 619, 627 (6th Cir.),
cert. denied, 506 U.S. 953 (1992).
---------------------------------------------------------------------------
As applied to the instant case, NEPA does not require the
consideration of alternatives that are remote and speculative
possibilities because they would require basic changes to statutes and
policies. Therefore, alternatives that would require the Commission to
ignore open access policies enacted by Congress in the Energy Policy
Act and to assume such policies would not be pursued by the states are
not feasible and need not be considered. Likewise, the Commission need
not consider alternatives that are ineffective or inconsistent with
basic policy objectives, or that would cause extraordinary costs and
community disruption. Finally, because the rule would have minimal
environmental effect, the range of alternatives that must be considered
is narrow. We conclude that staff has examined the appropriate
alternatives in the FEIS and correctly determined that promulgation of
the rule represents the most appropriate action.
Certain commenters have argued that the alternative that calls for
the Commission to abandon the policy of promoting transmission access
is more appropriate for the no-action alternative than the no-action
alternative selected by the staff.956 We disagree. As discussed
below, that contention is more properly an argument about the
appropriate baseline to use in the FEIS. That debate has been resolved
by the consideration of a reference case that includes a baseline which
bounds the effects that those commenters seek to have analyzed.
---------------------------------------------------------------------------
\956\ See Section V, Discussion, Subsection B.2.
---------------------------------------------------------------------------
4. Mitigation
To fulfill the requirements of NEPA with regard to mitigation, an
agency must identify and evaluate the adverse environmental effects of
the proposed action, in this case the rule. Having identified and
evaluated adverse environmental effects, the agency is not constrained
from then deciding that other values outweigh the environmental costs
of the proposal.
The leading case interpreting this requirement is Robertson v.
Methow Valley Citizens Council, 490 U.S. 332 (1989)(Methow Valley).
There, the Court explained that:
Although these procedures (preparation and circulation of an EIS)
are almost certain to affect the agency's substantive decision, it
is now well settled that NEPA itself does not mandate particular
results, but simply prescribes the necessary process. If the adverse
environmental effects of the proposed action are adequately
identified and evaluated, the agency is not constrained by NEPA from
deciding that other values outweigh the environmental costs * * *.
Other statutes may impose substantive environmental obligations on
federal agencies, but NEPA merely prohibits uninformed--rather than
unwise--agency action.957
\957\ Methow Valley, 490 U.S. at 350-51 (citations and footnote
omitted) (emphasis added).
---------------------------------------------------------------------------
The Court held that ``(t)o be sure, one important ingredient of an EIS
is the discussion of steps that can be taken to mitigate adverse
environmental consequences.'' 958 This is so because:
---------------------------------------------------------------------------
\958\ Id. at 351 (footnote omitted).
---------------------------------------------------------------------------
Implicit in NEPA's demand that an agency prepare a detailed
statement on ``any adverse environmental effects which cannot be
avoided should the proposal be implemented, 42 U.S.C. 4332(C)(ii),
is an understanding that the EIS will discuss the extent to which
adverse effects can be avoided. More generally, omission of a
reasonably complete discussion of possible mitigation measures would
undermine the ``action-forcing'' function of NEPA. Without such a
discussion, neither the agency nor other interested groups and
individuals can properly evaluate the severity of the adverse
effects * * * .959
\959\ Id. at 351-52 (citation omitted).
---------------------------------------------------------------------------
The Court acknowledged that:
There is a fundamental distinction, however, between a requirement
that mitigation be
[[Page 21675]]
discussed in sufficient detail to ensure that environmental
consequences have been fairly evaluated, on the one hand, and a
substantive requirement that a complete mitigation plan be actually
formulated and adopted, on the other * * *. Even more significantly,
it would be inconsistent with NEPA's reliance on procedural
mechanisms--as opposed to substantive, result-based standards--to
demand the presence of a fully developed plan that will mitigate
environmental harm before an agency can act.960.
\960\ Id. at 352-53 (citation and footnote omitted).
---------------------------------------------------------------------------
The Court again stressed that ``(b)ecause NEPA imposes no
substantive requirement that mitigation measures actually be taken, it
should not be read to require agencies to obtain an assurance that
third parties will implement particular measures.'' 961 Thus, the
Court held that mitigation, including mitigation that other
governmental bodies have jurisdiction to implement, must be discussed
in sufficient detail to ensure that environmental consequences of a
proposed action have been fairly evaluated. However, a complete
mitigation plan need not be actually formulated or adopted.
---------------------------------------------------------------------------
\961\ Id. at 353 n .16.
---------------------------------------------------------------------------
The suggestion by various commenters that the Commission is
required to adopt and implement a plan to mitigate the impacts of the
rule is without legal or factual basis. Even if the effects of the rule
were greater than the FEIS shows them to be, Methow Valley clearly
establishes that, regardless of the impacts of the proposed action, the
Commission is required only to understand the impacts of its actions.
This compels us to consider and discuss mitigation; it does not require
us to adopt and implement mitigation. This FEIS thoroughly examines
mitigation of possible adverse environmental effects and concludes that
sufficient mechanisms exist to address the impacts of the rule, if any.
5. Role of EPA
Section 309 of the Clean Air Act, 42 U.S.C. 7609, authorizes EPA to
review and comment on environmental impact statements prepared by
federal agencies. If the EPA Administrator determines that a proposed
regulation is unsatisfactory from, among other things, the standpoint
of environmental quality, she may refer the matter to the Council on
Environmental Quality (CEQ).962
---------------------------------------------------------------------------
\962\ The process appropriate for CEQ referral of actions by an
independent regulatory agency is not addressed here.
---------------------------------------------------------------------------
In this case, EPA has commented extensively on the DEIS. It sought
changes to the staff's analysis, primarily to include the use of the
frozen efficiency assumptions. The staff has fully complied with EPA's
study requests even though it regards such assumptions as implausible,
contrary to the Energy Policy Act and Commission policy, and at odds
with industry trends and practical considerations affecting the
industry.963
---------------------------------------------------------------------------
\963\ For example, see the discussion on transmission
constraints at Section V, Discussion, Subsection C.
---------------------------------------------------------------------------
Although EPA may disagree with the environmental acceptability of
an agency's proposal, the agency is charged with making the ultimate
determination whether to implement a proposal; in making that decision,
the agency is free to reject advice offered through the comment and
referral process.964 Objections on the part of EPA may give rise
to a heightened obligation of the agency to explain clearly and in
detail its reasons for proceeding in the face of those objections. This
the Commission has done. It has thoroughly examined the impact of the
assumptions advanced by EPA; that analysis is detailed in Chapter 6 of
the FEIS.965
---------------------------------------------------------------------------
\964\ See Alaska v. Andrus, 580 F.2d 465 (D.C. Cir.), vacated in
part on other grounds sub nom. Western Oil & Gas Ass'n v. Alaska,
439 U.S. 922 (1978).
\965\ The Commission bears the ultimate responsibility for
evaluating the environmental impacts of the rule. In doing so, it
must consider EPA's comments, but is not bound by them. See Citizens
Against Burlington, Inc. v. Busey, 938 F.2d 190, 201 (D.C.Cir.),
cert. denied, 502 U.S. 994 (1991). In that case the Court held that:
Congress wants the EPA to participate when other agencies
prepare environmental impact statements. See 42 U.S.C. 7609(a). The
EPA participated here. But the (Federal Aviation Agency), not the
EPA, bore the ultimate statutory responsibility for actually
preparing the environmental impact statement, and under the rule of
reason, a lead agency does not have to follow the EPA's comments
slavishly--it just has to take them seriously. See Alaska v. Andrus,
580 F.2d at 474.
---------------------------------------------------------------------------
In summary, NEPA prescribes a process and not a result. What is
critical is that environmental impacts of a proposed action be
adequately identified and evaluated--an important component of this
process is understanding the possible mitigation measures that are
involved, including measures which may be beyond the jurisdiction of an
agency to implement. This requirement does not translate, however, into
a requirement that an EIS adopt a mitigation plan, particularly where,
as here, the impacts of the rule are small and may be either positive
or negative.
B. Analysis of Alternatives
The FEIS evaluated three alternatives to the rule including: (1) A
no-action alternative which assumes that the rule is not adopted, but
that existing statutory and regulatory policies remain in place; (2) a
Commission decision to reverse existing policies and halt
implementation of mandatory open access; and (3) a Commission decision
to aggressively develop competitive power markets by mandating
corporate reorganization or divestiture.
1. The No-Action Alternative
The principal alternative to the proposed action is for the
Commission not to adopt the rule, but to continue its existing open
access and stranded cost policies. In recent years, the Commission has
required public utilities that merge or seek to acquire jurisdictional
transmission facilities under section 203 of the FPA to file open
access transmission tariffs. The Commission also has required public
utilities to file open access transmission tariffs to mitigate market
power and to ensure non-discrimination if they or their affiliates wish
to sell power at market-based rates. In addition, the Commission
processes case-by-case requests made by potential transmission users
under section 211 of the Energy Policy Act for transmission service,
and has allowed utilities to include stranded cost provisions in their
open access transmission tariffs on a case-by-case basis.966
---------------------------------------------------------------------------
\966\ See Section III.
---------------------------------------------------------------------------
Actions taken pursuant to section 211, and pursuant to sections 203
and 205 in merger and market-based rate cases respectively, represent a
case-by-case approach to establishing open access. By contrast, the
rule would, in a single generic proceeding, require each jurisdictional
public utility to file open access tariffs at the same time. The
consumer benefits from the rule are expected to be $3.8 to $5.4 billion
per year.967
---------------------------------------------------------------------------
\967\ See Section I.
---------------------------------------------------------------------------
Absent action on the rule, the Commission would continue on a case-
by-case basis to require public utilities to file open access tariffs
and provide case-specific service as necessary or appropriate. Sections
205 and 206 charge the Commission with ensuring that voluntary
transmission tariffs are not unduly discriminatory. If the rule were
not adopted, the Commission would continue to require that voluntary
tariffs be upgraded to offer non-discriminatory open access
transmission services pursuant to the Commission's current standards.
The result of continuing the Commission's policies without the rule is
that the Commission would effectuate a more open transmission grid than
is present today, but in a patchwork manner and at a slower pace. Over
some extended time period, many, but not necessarily
[[Page 21676]]
all, utilities would become subject to open access requirements.
The case-by-case approach to achieving open access now in use is
slower and more costly, and thereby less desirable, than the generic
approach set forth in the rule. Given the rapid changes facing the
industry, and the opportunity for great consumer savings, the no-action
alternative is not a reasonable alternative to the rule.
2. Abandon the Policy of Promoting Transmission Access
A second alternative is for the Commission to abandon its current
policy and take no action whatsoever to foster transmission access.
Under this alternative, the Commission would no longer require open
access transmission as a condition of mergers and asset acquisitions
under section 203 or requests for market-based pricing under section
205, and would no longer grant applications filed pursuant to section
211. Offers of transmission would become strictly voluntary.
This alternative is inconsistent with Congress' general intent in
the Energy Policy Act to foster wholesale competition, and also with
its specific intent in expanding section 211 to permit the Commission
to require a transmission-owning utility to make its transmission
system available to eligible users if to do so is in the public
interest. This alternative is also inconsistent with the Commission's
obligations under sections 205 and 206 to ensure that public utilities
do not unduly discriminate in providing jurisdictional services. It is,
therefore, not a reasonable alternative to the rule.
3. Corporate Reorganization/Divestiture Alternative
Under this alternative, the Commission would require public
utilities either to divest control of their transmission assets or to
reorganize their corporate structures to perform their transmission
functions through a separate subsidiary, thereby segregating
transmission from the rest of the utilities' operations. However,
corporate reorganization or divestiture would have no effect on the
operation of power plants, which are assumed to be dispatched on the
basis of economic efficiencies. Thus, this alternative would lead to
the same environmental impacts as the rule. That is, the environmental
effects would be no different from those studied in the FEIS.
C. The Scope of the FEIS
The FEIS examines the environmental impacts that could result from
implementing this rule. This analysis is undertaken against the
background of the existing electric industry. The electric industry
currently produces environmental impacts, and those impacts are certain
to change over time as the industry responds to factors as varied as
changes in demand for electricity, the price of fuels, changes in
regulatory programs, technological developments, and changes in market
structure.
The FEIS does not examine the environmental impact of electric
generation that is required to meet generators' existing service
requirements. Nor does it examine the environmental effects of the
inter-utility power exchanges that have occurred in the industry for as
long as utilities have been interconnected. Rather, the FEIS examines
impacts of potential increases in generation and changes in patterns of
generation that might result from implementation of the rule.
In creating an analytical construct to examine the impacts of the
rule, the staff developed a set of cases that defined the framework for
running the computer models utilized to examine the changes in types of
power plants constructed in the future and changes in operating
patterns of existing power plants, including changes in fuel mix.
First, staff characterized how electric power markets might evolve
absent adoption and implementation of the rule by establishing
baselines (i.e., base cases) to project the future impacts of the
industry.968 The relative prices of coal and natural gas are
critical in establishing what is likely to happen in the future.
Accordingly, a range of prices was developed to project the impacts of
these factors. In the first baseline, the Constant-Price-Differential
Base Case, coal and natural gas prices are assumed to maintain the same
relative position they have maintained over the past ten years. In the
second baseline, the High-Price-Differential Base Case, natural gas is
assumed to become substantially more expensive compared with coal than
it has been over the past 10 years. In all other respects, the
assumptions underlying the two base cases are the same.
---------------------------------------------------------------------------
\968\ As discussed below, once baselines were established to
portray what is likely to happen in the electric industry without
the rule, the projected impacts of the rule were then determined
against this background.
---------------------------------------------------------------------------
Because the purpose of the base cases is to describe the impacts of
the electric industry if the Commission takes no action over and beyond
continued implementation of existing policies, the baselines assume
that the Commission continues the open access and stranded cost
policies it has instituted in recent years.
Some commenters have challenged this aspect of the baselines used
in the study. The gist of their argument is that the environmental
impacts of these programs have not been evaluated and that the
baselines therefore improperly take credit for impacts that have not
yet occurred, thus understating the projected impacts of the rule. In
general, these commenters argue that the second alternative considered
by the staff represents the ``true'' no-action alternative.
At bottom, this debate is not about what constitutes the
appropriate no-action alternative. Rather, it is a debate about what
aspects of the electric industry should be taken into account when
determining future environmental impacts of the industry against which
to measure the impacts of the rule. The commenters urge the Commission
to consider varying baselines, but in general they oppose inclusion in
the base cases of the Commission's ongoing open access and stranded
cost programs.
Some commenters not only urge that the Commission not take into
account continued implementation of its open access and stranded cost
programs, but that it go much farther and establish baselines (against
which to examine the impacts of the rule) that do not reflect the
impacts of a great many changes that are already taking place in the
electric industry. This proposal would establish a baseline that does
not take into account: (1) Current Commission transmission policy; (2)
programs that states and industry players have adopted to improve
industry efficiency; and (3) mutually beneficial transactions that
electric companies enter into on a regular basis.
The use of these assumptions would fly in the face of long-standing
industry trends which move in precisely the opposite direction.
Utilities are reducing reserve margins, improving plant availabilities,
and reducing barriers to transmission even without Commission
action.969 Many states are aggressively pursuing plant efficiency
policies.970 These trends are long-standing and are not
attributable to the rule, or even to a broader Commission program of
open access. These trends, projected into the future, form the basis
for the conditions reflected in the FEIS base cases. These trends are
fundamentally at odds with the assumptions some commenters wish the
Commission to use to establish baselines.
---------------------------------------------------------------------------
\969\ FEIS Chapter 6.
\970\ Id.
---------------------------------------------------------------------------
[[Page 21677]]
We conclude that the approach used by staff to develop the
baselines used in the FEIS is appropriate. Abandoning current open
access policies is unrealistic, contrary to Congressional intent, and
at odds with pro-competition policies that are at the heart of the
Commission's current regulatory mission. The selection of the
appropriate methodology to establish the baselines used in the FEIS is
clearly within the Commission's discretion and expertise.971
---------------------------------------------------------------------------
\971\ See, e.g., Sierra Club v. Marita, 46 F.3d 606, 621, 623
(7th Cir. 1995).
---------------------------------------------------------------------------
What the commenters challenging this assumption desire is
additional study of the impacts of the rule. Specifically, they wish to
test the rule against a different set of assumptions for the
acknowledged purpose of attributing greater adverse environmental
consequences to the rule. The regulations of the Council on
Environmental Quality no longer contain a requirement to conduct a
conjectural ``worst-case analysis.'' 972 NEPA requires an agency
to adequately identify and evaluate the adverse environmental effects
of a proposed action.973 It does not require the agency to ignore
the world as it exists.
---------------------------------------------------------------------------
\972\ Methow Valley, 490 U.S. at 354-55. The revised
requirement, 40 CFR 1502.22, which pertains to incomplete or
unavailable information, is inapplicable as well. The problem here
is not incomplete or unavailable information, but rather which
existing policies and events should be included in the analysis.
\973\ 42 U.S.C. 4332.
---------------------------------------------------------------------------
Nonetheless, to respond to concerns about the baselines used in the
DEIS with respect to key atmospheric emissions, the staff conducted
sensitivity analyses to examine the outer boundaries of a range of
cases requested by some commenters. This range of cases is called the
``frozen efficiency'' case. In essence, the frozen efficiency cases
assume that no further open access of any kind occurs during the study
period and that efficiency in the industry (for instance, power plant
availability) remains frozen through the same period. The assumption
that there is substantially more inter-regional transmission capacity
than posited in the original analysis is separately examined in the
base and rule cases.974
---------------------------------------------------------------------------
\974\ Several commenters, including EPA, are concerned that
increases in transmission capacities resulting from open access
might increase generation levels and thus air emissions. EPA is
especially concerned with the expansion of transmission links
between the midwest and east coast. The FEIS examines scenarios that
increase transmission capacity substantially beyond current levels.
This analysis finds that postulated increases do not affect
emissions attributable to the rule. We believe increases considered
in the FEIS far exceed any transmission capacity increases that
might occur as a result of the rule. This is due in part to the fact
that state-level siting issues, the principal barrier to major
capacity increases in the transmission grid, are unaffected by the
rule. The issues regarding enhancement of existing lines are more
complex. Competition under open access will lead to improved
efficiencies in generation. Transmission, on the other hand, will
remain a regulated monopoly function. The rule will reduce barriers
to access, but will not open the transmission system to direct
competition. Thus, we believe that the competitive effects of the
rule on transmission expansion will be relatively small.
EPA urges us to assume that transmission capacity is expanded by
40 percent compared to our base case. We do not believe this is
likely to occur. The experience with one proposed new transmission
line in the very area EPA focuses on demonstrates this difficulty.
Duquesne Light filed an application with the Pennsylvania Public
Utilities Commission to construct a new 500 Kv line across
Pennsylvania to supply electricity to New Jersey. Within a few days
of the filing of the application, over 3,000 individuals and groups
filed complaints in opposition to the proposed line. ``Electricity
Utility Week'' (November 4, 1991). A bill was proposed in the
Pennsylvania Legislature to prevent construction of the line.
Another bill was introduced in Congress to halt construction of new
transmission lines throughout the U.S. for two years. Duquesne
ultimately decided to withdraw its proposal and the line was not
constructed. ``The Energy Daily'' (April 4, 1994).
---------------------------------------------------------------------------
We must reiterate that the frozen efficiency case is far more
restrictive in its assumptions than a true no-action case in which the
Commission simply stops all efforts to promote open access. A true no-
action case would closely resemble the FEIS base cases because much of
the efficiency gain in that base case would occur even with no move
toward open access.
As detailed in Chapter 6 of the FEIS, and as discussed below, even
the frozen efficiency case demonstrates results that are essentially
the same as those demonstrated by the base cases used by the staff. In
the frozen efficiency worst case, when coal prices become considerably
more attractive compared to gas prices, national NOX emissions
would be lower than in the base cases used by staff by only one percent
(in 2000) to four percent (in 2010). If coal and natural gas prices
remain at today's relative levels, the effects would be smaller--zero
percent in 2000 to two percent lower in 2010. National CO2
emissions would be between zero and two percent lower than in the base
cases used by the staff over the same time frame.
D. Economic and Environmental Impacts of the Rule
The FEIS reports a quantitative estimate of approximately $3.8
billion to $5.4 billion in benefits per year of cost savings expected
from competition under the rule. The FEIS also considers other, non-
quantifiable benefits that can be expected from implementing the rule.
These benefits include better use of existing assets and institutions,
new market mechanisms, technical innovation, and less rate distortion.
Further, the FEIS demonstrates to our satisfaction that the rule is
likely to have little or no adverse environmental impact and that any
impacts are as likely to be beneficial as harmful.
The issue most frequently raised by commenters involves air quality
impacts, particularly the possible transport of NOX emissions from
upwind areas to airsheds in the Northeast and the resulting impacts on
ozone non-attainment areas.
With regard to NOX, the FEIS demonstrates that, as a result of
clean air regulatory programs, NOX emissions nationwide, with or
without the rule, will decline through the year 2000, but begin to
climb thereafter.975 This basic trend remains the same in all
cases examined in the FEIS. This is because the level of NOX
emissions in any given year depends primarily on one key uncertainty
that is not related in any way to the rule--the relative price of
natural gas and coal.976 Lower prices for natural gas, relative to
coal, lead to lower levels of NOX emissions.
---------------------------------------------------------------------------
\975\ FEIS Figure ES-1 and Table ES-2, reproduced at Appendix H.
\976\ See, e.g., FEIS at ES-8.
---------------------------------------------------------------------------
The FEIS also demonstrates that increases in access to transmission
and efficiencies in electric power markets associated with the rule do
not alter the expected trend of NOX emissions, regardless of the
relative price of natural gas and coal. Increased transmission access
and industry efficiency facilitated by the rule may either decrease
total emissions somewhat or increase them somewhat, depending on
whether competitive conditions in the electric industry favor natural
gas or coal. When competitive conditions favor natural gas, the effect
of the rule is beneficial, reducing emissions somewhat. When
competitive conditions favor coal, emissions increase by a small
amount. Nevertheless, the overall trend of expected NOX emissions
retains its general shape.
In assessing the projected impacts of the electric industry absent
adoption of the rule (i.e., the base cases studied in the FEIS), the
most important factor affecting changes in national NOX emissions
is the relative competitive position of coal and natural gas. The most
important factor affecting the relative competitive positions of coal
and natural gas is price.
National NOX emissions from the electric industry were 5,844
thousand tons in 1993, the last year for which complete data is
available. If relative gas
[[Page 21678]]
and coal prices remain the same, for example, we project that national
NOX emissions will be 5,579 thousand tons in 2005 without adoption
of the rule. If gas prices rise relative to coal prices, we project
that NOX emissions in 2005 will be 6,053 thousand tons without
adoption of the rule. Stated another way, favorable coal prices are
projected to result in NOX emissions that are about three percent
higher in 2000 to 10 percent higher in 2010 over the base case where
gas is the favored fuel.
The effect of adopting the rule could be to raise or lower national
emissions slightly compared to the effects projected in the base cases.
Nationally, in 2005, we project that the Competition-Favors-Coal
Scenario (with rising relative gas prices) would add one percent to
NOX emissions above the base case that favors coal. The
Competition-Favors-Gas Scenario (with constant relative fuel prices)
would lower emissions by two percent compared with the base case that
favors gas.
Regional effects are generally similar. In 2005, in the East North
Central region (a source of potential increased NOX emissions that
might affect the Northeast), the base cases project small increases in
industry emissions (two percent). In that region in 2005, the rule may
add as much as one percent to NOX emissions compared to the
relevant base case (the Competition-Favors-Coal Scenario) or reduce
emissions compared to the relevant base case by as much as three
percent (the Competition-Favors-Gas Scenario).
The EIS uses the UAM-V model to track the effects of projected
NOX emissions on downstream ozone levels during a severe weather
period. This detailed air quality modeling shows no real difference in
the Northeast between the base case favoring coal (the High-Price-
Differential Base Case) and the Competition-Favors-Coal Scenario.
Detailed local analysis shows slightly lower ozone concentrations in
some locations and slightly higher concentrations in others. None of
the differences adds to non-attainment levels projected in the relevant
base case, and all fall within the noise levels of the model. That is,
they are smaller than the uncertainties in the science underlying the
model.
As discussed above, the Commission believes that the base cases
used by staff in its analysis are the most realistic and, therefore,
the most appropriate cases to consider the potential environmental
impacts of the rule. However, as requested by the EPA, DOE, and certain
other commenters, sensitivity analyses were conducted to examine the
impacts on the results of the analysis if key assumptions are changed
as requested by commenters. Presumably, comparing the projected impacts
of the rule to the requested ``frozen efficiency'' case provides a
measure of the greatest impacts that could possibly (albeit
unrealistically) be expected from implementing the rule.977
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\977\ These assumptions include, and go substantially beyond,
the ``no-action'' alternative advocated by EPA and others in
positing a baseline that would tend to maximize the amount of
NOX emissions attributed to the rule. This is because under a
frozen efficiency scenario all increases in power trading (and
resulting NOX emissions) would be attributed to the Rule. In
fact, as described below, many of the efficiencies posited under the
EPA assumptions are attributable to other factors and certain of the
efficiencies (e.g., 40 percent increase in transmission capacity)
are wholly unrealistic.
---------------------------------------------------------------------------
As the FEIS discusses, even comparing projected NOX emissions
under the rule to the highly implausible frozen efficiency case,
impacts attributable to the Rule are projected to be modest or non-
existent. This holds true even when large (up to 40 percent) increases
in transmission capacity are assumed to occur under the rule.978
Moreover, adding coal-favoring assumptions--which would presumably
increase emissions--about future competitive conditions in the electric
industry to the implausible frozen efficiency assumptions, NOX
emissions are projected to increase very modestly until the year 2010
(by only two percent in 2000 and three percent in 2005). Even using
this highly unlikely alternative to the rule, the analysis projects a
net environmental benefit (although a very small one) if gas prices
stay constant compared to coal prices.
---------------------------------------------------------------------------
\978\ Some commenters assume that large increases in
transmission capacity would result in a significant expansion in
generation and thus increased emissions. In reality, the analysis
present in Chapter 6 of the FEIS indicates that this is not the
case.
---------------------------------------------------------------------------
Concern also has been expressed with regard to the need to mitigate
CO2, mercury, and fine particulate emissions, and with the impact
of the rule on visibility. As with NOX, the FEIS demonstrates that
the rule is as likely to improve such emissions and visibility as it is
to exacerbate them. In any event, the impact is expected to be small.
In sum, the Commission adopts the FEIS findings that:
The relative price of coal and natural gas has a larger
effect on NOX emissions than any impacts from the proposed
rule. Without the proposed rule, different fuel price assumptions
are projected to lead to a 7 percent difference between the two base
cases in nationwide NOX emissions in 2005, with some regions
affected more than others.
The rule is projected to have only slight impacts on
NOX emissions, and the impacts are as likely to be beneficial
as harmful. In 2005, if competitive conditions in the electric
industry (for instance, heat rates) favor natural gas, the proposed
rule is projected to decrease baseline NOX emissions by 2
percent nationwide. If competitive conditions favor coal, the rule
is projected to raise baseline NOX emissions by 1 percent.
Regional effects in both cases are generally similar. In short, any
negative impacts that the rule might cause are a small fraction of
the uncertainty inherent in fuel price projections.
Even a substantial increase in transmission capacity
(up to 40 percent on every transmission line in the country) would
change emission estimates by very small amounts in all cases. In
many cases, the changes would represent net environmental benefits.
Even comparing projected emissions under the proposed
rule to the highly implausible frozen efficiency case, impacts
attributable to the rule are projected to be modest or non-existent.
The staff believes this is an unreasonable comparison because the
frozen efficiency assumptions ignore industry trends that the
Commission is generally powerless to stop. In effect, they assume
that the alternative to the proposed rule is (1) for the Commission
to reverse current transmission policy, an action that is
inconsistent with Congressional policies under EPAct, (2) for states
to cease adopting programs to improve industry efficiency, and (3)
for electric companies to cease entering mutually beneficial
transactions. Even after adding coal-favoring assumptions about
future competitive conditions in the electric industry to the
implausible frozen efficiency assumptions, NOX emissions are
projected to increase only very modestly until 2010 (by only 2
percent in 2000 and 3 percent in 2005). Even using this highly
unlikely alternative to the proposed rule, the analysis projects a
net environmental benefit (although a very small one) if gas prices
stay constant compared to coal prices. EPA indicates that it
considers the lower gas price assumption to be ``the more likely of
the base cases'' (DEIS comments, p. 35).979
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\979\ FEIS at ES-2.
---------------------------------------------------------------------------
E. Mitigation Analysis
An agency is required to consider mitigation if the proposed action
will result in adverse environmental impacts.980 The insistence of
commenters that the Commission adopt and implement mitigation measures
is based on significantly overstated assumptions regarding the
contribution of the rule to existing environmental problems. The
analysis presented in the FEIS establishes that these assumptions about
the impact of the Rule are wrong. As stated in the FEIS,
\980\ See Methow Valley, 490 U.S. at 348-53.
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The sensitivity analyses (i.e., the frozen efficiency case
requested by EPA, DOE and other commenters) do not support the
argument that the proposed rule is likely to lead to large immediate
impacts that require
[[Page 21679]]
immediate mitigation. In fact, using the more reasonable EIS base
cases, it is clear that the proposed rule is at least as likely, if
not more likely, to benefit the environment as it is to have adverse
environmental impacts. As a result, we believe it is not a
responsible course of action to undertake efforts to mitigate
speculative adverse environmental consequences that may well not
materialize; such action could well have the opposite effect and
delay the clear benefits the proposed rule will produce in order to
---------------------------------------------------------------------------
address small, highly uncertain environmental impacts.981
\981\ FEIS at 7-5.
---------------------------------------------------------------------------
Even if the rule were to result in adverse environmental impacts as
a result of competitive conditions that favor the future use of coal,
such impacts are not likely to occur until about the end of the time
period examined in the FEIS. EPA in its comments on the DEIS stressed,
based on views it formed prior to knowing the results of the frozen
efficiency case, that the Commission should develop interim mitigation
until EPA can implement a program of controls. EPA stated in its
comments that it has authority to address ``some'' of the impacts it
believed would result from the rule, but stated that it would take it
considerable time to do so--up to 10 years. The results of the
unrealistic worst case analysis demonstrate that adverse effects would
not be expected to occur for approximately 10 years in any event. Thus,
interim mitigation is not required; EPA will have sufficient time to
develop under the Clean Air Act whatever mitigation plan it may deem
necessary.
Although the staff concluded that mitigation was unnecessary given
the results of its analysis, given the importance of this issue, it
nonetheless examined in considerable detail measures, including those
proposed by commenters, that could be taken to mitigate adverse
environmental consequences of the rule if they were to occur. The FEIS
focuses on NOX emissions in particular given the importance
assigned to this issue by commenters.
1. Mitigation Measures Under the Clean Air Act
As discussed in greater detail in the FEIS, the existence for many
years of a significant ozone non-attainment problem in parts of the
U.S. has led to the development of mechanisms to address this issue. In
particular, Congress has established requirements in the Clean Air Act
for regulating NOX emissions. These requirements establish
specific NOX emission levels for certain types of boilers. As
discussed below, the Commission is not authorized to alter those
requirements as requested by certain commenters.
In the 1990 Amendments to the Clean Air Act, Congress enacted the
Acid Rain Program to reduce annual SO2 and NOX emissions. For
SO2, Congress established a cap and trade program that uses a
market-based allowance system to reduce SO2 emissions from
utilities by approximately 50 percent. The allowance system caps
utility emissions at 8.9 million tons a year by 2000. A pool of 8.9
million allowances was then created, each representing the right to
emit one ton of SO2 pollution in a specified calendar year. The
allowances can be used to permit current emissions, sold, or held in
reserve.
As a result of uncertainty in the understanding of ozone formation
and transport, Congress acted less aggressively in regulating NOX
emissions. It chose to limit NOX emissions from utilities by means
of allowable emission limits and to require further study of ozone
precursors, leaving room for the EPA to abate NOX requirements
where scientifically justified. Accordingly, in section 407 of the
Clean Air Act, 42 U.S.C. 7651f, Congress established a NOX
reduction program which provides that EPA shall by regulation establish
annual allowable emissions limitations for NOX for specified types
of utility boilers (Group 1 boilers). Section 407 also provides that,
by not later than January 1, 1997, the Administrator shall establish
allowable emission limitations for NOX on a lb/MMBtu, annual
average basis for specified other types of utility boilers (Group 2
boilers).
On April 13, 1995, EPA promulgated a Rule setting emission
limitations on Group 1 boilers that combust coal as a primary fuel. EPA
reports that the April 13, 1995 regulation ``is expected, by the year
2000, to nationally reduce NOX emissions by an estimated 1.54
million tons per year.'' 982
---------------------------------------------------------------------------
\982\ 61 FR 1442 (1996).
---------------------------------------------------------------------------
On January 19, 1996, EPA published a proposed rule to implement the
second phase of the Acid Rain Program. This rule proposes to establish
NOX emission limitations for Group 2 boilers and to revise
NOX emission limitations for Group 1 boilers to impose tougher
standards. EPA states that ``[t]he proposal would, by the year 2000,
achieve an additional reduction of 820,000 tons of NOX annually.''
983
---------------------------------------------------------------------------
\983\ Id.
---------------------------------------------------------------------------
In addition, Congress determined to deal with the issue of the
interstate transport of ozone by authorizing the formation of transport
commissions. The Clean Air Act authorizes EPA to establish transport
regions that are charged with assessing the degree of interstate
transport of pollutants, assessing mitigation strategies, and
recommending revisions to State Implementation Plans to correct the
problem. The Clean Air Act specifically establishes an ozone transport
region (OTR) for the Northeast. The jurisdictions that comprise the OTR
have developed a coordinated approach to this problem that includes
adopting a regional cap on NOX emissions.
Although the OTR process is achieving its purpose, a broader
program is clearly appropriate to address the overall problem. As a
consequence, the Ozone Transport Assessment Group (OTAG) has been
formed which encompasses the OTR and upwind states that contribute to
non-attainment. OTAG is performing extensive photochemical grid
modeling of the eastern U.S. to determine ozone transport problems and
to evaluate the efficiency of various control strategies. OTAG is
considering recommending a cap and trade system for NOX emissions
from all sources in a 37-state area comprising the Northeast OTR and
upwind states. If the cap and trading system becomes effective it
therefore should fully mitigate NOX emission increases, if any,
attributable to open access transmission within the 37-state area. A
cap and trade program is also likely to mitigate CO2 and mercury
emissions.984 Any incremental increases in NOX, mercury, or
CO2 emissions that may result from the rule can and should be
addressed within this existing framework.
---------------------------------------------------------------------------
\984\ It should be noted that the science relating to
determining mercury emission levels and also to the environmental
impacts of CO2 is uncertain, particularly with regard to the
impacts of CO2 emissions. The FEIS evaluates these matters as
best it can under the circumstances.
---------------------------------------------------------------------------
All of these factors lead us to agree with the staff's conclusion
in the FEIS that a cap and trading system such as that under
consideration in the OTAG process is the preferred approach to the
overall NOX emissions problem, including emissions associated with
the rule, if any. This approach brings together EPA and the concerned
states in a program that utilizes existing regulatory authority under
the Clean Air Act.
The OTAG process brings to the table the parties that must
participate in making the difficult decisions necessary to fully
resolve this problem. OTAG possesses the technical resources and
expertise to address the difficult scientific and technical issues that
must be resolved to remedy this problem. A cap and trading system will
require the
[[Page 21680]]
development of emission baselines for a great many entities;
development of such baselines is certain to require extensive modeling
and many difficult compromises. OTAG and others have been working
towards this end for a long time. A more limited approach--one
undertaken by this Commission or aimed at the limited (and only
potential) impacts of the rule--cannot render a satisfactory solution.
A program designed to deal with the slight impacts associated with the
rule will not contribute significantly to the overall solution and
could, indeed, impede it if the Commission took actions that prove
inconsistent with solutions developed by OTAG or if debate over
Commission-sponsored mitigation were to continue to distract interested
parties from the preferred route of developing a consensus solution
within the framework of the Clean Air Act. We respect the expertise and
the goals of the OTAG process and do not believe we can or should
substitute for them in addressing this long-term national problem.
2. Mitigation Measures Proposed by Commenters
The FEIS also analyzes NOX mitigation measures proposed by
commenters. These include voluntary measures pursuant to which the
Commission would support utility efforts to mitigate pollution and
proposals under which the Commission would mandate mitigation.
Commenters suggest a variety of Commission actions including using its
conditioning authority to require utilities to consider environmental
impacts; 985 sanctioning imputed charges in rates to reflect
incurred environmental externalities; and designing specific,
transaction-oriented mechanisms designed to address the increment of
emissions attributable to new wholesale transactions resulting from the
rule.986 The FEIS discusses five proposals in some detail: Those
presented by the Center for Clean Air Policy (CCAP), the EPA, Joint
Commenters, the Project for Sustainable FERC Energy Policy (Sustainable
FERC), and the DOE.987 Of these, the FEIS recommends the proposal
put forward by DOE:
\985\ For example, EPA suggests that we require certain types of
filings, such as a request to charge market-based rates, to include
an assessment of environmental impacts and mitigation, if necessary.
Joint Commenters suggest we require wheeling and interconnection
applicants to demonstrate that their requests will not contribute to
increased NOX or ozone in downwind regions, and Conservation
Law suggests linking recovery of stranded costs to the retirement of
unsuitable generators.
\986\ The FEIS also discusses mitigation measures that can be
undertaken by others. These include strategies to require some
existing plants to meet more str
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
ingent, new NOX standards,
relying on market forces to control inter-regional NOX
transport, or measures that could be employed by the states to limit
power purchases based on environmental considerations. See FEIS at
7-26 to 7-28.
\987\ FEIS at 7-28 to 7-43.
---------------------------------------------------------------------------
Staff concurs (with the DOE analysis) that the best solution to
the problem of NOX transport and ozone non-attainment lies in
exercise of statutory authority under the Clean Air Act by EPA and
the states. Absent Congressional action, no resolution of the
difficult political and technical issues will represent a lasting
solution of this problem except one that comes from a collaborative
process such as OTAG.988
\988\ FEIS at 7-43.
---------------------------------------------------------------------------
As the FEIS explains in great detail, each of the other
recommendations suffers from serious shortcomings. In one form or
another, they would require the Commission to implement technically
complex emissions control regimes outside of the Commission's
expertise. Some would require that we duplicate existing monitoring
systems. Others would require that we implement provisions that would,
in effect, defeat the very purpose of the rule.989 Indeed, these
recommendations would have the Commission embark upon an extensive
environmental regulatory regime that appears unwarranted, unworkable
and, as discussed below in some detail, beyond our lawful authority.
And they would have us act in a way that may well frustrate the ongoing
efforts to deal with these problems and would frustrate the benefits to
be derived from the rule.
---------------------------------------------------------------------------
\989\ The rule represents the Commission's remedy to unduly
discriminatory practices found to exist by public utilities that own
and/or control interstate transmission facilities. Having found an
unlawful practice, we must remedy it. However, EPA would require
that those seeking to enjoy the benefits of non-discriminatory open
access transmission further agree to go beyond current environmental
requirements specified by federal and state authorities authorized
by Congress to regulate such matters.
---------------------------------------------------------------------------
The CCAP asserts that FERC should establish an emissions monitoring
program for NOX and CO2 and implement an emission neutrality
requirement (ENR) to mitigate what it believes to be the impacts of the
rule. The monitoring program would require generators to identify
emissions associated with off-system sales on a kWh basis in real-time
and integrate this information with the data to be made available on
electronic bulletin boards (EBBs). Under the ENR aspect of CCAP's
proposal, to be eligible for service under open access tariffs,
companies that operate plants upwind from the Northeast OTR and the
upper Midwest would have to certify that firm and economy off-system
power sales using an open access tariff would have no incremental
impact on ozone compliance in other areas. All sales for resale that
require service under an open access tariff and originate upwind of the
OTR would need to include NOX emissions reduction credits equal to
the increase in emissions related to those sales. The seller could meet
its requirement to be ``emission neutral'' under the mechanism by
achieving the required emission reductions annually at their own
facilities, or through purchases of credits anywhere in the airshed.
EPA proposes two mitigation alternatives. In the first, it states
that FERC could deny open access service unless there is a showing that
the service will not have an adverse environmental impact. Under this
approach, EPA, in cooperation with the states in OTAG, would recommend
and establish a mitigation mechanism that could be entered into by a
customer seeking open access service and used by such customer to make
the necessary environmental demonstration supporting the provision of
the service. The FERC would rule on whether the mitigation mechanism
presented by the customer and the evidence on the likely effectiveness
of the mechanism were sufficient to make the environmental
demonstration.
In the second proposal, EPA suggests that any fossil fuel-burning
generating entity seeking service under open access transmission
tariffs would be required to commit by an enforceable contractual
undertaking that it will avoid or offset emission increases (measured
against as yet undetermined baselines), and periodically certify its
compliance with that commitment. Middlemen would have a similar
obligation. The generator could meet its emission limits either by
making verified emission reductions within its own facilities or by
obtaining eligible emissions offsets from other entities. An important
element of the mitigation mechanism is the emissions baseline above
which mitigation would be required. This mitigation mechanism would
operate until superseded by appropriate programs addressing these
pollution problems under other authority. EPA's own comments on the
DEIS recognize that there may be substantial practical complexities in
implementing such mechanism.
The Joint Commenters propose a flexible mitigation strategy
pursuant to which FERC would require as part of open access
transmission a demonstration that NOX emissions would not be
increased. To qualify for open access transmission access, an electric
generating unit would be
[[Page 21681]]
responsible for mitigating any excess NOX emissions that adversely
affect ozone non-attainment areas. Utility systems would be able to
comply by use of emission control technology, fuel changes, or other
measures to reduce applicable emissions, or by buying appropriate
emission reduction credits to offset excess emissions. To comply with
this policy, a company would need first to calculate whether it had
excess emissions for the ozone season. A company that failed to
mitigate would be required to remit to a regional emissions fund all
revenues in excess of the incremental operating cost of producing
electricity sold under the open transmission access policy during the
previous ozone season plus an emissions make-up penalty the following
year patterned after the penalty for excess emissions in the Acid Rain
Program. The proposed mitigation policy would apply generally
throughout the OTAG region.
The outlines of Sustainable FERC's proposal are vague, but it
appears to request that FERC, either singly or in combination with
other agencies, eliminate the different environmental standards that
apply to entities participating in open access transmission. This plan
would include the reporting of emissions data to EPA, principles to
eliminate the adverse impacts of non-comparable environmental
standards, and an EPA-administered emissions monitoring process
designed to determine whether generating plant emissions of specific
pollutants under open access exceed designated baselines.
Finally, DOE proposes action under the Clean Air Act as the most
effective mitigation of the inter-regional NOX transport problem.
DOE supports the activities of OTAG and believes that a regional
NOX cap and trading system is a particularly promising approach.
If OTAG does not succeed in addressing the problem, EPA should consider
exercising its authority under sections 110 and 126 of the Clean Air
Act, 42 U.S.C. 7410 and 7426, respectively, to require states to amend
their State Implementation Plans to reach the same result.
The proposals advanced by CCAP, EPA, Sustainable FERC, and Joint
Commenters suffer from practical and legal problems that render them
unworkable. A common thread is for the Commission to ``level the
environmental playing field.'' ``Impacts of non-comparable
environmental standards'' are not impacts of this rule, but rather of
the Clean Air Act regulations and statutory requirements under which
those standards have been imposed. We have no authority to ``level''
the different emissions standards for different types of power plants,
when those differences in standards are the direct result of the
program adopted in the Clean Air Act and regulations promulgated by
EPA. In enacting the Clean Air Act, Congress chose not to impose
identical emission standards on all electric utility powerplants, but
did create mechanisms for regulation of certain pollutants that can be
used to ``level the playing field'' if that is appropriate clean air
policy. For the Commission to presume to overturn those standards or
seek to impose more stringent standards is something the Commission
believes it cannot do.
A fundamental problem that plagues several proposals is the
difficulty in identifying causation. While it is generally accepted
that there is a link between increased emissions in certain areas of
the country and increases in ozone levels in other areas, that link is
in many respects poorly understood. In particular, it is difficult to
prove that emissions from a particular unit or particular system
contribute to ozone noncompliance elsewhere. As a result, it is very
difficult to establish an analysis that would support a certification
that a particular power sale would have no incremental impact on ozone
compliance.
Similarly, the proposals tying ``emission neutrality'' to ``open
access transactions'' seem to fundamentally misunderstand the operation
of power markets and the role of open access tariffs in moving power
from willing sellers to willing buyers. In particular, these proposals
do not reflect the difficulty in identifying the transactions that are
likely to result from the open access policies adopted in this rule.
The rule does not authorize sales for resale of electric energy;
rather, it establishes requirements for open access transmission, i.e.,
it requires utilities with monopoly control of transmission to make
transmission service available to customers who want to buy power from
someone other than the transmission owner. Open access will facilitate
transactions where the transmission owner will not provide service.
However, generators do not necessarily have to request service under a
Commission ordered open access tariff to make specific sales. There are
a number of ways to structure transactions where third party
transmission service is either not necessary or is voluntarily
available.990 Even when open access tariffs are used, the sales
are not always (or even often) sales from specific generators to
specific buyers. Marketers or brokers can buy generation from any
number of sources. They can also buy transmission service in blocks
that may not be associated with specific sales. Service agreements can
be executed that allow use of non-firm transmission service for
transactions that are not even known at the time of the execution of
the agreement.
---------------------------------------------------------------------------
\990\ Indeed, over 100 utilities are now providing some form of
open access on a voluntary basis.
---------------------------------------------------------------------------
The rule envisions a world where transmission will be arranged with
minimal transaction cost. Terms, conditions, rates, and even approvals
often will be established far in advance of particular transactions.
All other problems aside, requiring showings of the kind required by
the various mitigation proposals would undermine the basic philosophy
behind the rule, would make transactions much more difficult to engage
in, would increase transaction costs, and would cause delays resulting
in lost efficiencies. In addition, it would directly conflict with the
Commission's responsibility under the FPA to remedy undue
discrimination in jurisdictional services, which is the fundamental
purpose of the rule.
Another significant issue with several of the proposals is how to
establish the baselines against which to measure emissions.
Establishing such baselines is extremely difficult; EPA itself, for
example, has not come to grips with these complexities. The picture is
complicated by difficulties in identifying open access transactions
that result from the policies implemented by this rule. For example,
some utilities use holding company corporate structures in which
generation assets are held in an affiliate that sells power at
wholesale to the holding company's distribution affiliate. For these
utilities, all retail native load service would be subject to
environmental review under the mitigation proposals if the base were
established by reviewing all wholesale sales. This would make the
Commission responsible for addressing all NOX emissions from power
plants for utilities with such corporate structures, a result that goes
far beyond the stated goal of mitigating emissions that result from
increased interstate trade facilitated by the rule.
As the industry changes, new structures are emerging that will make
any system that tries to keep track of wholesale sales even more
difficult to administer. California is putting into place an industry
structure that could see all generation in the state sold into a
central pool and then sold again at wholesale to distributors. Other
states
[[Page 21682]]
are contemplating retail market structures that are even more fluid
than the California proposal. Differentiating between sales for resale
that are for former retail customers and sales for resale that are for
``new'' wholesale customers, and therefore somehow the result of open
access policies, would be extremely difficult. In general, it is not
easy to distinguish among growth in generation for native retail load,
wholesale requirements customers, existing economy sales, and new sales
that are facilitated by the rule, either for purposes of establishing a
baseline or for tracking responsibility for emissions.991
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\991\ We are also very concerned about the time and effort
involved in developing the various programs suggested by commenters.
The EPA and OTAG are working on the establishment of emissions
standards, which action is an essential prerequisite to three of the
proposals. However, developing those standards is among the
challenges that EPA believes may take up to 10 years to complete. It
simply makes no sense to delay the benefits of the rule (which has
slight, if any, environmental impacts) during the period required
for experts in the area to develop standards that, once established,
can form the basis of a program under existing Clean Air Act
authority.
---------------------------------------------------------------------------
Joint Commenters proposal would have the Commission impose a
revenue collection measure--in essence a tax on open access
transmission. The Commission is authorized by the FPA to pass through
costs, not to collect additional fees from entities utilizing programs
established by the Commission. The payment of emission fees is outside
the Commission's authority under the FPA.
The FEIS concludes that mitigation by the Commission should not be
undertaken in this rule because:
Any mitigation measures the Commission might undertake
are not justified by the small impacts of the rule, which impacts
are as likely to be beneficial as they are to be harmful;
The impacts of the proposed rule are dwarfed by the far
larger ozone and NOX emission issues that either have nothing
to do with the electric industry or will be unchanged by the rule or
the larger open access program. We believe that it would be
ineffective to address the NOX and ozone issues in a piecemeal
way;
The NOX issue is part of a long-standing,
difficult set of inter-regional environmental issues.
Representatives of many interests have invested substantial efforts
toward finding acceptable solutions through the OTAG process. Any
mitigation the Commission might undertake could usurp EPA's mandate
under the Clean Air Act and undermine progress towards comprehensive
solutions sought by OTAG. This is not justified by impacts that are
small and just as likely to be positive;
We do not agree that the frozen efficiency reference
case should be substituted for the EIS base cases or that
competitive forces will favor coal over the next 15 years. But even
accepting these assumptions, emissions attributable to the rule are
relatively small until well after the turn of the century. So, even
accepting such assumptions, the staff believes it would be
unreasonable for the Commission to adopt mitigation requirements as
part of the final rule; to do so would be tantamount to assuming
that EPA and OTAG will not implement reasonable control measures in
the next ten to 15 years;
The Federal Power Act and NEPA, either singly or
conjointly, do not authorize the Commission to adopt and implement
the proposed mitigation measures. The Commission does not possess
(and has no mandate to possess) expertise on the extremely difficult
issues involved in atmospheric chemistry and transport. It is
fundamentally an economic regulatory agency. As a result, any
mitigation measures the Commission undertook would be based on less-
than-ideal information and analysis. It is unreasonable for the
Commission to attempt such mitigation given the impacts found in
this FEIS. This is especially true in light of the substantial
additional research that EPA and OTAG are undertaking on the basic
nature of the problem;
Some suggested mitigation measures that might work at
the transaction level would undermine the purpose of the rule. There
is no justification for endangering the substantial benefits
projected from the rule to mitigate a problem that might not exist
and that is, in any case, likely to be small.992
\992\ FEIS at 7-48.
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In sum, the rule is expected to have small impacts and those
impacts are as likely to be beneficial as they are to be harmful.
Therefore, mitigation is not required. In addition, processes are in
place to address the pre-existing NOX problem--a problem that
dwarfs any impacts the Rule might have. These processes are expected to
address the underlying transport problems well before any potential
harmful effects of the rule will develop.993
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\993\ Many commenters state that the rule does not require
mitigation and urge that a mitigation plan not be adopted. We would
also note in light of the substantial number of comments opposing
the proposition that we have mitigation authority, that any such
mitigation measure we may choose to undertake would, in all
likelihood, be subject to judicial review and the inevitable delays
and uncertainties that accompany litigation. In the meantime, we
would expect actions by OTAG and EPA to eclipse whatever action the
Commission attempted to implement during this time.
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The mitigation measures that certain commenters urge the Commission
to adopt are truly unwarranted in light of these facts. They also fail
to recognize or adequately consider the Commission's limited
jurisdiction, its lack of expertise required to assess and address the
underlying problem, the existing mechanisms and efforts to address the
underlying problem, and the balance that has been reached and continues
to be defined by the many interests that have invested substantial
efforts toward finding acceptable solutions to these problems.
3. Legal and Policy Considerations
The FEIS concludes that the mitigation measures recommended by
commenters are beyond our authority to implement and that strong policy
considerations militate against their adoption. We agree.
Several commenters contend that the Commission is authorized to use
the rulemaking as a vehicle to impose an air emissions regulatory
regime on the electric utility industry.994 Others argue that, as
a matter of law and policy, we cannot and should not impose such
measures.995 While the conditioning proposals vary in specifics,
all have as their central theme that generators would be forced to
agree to operate generation facilities in a manner to reduce air
pollution below levels currently authorized by EPA and the
states.996
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\994\ Alliance for Affordable Energy, et al. (Alliance); EPA;
Project for Sustainable FERC Energy Policy (Project for Sustainable
FERC); and Northeast States For Coordinated Air Use Management
(NESCAUM).
\995\ See, e.g., AEP at 3; CINERGY at 8-9; Entergy at 11-13; GPU
at 2; Midwest Ozone Group at 3; NMA at 5-8; Ohio Consumers' Counsel
at 5; Ohio PUC at 1; TVA at 8; and WEPCO at 2. See also CCEM
Supplemental Comments at 1-5.
\996\ See, e.g., CCAP (FERC should establish an emissions
monitoring program and implement an emission neutrality
requirement); EPA (either deny open access service unless the
customer demonstrates no adverse environmental impact or require,
through contract terms, any generating entity seeking open access
service to avoid or offset emission increases for the benefit of
third parties); Joint Commenters (electric generators to qualify for
open access must be held responsible for mitigating any excess
NOX emissions through a revenue collection measure); Project
for Sustainable FERC (pro forma tariffs to contain environmental
mitigation measures imposed on generators). See generally, FEIS at
7-28 to 7-42.
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The Commission's authority to regulate public utilities is set out
in Parts II and III of the FPA. Parts II and III do not provide the
Commission with the authority to condition either the provision of, or
access to, jurisdictional services on the agreement to undertake
environmental mitigation measures.997 Section 201, which is found
in Part II of the FPA, explicitly bars the Commission from exercising
the jurisdiction that the proponents of the conditioning
[[Page 21683]]
proposals would have us undertake: authority over the operation of
generating facilities. Section 201(b)(1) provides that:
\997\ Parts II and III of the FPA originated with the Public
Utility Act of 1935, 49 Stat. 803, 838 (Aug. 26, 1935) and stemmed
in part from the financial abuses in the utility industry in the
late 1920s and early 1930s. See Report of National Power Policy
Committee on Public-Utility Holding Companies, S. Rep. No. 621,
Appendix, 74th Cong., 1st Sess. 55-60 (1935); see also H.R. Rep. No.
1318, 74th Cong., 1st. Sess. 1-3 (1935). The FPA has been amended
several times, most recently by the Energy Policy Act of 1992.
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The Commission shall have jurisdiction over all facilities for
(the transmission of electric energy in interstate commerce) or
(the) sale of electric energy (at wholesale in interstate commerce),
but shall not have jurisdiction, except as specifically provided in
(Parts II and III), over facilities used for the generation of
electric energy * * *. (emphasis added).
This standard is reflected throughout Parts II and III of the FPA.
Sections 205 and 206, which are the cornerstones of Parts II and III,
concern the regulation of rates, terms and charges occurring in
connection with transmission or sales subject to the Commission's
jurisdiction. Parts II and III do not grant the Commission authority to
regulate the environmental aspects of jurisdictional
activities.998 Instead, they provide authority over certain
interconnections; 999 the rates, terms and conditions of wholesale
sales of electric energy in interstate commerce and transmission in
interstate commerce; the disposition and merger of facilities used for
such sales and transmission; issuance of securities; accounting
matters; and interlocking directorates. Thus, the Commission's
jurisdiction over generation extends only to matters directly related
to the economic aspects of transactions resulting from such
facilities.1000 We do not have jurisdiction over the physical
aspects of generation facilities.1001
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\998\ The statutory framework established by Congress in
sections 205 and 206 is not compatible with the administration of
environmental regulatory regimes as a precondition to authorization.
The Commission has only 60 days to review rate filings under section
205 before they become effective. Absent Commission action rejecting
a rate filing or suspending its operation for up to five months
within such period, a jurisdictional transaction (either the sale of
energy or the transmission of energy) and the proposed rates
accompanying the transaction go into effect by operation of law.
Some mitigation proposals would require us to reject transactions
within 60 days or allow them to go forward but with case-by-case
determinations or hearings on environmental effects made within that
time period. This could result in transaction gridlock for the trade
of electricity in interstate commerce--a situation that is totally
at odds with the regulatory framework established by Congress in the
FPA and the Commission policy objectives under this rule to minimize
regulatory impediments to fluid competitive power sales markets.
Moreover, letting transactions go into effect subject to
environmental hearings is not likely to produce meaningful
environmental controls. Clearly, our processes, which contemplate
the resolution of factual matters through hearings and the use of
refund obligations to adjust parties' obligations on the basis of
the record, make no provision for extensive scientific inquiry and
are not designed to accommodate the imposition of clean air
standards on power sellers.
\999\ See FPA section 202(b), 16 U.S.C. 824c(b). See also
Department of Energy Organization Act, 42 U.S.C. 7151, 7172.
\1000\ We also note that section 731 of the Energy Policy Act
preserves state and local authority over environmental protection
and the siting of facilities.
\1001\ For example, we do not have jurisdiction over the
physical location of generation or transmission facilities, even
though we have exclusive jurisdiction of the rates, terms and
conditions of sales for resale or transmission of electric energy in
interstate commerce by public utilities using such facilities, i.e.,
the economic aspects of the use of such facilities.
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This limitation on the Commission's jurisdiction stems from the
historical purposes for which the Commission was established. Congress
had two objectives in expanding the authority of the Federal Water
Power Commission in 1935.1002 The first was to close the gap
created by Public Utilities Commission v. Attleboro Steam & Electric
Co., 273 U.S. 83 (1927)(Attleboro), in which the Court found that under
the Commerce Clause states could not regulate wholesale sales of
electricity in interstate commerce. The result was a gap in regulation
of such sales because there was no federal entity with authority to
regulate them at that time. The second was to eliminate the economic
abuses that were then rampant in the industry.1003 In expanding
the Commission's jurisdiction Congress made clear that such Federal
regulation, however, was ``to extend only to those matters which are
not subject to regulation by the States.'' 1004
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\1002\ The Federal Water Power Commission was established in
1920 with jurisdiction over the licensing of hydropower projects. 41
Stat. 1063 (June 10, 1920). In 1935, it was reconstituted as the
Federal Power Commission, with expanded responsibilities over
utility regulation. The jurisdiction over the licensing of
hydropower was preserved as Part I of the Federal Power Act.
\1003\ See Report of National Power Policy Committee on Public
Utility Holding Companies.
\1004\ FPA section 201(a), 16 U.S.C. 824(a). The House, Senate
and Conference Reports concerning the Public Utility Act of 1935,
i.e., concerning Parts II and III of the FPA, are silent with
respect to environmental concerns.
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Several commenters argue nonetheless that the Commission may do
indirectly what it is barred from doing directly. Their arguments boil
down to the claim that the Commission's responsibility under the FPA to
act in the ``public interest'', either alone or in conjunction with
NEPA, provides the Commission with the authority to impose
environmental regulation on generators to address the supposed impacts
of the Rule.1005 We disagree. In making this argument, the
commenters attribute to that standard a breadth of discretion that
vastly exceeds the traditional ambit of our authority.
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\1005\ See, e.g., comments by EPA, Project for Sustainable FERC,
and Attorneys General.
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It is well established that NEPA merely establishes a procedural
vehicle for assessing the impacts of a proposed action on the
environment. It neither expands nor contracts the basic grant of
jurisdiction made by Congress to the agency conducting the review, and
it does not mandate particular results but simply prescribes a
process.1006 Commenters' arguments that NEPA somehow ``fills in
the blanks'' of the FPA to authorize us to impose environmental
regulatory regimes on generating facilities, or those who may purchase
power from them, is simply incorrect. If we have such authority, it
must be found in our substantive statute, the FPA.
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\1006\ See, e.g., Methow Valley, 490 U.S. at 350-53; see also,
LaFlamme v. FERC, 852 F.2d 389, 399 (9th Cir. 1988).
---------------------------------------------------------------------------
Courts have addressed the breadth of our public interest standard
on several occasions. The principal case on this point is National
Association for the Advancement of Colored People v. FPC 520 F.2d 432
(D.C. Cir. 1975), aff'd, 425 U.S. 662 (1976) (NAACP). In NAACP, a
number of organizations requested that the Commission promulgate
regulations requiring equal employment opportunity and proscribing
racial discrimination in the employment practices of public
utilities.1007 The Commission declined, finding that the FPA did
not authorize it to do so. Petitioners appealed, contending that the
Commission was authorized and required to act in the public interest:
\1007\ NAACP, 520 F.2d at 433.
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to order such interconnections of electric power transmission
facilities, setting such terms and conditions for the same, as are
``necessary or appropriate in the public interest''; to approve such
asset sales and consolidations of interstate electric power
companies as are ``consistent with the public interest; to approve
such securities issuances by those companies as are ``compatible
with the public interest'' and ``consistent with the proper
performance * * * of service as a public utility''; to determine
``just and reasonable'' rates for interstate sales and transmission
of electric power; and to order that ``proper, adequate or
sufficient'' interstate power service be rendered.1008
\1008\ Id. at 437-38 (footnotes omitted). The authorities listed
cover FPA sections 202, 203, 204, 205, 206, and 207.
---------------------------------------------------------------------------
On this basis, they argued that because prohibition of discrimination
is in the ``public interest,'' the Commission was therefore required to
proscribe discrimination by jurisdictional entities.
The Court rejected petitioners' argument. It observed that:
the (Federal Power) Act's preamble echoes the generality of the
foregoing quoted
[[Page 21684]]
phrases, declaring that the sale and transmission of electric power
are ``affected with the public interest,'' federal regulation of
interstate aspects being ``necessary in the public interest.'' The
statute itself nowhere defines the ``public interest,'' but instead
leaves the precise ambit of the Commission's concern
uncertain.1009
\1009\ Id. at 438 (footnote omitted).
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The Court found from the entirety of the Act that, ``(o)f the
Commission's primary task there is no doubt, however, and that is to
guard the consumer from exploitation by non-competitive electric power
companies.'' 1010 The Court reiterated that ``(t)he Supreme Court
has stated that the words `public interest' do not constitute a `mere
general reference to the general welfare, without any standard to guide
determinations.' '' 1011 Significantly, the Court also found that
``(w)ords like `public interest' * * * though of wide generality, take
their meaning from the substantive provisions and purposes of the
Act.'' 1012 The Court concluded that:
\1010\ Id.
\1011\ Id. at 440, citing New York Central Securities Co. v.
United States, 287 U.S. 12, 24 (1932).
\1012\ Id., quoting Alabama Electric Cooperative, Inc. v. SEC,
353 F.2d 905, 907 (1965), cert. denied, 383 U.S. 968 (1966).
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Congress has not charged the Commission with advancing all public
interests, but only the public's interest in having the particular
mandates of the Commission carried out, its interest, in other
words, in the conservation of natural resources and the enjoyment of
cheap and plentiful electricity and natural gas. 1013
\1013\ Id. at 441 (emphasis in original). The Court made clear
that ``the conservation of natural resources'' was a Commission
interest only with regard to the regulation of hydropower resources
under Part I of the FPA. Id. at 437.
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With this, the Court rejected petitioners' argument that the FPA
``public interest'' standard requires the Commission to promulgate
regulations prohibiting discriminatory practices by entities who are in
some way regulated by the Commission. The Court found that the
Commission was not empowered to promulgate anti-discrimination
regulations because to do so would not be ``reasonably related to the
furtherance of the Commission's proper objectives,'' which, under Part
II of the FPA, are ``the enjoyment of cheap and plentiful
electricity.'' 1014
---------------------------------------------------------------------------
\1014\ Id. at 443 and 441.
---------------------------------------------------------------------------
On review, the Supreme Court affirmed this limited reading of the
Commission's authority to act in the public interest.1015 In doing
so, the Court noted that:
\1015\ NAACP, 425 U.S. 662 (1976).
---------------------------------------------------------------------------
The use of the words ``public interest'' in the Gas and Power
Acts is not a directive to the Commission to seek to eradicate
discrimination, but, rather, is a charge to promote the orderly
production of plentiful supplies of electric energy and natural gas
at just and reasonable rates.1016
\1016\ Id. at 670 (footnote omitted). Several commenters, e.g.,
Project for Sustainable FERC at 31-32 and Alliance at 53, make much
of the Court's statement that there are undoubtedly other subsidiary
purposes contained in the FPA and NGA, noting its reference in a
footnote that the Commission has authority to consider
``environmental'' questions. NAACP, 425 U.S. at 670 n.6. However,
they neglect to mention that the section of the FPA which the Court
identified in support of this reference to environmental questions
is section 10 of the FPA concerning our Part I authority over
hydroelectric licensing matters, not Parts II and III. Part I
contains explicit authority for the Commission to consider and
require environmental mitigation measures.
---------------------------------------------------------------------------
The question the Supreme Court asked in NAACP is the appropriate
question here concerning the commenters' environmental mitigation
proposals:
The question presented is not whether the elimination of
discrimination from our society is an important national goal. It
clearly is. The question is not whether Congress could authorize the
Federal (Energy Regulatory) Commission to combat such
discrimination. It clearly could. The question is simply whether and
to what extent Congress did grant the Commission such
authority.1017
\1017\ NAACP, 425 U.S. at 665.
---------------------------------------------------------------------------
We believe the same conclusion is true here for air pollution as the
Court found there regarding discrimination.1018
---------------------------------------------------------------------------
\1018\ In analyzing the scope of the Commission's authority to
act in the public interest, the NAACP Court found it useful to
analogize to federal labor law. While noting that Congress had
``unmistakably defined the national interest in free collective
bargaining,'' Id. at 671, the Court found that it could not be
supposed that in directing the Commission to be guided by the
``public interest,'' Congress instructed the Commission ``to take
original jurisdiction over the processing of charges of unfair labor
practices on the part of its regulatees.'' Id. Yet this is exactly
the form of what EPA and the other commenters supporting our
authority to require environmental mitigation would have us do.
However, just as with discriminatory employment practices, we can
consider the consequences of air pollution practices of our
regulatees ``only insofar as such consequences are directly related
to the Commission's establishment of just and reasonable rates in
the public interest.'' Id. (emphasis added).
---------------------------------------------------------------------------
The argument by EPA and others that because the FPA authorizes the
Commission to act in the ``public interest'' it somehow authorizes the
Commission to impose environmental mitigation measures is virtually
indistinguishable from petitioners' argument in NAACP.1019 Here,
as in NAACP, parties urge the Commission to act to achieve worthwhile
goals. However, the question is not whether the measures proposed by
the parties would advance important national goals. Rather, ``[t]he
question is simply whether or to what extent Congress did grant the
Commission such authority.'' 1020 Also here, as in NAACP, the
parties improperly base their belief that the Commission has authority
to act under the FPA on an incorrect, overly broad application of the
``public interest'' standard. The goals sought to be advanced by EPA
and others are broadly speaking ``in the public interest,'' but they
are not goals that Congress has directed this Commission to
pursue.1021 Thus, just as the FPA did not authorize the Commission
to take actions that petitioners requested in NAACP, the FPA does not
authorize the Commission to undertake the types of environmental
mitigation measures proposed by the commenters.1022
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\1019\ We note that the standard the Commission is bound to
apply in reviewing section 205 and section 206 transactions (which
are the focus of the majority of commenters' mitigation proposals)
is not a broad ``public interest'' standard, but rather a standard
that rates, terms and conditions of such transactions be ``just,
reasonable and not unduly discriminatory or preferential.'' 16
U.S.C. 824d, 824e.
\1020\ NAACP, 425 U.S. at 665.
\1021\ The limited nature of the Commission's ability under
NAACP to consider ``environmental'' issues is reflected in the few
court decisions on this subject. See Public Utility Commission of
California v. FERC, 900 F.2d 269, 281 (D.C. Cir. 1990) (The broad
public interest standards in the Commission's enabling legislation
are limited to ``the purposes that Congress had in mind when it
enacted this (NGA and FPA) legislation. This rule helps confine an
agency's authorization ``to those areas in which the agency fairly
may be said to have expertise.''); Process Gas Consumers Group v.
FERC, 930 F.2d 926, 935 & n.14 (D.C. Cir. 1991) (Commission
improperly allowed in rates the costs of research intended to
benefit ratepayers solely through a ``cleaner environment''; the
Court found that the Commission has no particular ``expertise'' in
determining and promoting the pollution-reducing effects of natural
gas vehicles).
\1022\ The Supreme Court's holding in NAACP as to the limited
ability of administrative agencies to implement broad ``public
interest'' mandates, and direction to refrain from straying beyond
the specific purposes of the regulatory legislation they are
entrusted to administer, is well established. See Community
Television of Southern California v. Gottfried, 459 U.S. 498, 510-11
n.17 (1983) (``[A]n agency's general duty to enforce the public
interest does not require it to assume responsibility for enforcing
legislation that is not directed at the agency''); Hampton v. Mow
Sun Wong, 426 U.S. 88, 114 (1976) (``It is the business of the Civil
Service Commission to adopt and enforce regulations which will best
promote the efficiency of the federal civil service. That agency has
no responsibility for foreign affairs, for treaty negotiations, for
establishing immigration quotas or conditions of entry, or for
naturalization policies''); McLean Trucking Company v. United
States, 321 U.S. 67, 79 (1944) (that Congress ``has vested expert
administrative bodies such as the Interstate Commerce Commission
with broad discretion and has charged them with the duty to execute
stated and specific statutory policies'' does not ``necessarily
include either the duty or the authority to execute numerous other
laws'' beyond enumerated statutory responsibilities); see also Bob
Jones University v. United States, 461 U.S. 574, 611 (1983) (Powell,
J., concurring) (``This Court often has expressed concern that the
scope of an agency's authorization be limited to those areas in
which the agency fairly may be said to have expertise'').
Lower courts have repeated the Court's admonition in this regard
on numerous occasions in finding that federal agencies improperly
have overstepped, or properly have refrained from overstepping, the
limitations of their ``public interest'' (or similarly worded)
jurisdiction. See, e.g., The Business Roundtable v. Securities and
Exchange Commission, 905 F.2d 406, 413-14 (D.C. 1990) (SEC's
assertion of authority under ``public interest'' standard to bar
national security exchanges and associations from listing stock of
certain corporations invaded traditional state regulatory purview);
Public Utility Commission of California v. FERC, 900 F.2d 269, 281
(D.C. Cir. 1990) (FERC has no authority to consider allegations of
copyright infringement or unfair trade practices in determining
whether to issue certificates of public convenience and necessity);
American Trucking Association v. United States, 642 F.2d 916 (5th
Cir. 1981) (intention of ICC to promote competition is consistent
with statutory standard; more generalized intention to promote
public welfare needs, unrelated to its legislative instruction to
attend to transportation needs of the public, is not); Natural
Resources Defense Council, Inc. v. Securities and Exchange
Commission, 606 F.2d 1031 (D.C. Cir. 1979) (SEC has no obligation to
promulgate regulations requiring comprehensive disclosure of (among
other things) corporate environmental policies unrelated to
objectives of federal securities laws); Sunflower Electric
Cooperative, Inc. v. Kansas Power & Light Company, 603 F.2d 791, 799
(D.C. Cir. 1979) (FERC does not have primary jurisdiction to
consider antitrust-related issues that do not involve rate-setting
practices of public utilities); O-J Transport Company v. United
States, 536 F.2d 126, 131-32 (6th Cir.), cert. denied, 429 U.S. 960
(1976) (ICC properly did not stray beyond its congressionally-
defined role over transportation regulation by refusing to promote
more generalized public welfare concerns); see also, e.g., In re
Multidistrict Vehicle Air Pollution, 538 F.2d 231 (9th Cir. 1976)
(under antitrust laws, federal district court has no authority to
fashion an environmental remedy, intended to reduce auto emissions,
that serves no antitrust purpose).
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[[Page 21685]]
The Project for Sustainable FERC argues that in Richmond Power &
Light v. FERC, 574 F.2d 610, 616-17 n.22 (D.C. Cir. 1978) (Richmond
Power), the Court ``suggested'' a broader agency latitude than
described in NAACP.1023 We disagree.
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\1023\ Project for Sustainable FERC at 31.
---------------------------------------------------------------------------
Richmond Power involved a case where the Commission was challenged,
inter alia, because it declined to adopt a particular transmission rate
that would have permitted Richmond to shift from oil to some other
fuel. The Court affirmed the Commission's decision, finding that:
Although the Commission must serve the public interest in
approving rates, we see no abuse of discretion in limiting this
proceeding to the shortrun problem of setting just and reasonable
rates for the service theretofore provided in response to the 1973
oil embargo. While an administrative agency must remain faithful to
public policies directly related to its regulatory authority, surely
at any given moment of history it may rationally decline to
affirmatively foster other policies in weighing the specific
interests that it is required by the statute to consider. This is
especially true when the forum chosen by proponents of the other
policy is not well suited to the study of its implications.1024
\1024\ Richmond Power, 574 F.2d at 616-17 (footnotes omitted).
---------------------------------------------------------------------------
In dicta, in a footnote that began with the Court doubting whether
the goal of energy independence is within the Commission's
regulatory jurisdiction at all, the Court merely said that
``(n)othing in NAACP v. FPC, supra, forecloses agency discretion to
consider in given situations pervasive public policies that it is
not required to evaluate in every decision it makes.'' 1025
---------------------------------------------------------------------------
\1025\ Id. at 616 n.22 (emphasis added).
---------------------------------------------------------------------------
The discretion to consider public policy matters is a far cry from
the authority, or obligation, to regulate those matters. We have
considered the environmental impact of the rule. Nothing in Richmond
Power suggests that the consideration of such matters conveys an
affirmative grant of broad new regulatory powers to develop and
implement a comprehensive regulatory program in an area expressly
assigned by Congress to another agency.1026
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\1026\ Alliance and the Project for Sustainable FERC cite
American Trucking Association, Inc. v. United States, 642 F.2d 916
(5th Cir. 1981), to support an argument that, even under NAACP, the
Commission can impose conditions under the FPA ``public interest''
standard because there is a ``nexus'' between the primary goals of
the FPA and the proffered conditions. As discussed below in greater
detail, we disagree.
American Trucking involved review of an ICC rulemaking effort
to, among other things, allow government agencies to tender a fair
portion of their freight shipments to small businesses and those
operated by disadvantaged persons. In reviewing the case, the Court
referenced the NAACP decision to observe that under the governing
law, the ICC's ``useful purpose'' and ``public need'' criterion
(used here to justify the regulations) do ``not (refer) to the
pursuit of affirmative action goals.'' Id. at 921-922. Indeed, it is
clear that the Court read NAACP as permitting the consideration of
``racial, ethnic and social-economic factors'' only when they relate
to the matters within the ICC's authority, i.e., the transportation
needs of the public, as opposed to some generalized notion of the
general public welfare. Id. at 922 n.3.
---------------------------------------------------------------------------
The cases rejecting commenters' broad reading of our public
interest authority are supported by the decision in Office of
Consumers' Counsel v. FERC, 655 F.2d 1132 (D.C. Cir. 1980) (Great
Plains). There, the Court found that, even under the explicit ``public
interest'' standard in section 7(a) of the Natural Gas Act, the
Commission is not granted power to act on matters outside of its
statutory mandate.1027
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\1027\ NGA section 7(a), like, for example, FPA section 203(a),
provides for a ``public interest'' standard of review. Section 7 of
the NGA represents the maximum authority the Commission has over
environmental issues under that Act. Section 7 provides the
Commission authority to approve the siting and construction of
facilities.
---------------------------------------------------------------------------
In Great Plains, the Court reviewed a Commission decision to grant
a certificate of public convenience and necessity to facilitate
construction and operation of a coal gasification plant. Although the
NGA does not explicitly provide the Commission with authority to
certificate coal gasification projects, the Commission reasoned that it
had such authority because the demonstration project was ``in the
public interest'' and, because the Commission was authorized under
section 7 of the NGA to ``consider'' all factors in reaching a decision
on whether to grant the certificate, it had the requisite authority to
act.
The Court rejected the Commission's reasoning in that case, stating
that:
Any such authority to consider all factors bearing on the
``public interest'' must take into account what the ``public
interest'' means in the context of the Natural Gas Act. FERC's
authority to consider all factors bearing on the public interest
when issuing certificates means authority to look into those factors
which reasonably relate to the purposes for which FERC was given
certification authority.1028
---------------------------------------------------------------------------
\1028\ Great Plains, 655 F.2d at 1147.
The Court repeated the finding in NAACP that the Commission's authority
to act in the public interest is limited to the furtherance of the
purposes for which its organic statutes were adopted.1029
---------------------------------------------------------------------------
\1029\ Id.
---------------------------------------------------------------------------
In concluding that the Commission was not authorized to act as it
did, the Court looked to several factors. The Court found it persuasive
that Congress had specifically authorized a different governmental
entity, the Synthetic Fuels Corporation, to provide support for coal
gasification, and that Congress had carefully crafted a special means
for providing federal financial assistance for synfuel
development.1030 The Court also found it persuasive that the
Commission possessed no expertise in making determinations regarding
the relative merits of different synfuel processes, methods or
technologies, and that the financing arrangements ``were certainly not
ordered with the interests of ratepayers foremost in mind.''1031
The Court stated that ``by utilizing its statutory tools for a non-
statutory purpose, FERC very likely was distracted from its primary
statutory duty to protect the interests of ratepayers.'' 1032
Finally, the Court found that the Commission's action seemed to have
been prompted at least in part by an attitude that, because Congress
had not acted speedily, the Commission could act. The Court criticized
the Commission for improperly attempting to preempt Congressional
action and to ``fill in''
[[Page 21686]]
where the agency believed federal action was needed.1033
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\1030\ Id. at 1150.
\1031\ Id. at 1151.
\1032\ Id.
\1033\ Id. at 1151-52.
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The facts and reasoning in Great Plains are directly analogous to
this proceeding. Congress has specifically authorized other entities--
EPA and the states--under other statutes to address air pollution. The
Commission is being urged to regulate in an area in which, as in Great
Plains, it possesses no special expertise (i.e., in making
determinations regarding appropriate air pollution control mitigation
measures) and in which it is not authorized to act.1034 Finally,
as in Great Plains, if the Commission were to undertake mitigation, it
would be diverted from its primary statutory duty to protect the
economic interests of ratepayers, i.e., by having to continually
monitor compliance with mitigation conditions.1035
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\1034\ To our knowledge the only time Congress has asked the
Commission with respect to its regulation under Parts II and III of
the FPA to address environmental issues was in Section 808 of the
Clean Air Act Amendments of 1990. There, Congress directed the
Commission, in consultation with EPA, to study the environmental
externalities of electricity production. The Commission staff did so
and provided the required report to Congress. While the Commission
in compliance with the 1990 Amendments also addressed the accounting
issues related to SO2 emissions trading, the Commission did so
within the context of its accounting authority under the FPA.
\1035\ EPA argues that the Commission would not be required to
monitor compliance with the environmental mitigation measures.
However, if environmental mitigation is within our statutory
mandate, we could not delegate that authority to others. See EPA at
51.
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As in Great Plains, the Commission is being urged to act at least
in part because of the belief that Congress has not provided a
sufficiently speedy process by which to regulate air pollution produced
by electric utilities. The EPA argues that:
Regulations under the Clean Air Act must in general be
implemented through State Implementation Plans; the time from
reaching a general conclusion that control is needed to adoption of
necessary regulations by states generally takes from three to five
years; that regulatory lag time means compliance with new rules can
be, and usually is, more than a decade from the point at which the
problem occurred. Ten years of bad air is ten years delay too
many.1036
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\1036\ EPA at 4-5; see also Project for Sustainable FERC
(protections achieved by the Clean Air Act Amendments of 1990 are in
danger of being destroyed by the Energy Policy Act's open access
policies if those policies are implemented without environmental
mitigation).
We would also note that the premise upon which EPA makes this
argument--that air emissions will rapidly increase with
implementation of the rule--is not supported by the record. See
Section V, Discussion, Subsection C.
That Congress has imposed upon the EPA procedures that the EPA and
others find burdensome and overly time consuming is an issue for
Congress and EPA to address, not the Commission.1037
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\1037\ We believe that this conclusion is supported by section
205(a) of the Public Utility Regulatory Policies Act of 1978
(PURPA). PURPA, inter alia, amended the FPA in certain respects but
also gave the Commission authority in certain sections, such as
PURPA sections 205(a) and 210, that did not amend the FPA. Under
PURPA section 205(a), the Commission in certain circumstances may
exempt electric utilities, in whole or in part, from state laws,
rules or regulations which prohibit or prevent voluntary
coordination, including agreements for central dispatch. (Of course,
the central dispatch is dispatch of generation facilities.) However,
PURPA section 205(a)(2) provides that no exemption may be granted if
the state law, rule or regulation is designed, among others, to
protect public health, safety or welfare or the environment. In
commenting on the limitation of the Commission's exemption authority
under PURPA section 205(a), the Conferees noted that the prohibition
includes ``regulations under the Clean Air Act.'' H.R. Conf. Rep.
No. 1750, 95th Cong., 2d Sess. 95 (1978), reprinted in 1978 U.S.
Code Cong. & Ad. News 7797, 7829. While the Commission's statutory
authority has been modified in legislation enacted subsequent to
PURPA, the provisions of PURPA section 205(a) have not been
modified.
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This conclusion has particular force when, as here, we are urged to
impose environmental restrictions on certain coal-fired generators in
spite of Congressional actions regulating those entities. In essence,
some commenters argue that under a very tenuous connection to the
public interest standard of the FPA we may undertake to do more than
the agency that Congress has authorized to act on such matters. This
result is not a correct reading of the law and we reject it.
Several commenters attempt to overcome the various Courts' views of
the scope of the public interest standard under the FPA by arguing that
there is a ``direct nexus'' between the Rule and environmental concerns
that suffices to invoke an imputed authorization under the FPA to
prescribe environmental requirements on generators.1038 To this
end, they argue that the purpose of the rule is really to facilitate
the least-cost use and construction of generation resources and that
the environmental consequences of these actions will impact economic
efficiency, rates, competition, and competitive markets. Thus, they
conclude that we have the authority to require that those who seek to
obtain transmission access on a non-discriminatory basis must first
mitigate air emissions under as yet undefined standards.
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\1038\ See, e.g., EPA at 54. See also Alliance; Project for
Sustainable FERC; Coalition; Signatories; CCAP; Attorneys General.
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These commenters misstate the question. The question is not whether
there is a nexus between the rule and environmental concerns. Clearly,
electric utilities contribute to pollution; anything that facilitates
the sale of power from whatever source is, under this tenuous logic,
``related'' to environmental concerns.1039
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\1039\ Under this logic, the Securities and Exchange Commission,
for example, which facilitates utility financing for new facilities
would be empowered to administer environmental requirements.
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However, as discussed below, Congress did not give us plenary
powers over public utilities to shape their activities in response to a
broad range of public policy concerns. The nexus that must be
established is a nexus between the requirements sought to be imposed,
in this case emission controls, and the statutory standards which
authorize us to act. That is, in order to impose the environmental
conditions sought by commenters, a direct connection must be
established between those conditions and our duty to determine that the
rates, terms and conditions of service under our open access tariffs
are not unjust, unreasonable, unduly discriminatory, or preferential.
It is on this point that commenters' arguments founder. While the
Commission has broad latitude to interpret these standards to advance
the interests of ratepayers, we cannot implement policy objectives that
are not assigned to us and that are, in fact, clearly assigned to other
entities. The Congress has assigned responsibility for environmental
regulation of air quality to EPA and the states; it has explicitly
charged them with dealing with such pollution from electric generating
facilities. While, as noted earlier, we do not dispute the need to give
appropriate weight to environmental considerations in making decisions
within our authority, we cannot use that authority to accomplish public
policy objectives that, by statute, are required to be implemented and
administered by other agencies.1040
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\1040\ We are also troubled by the confusion that persists as to
the usefulness of imposing a condition on the use of open access
tariffs as a means to accomplish environmental goals. As noted
earlier, the Commission's decision to compel the filing of open
access tariffs is intended to provide access to third party power
suppliers who need access across a utility's transmission system.
Open access will primarily benefit independent power suppliers
offering power from new facilities, most of which under current
market conditions are likely to be gas-fired facilities. Traditional
utilities that own the generating plants of particular concern to
commenters (i.e., coal-fired plants subject to less strict
environmental controls) have extensive transmission systems that
they can use to get power to market. Thus, the exercise of
conditioning authority is more likely to impede sales from new,
cleaner facilities than it is sales from older, coal-fired
facilities. It makes no sense from an economic or environmental
perspective to burden new transactions with this cumbersome
condition for what will likely be little in the way of effective
environmental controls.
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[[Page 21687]]
Some commenters have sought to address this issue by characterizing
the proposed conditions as necessary to create a level competitive
playing field among generators. For example, Alliance argues that
unless the Commission requires environmental mitigation certain
competitors in the bulk power market (those with ``dirty generation'')
---------------------------------------------------------------------------
would be favored over ``clean'' competitors. It argues that:
Mitigation of the environmental impacts resulting from the NOPR
has a direct relationship to ensuring that open access is
implemented under terms of economic fairness for all utilities and
utility consumers, and not merely those with current low-cost
regulatory advantages.1041
---------------------------------------------------------------------------
\1041\ Alliance at 55. See also Project for Sustainable FERC at
37.
We note that all power generation technologies have different costs.
For example, hydroelectric facilities which, like coal-fired
facilities, may have environmental mitigation conditions imposed on
them, may be quite expensive to build compared to gas or oil-fired
generation, but their operating costs may be significantly lower. These
cost differences may reflect the different costs of complying with
mandated environmental requirements; the prudent costs of complying
with such mandates may be reflected in rates.
Indeed, sellers come to the power markets with a variety of
advantages and disadvantages, many of which are the result of federal
laws--for example, tax preferences, labor standards, and similar
matters. In empowering the Commission to remedy undue discrimination
and promote competition, Congress has not authorized the Commission to
equalize the environmental costs of electricity production in order to
ensure ``economic fairness.'' Such homogenization of competitors, or
their costs, has never been a goal of the FPA.1042
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\1042\ For the same reason, we do not have authority to impose
an obligation on utilities to ``internalize'' environmental
externalities. See generally FEIS at 7-24. In effect, such proposals
would involve the Commission requiring a surcharge on power sales
rates fixed at some amount equal to the environmental ``cost''
inflicted by the generation supporting those sales. Assuming such a
surcharge could be calculated, imposing such a cost would be to fix
a rate without reference to any cost incurred by the public utility.
Indeed, we would impose in rates, and require ratepayers to pay, a
cost that was manifestly not incurred by the utility. In reality,
such a surcharge would require us to impose a tax or a penalty,
neither of which we are authorized to impose.
The SO2 program created under the 1990 Clean Air Act
Amendments illustrates the way in which EPA and FERC authority can
intersect to accomplish the goal of internalizing externalities.
There, the Congress by capping emissions and providing for a market
in emission allowances required utilities to ``pay for'' the right
to emit SO2. These costs are legitimate costs and the
Commission's role is to permit their recovery in rates. Similarly, a
comparable NOX cap and trading scheme established by EPA would
``internalize'' the external costs of NOX pollution and the
Commission would provide for prudently incurred allowance costs in
rates.
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In short, the ``economic nexus'' urged by commenters advocating
that the Commission undertake to regulate air emissions is inconsistent
with the ``charge to promote the orderly production of plentiful
supplies of electric energy'' envisioned by the FPA.1043
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\1043\ NAACP, 425 U.S. at 670.
---------------------------------------------------------------------------
We have exercised conditioning authority in the past only where
necessary to ensure that jurisdictional transactions and rates do not
result in anti-competitive effects, or are not unjust, unreasonable or
unduly discriminatory or preferential.1044 Thus, the conditions we
have imposed have involved economic regulatory matters within our
purview under the FPA.1045 Any exercise of conditioning authority
must, as the Supreme Court noted in NAACP, be directly related to our
economic regulation responsibilities; EPA and the other commenters have
not demonstrated such a nexus.1046
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\1044\ Cf. Utah Power & Light Co., Opinion No. 318, 45 FERC
para. 61,095 at 61,280-83 (1988) (discussing the Commission's
authority to condition a merger). Unlike the situation in Opinion
No. 318 where the Commission had the authority under section 203 to
disapprove a merger upon a finding of actual and potential
anticompetitive effects, the Commission's rate authority under
sections 205 and 206 does not permit the Commission to deny the
proposed rates out of a concern that such action will result in an
increase in air pollution. See Monongahela Power Co., 39 FERC para.
61,350 at 62,096, reh'g denied, 40 FERC para. 61,256 (1987). As a
result, we have no authority to condition the same result under
these sections on environmental mitigation.
\1045\ The obligation of the Commission to weigh antitrust
considerations highlights this point. The Commission must take into
account anticompetitive effects when setting rates. See Northern
Natural Gas Co. v. FPC, 399 F.2d 953 (D.C. Cir. 1968). However, we
are limited as to the remedies we may impose. We cannot go further
and assess the range of remedies that, for example, a Court may
exact upon finding an antitrust violation. See generally NAACP, 520
F.2d at 441.
\1046\ Project for Sustainable FERC, at 32-33, and Alliance, at
41-42, have attempted to argue that NAACP actually supports the
Commission having authority to order environmental mitigation. Their
argument fails because they have not shown, and cannot show, the
necessary direct nexus to our economic regulation.
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This distinction is more evident when one considers the way in
which we are authorized to treat the costs of environmental compliance.
There are legitimate costs of environmental compliance that should be
reflected in jurisdictional rates to the extent prudently incurred,
just as the prudent costs of complying with, for example, occupational
health and safety requirements designed to protect utility employees
should be reflected in jurisdictional rates. This we are authorized to
do and we routinely review and allow such costs.1047 However, the
fact that the costs of providing utility workers with a safe workplace
are properly reflected in utilities' jurisdictional rates does not mean
that we have authority to condition sellers' rates or customers' use of
jurisdictional services on meeting safety regulations that are in the
public interest. The same rationale applies to environmental matters
related to the rule.1048
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\1047\ For example, our regulations permit 100 percent of any
construction work in progress for pollution control facilities
allocable to wholesale sales to be included in rate base. See 18 CFR
35.25 (1995). This regulatory action, directly related to our core
ratemaking responsibilities, removes an economic disincentive for
public utilities to invest in structures designed to reduce the
amount of pollution produced by a generating facility. See 18 CFR
35.25(b) (definition of pollution control facility).
The Commission also addressed the ratemaking consequences of
SO2 emissions trading in response to a petition from the Edison
Electric Institute. This is another example of the Commission's
proper exercise of its jurisdiction, i.e., over the costs of
environmental compliance.
\1048\ Indeed, our regulations provide for such cost recovery.
---------------------------------------------------------------------------
Commenters also raise several other arguments to support the claim
that the Rule requires us to undertake environmental regulation to
remedy supposed impacts of the rule. EPA, for example, argues that
requiring environmental mitigation would not run afoul of the
prescription of section 201(b)(1) of the FPA enjoining our regulation
of generation facilities because the ``regulation of transmission
tariffs necessarily has manifold indirect effects on generation
sources. The proposed mitigation mechanism would influence generation
sources in a similar, indirect manner.'' 1049
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\1049\ EPA at 50.
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EPA fundamentally misunderstands the purpose of the Rule. We act to
remedy unduly discriminatory practices in, as here for example, the
provision of transmission access. Since ``undue discrimination,'' is
one of the matters ``specifically provided in this Part (II)'', i.e.,
in FPA sections 205 and 206, we are acting within the bounds of our
statutory mandate and the effect that the Rule may have ``over
facilities used for the generation of electric energy'' is specifically
sanctioned. Indeed, many generators are transmission customers who we
are obliged to protect under the FPA. That there may be indirect
environmental consequences from our Rule does not trigger our
jurisdiction under the FPA.
[[Page 21688]]
EPA next argues that, even if we could not impose a specific
mitigation mechanism for open access transmission, we could deny
transmission service unless there is a showing that the service will
not have an adverse environmental impact.1050
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\1050\ EPA at 51. See also NESCAUM at 19; Alliance at 18, 53;
Project for Sustainable FERC at 37.
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We have already discussed why we believe this approach is
unworkable and inconsistent with sections 205 and 206 of the
FPA.1051 Plainly stated, EPA would have transmission customers
assume an additional regulatory burden in order to be treated
lawfully.1052 Quite apart from this fundamental problem, such a
regime is beyond our authority. Our regulation under sections 205 and
206 is over the selling public utility's rates, terms and conditions,
not over the buyer's agreement to undertake measures which have no
nexus whatsoever with the seller's costs or terms of service.
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\1051\ CCEM argues that the tracking of documentation with
environmental compliance requirements will stifle the very
competitive bulk p
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
ower market that EPA and others profess to
support. CCEM notes that ``(i)t is both ironic and inexplicable why
EPA, the agency charged with enforcing the nation's clean air and
other environmental protection laws is so anxious to shift this
responsibility away from itself and onto economic participants in
the incipient, competitive power supply industry.'' CCEM
Supplemental Comments at 4.
\1052\ We also note that under EPA's scheme those most likely to
benefit from denying access--transmission sellers--would be provided
the authority to lawfully deny transmission access.
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EPA states that its alternative mitigation mechanism would not be a
condition of the open access tariff, but apparently a condition on the
ability of customers to take service under the tariff. However, our
authority to set terms and conditions of eligibility derives from
precisely the same authority that we use to set other tariff terms. It
must still be based on a nexus with the subject matter of our
jurisdiction. For buyers, open access is a right, not a privilege. We
fail to see, given the direction of the FPA to ensure these rights, any
basis for us to undertake the actions EPA proposes.
Finally, EPA points to the Commission's decision to exclude certain
diesel facilities in defining qualifying facilities (QF) under PURPA
section 210.1053 However, this provides no precedent for imposing
environmental standards to prevent customers from obtaining
nondiscriminatory open access. Whatever the merits of that
decision,1054 the Commission subsequently found that any facility
that satisfies the ownership and technical requirements for QF status
set forth in PURPA and the Commission's regulations is a QF without any
action by the Commission.1055 More to the point, EPA ignores the
fact that, in issuing environmental findings with its QF Rules, the
Commission found that environmental concerns were a local matter to be
handled under other statutory authorities. While PURPA permitted
certain qualifying facilities to be exempt from state and federal laws,
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\1053\ EPA states at 51-52 that:
In implementing section 210 of the Public Utility Regulatory
Policies Act, the FERC took the approach of declining to act because
of the potential adverse environmental impacts of the action.
Section 210 required the FERC to prescribe regulations ``to
encourage cogeneration and small power production * * * Because of
its concern that ``diesel and dual-fuel commercial cogeneration
facilities in the New York City area had the potential to cause
environmentally significant effects'' (46 FR 33025) (1981)), the
FERC issued regulations that excluded new diesel cogeneration
facilities from being ``qualifying facilities.'' 45 FR 17964.
EPA maintains that the FERC similarly has authority in the
instant case to deny open access transmission to the extent such
transmission would have adverse environmental impacts.
\1054\ The Commission subsequently modified this position and
decided to treat diesel cogeneration facilities like other QFs.
\1055\ See CMS Midland, Inc., 50 FERC para. 61,098 at 61,277-278
(1990), reh'g denied, 56 FERC para. 61,177 (1991), aff'd mem. sub
nom., Michigan Municipal Cooperative Group, v. FERC, 990 F.2d 1377
(D.C. Cir.) (per curiam), cert. denied, 114 S.Ct. 546 (1993); see
also Mesquite Lake Associates, Ltd., 63 FERC para. 61,351 (1993);
Citizens for Clean Air and Reclaiming Our Environment v. Newbay
Corporation, 56 FERC para. 61,428 at 62,532-33, reh'g denied, 57
FERC para. 61,219 (1991).
it excludes exemptions from environmental laws. Thus, a qualifying
facility may not be built or operated unless it complies with all
applicable local, State, and Federal zoning, air, water, and other
environmental quality laws, and unless it obtains all required
permits.1056
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\1056\ Small Power Production and Cogeneration Facilities--
Environmental Findings, 10 FERC para. 61,314 at 61,632 (1980). The
Commission has included similar language in every order it issues
finding qualifying facility status. See also Small Power Production
and Cogeneration, Order No. 70-E, FERC Stats. & Regs., Regs.
Preambles 1977-81 para. 30,274 at 31,596 (1981).
Thus, while we have noted that QFs are required to satisfy all
environmental requirements, we have not viewed our responsibilities
under PURPA as permitting us to enforce compliance with environmental
laws.1057
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\1057\ The important point is that the Commission has fully
complied with its responsibilities under NEPA in both instances.
Whatever initial decision it may have come to in 1981 with regard to
the particular circumstances involved in adopting QF regulations
under PURPA is irrelevant to the instant rulemaking.
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EPA then proposes to require any fossil fuel-burning generating
entity seeking service under an open access tariff to (a) commit by
contract to avoid or offset emissions increases (measured against
certain baselines), and (b) periodically certify its compliance with
that commitment.1058 This proposal is neither workable nor within
our jurisdiction.
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\1058\ EPA's proposal apparently would apply only for NOX,
CO2 and mercury. See EPA at 58 n.31 and 60 (because there is
already a nationwide cap on SO2 emissions in the Clean Air Act,
there is no need for mitigation for that pollutant). In other words,
EPA apparently would require us to impose environmental mitigation
only in those instances in which Congress has not provided a
nationwide cap for a pollutant.
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The deficiency with respect to (a) is that we have no authority to
require such action. While EPA cites to FPA section 206 for the
proposition that we may change jurisdictional contracts, we may do so
only if the contract is, for example, unjust or unreasonable with
respect to matters within our jurisdiction, i.e., economic regulation.
Our standards for acting are strictly prescribed under the
FPA.1059 As NAACP and Great Plains teach, sections 205 and 206 do
not provide the Commission with the means to remedy every possible
problem that is in any fashion related to a sale for resale or
transmission in interstate commerce by a public utility. Since we do
not have the authority to require (a), it follows we cannot require the
periodic certification of compliance recommended in (b).
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\1059\ See United Gas Pipe Line Co. v. Mobile Gas Service Corp.,
350 U.S. 332 (1956); FPC v. Sierra Pacific Power Co., 350 U.S. 348
(1956).
---------------------------------------------------------------------------
EPA notes that it ``could establish a procedure whereby a generator
could voluntarily subject its facilities to emission limits that are
enforceable by EPA and/or state environmental authorities.'' 1060
This is a matter within EPA's province, and we support EPA in
undertaking whatever measures it determines to be within its authority
and appropriate to the problem.
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\1060\ EPA at 59 (emphasis added). See also Project for
Sustainable FERC at 38-39 (proposing that a regulatory plan be
developed through consultations between the Commission, EPA, DOE,
and appropriate regional and state regulators and then presented in
the FEIS).
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Alliance argues, at 47-51, that sections 211 and 212 of the FPA, as
amended by the Energy Policy Act, authorize the Commission to impose
environmental conditions. To the extent that Alliance's arguments rely
on the ``public interest'' language used in section 211, we believe
that the discussion above already addresses such arguments, with one
exception: Alliance argues that the House Report for the Energy Policy
Act states that the purpose of the Act is to ``increase U.S. energy
security in cost-effective and environmentally beneficial ways
[[Page 21689]]
* * *.'' 1061 However, even if we assume that the Report language
reflects Congressional intent for the Energy Policy Act in general, we
note that, in Title VII of the Energy Policy Act concerning
electricity, the only mention of the environment was, as noted above,
in section 731 which specifically provided that nothing in the Energy
Policy Act in any way interferes with the authority of any state or
local government relating to, inter alia, environmental protection.
While we do not quarrel with the proposition that Congress in the
Energy Policy Act obviously had concerns with environmental
matters,1062 Congress did not provide the Commission with any
authority to mandate environmental mitigation.
---------------------------------------------------------------------------
\1061\ Alliance at 62, quoting H.R. Rep. No. 474 (Part I) (Vol.
4), 103d Cong., 2d Sess. 132 (1992), reprinted in 1992 U.S. Code
Cong. & Ad. News 1955.
\1062\ For example, Title XVI concerned Global Climate Change.
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We have undertaken an extensive NEPA analysis to consider the
environmental effects of our Rule. We cannot, however, take NEPA's
requirement to consider environmental effects as authority to require
the environmental mitigation proposed in the comments. Congress has
charged other agencies, most notably the EPA, with the responsibility
of protecting the environment and enforcing environmental
laws.1063 While we stand ready to work in a complementary fashion
with these agencies, we believe that any attempt by the Commission to
go beyond the economic regulation that Congress has delegated to us
would be ultra vires.
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\1063\ See, e.g., S. Rep. No. 228 (concerning the Clean Air Act
Amendments of 1990), 101st Cong., 2d Sess. 5 (1990), reprinted in
1990 U.S. Code Cong. & Ad. News 3391 (``The States, together with
EPA, are responsible for ensuring that the primary air quality
standards are met * * *''); S. Rep. No. 228, 101st Cong., 2d Sess.
9, reprinted in 1990 U.S. Code Cong. & Ad. News 3395 (``The 1970 and
1977 Clean Air Act Amendments established a partnership between the
States and Federal government. EPA sets nationally uniform air
quality standards and States, with the Agency's assistance, are
responsible for meeting them.''). See also, e.g., Connecticut v.
EPA, 696 F.2d 147, 163 (2d Cir. 1982) (``One central focus of the
Clean Air Act Amendments of 1977 was to ensure that the EPA would
monitor and control the impact of pollution from one state on air
quality in another.''); Ohio Environmental Council v. EPA, 593 F.2d
24, 31 (6th Cir. 1979) (``Congress placed responsibility for
enforcing the Clean Air Act in the U.S. EPA.'').
We further note the following limitations on the Clean Air Act
Amendments of 1990 with respect to the emission allowance program in
section 403(f), which provides in pertinent part:
Nothing in this section shall be construed as requiring a change
of any kind in any State law regulating electric utility rates and
charges or affecting any State law regarding such State regulation
or as limiting State regulation (including any prudency review)
under such a State law. Nothing in this section shall be construed
as modifying the Federal Power Act (16 U.S.C.A. 791a et seq.) or as
affecting the authority of the Federal Energy Regulatory Commission
under that Act. Nothing in this subchapter shall be construed to
interfere with or impair any program for competitive bidding for
power supply in a State in which such program is established.
42 U.S.C. 7651b(f). Thus, Congress expressly chose not to tie
environmental authority under the emission allowance program to the
Commission's and states' ratemaking authority.
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To summarize: The Commission's jurisdiction under Parts II and III
of the FPA is limited to matters relating to economic regulation.
Neither the relevant statutes nor the case law supports the expansive
and novel reading of the Commission's authority advocated by the
commenters that argue that we have environmental mitigation authority.
The Commission is not explicitly given such authority in either the FPA
or NEPA. Moreover, the FPA and the case law clearly compel the
conclusion that we cannot impose environmental conditions that do not
directly relate to the economic matters over which we have
jurisdiction. To do so, in fact, would prevent the Commission from
effectively carrying out its responsibilities under the FPA.
F. Coastal Zone Management Act Issue
By letter dated February 22, 1996, and filed with the Commission on
March 5, 1996, the Connecticut Department of Environmental Protection
(Connecticut) notified the Commission that it has determined that the
Commission's proposed action in this rulemaking proceeding is likely to
adversely affect Connecticut's coastal resources. Connecticut reasons
that the Rule's promotion of competition ``is likely to increase energy
production by mid-west coal burning plants(,) which will in turn
increase the export of nitrogen and sulphur oxides.'' Connecticut
states that airborne nitrogen emissions are linked to adverse
environmental impacts in Long Island Sound. It therefore asserts that,
pursuant to section 307(c)(1) of the Coastal Zone Management Act (16
U.S.C. 1456(c)(1)) (CZMA), and the federal regulations promulgated
thereunder (15 CFR part 930), the Commission is required to provide it
with a determination of the Rules' consistency with Connecticut's
federally approved coastal management plan.
Section 307(c)(1)(A) of the CZMA deals with the prevention or
amelioration of adverse physical impacts on coastal zone resources
attributable to federal activities. The legislative history indicates
that in enacting the CZMA Congress was concerned with the adverse
effects on coastal lands and waters of such activities as excavation,
filling, diversion of water or sediment, clearing, and off-shore energy
exploration and dumping.1064
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\1064\ The conference report on the 1990 CZMA amendments
expressly states that the principal objective of the 1990 revisions
to the language of section 307(c)(1) was to overturn a Supreme Court
decision holding that Outer Continental Shelf oil and gas lease
sales were not subject to CZMA consistency determinations. H.R. Rep.
No. 101-964, 101st Cong., 2d Sess. 2675 (1990).
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As discussed more fully above, section 201 of the FPA declares that
the Commission shall not have jurisdiction over facilities used for the
generation of electricity except as specifically provided. Thus, the
Commission has no direct jurisdiction over fossil-fuel plants. Its
jurisdiction extends only to the rates, terms, and conditions of
wholesale sales and transmission of electric energy in interstate
commerce from those plants. While we are aware that the legislative
history of the CZMA indicates a Congressional intent to cover all
federal activities, there is absolutely no indication in the CZMA or
its legislative history that ``federal activities'' should include all
federal regulatory decisions, including Commission orders involving
interstate electric rates and service (or any other jurisdictional
matter under Part II of the FPA).1065 We are not aware of any
judicial or agency interpretation that would cast the net of the states
under the CZMA broadly enough to include the generic federal regulatory
action undertaken in this Rule. Such action is clearly remote from the
kind of activities such as leasing of land, and dredging and filling
that either affect, or authorize specific activities that affect, the
environment in the coastal zone.
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\1065\ In using the phrase ``federal activities'' Congress did
not use the term ``federal action'' which has clear and broad
meaning under NEPA.
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Connecticut's attempt to pull FPA Part II regulation into the CZMA
federal consistency provisions by dint of the rulemaking's alleged
adverse impact on air quality and consequent adverse impact on water
quality in the coastal zone is untenable in view of the existence of
the Clean Air Act, a complex, 700-page environmental law that
constitutes a comprehensive scheme of regulation of the Nation's air
quality, including the direct regulation of emissions by utility power
plants. Indeed, the CZMA provides that the requirements of the Clean
Air Act, and governmental directives pursuant to that Act, shall be
incorporated in, and shall be the air pollution control requirements
of, all state coastal zone
[[Page 21690]]
management programs.1066 It therefore defies logic to assert that,
despite the pervasive regulatory reach of the Clean Air Act and the
clear authority of EPA to regulate NOX emissions under that
statute, the CZMA is a separate source of authority for state
jurisdiction over air quality impacts to coastal zones.
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\1066\ Section 307(f) of the CZMA, 16 U.S.C. 1456(f). A state
may develop more stringent standards, if they can be enforced by the
state (15 CFR 923.45(c)(2)), but more stringent state air quality
standards would not alter the characteristics of FPA Part II
regulation that put it beyond the federal consistency requirements
of the CZMA.
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While it is clear that Connecticut's invocation of the CZMA is
incorrect, we note that, under the Commerce Department's implementing
regulations, Connecticut has in any event waived its right to request a
consistency determination for the Commission's rulemaking.
Connecticut's coastal management program's list of federal agency
activities likely to require a consistency determination does not (for
good reason) describe rulemakings of this kind, and the rule will not
``result in a significant change in air or water quality within the
management area'' (the program's catch-all category). In addition,
Connecticut did not notify the Commission of its conclusion that the
Rule requires a consistency determination until well after 45 days from
receipt of several notices of the rulemaking proceeding.1067
Consequently, pursuant to 15 CFR 930.35(b), Connecticut has in any
event waived its right to request a consistency determination for this
rulemaking.
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\1067\ The Connecticut Department of Environmental Protection is
on the service list for the rulemaking proceeding. The Commission
issued a NOPR in this proceeding on March 29, 1995 (60 FR 17662,
April 7, 1995). On July 12, 1995, it issued a notice of intent to
prepare an EIS in this proceeding (60 FR 36752, July 18, 1995). On
November 17, 1995, the Commission issued a Draft EIS (60 FR 58304,
Nov. 27, 1995).
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Conclusion
After reviewing the record in this proceeding, including the FEIS,
we find for the reasons discussed above that proceeding with this rule
is the best alternative. No other alternative will accomplish the
Commission's purposes.
The rule is expected to slightly increase or slightly decrease
total future NOX emissions, depending on whether competitive
conditions in the electric industry favor the utilization of natural
gas or coal as a fuel for the generation of electricity. Other impacts
of the rule have also been determined to be slight. Therefore, it is
unnecessary to adopt and implement a plan of mitigation.
A wide range of mitigation measures have nonetheless been fully
evaluated as discussed in Chapter 7 of the FEIS. This discussion
concludes that the Commission does not have authority under the FPA and
NEPA, singly or conjointly, to impose mitigation, and that existing and
proposed mitigation strategies and efforts are the best way to deal
with potential environmental effects that might result from
implementing the rule. Such effects, if they indeed materialize, are
not expected to occur for many years. In the meantime, action by
entities such as EPA and OTAG are expected to address the underlying
air emission problems facing parts of the Nation. Interim mitigation
efforts to be undertaken by the Commission would address only a very
small part of the problem, would require the exercise of technical
expertise and authority that the Commission does not possess, and could
well interfere with efforts by EPA and others to address this
situation.
For these reasons, we support the analysis in the staff's FEIS and
adopt the conclusions in that document.1068
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\1068\ A Record of Decision (ROD) will not be issued as a
separate document; instead this rule, including the FEIS as
incorporated into the rule by adoption, will serve as the ROD for
the rule.
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VI. Regulatory Flexibility Act Certification
The Regulatory Flexibility Act (RFA) 1069 requires rulemakings
to contain either a description and analysis of the effect that the
proposed rule will have on small entities or a certification that the
rule will not have a significant economic impact on a substantial
number of small entities. In the Open Access and Stranded Cost NOPRs,
the Commission concluded that the proposed rules would not have a
significant economic impact upon a substantial number of small
entities.1070
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\1069\ 5 U.S.C. 601-612.
\1070\ 60 FR 17662 at 17721 (April 7, 1995), FERC Stats. & Regs.
para. 32,514 at 33,151.
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SBA questions this conclusion.1071 It states that,
``[a]ccording to data from the Department of Energy, the vast majority
of utilities are small.'' 1072 SBA requests that if, upon
reconsideration, the Commission determines that the final rule in the
Open Access NOPR proceeding would have a significant economic impact on
a substantial number of small entities, the Commission perform a
Regulatory Flexibility Analysis under the requirements of the
RFA.1073
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\1071\ SBA Initial Comments at 1 and n.1.
\1072\ SBA Initial Comments at 2 n.1. SBA ``defines a small
electric utility as one that disposes of 4 million MWh of
electricity in a given year.'' Id. At an average wholesale price of
between $30 and $40 per MWh (Energy Information Administration,
Financial Statistics of Major Investor-Owned Utilities, 1994, Table
No. 1), utilities that dispose of 4 million MWh per year would have
annual sales in the range of $120 million to $180 million.
\1073\ 5 U.S.C. 601-612. SBA Initial Comments at 2 n.1.
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A. Docket No. RM95-8-000 (Open Access Final Rule)
1. Public Utilities
The Open Access Final Rule is applicable to public utilities that
own, control or operate interstate transmission facilities, not to
electric utilities per se.1074 The total number of public
utilities that, absent waiver, would have to have open access tariffs
on file is 166.1075 Of these, only 50 public utilities dispose of
4 million MWh or less per year.1076 Eliminating those utilities
that are affiliates of other utilities whose sales exceed 4 million MWh
per year, or are not independently owned,1077 the total number of
public utilities affected by the Open Access Final Rule that qualify
under the SBA's definition of small electric utility is 19, or 11
percent of the total number of public utilities that would have to have
on file open access tariffs.1078 We do not consider this a
substantial number,1079 and, in any event, these entities may seek
waiver of the Open Access Final
[[Page 21691]]
Rule's requirements under the Rule's waiver provisions.
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\1074\ The Stranded Cost Final Rule is applicable to public
utilities and to transmitting utilities (that are not also public
utilities).
\1075\ Over 100 of these entities have already filed some type
of open access tariff.
\1076\ The sources for this figure are FERC Form No. 1 and FERC
Form No. 1-F data.
\1077\ The RFA defines a ``small entity'' as ``one which is
independently owned and operated and which is not dominant in its
field of operation.'' See 5 U.S.C. 601(3) and 601(6) and 15 U.S.C.
632(a)(1) (definition of ``small business concern'').
\1078\ We note that five of these 19 public utilities have
already filed open access tariffs with the Commission. While these
five public utilities fall within SBA's definition of small electric
utility, since they have already filed open access tariffs, the
effect of the Open Access Final Rule on these entities should not be
significant. The remaining 14 small public utilities constitute
eight percent of the total number of public utilities that would
have to have on file open access tariffs. To the extent these 14
small public utilities consider the impact of the Final Rule to be
significant, these entities may request a waiver of the open access
filing requirements under the waiver provisions of the Open Access
Final Rule.
\1079\ In Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327,
340-43 (D.C. Cir. 1985) (Mid-Tex), the court accepted the
Commission's conclusion that, since virtually all of the public
utilities that it regulates do not fall within the meaning of the
term ``small entities'' as defined in the RFA, the Commission did
not need to prepare a regulatory flexibility analysis in connection
with its proposed rule governing the allocation of costs for
construction work in progress (CWIP). The CWIP rules applied to all
public utilities. The Open Access Final Rule applies to only those
public utilities that own, control or operate interstate
transmission facilities. These entities are a subset of the group of
public utilities found not to require preparation of a regulatory
flexibility analysis for the CWIP rule.
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Moreover, in the Open Access Final Rule, the Commission is
specifying the non-rate terms and conditions of the tariffs that the
public utilities must have on file. The public utilities need only
develop and file a rate.1080 When one considers that the
disposition of 4 million MWhs a year translates into sales in the range
of $120 million to $180 million per year, the cost to prepare and file
proposed rates,1081 which these utilities must regularly do anyway
in the ordinary course of business, is not a significant economic
impact.
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\1080\ Those public utilities that already have open access
tariffs on file are not even required to propose rates. They may
elect to continue service under the Open Access Final Rule's non-
rate terms and conditions at their existing rates.
\1081\ In the Public Reporting Burden section (Section II), the
Commission reaffirms the average reporting burden of 300 hours per
response, which was proposed and unchallenged in the NOPR. If a cost
of $200 per hour is used, the cost of making the required filing
would be $60,000. On average, this is no more than one half of one
percent of total annual sales for small electric utilities.
---------------------------------------------------------------------------
2. Non-Public Utilities
The Open Access Final Rule will not impose any burden on non-public
utilities, since they need not themselves file open access tariffs.
Triggering the reciprocity provision in the Open Access Final Rule is
optional; it is merely a condition of receiving a benefit, i.e., open
access transmission service from a public utility. If non-public
utilities elect not to take advantage of open access services because
they do not want to meet the tariff reciprocity provision, they can
still seek voluntary, bilateral transmission services from public
utilities. Also, under the waiver provisions in the Open Access Final
Rule, small non-public utilities may seek waiver from the reciprocity
provision.
B. Docket No. RM94-7-001 (Stranded Cost Final Rule)
1. Public Utilities
As with the Open Access Final Rule, there are not a substantial
number of public utilities that qualify under the SBA's definition of
small electric utility that are subject to the Stranded Cost Final
Rule. The Stranded Cost Rule applies only to public utilities that seek
stranded cost recovery in connection with a limited set of wholesale
requirements contracts (those executed on or before July 11, 1994 that
do not contain an exit fee or other explicit stranded cost provision).
To the extent that public utilities seek stranded cost recovery, they
will do so in a rate filing, where stranded cost recovery is likely to
be one of many items considered. Accordingly, the Stranded Cost Final
Rule will not pose a significant economic impact on a substantial
number of public utility small entities.
2. Non-Public Utilities
With regard to non-public utilities, the stranded cost issue would
only arise in a proceeding under sections 211 and 212 of the FPA when,
in directing transmission, the Commission addresses the stranded cost
issue in determining a just and reasonable rate. As with public
utilities, stranded costs will be just one more item to be considered
in establishing just and reasonable rates for transmission. As a
result, the Stranded Cost Final Rule will not impose a significant
economic impact on a substantial number of non-public utility small
entities.
C. Conclusion
Accordingly, the Commission certifies that these final rules will
not have a significant economic impact on a substantial number of small
entities.
VII. Information Collection Statement
The Office of Management and Budget's (OMB) regulations 1082
require that OMB approve certain information and recordkeeping
requirements (collections of information) imposed by an agency. Upon
approval of a collection of information, OMB shall assign an OMB
control number and an expiration date. Respondents subject to the
filing requirements of this Rule shall not be penalized for failing to
respond to this collection of information unless the collection of
information displays a valid OMB control number.
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\1082\ 5 CFR 1320.11.
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There are now approximately 328 public utilities, including
marketers and wholesale generation entities. The Commission estimates
that 166 of these utilities own, control or operate facilities used for
the transmission of electric energy in interstate commerce and would be
subject to the filing requirements of this Rule.
Title: FERC-516, Electric Rate Schedule Filings.
Action: Final Rule.
OMB Control No: 1902-0096.
Respondents: Public Utilities that own, control or operate
facilities used for the transmission of electric energy in interstate
commerce.
Frequency of Responses: On occasion.
Necessity of information: The Final Rule requires public utilities
that own, control or operate facilities used for the transmission of
electric energy in interstate commerce to have on file with the
Commission non-discriminatory open access transmission tariffs that
contain minimum terms and conditions of service and permits public
utilities to make filings to seek recovery of legitimate, prudent and
verifiable stranded costs associated with providing open access and FPA
section 211 transmission services. The Commission has a mandate under
sections 205 and 206 of the FPA to ensure, with respect to any
transmission in interstate commerce or any sale of electric energy for
resale in interstate commerce by a public utility, that no entity is
subject to undue discrimination. The Commission will use the data
collected in this collection of information to carry out its
responsibilities under Part II of the FPA. The Commission's Office of
Electric Power Regulation will use the data to review electric rate and
tariff filings.
The Commission is submitting notification of this Final Rule to
OMB. Interested persons may obtain information on the reporting
requirements by contacting the Federal Energy Regulatory Commission,
888 First Street, NE., Washington, DC. 20426 [Attention: Michael
Miller, Information Services Division, (202) 208-1415], and to the
Office of Management and Budget (Attention: Desk Officer for the
Federal Energy Regulatory Commission, (202) 395-3087).
VIII. Effective Date
This Rule will take effect on July 9, 1996. The Commission has
determined, with the concurrence of the Administrator of the Office of
Information and Regulatory Affairs of the Office of Management and
Budget, that this rule is a ``major rule'' within the meaning of
section 351 of the Small Business Regulatory Enforcement Act of
1996.1083 The rule will be submitted to both Houses of Congress
and the Comptroller General prior to its publication in the Federal
Register.
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\1083\ 5 U.S.C. 804(2).
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List of Subjects
18 CFR Part 35
Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.
18 CFR Part 385
Administrative practice and procedure, Electric power, Penalties,
Pipelines, Reporting and recordkeeping requirements.
By the Commission. Commissioner Hoecker concurred in part and
dissented in
[[Page 21692]]
part with a separate statement attached. Commissioner Massey
dissented in part with a separate statement attached.
Lois D. Cashell,
Secretary.
In consideration of the foregoing, the Commission amends parts 35
and 385, chapter I, title 18 of the Code of Federal Regulations, as set
forth below.
PART 35--FILING OF RATE SCHEDULES
1. The authority citation for part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
2. Part 35 is amended by revising Sec. 35.15, by redesignating
Sec. 35.28 as Sec. 35.29, and by adding new Secs. 35.26, 35.27, and
35.28 to read as follows:
Sec. 35.15 Notices of cancellation or termination.
(a) General rule. When a rate schedule or part thereof required to
be on file with the Commission is proposed to be cancelled or is to
terminate by its own terms and no new rate schedule or part thereof is
to be filed in its place, each party required to file the schedule
shall notify the Commission of the proposed cancellation or termination
on the form indicated in Sec. 131.53 of this chapter at least sixty
days but not more than one hundred-twenty days prior to the date such
cancellation or termination is proposed to take effect. A copy of such
notice to the Commission shall be duly posted. With such notice each
filing party shall submit a statement giving the reasons for the
proposed cancellation or termination, and a list of the affected
purchasers to whom the notice has been mailed. For good cause shown,
the Commission may by order provide that the notice of cancellation or
termination shall be effective as of a date prior to the date of filing
or prior to the date the filing would become effective in accordance
with these rules.
(b) Applicability. (1) The provisions of paragraph (a) of this
section shall apply to all contracts for unbundled transmission service
and all power sale contracts:
(i) Executed prior to July 9, 1996; or
(ii) If unexecuted, filed with the Commission prior to July 9,
1996.
(2) Any power sales contract executed on or after July 9, 1996 that
is to terminate by its own terms shall not be subject to the provisions
of paragraph (a) of this section.
(c) Notice. Any public utility providing jurisdictional services
under a power sales contract that is not subject to the provisions of
paragraph (a) of this section shall notify the Commission of the date
of the termination of such contract within 30 days after such
termination takes place.
Sec. 35.26 Recovery of stranded costs by public utilities and
transmitting utilities.
(a) Purpose. This section establishes the standards that a public
utility or transmitting utility must satisfy in order to recover
stranded costs.
(b) Definitions.
(1) Wholesale stranded cost means any legitimate, prudent and
verifiable cost incurred by a public utility or a transmitting utility
to provide service to:
(i) A wholesale requirements customer that subsequently becomes, in
whole or in part, an unbundled wholesale transmission services customer
of such public utility or transmitting utility; or
(ii) A retail customer, or a newly created wholesale power sales
customer, that subsequently becomes, in whole or in part, an unbundled
wholesale transmission services customer of such public utility or
transmitting utility.
(2) Wholesale requirements customer means a customer for whom a
public utility or transmitting utility provides by contract any portion
of its bundled wholesale power requirements.
(3) Wholesale transmission services has the same meaning as
provided in section 3(24) of the Federal Power Act (FPA): The
transmission of electric energy sold, or to be sold, at wholesale in
interstate commerce.
(4) Wholesale requirements contract means a contract under which a
public utility or transmitting utility provides any portion of a
customer's bundled wholesale power requirements.
(5) Retail stranded cost means any legitimate, prudent and
verifiable cost incurred by a public utility or transmitting utility to
provide service to a retail customer that subsequently becomes, in
whole or in part, an unbundled retail transmission services customer of
that public utility or transmitting utility.
(6) Retail transmission services means the transmission of electric
energy sold, or to be sold, in interstate commerce directly to a retail
customer.
(7) New wholesale requirements contract means any wholesale
requirements contract executed after July 11, 1994, or extended or
renegotiated to be effective after July 11, 1994.
(8) Existing wholesale requirements contract means any wholesale
requirements contract executed on or before July 11, 1994.
(c) Recovery of wholesale stranded costs.
(1) General requirement. A public utility or transmitting utility
will be allowed to seek recovery of wholesale stranded costs only as
follows:
(i) No public utility or transmitting utility may seek recovery of
wholesale stranded costs if such recovery is explicitly prohibited by a
contract or settlement agreement, or by any power sales or transmission
rate schedule or tariff.
(ii) No public utility or transmitting utility may seek recovery of
stranded costs associated with a new wholesale requirements contract if
such contract does not contain an exit fee or other explicit stranded
cost provision.
(iii) If wholesale stranded costs are associated with a new
wholesale requirements contract containing an exit fee or other
explicit stranded cost provision, and the seller under the contract is
a public utility, the public utility may seek recovery of such costs,
in accordance with the contract, through rates for electric energy
under sections 205-206 of the FPA. The public utility may not seek
recovery of such costs through any transmission rate for FPA section
205 or 211 transmission services.
(iv) If wholesale stranded costs are associated with a new
wholesale requirements contract, and the seller under the contract is a
transmitting utility but not also a public utility, the transmitting
utility may not seek an order from the Commission allowing recovery of
such costs.
(v) If wholesale stranded costs are associated with an existing
wholesale requirements contract, if the seller under such contract is a
public utility, and if the contract does not contain an exit fee or
other explicit stranded cost provision, the public utility may seek
recovery of stranded costs only as follows:
(A) If either party to the contract seeks a stranded cost amendment
pursuant to a section 205 or section 206 filing under the FPA made
prior to the expiration of the contract, and the Commission accepts or
approves an amendment permitting recovery of stranded costs, the public
utility may seek recovery of such costs through FPA section 205-206
rates for electric energy.
(B) If the contract is not amended to permit recovery of stranded
costs as described in paragraph (c)(1)(v)(A) of this section, the
public utility may file a proposal, prior to the expiration of the
contract, to recover stranded costs through FPA section 205-206 or
section 211-212 rates for wholesale transmission services to the
customer.
(vi) If wholesale stranded costs are associated with an existing
wholesale requirements contract, if the seller under such contract is a
transmitting
[[Page 21693]]
utility but not also a public utility, and if the contract does not
contain an exit fee or other explicit stranded cost provision, the
transmitting utility may seek recovery of stranded costs through FPA
section 211-212 transmission rates.
(vii) If a retail customer becomes a legitimate wholesale
transmission customer of a public utility or transmitting utility,
e.g., through municipalization, and costs are stranded as a result of
the retail-turned-wholesale customer's access to wholesale
transmission, the utility may seek recovery of such costs through FPA
section 205-206 or section 211-212 rates for wholesale transmission
services to that customer.
(2) Evidentiary demonstration for wholesale stranded cost recovery.
A public utility or transmitting utility seeking to recover wholesale
stranded costs in accordance with paragraphs (c)(1)(v)-(vii) of this
section must demonstrate that:
(i) It incurred stranded costs on behalf of its wholesale
requirements customer or retail customer based on a reasonable
expectation that the utility would continue to serve the customer;
(ii) The stranded costs are not more than the customer would have
contributed to the utility had the customer remained a wholesale
requirements customer of the utility, or, in the case of a retail-
turned-wholesale customer, had the customer remained a retail customer
of utility; and
(iii) The stranded costs are derived using the following formula:
Stranded Cost Obligation = (Revenue Stream Estimate-Competitive Market
Value Estimate) x Length of Obligation (reasonable expectation period).
(3) Rebuttable presumption. If a public utility or transmitting
utility seeks recovery of wholesale stranded costs associated with an
existing wholesale requirements contract, as permitted in paragraph
(c)(1) of this section, and the existing wholesale requirements
contract contains a notice provision, there will be a rebuttable
presumption that the utility had no reasonable expectation of
continuing to serve the customer beyond the term of the notice
provision.
(4) Procedure for customer to obtain stranded cost estimate. A
customer under an existing wholesale requirements contract with a
public utility seller may obtain from the seller an estimate of the
customer's stranded cost obligation if it were to leave the public
utility's generation supply system by filing with the public utility a
request for an estimate at any time prior to the termination date
specified in its contract.
(i) The public utility must provide a response within 30 days of
receiving the request. The response must include:
(A) An estimate of the customer's stranded cost obligation based on
the formula in paragraph (c)(2)(iii) of this section;
(B) Supporting detail indicating how each element in the formula
was derived;
(C) A detailed rationale justifying the basis for the utility's
reasonable expectation of continuing to serve the customer beyond the
termination date in the contract;
(D) An estimate of the amount of released capacity and associated
energy that would result from the customer's departure; and
(E) The utility's proposal for any contract amendment needed to
implement the customer's payment of stranded costs.
(ii) If the customer disagrees with the utility's response, it must
respond to the utility within 30 days explaining why it disagrees. If
the parties cannot work out a mutually agreeable resolution, they may
exercise their rights to Commission resolution under the FPA.
(5) A customer must be given the option to market or broker a
portion or all of the capacity and energy associated with any stranded
costs claimed by the public utility.
(i) To exercise the option, the customer must so notify the utility
in writing no later than 30 days after the public utility files its
estimate of stranded costs for the customer with the Commission.
(A) Before marketing or brokering can begin, the utility and
customer must execute an agreement identifying, at a minimum, the
amount and the price of capacity and associated energy the customer is
entitled to schedule, and the duration of the customer's marketing or
brokering of such capacity and energy.
(ii) If agreement over marketing or brokering cannot be reached,
and the parties seek Commission resolution of disputed issues, upon
issuance of a Commission order resolving the disputed issues, the
customer may reevaluate its decision in paragraph (c)(5)(i) of this
section to exercise the marketing or brokering option. The customer
must notify the utility in writing within 30 days of issuance of the
Commission's order resolving the disputed issues whether the customer
will market or broker a portion or all of the capacity and energy
associated with stranded costs allowed by the Commission.
(iii) If a customer undertakes the brokering option, and the
customer's brokering efforts fail to produce a buyer within 60 days of
the date of the brokering agreement entered into between the customer
and the utility, the customer shall relinquish all rights to broker the
released capacity and associated energy and will pay stranded costs as
determined by the formula in paragraph (c)(2)(iii) of this section.
(d) Recovery of retail stranded costs.
(1) General requirement. A public utility may seek to recover
retail stranded costs through rates for retail transmission services
only if the state regulatory authority does not have authority under
state law to address stranded costs at the time the retail wheeling is
required.
(2) Evidentiary demonstration necessary for retail stranded cost
recovery. A public utility seeking to recover retail stranded costs in
accordance with paragraph (d)(1) of this section must demonstrate that:
(i) It incurred stranded costs on behalf of a retail customer that
obtains retail wheeling based on a reasonable expectation that the
utility would continue to serve the customer; and
(ii) The stranded costs are not more than the customer would have
contributed to the utility had the customer remained a retail customer
of the utility.
Sec. 35.27 Power sales at market-based rates.
(a) Notwithstanding any other requirements, any public utility
seeking authorization to engage in sales for resale of electric energy
at market-based rates shall not be required to demonstrate any lack of
market power in generation with respect to sales from capacity for
which construction has commenced on or after July 9, 1996.
(b) Nothing in this part
(1) Shall be construed as preempting or affecting any jurisdiction
a state commission or other state authority may have under applicable
state and federal law, or
(2) Limits the authority of a state commission in accordance with
state and federal law to establish
(i) Competitive procedures for the acquisition of electric energy,
including demand-side management, purchased at wholesale, or
(ii) Non-discriminatory fees for the distribution of such electric
energy to retail consumers for purposes established in accordance with
state law.
Sec. 35.28 Non-discriminatory open access transmission tariff.
(a) Applicability. This section applies to any public utility that
owns, controls or operates facilities used for the transmission of
electric energy in
[[Page 21694]]
interstate commerce and to any non-public utility that seeks voluntary
compliance with jurisdictional transmission tariff reciprocity
conditions.
(b) Definitions.
(1) Requirements service agreement means a contract or rate
schedule under which a public utility provides any portion of a
customer's bundled wholesale power requirements.
(2) Economy energy coordination agreement means a contract, or
service schedule thereunder, that provides for trading of electric
energy on an ``if, as and when available'' basis, but does not require
either the seller or the buyer to engage in a particular transaction.
(3) Non-economy energy coordination agreement means any non-
requirements service agreement, except an economy energy coordination
agreement as defined in paragraph (b)(2) of this section.
(c) Non-discriminatory open access transmission tariffs.
(1) Every public utility that owns, controls or operates facilities
used for the transmission of electric energy in interstate commerce
must have on file with the Commission a tariff of general applicability
for transmission services, including ancillary services, over such
facilities. Such tariff must be the open access pro forma tariff
contained in Order No. 888, FERC Stats. & Regs. para. 31,036 (Final
Rule on Open Access and Stranded Costs) or such other open access
tariff as may be approved by the Commission consistent with Order No.
888, FERC Stats. & Regs. para. 31,036.
(i) Subject to the exceptions in paragraphs (c)(1)(ii),
(c)(1)(iii), and (c)(1)(iv) of this section, the pro forma tariff
contained in Order No. 888, FERC Stats. & Regs. para. 31,036, and
accompanying rates, must be filed no later than 60 days prior to the
date on which a public utility would engage in a sale of electric
energy at wholesale in interstate commerce or in the transmission of
electric energy in interstate commerce.
(ii) If a public utility owns, controls or operates facilities used
for the transmission of electric energy in interstate commerce as of
July 9, 1996, it must file the pro forma tariff contained in Order No.
888, FERC Stats. & Regs. para. 31,036, pursuant to section 206 of the
FPA and accompanying rates pursuant to section 205 of the FPA, no later
than July 9, 1996. However, if a public utility has already filed, or
has on file, an open access tariff and accompanying rates as of April
24, 1996, it may, but is not required to, file new rates with its
section 206 pro forma tariff filing.
(iii) If a public utility owns, controls or operates transmission
facilities used for the transmission of electric energy in interstate
commerce as of July 9, 1996, such facilities are jointly owned with a
non-public utility, and the joint ownership contract prohibits
transmission service over the facilities to third parties, the public
utility with respect to access over the public utility's share of the
jointly owned facilities must file no later than December 31, 1996 the
pro forma tariff contained in Order No. 888, FERC Stats. & Regs. para.
31,036, pursuant to section 206 of the FPA and accompanying rates
pursuant to section 205 of the FPA.
(iv) If a public utility obtains a waiver of the tariff requirement
pursuant to paragraph (d) of this section, it does not need to file the
pro forma tariff required by this section.
(v) Any public utility that seeks a deviation from the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. para. 31,036,
must demonstrate that the deviation is consistent with the principles
of Order No. 888, FERC Stats. & Regs. para. 31,036.
(2) Every public utility that owns, controls or operates facilities
used for the transmission of electric energy in interstate commerce,
and that uses those facilities to engage in wholesale sales and/or
purchases of electric energy, or unbundled retail sales of electric
energy, must take transmission service for such sales and/or purchases
under the open access tariff filed pursuant to this section.
(i) Subject to the exceptions in paragraphs (c)(2)(ii) and
(c)(3)(iv) of this section, this requirement is effective on the date
that such public utility engages in a wholesale sale or purchase of
electric energy or any unbundled retail sale of electric energy, but no
earlier than July 9, 1996.
(ii) For sales of electric energy pursuant to a requirements
service agreement executed on or before July 9, 1996, this requirement
will not apply unless separately ordered by the Commission. For sales
of electric energy pursuant to a bilateral economy energy coordination
agreement executed on or before July 9, 1996, this requirement is
effective on December 31, 1996. For sales of electric energy pursuant
to a bilateral non-economy energy coordination agreement executed on or
before July 9, 1996, this requirement will not apply unless separately
ordered by the Commission.
(3) Every public utility that owns, controls or operates facilities
used for the transmission of electric energy in interstate commerce,
and that is a member of a power pool, public utility holding company,
or other multi-lateral trading arrangement or agreement that contains
transmission rates, terms or conditions, must file a joint pool-wide or
system-wide open access transmission pro forma tariff.
(i) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed after July 9, 1996,
this requirement is effective on the date that transactions begin under
the arrangement or agreement.
(ii) For any public utility holding company arrangement or
agreement that contains transmission rates, terms or conditions and
that is executed on or before July 9, 1996, this requirement is
effective July 9, 1996, except for the Central and South West System,
which must comply no later than December 31, 1996.
(iii) For any power pool or multi-lateral arrangement or agreement
other than a public utility holding company arrangement or agreement,
that contains transmission rates, terms or conditions and that is
executed prior to July 9, 1996, this requirement is effective on
December 31, 1996.
(iv) A public utility member of a power pool, public utility
holding company or other multi-lateral arrangement or agreement that
contains transmission rates, terms or conditions and that is executed
on or before July 9, 1996 must begin to take service under a joint
pool-wide or system-wide pro forma tariff for wholesale trades among
the pool or system members no later than December 31, 1996.
(d) Waivers. A public utility subject to the requirements of this
section and Order No. 889, FERC Stats. & Regs. para. 31,037 (Final Rule
on Open Access Same-Time Information System and Standards of Conduct)
may file a request for waiver of all or part of the requirements of
this section, or Part 37 (Open Access Same-Time Information System and
Standards of Conduct for Public Utilities), for good cause shown. An
application for waiver must be filed either:
(i) No later than July 9, 1996 or
(ii) No later than 60 days prior to the time the public utility
would otherwise have to comply with the requirement.
(e) Non-public utility procedures for tariff reciprocity
compliance.
(1) A non-public utility may submit a transmission tariff and a
request for declaratory order that its voluntary transmission tariff
meets the requirements of Order No. 888 (Final Rule on Open Access and
Stranded Costs).
[[Page 21695]]
(i) Any submittal and request for declaratory order submitted by a
non-public utility will be provided an NJ (non-jurisdictional) docket
designation.
(ii) If the submittal is found to be an acceptable transmission
tariff, an applicant in a Federal Power Act (FPA) section 211 case
against the non-public utility shall have the burden of proof to show
why service under the open access tariff is not sufficient and why a
section 211 order should be granted.
(2) A non-public utility may file a request for waiver of all or
part of the reciprocity conditions contained in a public utility open
access tariff, for good cause shown. An application for waiver may be
filed at any time.
PART 385--RULES OF PRACTICE AND PROCEDURE
1. The authority citation for part 385 continues to read as
follows:
Authority: 5 U.S.C. 551-557; 15 U.S.C. 717-717z, 3301-3432; 16
U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 49
U.S.C. 60502; 49 App. U.S.C. 1-85.
2. Part 385 is amended by adding paragraph (b)(5) to Sec. 385.2011
to read as follows:
Sec. 385.2011 Procedures for filing on electronic media (Rule 2011).
* * * * *
(b) * * *
(5) Non-discriminatory open access transmission tariffs filed
pursuant to Sec. 35.28 of this chapter.
* * * * *
Note: Appendices A through H and statements of Commissioners
Hoecker and Massey will not be published in the Code of Federal
Regulations.
List of Section 211 Applications
----------------------------------------------------------------------------------------------------------------
No. Docket No. Applicant Transmitter Commission action
----------------------------------------------------------------------------------------------------------------
1 TX93-1-000 Tex-La Electric Texas Utilities Electric Denied, 64 FERC para.
Cooperative of Texas, Company. 61,162.
Inc.
2 TX93-2-000 City of Bedford, American Electric Power Granted. Final order, 68
Virginia, et al. Company, Inc. FERC para. 61,003.
Reh'g denied, 73 FERC
para. 61,322.
3 TX93-3-000 Wisconsin Electric Power Upper Peninsula Power Withdrawn 9/10/93.
Company. Company.
4 TX93-4-000 Florida Municipal Power Florida Power & Light Granted. Final order, 67
Agency. Company. FERC para. 61,167.
Order on reh'g, 74 FERC
para. 61,006.
5 TX94-1-000 Minnesota Municipal Power Northern States Power Granted. Proposed order,
Agency. Company. 66 FERC para. 61,114.
Reh'g denied, 66 FERC
para. 61,323 Settlement
accepted by letter
order, 68 FERC para.
61,031.
6 TX94-2-000 El Paso Electric Company, Southwestern Public Proposed order, 68 FERC
et al. Service Company. para. 61,182; order on
reh'g, 68 FERC para.
61,399; order dismiss'g
proceeding, 72 FERC
para. 61,292.
7 TX94-3-000 Minnesota Municipal Power Southern Minnesota Granted. Proposed order,
Agency. Municipal Power Agency. 66 FERC para. 61,223;
reh'g denied, 67 FERC
para. 61,075; Final
order, 68 FERC para.
61,060.
8 TX94-4-000 Tex-La Electric Texas Utilities Electric Granted. Proposed order,
Cooperative of Texas, Company. 67 FERC para. 61,019;
Inc. Final order, 69 FERC
para. 61,269.
9 TX94-5-000 Old Dominion Electric Delmarva Power & Light Granted. Proposed order,
Cooperative, Inc. Company. 68 FERC para. 61,169.
Settl'd, 69 FERC para.
61,436, 70 FERC para.
61,082.
10 TX94-6-000 Reading Municipal Light 16 New England Terminated July 10, 1995
Department. Transmitting Utilities. by OEPR Letter Order,
following notice of
withdrawal filed May 8,
1995.
11 TX94-7-000 AES Power, Inc........... Tennessee Valley Granted. Final Order
Authority. issued Feb. 29, 1996,
74 FERC para. 61,220,
reh'g pending.
12 TX94-8-000 Duquesne Light Company... PJM Companies........... Granted. Proposed order
issued 5/16/95, 71 FERC
para. 61,155.
13 TX94-9-000 Borough of Zelienople, Pennsylvania Power Granted. Proposed order
Pennsylvania. Company. issued 1/25/95, 70 FERC
para. 61,073.
14 TX94-10-000 Duquesne Light Company... Allegheny Power System.. Granted. Proposed order
issued 5/16/95, 71 FERC
para. 61,156.
15 TX95-1-000 Enron Power Marketing, Consolidated Edison Co. Pending. Comments due 11/
Inc. of New York. 3/94.
16 TX95-2-000 Wisconsin Public Power WEPCO, WP&L, WPSC....... Pending. Comments due 11/
Inc. SYSTEM. 16/94.
17 TX95-3-000 Municipal Energy Agency Nebraska Public Power w/drawn 11-16-95
of Nebraska. District and Tri-State
Generation and
Transmission
Association, Inc.
18 TX95-4-000 American Municipal Power- Ohio Edison Company..... Granted. Proposed Order
Ohio, Inc. issued Feb. 1, 1996 74
FERC para. 61,086.
19 TX95-5-000 United States Department Southern Company System. Pending.
of Energy--Southeastern
Power Administration.
20 TX95-6-000 Cleveland Public Power... Centerior Energy Rejected Without
Corporation. Prejudice 72 FERC para.
61,189.
21 TX95-7-000 Cleveland Public Power... Cleveland Electric Pending.
Illuminating Company
and Toledo Edison
Company.
22 TX96-1-000 Citizens Utilities Swanton Village, Vermont Pending.
Company.
[[Page 21696]]
23 TX96-2-000 City of College Station, City of Bryan, Texas and Pending.
Texas. Texas Municipal Power
Agency.
24 TX96-3-000 Citizens Utilities Swanton Village, Vermont Pending.
Company.
25 TX96-4-000 Suffolk County Electrical Long Island Lighting Pending.
Agency. Company.
26 TX96-5-000 United States Department Public Service Company Pending.
of Energy--Western Area of New Mexico.
Power Administration.
27 TX96-6-000 Montana Power Company.... Basin Electric Pending.
Cooperative.
28 TX96-7-000 City of Palm Springs, Southern California Pending.
California. Edison Company.
----------------------------------------------------------------------------------------------------------------
Appendix B--List of Commenters
------------------------------------------------------------------------
Abbreviation Commenter
------------------------------------------------------------------------
1. ABATE.......................... Association of Businesses Advocating
Tariff Equity.
2. AEC & SMEPA.................... Alabama Electric Cooperative, Inc.
and South Mississippi Electric
Power Association.
3. AEP............................ American Electric Power System.
4. AGA............................ American Gas Association.
5. Air Liquide.................... Air Liquide America Corporation.
6. AL Com......................... Alabama Public Service Commission.
7. ALCOA.......................... Aluminum Company of America.
8. Allegheny...................... Allegheny Power Service Corporation.
9. Alma........................... City of Alma, Michigan.
10. Aluminum...................... Aluminum Association.
11. American Forest & Paper....... American Forest & Paper Association.
12. American Iron & Steel......... American Iron & Steel Institute
American Forest & Paper
Association, American Public Power
Association, Chemical Manufacturers
Association, Citizen Action,
Council of Industrial Boiler
Owners, Electricity Consumers
Resource Council, Environmental
Action Foundation, City of Las
Cruces, New Mexico, City of
Westbrook, Maine, Sovereign
California Cities Joint Powers
Committee, Toward Utility Rate
Normalization.
13. American National Power....... American National Power, Inc.
14. American Wind................. American Wind Energy Association.
15. AMP-Ohio...................... American Municipal Power-Ohio, Inc.
and Indiana Municipal Power Agency.
16. Anaheim....................... Cities of Anaheim, Azusa, Banning,
Colton and Riverside, California.
17. Anchorage..................... Anchorage Municipal Light and Power.
18. Anoka EC...................... Anoka Electric Cooperative.
19. APPA.......................... American Public Power Association.
20. APS Customers................. APS Wholesale Customer Group (Aquila
Irrigation District, Buckeye Water
Conservation District, Electrical
District No. 3 of Pinal County,
Electrical District No. 6 of Pinal
County, Electrical District No. 7
of Maricopa County, Electrical
District No. 8 of Maricopa County,
Harquahala Valley Power District,
Maricopa County Municipal Water
Conservation District No. 1,
McMullan Valley Water Conservation
District, Roosevelt Irrigation
District and Tonopah Irrigation
District).
21. Arcadia....................... Arcadia Resources, Inc.
22. Arizona....................... Arizona Pub
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
lic Service Company.
23. Arizona EC.................... Arizona Electric Power Cooperative.
24. Ark Elec...................... Arkansas Electric Cooperative
Corporation.
25. Arkansas Cities............... Arkansas Cities and Farmers Electric
Cooperative.
26. Associated EC................. Associated Electric Cooperative,
Inc.
27. Associated Power.............. Associated Power Services, Inc.
28. Atlantic City................. Atlantic City Electric Company.
29. AZ Com........................ Arizona Corporation Commission.
30. Baker EC...................... Baker Electric Cooperative, Inc.
31. Baltimore Transp Bureau....... Transportation Bureau of Baltimore,
Inc.
32. Basin EC...................... Basin Electric Power Cooperative.
33. BG&E.......................... Baltimore Gas and Electric Company.
34. Big Horn REC.................. Big Horn Rural Electric Company.
35. Big Rivers EC................. Big Rivers Electric Cooperative.
36. Black Hills EC................ Black Hills Electric Cooperative.
37. Black Mayors.................. National Conference of Black Mayors.
38. Blue Ridge.................... Blue Ridge Power Agency, Northeast
Texas Electric Cooperative, Inc.,
Sam Rayburn G&T Electric
Cooperative, Inc., and Tex-La
Electric Cooperative of Texas, Inc.
39. Bon Homme Yankton EC.......... Bon Homme Yankton Electric
Association, Inc.
40. Boston Edison................. Boston Edison Company.
41. Boulder....................... City of Boulder, Colorado.
42. BPA........................... Bonneville Power Administration.
43. Brazos........................ Brazos Electric Power Cooperative,
Inc.
44. Brownsville................... Brownsville, Texas Public Utilities
Board.
45. Building Owners............... Building Owners and Managers
Association International.
46. CA Cogen...................... Cogeneration Association of
California.
47. CA Com........................ California Public Utilities
Commission.
[[Page 21697]]
48. CA Energy Co.................. California Energy Company, Inc.
49. CA Energy Com................. California Energy Commission.
50. Cajun......................... Cajun Electric Power Cooperative,
Inc.
51. California DWR................ California Department of Water
Resources.
52. California Water Agencies..... Association of California Water
Agencies.
53. Calpine....................... Calpine Corporation.
54. CAMU.......................... Colorado Association of Municipal
Utilities.
55. Canada........................ Canadian Embassy.
56. Canadian Petroleum Producers.. Canadian Association of Petroleum
Producers.
57. Caparo........................ Caparo Steel.
58. Carbon Power.................. Carbon Power & Light Inc.
59. Carolina P&L.................. Carolina Power & Light Company.
60. CCEM.......................... Coalition for a Competitive Electric
Market (consisting of Catex Vitol
Electric, Inc., Coastal Electric
Services Company, Destec Power
Services, Inc., Electric
Clearinghouse, Inc., Enron Power
Marketing, Inc., Equitable Power
Services Company, KCS Power
Marketing, Inc. and MidCon Power
Services Corp.).
61. Centerior..................... Centerior Energy Corporation.
62. Central EC.................... Central Electric Power Cooperative.
63. Central Hudson................ Central Hudson Gas & Electric
Corporation.
64. Central Illinois Light........ Central Illinois Light Company.
65. Central Illinois Public Central Illinois Public Service
Service. Company.
66. Central Louisiana............. Central Louisiana Electric Company,
Inc.
67. Central Montana EC............ Central Montana Electric Power
Cooperative, Inc.
68. Christensen................... Laurits R. Christensen Associates
Inc.
69. Chugach....................... Chugach Electric Association, Inc.
70. CINergy....................... CINergy Corp.
71. Citizens Lehman............... Citizens Lehman Power L.P.
72. Citizens Utilities............ Citizens Utilities Company.
73. Clark......................... Clark Public Utilities.
74. Clean Air..................... Clean Air Action Corporation.
75. Cleveland..................... Cleveland Public Power.
76. CO Com........................ Colorado Public Utilities Commission
Staff.
77. CO Consumers Counsel.......... Colorado Office of Consumer Counsel.
78. Coalition for Economic Coalition for Economic Competition
Competition. (consisting of Central Hudson Gas &
Electric Corporation, Central Maine
Power Company, Consolidated Edison
Company of New York, Inc., Illinois
Power Company, Long Island Lighting
Company, New York State Electric &
Gas Corporation, Niagara Mohawk
Power Corporation, Orange and
Rockland Utilities, Inc., and
Rochester Gas and Electric
Corporation.
79. Coalition on Federal-State Coalition on Federal-State Issues of
Issues. the Power Marketing Association.
80. Com Ed........................ Commonwealth Edison Company.
81. Com Electric.................. Commonwealth Electric Company.
82. Competitive Enterprise........ Competitive Enterprise Institute.
83. Concord....................... Concord Municipal Light Plant.
84. ConEd......................... Consolidated Edison Company of New
York, Inc.
85. Conservation Law Foundation... Conservation Law Foundation and
Center for Efficiency and Renewable
Technologies.
86. Consolidated Natural Gas...... Consolidated Natural Gas Company.
87. Consumers Power............... Consumers Power Company.
88. Continental Power Exchange.... Continental Power Exchange, Inc.
89. Cooperative Power............. Cooperative Power.
90. CSW........................... Central and South West Corporation.
91. CT DPUC....................... Connecticut Department of Public
Utility Control.
92. CT Munis...................... Connecticut Conference of
Municipalities.
93. CVPSC......................... Central Vermont Public Service
Corporation.
94. Dairyland..................... Dairyland Power Cooperative.
95. Dayton P&L.................... Dayton Power and Light Company.
96. DC Com........................ Public Service Commission of the
District of Columbia.
97. DE Muni....................... Delaware Municipal Electric
Corporation, Inc.
98. DE, DC, NJ and MD Coms........ Delaware Public Service Commission,
District of Columbia Public Service
Commission, Maryland Public Service
Commission, and New Jersey Board of
Public Utilities.
99. Deloitte & Touche............. Deloitte & Touche LLP.
100. Destec....................... Destec Energy.
101. Detroit Edison............... Detroit Edison Company.
102. Detroit Edison............... Detroit Edison Wholesale Customers
(consisting of City of Croswell,
Michigan, and Thumb Electric
Cooperative).
103. Direct Service Industries.... Direct Service Industries
(consisting of ELF Atochem North
America, Inc., Columbia Columbia
Aluminum Corporation, Columbia
Falls Aluminum Co., Georgia
Pacific, Kaiser Aluminum & Chemical
Corporation, Intalco Aluminum,
Northwest Aluminum Company,
Reynolds Metals Company and
Vanalco, Inc.).
104. DOD.......................... Department of Defense.
105. DOE.......................... United States Department of Energy.
106. DOJ.......................... United States Department of Justice.
107. Dominion..................... Dominion Resources.
108. Douglas EC................... Douglas Electric Cooperative, Inc.
109. Duke......................... Duke Power Company.
[[Page 21698]]
110. Duquesne..................... Duquesne Light Company.
111. East Kentucky................ East Kentucky Power Cooperative, Big
Rivers Electric Corporation, and
Hoosier Energy Rural Electric
Cooperative.
112. East River EC................ East River Electric Power
Cooperative.
113. EDS Utilities................ Electronic Data Systems Inc.,
Utilities Division (Joussef Heguzy,
Clifford J. Meagh, Julius A.
Wright).
114. Education.................... American Council on Education and
the National Association of College
and University Business Officers
115............................... EEI Edison Electric Institute.
116. EGA.......................... Electric Generation Association.
117. El Paso...................... El Paso Electric Company.
118. ELCON........................ Electricity Consumers Resource
Council, American Iron and Steel
Institute, Chemical Manufacturers
Association and Council of
Industrial Boiler Owners.
119. Electric Consumers Alliance.. Electric Consumers' Alliance.
120. Electronic Data Systems...... EDS Utilities Division (James F.
Susman).
121. ENEREX....................... ENEREX, Inc.
122. Entergy...................... Entergy Services, Inc.
123. Entergy Retail Regulators.... Arkansas Public Service Commission,
City Council of New Orleans,
Louisiana Public Service
Commission, and Mississippi Public
Service Commission.
124. Environmental Action......... Environmental Action Foundation.
125. EPA.......................... United States Environmental
Protection Agency.
126. Fertilizer Institute......... The Fertilizer Institute.
127. FL Com....................... Florida Public Service Commission.
128. Florida Power Corp........... Florida Power Corporation.
129. FPL.......................... Florida Power & Light Company.
130. Freedom Energy Co............ Freedom Energy Company, LLC.
131. FTC.......................... United States Federal Trade
Commission, Staff of the Bureau of
Economics.
132. Fuel Managers................ Fuel Managers Association.
133. GA Com....................... Georgia Public Service Commission.
134. GAPP Committee............... General Agreement of Parallel Paths
Committee (A. Garfield).
135. Graves....................... Graves, Frank and Ilic, Marija.
136. Green Mountain............... Green Mountain Power Corporation.
137. Heartland.................... Heartland Consumers Power District.
138. Hogan........................ Hogan, William W.
139. Home Builders................ National Association of Home
Builders.
140. Homelessness Alliance........ National Alliance to End
Homelessness, Inc.
141. Hoosier EC................... Hoosier Energy Rural Electric
Cooperative.
142. Hopkinsville EC.............. Hopkinsville Electric System.
143. Houston L&P.................. Houston Lighting & Power Company.
144. Hydro-Quebec................. Hydro-Quebec.
145. IA Com....................... Iowa Utilities Board.
146. IBM.......................... International Business Machines.
147. ID Com....................... Idaho Public Utilities Commission.
148. Ida County REC............... Ida County Rural Electric
Cooperative.
149. Idaho........................ Idaho Power Company.
150. IES Utilities................ IES Utilities Inc.
151. IL Com....................... Illinois Commerce Commission.
152. IL Industrials............... Illinois Industrial Energy
Consumers.
153. Illinois Municipal Electric Illinois Municipal Electric Agency.
Agency.
154. Illinois Power............... Illinois Power Company.
155. IN Com....................... Indiana Utility Regulatory
Commission.
156. IN Industrials............... Indiana Industrial Energy Consumers,
Inc.
157. Industrial Energy Industrial Energy Applications.
Applications.
158. Inland Power Pool............ Inland Power Pool.
159. IPALCO....................... IPALCO Enterprises, Inc.
160. James Valley EC.............. James Valley Electric Cooperative,
Inc.
161. Jay.......................... Town of Jay, Maine and the Jay Power
District.
162. KCPL......................... Kansas City Power & Light Company.
163. Knoxville.................... Knoxville Utilities Board.
164. KS Com....................... Kansas Corporation Commission Staff.
165. KU........................... Kentucky Utilities Company.
166. KY AG........................ Kentucky Attorney General.
167. KY Com....................... Kentucky Public Service Commission.
168. LA DWP....................... Department of Water and Power of the
City of Los Angeles.
169. LA Industrials............... Louisiana Energy Users Group.
170. La Raza...................... National Council of La Raza.
171. Las Cruces................... City of Las Cruces, New Mexico.
172. Latin League................. League of United Latin American
Citizens.
173. Legal Environmental Legal Environmental Assistance
Assistance. Foundation.
174. LEPA......................... Louisiana Energy and Power
Authority.
175. Lester Fink.................. Fink, Lester.
176. LG&E......................... LG&E Energy Corp.
177. LILCO........................ Long Island Lighting Company.
178. Lincoln-Union EC............. Lincoln-Union Electric Company.
[[Page 21699]]
179. Lively....................... Lively, Mark B.
180. Local Furnishing Utilities... Local Furnishing Utilities (Long
Island Lighting Company, Nevada
Power Company, and San Diego Gas &
Electric Company).
181. Lower Colorado River Lower Colorado River Authority.
Authority.
182. LPPC......................... Large Public Power Council.
183. MA DPU....................... Massachusetts Department of Public
Utilities.
184. Madison G&E.................. Madison Gas & Electric Company.
185. Maine Public Service......... Maine Public Service Company.
186. Maritime..................... Maritime Electric Company.
187. McKenzie EC.................. McKenzie Electric Cooperative, Inc.
188. MD Com....................... Maryland Public Service Commission.
189. ME Consumer-Owned Utilities.. Maine Consumer-Owned Utilities
(consisting of Eastern Maine
Electric Cooperative, Inc., Fox
Islands Electric Cooperative, Inc.
Houlton Water Company, Isle au Haut
Electric Power Co., Kennebunk Light
& Power District, Madison Electric
Works, Swans Island Electric
Cooperative, Inc., and Van Buren
Light & Power District).
190. ME Industrials............... Industrial Energy Consumer Group of
Maine.
191. MEAG......................... Municipal Electric Authority of
Georgia.
192. Memphis...................... Memphis Light, Gas and Water
Division.
193. Mercer....................... Mercer, Dorothy Ph.D.
194. MI Com....................... Michigan Public Service Commission.
195. MI MEA....................... Municipal Energy Agency of
Mississippi.
196. Michigan Coalition........... Consumers Power, Detroit Edison and
Michigan Public Service Commission.
197. Michigan Systems............. Florida Municipal Power Agency,
Michigan Public Power Agency,
Michigan South Central Power
Agency, Michigan Public Power
Ratepayers Association and
Wolverine Power Supply Cooperative.
198. MidAmerican.................. MidAmerican Energy Company.
199. Midwest Commissions.......... Arkansas, Kansas & Missouri State
Commissions.
200. Minnesota P&L................ Minnesota Power & Light Company.
201. Missouri Basin Group......... Missouri Basin Systems Group, Inc.
202. Missouri Basin MPA........... Missouri Basin Municipal Power
Agency.
203. Missouri Joint Commission.... Missouri Joint Municipal Electric
Utilities Commission.
204. Missouri-Kansas Industrials.. Missouri-Kansas Industrial Energy
Consumers.
205. MMWEC........................ Massachusetts Municipal Wholesale
Electric Company.
206. MN DPS....................... Minnesota Department of Public
Service.
207. Montana Power................ Montana Power Company.
208. Montana-Dakota Utilities..... Montana-Dakota Utilities Company.
209. Montaup...................... Montaup Electric Company.
210. Mor-Gran-Sou EC.............. Mor-Gran-Sou Electric Cooperative.
211. Mountain States Petroleum Independent Petroleum Association of
Assoc. Mountain States and Colorado Oil
and Gas Association.
212. MS Com....................... Mississippi Public Service
Commission.
213. MT Com....................... Montana Public Service Commission.
214. MT Dept of Environmental Montana Department of Environmental
Quality. Quality.
215. Mt. Hope Hydro............... Mt. Hope Hydro, Inc.
216. Municipal Energy Agency Municipal Energy Agency of Nebraska.
Nebraska.
217. NARUC........................ National Association of Regulatory
Utility Commissioners.
218. NASUCA....................... National Association of State
Utility Consumer Advocates.
219. National Hydropower.......... National Hydropower Association.
220. National Women's Caucus...... National Women's Political Caucus.
221. Natural Resources Defense.... Natural Resources Defense Council
and Pacific Gas and Electric
Company.
222. NC Com....................... North Carolina Utilities Commission.
223. NCMPA........................ North Carolina Municipal Power
Agency Number 1.
224. NCPA......................... Northern California Power Agency.
225. ND Com....................... North Dakota Public Service
Commission.
226. NE Public Power District..... Nebraska Public Power District.
227. NE States Air Management..... Northeast States for Coordinated Air
Use Management.
228. NEPCO........................ New England Power Company.
229. NEPOOL....................... New England Power Pool Executive
Committee.
230. NEPOOL Review Committee...... New England Public Power NEPOOL
Review Committee.
231. NERC......................... North American Electric Reliability
Council.
232. Nevada....................... Nevada Power Company.
233. New Brunswick................ New Brunswick Power.
234. NGSA......................... Natural Gas Supply Association.
235. NH Com....................... New Hampshire Public Utilities
Commission.
236. NH General Court............. Retail Wheeling & Restructuring
Committee of the New Hampshire
General Court.
237. NIEP......................... National Independent Energy
Producers.
238. NIMO......................... Niagara Mohawk Power Corporation.
239. NIPSCO....................... Northern Indiana Public Service
Company.
240. NJ BPU....................... New Jersey Board of Public
Utilities.
241. NJ Ratepayer Advocate........ New Jersey Division of the Ratepayer
Advocate.
242. NM Com....................... New Mexico Public Utility
Commission.
243. NM Industrials............... New Mexico Industrial Energy
Consumers.
244. NorAm........................ NorAm Energy Services, Inc.
245. Nordhaus..................... Nordhaus, William D.
246. North Dakota RECs............ North Dakota Association of Rural
Electric Cooperatives.
[[Page 21700]]
247. NRECA........................ National Rural Electric Cooperative
Association.
248. NRECA/APPA................... National Rural Electric Cooperative
Association and APPA.
249. NRRI......................... National Regulatory Research
Institute.
250. NSP.......................... Northern States Power Company.
251. NU........................... Northeast Utilities System
Companies.
252. Nuclear Energy Institute..... Nuclear Energy Institute.
253. Nucor........................ Nucor Corporation.
254. NV Com....................... Public Service Commission of Nevada.
255. NW Conservation Act Coalition Northwest Conservation Act
Coalition.
256. NW Iowa Cooperative.......... Northwest Iowa Power Cooperative.
257. NW Power Planning Council.... Northwest Power Planning Council.
258. NWRTA........................ Northwest Regional Transmission
Association.
259. NY AG........................ New York State Attorney General.
260. NY Com....................... Public Service Commission of the
State of New York.
261. NY Consumer Protection....... New York Consumer Protection Board.
262. NY Energy Buyers............. New York Energy Buyers Forum.
263. NY Industrials............... Multiple Industrial Intervenors of
New York.
264. NY IOUs...................... Long Island Lighting, New York State
Electric & Gas and Rochester Gas &
Elec.
265. NY Mayors.................... New York State Conference of Mayors
and Municipal Officals.
266. NYMEX........................ New York Mercantile Exchange.
267. NYPP......................... New York Power Pool.
268. NYSEG........................ New York State Electric & Gas
Corporation.
269. Oahe EC...................... Oahe Electric Cooperative, Inc.
270. Oak Ridge.................... Oak Ridge National Laboratory.
271. Occidental Chemical.......... Occidental Chemical Corporation.
272. Oglethorpe................... Oglethorpe Power Corporation.
273. OH Com....................... Public Utilities Commission of Ohio.
274. OH Coops..................... Ohio Rural Electric Cooperatives,
Inc. and Buckeye Power, Inc.
275. OH Industrials............... Industrial Energy Users--Ohio.
276. Ohio Edison.................. Ohio Edison Company.
277. Ohio Manufacturers........... Ohio Manufacturers' Association.
278. Ohio Valley.................. Ohio Valley Electric Corporation.
279. OK Com....................... Oklahoma Corporation Commission.
280. Oklahoma G&E................. Oklahoma Gas and Electric Company.
281. Old Dominion EC.............. Old Dominion Electric Cooperative,
Inc.
282. Oliver-Mercer EC............. Oliver-Mercer Electric Cooperative,
Inc.
283. Omaha PPD.................... Omaha Public Power District.
284. Ontario Hydro................ Ontario Hydro.
285. Orange & Rockland............ Orange and Rockland Utilities, Inc.
286. Oregon Trail EC.............. Oregon Trail Electric Cooperative,
Inc.
287. Otter Tail................... Otter Tail Power Company.
288. PA Com....................... Pennsylvania Public Utility
Commission.
289. PA Coops..................... Pennsylvania Rural Electric
Association and Allegheny Electric
Cooperative, Inc.
290. PA Industrials............... Industrial Energy Consumers of
Pennsylvania.
291. PA Munis..................... Pennsylvania Municipal Electric
Association.
292. Pacific Northwest Coop....... Pacific Northwest Generating
Cooperative.
293. PacifiCorp................... PacifiCorp.
294. Panhandle Coop............... Panhandle Rural Electric Membership
Association.
295. PECO......................... PECO Energy Company.
296. Pennsylvania P&L............. Pennsylvania Power & Light Company.
297. PG&E......................... Pacific Gas and Electric Company.
298. Phelps Dodge................. Phelps Dodge Corporation.
299. Philip Morris................ Philip Morris Management Corp.
300. PJM.......................... PJM--Pennsylvania New Jersey
Maryland Interconnection.
301. Portland..................... Portland General Electric Company.
302. Power Marketing Association.. Power Marketing Association.
303. PSE&G........................ Public Service Electric and Gas
Company.
304. PSNM......................... Public Service Company of New
Mexico.
305. Public Generating Pool....... Public Generating Pool.
306. Public Power Council......... Public Power Council.
307. Public Service Co of CO...... Public Service Company of Colorado
and Cheyenne Light, Fuel and Power
Company.
308. Puget........................ Puget Sound Power & Light Company.
309. Redding...................... Cities of Redding and Santa Clara,
California.
310. Reynolds..................... Reynolds Metals Company.
311. Rochester G&E................ Rochester Gas and Electric
Corporation.
312. Rocky Mountain Institute..... Rocky Mountain Institute (Amory
Lovins).
313. Rosebud...................... Rosebud Enterprises, Inc.
314. RUS.......................... Rural Utilities Service (formerly
REA).
315. Rushmore EC.................. Rushmore Electric Power Cooperative,
Inc.
316. Salt River................... Salt River Project Agriculture
Improvement and Power District.
317. San Diego G&E................ San Diego Gas & Electric Company.
318. San Francisco................ City and County of San Francisco.
319. San Luis Valley REC.......... San Luis Valley Rural Electric
Cooperative.
320. SBA.......................... United States Small Business
Administration, Office of Advocacy.
[[Page 21701]]
321. SC Com....................... South Carolina Public Service
Commission.
322. SCE&G........................ South Carolina Electric & Gas
Company.
323. SC Public Service Authority.. South Carolina Public Service
Authority.
324. Seattle...................... Seattle City Light Department.
325. Seminole EC.................. Seminole Electric Cooperative, Inc.
326. SEPA......................... Southeastern Power Administration/
Federal Power Customers.
327. Shelby County................ Shelby County Board of
Commissioners.
328. Sierra....................... Sierra Pacific Power Company.
329. Slope EC..................... Slope Electric Cooperative Inc.
330. SMUD......................... Sacramento Municipal Utility
District.
331. Snohomish.................... Public Utility District No. 1 of
Snohomish County, Washington.
332. SoCal Edison................. Southern California Edison Company.
333. SoCal Gas.................... Southern California Gas Company.
334. South Jersey Gas............. South Jersey Gas Company.
335. Southern..................... Southern Company Services, Inc.
336. Southwest TDU Group.......... Southwest Transmission Dependent
Utility Group (consisting of Aguila
Irrigation District, Ak-Chin Indian
Community, Buckeye Irrigation
District, Central Arizona Water
Conservation District, Electrical
District No. 3, No. 4, No. 5, No.
6, No. 7, Harquahala Valley Power
District, Maricopa Water District,
McMullen Valley Water Conservation
and Drainage District, City of
Needles, Roosevelt Irrigation
District, City of Safford, Tonopah
Irrigation District, Wellton-Mohawk
Irrigation and Drainage District).
337. Southwestern................. Southwestern Public Service Company.
338. Soyland...................... Soyland Power Cooperative.
339. Spink EC..................... Spink Electric, Redfield, SD.
340. SPP.......................... Southwest Power Pool, Inc.
341. Springfield.................. City Utilities of Springfield,
Missouri.
342. St. Joseph................... St. Joseph Light & Power Company.
343. Suffolk County............... Suffolk County (New York) Electric
Agency.
344. Sunflower.................... Sunflower Electric Power
Corporation.
345. Supervised Housing........... State and City Supervised Housing
for Equity in Electric Rates.
346. Sustainable Energy Policy.... Project For Sustainable FERC Energy
Policy (on behalf of Alliance for
Affordable Energy, Citizens Action
Coalition of Indiana, Conservation
Law Foundation, Environmental
Defense Fund, Environmental Law &
Policy Center of the Midwest, Izaak
Walton League of America, Land and
Water Fund of the Rockies, Legal
Environmental Assistance
Foundation, Mid-Atlantic Energy
Project, Minnesotans for an Energy-
Efficient Economy, Natural
Resources Defense Council,
Northwest Conservation Act
Coalition, Pace Energy Project,
Public Citizen, Texas, RENEW
Wisconsin, Southern Environmental
Law Center, Texas Ratepayers'
Organization to Save Energy, Union
of Concerned Scientists, and
Wisconsin's Environmental Decade).
347. Tallahassee.................. City of Tallahassee, Florida.
348. Tampa........................ Tampa Electric Company.
349. TANC......................... Transmission Agency of Northern
California.
350. TAPS......................... Transmission Access Policy Study
Group.
351. TDU Systems.................. Transmission Dependent Utility
Systems (Arkansas Electric
Cooperative Corporation,
Connecticut Municipal Electric
Energy Cooperative, Golden Spread
Electric Cooperative, Inc., Holy
Cross Electric Association, Inc.,
Kansas Electric Power Cooperative,
Inc., Magic Valley Electric
Cooperative, Inc., Mid-Tex
Generation & Transmission Electric
Cooperative, Inc., NewCorp
Resources, Inc., Old Dominion
Electric Cooperative, Inc.).
352. Texaco....................... Texaco Inc.
353. Texas Utilities.............. Texas Utilities Electric Company.
354. Texas-New Mexico............. Texas-New Mexico Power Company.
355. Tonko........................ Tonko, Paul D. (NY State Assembly).
356. Torco........................ Torco Energy Marketing, Inc.
357. Total Petroleum.............. Total Petroleum, Inc.
358. Traverse EC.................. Traverse Electric Cooperative, Inc.
359. Tri-County EC................ Tri-County Electric Association,
Inc.
360. Tri-State G&T................ Tri-State Generation and
Transmission Association, Inc.
361. Tucson Power................. Tucson Electric Power Company.
362. Turlock...................... Turlock Irrigation District.
363. Turner-Hutchinson EC......... Turner-Hutchinson Electric
Cooperative, Inc.
364. TVA.......................... Tennessee Valley Authority.
365. TX Com....................... Public Utility Commission of Texas.
366. TX Industrials............... Texas Industrial Energy Consumers.
367. UAMPS........................ Utah Associated Municipal Power
Systems.
368. Union County EC.............. Union County Electric Cooperative,
Inc.
369. Union Electric............... Union Electric Company.
370. United Illuminating.......... United Illuminating Company.
371. UNITIL....................... UNITIL Corporation.
372. Urban League................. Greater Washington Urban League,
Inc.
373. UT Com....................... Utah Public Service Commission and
Utah Division of Public Utilities.
374. UT Industrials............... Utah Industrial Energy Consumers
(consisting of Alliant Techsystems,
Inc., Amoco Oil Company, Holnam,
Inc., Kennecott Copper Corp., and
Western Zirconium.
375. UtiliCorp.................... UtiliCorp United Inc.
[[Page 21702]]
376. Utilities For Improved Utilities For an Improved Transition
Transition. (consisting of Basin Electric
Cooperative, Black Hills
Corporation, Boston Edison Company,
Central Vermont Public Service
Corporation, Montaup Electric
Company, Wisconsin Electric Power
Company, and Wisconsin Public
Service Corporation).
377. Utility--Trade Corp. Utility--
Trade Corp..
378. Utility Investors Analysts... Utility Investors and Analysts.
379. Utility Shareholders......... United Utility Shareholders
Association of America.
380. Utility Wind Interest Group.. Utility Wind Interest Group, Inc.
381. Utility Workers Union........ Utility Workers Union of America,
AFL-CIO.
382. Utility Working Group........ Utility Working Group (consisting of
Atlantic City Electric Company,
Dominion Resources, Inc., Duke
Power Company, Florida Power &
Light Company, Niagara Mohawk Power
Corporation, Pacific Gas and
Electric Company, Public Service
Electric and Gas Company, and San
Diego Gas & Electric Company).
383. VA Com....................... Staff of the Virginia State
Corporation Commission.
384. Vann......................... Vann, Albert (NY State Assembly).
385. VEPCO........................ Virginia Electric and Power Company.
386. Verendrye EC................. Verendrye Electric Cooperative, Inc.
387. Vernon....................... City of Vernon, California.
388. VT DPS....................... Vermont Department of Public
Service.
389. WA Com....................... Washington Utilities and
Transportation Commission.
390. Wabash....................... Wabash Valley Power Association,
Inc.
391. WAPA......................... Western Area Power Administration
and Department of Energy.
392. Washington and Oregon Energy Washington State Energy Office and
Offices. Oregon Department of Energy.
393. Washington Water Power....... Washington Water Power Company
Energy Offices.
394. WEPCO........................ Wisconsin Electric Power Company.
395. West River EC................ West River Electric Association,
Inc.
396. Western Resources............ Western Resources Inc.
397. Whetstone Valley EC.......... Whetstone Valley Electric
Cooperative, Inc.
398. WI Com....................... Public Service Commission of
Wisconsin.
399. Wing Group................... Wing Group.
400. Wisconsin Coalition.......... Wisconsin Coalition (Wisconsin
Public Power Incorporated System,
Municipal Electric Utilities of
Wisconsin, Madison Gas and Electric
Company, and Citizens' Utility
Board of Wisconsin).
401. Wisconsin EC................. Wisconsin Electric Cooperative
Association.
402. Wisconsin Municipals......... Municipal Electric Utilities of
Wisconsin.
403. Wollenberg................... Wollenberg, Bruce, et al.
404. Wolverine Coop Members....... Wolverine Power Supply Cooperative
Special Members Committee.
405. Woodbury County REC.......... Woodbury County Rural Electric
Cooperative.
406. WP&L......................... Wisconsin Power and Light Company.
407. WSCC......................... Western Systems Coordinating Council
Board of Trustees.
408. WSPP......................... Western Systems Power Pool.
409. Yellowstone Valley EC........ Yellowstone Valley Electric
Cooperative, Inc.
------------------------------------------------------------------------
Environmental Impact Commenters
1. Attorneys General of Massachusetts, Connecticut, New Jersey and
Vermont
2. Center for Clean Air Policy
3. Central Maine Power Company
4. Cincinnati Gas & Electric Company and PSI Energy, Inc.
5. Clifton Below
6. Electric Consumer's Alliance
7. Connecticut Siting Council
8. Southern Environmental Law Center
9. General Public Utilities Corporation
10. Public Advisory Committee of the Grand Canyon Visibility
Transport Commission
11. Institute of Clean Air Companies
12. Interstate Natural Gas Association of America
13. Atlantic Electric Co. and Audubon Society of New Hampshire et
al.
14. Maryland Department of Natural Resources and Maryland Energy
Administration
15. Midwest Ozone Group
16. Missouri Department of Natural Resources
17. National Mining Association, Western Fuels Association, Inc. and
the Center for Energy and Economic Efficiency
18. The Navajo Nation
19. Maine, Massachusetts, Vermont and New Hampshire Public Service
Commissions
20. New Jersey Board of Public Utilities and the New Jersey
Department of Environmental Protection
21. New York State Department of Public Service and the New York
State Department of Environmental Conservation
22. Office of the Ohio Consumers' Counsel
23. Ohio Electric Utility Institute Environmental Committee
24. Ozone Transport Assessment Group
25. Ozone Transport Commission
26. Utility Air Regulatory Group (Edison Electric Institute, the
National Rural Electric Cooperative Association and the American
Public Power Association)
27. Wisconsin Department of Natural Resources
Other (Including Technical Conference Commenters)
1. Electric Power Research Institute
2. Electric Policy Technical Issues Group
3. Tejas Power Corporation
4. Competitive Power Coalition of New England
5. Mid-Continent Area Power Pool
6. Michigan Electric Coordinated Systems
7. Independent Energy Producers Association
8. Praxair, Inc.
9. Utility-Trade Corp.
10. Competitive Power Coalition of New England
11. Wyoming Public Service Commission
12. State of New Jersey
13. Paul Joskow
14. New England Conference of Public Utility Commissioners
15. Commonwealth of Massachusetts
16. Florida Electric Power Coordinating Group
17. Dine Power Authority
18. State of Connecticut Department of Environmental Protection
19. Commonwealth of Massachusetts Department of Environmental
Protection
20. State of Maine Department of Environmental Protection
21. Comision Federal de Electricidad of Mexico
Appendix C--Allegations of Public Utilities Exercising Transmission
Dominance
I. Examples From Proceedings Before Administrative Law Judges
These are examples of allegations that various public utilities
have refused to
[[Page 21703]]
provide comparable service, either through refusals to wheel,
dilatory tactics that so protracted negotiations as to effectively
deny wheeling, refusals to provide service priority equal to native
load, or refusals to provide service flexibility equivalent to the
utility's own use.
A. American Electric Power Service Corp. (AEP)
In 1993, AEP filed, on behalf of its public utility associate
companies, an open access tariff that offered only firm point-to-
point service with very limited flexibility. It did not offer
network service, flexible point-to-point service, or non-firm
service. Thus, it did not provide customers with the same
flexibility that AEP itself has. Nor did it provide a service
priority equivalent to that enjoyed by native load. The Commission
set AEP's tariff for hearing and, on rehearing, held that in order
not to be unduly discriminatory, the tariff had to offer comparable
service. American Electric Power Service Corp., 64 FERC para. 61,279
(1993), reh'g, 67 FERC para. 61,168 (1994).
At hearing, Raj Rao of Indiana Michigan Power Agency (IMPA) (Ex.
IMPA-1, Feb 23, 1994) and Kenneth Hegemann of American Municipal
Power-Ohio, Inc. (AMP-Ohio) (Ex. AMPO-1, Feb 23, 1994), both senior
management officials, testified concerning AEP's alleged
discriminatory practices.1 AMP-Ohio is an association of
municipalities in Ohio, some of whose members depend on AEP for
transmission and partial requirements service. IMPA is an
association of municipalities in Indiana, and many of IMPA's loads
are captive to the AEP transmission system. The witnesses alleged as
follows:
---------------------------------------------------------------------------
\1\ After the Rehearing Order expanding the scope of the
proceeding, AMP-Ohio and IMPA withdrew this testimony as no longer
necessary. This withdrawal does not change the fact that the
testimony was sworn to under oath.
---------------------------------------------------------------------------
1. In anticipation of high peak demands, AEP would contract for
large blocks of available short-term power, withhold sale of short-
term power, refuse to transmit third party short-term power, and
require purchases from AEP at the emergency rate (100 mill/kwh) when
an emergency might not exist. Ex. AMPO-1 at 6.
2. In December 1989, AMP-Ohio negotiated a 20 MW purchase of
short-term power from Louisville Gas & Electric Company (LG&E). AEP
refused to wheel because LG&E had earlier that day told AEP it had
no power to sell to AEP. AEP then bought the power from LG&E and
offered to resell it to AMP-Ohio. Ex. AMPO-1 at 6-7.
3. In January 1990, AMP-Ohio solicited bids for February power
purchases from a number of utilities including AEP. AEP was not the
winning bid. AMP-Ohio made arrangements to purchase the power from
four winning bidders and sought transmission through AEP. When AMP-
Ohio gave AEP the schedule for delivery, AEP refused to transmit the
power, matched the average price of the winning bids, and made the
sale itself. Ex. AMPO-1 at 7.
4. In August 1993, an AMP-Ohio member (Columbus, Ohio) was
purchasing 10 MW of hourly non-displacement power from AEP and,
after AEP raised its price to 60 mills/kwh, sought another source
for the next hour. Consumers Power Company and Detroit Edison
Company both offered non-displacement power at 40 mills. AEP refused
to transmit, saying it had a 600 MW unit out and could not resell
power from another source.2 Columbus cancelled the transaction
and had to buy 10 MW of power from AEP at 100 mills/kwh. Ex. AMPO-1
at 7-8.
---------------------------------------------------------------------------
\2\ AEP generally limited its offer of short-term transmission
to buy/sell transactions; that is, AEP would buy the power from the
seller and resell it to the purchaser. Supplemental testimony of AEP
Witness Baker (Ex. A-73) at 27-29. Often, the terms of the buy/sell
transaction required transmission dependent utilities (TDUs) to
maintain reserves and meet contractual commitments for at least a
year. Id.
---------------------------------------------------------------------------
5. In July 1993, two AMP-Ohio members (Columbus and St. Mary's)
had been buying hourly non-displacement power from AEP when the
price rose to 35 mills. Dayton Power & Light Company (DP&L) offered
to sell at 23 mills and AEP agreed to transmit for one hour. But for
the next hour, AEP said it had problems with its system, refused to
transmit the power, kept the power from DP&L for itself and offered
to sell power to AMP-Ohio for Columbus and St. Mary's at 100 mills.
Columbus increased its local generation, but St. Mary's purchased 8
MW at 100 mills. For the next hour, AMP-Ohio arranged with DP&L for
another 8 MW, hoping AEP would transmit under the 24 hour buy-sell
agreement. AEP did transmit this power. Seven hours later in the
day, St. Mary's Greenup Hydro project power was available and the 8
MW from DP&L was no longer needed. If St. Mary's had been receiving
the hourly power that AEP had refused to transmit, St. Mary's could
have switched to Greenup power. But because AMP-Ohio had changed to
daily service, St. Mary's had to pay a demand charge for the entire
day, even though it used the power only 7 hours and would have paid
less under the hourly rate. Ex. AMPO-1 at 8-9.
6. In January 1994, AMP-Ohio sought to transfer power from one
member with generation to other members, which required transmission
over AEP and Toledo Edison lines. Toledo Edison said yes, AEP said
no. AMP-Ohio's northern members purchased emergency power from
Toledo Edison. AMP-Ohio then reminded AEP that it had agreed not to
deny transmission and AEP agreed to transmit. Ex. AMPO-1 at 9.
7. IMPA arranged to buy 80 MW of short-term power from LG&E and
have it wheeled, using buy-sell arrangements, through Public Service
Company of Indiana (PSI) and AEP to serve IMPA's load at Richmond
(an IMPA member). The delivered price was $.292 per kW-day plus a 1
mill adder. At the same time AEP arranged to buy 300 MW from PSI at
$.30 per kW day plus out-of-pocket energy costs. Hence, PSI was
shipping a total of 380 MW to AEP with 80 MW of that amount to be
delivered to IMPA's load at Richmond. Then, on a day when IMPA
should have received the 80 MW, AEP told IMPA that PSI had sold
everything to AEP and that IMPA would have to buy from AEP at $.63
per kW day plus the cost of energy from AEP. IMPA purchased from AEP
under protest. AEP used its control over transmission to intercept
the 80 MW at a lower price and resell it as short-term power to
IMPA. AEP claimed that PSI had terminated its sales to AEP on that
day. But the 80 MW was independent of PSI's other sales to AEP and
would not have been interrupted if AEP had not interrupted it. IMPA-
1 at 7.
8. IMPA has combustion turbines owned by and located at one
member, which IMPA would like to connect to the Joint Transmission
System owned by IMPA, CINergy and Wabash Valley Power Association.
To do so, IMPA needed a metering agreement with AEP, to which AEP
would not agree. IMPA-1 at 6.
9. In January 1994, IMPA had power to sell from its turbines
when AEP and others needed power. IMPA offered power to AEP but AEP
it said could not purchase the power without an existing contract.
Moreover, since there was no short-term tariff, IMPA could not sell
the power to another utility. IMPA-1 at 6.
10. Another example of the utility engaging in dilatory tactics
that raised the customer's transaction costs and effectively denied
transmission is the ``sham transaction'' provision proposed by AEP.
As filed, AEP's tariffs permitted it to deny service merely because
a portion of the transmitted power might be used to serve a former
retail customer of AEP. See, e.g., Ex. BR&WVP-1 (J. Bertram Solomon
testimony, February 23, 1994). (As part of a settlement AEP filed
the pro forma tariff and withdrew this provision.)
11. Finally, AEP's originally filed tariff contained a
``prodigal customer'' provision. Under this provision, transmission
customers who sought to convert back to requirements service had to
give AEP five years' notice, in which case AEP and the customer
would enter into negotiations to determine whether AEP will provide
service at all and if so under what rate, terms, and conditions. Ex.
S-39 at 1 (Staff testimony). AEP did not require notice from all new
customers, only from prodigal customers. Id. at 2. That a potential
customer was previously served by AEP is not a reason to treat the
customer differently. (AEP withdrew this provision when it filed the
pro forma tariff.)
B. Entergy Services, Inc. (Entergy)
Entergy filed a partial settlement largely adopting the NOPR pro
forma tariffs except for two provisions (headroom and ancillary
services). Because the settlement predated the filing date for
customer testimony before the ALJ, the customers did not address the
need for Entergy to file a tariff. However, customers did make
allegations of discriminatory practices, as follows.
1. Customers alleged that Entergy flat-out refused to wheel.
Louisiana Energy and Power Authority (LEPA) witness Sylvan J.
Richard testified that LEPA's predecessor systems could not obtain
interconnections from Entergy. Ex. SJR-1 at 50.
2. Customers also alleged that Entergy refused to provide
service priority equal to native load and refused to provide service
flexibility equivalent to the utility's own use. For example, LEPA
witness Richard testified that even after state commissions ordered
interconnections and other coordination
[[Page 21704]]
services, LEPA's predecessors were still not able to obtain
coordination services because Entergy was not willing to coordinate
and because the transmission service it did offer was inflexible,
unidirectional point-to-point service, which prevented economic
coordination with others. Id. at 50-51.
3. South Mississippi Electric Power Association (SMEPA) witness
J. Bertram Solomon testified that Entergy's original ``open access''
tariff was restricted to point-to-point service, proposed separate
charges for each operating company, and required the cancellation of
existing agreements in order to take service under the proposed
tariff. Ex. SMEPA-10 at 28. Entergy eventually filed a network
tariff, but proposed different local facilities charges for the
various Entergy public utility operating subsidiaries. Id. at 29.
Since these local facilities charges were higher than the
transmission component of the subsidiaries' bundled rates, Entergy
obtained a competitive advantage. Id.
4. The Arkansas Cities and Cooperatives (ACC) is a group of
cities and cooperatives that own or operate electric generation or
distribution systems in Arkansas. ACC Witness Steven Merchant
testified that Entergy has segregated the wholesale market between
two of its subsidiaries, Arkansas Power & Light Copmpany (APL) and
Entergy Power, Inc. (EPI). Ex. SMM-1 at 16. In marketing power and
energy in Arkansas, EPI is subject to an Arkansas Commission order
that bars EPI from competing with APL for wholesale loads without
first obtaining a waiver. Id. Recently, EPI requested this waiver
for all wholesale transactions in Arkansas except for wholesale
customers currently served by an Entergy subsidiary; in other words,
EPI requested the Arkansas Commission to expand competition for all
wholesale customers except where EPI might compete with APL. Id. ACC
witness Merchant concluded that, since EPI does not compete with
APL, Entergy insulates APL's wholesale business from competition and
denies those wholesale customers access to EPI as a source of power,
thereby limiting alternative generation sources available to ACC.
Id. at 17-19. (Entergy's witness Kenney stated that Entergy has
recently filed a joint motion with ACC to the Arkansas Commission
seeking to extend the waiver and permit EPI to sell to APL's
wholesale customers. Ex. JFK-11 at 14-15.)
C. Pacific Gas & Electric Company (PG&E)
Northern California Power Agency (NCPA) attached several
documents to its 1988 complaint in Docket No. EL89-4. These
documents were provided to support NCPA's claim that PG&E's
unreasonable practices under the PG&E/NCPA Interconnection Agreement
(IA) effectively denied NCPA access to transmission properly
requested under the IA. Although the parties eventually settled and
the Commission terminated the docket with a letter order dated May
18, 1988, these documents provide allegations of PG&E using dilatory
tactics that so protracted negotiations as to effectively equal a
refusal to wheel.3
---------------------------------------------------------------------------
\3\ All of these incidents are related to and examples of PG&E's
conduct described in the NOPR (FERC Stats. & Regs. para. 32,514 at
33,073 n.151), that is, the history of PG&E's attempt to avoid its
commitments made to the California owners of the California Oregon
Transmission Project (COTP). However, these incidents are not
exactly the same as the incidents described in the NOPR, because
NCPA is not one of the owners of the COTP.
---------------------------------------------------------------------------
1. PG&E stated that since transmission was not currently
available, it was entitled to wait 72 months before providing
transmission; that is, transmission access could not be granted
before the passing of the 72-month notice period. NCPA 1988
Complaint, Ex. 3. However, the IA provided that transmission be
provided when it becomes actually available. PG&E also requested
substantial additional information, which NCPA considered beyond
that reasonably necessary for a study, but still provided. PG&E then
determined that transmission was not available, reasoning that
transmission was unavailable unless all the transmission requested
could be provided 8760 hours per year without restrictions or
limitations, extending through the expiration of the agreement in
2013. NCPA 1988 Complaint at 9.
2. On November 27, 1987, NCPA made a new transmission request to
PG&E, seeking 50 MW of bi-directional transmission at Midway. NCPA
1988 Complaint, Ex. 5. On January 28, 1988, PG&E filed an
interconnection agreement with Turlock Irrigation District (TID)
that provided TID with 50 MW of bi-directional transmission at
Midway. Pacific Gas & Electric Company, 42 FERC para. 61,406, order
on reh'g, 43 FERC para. 61,403 (1988). On February 22, 1988, PG&E
advised NCPA that all firm transmission service available at Midway
had been fully subscribed. NCPA 1988 Complaint, Ex. 6. Then, on
March 29, 1988, PG&E filed with the Commission an interconnection
agreement with Modesto Irrigation District (MID), that provided MID
with 50 MW of bi-directional transmission at Midway. Pacific Gas &
Electric Company, 44 FERC para. 61,010 (1988). At about the same
time (in the last week in March 1988), PG&E advised NCPA that the
allocations of transmission to TID, MID, and others, including a not
yet finalized allocation to Sacramento Municipality Utility
District, had used all the transmission available at Midway. NCPA
1988 Complaint, Exs. 7 and 8.
D. Northeast Utilities Service Company (NU)
This is the case where Northeast Utilities acquired Public
Service of New Hampshire (PSNH) (Docket No. EC90-10). New England
Power Company (NEP) witness Robert Bigelow's direct testimony
expressed concern over the ``relatively restrictive transmission
policies of both'' NU, on behalf of Northeast Utilities' public
utility subsidiaries, and PSNH. Bigelow Direct Testimony at 21
(filed May 25, 1990). In his cross rebuttal testimony, Mr. Bigelow
testified that ``NU has a poor track record as a provider of
transmission service'' and ``PSNH also has an abhorrent track record
as a provider of transmission services.'' Bigelow Cross Rebuttal
Testimony, at 3 (filed June 20, 1990). Mr. Bigelow described both
NU's and NEP's (his own company) failure to provide service
flexibility equivalent to their own use. Except for NEP's TDUs, both
NEP and NU historically provided only point-to-point transmission,
which required separate scheduling for each transaction. Bigelow
Cross Rebuttal at 4.
E. Southern California Edison Company and San Diego Gas and Electric
Company
The evidence in this merger proceeding (Docket No. EC89-5)
included testimony from a number of witnesses describing instances
of Edison's conduct. Richard Greenwalt was the power supply
supervisor for the City of Riverside, California. He was responsible
for scheduling all purchases of energy for Riverside and for the
cities of Azusa, Banning and Colton, California. Greenwalt testimony
at 1 (November 1989). (These four cities and Anaheim, California,
are collectively referred to as the Southern Cities or Cities.)
Joseph Hsu was the Director of Utilities for Azusa. Hsu testimony at
1 (November 1989). Gale Drews was the electric utility director of
Colton. Drews testimony at 1-2 (November 1989). Bill Carnahan was
the director for Riverside. Carnahan testimony at 1 (November 1989).
Gordon Hoyt was the general manager of the Anaheim power department.
Hoyt testimony at 1 (November 1989). Dan McCann was the power
coordination supervisor for Anaheim. He supervised Anaheim's load
scheduling and is a former Edison employee, having worked for Edison
for 20 years. McCann Testimony at 1-2 (November 1989). These
witnesses testified that Edison refused to wheel as follows.
1. Edison's policy was to curtail the Cities any time it could
be justified using any of a list of acceptable reasons to deny
interruptible transmission service. Id. at 22-23.
2. Edison would not generally provide transmission service when
Edison could save money by itself purchasing the economy energy that
would be wheeled. McCann testimony at 19. The Cities called Edison
every hour to request interruptible transmission service. Id. Edison
often refused to sell energy available in the Western Systems Power
Pool to the Cities and then made available higher cost contract
energy or partial requirements service. Id. at 19-20.
3. When Anaheim requested Edison provide firm transmission of
power from neighboring states, Edison would often agree to provide
non-firm service but would not integrate the capacity for many years
in the future, saying that its control area did not need capacity at
that time. Hoyt testimony at 9. Since the selling utility was
interested in a sale of capacity, not just energy, the transaction
would not occur. Id. Edison repeatedly used its control over
transmission to deny Anaheim access to low-cost firm power. Id. at
9-10.
4. While Edison provided short-term firm transmission service to
the Cities, it would only provide long-term firm service for three
specific resources: The SONGS nuclear plant, a specific IPP, and
Hoover Dam power. Hoyt testimony at 20. One of Edison's reasons for
denying long-term transmission was that Edison desired to reserve
the transmission for its own future (unspecified) needs. Id.
5. In the 1970s, Edison refused to allow the Cities access to
the Pacific Intertie. Hoyt testimony at 21; Drews testimony at 7-8.
[[Page 21705]]
6. In 1988, Edison refused to provide transmission service for a
Cities power purchase from Public Service Company of New Mexico
(PSNM) from Palo Verde Nuclear station. Hoyt testimony at 21.
7. Edison has refused to provide requested firm transmission
from
--California-Oregon border to Midway Station
--Nevada-Oregon Border to Sylmar Substation
--Palo Verde Switchyard to Vista
--SONGS Switchyard to Vista.
Carahan testimony at 15.
8. Riverside requested transmission from Palo Verde and was told
that such service was not available. Carnahan testimony at 16.
Edison offered Riverside only 12 MW of curtailable transmission
entitlement to provide Riverside's share of Palo Verde. Id. This
service was neither large enough or long enough, and Edison insisted
on unreasonable terms and conditions. Id.
9. Azusa, Banning and Colton had a contract with Edison that
entitled them to use their Palo Verde firm transmission path to
schedule energy to meet their contract energy obligation. Edison
refused to permit the three cities to use that path. Edison did not
contest that the contracts allowed this use, but said that the
scheduling of such small amounts of energy for the three cities
would be too burdensome. Greenwalt testimony at 14.
10. Edison would not respond in a timely manne
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
r to the Cities'
requests, routinely taking months to respond. Drews testimony at 15.
11. During the 1980s, Edison provided Colton with some
transmission service to allow the Cities to reach certain suppliers,
but limited the choices available to the Cities and imposed terms
and conditions that increased the Cities' costs and placed Colton at
a disadvantage against Edison. Drews testimony at 9. Arranging
alternative generation sources was difficult because the Cities
always had to first get Edison to state whether it would provide
transmission.
12. During 1988 and 1989, a dispute arose between Edison and the
Cities concerning the Hoover Uprating Project. Drews testimony at
16. Edison argued that for the months when units were out of service
for uprating, and Southern Cities capacity was reduced to zero,
Southern Cities would not receive an energy credit, even though
energy was still available and used by Edison. But the contracts
allowed a participant who did not have capacity to still schedule
its energy as non-firm energy on the capacity of another
participant. Id. at 16-17.
13. In 1986, Azusa negotiated a power purchase contract with the
California Department of Water Resources in increments of first 5 MW
and then 2 MW (for a total of 7 MW). Hsu testimony at 14. First
Edison assured Azusa that the transmission for the additional 2 MW
would not be a problem. Id. Then Edison would not agree to amend the
transmission service agreement for the additional 2 MW. Id.
14. In 1986, Azusa notified Edison of Special Condition 12
4 purchases from PG&E and requested firm transmission service.
Id. Two months before service was to begin, Edison notified the
Cities of a problem with the transmission lines. Id. Transmission
was eventually granted, but only after a four-month delay and
substantial losses to the Cities. Id. Then Edison decided there was
no problem with its transmission facilities. Id. at 14-15.
---------------------------------------------------------------------------
\4\ Special Condition 12 of the Integrated Operations Agreement
between Edison and the Southern Cities defined certain Special
Condition 12 resources and allowed the Cities to make certain uses
of those resources, subject to certain restrictions.
---------------------------------------------------------------------------
15. In 1986-87, the Cities purchased 20 MW from PG&E and 80 MW
from Deseret G&T Cooperative. Hoyt testimony at 7-8. Edison stated
that without reinforcement of its transmission system, Edison would
not provide the transmission. Id. There was a five-month delay
during which the Cities were forced to purchase from Edison at a
higher cost. Id. at 8-9. Then Edison decided that the transmission
system did not need reinforcement. Id. at 8.
16. Edison also refused to provide a service priority equal to
that of native load. It would curtail the Cities in order to
purchase more economy energy for itself. McCann testimony at 28. If
Edison could make the purchase, it would curtail the City and use
the energy for itself. Id. When Edison curtailed the Cities, they
were not able to purchase economy energy and instead purchased
energy from Edison. Id. at 24.
17. According to Edison, the interruptible transmission it
provided the Cities was interruptible for any reason. Id. at 20. A
purchase could be terminated the hour after it is begun or even
during the hour. Id. As a result, the Cities lost opportunities to
make advantageous economy purchases. Id. at 20-21.
18. Edison also refused to provide customers flexibility similar
to the flexibility Edison provided itself. Edison's refusal to
provide bi-directional transmission service restricted the Cities'
abilities to purchase hydroelectric energy from the Pacific
Northwest. Hoyt testimony at 22. Because most contracts with
Northwest utilities require a return of power, the Northwest
utilities would not deal with the Cities without transmission to
return energy. Id. at 22-23. Edison did provide bi-directional
transmission to the Los Angeles Department of Water & Power (LADWP)
to accommodate flows to and from Arizona. Id.
19. Riverside was unable to obtain non-firm service more than
two hours in advance of need. Carnahan testimony at 18.
20. Riverside and Colton were both served out of Edison's Vista
substation. Although the two cities were on the same 69 kV bus,
Edison would not allow them to sell energy to each other. Greenwalt
testimony at 17.
21. Riverside's agreement with Edison allowed Riverside to
purchase a block of energy through the WSPP and divide it up among
the four Cities (Azusa, Banning, Colton and Riverside). Greenwalt
testimony at 17. When Riverside had excess energy from other
sources, Edison would not permit it to sell that energy to the other
three cities. Id. For example, Riverside attempted to sell Deseret
energy transmitted by LADWP to the Edison system. Id. at 17-18.
LADWP would not break out the Cities' shares of that energy, and
Edison would not accept the energy as a delivery for all four
cities. Id. at 18. Edison argued that because this energy was excess
energy that Riverside could not use, Riverside did not have
transmission rights to bring it into the control area. Id. As a
result, Riverside paid for the energy delivered by LADWP to the
Edison control area, but could not sell it to the other three
cities, and gave it to Edison itself, which consumed the energy
without making any payment for it. Id. Riverside tried a number of
alternative paths, including using WSPP transmission where Riverside
paid Edison 5 mills to connect to Azusa, 5 mills to connect to
Banning, and 5 mills to connect to Colton for each megawatthour.
While this approach was successful for a while, eventually Edison
refused to permit these sales.
22. Edison claimed that the Cities only have transmission rights
to bring in enough Special Condition 12 energy to satisfy the
Cities' load. Greenwalt testimony at 18.
23. Edison contended that the Cities' load requirements were
satisfied first by integrated resources and then by Special
Condition 12 and economy energy purchases. Id. at 19. When the
Cities' integrated resources exceeded their load, any Special
Condition 12 resources became excess. Under Riverside's Deseret
contract, the Cities were required to take a minimum of 35 MW each
hour. Id. Edison acknowledged that it was obligated to buy, or allow
the Cities to sell, any excess energy from Riverside's integrated
resources. Id. However, Edison refused to give the Cities credit for
excess Special Condition 12 energy brought into the area, claiming
that the Cities could not have brought it in because they did not
have transmission rights. Id.
II. Other Examples of Transmission Disputes
Disputes over transmission are not uncommon, contrary to EEI's
suggestion. Some recent examples taken from pleadings and other
documents and from Commission orders reveal that it has been very
difficult for various entities in the electric power industry to
agree on transmission rights. These examples also reveal that even
after issuance of AEP and the Open Access NOPR with its proposed pro
forma tariffs, there has been considerable controversy over whether
various utilities' ``open access'' tariffs deviate from those
tariffs. (The Commission has allowed utilities that adopt tariffs
that match or exceed the non-rate terms and conditions in the NOPR
pro forma tariffs to obtain certain benefits.)
A. In a letter of February 3, 1995 to Mr. Gerald Richman of the
Commission's Enforcement section in the Office of the General
Counsel, Steven J. Kean, Vice President, Regulatory Affairs, Enron
Power Marketing, Inc. (Enron) alleged that Niagara Mohawk Power
Corporation (NiMo) refused to wheel power from Rochester Gas &
Electric (RG&E) to Enron under RG&E's transmission contract with
NiMo; however, when Enron revealed the buyer, NiMo did wheel power
for RG&E to the buyer. Mr. Kean alleged that this was not an
isolated incident. NiMo argued that the contract did not require it
to
[[Page 21706]]
provide RG&E with transmission to Enron. It also said that the
principle of comparability does not require the service. Letter of
November 21, 1994 from NiMo representative A. Karen Hill to Gerald
Richman.
B. The Commission's Task Force Hot Line (Hot Line) received a
complaint that a member of the New York Power Pool (NYPP) refused to
transmit power that another member bought from a power marketer. In
a letter of November 17, 1994, from Chair Moler to Mr. William J.
Balet, Executive Director of NYPP, Chair Moler explained that the
Commission's enforcement staff had investigated and found the
allegation to be true.
C. In Southern Minnesota Municipal Power Agency v. Northern
States Power Company (Minnesota), 73 FERC para. 61,350 (1995), NSP
and SMMPA had a contract under which NSP agreed to provide
transmission service. However, the parties had numerous disputes
over the service. The Commission found that NSP had misinterpreted
the contract in several ways. For, example, SMMPA argued that it
should be able to directly schedule its deliveries of energy out of
the NSP control area and that it should not be limited to particular
points of delivery. NSP argued that only it was entitled to control
the physical operation of scheduling. The Commission found that the
clear language of the contracts gave SMMPA the authority to schedule
its own power.
D. Mid-Continent Area Power Pool, 72 FERC para. 61,223 (1995),
involved MAPP's membership criteria, which made it impossible for a
power marketer to join MAPP and obtain the benefits of certain
transmission services available only to MAPP members. The Commission
found that the membership criteria may be unreasonable, particularly
since there may be less burdensome ways of setting up membership
criteria for non-traditional entities.
Appendix D--Pro Forma Open Access Transmission Tariff
Table of Contents
I. Common Service Provisions
1 Definitions
1.1 Ancillary Services
1.2 Annual Transmission Costs
1.3 Application
1.4 Commission
1.5 Completed Application
1.6 Control Area
1.7 Curtailment
1.8 Delivering Party
1.9 Designated Agent
1.10 Direct Assignment Facilities
1.11 Eligible Customer
1.12 Facilities Study
1.13 Firm Point-To-Point Transmission Service
1.14 Good Utility Practice
1.15 Interruption
1.16 Load Ratio Share
1.17 Load Shedding
1.18 Long-Term Firm Point-To-Point Transmission Service
1.19 Native Load Customers
1.20 Network Customer
1.21 Network Integration Transmission Service
1.22 Network Load
1.23 Network Operating Agreement
1.24 Network Operating Committee
1.25 Network Resource
1.26 Network Upgrades
1.27 Non-Firm Point-To-Point Transmission Service
1.28 Open Access Same-Time Information System (OASIS)
1.29 Part I
1.30 Part II
1.31 Part III
1.32 Parties
1.33 Point(s) of Delivery
1.34 Point(s) of Receipt
1.35 Point-To-Point Transmission Service
1.36 Power Purchaser
1.37 Receiving Party
1.38 Regional Transmission Group (RTG)
1.39 Reserved Capacity
1.40 Service Agreement
1.41 Service Commencement Date
1.42 Short-Term Firm Point-To-Point Transmission Service
1.43 System Impact Study
1.44 Third-Party Sale
1.45 Transmission Customer
1.46 Transmission Provider
1.47 Transmission Provider's Monthly Transmission System Peak
1.48 Transmission Service
1.49 Transmission System
2 Initial Allocation and Renewal Procedures
2.1 Initial Allocation of Available Transmission Capability
2.2 Reservation Priority For Existing Firm Service Customers
3 Ancillary Services
3.1 Scheduling, System Control and Dispatch Service
3.2 Reactive Supply and Voltage Control from Generation Sources
Service
3.3 Regulation and Frequency Response Service
3.4 Energy Imbalance Service
3.5 Operating Reserve--Spinning Reserve Service
3.6 Operating Reserve--Supplemental Reserve Service
4 Open Access Same-Time Information System (OASIS)
5 Local Furnishing Bonds
5.1 Transmission Providers That Own Facilities Financed by
Local Furnishing Bonds
5.2 Alternative Procedures for Requesting Transmission Service
6 Reciprocity
7 Billing and Payment
7.1 Billing Procedure
7.2 Interest on Unpaid Balances
7.3 Customer Default
8 Accounting for the Transmission Provider's Use of the Tariff
8.1 Transmission Revenues
8.2 Study Costs and Revenues
9 Regulatory Filings
10 Force Majeure and Indemnification
10.1 Force Majeure
10.2 Indemnification
11 Creditworthiness
12 Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures
12.2 External Arbitration Procedures
12.3 Arbitration Decisions
12.4 Costs
12.5 Rights Under The Federal Power Act
II. Point-to-Point Transmission Service
Preamble
13 Nature of Firm Point-To-Point Transmission Service
13.1 Term
13.2 Reservation Priority
13.3 Use of Firm Transmission Service by the Transmission
Provider
13.4 Service Agreements
13.5 Transmission Customer Obligations for Facility Additions
or Redispatch Costs
13.6 Curtailment of Firm Transmission Service
13.7 Classification of Firm Transmission Service
13.8 Scheduling of Firm Point-To-Point Transmission Service
14 Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term
14.2 Reservation Priority
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider
14.4 Service Agreements
14.5 Classification of Non-Firm Point-To-Point Transmission
Service
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service
14.7 Curtailment or Interruption of Service
15 Service Availability
15.1 General Conditions
15.2 Determination of Available Transmission Capability
15.3 Initiating Service in the Absence of an Executed Service
Agreement
15.4 Obligation to Provide Transmission Service that Requires
Expansion or Modification of the Transmission System
15.5 Deferral of Service
15.6 Other Transmission Service Schedules
15.7 Real Power Losses
16 Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers
16.2 Transmission Customer Responsibility for Third-Party
Arrangements
17 Procedures for Arranging Firm Point-To-Point Transmission
Service
17.1 Application
17.2 Completed Application
17.3 Deposit
17.4 Notice of Deficient Application
17.5 Response to a Completed Application
17.6 Execution of Service Agreement
17.7 Extensions for Commencement of Service
18 Procedures for Arranging Non-Firm Point-To-Point Transmission
Service
18.1 Application
18.2 Completed Application
18.3 Reservation of Non-Firm Point-To-Point Transmission
Service
[[Page 21707]]
18.4 Determination of Available Transmission Capability
19 Additional Study Procedures For Firm Point-To-Point Transmission
Service Requests
19.1 Notice of Need for System Impact Study
19.2 System Impact Study Agreement and Cost Reimbursement
19.3 System Impact Study Procedures
19.4 Facilities Study Procedures
19.5 Facilities Study Modifications
19.6 Due Diligence in Completing New Facilities
19.7 Partial Interim Service
19.8 Expedited Procedures for New Facilities
20 Procedures if The Transmission Provider is Unable to Complete
New Transmission Facilities for Firm Point-To-Point Transmission
Service
20.1 Delays in Construction of New Facilities
20.2 Alternatives to the Original Facility Additions
20.3 Refund Obligation for Unfinished Facility Additions
21 Provisions Relating to Transmission Construction and Services on
the Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions
21.2 Coordination of Third-Party System Additions
22 Changes in Service Specifications
22.1 Modifications On a Non-Firm Basis
22.2 Modification On a Firm Basis
23 Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service
23.2 Limitations on Assignment or Transfer of Service
23.3 Information on Assignment or Transfer of Service
24 Metering and Power Factor Correction at Receipt and Delivery
Points(s)
24.1 Transmission Customer Obligations
24.2 Transmission Provider Access to Metering Data
24.3 Power Factor
25 Compensation for Transmission Service
26 Stranded Cost Recovery
27 Compensation for New Facilities and Redispatch Costs
III. Network Integration Transmission Service
Preamble
28 Nature of Network Integration Transmission Service
28.1 Scope of Service
28.2 Transmission Provider Responsibilities
28.3 Network Integration Transmission Service
28.4 Secondary Service
28.5 Real Power Losses
28.6 Restrictions on Use of Service
29 Initiating Service
29.1 Condition Precedent for Receiving Service
29.2 Application Procedures
29.3 Technical Arrangements to be Completed Prior to
Commencement of Service
29.4 Network Customer Facilities
29.5 Filing of Service Agreement
30 Network Resources
30.1 Designation of Network Resources
30.2 Designation of New Network Resources
30.3 Termination of Network Resources
30.4 Operation of Network Resources
30.5 Network Customer Redispatch Obligation
30.6 Transmission Arrangements for Network Resources Not
Physically Interconnected With The Transmission Provider
30.7 Limitation on Designation of Network Resources
30.8 Use of Interface Capacity by the Network Customer
30.9 Network Customer Owned Transmission Facilities
31 Designation of Network Load
31.1 Network Load
31.2 New Network Loads Connected With the Transmission Provider
31.3 Network Load Not Physically Interconnected with the
Transmission Provider
31.4 New Interconnection Points
31.5 Changes in Service Requests
31.6 Annual Load and Resource Information Updates
32 Additional Study Procedures For Network Integration Transmission
Service Requests
32.1 Notice of Need for System Impact Study
32.2 System Impact Study Agreement and Cost Reimbursement
32.3 System Impact Study Procedures
32.4 Facilities Study Procedures
33 Load Shedding and Curtailments
33.1 Procedures
33.2 Transmission Constraints
33.3 Cost Responsibility for Relieving Transmission Constraints
33.4 Curtailments of Scheduled Deliveries
33.5 Allocation of Curtailments
33.6 Load Shedding
33.7 System Reliability
34 Rates and Charges
34.1 Monthly Demand Charge
34.2 Determination of Network Customer's Monthly Network Load
34.3 Determination of Transmission Provider's Monthly
Transmission System Load
34.4 Redispatch Charge
34.5 Stranded Cost Recovery
35 Operating Arrangements
35.1 Operation under The Network Operating Agreement
35.2 Network Operating Agreement
35.3 Network Operating Committee
Schedule 1
Scheduling, System Control and Dispatch Service
Schedule 2
Reactive Supply and Voltage Control from Generation Sources
Service
Schedule 3
Regulation and Frequency Response Service
Schedule 4
Energy Imbalance Service
Schedule 5
Operating Reserve--Spinning Reserve Service
Schedule 6
Operating Reserve--Supplemental Reserve Service
Schedule 7
Long-Term Firm and Short-Term Firm Point-To-Point Transmission
Service
Schedule 8
Non-Firm Point-To-Point Transmission Service
Attachment A
Form of Service Agreement for Firm Point-To-Point Transmission
Service
Attachment B
Form Of Service Agreement For Non-Firm Point-To-Point
Transmission Service
Attachment C
Methodology To Assess Available Transmission Capability
Attachment D
Methodology for Completing a System Impact Study
Attachment E
Index Of Point-To-Point Transmission Service Customers
Attachment F
Service Agreement For Network Integration Transmission Service
Attachment G
Network Operating Agreement
Attachment H
Annual Transmission Revenue Requirement For Network Integration
Transmission Service
Attachment I
Index Of Network Integration Transmission Service Customers
I. Common Service Provisions
1. Definitions
1.1 Ancillary Services: Those services that are necessary to
support the transmission of capacity and energy from resources to
loads while maintaining reliable operation of the Transmission
Provider's Transmission System in accordance with Good Utility
Practice.
1.2 Annual Transmission Costs: The total annual cost of the
Transmission System for purposes of Network Integration Transmission
Service shall be the amount specified in Attachment H until amended
by the Transmission Provider or modified by the Commission.
1.3 Application: A request by an Eligible Customer for
transmission service pursuant to the provisions of the Tariff.
1.4 Commission: The Federal Energy Regulatory Commission.
1.5 Completed Application: An Application that satisfies all of
the information and other requirements of the Tariff, including any
required deposit.
1.6 Control Area: An electric power system or combination of
electric power systems to which a common automatic generation
control scheme is applied in order to:
(1) Match, at all times, the power output of the generators
within the electric power system(s) and capacity and energy
purchased from entities outside the electric power system(s), with
the load within the electric power system(s);
[[Page 21708]]
(2) maintain scheduled interchange with other Control Areas,
within the limits of Good Utility Practice;
(3) maintain the frequency of the electric power system(s)
within reasonable limits in accordance with Good Utility Practice;
and
(4) provide sufficient generating capacity to maintain operating
reserves in accordance with Good Utility Practice.
1.7 Curtailment: A reduction in firm or non-firm transmission
service in response to a transmission capacity shortage as a result
of system reliability conditions.
1.8 Delivering Party: The entity supplying capacity and energy
to be transmitted at Point(s) of Receipt.
1.9 Designated Agent: Any entity that performs actions or
functions on behalf of the Transmission Provider, an Eligible
Customer, or the Transmission Customer required under the Tariff.
1.10 Direct Assignment Facilities: Facilities or portions of
facilities that are constructed by the Transmission Provider for the
sole use/benefit of a particular Transmission Customer requesting
service under the Tariff. Direct Assignment Facilities shall be
specified in the Service Agreement that governs service to the
Transmission Customer and shall be subject to Commission approval.
1.11 Eligible Customer: (i) Any electric utility (including the
Transmission Provider and any power marketer), Federal power
marketing agency, or any person generating electric energy for sale
for resale; electric energy sold or produced by such entity may be
electric energy produced in the United States, Canada or Mexico;
however, such entity is not eligible for transmission service that
would be prohibited by Section 212(h)(2) of the Federal Power Act;
and (ii) any retail customer taking unbundled Transmission Service
pursuant to a state retail access program or pursuant to a voluntary
offer of unbundled retail transmission service by the Transmission
Provider.
1.12 Facilities Study: An engineering study conducted by the
Transmission Provider to determine the required modifications to the
Transmission Provider's Transmission System, including the cost and
scheduled completion date for such modifications, that will be
required to provide the requested transmission service.
1.13 Firm Point-To-Point Transmission Service: Transmission
Service under this Tariff that is reserved and/or scheduled between
specified Points of Receipt and Delivery pursuant to Part II of this
Tariff.
1.14 Good Utility Practice: Any of the practices, methods and
acts engaged in or approved by a significant portion of the electric
utility industry during the relevant time period, or any of the
practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired result at a
reasonable cost consistent with good business practices,
reliability, safety and expedition. Good Utility Practice is not
intended to be limited to the optimum practice, method, or act to
the exclusion of all others, but rather to be acceptable practices,
methods, or acts generally accepted in the region.
1.15 Interruption: A reduction in non-firm transmission service
due to economic reasons pursuant to Section 14.7.
1.16 Load Ratio Share: Ratio of a Transmission Customer's
Network Load to the Transmission Provider's total load computed in
accordance with Sections 34.2 and 34.3 of the Network Integration
Transmission Service under Part III the Tariff and calculated on a
rolling twelve month basis.
1.17 Load Shedding: The systematic reduction of system demand
by temporarily decreasing load in response to transmission system or
area capacity shortages, system instability, or voltage control
considerations under Part III of the Tariff.
1.18 Long-Term Firm Point-To-Point Transmission Service: Firm
Point-To-Point Transmission Service under Part II of the Tariff with
a term of one year or more.
1.19 Native Load Customers: The wholesale and retail power
customers of the Transmission Provider on whose behalf the
Transmission Provider, by statute, franchise, regulatory
requirement, or contract, has undertaken an obligation to construct
and operate the Transmission Provider's system to meet the reliable
electric needs of such customers.
1.20 Network Customer: An entity receiving transmission service
pursuant to the terms of the Transmission Provider's Network
Integration Transmission Service under Part III of the Tariff.
1.21 Network Integration Transmission Service: The transmission
service provided under Part III of the Tariff.
1.22 Network Load: The load that a Network Customer designates
for Network Integration Transmission Service under Part III of the
Tariff. The Network Customer's Network Load shall include all load
served by the output of any Network Resources designated by the
Network Customer. A Network Customer may elect to designate less
than its total load as Network Load but may not designate only part
of the load at a discrete Point of Delivery. Where an Eligible
Customer has elected not to designate a particular load at discrete
points of delivery as Network Load, the Eligible Customer is
responsible for making separate arrangements under Part II of the
Tariff for any Point-To-Point Transmission Service that may be
necessary for such non-designated load.
1.23 Network Operating Agreement: An executed agreement that
contains the terms and conditions under which the Network Customer
shall operate its facilities and the technical and operational
matters associated with the implementation of Network Integration
Transmission Service under Part III of the Tariff.
1.24 Network Operating Committee: A group made up of
representatives from the Network Customer(s) and the Transmission
Provider established to coordinate operating criteria and other
technical considerations required for implementation of Network
Integration Transmission Service under Part III of this Tariff.
1.25 Network Resource: Any designated generating resource owned
or purchased by a Network Customer under the Network Integration
Transmission Service Tariff. Network Resources do not include any
resource, or any portion thereof, that is committed for sale to
third parties or otherwise cannot be called upon to meet the Network
Customer's Network Load on a non-interruptible basis.
1.26 Network Upgrades: Modifications or additions to
transmission-related facilities that are integrated with and support
the Transmission Provider's overall Transmission System for the
general benefit of all users of such Transmission System.
1.27 Non-Firm Point-To-Point Transmission Service: Point-To-
Point Transmission Service under the Tariff that is reserved and
scheduled on an as-available basis and is subject to Curtailment or
Interruption as set forth in Section 14.7 under Part II of this
Tariff. Non-Firm Point-To-Point Transmission Service is available on
a stand-alone basis for periods ranging from one hour to one month.
1.28 Open Access Same-Time Information System (OASIS): The
information system and standards of conduct contained in Part 37 of
the Commission's regulations.
1.29 Part I: Tariff Definitions and Common Service Provisions
contained in Sections 2 through 12.
1.30 Part II: Tariff Sections 13 through 27 pertaining to
Point-To-Point Transmission Service in conjunction with the
applicable Common Service Provisions of Part I and appropriate
Schedules and Attachments.
1.31 Part III: Tariff Sections 28 through 35 pertaining to
Network Integration Transmission Service in conjunction with the
applicable Common Service Provisions of Part I and appropriate
Schedules and Attachments.
1.32 Parties: The Transmission Provider and the Transmission
Customer receiving service under the Tariff.
1.33 Point(s) of Delivery: Point(s) on the Transmission
Provider's Transmission System where capacity and energy transmitted
by the Transmission Provider will be made available to the Receiving
Party under Part II of the Tariff. The Point(s) of Delivery shall be
specified in the Service Agreement.
1.34 Point(s) of Receipt: Point(s) of interconnection on the
Transmission Provider's Transmission System where capacity and
energy will be made available to the Transmission Provider by the
Delivering Party under Part II of the Tariff. The Point(s) of
Receipt shall be specified in the Service Agreement.
1.35 Point-To-Point Transmission Service: The reservation and
transmission of capacity and energy on either a firm or non-firm
basis from the Point(s) of Receipt to the Point(s) of Delivery under
Part II of the Tariff.
1.36 Power Purchaser: The entity that is purchasing the
capacity and energy to be transmitted under the Tariff.
1.37 Receiving Party: The entity receiving the capacity and
energy transmitted by the Transmission Provider to Point(s) of
Delivery.
1.38 Regional Transmission Group (RTG): A voluntary
organization of transmission owners, transmission users and other
entities approved by the Commission to efficiently
[[Page 21709]]
coordinate transmission planning (and expansion), operation and use
on a regional (and interregional) basis.
1.39 Reserved Capacity: The maximum amount of capacity and
energy that the Transmission Provider agrees to transmit for the
Transmission Customer over the Transmission Provider's Transmission
System between the Point(s) of Receipt and the Point(s) of Delivery
under Part II of the Tariff. Reserved Capacity shall be expressed in
terms of whole megawatts on a sixty (60) minute interval (commencing
on the clock hour) basis.
1.40 Service Agreement: The initial agreement and any
amendments or supplements thereto entered into by the Transmission
Customer and the Transmission Provider for service under the Tariff.
1.41 Service Commencement Date: The date the Transmission
Provider begins to provide service pursuant to the terms of an
executed Service Agreement, or the date the Transmission Provider
begins to provide service in accordance with Section 15.3 or Section
29.1 under the Tariff.
1.42 Short-Term Firm Point-To-Point Transmission Service: Firm
Point-To-Point Transmission Service under Part II of the Tariff with
a term of less than one year.
1.43 System Impact Study: An assessment by the Transmission
Provider of (i) the adequacy of the Transmission System to
accommodate a request for either Firm Point-To-Point Transmission
Service or Network Integration Transmission Service and (ii) whether
any additional costs may be incurred in order to provide
transmission service.
1.44 Third-Party Sale: Any sale for resale in interstate
commerce to a Power Purchaser that is not designated as part of
Network Load under the Network Integration Transmission Service.
1.45 Transmission Customer: Any Eligible Customer (or its
Designated Agent) that (i) executes a Service Agreement, or (ii)
requests in writing that the Transmission Provider file with the
Commission, a proposed unexecuted Service Agreement to receive
transmission service under Part II of the Tariff. This term is used
in the Part I Common Service Provisions to include customers
receiving transmission service under Part II and Part III of this
Tariff.
1.46 Transmission Provider: The public utility (or its
Designated Agent) that owns, controls, or operates facilities used
for the transmission of electric energy in interstate commerce and
provides transmission service under the Tariff.
1.47 Transmission Provider's Monthly Transmission System Peak:
The maximum firm usage of the Transmission Provider's Transmission
System in a calendar month.
1.48 Transmission Service: Point-To-Point Transmission Service
provided under Part II of the Tariff on a firm and non-firm basis.
1.49 Transmission System: The facilities owned, controlled or
operated by the Transmission Provider that are used to provide
transmission service under Part II and Part III of the Tariff.
2 Initial Allocation and Renewal Procedures
2.1 Initial Allocation of Available Transmission Capability:
For purposes of determining whether existing capability on the
Transmission Provider's Transmission System is adequate to
accommodate a request for firm service under this Tariff, all
Completed Applications for new firm transmission service received
during the initial sixty (60) day period commencing with the
effective date of the Tariff will be deemed to have been filed
simultaneously. A lottery system conducted by an independent party
shall be used to assign priorities for Completed Applications filed
simultaneously. All Completed Applications for firm transmission
service received after the initial sixty (60) day period shall be
assigned a priority pursuant to Section 13.2.
2.2 Reservation Priority For Existing Firm Service Customers:
Existing firm service customers (wholesale requirements and
transmission-only, with a contract term of one-year or more), have
the right to continue to take transmission service from the
Transmission Provider when the contract expires, rolls over or is
renewed. This transmission reservation priority is independent of
whether the existing customer continues to purchase capacity and
energy from the Transmission Provider or elects to purchase capacity
and energy from another supplier. If at the end of the contract
term, the Transmission Provider's Transmission System cannot
accommodate all of the requests for transmission service the
existing firm service customer must agree to accept a contract term
at least equal to a competing request by any new Eligible Customer
and to pay the current just and reasonable rate, as approved by the
Commission, for such service. This transmission reservation priority
for existing firm service customers is an ongoing right that may be
exercised at the end of all firm contract terms of one-year or
longer.
3 Ancillary Services
Ancillary Services are needed with transmission service to
maintain reliability within and among the Control Areas affected by
the transmission service. The Transmission Provider is required to
provide (or offer to arrange with the local Control Area operator as
discussed below), and the Transmission Customer is required to
purchase, the following Ancillary Services (i) Scheduling, System
Control and Dispatch, and (ii) Reactive Supply and Voltage Control
from Generation Sources.
The Transmission Provider is required to offer to provide (or
offer to arrange with the local Control Area operator as discussed
below) the following Ancillary Services only to the Transmission
Customer serving load within the Transmission Provider's Control
Area (i) Regulation and Frequency Response, (ii) Energy Imbalance,
(iii) Operating Reserve--Spinning, and (iv) Operating Reserve--
Supplemental. The Transmission Customer serving load within the
Transmission Provider's Control Area is required to acquire these
Ancillary Services, whether from the Transmission Provider, from a
third party, or by self-supply. The Transmission Customer may not
decline the Transmission Provider's offer of Ancillary Services
unless it demonstrates that it has acquired the Ancillary Services
from another source. The Transmission Customer must list in its
Application which Ancillary Services it will purchase from the
Transmission Provider.
If the Transmission Provider is a public utility providing
transmission service but is not a Control Area operator, it may be
unable to provide some or all of the Ancillary Services. In this
case, the Transmission Provider can fulfill its obligation to
provide Ancillary Services by acting as the Transmission Customer's
agent to secure these Ancillary Services from the Control Area
operator. The Transmission Customer may elect to (i) have the
Transmission Provider act as its agent, (ii) secure the Ancillary
Services directly from the Control Area operator, or (iii) secure
the Ancillary Services (discussed in Schedules 3, 4, 5 and 6) from a
third party or by self-supply when technically feasible.
The Transmission Provider shall specify the rate treatment and
all related terms and conditions in the event of an unauthorized use
of Ancillary Services by the Transmission Customer.
The specific Ancillary Services, prices and/or compensation
methods are described on the Schedules that are attached to and made
a part of the Tariff. If the Transmission Provider offers an
affiliate a rate discount, or attributes a discounted Ancillary
Service rate to its own transactions, the Transmission Provider must
offer at the same time the same discounted Ancillary Service rate to
all Eligible Customers. Information regarding any discounted
Ancillary Service rates must be posted on the OASIS pursuant to Part
37 of the Commission's regulations. In addition, discounts to non-
affiliates must be offered in a not unduly discriminatory manner.
Sections 3.1 through 3.6 below list the six Ancillary Services.
3.1 Scheduling, System Control and Dispatch Service: The rates
and/or methodology are described in Schedule 1.
3.2 Reactive Supply and Voltage Control from Generation Sources
Service: The rates and/or methodology are described in Schedule 2.
3.3 Regulation and Frequency Response Service: Where applicable
the rates and/or methodology are described in Schedule 3.
3.4 Energy Imbalance Service: Where applicable the rates and/or
methodology are described in Schedule 4.
3.5 Operating Reserve--Spinning Reserve Service: Where
applicable the rates and/or methodology are described in Schedule 5.
3.6 Operating Reserve--Supplemental Reserve Service: Where
applicable the rates and/or methodology are described in Schedule 6.
4 Open Access Same-Time Information System (OASIS)
Terms and conditions regarding Open Access Same-Time Information
System and standards of conduct are set forth in 18 CFR part 37 of
the Commission's regulations (Open Access Same-Time Information
System and Standards of Conduct for Public
[[Page 21710]]
Utilities). In the event available transmission capability as posted
on the OASIS is insufficient to accommodate a request for firm
transmission service, additional studies may be required as provided
by this Tariff pursuant to Sections 19 and 32.
5 Local Furnishing Bonds
5.1 Transmission Providers That Own Facilities Financed by
Local Furnishing Bonds: This provision is applicable only to
Transmission Providers that have financed facilities for the local
furnishing of electric energy with tax-exempt bonds, as described in
Section 142(f) of the Internal Revenue Code (``local furnishing
bonds''). Notwithstanding any other provision of this Tariff, the
Transmission Provider shall not be required to provide Transmission
Service to any Eligible Customer pursuant to this Tariff if the
provision of such Transmission Service would jeopardize the tax-
exempt status of any local furnishing bond(s) used to finance the
Transmission Provider's facilities that would be used in providing
such Transmission Service.
5.2 Alternative Procedures for Requesting Transmission Service:
(i) If the Transmission Provider determines that the provision
of transmission service requested by an Eligible Customer would
jeopardize the tax-exempt status of any local furnishing bond(s)
used to finance its facilities that would be used in providing such
transmission service, it shall advise the Eligible Customer within
thirty (30) days of receipt of the Completed Application.
(ii) If the Eligible Customer thereafter renews its request for
the same transmission service referred to in (i) by tendering an
application under Section 211 of the Federal Power Act, the
Transmission Provider, within ten (10) days of receiving a copy of
the Section 211 application, will waive its rights to a request for
service under Section 213(a) of the Federal Power Act and to the
issuance of a proposed order under Section 212(c) of the Federal
Power Act and shall provide the requested transmission service in
accordance with the terms and conditions of this Tariff.
6 Reciprocity
A Transmission Customer receiving transmission service under
this Tariff agrees to provide comparable transmission service to the
Transmission Provider on similar terms and conditions over
facilities used for the transmission of electric energy in
interstate commerce owned, controlled or operated by the
Transmission Customer and over facilities used for the transmission
of electric energy in interstate commerce owned, controlled or
operated by the Transmission Customer's corporate affiliates. A
Transmission Customer that is a member of a power pool or Regional
Transmission Group also agrees to provide comparable transmission
service to the members of such power pool and Regional Transmission
Group on similar terms and conditions over facilities used for the
transmission of electric energy in interstate commerce owned,
controlled or operated by the Transmission Customer and over
facilities used for the transmission of electric energy in
interstate commerce owned, controlled or operated by the
Transmission Customer's corporate affiliates. This reciprocity
requirement also applies to any Eligible Customer that owns,
controls or operates transmission facilities that uses an
intermediary, such as a power marketer, to request transmission
service under the Tariff. If the Transmission Customer does not own,
control or operate transmission facilities, it must include in its
Application a sworn statement of one of its duly authorized officers
or other representatives that the purpose of its Application is not
to assist an Eligible Customer to avoid the requirements of this
provision.
7 Billing and Payment
7.1 Billing Procedure: Within a reasonable time after the first
day of each month, the Transmission Provider shall submit an invoice
to the Transmission Customer for the charges for all services
furnished under the Tariff during the preceding month. The invoice
shall be paid by the Transmission Customer within twenty (20) days
of receipt. All payments shall be made in immediately available
funds payable to the Transmission Provider, or by wire transfer to a
bank named by the Transmission Provider.
7.2 Interest on Unpaid Balances: Interest on any unpaid amounts
(including amounts placed in escrow) shall be calculated in
accordance with the methodology specified for interest on refunds in
the Commission's regulations at 18 CFR 35.19a(a)(2)(iii). Interest
on delinquent amounts shall be calculated from the due date of the
bill to the date of payment. When payments are made by mail, bills
shall be considered as having been paid on the date of receipt by
the Transmission Provider.
7.3 Customer Default: In the event the Transmission Customer
fails, for any reason other than a billing dispute as described
below, to make payment to the Transmission Provider on or before the
due date as described above, and such failure of payment is not
corrected within thirty (30) calendar days after the Transmission
Provider notifies the Transmission Customer to cure such failure, a
default by the Transmission Customer shall be deemed to exist. Upon
the occurrence of a default, the Transmission Provider may initiate
a proceeding with the Commission to terminate service but shall not
terminate service until the Commission so approves any such request.
In the event of a billing dispute between the Transmission Provider
and the Transmission Customer, the Transmission Provider will
continue to provide service under the Service Agreement as long as
the Transmission Customer (i) continues to make all payments not in
dispute, and (ii) pays into an independent escrow account the
portion of the invoice in dispute, pending resolution of such
dispute. If the Transmission Customer fails to meet these two
requirements for continuation of service, then the Transmission
Provider may provide notice to the Transmission Customer of its
intention to suspend service in sixty (60) days, in accordance with
Commission policy.
8 Accounting for the Transmission Provider's Use of the Tariff
The Transmission Provider shall record the following amounts, as
outlined below.
8.1 Transmission Revenues: Include in a separate operating
revenue account or subaccount the revenues it receives from
Transmission Service when making Third-Party Sales under Part II of
the Tariff.
8.2 Study Costs and Revenues: Include in a separate
transmission operating expense account or subaccount, costs properly
chargeable to expense that are incurred to perform any System Impact
Studies or Facilities Studies which the Transmission Provider
conducts to determine if it must construct new transmission
facilities or upgrades necessary for its own uses, including making
Third-Party Sales under the Tariff; and include in a separate
operating revenue account or subaccount the revenues received for
System Impact Studies or Facilities Studies performed when such
amounts are separately stated and identified in the Transmission
Customer's billing under the Tariff.
9 Regulatory Filings
Nothing contained in the Tariff or any Service Agreement shall
be construed as affecting in any way the right of the Transmission
Provider to unilaterally make application to the Commission for a
change in rates, terms and conditions, charges, classification of
service, Service Agreement, rule or regulation under Section 205 of
the Federal Power Act and pursuant to the Commission's rules and
regulations promulgated thereunder.
Nothing contained in the Tariff or any Service Agreement shall
be construed as affecting in any way the ability of any Party
receiving service under the Tariff to exercise its rights under the
Federal Power Act and pursuant to the Commission's rules and
regulations promulgated thereunder.
10 Force Majeure and Indemnification
10.1 Force Majeure: An event of Force Majeure means any act of
God, labor disturbance, act of the public enemy, war, insurrection,
riot, fire, storm or flood, explosion, breakage or accident to
machinery or equipment, any Curtailment, order, regulation or
restriction imposed by governmental military or lawfully established
civilian authorities, or any other cause beyond a Party's control.
Neither the Transmission Provider nor the Transmission Customer will
be considered in default as to any obligation under this Tariff if
prevented from fulfilling the obligation due to an event of Force
Majeure. However, a Party whose performance under this Tariff is
hindered by an event of Force Majeure shall make all reasonable
efforts to perform its obligations under this Tariff.
10.2 Indemnification: The Transmission Customer shall at all
times indemnify, defend, and save the Transmission Provider harmless
from, any and all damages, losses, claims, including claims and
actions relating to injury to or death of any person or damage to
property, demands, suits, recoveries, costs and expenses, court
costs, attorney fees, and all other obligations by or to third
parties,
[[Page 21711]]
arising out of or resulting from the Transmission Provider's
performance of its obligations under this Tariff on behalf of the
Transmission Customer, except in cases of negligence or intentional
wrongdoing by the Transmission Provider.
11 Creditworthiness
For the purpose of determining the ability of the Transmission
Customer to meet its obligations related to service hereunder, the
Transmission Provider may require reasonable credit review
procedures. This review shall be made in accordance with standard
commercial practices. In addition, the Transmission Provider may
require the Transmission Customer to provide and maintain in effect
during the term of the Service Agreement, an unconditional and
irrevocable letter of credit as security to meet its
responsibilities and obligations under the Tariff, or an alternative
form of security proposed by the Transmission Customer and
acceptable to the Transmission Provider and consistent with
commercial practices established by the Uniform Commercial Code that
protects the Transmission Provider against the risk of non-payment.
12 Dispute Resolution Procedures
12.1 Internal Dispute Resolution Procedures: Any dispute
between a Transmission Customer and the Transmission Provider
involving Transmission Service under the Tariff (excluding
applications for rate changes or other changes to the Tariff, or to
any Service Agreement entered into under the Tariff, which shall be
presented directly to the Commission for resolution) shall be
referred to a designated senior representative of the Transmission
Provider and a senior representative of the Transmission Customer
for resolution on an informal basis as promptly as practicable. In
the event the designated representatives are unable to resolve the
dispute within thirty (30) days [or such other period as the Parties
may agree upon] by mutual agreement, such dispute may be submitted
to arbitration and resolved in accordance with the arbitration
procedures set forth below.
12.2 External Arbitration Procedures: Any arbitration initiated
under the Tariff shall be conducted before a single neutral
arbitrator appointed by the Parties. If the Parties fail to agree
upon a single arbitrator within ten (10) days of the referral of the
dispute to arbitration, each Party shall choose one arbitrator who
shall sit on a three-member arbitration panel. The two arbitrators
so chosen shall within twenty (20) days select a third arbitrator to
chair the arbitration panel. In either case, the arbitrators shall
be knowledgeable in electric utility matters, including electric
transmission and bulk power issues, and shall not have any current
or past substantial business or financial relationships with any
party to the arbitration (except prior arbitration). The
arbitrator(s) shall provide each of the Parties an opportunity to be
heard and, except as otherwise provided herein, shall generally
conduct the arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association and any
applicable Commission regulations or Regional Transmission Group
rules.
12.3 Arbitration Decisions: Unless otherwise agreed, the
arbitrator(s) shall render a decision within ninety (90) days of
appointment and shall notify the Parties in writing of such decision
and the reasons therefor. The arbitrator(s) shall be authorized only
to interpret and apply the provisions of the Tariff and any Service
Agreement entered into under the Tariff and shall have no power to
modify or change any of the above in any manner. The decision of the
arbitrator(s) shall be final and binding upon the Parties, and
judgment on the award may be entered in any court having
jurisdiction. The decision of the arbitrator(s) may be appealed
solely on the grounds that the conduct of the arbitrator(s), or the
decision itself, violated the standards set forth in the Federal
Arbitration Act and/or the Administrative Dispute Resolution Act.
The final decision of the arbitrator must also be filed with the
Commission if it affects jurisdictional rates, terms and conditions
of service or facilities.
12.4 Costs: Each Party shall be responsible for its own costs
incurred during the arbitration process and for the following costs,
if applicable:
(A) The cost of the arbitrator chosen by the Party to sit on the
three member panel and one half of the cost of the third arbitrator
chosen; or
(B) One half the cost of the single arbitrator jointly chosen by
the Parties.
12.5 Rights Under the Federal Power Act: Nothing in this
section shall restrict the rights of any party to file a Complaint
with the Commission under relevant provisions of the Federal Power
Act.
II. Point-To-Point Transmission Service
Preamble
The Transmission Provider will provide Firm and Non-Firm Point-
To-Point Transmission Service pursuant to the applicable terms and
conditions of this Tariff. Point-To-Point Transmission Service is
for the receipt of capacity and energy at designated Point(s) of
Receipt and the transmission of such capacity and energy to
designated Point(s) of Delivery.
13 Nature of Firm Point-To-Point Transmission Service
13.1 Term: The minimum term of Firm Point-To-Point Transmission
Service shall be one day and the maximum term shall be specified in
the Service Agreement.
13.2 Reservation Priority: Long-Term Firm Point-To-Point
Transmission Service shall be available on a first-come, first-
served basis i.e., in the chronological sequence in which each
Transmission Customer has reserved service. Reservations for Short-
Term Firm Point-To-Point Transmission Service will be conditional
based upon the length of the requested transaction. If the
Transmission System becomes oversubscribed, requests for longer term
service may preempt requests for shorter term service up to the
following deadlines: one day before the commencement of daily
service, one week before the commencement of weekly service, and one
month before the commencement of monthly service. Before the
deadline, if available transmission capability is insufficient to
satisfy all Applications, an Eligible Customer with a reservation
for shorter term service has the right of first refusal to match any
longer term reservation before losing its reservation priority.
After the deadline, service will commence pursuant to the terms of
Part II of the Tariff. Firm Point-To-Point Transmission Service will
always have a reservation priority over Non-Firm Point-To-Point
Transmission Service under the Tariff. All Long-Term Firm Point-To-
Point Transmission Service will have equal reservation priority with
Native Load Customers and Network Customers. Reservation priorities
for existing firm service customers are provided in Section 2.2.
13.3 Use of Firm Transmission Service by the Transmission
Provider: The Transmission Provider will be subject to the rates,
terms and conditions of Part II of the Tariff when making Third-
Party Sales under (i) agreements executed on or after July 9, 1996,
or (ii) agreements executed prior to the aforementioned date that
the Commission requires to be unbundled, by the date specified by
the Commission. The Transmission Provider will maintain separate
accounting, pursuant to Section 8, for any use of the Point-To-Point
Transmission Service to make Third-Party Sales.
13.4 Service Agreements: The Transmission Provider shall offer
a standard form Firm Point-To-Point Transmission Service Agreement
(Attachment A) to an Eligible Customer when it submits a Completed
Application for Firm Point-To-Point Transmission Service. Executed
Service Agreements that contain the information required under the
Tariff shall be filed with the Commission in compliance with
applicable Commission regulations.
13.5 Transmission Customer Obligations for Facility Additions
or Redispatch Costs: In cases where the Transmission Provider
determines that the Transmission System is not capable of providing
Firm Point-To-Point Transmission Service without (1) degrading or
impairing the reliability of service to Native Load Customers,
Network Customers and other Transmission Customers taking Firm
Point-To-Point Transmission Service, or (2) interfering with the
Transmission Provider's ability to meet prior firm contractual
commitments to others, the Transmission Provider will be obligated
to expand or upgrade its Transmission System pursuant to the terms
of Section 15.4. The Transmission Customer must agree to compensate
the Transmission Provider for any necessary transmission facility
additions pursuant to the terms of Section 27. To the extent the
Transmission Provider can relieve any system constraint more
economically by redispatching the Transmission Provider's resources
than through constructing Network Upgrades, it shall do so, provided
that the Eligible Customer agrees to compensate the Transmission
Provider pursuant to the terms of Section 27. Any redispatch,
Network Upgrade or Direct Assignment Facilities costs to be charged
to the Transmission Customer under the Tariff will be specified in
the Service Agreement prior to initiating service.
[[Page 21712]]
13.6 Curtailment of Firm Transmission Service: In the event
that a Curtailment on the Transmission Provider's Transmission
System, or a portion thereof, is required to maintain reliable
operation of such system, Curtailments will be made on a non-
discriminatory basis to the transaction(s) that effectively relieve
the constraint. If multiple transactions require Curtailment, to the
extent practicable and consistent with Good Utility Practice,
Curtailments will be proportionally allocated among the Transmission
Provider's Native Load Customers, Network Customers, and
Transmission Customers taking Firm Point-To-Point Transmission
Service. All Curtailments will be made on a non-discriminatory
basis, however, Non-Firm Point-To-Point Transmission Service shall
be subordinate to Firm Transmission Service. When the Transmission
Provider determines that an electrical emergency exists on its
Transmission System and implements emergency procedures to Curtail
Firm Transmission Service, the Transmission Customer shall make the
required reductions upon request of the Transmission Provider.
However, the Transmission Provider reserves the right to Curtail, in
whole or in part, any Firm Transmission Service provided under the
Tariff when, in the Transmission Provider's sole discretion, an
emergency or other unforeseen condition impairs or degrades the
reliability of its Transmission System. The Transmission Provider
will notify all affected Transmission Customers in a timely manner
of any scheduled Curtailments.
13.7 Classification of Firm Transmission Service:
(a) The Transmission Customer taking Firm Point-To-Point
Transmission Service may (1) change its Receipt and Delivery Points
to obtain service on a non-firm basis consistent with the terms of
Section 22.1 or (2) request a modification of the Points of Receipt
or Delivery on a firm basis pursuant to the terms of Section 22.2.
(b) The Transmission Customer may purchase transmission service
to make sales of capacity and energy from multiple generating units
that are on the Transmission Provider's Transmission System. For
such a purchase of transmission service, the resources will be
designated as multiple Points of Receipt, unless the multiple
generating units are at the same generating plant in which case the
units would be treated as a single Point of Receipt.
(c) The Transmission Provider shall provide firm deliveries of
capacity and energy from the Point(s) of Receipt to the Point(s) of
Delivery. Each Point of Receipt at which firm transmission capacity
is reserved by the Transmission Customer shall be set forth in the
Firm Point-To-Point Service Agreement along with a corresponding
capacity reservation associated with each Point of Receipt. Each
Point of Delivery at which firm transmission capacity is reserved by
the Transmission Customer shall be set forth in the Firm Point-To-
Point Service Agreement along with a corresponding capacity
reservation associated with each Point of Delivery. The greater of
either (1) the sum of the capacity reservations at the Point(s) of
Receipt, or (2) the sum of the capacity reservations at the Point(s)
of Delivery shall be the Transmission Customer's Reserved Capacity.
The Transmission Customer will be billed for its Reserved Capacity
under the terms of Schedule 7. The Transmission Customer may not
exceed its firm capacity reserved at each Point of Receipt and each
Point of Delivery except as otherwise specified in Section 22. The
Transmission Provider shall specify the rate treatment and all
related terms and conditions applicable in the event that a
Transmission Customer (including Third-Party Sales by the
Transmission Provider) exceeds its firm reserved capacity at any
Point of Receipt or Point of Delivery.
13.8 Scheduling of Firm Point-To-Point Transmission Service:
Schedules for the Transmission Customer's Firm Point-To-Point
Transmission Service must be submitted to the Transmission Provider
no later than 10:00 a.m. [or a reasonable time that is generally
accepted in the region and is consistently adhered to by the
Transmission Provider] of the day prior to commencement of such
service. Schedules submitted after 10:00 a.m. will be accommodated,
if practicable. Hour-to-hour schedules of any capacity and energy
that is to be delivered must be stated in increments of 1,000 kW per
hour (or a reasonable increment that is generally accepted in the
region and is consistently adhered to by the Transmission Provider).
Transmission Customers within the Transmission Provider's service
area with multiple requests for Transmission Service at a Point of
Receipt, each of which is under 1,000 kW per hour, may consolidate
their service requests at a common point of receipt into units of
1,000 kW per hour for scheduling and billing purposes. Scheduling
changes will be permitted up to twenty (20) minutes (or a reasonable
time that is generally accepted in the region and is consistently
adhered to by the Transmission Provider) before the start of the
next clock hour provided that the Delivering Party and Receiving
Party also agree to the schedule modification. The Transmission
Provider will furnish to the Delivering Party's system operator,
hour-to-hour schedules equal to those furnished by the Receiving
Party (unless reduced for losses) and shall deliver the capacity and
energy provided by such schedules. Should the Transmission Customer,
Delivering Party or Receiving Party revise or terminate any
schedule, such party shall immediately notify the Transmission
Provider, and the Transmission Provider shall have the right to
adjust accordingly the schedule for capacity and energy to be
received and to be delivered.
14 Nature of Non-Firm Point-To-Point Transmission Service
14.1 Term: Non-Firm Point-To-Point Transmission Service will be
available for periods ranging from one (1) hour to one (1) month.
However, a Purchaser of Non-Firm Point-To-Point Transmission Service
will be entitled to reserve a sequential term of service (such as a
sequential monthly term without having to wait for the initial term
to expire before requesting another monthly term) so that the total
time period for which the reservation applies is greater than one
month, subject to the requirements of Section 18.3.
14.2 Reservation Priority: Non-Firm Point-To-Point Transmission
Service shall be available from transmission capability in excess of
that needed for reliable service to Native Load Customers, Network
Customers and other Transmission Customers taking Long-Term and
Short-Term Firm Point-To-Point Transmission Service. A higher
priority will be assigned to reservations with a longer duration of
service. In the event the Transmission System is constrained,
competing requests of equal duration will be prioritized based on
the highest price offered by the Eligible Customer for the
Transmission Service. Eligible Customers that have already reserved
shorter term service have the right of first refusal to match any
longer term reservation before being preempted. Transmission service
for Network Customers from resources other than designated Network
Resources will have a higher priority than any Non-Firm Point-To-
Point Transmission Service. Non-Firm Point-To-Point Transmission
Service over secondary Point(s) of Receipt and Point(s) of Delivery
will have the lowest reservation priority under the Tariff.
14.3 Use of Non-Firm Point-To-Point Transmission Service by the
Transmission Provider: The Transmission Provider will be subject to
the rates, terms and conditions of Part II of the Tariff when making
Third-Party Sales under (i) agreements executed on or after July 9,
1996 or (ii) agreements executed prior to the aforementioned date
that the Commission requires to be unbundled, by the date specified
by the Commission. The Transmission Provider will maintain separate
accounting, pursuant to Section 8, for any use of Non-Firm Point-To-
Point Transmission Service to make Third-Party Sales.
14.4 Service Agreements: The Transmission Provider shall offer
a standard form Non-Firm Point-To-Point Transmission Service
Agreement (Attachment B) to an Eligible Customer when it first
submits a Completed Application for Non-Firm Point-To-Point
Transmission Service pursuant to the Tariff. Executed Service
Agreements that contain the information required under the Tariff
shall be filed with the Commission in compliance with applicable
Commission regulations.
14.5 Classification of Non-Firm Point-To-Point Transmission
Service: Non-Firm Point-To-Point Transmission Service shall be
offered under terms and conditions contained in Part II of the
Tariff. The Transmission Provider undertakes no obligation under the
Tariff to plan its Transmission System in order to have sufficient
capacity for Non-Firm Point-To-Point Transmission Service. Parties
requesting Non-Firm Point-To-Point Transmission Service for the
transmission of firm power do so with the full realization that such
service is subject to availability and to Curtailment or
Interruption under the terms of the Tariff. The Transmission
Provider shall specify the rate treatment and all related terms and
conditions applicable in
[[Page 21713]]
the event that a Transmission Customer (including Third-Party Sales
by the Transmission Provider) exceeds its non-firm capacity
reservation. Non-Firm Point-To-Point Transmission Service shall
include transmission of energy on an hourly basis and transmission
of scheduled short-term capacity and energy on a daily, weekly or
monthly basis, but not to exceed one month's reservation for any one
Application, under Schedule 8.
14.6 Scheduling of Non-Firm Point-To-Point Transmission Service:
Schedules for Non-Firm Point-To-Point Transmission Service must be
submitted to the Transmission Provider no later than 2:00 p.m. [or a
reasonable time that is generally accepted in the region and is
consistently adhered to by the Transmission Provider] of the day
prior to commencement of such service. Schedules submitted after
2:00 p.m. will be accommodated, if practicable. Hour-to-hour
schedules of energy that is to be delivered must be stated in
increments of 1,000 kW per hour [or a reasonable increment that is
generally accepted in the region and is consistently adhered to by
the Transmission Provider]. Transmission Customers within the
Transmission Provider's service area with multiple requests for
Transmission Service at a Point of Receipt, each of which is under
1,000 kW per hour, may consolidate their schedules at a common Point
of Receipt into units of 1,000 kW per hour. Scheduling changes will
be permitted up to twenty (20) minutes [or a reasonable time that is
generally accepted in the region and is consistently adhered to by
the Transmission Provider] before the start of the next clock hour
provided that the Delivering Party and Receiving Party also agree to
the schedule modification. The Transmission Provider will furnish to
the Delivering Party's system operator, hour-to-hour schedules equal
to those furnished by the Receiving Party (unless reduced for
losses) and shall deliver the capacity and energy provided by such
schedules. Should the Transmission Customer, Delivering Party or
Receiving Party revise or terminate any schedule, such party shall
immediately notify the Transmission Provider, and the Transmission
Provider shall have the right to adjust accordingly the schedule for
capacity and energy to be received and to be delivered.
14.7 Curtailment or Interruption of Service: The Transmission
Provider reserves the right to Curtail, in whole or in part, Non-
Firm Point-To-Point Transmission Service provided under the Tariff
for reliability reasons when, an emergency or other unforeseen
condition threatens to impair or degrade the reliability of its
Transmission System. The Transmission Provider reserves the right to
Interrupt, in whole or in part, Non-Firm Point-To-Point Transmission
Service provided under the Tariff for economic reasons in order to
accommodate (1) a request for Firm Transmission Service, (2) a
request for Non-Firm Point-To-Point Transmission Service of greater
duration, (3) a request for Non-Firm Point-To-Point Transmission
Service of equal duration with a higher price, or (4) transmission
service for Network Customers from non-designated resources. The
Transmission Provider also will discontinue or reduce service to the
Transmission Customer to the extent that deliveries for transmission
are discontinued or reduced at the Point(s) of Receipt. Where
required, Curtailments or Interruptions will be made on a non-
discriminatory basis to the transaction(s) that effectively relieve
the constraint, however, Non-Firm Point-To-Point Transmission
Service shall be subordinate to Firm Transmission Service. If
multiple transactions require Curtailment or Interruption, to the
extent practicable and consistent with Good Utility Practice,
Curtailments or Interruptions will be made to transactions of the
shortest term (e.g., hourly non-firm transactions will be Curtailed
or Interrupted before daily non-firm transactions and daily non-firm
transactions will be Curtailed or Interrupted before weekly non-firm
transactions). Transmission service for Network Customers from
resources other than designated Network Resources will have a higher
priority than any Non-Firm Point-To-Point Transmission Service under
the Tariff. Non-Firm Point-To-Point Transmission Service over
secondary Point(s) of Receipt and Point(s) of Delivery will have a
lower priority than any Non-Firm Point-To-Point Transmission Service
under the Tariff. The Transmission Provider will provide advance
notice of Curtailment or Interruption where such notice can be
provided consistent with Good Utility Practice.
15 Service Availability
15.1 General Conditions: The Transmission Provider will provide
Firm and Non-Firm Point-To-Point Transmission Service over, on or
across its Transmission System to any Transmission Customer that has
met the requirements of Section 16.
15.2 Determination of Available Transmission Capability: A
description of the Transmission Provider's specific methodology for
assessing available transmission capability posted on the
Transmission Provider's OASIS (Section 4) is contained in Attachment
C of the Tariff. In the event sufficient transmission capability may
not exist to accommodate a service request, the Transmission
Provider will respond by performing a System Impact Study.
15.3 Initiating Service in the Absence of an Executed Service
Agreement: If the Transmission Provider and the Transmission
Customer requesting Firm or Non-Firm Point-To-Point Transmission
Service cannot agree on all the terms and conditions of the Point-
To-Point Service Agreement, the Transmission Provider shall file
with the Commission, within thirty (30) days after the date the
Transmission Customer provides written notification directing the
Transmission Provider to file, an unexecuted Point-To-Point Service
Agreement containing terms and conditions deemed appropriate by the
Transmission Provider for such requested Transmission Service. The
Transmission Provider shall commence providing Transmission Service
subject to the Transmission Customer agreeing to (i) compensate the
Transmission Provider at whatever rate the Commission ultimately
determines to be just and reasonable, and (ii) comply with the terms
and conditions of the Tariff including posting appropriate security
deposits in accordance with the terms of Section 17.3.
15.4 Obligation to Provide Transmission Service that Requires
Expansion or Modification of the Transmission System: If the
Transmission Provider determines that it cannot accommodate a
Completed Application for Firm Point-To-Point Transmission Service
because of insufficient capability on its Transmission System, the
Transmission Provider will use due diligence to expand or modify its
Transmission System to provide the reque
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
sted Firm Transmission
Service, provided the Transmission Customer agrees to compensate the
Transmission Provider for such costs pursuant to the terms of
Section 27. The Transmission Provider will conform to Good Utility
Practice in determining the need for new facilities and in the
design and construction of such facilities. The obligation applies
only to those facilities that the Transmission Provider has the
right to expand or modify.
15.5 Deferral of Service: The Transmission Provider may defer
providing service until it completes construction of new
transmission facilities or upgrades needed to provide Firm Point-To-
Point Transmission Service whenever the Transmission Provider
determines that providing the requested service would, without such
new facilities or upgrades, impair or degrade reliability to any
existing firm services.
15.6 Other Transmission Service Schedules: Eligible Customers
receiving transmission service under other agreements on file with
the Commission may continue to receive transmission service under
those agreements until such time as those agreements may be modified
by the Commission.
15.7 Real Power Losses: Real Power Losses are associated with
all transmission service. The Transmission Provider is not obligated
to provide Real Power Losses. The Transmission Customer is
responsible for replacing losses associated with all transmission
service as calculated by the Transmission Provider. The applicable
Real Power Loss factors are as follows: [To be completed by the
Transmission Provider].
16 Transmission Customer Responsibilities
16.1 Conditions Required of Transmission Customers: Point-To-
Point Transmission Service shall be provided by the Transmission
Provider only if the following conditions are satisfied by the
Transmission Customer:
a. The Transmission Customer has pending a Completed Application
for service;
b. The Transmission Customer meets the creditworthiness criteria
set forth in Section 11;
c. The Transmission Customer will have arrangements in place for
any other transmission service necessary to effect the delivery from
the generating source to the Transmission Provider prior to the time
service under Part II of the Tariff commences;
d. The Transmission Customer agrees to pay for any facilities
constructed and
[[Page 21714]]
chargeable to such Transmission Customer under Part II of the
Tariff, whether or not the Transmission Customer takes service for
the full term of its reservation; and
e. The Transmission Customer has executed a Point-To-Point
Service Agreement or has agreed to receive service pursuant to
Section 15.3.
16.2 Transmission Customer Responsibility for Third-Party
Arrangements: Any scheduling arrangements that may be required by
other electric systems shall be the responsibility of the
Transmission Customer requesting service. The Transmission Customer
shall provide, unless waived by the Transmission Provider,
notification to the Transmission Provider identifying such systems
and authorizing them to schedule the capacity and energy to be
transmitted by the Transmission Provider pursuant to Part II of the
Tariff on behalf of the Receiving Party at the Point of Delivery or
the Delivering Party at the Point of Receipt. However, the
Transmission Provider will undertake reasonable efforts to assist
the Transmission Customer in making such arrangements, including
without limitation, providing any information or data required by
such other electric system pursuant to Good Utility Practice.
17 Procedures for Arranging Firm Point-To-Point Transmission
Service
17.1 Application: A request for Firm Point-To-Point
Transmission Service for periods of one year or longer must contain
a written Application to: [Transmission Provider Name and Address],
at least sixty (60) days in advance of the calendar month in which
service is to commence. The Transmission Provider will consider
requests for such firm service on shorter notice when feasible.
Requests for firm service for periods of less than one year shall be
subject to expedited procedures that shall be negotiated between the
Parties within the time constraints provided in Section 17.5. All
Firm Point-To-Point Transmission Service requests should be
submitted by entering the information listed below on the
Transmission Provider's OASIS. Prior to implementation of the
Transmission Provider's OASIS, a Completed Application may be
submitted by (i) transmitting the required information to the
Transmission Provider by telefax, or (ii) providing the information
by telephone over the Transmission Provider's time recorded
telephone line. Each of these methods will provide a time-stamped
record for establishing the priority of the Application.
17.2 Completed Application: A Completed Application shall
provide all of the information included in 18 CFR Sec. 2.20
including but not limited to the following:
(i) The identity, address, telephone number and facsimile number
of the entity requesting service;
(ii) A statement that the entity requesting service is, or will
be upon commencement of service, an Eligible Customer under the
Tariff;
(iii) The location of the Point(s) of Receipt and Point(s) of
Delivery and the identities of the Delivering Parties and the
Receiving Parties;
(iv) The location of the generating facility(ies) supplying the
capacity and energy and the location of the load ultimately served
by the capacity and energy transmitted. The Transmission Provider
will treat this information as confidential except to the extent
that disclosure of this information is required by this Tariff, by
regulatory or judicial order, for reliability purposes pursuant to
Good Utility Practice or pursuant to RTG transmission information
sharing agreements. The Transmission Provider shall treat this
information consistent with the standards of conduct contained in
Part 37 of the Commission's regulations;
(v) A description of the supply characteristics of the capacity
and energy to be delivered;
(vi) An estimate of the capacity and energy expected to be
delivered to the Receiving Party;
(vii) The Service Commencement Date and the term of the
requested Transmission Service; and
(viii) The transmission capacity requested for each Point of
Receipt and each Point of Delivery on the Transmission Provider's
Transmission System; customers may combine their requests for
service in order to satisfy the minimum transmission capacity
requirement.
The Transmission Provider shall treat this information
consistent with the standards of conduct contained in Part 37 of the
Commission's regulations.
17.3 Deposit: A Completed Application for Firm Point-To-Point
Transmission Service also shall include a deposit of either one
month's charge for Reserved Capacity or the full charge for Reserved
Capacity for service requests of less than one month. If the
Application is rejected by the Transmission Provider because it does
not meet the conditions for service as set forth herein, or in the
case of requests for service arising in connection with losing
bidders in a Request For Proposals (RFP), said deposit shall be
returned with interest less any reasonable costs incurred by the
Transmission Provider in connection with the review of the losing
bidder's Application. The deposit also will be returned with
interest less any reasonable costs incurred by the Transmission
Provider if the Transmission Provider is unable to complete new
facilities needed to provide the service. If an Application is
withdrawn or the Eligible Customer decides not to enter into a
Service Agreement for Firm Point-To-Point Transmission Service, the
deposit shall be refunded in full, with interest, less reasonable
costs incurred by the Transmission Provider to the extent such costs
have not already been recovered by the Transmission Provider from
the Eligible Customer. The Transmission Provider will provide to the
Eligible Customer a complete accounting of all costs deducted from
the refunded deposit, which the Eligible Customer may contest if
there is a dispute concerning the deducted costs. Deposits
associated with construction of new facilities are subject to the
provisions of Section 19. If a Service Agreement for Firm Point-To-
Point Transmission Service is executed, the deposit, with interest,
will be returned to the Transmission Customer upon expiration of the
Service Agreement for Firm Point-To-Point Transmission Service.
Applicable interest shall be computed in accordance with the
Commission's regulations at 18 CFR Sec. 35.19a(a)(2)(iii), and shall
be calculated from the day the deposit check is credited to the
Transmission Provider's account.
17.4 Notice of Deficient Application: If an Application fails
to meet the requirements of the Tariff, the Transmission Provider
shall notify the entity requesting service within fifteen (15) days
of receipt of the reasons for such failure. The Transmission
Provider will attempt to remedy minor deficiencies in the
Application through informal communications with the Eligible
Customer. If such efforts are unsuccessful, the Transmission
Provider shall return the Application, along with any deposit, with
interest. Upon receipt of a new or revised Application that fully
complies with the requirements of Part II of the Tariff, the
Eligible Customer shall be assigned a new priority consistent with
the date of the new or revised Application.
17.5 Response to a Completed Application: Following receipt of
a Completed Application for Firm Point-To-Point Transmission
Service, the Transmission Provider shall make a determination of
available transmission capability as required in Section 15.2. The
Transmission Provider shall notify the Eligible Customer as soon as
practicable, but not later than thirty (30) days after the date of
receipt of a Completed Application either (i) if it will be able to
provide service without performing a System Impact Study or (ii) if
such a study is needed to evaluate the impact of the Application
pursuant to Section 19.1.
17.6 Execution of Service Agreement: Whenever the Transmission
Provider determines that a System Impact Study is not required and
that the service can be provided, it shall notify the Eligible
Customer as soon as practicable but no later than thirty (30) days
after receipt of the Completed Application. Where a System Impact
Study is required, the provisions of Section 19 will govern the
execution of a Service Agreement. Failure of an Eligible Customer to
execute and return the Service Agreement or request the filing of an
unexecuted service agreement pursuant to Section 15.3, within
fifteen (15) days after it is tendered by the Transmission Provider
will be deemed a withdrawal and termination of the Application and
any deposit submitted shall be refunded with interest. Nothing
herein limits the right of an Eligible Customer to file another
Application after such withdrawal and termination.
17.7 Extensions for Commencement of Service: The Transmission
Customer can obtain up to five (5) one-year extensions for the
commencement of service. The Transmission Customer may postpone
service by paying a non-refundable annual reservation fee equal to
one-month's charge for Firm Transmission Service for each year or
fraction thereof. If during any extension for the commencement of
service an Eligible Customer submits a Completed Application for
Firm Transmission Service, and such request can be satisfied only by
releasing all or part of the Transmission Customer's Reserved
Capacity, the original Reserved
[[Page 21715]]
Capacity will be released unless the following condition is
satisfied. Within thirty (30) days, the original Transmission
Customer agrees to pay the Firm Point-To-Point transmission rate for
its Reserved Capacity concurrent with the new Service Commencement
Date. In the event the Transmission Customer elects to release the
Reserved Capacity, the reservation fees or portions thereof
previously paid will be forfeited.
18 Procedures for Arranging Non-Firm Point-To-Point Transmission
Service
18.1 Application: Eligible Customers seeking Non-Firm Point-To-
Point Transmission Service must submit a Completed Application to
the Transmission Provider. Applications should be submitted by
entering the information listed below on the Transmission Provider's
OASIS. Prior to implementation of the Transmission Provider's OASIS,
a Completed Application may be submitted by (i) transmitting the
required information to the Transmission Provider by telefax, or
(ii) providing the information by telephone over the Transmission
Provider's time recorded telephone line. Each of these methods will
provide a time-stamped record for establishing the service priority
of the Application.
18.2 Completed Application: A Completed Application shall
provide all of the information included in 18 CFR Sec. 2.20
including but not limited to the following:
(i) The identity, address, telephone number and facsimile
number of the entity requesting service;
(ii) A statement that the entity requesting service is, or will
be upon commencement of service, an Eligible Customer under the
Tariff;
(iii) The Point(s) of Receipt and the Point(s) of Delivery;
(iv) The maximum amount of capacity requested at each Point of
Receipt and Point of Delivery; and
(v) The proposed dates and hours for initiating and terminating
transmission service hereunder.
In addition to the information specified above, when required
to properly evaluate system conditions, the Transmission Provider
also may ask the Transmission Customer to provide the following:
(vi) The electrical location of the initial source of the power
to be transmitted pursuant to the Transmission Customer's request
for service; and
(vii) The electrical location of the ultimate load.
The Transmission Provider will treat this information in (vi)
and (vii) as confidential at the request of the Transmission
Customer except to the extent that disclosure of this information is
required by this Tariff, by regulatory or judicial order, for
reliability purposes pursuant to Good Utility Practice, or pursuant
to RTG transmission information sharing agreements. The Transmission
Provider shall treat this information consistent with the standards
of conduct contained in Part 37 of the Commission's regulations.
18.3 Reservation of Non-Firm Point-To-Point Transmission
Service: Requests for monthly service shall be submitted no earlier
than sixty (60) days before service is to commence; requests for
weekly service shall be submitted no earlier than fourteen (14) days
before service is to commence, requests for daily service shall be
submitted no earlier than two (2) days before service is to
commence, and requests for hourly service shall be submitted no
earlier than noon the day before service is to commence. Requests
for service received later than 2:00 p.m. prior to the day service
is scheduled to commence will be accommodated if practicable [or
such reasonable times that are generally accepted in the region and
are consistently adhered to by the Transmission Provider].
18.4 Determination of Available Transmission Capability:
Following receipt of a tendered schedule the Transmission Provider
will make a determination on a non-discriminatory basis of available
transmission capability pursuant to Section 15.2. Such determination
shall be made as soon as reasonably practicable after receipt, but
not later than the following time periods for the following terms of
service (i) thirty (30) minutes for hourly service, (ii) thirty (30)
minutes for daily service, (iii) four (4) hours for weekly service,
and (iv) two (2) days for monthly service. [Or such reasonable times
that are generally accepted in the region and are consistently
adhered to by the Transmission Provider].
19 Additional Study Procedures for Firm Point-To-Point
Transmission Service Requests
19.1 Notice of Need for System Impact Study: After receiving a
request for service, the Transmission Provider shall determine on a
non-discriminatory basis whether a System Impact Study is needed. A
description of the Transmission Provider's methodology for
completing a System Impact Study is provided in Attachment D. If the
Transmission Provider determines that a System Impact Study is
necessary to accommodate the requested service, it shall so inform
the Eligible Customer, as soon as practicable. In such cases, the
Transmission Provider shall within thirty (30) days of receipt of a
Completed Application, tender a System Impact Study Agreement
pursuant to which the Eligible Customer shall agree to reimburse the
Transmission Provider for performing the required System Impact
Study. For a service request to remain a Completed Application, the
Eligible Customer shall execute the System Impact Study Agreement
and return it to the Transmission Provider within fifteen (15) days.
If the Eligible Customer elects not to execute the System Impact
Study Agreement, its application shall be deemed withdrawn and its
deposit, pursuant to Section 17.3, shall be returned with interest.
19.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study Agreement will clearly specify the
maximum charge, based on the Transmission Provider's estimate of the
actual cost, and time for completion of the System Impact Study. The
charge shall not exceed the actual cost of the study. In performing
the System Impact Study, the Transmission Provider shall rely, to
the extent reasonably practicable, on existing transmission planning
studies. The Eligible Customer will not be assessed a charge for
such existing studies; however, the Eligible Customer will be
responsible for charges associated with any modifications to
existing planning studies that are reasonably necessary to evaluate
the impact of the Eligible Customer's request for service on the
Transmission System.
(ii) If in response to multiple Eligible Customers requesting
service in relation to the same competitive solicitation, a single
System Impact Study is sufficient for the Transmission Provider to
accommodate the requests for service, the costs of that study shall
be pro-rated among the Eligible Customers.
(iii) For System Impact Studies that the Transmission Provider
conducts on its own behalf, the Transmission Provider shall record
the cost of the System Impact Studies pursuant to Section 20.
19.3 System Impact Study Procedures: Upon receipt of an
executed System Impact Study Agreement, the Transmission Provider
will use due diligence to complete the required System Impact Study
within a sixty (60) day period. The System Impact Study shall
identify any system constraints and redispatch options, additional
Direct Assignment Facilities or Network Upgrades required to provide
the requested service. In the event that the Transmission Provider
is unable to complete the required System Impact Study within such
time period, it shall so notify the Eligible Customer and provide an
estimated completion date along with an explanation of the reasons
why additional time is required to complete the required studies. A
copy of the completed System Impact Study and related work papers
shall be made available to the Eligible Customer. The Transmission
Provider will use the same due diligence in completing the System
Impact Study for an Eligible Customer as it uses when completing
studies for itself. The Transmission Provider shall notify the
Eligible Customer immediately upon completion of the System Impact
Study if the Transmission System will be adequate to accommodate all
or part of a request for service or that no costs are likely to be
incurred for new transmission facilities or upgrades. In order for a
request to remain a Completed Application, within fifteen (15) days
of completion of the System Impact Study the Eligible Customer must
execute a Service Agreement or request the filing of an unexecuted
Service Agreement pursuant to Section 15.3, or the Application shall
be deemed terminated and withdrawn.
19.4 Facilities Study Procedures: If a System Impact Study
indicates that additions or upgrades to the Transmission System are
needed to supply the Eligible Customer's service request, the
Transmission Provider, within thirty (30) days of the completion of
the System Impact Study, shall tender to the Eligible Customer a
Facilities Study Agreement pursuant to which the Eligible Customer
shall agree to reimburse the Transmission Provider for performing
the required Facilities Study. For a service request to remain a
Completed Application, the Eligible Customer shall execute the
[[Page 21716]]
Facilities Study Agreement and return it to the Transmission
Provider within fifteen (15) days. If the Eligible Customer elects
not to execute the Facilities Study Agreement, its application shall
be deemed withdrawn and its deposit, pursuant to Section 17.3, shall
be returned with interest. Upon receipt of an executed Facilities
Study Agreement, the Transmission Provider will use due diligence to
complete the required Facilities Study within a sixty (60) day
period. If the Transmission Provider is unable to complete the
Facilities Study in the allotted time period, the Transmission
Provider shall notify the Transmission Customer and provide an
estimate of the time needed to reach a final determination along
with an explanation of the reasons that additional time is required
to complete the study. When completed, the Facilities Study will
include a good faith estimate of (i) the cost of Direct Assignment
Facilities to be charged to the Transmission Customer, (ii) the
Transmission Customer's appropriate share of the cost of any
required Network Upgrades as determined pursuant to the provisions
of Part II of the Tariff, and (iii) the time required to complete
such construction and initiate the requested service. The
Transmission Customer shall provide the Transmission Provider with a
letter of credit or other reasonable form of security acceptable to
the Transmission Provider equivalent to the costs of new facilities
or upgrades consistent with commercial practices as established by
the Uniform Commercial Code. The Transmission Customer shall have
thirty (30) days to execute a Service Agreement or request the
filing of an unexecuted Service Agreement and provide the required
letter of credit or other form of security or the request will no
longer be a Completed Application and shall be deemed terminated and
withdrawn.
19.5 Facilities Study Modifications: Any change in design
arising from inability to site or construct facilities as proposed
will require development of a revised good faith estimate. New good
faith estimates also will be required in the event of new statutory
or regulatory requirements that are effective before the completion
of construction or other circumstances beyond the control of the
Transmission Provider that significantly affect the final cost of
new facilities or upgrades to be charged to the Transmission
Customer pursuant to the provisions of Part II of the Tariff.
19.6 Due Diligence in Completing New Facilities: The
Transmission Provider shall use due diligence to add necessary
facilities or upgrade its Transmission System within a reasonable
time. The Transmission Provider will not upgrade its existing or
planned Transmission System in order to provide the requested Firm
Point-To-Point Transmission Service if doing so would impair system
reliability or otherwise impair or degrade existing firm service.
19.7 Partial Interim Service: If the Transmission Provider
determines that it will not have adequate transmission capability to
satisfy the full amount of a Completed Application for Firm Point-
To-Point Transmission Service, the Transmission Provider nonetheless
shall be obligated to offer and provide the portion of the requested
Firm Point-To-Point Transmission Service that can be accommodated
without addition of any facilities and through redispatch. However,
the Transmission Provider shall not be obligated to provide the
incremental amount of requested Firm Point-To-Point Transmission
Service that requires the addition of facilities or upgrades to the
Transmission System until such facilities or upgrades have been
placed in service.
19.8 Expedited Procedures for New Facilities: In lieu of the
procedures set forth above, the Eligible Customer shall have the
option to expedite the process by requesting the Transmission
Provider to tender at one time, together with the results of
required studies, an ``Expedited Service Agreement'' pursuant to
which the Eligible Customer would agree to compensate the
Transmission Provider for all costs incurred pursuant to the terms
of the Tariff. In order to exercise this option, the Eligible
Customer shall request in writing an expedited Service Agreement
covering all of the above-specified items within thirty (30) days of
receiving the results of the System Impact Study identifying needed
facility additions or upgrades or costs incurred in providing the
requested service. While the Transmission Provider agrees to provide
the Eligible Customer with its best estimate of the new facility
costs and other charges that may be incurred, such estimate shall
not be binding and the Eligible Customer must agree in writing to
compensate the Transmission Provider for all costs incurred pursuant
to the provisions of the Tariff. The Eligible Customer shall execute
and return such an Expedited Service Agreement within fifteen (15)
days of its receipt or the Eligible Customer's request for service
will cease to be a Completed Application and will be deemed
terminated and withdrawn.
20 Procedures if the Transmission Provider is Unable to Complete
New Transmission Facilities for Firm Point-To-Point Transmission
Service
20.1 Delays in Construction of New Facilities: If any event
occurs that will materially affect the time for completion of new
facilities, or the ability to complete them, the Transmission
Provider shall promptly notify the Transmission Customer. In such
circumstances, the Transmission Provider shall within thirty (30)
days of notifying the Transmission Customer of such delays, convene
a technical meeting with the Transmission Customer to evaluate the
alternatives available to the Transmission Customer. The
Transmission Provider also shall make available to the Transmission
Customer studies and work papers related to the delay, including all
information that is in the possession of the Transmission Provider
that is reasonably needed by the Transmission Customer to evaluate
any alternatives.
20.2 Alternatives to the Original Facility Additions: When the
review process of Section determines that one or more alternatives
exist to the originally planned construction project, the
Transmission Provider shall present such alternatives for
consideration by the Transmission Customer. If, upon review of any
alternatives, the Transmission Customer desires to maintain its
Completed Application subject to construction of the alternative
facilities, it may request the Transmission Provider to submit a
revised Service Agreement for Firm Point-To-Point Transmission
Service. If the alternative approach solely involves Non-Firm Point-
To-Point Transmission Service, the Transmission Provider shall
promptly tender a Service Agreement for Non-Firm Point-To-Point
Transmission Service providing for the service. In the event the
Transmission Provider concludes that no reasonable alternative
exists and the Transmission Customer disagrees, the Transmission
Customer may seek relief under the dispute resolution procedures
pursuant to Section 12 or it may refer the dispute to the Commission
for resolution.
20.3 Refund Obligation for Unfinished Facility Additions: If
the Transmission Provider and the Transmission Customer mutually
agree that no other reasonable alternatives exist and the requested
service cannot be provided out of existing capability under the
conditions of Part II of the Tariff, the obligation to provide the
requested Firm Point-To-Point Transmission Service shall terminate
and any deposit made by the Transmission Customer shall be returned
with interest pursuant to Commission regulations 35.19a(a)(2)(iii).
However, the Transmission Customer shall be responsible for all
prudently incurred costs by the Transmission Provider through the
time construction was suspended.
21 Provisions Relating to Transmission Construction and Services
on the Systems of Other Utilities
21.1 Responsibility for Third-Party System Additions: The
Transmission Provider shall not be responsible for making
arrangements for any necessary engineering, permitting, and
construction of transmission or distribution facilities on the
system(s) of any other entity or for obtaining any regulatory
approval for such facilities. The Transmission Provider will
undertake reasonable efforts to assist the Transmission Customer in
obtaining such arrangements, including without limitation, providing
any information or data required by such other electric system
pursuant to Good Utility Practice.
21.2 Coordination of Third-Party System Additions: In
circumstances where the need for transmission facilities or upgrades
is identified pursuant to the provisions of Part II of the Tariff,
and if such upgrades further require the addition of transmission
facilities on other systems, the Transmission Provider shall have
the right to coordinate construction on its own system with the
construction required by others. The Transmission Provider, after
consultation with the Transmission Customer and representatives of
such other systems, may defer construction of its new transmission
facilities, if the new transmission facilities on another system
cannot be completed in a timely manner. The Transmission Provider
shall notify the Transmission Customer in writing of the basis for
any decision to defer construction and the specific problems
[[Page 21717]]
which must be resolved before it will initiate or resume
construction of new facilities. Within sixty (60) days of receiving
written notification by the Transmission Provider of its intent to
defer construction pursuant to this section, the Transmission
Customer may challenge the decision in accordance with the dispute
resolution procedures pursuant to Section 12 or it may refer the
dispute to the Commission for resolution.
22 Changes in Service Specifications
22.1 Modifications On a Non-Firm Basis: The Transmission
Customer taking Firm Point-To-Point Transmission Service may request
the Transmission Provider to provide transmission service on a non-
firm basis over Receipt and Delivery Points other than those
specified in the Service Agreement (``Secondary Receipt and Delivery
Points''), in amounts not to exceed its firm capacity reservation,
without incurring an additional Non-Firm Point-To-Point Transmission
Service charge or executing a new Service Agreement, subject to the
following conditions.
(a) Service provided over Secondary Receipt and Delivery Points
will be non-firm only, on an as-available basis and will not
displace any firm or non-firm service reserved or scheduled by
third-parties under the Tariff or by the Transmission Provider on
behalf of its Native Load Customers.
(b) The sum of all Firm and non-firm Point-To-Point Transmission
Service provided to the Transmission Customer at any time pursuant
to this section shall not exceed the Reserved Capacity in the
relevant Service Agreement under which such services are provided.
(c) The Transmission Customer shall retain its right to schedule
Firm Point-To-Point Transmission Service at the Receipt and Delivery
Points specified in the relevant Service Agreement in the amount of
its original capacity reservation.
(d) Service over Secondary Receipt and Delivery Points on a non-
firm basis shall not require the filing of an Application for Non-
Firm Point-To-Point Transmission Service under the Tariff. However,
all other requirements of Part II of the Tariff (except as to
transmission rates) shall apply to transmission service on a non-
firm basis over Secondary Receipt and Delivery Points.
22.2 Modification On a Firm Basis: Any request by a
Transmission Customer to modify Receipt and Delivery Points on a
firm basis shall be treated as a new request for service in
accordance with Section 17 hereof, except that such Transmission
Customer shall not be obligated to pay any additional deposit if the
capacity reservation does not exceed the amount reserved in the
existing Service Agreement. While such new request is pending, the
Transmission Customer shall retain its priority for service at the
existing firm Receipt and Delivery Points specified in its Service
Agreement.
23 Sale or Assignment of Transmission Service
23.1 Procedures for Assignment or Transfer of Service: Subject
to Commission approval of any necessary filings, a Transmission
Customer may sell, assign, or transfer all or a portion of its
rights under its Service Agreement, but only to another Eligible
Customer (the Assignee). The Transmission Customer that sells,
assigns or transfers its rights under its Service Agreement is
hereafter referred to as the Reseller. Compensation to the Reseller
shall not exceed the higher of (i) the original rate paid by the
Reseller, (ii) the Transmission Provider's maximum rate on file at
the time of the assignment, or (iii) the Reseller's opportunity
cost. If the Assignee does not request any change in the Point(s) of
Receipt or the Point(s) of Delivery, or a change in any other term
or condition set forth in the original Service Agreement, the
Assignee will receive the same services as did the Reseller and the
priority of service for the Assignee will be the same as that of the
Reseller. A Reseller should notify the Transmission Provider as soon
as possible after any assignment or transfer of service occurs but
in any event, notification must be provided prior to any provision
of service to the Assignee. The Assignee will be subject to all
terms and conditions of this Tariff. If the Assignee requests a
change in service, the reservation priority of service will be
determined by the Transmission Provider pursuant to Section 13.2.
23.2 Limitations on Assignment or Transfer of Service: If the
Assignee requests a change in the Point(s) of Receipt or Point(s) of
Delivery, or a change in any other specifications set forth in the
original Service Agreement, the Transmission Provider will consent
to such change subject to the provisions of the Tariff, provided
that the change will not impair the operation and reliability of the
Transmission Provider's generation, transmission, or distribution
systems. The Assignee shall compensate the Transmission Provider for
performing any System Impact Study needed to evaluate the capability
of the Transmission System to accommodate the proposed change and
any additional costs resulting from such change. The Reseller shall
remain liable for the performance of all obligations under the
Service Agreement, except as specifically agreed to by the Parties
through an amendment to the Service Agreement.
23.3 Information on Assignment or Transfer of Service: In
accordance with Section 4, Resellers may use the Transmission
Provider's OASIS to post transmission capacity available for resale.
24 Metering and Power Factor Correction at Receipt and Delivery
Points(s)
24.1 Transmission Customer Obligations: Unless otherwise
agreed, the Transmission Customer shall be responsible for
installing and maintaining compatible metering and communications
equipment to accurately account for the capacity and energy being
transmitted under Part II of the Tariff and to communicate the
information to the Transmission Provider. Such equipment shall
remain the property of the Transmission Customer.
24.2 Transmission Provider Access to Metering Data: The
Transmission Provider shall have access to metering data, which may
reasonably be required to facilitate measurements and billing under
the Service Agreement.
24.3 Power Factor: Unless otherwise agreed, the Transmission
Customer is required to maintain a power factor within the same
range as the Transmission Provider pursuant to Good Utility
Practices. The power factor requirements are specified in the
Service Agreement where applicable.
25 Compensation for Transmission Service
Rates for Firm and Non-Firm Point-To-Point Transmission Service
are provided in the Schedules appended to the Tariff: Firm Point-To-
Point Transmission Service (Schedule 7); and Non-Firm Point-To-Point
Transmission Service (Schedule 8). The Transmission Provider shall
use Part II of the Tariff to make its Third-Party Sales. The
Transmission Provider shall account for such use at the applicable
Tariff rates, pursuant to Section 8.
26 Stranded Cost Recovery
The Transmission Provider may seek to recover stranded costs
from the Transmission Customer pursuant to this Tariff in accordance
with the terms, conditions and procedures set forth in FERC Order
No. 888. However, the Transmission Provider must separately file any
specific proposed stranded cost charge under Section 205 of the
Federal Power Act.
27 Compensation for New Facilities and Redispatch Costs
Whenever a System Impact Study performed by the Transmission
Provider in connection with the provision of Firm Point-To-Point
Transmission Service identifies the need for new facilities, the
Transmission Customer shall be responsible for such costs to the
extent consistent with Commission policy. Whenever a System Impact
Study performed by the Transmission Provider identifies capacity
constraints that may be relieved more economically by redispatching
the Transmission Provider's resources than by building new
facilities or upgrading existing facilities to eliminate such
constraints, the Transmission Customer shall be responsible for the
redispatch costs to the extent consistent with Commission policy.
III. Network Integration Transmission Service
Preamble
The Transmission Provider will provide Network Integration
Transmission Service pursuant to the applicable terms and conditions
contained in the Tariff and Service Agreement. Network Integration
Transmission Service allows the Network Customer to integrate,
economically dispatch and regulate its current and planned Network
Resources to serve its Network Load in a manner comparable to that
in which the Transmission Provider utilizes its Transmission System
to serve its Native Load Customers. Network Integration Transmission
Service also may be used by the Network Customer to deliver economy
energy purchases to its Network Load from non-designated resources
on an as-available basis without additional charge. Transmission
service for sales to non-designated loads will be provided pursuant
to the applicable terms and conditions of Part II of the Tariff.
[[Page 21718]]
28 Nature of Network Integration Transmission Service
28.1 Scope of Service: Network Integration Transmission Service
is a transmission service that allows Network Customers to
efficiently and economically utilize their Network Resources (as
well as other non-designated generation resources) to serve their
Network Load located in the Transmission Provider's Control Area and
any additional load that may be designated pursuant to Section 31.3
of the Tariff. The Network Customer taking Network Integration
Transmission Service must obtain or provide Ancillary Services
pursuant to Section 3.
28.2 Transmission Provider Responsibilities: The Transmission
Provider will plan, construct, operate and maintain its Transmission
System in accordance with Good Utility Practice in order to provide
the Network Customer with Network Integration Transmission Service
over the Transmission Provider's Transmission System. The
Transmission Provider, on behalf of its Native Load Customers, shall
be required to designate resources and loads in the same manner as
any Network Customer under Part III of this Tariff. This information
must be consistent with the information used by the Transmission
Provider to calculate available transmission capability. The
Transmission Provider shall include the Network Customer's Network
Load in its Transmission System planning and shall, consistent with
Good Utility Practice, endeavor to construct and place into service
sufficient transmission capacity to deliver the Network Customer's
Network Resources to serve its Network Load on a basis comparable to
the Transmission Provider's delivery of its own generating and
purchased resources to its Native Load Customers.
28.3 Network Integration Transmission Service: The Transmission
Provider will provide firm transmission service over its
Transmission System to the Network Customer for the delivery of
capacity and energy from its designated Network Resources to service
its Network Loads on a basis that is comparable to the Transmission
Provider's use of the Transmission System to reliably serve its
Native Load Customers.
28.4 Secondary Service: The Network Customer may use the
Transmission Provider's Transmission System to deliver energy to its
Network Loads from resources that have not been designated as
Network Resources. Such energy shall be transmitted, on an as-
available basis, at no additional charge. Deliveries from resources
other than Network Resources will have a higher priority than any
Non-Firm Point-To-Point Transmission Service under Part II of the
Tariff.
28.5 Real Power Losses: Real Power Losses are associated with
all transmission service. The Transmission Provider is not obligated
to provide Real Power Losses. The Network Customer is responsible
for replacing losses associated with all transmission service as
calculated by the Transmission Provider. The applicable Real Power
Loss factors are as follows: [To be completed by the Transmission
Provider].
28.6 Restrictions on Use of Service: The Network Customer shall
not use Network Integration Transmission Service for (i) sales of
capacity and energy to non-designated loads, or (ii) direct or
indirect provision of transmission service by the Network Customer
to third parties. All Network Customers taking Network Integration
Transmission Service shall use Point-To-Point Transmission Service
under Part II of the Tariff for any Third-Party Sale which requires
use of the Transmission Provider's Transmission System.
29 Initiating Service
29.1 Condition Precedent for Receiving Service: Subject to the
terms and conditions of Part III of the Tariff, the Transmission
Provider will provide Network Integration Transmission Service to
any Eligible Customer, provided that (i) the Eligible Customer
completes an Application for service as provided under Part III of
the Tariff, (ii) the Eligible Customer and the Transmission Provider
complete the technical arrangements set forth in Sections 29.3 and
29.4, (iii) the Eligible Customer executes a Service Agreement
pursuant to Attachment F for service under Part III of the Tariff or
requests in writing that the Transmission Provider file a proposed
unexecuted Service Agreement with the Commission, and (iv) the
Eligible Customer executes a Network Operating Agreement with the
Transmission Provider pursuant to Attachment G.
29.2 Application Procedures: An Eligible Customer requesting
service under Part III of the Tariff must submit an Application,
with a deposit approximating the charge for one month of service, to
the Transmission Provider as far as possible in advance of the month
in which service is to commence. Unless subject to the procedures in
Section 2, Completed Applications for Network Integration
Transmission Service will be assigned a priority according to the
date and time the Application is received, with the earliest
Application receiving the highest priority. Applications should be
submitted by entering the information listed below on the
Transmission Provider's OASIS. Prior to implementation of the
Transmission Provider's OASIS, a Completed Application may be
submitted by (i) transmitting the required information to the
Transmission Provider by telefax, or (ii) providing the information
by telephone over the Transmission Provider's time recorded
telephone line. Each of these methods will provide a time-stamped
record for establishing the service priority of the Application. A
Completed Application shall provide all of the information included
in 18 CFR Sec. 2.20 including but not limited to the following:
(i) The identity, address, telephone number and facsimile number
of the party requesting service;
(ii) A statement that the party requesting service is, or will
be upon commencement of service, an Eligible Customer under the
Tariff;
(iii) A description of the Network Load at each delivery point.
This description should separately identify and provide the Eligible
Customer's best estimate of the total loads to be served at each
transmission voltage level, and the loads to be served from each
Transmission Provider substation at the same transmission voltage
level. The description should include a ten (10) year forecast of
summer and winter load and resource requirements beginning with the
first year after the service is scheduled to commence;
(iv) The amount and location of any interruptible loads included
in the Network Load. This shall include the summer and winter
capacity requirements for each interruptible load (had such load not
been interruptible), that portion of the load subject to
interruption, the conditions under which an interruption can be
implemented and any limitations on the amount and frequency of
interruptions. An Eligible Customer should identify the amount of
interruptible customer load (if any) included in the 10 year load
forecast provided in response to (iii) above;
(v) A description of Network Resources (current and 10-year
projection), which shall include, for each Network Resource:
--Unit size and amount of capacity from that unit to be designated
as Network Resource
--VAR capability (both leading and lagging) of all generators
--Operating restrictions
--Any periods of restricted operations throughout the year
--Maintenance schedules
--Minimum loading level of unit
--Normal operating level of unit
--Any must-run unit designations required for system reliability or
contract reasons
--Approximate variable generating cost ($/MWH) for redispatch
computations
--Arrangements governing sale and delivery of power to third parties
from generating facilities located in the Transmission Provider
Control Area, where only a portion of unit output is designated as a
Network Resource
--Description of purchased power designated as a Network Resource
including source of supply, Control Area location, transmission
arrangements and delivery point(s) to the Transmission Provider's
Transmission System;
(vi) Description of Eligible Customer's transmission system:
--Load flow and stability data, such as real and reactive parts of
the load, lines, transformers, reactive devices and load type,
including normal and emergency ratings of all transmission equipment
in a load flow format compatible with that used by the Transmission
Provider
--Operating restrictions needed for reliability
--Operating guides employed by system operators
--Contractual restrictions or committed uses of the Eligible
Customer's transmission system, other than the Eligible Customer's
Network Loads and Resources
--Location of Network Resources described in subsection (v) above
--10 year projection of system expansions or upgrades
--Transmission System maps that include any proposed expansions or
upgrades
--Thermal ratings of Eligible Customer's Control Area ties with
other Control Areas; and
(vii) Service Commencement Date and the term of the requested
Network Integration
[[Page 21719]]
Transmission Service. The minimum term for Network Integration
Transmission Service is one year.
Unless the Parties agree to a different time frame, the
Transmission Provider must acknowledge the request within ten (10)
days of receipt. The acknowledgement must include a date by which a
response, including a Service Agreement, will be sent to the
Eligible Customer. If an Application fails to meet the requirements
of this section, the Transmission Provider shall notify the Eligible
Customer requesting service within fifteen (15) days of receipt and
specify the reasons for such failure. Wherever possible, the
Transmission Provider will attempt to remedy deficiencies in the
Application through informal communications with the Eligible
Customer. If such efforts are unsuccessful, the Transmission
Provider shall return the Application without prejudice to the
Eligible Customer filing a new or revised Application that fully
complies with the requirements of this section. The Eligible
Customer will be assigned a new priority consistent with the date of
the new or revised Application. The Transmission Provider shall
treat this information consistent with the standards of conduct
contained in Part 37 of the Commission's regulations.
29.3 Technical Arrangements to be Completed Prior to
Commencement of Service: Network Integration Transmission Service
shall not commence until the Transmission Provider and the Network
Customer, or a third party, have completed installation of all
equipment specified under the Network Operating Agreement consistent
with Good Utility Practice and any additional requirements
reasonably and consistently imposed to ensure the reliable operation
of the Transmission System. The Transmission Provider shall exercise
reasonable efforts, in coordination with the Network Customer, to
complete such arrangements as soon as practicable taking into
consideration the Service Commencement Date.
29.4 Network Customer Facilities: The provision of Network
Integration Transmission Service shall be conditioned upon the
Network Customer's constructing, maintaining and operating the
facilities on its side of each delivery point or interconnection
necessary to reliably deliver capacity and energy from the
Transmission Provider's Transmission System to the Network Customer.
The Network Customer shall be solely responsible for constructing or
installing all facilities on the Network Customer's side of each
such delivery point or interconnection.
29.5 Filing of Service Agreement: The Transmission Provider
will file Service Agreements with the Commission in compliance with
applicable Commission regulations.
Network Resources
30.1 Designation of Network Resources: Network Resources shall
include all generation owned or purchased by the Network Customer
designated to serve Network Load under the Tariff. Network Resources
may not include resources, or any portion thereof, that are
committed for sale to non-designated third party load or otherwise
cannot be called upon to meet the Network Customer's Network Load on
a non-interruptible basis. Any owned or purchased resources that
were serving the Network Customer's loads under firm agreements
entered into on or before the Service Commencement Date shall
initially be designated as Network Resources until the Network
Customer terminates the designation of such resources.
30.2 Designation of New Network Resources: The Network Customer
may designate a new Network Resource by providing the Transmission
Provider with as much advance notice as practicable. A designation
of a new Network Resource must be made by a request for modification
of service pursuant to an Application under Section 29.
30.3 Termination of Network Resources: The Network Customer may
terminate the designation of all or part of a generating resource as
a Network Resource at any time but should provide notification to
the Transmission Provider as soon as reasonably practicable.
30.4 Operation of Network Resources: The Network Customer shall
not operate its designated Network Resources located in the Network
Customer's or Transmission Provider's Control Area such that the
output of those facilities exceeds its designated Network Load plus
losses.
30.5 Network Customer Redispatch Obligation: As a condition to
receiving Network Integration Transmission Service, the Network
Customer agrees to redispatch its Network Resources as requested by
the Transmission Provider pursuant to Section 33.2. To the extent
practical, the redispatch of resources pursuant to this section
shall be on a least cost, non-discriminatory basis between all
Network Customers, and the Transmission Provider.
30.6 Transmission Arrangements for Network Resources Not
Physically Interconnected With The Transmission Provider: The
Network Customer shall be responsible for any arrangements necessary
to deliver capacity and energy from a Network Resource not
physically interconnected with the Transmission Provider's
Transmission System. The Transmission Provider will undertake
reasonable efforts to assist the Network Customer in obtaining such
arrangements, including without limitation, providing any
information or data required by such other entity pursuant to Good
Utility Practice.
30.7 Limitation on Designation of Network Resources: The
Network Customer must demonstrate that it owns or has committed to
purchase generation pursuant to an executed contract in order to
designate a generating resource as a Network Resource.
Alternatively, the Network Customer may establish that execution of
a contract is contingent upon the availability of transmission
service under Part III of the Tariff.
30.8 Use of Interface Capacity by the Network Customer: There
is no limitation upon a Network Customer's use of the Transmission
Provider's Transmission System at any particular interface to
integrate the Network Customer's Network Resources (or substitute
economy purchases) with its Network Loads. However, a Network
Customer's use of the Transmission Provider's total interface
capacity with other transmission systems may not exceed the Network
Customer's Load Ratio Share.
30.9 Network Customer Owned Transmission Facilities: The
Network Customer that owns existing transmission facilities that are
integrated with the Transmission Provider's Transmission System may
be eligible to receive consideration either through a billing credit
or some other mechanism. In order to receive such consideration the
Network Customer must demonstrate that its transmission facilities
are integrated into the planning and operations of the Transmission
Provider to serve all of its power and transmission customers. For
facilities constructed by the Network Customer subsequent to the
Service Commencement Date under Part III of the Tariff, the Network
Customer shall receive credit where such facilities are jointly
planned and installed in coordination with the Transmission
Provider. Calculation of the credit shall be addressed in either the
Network Customer's Service Agreement or any other agreement between
the Parties.
31 Designation of Network Load
31.1 Network Load: The Network Customer must designate the
individual Network Loads on whose behalf the Transmission Provider
will provide Network Integration Transmission Service. The Network
Loads shall be specified in the Service Agreement.
31.2 New Network Loads Connected With the Transmission
Provider: The Network Customer shall provide the Transmission
Provider with as much advance notice as reasonably practicable of
the designation of new Network Load that will be added to its
Transmission System. A designation of new Network Load must be made
through a modification of service pursuant to a new Application. The
Transmission Provider will use due diligence to install any
transmission facilities required to interconnect a new Network Load
designated by the Network Customer. The costs of new facilities
required to interconnect a new Network Load shall be determined in
accordance with the procedures provided in Section 32.4 and shall be
charged to the Network Customer in accordance with Commission
policies.
31.3 Network Load Not Physically Interconnected with the
Transmission Provider: This section applies to both initial
designation pursuant to Section 31.1 and the subsequent addition of
new Network Load not physically interconnected with the Transmission
Provider. To the extent that the Network Customer desires to obtain
transmission service for a load outside the Transmission Provider's
Transmission System, the Network Customer shall have the option of
(1) electing to include the entire load as Network Load for all
purposes under Part III of the Tariff and designating Network
Resources in connection with such additional Network Load, or (2)
excluding that entire load from its Network Load and purchasing
Point-To-Point Transmission
[[Page 21720]]
Service under Part II of the Tariff. To the extent that the Network
Customer gives notice of its intent to add a new Network Load as
part of its Network Load pursuant to this section the request must
be made through a modification of service pursuant to a new
Application.
31.4 New Interconnection Points: To the extent the Network
Customer desires to add a new Delivery Point or interconnection
point between the Transmission Provider's Transmission System and a
Network Load, the Network Customer shall provide the Transmission
Provider with as much advance notice as reasonably practicable.
31.5 Changes in Service Requests: Under no circumstances shall
the Network Customer's decision to cancel or delay a requested
change in Network Integration Transmission Service (e.g. the
addition of a new Network Resource or designation of a new Network
Load) in any way relieve the Network Customer of its obligation to
pay the costs of transmission facilities constructed by the
Transmission Provider and charged to the Network Customer as
reflected in the Service Agreement. However, the Transmission
Provider must treat any requested change in Network Integration
Transmission Service in a non-discriminatory manner.
31.6 Annual Load and Resource Information Updates: The Network
Customer shall provide the Transmission Provider with annual updates
of Network Load and Network Resource forecasts consistent with those
included in its Application for Network Integration Transmission
Service under Part III of the Tariff. The Network Customer also
shall provide the Transmission Provider with timely written notice
of material changes in any other information provided in its
Application relating to the Network Customer's Network Load, Network
Resources, its transmission system or other aspects of its
facilities or operations affecting the Transmission Provider's
ability to provide reliable service.
32 Additional Study Procedures for Network Integration
Transmission Service Requests
32.1 Notice of Need for System Impact Study: After receiving a
request for service, the Transmission Provider shall determine on a
non-discriminatory basis whether a System Impact Study is needed. A
description of the Transmission Provider's methodology for
completing a System Impact Study is provided in Attachment D. If the
Transmission Provider determines that a System Impact Study is
necessary to accommodate the requested service, it shall so inform
the Eligible Customer, as soon as practicable. In such cases, the
Transmission Provider shall within thirty (30) days of receipt of a
Completed Application, tender a System Impact Study Agreement
pursuant to which the Eligible Customer shall agree to reimburse the
Transmission Provider for performing the required System Impact
Study. For a service request to remain a Completed Application, the
Eligible Customer shall execute the System Impact Study Agreement
and return it to the Transmission Provider within fifteen (15) days.
If the Eligible Customer elects not to execute the System Impact
Study Agreement, its Application shall be deemed withdrawn and its
deposit shall be returned with interest.
32.2 System Impact Study Agreement and Cost Reimbursement:
(i) The System Impact Study Agreement will clearly specify the
maximum charge, based on the Transmission Provider's estimate of the
actual cost, and time for completion of the System Impact Study. The
charge shall not exceed the actual cost of the study. In performing
the System Impact Study, the Transmission Provider shall rely, to
the extent reasonably practicable, on existing transmission planning
studies. The Eligible Customer will not be assessed a charge for
such existing studies; however, the Eligible Customer will be
responsible for charges associated with any modifications to
existing planning studies that are reasonably necessary to evaluate
the impact of the Eligible Customer's request for service on the
Transmission System.
(ii) If in response to multiple Eligible Customers requesting
service in relation to the same competitive solicitation, a single
System Impact Study is sufficient for the Transmission Provider to
accommodate the service requests, the costs of that study shall be
pro-rated among the Eligible Customers.
(iii) For System Impact Studies that the Transmission Provider
conducts on its own behalf, the Transmission Provider shall record
the cost of the System Impact Studies pursuant to Section 8.
32.3 System Impact Study Procedures: Upon receipt of an
executed System Impact Study Agreement, the Transmission Provider
will use due diligence to complete the required System Impact Study
within a sixty (60) day period. The System Impact Study shall
identify any system constraints and redispatch options, additional
Direct Assignment Facilities or Network Upgrades required to provide
the requested service. In the event that the Transmission Provider
is unable to complete the required System Impact Study within such
time period, it shall so notify the Eligible Customer and provide an
estimated completion date along with an explanation of the reasons
why additional time is required to complete the required studies. A
copy of the completed System Impact Study and related work papers
shall be made available to the Eligible Customer. The Transmission
Provider will use the same due diligence in completing the System
Impact Study for an Eligible Customer as it uses when completing
studies for itself. The Transmission Provider shall notify the
Eligible Customer immediately upon completion of the System Impact
Study if the Transmission System will be adequate to accommodate all
or part of a request for service or that no costs are likely to be
incurred for new transmission facilities or upgrades. In order for a
request to remain a Completed Application, within fifteen (15) days
of completion of the System Impact Study the Eligible Customer must
execute a Service Agreement or request the filing of an unexecuted
Service Agreement, or the Application shall be deemed terminated and
withdrawn.
32.4 Facilities Study Procedures: If a System Impact Study
indicates that additions or upgrades to the Transmission System are
needed to supply the Eligible Customer's service request, the
Transmission Provider, within thirty (30) days of the completion of
the System Impact Study, shall tender to the Eligible Customer a
Facilities Study Agreement pursuant to which the Eligible Customer
shall agree to reimburse the Transmission Provider for performing
the required Facilities Study. For a service request to remain a
Completed Application, the Eligible Customer shall execute the
Facilities Study Agreement and return it to the Transmission
Provider within fifteen (15) days. If the Eligible Customer elects
not to execute the Facilities Study Agreement, its Application shall
be deemed withdrawn and its deposit shall be returned with interest.
Upon receipt of an executed Facilities Study Agreement, the
Transmission Provider will use due diligence to complete the
required Facilities Study within a sixty (60) day period. If the
Transmission Provider is unable to complete the Facilities Study in
the allotted time period, the Transmission Provider shall notify the
Eligible Customer and provide an estimate of the time needed to
reach a final determination along with an explanation of the reasons
that additional time is required to complete the study. When
completed, the Facilities Study will include a good faith estimate
of (i) the cost of Direct Assignment Facilities to be charged to the
Eligible Customer, (ii) the Eligible Customer's appropriate share of
the cost of any required Network Upgrades, and (iii) the time
required to complete such construction and initiate the requested
service. The Eligible Customer shall provide the Transmission
Provider with a letter of credit or other reasonable form of
security acceptable to the Transmission Provider equivalent to the
costs of new facilities or upgrades consistent with commercial
practices as established by the Uniform Commercial Code. The
Eligible Customer shall have thirty (30) days to execute a Service
Agreement or request the filing of an unexecuted Service Agreement
and provide the required letter of credit or other form of security
or the request no longer will be a Completed Application and shall
be deemed terminated and withdrawn.
33 Load Shedding and Curtailments
33.1 Procedures: Prior to the Service Commencement Date, the
Transmission Provider and the Network Customer shall establish Load
Shedding and Curtailment procedures pursuant to the Network
Operating Agreement with the objective of responding to
contingencies on the Transmission System. The Parties will implement
such programs during any period when the Transmission Provider
determines that a system contingency exists and such procedures are
necessary to alleviate such contingency. The Transmission Provider
will notify all affected Network Customers in a timely manner of any
scheduled Curtailment.
33.2 Transmission Constraints: During any period when the
Transmission Provider determines that a transmission constraint
exists on the Transmission System, and such constraint may impair
the reliability of the Transmission Provider's system, the
Transmission Provider will take whatever
[[Page 21721]]
actions, consistent with Good Utility Practice, that are reasonably
necessary to maintain the reliability of the Transmission Provider's
system. To the extent the Transmission Provider determines that the
reliability of the Transmission System can be maintained by
redispatching resources, the Transmission Provider will initiate
procedures pursuant to the Network Operating Agreement to redispatch
all Network Resources and the Transmission Provider's own resources
on a least-cost basis without regard to the ownership of such
resources. Any redispatch under this section may not unduly
discriminate between the Transmission Provider's use of the
Transmission System on behalf of its Native Load Customers and any
Network Customer's use of the Transmission System to serve its
designated Network Load.
33.3 Cost Responsibility for Relieving Transmission
Constraints: Whenever the Transmission Provider implements least-
cost redispatch procedures in response to a transmission constraint,
the Transmission Provider and Network Customers will each bear a
proportionate share of the total redispatch cost based on their
respective Load Ratio Shares.
33.4 Curtailments of Scheduled Deliveries: If a transmission
constraint on the Transmission Provider's Transmission System cannot
be relieved through the implementation of least-cost redispatch
procedures and the Transmission Provider determines that it is
necessary to Curtail scheduled deliveries, the Parties shall Curtail
such schedules in accordance with the Network Operating Agreement.
33.5 Allocation of Curtailments: The Transmission Provider
shall, on a non-discriminatory basis, Curtail the transaction(s)
that effectively relieve the constraint. However, to the extent
practicable and consistent with Good Utility Practice, any
Curtailment will be shared by the Transmission Provider and Network
Customer in proportion to their respective Load Ratio Shares. The
Transmission Provider shall not direct the Network Customer to
Curtail schedules to an extent greater than the Transmission
Provider would Curtail the Transmission Provider's schedules under
similar circumstances.
33.6 Load Shedding: To the extent that a system contingency
exists on the Transmission Provider's Transmission System and the
Transmission Provider determines that it is necessary for the
Transmission Provider and the Network Customer to shed load, the
Parties shall shed load in accordance with previously established
procedures under the Network Operating Agreement.
33.7 System Reliability: Notwithstanding any other provisions
of this Tariff, the Transmission Provider reserves the right,
consistent with Good Utility Practice and on a not unduly
discriminatory basis, to Curtail Network Integration Transmission
Service without liability on the Transmission Provider's part for
the purpose of making necessary adjustments to, changes in, or
repairs on its lines, substations and facilities, and in cases where
the continuance of Network Integration Transmission Service would
endanger persons or property. In the event of any adverse
condition(s) or disturbance(s) on the Transmission Provider's
Transmission System or on any other system(s) directly or indirectly
interconnected with the Transmission Provider's Transmission System,
the Transmission Provider, consistent with Good Utility Practice,
also may Curtail Network Integration Transmission Service in order
to (i) limit the extent or damage of the adverse condition(s) or
disturbance(s), (ii) prevent damage to generating or transmission
facilities, or (iii) expedite restoration of service. The
Transmission Provider will give the Network Customer as much advance
notice as is practicable in the event of such Curtailment. Any
Curtailment of Network Integration Transmission Service will be not
unduly discriminatory relative to the Transmission Provider's use of
the Transmission System on behalf of its Native Load Customers. The
Transmission Provider shall specify the rate treatment and all
related terms and conditions applicable in the event that the
Network Customer fails to respond to established Load Shedding and
Curtailment procedures.
34 Rates and Charges
The Network Customer shall pay the Transmission Provider for any
Direct Assignment Facilities, Ancillary Services, and applicable
study costs, consistent with Commission policy, along with the
following:
34.1 Monthly Demand Charge: The Network Customer shall pay a
monthly Demand Charge, which shall be determined by multiplying its
Load Ratio Share times one twelfth (\1/12\) of the Transmission
Provider's Annual Transmission Revenue Requirement specified in
Schedule H.
34.2 Determination of Network Customer's Monthly Network Load:
The Network Customer's monthly Network Load is its hourly load
(including its designated Network Load not physically interconnected
with the Transmission Provider under Section 31.3) coincident with
the Transmission Provider's Monthly Transmission System Peak.
34.3 Determination of Transmission Provider's Monthly
Transmission System Load: The Transmission Provider's monthly
Transmission System load is the Transmission Provider's Monthly
Transmission System Peak minus the coincident peak usage of all Firm
Point-To-Point Transmission Service customers pursuant to Part II of
this Tariff plus the Reserved Capacity of all Firm Point-To-Point
Transmission Service customers.
34.4 Redispatch Charge: The Network Customer shall pay a Load
Ratio Share of any redispatch costs allocated between the Network
Customer and the Transmission Provider pursuant to Section 33. To
the extent that the Transmission Provider incurs an obligation to
the Network Customer for redispatch costs in accordance with Section
33, such amounts shall be credited against the Network Customer's
bill for the applicable month.
34.5 Stranded Cost Recovery: The Transmission Provider may seek
to recover stranded costs from the Network Customer pursuant to this
Tariff in accordance with the terms, conditions and procedures set
forth in FERC Order No. 888. However, the Transmission Provider must
separately file any proposal to recover stranded costs under Section
205 of the Federal Power Act.
35 Operating Arrangements
35.1 Operation under The Network Operating Agreement: The
Network Customer shall plan, construct, operate and maintain its
facilities in accordance with Good Utility Practice and in
conformance with the Network Operating Agreement.
35.2 Network Operating Agreement: The terms and conditions
under which the Network Customer shall operate its facilities and
the technical and operational matters associated with the
implementation of Part III of the Tariff shall be specified in the
Network Operating Agreement. The Network Operating Agreement shall
provide for the Parties to (i) operate and maintain equipment
necessary for integrating the Network Customer within the
Transmission Provider's Transmission System (including, but not
limited to, remote terminal units, metering, communications
equipment and relaying equipment), (ii) transfer data between the
Transmission Provider and the Network Customer (including, but not
limited to, heat rates and operational characteristics of Network
Resources, generation schedules for units outside the Transmission
Provider's Transmission System, interchange schedules, unit outputs
for redispatch required under Section 33, voltage schedules, loss
factors and other real t
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
ime data), (iii) use software programs
required for data links and constraint dispatching, (iv) exchange
data on forecasted loads and resources necessary for long-term
planning, and (v) address any other technical and operational
considerations required for implementation of Part III of the
Tariff, including scheduling protocols. The Network Operating
Agreement will recognize that the Network Customer shall either (i)
operate as a Control Area under applicable guidelines of the North
American Electric Reliability Council (NERC) and the [applicable
regional reliability council], (ii) satisfy its Control Area
requirements, including all necessary Ancillary Services, by
contracting with the Transmission Provider, or (iii) satisfy its
Control Area requirements, including all necessary Ancillary
Services, by contracting with another entity, consistent with Good
Utility Practice, which satisfies NERC and the [applicable regional
reliability council] requirements. The Transmission Provider shall
not unreasonably refuse to accept contractual arrangements with
another entity for Ancillary Services. The Network Operating
Agreement is included in Attachment G.
35.3 Network Operating Committee: A Network Operating Committee
(Committee) shall be established to coordinate operating criteria
for the Parties' respective responsibilities under the Network
Operating Agreement. Each Network Customer shall be entitled to have
at least one representative on the Committee. The Committee shall
meet from time to time as need requires, but no less than once each
calendar year.
[[Page 21722]]
Schedule 1--Scheduling, System Control and Dispatch Service
This service is required to schedule the movement of power
through, out of, within, or into a Control Area. This service can be
provided only by the operator of the Control Area in which the
transmission facilities used for transmission service are located.
Scheduling, System Control and Dispatch Service is to be provided
directly by the Transmission Provider (if the Transmission Provider
is the Control Area operator) or indirectly by the Transmission
Provider making arrangements with the Control Area operator that
performs this service for the Transmission Provider's Transmission
System. The Transmission Customer must purchase this service from
the Transmission Provider or the Control Area operator. The charges
for Scheduling, System Control and Dispatch Service are to be based
on the rates set forth below. To the extent the Control Area
operator performs this service for the Transmission Provider,
charges to the Transmission Customer are to reflect only a pass-
through of the costs charged to the Transmission Provider by that
Control Area operator.
Schedule 2--Reactive Supply and Voltage Control from Generation Sources
Service
In order to maintain transmission voltages on the Transmission
Provider's transmission facilities within acceptable limits,
generation facilities (in the Control Area where the Transmission
Provider's transmission facilities are located) are operated to
produce (or absorb) reactive power. Thus, Reactive Supply and
Voltage Control from Generation Sources Service must be provided for
each transaction on the Transmission Provider's transmission
facilities. The amount of Reactive Supply and Voltage Control from
Generation Sources Service that must be supplied with respect to the
Transmission Customer's transaction will be determined based on the
reactive power support necessary to maintain transmission voltages
within limits that are generally accepted in the region and
consistently adhered to by the Transmission Provider.
Reactive Supply and Voltage Control from Generation Sources
Service is to be provided directly by the Transmission Provider (if
the Transmission Provider is the Control Area operator) or
indirectly by the Transmission Provider making arrangements with the
Control Area operator that performs this service for the
Transmission Provider's Transmission System. The Transmission
Customer must purchase this service from the Transmission Provider
or the Control Area operator. The charges for such service will be
based on the rates set forth below. To the extent the Control Area
operator performs this service for the Transmission Provider,
charges to the Transmission Customer are to reflect only a pass-
through of the costs charged to the Transmission Provider by the
Control Area operator.
Schedule 3--Regulation and Frequency Response Service
Regulation and Frequency Response Service is necessary to
provide for the continuous balancing of resources (generation and
interchange) with load and for maintaining scheduled Interconnection
frequency at sixty cycles per second (60 Hz). Regulation and
Frequency Response Service is accomplished by committing on-line
generation whose output is raised or lowered (predominantly through
the use of automatic generating control equipment) as necessary to
follow the moment-by-moment changes in load. The obligation to
maintain this balance between resources and load lies with the
Transmission Provider (or the Control Area operator that performs
this function for the Transmission Provider). The Transmission
Provider must offer this service when the transmission service is
used to serve load within its Control Area. The Transmission
Customer must either purchase this service from the Transmission
Provider or make alternative comparable arrangements to satisfy its
Regulation and Frequency Response Service obligation. The amount of
and charges for Regulation and Frequency Response Service are set
forth below. To the extent the Control Area operator performs this
service for the Transmission Provider, charges to the Transmission
Customer are to reflect only a pass-through of the costs charged to
the Transmission Provider by that Control Area operator.
Schedule 4--Energy Imbalance Service
Energy Imbalance Service is provided when a difference occurs
between the scheduled and the actual delivery of energy to a load
located within a Control Area over a single hour. The Transmission
Provider must offer this service when the transmission service is
used to serve load within its Control Area. The Transmission
Customer must either purchase this service from the Transmission
Provider or make alternative comparable arrangements to satisfy its
Energy Imbalance Service obligation. To the extent the Control Area
operator performs this service for the Transmission Provider,
charges to the Transmission Customer are to reflect only a pass-
through of the costs charged to the Transmission Provider by that
Control Area operator.
The Transmission Provider shall establish a deviation band of +/
- 1.5 percent (with a minimum of 1 MW) of the scheduled transaction
to be applied hourly to any energy imbalance that occurs as a result
of the Transmission Customer's scheduled transaction(s). Parties
should attempt to eliminate energy imbalances within the limits of
the deviation band within thirty (30) days or within such other
reasonable period of time as is generally accepted in the region and
consistently adhered to by the Transmission Provider. If an energy
imbalance is not corrected within thirty (30) days or a reasonable
period of time that is generally accepted in the region and
consistently adhered to by the Transmission Provider, the
Transmission Customer will compensate the Transmission Provider for
such service. Energy imbalances outside the deviation band will be
subject to charges to be specified by the Transmission Provider. The
charges for Energy Imbalance Service are set forth below.
Schedule 5--Operating Reserve--Spinning Reserve Service
Spinning Reserve Service is needed to serve load immediately in
the event of a system contingency. Spinning Reserve Service may be
provided by generating units that are on-line and loaded at less
than maximum output. The Transmission Provider must offer this
service when the transmission service is used to serve load within
its Control Area. The Transmission Customer must either purchase
this service from the Transmission Provider or make alternative
comparable arrangements to satisfy its Spinning Reserve Service
obligation. The amount of and charges for Spinning Reserve Service
are set forth below. To the extent the Control Area operator
performs this service for the Transmission Provider, charges to the
Transmission Customer are to reflect only a pass-through of the
costs charged to the Transmission Provider by that Control Area
operator.
Schedule 6--Operating Reserve--Supplemental Reserve Service
Supplemental Reserve Service is needed to serve load in the
event of a system contingency; however, it is not available
immediately to serve load but rather within a short period of time.
Supplemental Reserve Service may be provided by generating units
that are on-line but unloaded, by quick-start generation or by
interruptible load. The Transmission Provider must offer this
service when the transmission service is used to serve load within
its Control Area. The Transmission Customer must either purchase
this service from the Transmission Provider or make alternative
comparable arrangements to satisfy its Supplemental Reserve Service
obligation. The amount of and charges for Supplemental Reserve
Service are set forth below. To the extent the Control Area operator
performs this service for the Transmission Provider, charges to the
Transmission Customer are to reflect only a pass-through of the
costs charged to the Transmission Provider by that Control Area
operator.
Schedule 7--Long-Term Firm and Short-Term Firm Point-To-Point
Transmission Service
The Transmission Customer shall compensate the Transmission
Provider each month for Reserved Capacity at the sum of the
applicable charges set forth below:
(1) Yearly delivery: one-twelfth of the demand charge of
$________/KW of Reserved Capacity per year.
(2) Monthly delivery: $________/KW of Reserved Capacity per
month.
(3) Weekly delivery: $________/KW of Reserved Capacity per week.
(4) Daily delivery: $________/KW of Reserved Capacity per day.
The total demand charge in any week, pursuant to a reservation
for Daily delivery, shall not exceed the rate specified in section
(3) above times the highest amount in kilowatts of Reserved Capacity
in any day during such week.
(5) Discounts: If the Transmission Provider offers an affiliate
a rate discount or attributes a discounted transmission rate to its
own
[[Page 21723]]
transactions, the Transmission Provider must offer at the same time
the same discounted Firm Point-To-Point Transmission Service rate to
all Eligible Customers on the same path and on all unconstrained
transmission paths. Information regarding any firm transmission
discounts must be posted on the OASIS pursuant to Part 37 of the
Commission's regulations. In addition, discounts to non-affiliates
must be offered in a not unduly discriminatory manner.
Schedule 8--Non-Firm Point-To-Point Transmission Service
The Transmission Customer shall compensate the Transmission
Provider for Non-Firm Point-To-Point Transmission Service up to the
sum of the applicable charges set forth below:
(1) Monthly delivery: $________/KW of Reserved Capacity per
month.
(2) Weekly delivery: $________/KW of Reserved Capacity per week.
(3) Daily delivery: $________/KW of Reserved Capacity per day.
The total demand charge in any week, pursuant to a reservation
for Daily delivery, shall not exceed the rate specified in section
(2) above times the highest amount in kilowatts of Reserved Capacity
in any day during such week.
(4) Hourly delivery: The basic charge shall be that agreed upon
by the Parties at the time this service is reserved and in no event
shall exceed $________/MWH. The total demand charge in any day,
pursuant to a reservation for Hourly delivery, shall not exceed the
rate specified in section (3) above times the highest amount in
kilowatts of Reserved Capacity in any hour during such day. In
addition, the total demand charge in any week, pursuant to a
reservation for Hourly or Daily delivery, shall not exceed the rate
specified in section (2) above times the highest amount in kilowatts
of Reserved Capacity in any hour during such week.
(5) Discounts: If the Transmission Provider offers an affiliate
a rate discount or attributes a discounted transmission rate to its
own transactions, the Transmission Provider must offer at the same
time the same discounted Non-Firm Point-To-Point Transmission
Service rate to all Eligible Customers on the same path and on all
unconstrained transmission paths. Information regarding any non-firm
transmission discounts must be posted on the OASIS pursuant to Part
37 of the Commission's regulations. In addition, discounts to non-
affiliates must be offered in a not unduly discriminatory manner.
Attachment A--Form Of Service Agreement for Firm Point-To-Point
Transmission Service
1.0 This Service Agreement, dated as of ________________, is
entered into, by and between ________________ (the Transmission
Provider), and ________________ (``Transmission Customer'').
2.0 The Transmission Customer has been determined by the
Transmission Provider to have a Completed Application for Firm
Point-To-Point Transmission Service under the Tariff.
3.0 The Transmission Customer has provided to the Transmission
Provider an Application deposit in the amount of $________, in
accordance with the provisions of Section 17.3 of the Tariff.
4.0 Service under this agreement shall commence on the later of
(1) ________________, or (2) the date on which construction of any
Direct Assignment Facilities and/or Network Upgrades are completed,
or (3) such other date as it is permitted to become effective by the
Commission. Service under this agreement shall terminate on
________________.
5.0 The Transmission Provider agrees to provide and the
Transmission Customer agrees to take and pay for Firm Point-To-Point
Transmission Service in accordance with the provisions of Part II of
the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either Party regarding
this Service Agreement shall be made to the representative of the
other Party as indicated below.
Transmission Provider:
----------------------------------------------------------------------
----------------------------------------------------------------------
Transmission Customer:
----------------------------------------------------------------------
----------------------------------------------------------------------
7.0 The Tariff is incorporated herein and made a part hereof.
In Witness Whereof, the Parties have caused this Service
Agreement to be executed by their respective authorized officials.
Transmission Provider:
By:--------------------------------------------------------------------
Name
----------------------------------------------------------------------
Title
----------------------------------------------------------------------
Date
----------------------------------------------------------------------
----------------------------------------------------------------------
Transmission Customer:
By:--------------------------------------------------------------------
Name
----------------------------------------------------------------------
Title
----------------------------------------------------------------------
Date
----------------------------------------------------------------------
----------------------------------------------------------------------
Specifications for Firm Point-To-Point Transmission Service
1.0 Term of Transaction:----------------------------------------------
Start Date:------------------------------------------------------------
Termination Date:------------------------------------------------------
2.0 Description of capacity and energy to be transmitted by
Transmission Provider including the electric Control Area in which the
transaction originates.------------------------------------------------
----------------------------------------------------------------------
3.0 Point(s) of Receipt:----------------------------------------------
Delivering Party:------------------------------------------------------
4.0 Point(s) of Delivery:---------------------------------------------
Receiving Party:-------------------------------------------------------
5.0 Maximum amount of capacity and energy to be transmitted-----------
(Reserved Capacity):---------------------------------------------------
6.0 Designation of party(ies) subject to reciprocal service
obligation:------------------------------------------------------------
7.0 Name(s) of any Intervening Systems providing transmission service:
8.0 Service under this Agreement may be subject to some
combination of the charges detailed below. (The appropriate charges
for individual transactions will be determined in accordance with
the terms and conditions of the Tariff.)
8.1 Transmission Charge:----------------------------------------------
8.2 System Impact and/or Facilities Study Charge(s):------------------
8.3 Direct Assignment Facilities Charge:------------------------------
----------------------------------------------------------------------
8.4 Ancillary Services Charges:---------------------------------------
Attachment B--Form Of Service Agreement For Non-Firm Point-To-Point
Transmission Service
1.0 This Service Agreement, dated as of ____________, is
entered into, by and between ____________, (the Transmission
Provider), and ____________, (Transmission Customer).
2.0 The Transmission Customer has been determined by the
Transmission Provider to be a Transmission Customer under Part II of
the Tariff and has filed a Completed Application for Non-Firm Point-
To-Point Transmission Service in accordance with Section 18.2 of the
Tariff.
3.0 Service under this Agreement shall be provided by the
Transmission Provider upon request by an authorized representative
of the Transmission Customer.
4.0 The Transmission Customer agrees to supply information the
Transmission Provider deems reasonably necessary in accordance with
Good Utility Practice in order for it to provide the requested
service.
5.0 The Transmission Provider agrees to provide and the
Transmission Customer agrees to take and pay for Non-Firm Point-To-
Point Transmission Service in accordance with the provisions of Part
II of the Tariff and this Service Agreement.
6.0 Any notice or request made to or by either Party regarding
this Service Agreement shall be made to the representative of the
other Party as indicated below.
Transmission Provider:
----------------------------------------------------------------------
Transmission Customer:
----------------------------------------------------------------------
7.0 The Tariff is incorporated herein and made a part hereof.
In Witness Whereof, the Parties have caused this Service
Agreement to be executed by their respective authorized officials.
Transmission Provider:
----------------------------------------------------------------------
By:--------------------------------------------------------------------
----------------------------------------------------------------------
----------------------------------------------------------------------
Name
----------------------------------------------------------------------
Title
----------------------------------------------------------------------
Date
Transmission Customer:
----------------------------------------------------------------------
By:--------------------------------------------------------------------
----------------------------------------------------------------------
----------------------------------------------------------------------
Name
----------------------------------------------------------------------
Title
----------------------------------------------------------------------
Date
[[Page 21724]]
Attachment C--Methodology To Assess Available Transmission Capability
To be filed by the Transmission Provider.
Attachment D--Methodology for Completing a System Impact Study
To be filed by the Transmission Provider.
Attachment E--Index Of Point-To-Point Transmission Service Customers
Customer---------------------------------------------------------------
Date of Service Agreement----------------------------------------------
Attachment F--Service Agreement for Network Integration Transmission
Service
To be filed by the Transmission Provider.
Attachment G--Network Operating Agreement
To be filed by the Transmission Provider.
Attachment H--Annual Transmission Revenue Requirement for Network
Integration Transmission Service
1. The Annual Transmission Revenue Requirement for purposes of
the Network Integration Transmission Service shall be ____________.
2. The amount in (1) shall be effective until amended by the
Transmission Provider or modified by the Commission.
Attachment I--Index of Network Integration Transmission Service
Customers
Customer---------------------------------------------------------------
Date of Service Agreement----------------------------------------------
Appendix E--Group 1 Public Utilities
Alabama Power Company
Appalachian Power Company
Arkansas Power & Light Company
Atlantic City Electric Company
Baltimore Gas & Electric Company
Black Hills Power & Light Company
Cambridge Electric Light Company
Central Illinois Light Company
Central Power and Light Company
Central Vermont Public Service Corporation
Cheyenne Light, Fuel and Power Company
Cincinnatti Gas & Electric Company
Citizens Utilities Company
Columbus Southern Power Company
Commonwealth Edison Company
Commonwealth Electric Company
Connecticut Light & Power Company
Connecticut Valley Electric Company
Consumers Power Company
Dayton Power & Light Company
Delmarva Power & Light Company
Duke Power Company
Duquesne Light Company
Florida Power & Light Company
Florida Power Corporation
Georgia Power Company
Granite State Electric Company
Gulf Power Company
Gulf States Utilities Company
Holyoke Power & Electric Company
Holyoke Water Power Company
Idaho Power Company
IES Utilities, Inc.
Illinois Power Company
Indiana Michigan Power Company
Interstate Power Company
Jersey Central Power & Light Company
Kansas City Power & Light Company
Kansas Gas & Electric Company
Kentucky Power Company
Kentucky Utilities Company
Kingsport Power Company
Louisiana Power & Light Company
Louisville Gas & Electric Company
Maine Public Service Company
Massachusetts Electric Company
Metropolitan Edison Company
MidAmerican Energy Company
Midwest Energy, Inc.
Minnesota Power & Light Company
Mississippi Power Company
Mississippi Power & Light Company
Monongahela Power Company
Montana Power Company
Montaup Electric Company
Nantahala Power & Light Company
Narragansett Electric Company
Nevada Power Company
New England Power Company
New Orleans Public Service Inc.
Northern Indiana Public Service Company
Northern States Power Company( Wisconsin)
Northern States Power Company (Minnesota)
Ohio Power Company
Orange & Rockland Utilities, Inc.
Pacific Gas & Electric Company
PacifiCorp
PECO Energy Company
Pennsylvania Electric Company
Pennsylvania Power & Light Company
Pike County Light & Power Company
Portland General Electric Company
Potomac Edison Company
Potomac Electric Power Company
PSI Energy, Inc.
Public Service Company of Colorado
Public Service Company of New Mexico
Public Service Company of New Hampshire
Public Service Electric and Gas Company
Public Utility Company of Oklahoma
Puget Sound Power & Light Company
Rockland Electric Company
San Diego Gas & Electric Company
Savannah Electric and Power Company
South Carolina Electric & Gas Company
Southern California Edison Company
Southern Indiana Gas & Electric Company
Southwestern Electric Power Company
Southwestern Public Service Company
Tampa Electric Company
United Illiminating Company
UtiliCorp United, Inc.
Washington Water Power Company
West Penn Power Company
West Texas Utilities Company
Western Massachusetts Electric Company
Western Resources, Inc.
Wheeling Power Company
Wisconsin Electric Power Company
Wisconsin Power & Light Company
Wisconsin Public Service Corporation
Note: Transmission tariffs have also been filed for some public
utilities associated with pending merger applications. These
individual utilities are not included in Group 1 and will be
required to file tariffs on compliance with the Final Rule. They
are: Centerior's filing for Cleveland Electric Illuminating Company
and Toledo Edison Company; Interstate Energy Corporation's filing
for South Beloit Water, Gas & Electric Company; Resources West's for
Sierra Pacific Power Company; and the rate filing associated with
the merger of Union Electric Company and Central Illinois Public
Service Company.
Appendix F--Group 2 Public Utilities
Arizona Public Service Company
Bangor Hydro-Electric Company
Blackstone Valley Electric Company
Boston Edison Company
Carolina Power & Light Company
Central Hudson Gas & Electric Corporation
Central Illinois Public Service Company
Central Louisiana Electric Company, Inc.
Central Maine Power Company
Cleveland Electric Illuminating Company
Commonwealth Edison Company of Indiana
Concord Electric Company
Consolidated Edison Company of New York Inc.
Consolidated Water Power Company
Detroit Edison Company
Eastern Edison Company
Edison Sault Electric Company
El Paso Electric Company
Electric Energy Inc.
Empire District Electric Company
Exeter & Hampton Electric Company
Fitchburg Gas & Electric Light Company
Green Mountain Power Corporation
Indiana-Kentucky Electric Corporation
Indianapolis Power & Light Company
Kanawha Valley Power Company
Lockhart Power Company
Long Island Lighting Company
Long Sault, Inc.
Madison Gas & Electric Company
MDU Resources Group, Inc.
Mt. Carmel Public Utility Company
New England Electric Transmission Corporation
New England Hydro Transmission Electric Company
New England Hydro Transmission Corporation
New York State Electric & Gas Corporation
Newport Electric Corporation
Niagara Mohawk Power Corporation
Northwestern Public Service Company
Northwestern Wisconsin Electric Company
Ohio Edison Company
Ohio Valley Electic Corporation
Oklahoma Gas & Electric Company
Old Dominion Electric Cooperative
Otter Tail Power Company
Pennsylvania Power Company
Peoples Electric Cooperative
Rayburn Country Electric Cooperative
Rochester Gas & Electric Corporation
Sierra Pacific Power Company
South Beloit Water, Gas & Electric Company
St. Joseph Light & Power Company
Superior Water, Light and Power Company
Texas-New Mexico Power Company
Toledo Edison Company
Tucson Electric Power Company
UGI Utilities, Inc.
Union Electric Company
Union Light, Heat & Power Company
Unitil Power Corporation
Upper Penninsula Power Company
Vermont Electric Transmission Company
Vermont Electric Power Company
Virginia Electric & Power Company
Yadkin, Inc.
[[Page 21725]]
Appendix G
I. Legal Analysis of Commission Jurisdiction Over the Rates, Terms and
Conditions of Unbundled Retail Transmission in Interstate Commerce
Based on an analysis of the relevant legislative history and
case law under the Federal Power Act (FPA), the Commission concludes
that it has exclusive jurisdiction over the rates, terms and
conditions of the unbundled transmission in interstate commerce, by
a public utility, of electric energy to an end user. This is also
known as retail wheeling in interstate commerce. 1
---------------------------------------------------------------------------
\1\ Section 212(h) of the FPA provides that no order issued
under the FPA shall be conditioned upon or require the transmission
of electric energy directly to an ultimate consumer. 16 U.S.C.
824k(h). The Commission's assertion of jurisdiction in this final
rule is over the rates, terms and conditions of retail transmission
that occurs voluntarily or as a result of a state retail access
program.
---------------------------------------------------------------------------
The Commission's jurisdiction over the rates, terms and
conditions of transmission in interstate commerce derives from
Congress' power to regulate interstate commerce under the United
States Constitution 2 and the FPA. When Congress enacted the
FPA, it gave the Commission exclusive jurisdiction over the rates,
terms and conditions of transmission in interstate commerce by
public utilities. The Supremacy Clause of the Constitution provides
that federal laws enacted pursuant to the powers delegated to the
federal government by the United States Constitution are the supreme
law of the land.3 Accordingly, to the extent that retail
wheeling involves transmission in interstate commerce by public
utilities, the rates, terms and conditions of such service are
subject to the exclusive jurisdiction of the Commission, and must be
filed with the Commission.4
---------------------------------------------------------------------------
\2\ U.S. Const. art I, Section 8, cl.3.
\3\ U.S. Const. art. VI, cl.2.
\4\ See Montana-Dakota Utilities Co. v. Northwestern Public
Service Co., 341 U.S. 246, 251-52 (1951) (Montana-Dakota).
---------------------------------------------------------------------------
1. Relevant Federal Power Act Provisions
Section 201(b)(1) of the FPA provides:
The provisions of this Part shall apply to the transmission of
electric energy in interstate commerce and to the sale of electric
energy at wholesale in interstate commerce * * *. The Commission
shall have jurisdiction over all facilities for such transmission or
sale of electric energy, but shall not have jurisdiction * * * over
facilities used in local distribution or only for the transmission
of electric energy in intrastate commerce, or over facilities for
the transmission of electric energy consumed wholly by the
transmitter.
16 U.S.C. 824(b)(1) (emphasis added). Thus, the statute on its face
limits Commission jurisdiction over sales of energy to sales at
wholesale, but does not limit jurisdiction over transmission to
transmission used only for wholesale sales.
Sections 201 (c) and (d) define the meaning of ``the
transmission of electric energy in interstate commerce'' and ``sale
of electric energy at wholesale in interstate commerce.'' Section
201(c) provides:
For the purpose of this Part, electric energy shall be held to
be transmitted in interstate commerce if transmitted from a State
and consumed at any point outside thereof: but only insofar as such
transmission takes place within the United States.
16 U.S.C. 824(c). Section 201(d) provides:
The term ``sale of electric energy at wholesale'' when used in
this Part means a sale of electric energy to any person for resale.
16 U.S.C. 824(d).
Sections 205 and 206 of the FPA give the Commission jurisdiction
over the rates, terms and conditions of transmission in interstate
commerce, and sales at wholesale in interstate commerce, by public
utilities. 16 U.S.C. 824d and 824e.
2. Legislative History and Case Law
Much of the legislative history of the FPA indicates that
Congress intended the Commission's jurisdiction to extend only to
those matters which the Attleboro decision 5 held to be beyond
the reach of the States. For instance, the report accompanying the
Senate bill states that subsection (b) ``leaves to the States the
authority to fix local rates even in cases where the energy is
brought in from another State.'' 6 In other words, states
retain authority to regulate rates of electric energy to ultimate
consumers. The Senate report also states:
---------------------------------------------------------------------------
\5\ Public Utilities Commission v. Attleboro Steam & Electric
Co., 273 U.S. 83 (1927) (Attleboro). In Attleboro, the Supreme Court
held that State regulation of the interstate sale of electricity was
barred by the Commerce Clause because such regulation would impose a
``direct burden'' on interstate commerce.
\6\ S. Rep. No. 621, 74th Cong., 1st Sess. 48 (1935). See also
H.R. Rep. No. 1318, 74th Cong., 1st Sess. 8 (1935).
---------------------------------------------------------------------------
The rate-making powers of the Commission are confined to those
wholesale transactions which the Supreme Court held in (Attleboro)
to be beyond the reach of the States. Jurisdiction is asserted also
over all interstate transmission lines whether or not there is sale
of the energy carried by those lines and over the generating
facilities which produce energy 7 for interstate transmission
and sale.
\7\ The provisions of the Senate bill regarding federal
jurisdiction over generating facilities were eliminated from the
final version of the bill.
---------------------------------------------------------------------------
S. Rep. No. 621, 74th Cong., 1st Sess. 48 (1935) (emphasis added).
Thus, federal jurisdiction over transmission lines is not dependent
on whether those lines are used to effect a sale, wholesale or
otherwise.
The provisions of FPA section 201 reserving certain regulatory
authority to the States have been interpreted narrowly.8 The
Supreme Court has stated:
---------------------------------------------------------------------------
\8\ Section 201(a) declares that Federal regulation of the
transmission of electric energy in interstate commerce and the sale
of such energy at wholesale in interstate commerce is necessary in
the public interest, ``such Federal regulation, however, to extend
only to those matters which are not subject to regulation by the
States.'' 16 U.S.C. 824(a). Section 201(b)(1) states that the
provisions of Part II of the FPA apply to the transmission of
electric energy in interstate commerce and the sale of electric
energy at wholesale in interstate commerce but, except as
specifically provided, ``shall not apply to any other sale of
electric energy or deprive a State or State commission of its lawful
authority now exercised over the exportation of hydroelectric energy
which is transmitted across a State line.'' 16 U.S.C. 824(b)(1).
---------------------------------------------------------------------------
In section 201(b), Congress did no more than leave standing
whatever valid state laws then existed relating to the exportation
of hydroelectric energy; by its plain terms, section 201(b) simply
saves from pre-emption under Part II of the Federal Power Act such
state authority as was otherwise ``lawful.'' 9
---------------------------------------------------------------------------
\9\ New England Power Co. v. New Hampshire, 455 U.S. 331, 341
(1982) (NEPCO).
---------------------------------------------------------------------------
The Court also stated:
Nothing in the legislative history or language of the statute
evinces a congressional intent `to alter the limits of state power
otherwise imposed by the Commerce Clause,' * * * or to modify the
earlier holding of this Court concerning the limits of state
authority to restrain interstate trade.10
---------------------------------------------------------------------------
\10\ Id. (citation omitted).
---------------------------------------------------------------------------
Unlike the narrow interpretations given to the FPA provisions
reserving certain regulatory authority to the States,11 the
courts have construed transmission ``in interstate commerce''
broadly. The term does not turn on whether the contract path for a
particular power or transmission sale crosses state lines, but
rather follows the physical flow of electricity. Because of the
highly integrated nature of the electric system, this results in
most transmission of electric energy being ``in interstate
commerce.''
---------------------------------------------------------------------------
\11\ While Congress may exercise its Commerce Clause authority
to grant the States that ``ability to restrict the flow of
interstate commerce that they would not otherwise enjoy,'' Lewis v.
BT Investment Managers, Inc., 447 U.S. 27, 44 (1980), States may not
exercise such regulatory powers unless Congress has expressly stated
its intention to make such an affirmative grant of power. NEPCO, 455
U.S. at 343.
---------------------------------------------------------------------------
One of the earliest cases construing Commission jurisdiction
over transmission was Jersey Central Power & Light Co. v. FPC, 319
U.S. 61 (1943) (Jersey Central). In that case, the Commission
asserted jurisdiction over a New Jersey utility by showing that the
utility owned transmission facilities that were used to transmit
energy in interstate commerce. The Court found that the Commission
had demonstrated that the utility owned transmission facilities that
were indirectly interconnected, through a second New Jersey utility,
to facilities owned by a New York utility and that the facilities
were used to transmit electric energy in interstate commerce.
The Court noted that section 201(c) of the FPA defines electric
energy transmitted in interstate commerce to be energy ``transmitted
from a State and consumed at any point outside thereof.'' The Court
stated:
It is impossible for us to conclude that this definition [of
transmission in interstate commerce] means less than it says and
applies only to the energy at the instant it crosses the state line
and so only to the facilities which cross the line and only to the
company which owns the facilities that cross the line.
319 U.S. at 71. Thus, a critical question regarding the
jurisdictional status of a wheeling transaction is whether the
facilities used to provide the service transmit electric energy in
interstate commerce.
[[Page 21726]]
In Connecticut Light & Power Co. v. FPC, 324 U.S. 515 (1945)
(CL&P), the Court reviewed the Commission's finding that a
Connecticut utility was jurisdictional because it owned transmission
facilities that were used in interstate commerce. The Court
generally embraced the Jersey Central standard for determining
whether facilities are used to transmit electric energy in
interstate commerce. The Court emphasized that whether certain
facilities transmit electric energy in interstate commerce is more a
technical than a legal question. The Court stated:
Federal jurisdiction was to follow the flow of electric energy,
an engineering and scientific, rather than a legalistic or
governmental, test.
324 U.S. at 529. Thus, the Court adopted the Jersey Central test
providing that the Commission's jurisdiction generally extends to
transmission facilities that transmit electric energy in interstate
commerce.
The Court also applied the Jersey Central test in FPC v. Florida
Power & Light Co., 404 U.S. 453 (1972), affirming the Commission's
finding of jurisdiction over a Florida utility. The Commission
demonstrated that the utility transmitted power to another Florida
utility's ``bus'' 12 and that power was simultaneously
transferred from the ``bus'' to a Georgia utility. The Court upheld
the Commission's finding that electric energy from the two Florida
utilities was commingled and was therefore transmitted in interstate
commerce. 404 U.S. at 463.
---------------------------------------------------------------------------
\12\ A bus is an electrical conductor which serves as a common
connection for two or more electrical circuits. Electric Utility
Rate Design Study, Glossary: Electric Utility and Ratemaking Load &
Management Terms, Edison Electric Institute (Sept. 11, 1978).
---------------------------------------------------------------------------
In all of the above cases, the Court's decisions turned on
whether energy being transmitted flowed in interstate commerce as a
technical matter. The decisions did not turn on whether the
transmission of energy flowing in interstate commerce involved
energy that was being sold for resale or was being sold to an end
user. Thus, there is nothing in the statute, its legislative
history, or the case law to indicate that the Commission's
jurisdiction over rates, terms and conditions of transmission in
interstate commerce extends only to wholesale transmission and not
retail transmission. Indeed, the statute on its face gives the
Commission jurisdiction over transmission in interstate commerce and
makes no distinction between wholesale transmission and retail
transmission.
However, there are two important limitations on Commission
authority. First, as discussed above, the FPA does not give the
Commission jurisdiction over sales of electric energy at retail.
Such sales historically have been bundled sales (i.e., generation
and transmission), and courts and the Commission have recognized
State jurisdiction over bundled sales of energy. Second, under
section 201(b)(1) of the FPA, the Commission does not have
jurisdiction over facilities used in local distribution. In CL&P,
the Court stated that local distribution facilities are exempt from
Commission jurisdiction even if those facilities ``carry no energy
except extra-state energy.'' 324 U.S. at 531.
In the next section the Commission further discusses the
statutory provisions and case law that shed light on the demarcation
between transmission and local distribution, and thus on the
jurisdictional line between federal and State authority.
II. Legal Analysis of Commission Jurisdictional Transmission Facilities
and State Jurisdictional Local Distribution Facilities
Two specific circumstances are addressed:
First, what facilities are jurisdictional to the Commission in a
situation involving the unbundled delivery in interstate commerce by
a public utility of electric energy from a third-party supplier to a
purchaser who will then re-sell the energy to an end user?
Second, what facilities are jurisdictional to the Commission in
a situation involving the unbundled delivery in interstate commerce
by a public utility of electric energy from a third-party supplier
to an end user?
Based on an analysis of the relevant legislative history and
case law under the FPA, the Commission reaches the following
conclusions. With respect to the first circumstance, the Commission
concludes that a public utility's facilities used to deliver
electric energy to a wholesale purchaser, whether labeled
``transmission,'' ``distribution,'' or ``local distribution'' are
subject to the Commission's exclusive jurisdiction under sections
205 and 206 of the FPA, and that a public utility's facilities used
to deliver electric energy from the wholesale purchaser to the
ultimate consumer are ``local distribution'' facilities subject to
the rate jurisdiction of the state. 13
---------------------------------------------------------------------------
\13\ There are, of course, facilities that are used to provide
delivery to both wholesale purchasers and end users. In those
situations, we believe that the Commission and the States have
jurisdiction to set rates for the services that are within their
respective jurisdictions. That facilities are used to serve resale
and retail customers does not, however, necessarily mean that the
facilities are local distribution facilities.
---------------------------------------------------------------------------
With respect to the second circumstance, the Commission believes
that, based on the particular facts of the case, some of the public
utility's facilities used to deliver electric energy to an end-user
may be FERC-jurisdictional transmission facilities, while some of
the facilities used may be state-jurisdictional local distribution
facilities.
We set forth below the relevant legislative history and case
law, our legal conclusions, and the factors which we believe are
indicative of whether facilities are used in ``local distribution''
or ``transmission in interstate commerce,'' as those terms are used
in the FPA.
1. Relevant Federal Power Act Provisions
The Commission's jurisdiction is set forth in section 201 of the
FPA. 14 Section 201(b)(1) provides in pertinent part:
---------------------------------------------------------------------------
\14\ 16 U.S.C. 824.
---------------------------------------------------------------------------
The provisions of this Part shall apply to the transmission of
electric energy in interstate commerce and to the sale of electric
energy at wholesale in interstate commerce * * *. The Commission
shall have jurisdiction over all facilities for such transmission or
sale of electric energy, but shall not have jurisdiction * * * over
facilities used in local distribution or only for the transmission
of electric energy in intrastate commerce, or over facilities for
the transmission of electric energy consumed wholly by the
transmitter.15
---------------------------------------------------------------------------
\15\ 16 U.S.C. 824(b) (emphasis added).
---------------------------------------------------------------------------
Some of the court decisions that construe jurisdictional
facilities under section 201 also construe the Commission's
jurisdiction under section 203. Section 203(a) provides, in relevant
part:
No public utility shall sell, lease, or otherwise dispose of the
whole of its facilities subject to the jurisdiction of the
Commission, * * * or by any means whatsoever, directly or
indirectly, merge or consolidate such facilities or any part thereof
with those of any other person * * * without first having secured an
order of the Commission to do so.16
---------------------------------------------------------------------------
\16\ 16 U.S.C. 824b (emphasis added).
---------------------------------------------------------------------------
In addition, section 206(d) concerns facilities ``under the
jurisdiction of the Commission'':
The Commission upon its own motion, or upon the request of any
State commission whenever it can do so without prejudice to the
efficient and proper conduct of its affairs, may investigate and
determine the cost of the production or transmission of electric
energy by means of facilities under the jurisdiction of the
Commission in cases where the Commission has no authority to
establish a rate governing the sale of such energy.17
---------------------------------------------------------------------------
\17\ 16 U.S.C. 824e(d) (emphasis added).
---------------------------------------------------------------------------
2. Legislative History of the FPA
The relevant legislative history of the general purposes of
Title II of the FPA, and of section 201 in particular, focuses
primarily on bundled sales of electric energy and does not directly
address the issue of what constitutes local distribution as opposed
to transmission in interstate commerce.
In discussing the general purposes of Title II of the House
bill, the House Report states:
Title II * * * establishes for the first time regulation of
electric utility companies transmitting energy in interstate
commerce.
* * * * *
* * * Under the decision of the Supreme Court of the United
States in (Attleboro), the rates charged in interstate wholesale
transactions may not be regulated by the States. Part II gives the
Federal Power Commission jurisdiction to regulate these rates. A
``wholesale'' transaction is defined to mean the sale of electric
energy for resale and the Commission is given no jurisdiction over
local rates even where the electric energy moves in interstate
commerce.18
---------------------------------------------------------------------------
\18\ H.R. Rep. No. 1318, 74th Cong., 1st Sess. 7-8 (1935).
---------------------------------------------------------------------------
In its analysis of section 201, the House Report states:
As in the Senate bill no jurisdiction is given over local
distribution of electric energy, and the authority of States to fix
local rates is not disturbed even in those cases where the energy is
brought in from another State.19
---------------------------------------------------------------------------
\19\ Id. at 27.
---------------------------------------------------------------------------
[[Page 21727]]
The Senate Report's discussion of the general purposes of the
FPA states:
The decision of the Supreme Court in (Attleboro) placed the
interstate wholesale transactions of the electric utilities entirely
beyond the reach of the States. Other features of this interstate
utility business are equally immune from State control either
legally or practically.20
---------------------------------------------------------------------------
\20\ S. Rep. No. 621, 74th Cong., 1st Sess. at 17 (1935). See
id. at 18 (``The revision [between the original and final versions
of the Senate bill] has also removed every encroachment upon the
authority of the States. The revised bill would impose Federal
regulation only over those matters which cannot effectively be
controlled by the States.'')
---------------------------------------------------------------------------
In discussing material differences between the final version of
the Senate bill and the original version, the Senate Report states:
Subsection (b), formerly (a), which states the subject matter to
which the part relates, has been clarified to make plain that it
includes interstate transmission where there is no sale and excludes
all facilities used only for production of transmission in
intrastate commerce or in local distribution.21
---------------------------------------------------------------------------
\21\ Id. at 19.
---------------------------------------------------------------------------
In discussing section 201 of the Senate bill, the Senate Report
further states:
The rate-making powers of the Commission are confined to those
wholesale transactions which the Supreme Court held in (Attleboro)
to be beyond the reach of the States. Jurisdiction is asserted also
over all interstate transmission lines whether or not there is sale
of the energy carried by those lines and over the generating
facilities which produce energy for interstate transmission and
sale. It is obvious that no steps can be taken to secure the planned
coordination of this industry on a regional scale unless all of the
facilities, other than those used solely for retail distribution,
are made subject to the jurisdiction of the Commission. Facilities
used only for intrastate commerce or local distribution are
expressly excluded from the operation of the act.22
---------------------------------------------------------------------------
\22\ Id. at 48. The provisions of the Senate bill regarding
federal jurisdiction over generating facilities were eliminated from
the final version of the bill.
---------------------------------------------------------------------------
The Conference Report adds little description regarding
jurisdictional facilities. In reference to section 201(b) it states
that:
[T]he language of the House amendment has been followed with a
clarifying phrase added to remove any doubt as to the Commission's
jurisdiction over facilities used for the generation and local
distribution of electric energy to the extent provided in other
sections of this part and the part next following.23
---------------------------------------------------------------------------
\23\ H.R. Conf. Rep. No. 1903, 74th Cong., 1st Sess. 74 (1935).
---------------------------------------------------------------------------
In addition to the above statements pertaining to section 201 of
the FPA, Congress referenced distribution of energy in the
legislative history of section 206(d). Section 206(d) was originally
enacted as section 206(b) of the FPA. Under the Regulatory Fairness
Act of 1988,24 section 206(b) was redesignated as section
206(d).
---------------------------------------------------------------------------
\24\ Pub. L. No. 100-473, 102 Stat. 2299 (1988).
---------------------------------------------------------------------------
The Conference Report on the original FPA does not address
section 206(b). The Senate Report on the FPA bill states in
pertinent part:
Subsection (b) authorizes the Commission to investigate and
determine the cost of the production or transmission of electric
energy by means of facilities under the jurisdiction of the
Commission in cases where the Commission has no authority to
establish a rate governing the sale of such energy. * * * Since the
rate-making powers granted to the Commission apply only to the
wholesale rates of energy sold in interstate commerce, this last
subsection should be of great benefit in removing the practical
difficulty which the States may encounter in regulating the
interstate distribution rates which are left under their control.
Such rate regulation involves the examination and valuation of
property outside the State. The task is one requiring an agency with
a jurisdiction broader than that of a single State. The authority of
the Federal Commission is to render assistance to the State
commissions in a way which would preserve and make more effective
the jurisdiction which is thus left to the States.25
---------------------------------------------------------------------------
\25\ S. Rep. No. 621, 74th Cong., 1st Sess. 51 (1935) (emphasis
added).
---------------------------------------------------------------------------
The House Report discusses section 206(b) as follows:
This subsection reaches those situations where electric energy
is transmitted in interstate commerce by the same company which
distributes it locally, and will greatly aid State commissions in
fixing reasonable rates in such cases.26
---------------------------------------------------------------------------
\26\ H.R. Rep. No. 1318, 74th Cong., 1st Sess. 29 (1935)
(emphasis added).
---------------------------------------------------------------------------
Thus, the discussions in the two reports do not appear to
contemplate a situation in which the transmitter and seller of
electric energy are different, and neither is a ``local''
distributor. The House Report expressly refers to the same company
being the transmitter and seller of electric energy. The Senate
Report by its terms addresses the regulation of interstate
distribution rates.27
---------------------------------------------------------------------------
\27\ The Senate Report states that interstate distribution rates
are left in the States' control. Obviously, the Senate drew a
distinction between interstate distribution (left in the States'
control) and interstate transmission (given to the FPC). Compare S.
Rep. No. 621 at 49 with H.R. Rep. No. 1318 at 51.
---------------------------------------------------------------------------
The above legislative history on sections 201 and 206(b) does
not provide any definitive answers to the questions raised. We
therefore turn to the case law under the FPA.
3. Case Law Under the FPA
Jersey Central was the first of the major FPC jurisdictional
cases considered by the Supreme Court. The case involved the
acquisition by New Jersey Power and Light Company (New Jersey Power)
of certain securities of Jersey Central Power & Light Company
(Jersey Central) without the Commission's prior approval. The
question before the Court was whether Jersey Central was a ``public
utility'' under section 201(e) 28 of the FPA so that the
Commission's prior approval of the stock acquisition was necessary
under section 203 of the FPA.
---------------------------------------------------------------------------
\28\ Section 201(e) defines a ``public utility'' as ``any person
who owns or operates facilities subject to the jurisdiction under
this Part (other than facilities subject to such jurisdiction solely
by reason of section 210, 211, or 212).'' 16 U.S.C. 824(e). The
section as adopted in 1935 did not contain the parenthetical, which
was adopted in 1978 as part of the Public Utility Regulatory
Policies Act.
---------------------------------------------------------------------------
Jersey Central owned transmission facilities that connected to
facilities that Public Service Electric & Gas Company (Public
Service) owned. The interconnection of these transmission facilities
was in New Jersey. Public Service's facilities in turn connected to
the facilities of the Staten Island Edison Corporation (Staten
Island Edison), a New York utility, at the mid-channel of Kill van
Kull, a body of water separating New Jersey and New York. Jersey
Central delivered energy to and received energy from Public Service
under contract, and Public Service delivered energy to and received
energy from Staten Island Edison under contract.29
---------------------------------------------------------------------------
\29\ Jersey Central, 319 U.S. at 63-65.
---------------------------------------------------------------------------
The Court found that, although Jersey Central generated and
received electricity only in New Jersey, some of the electric energy
that it dispatched to Public Service ``was instantaneously
transmitted to New York.'' 30 The Court held that ``[t]his
evidence * * * furnishes substantial basis for the conclusion of the
Commission that facilities of Jersey Central are utilized for the
transmission of electric energy across state lines.'' 31
Therefore, the Court found that Jersey Central was a public utility
within the meaning of section 201(e).32
---------------------------------------------------------------------------
\30\ Id. at 66.
\31\ Id. at 67 (citation omitted).
\32\ Id. at 73.
---------------------------------------------------------------------------
The Court cited Attleboro, in which the Court found that the
sale of locally produced electric energy for use in another state
resulted in the transmission of electric energy in interstate
commerce, even though title passed at the state line.33 In
Jersey Central, the Court explained the rationale for federal
jurisdiction as follows:
---------------------------------------------------------------------------
\33\ 273 U.S. at 86, 89-90.
---------------------------------------------------------------------------
(Section 201(c) of the FPA) defines the electric energy in
commerce as that ``transmitted from a State and consumed at any
point outside thereof.'' There was no change in this definition in
the various drafts of the bill. The definition was used to ``lend
precision to the scope of the bill.'' It is impossible for us to
conclude that this definition means less than it says * * *. The
purpose of this act was primarily to regulate the rates and charges
of the interstate energy.34
---------------------------------------------------------------------------
\34\ 319 U.S. at 71 (footnote omitted).
---------------------------------------------------------------------------
The Court in Jersey Central thus interpreted the FPA as placing
within the federal province regulation of wholesale sales of
electric energy that, in any manner, flows in interstate commerce.
The language quoted above and the citation to section 201(c) of the
FPA, to be relied upon in subsequent Supreme Court cases, strongly
suggested that the Commission's jurisdiction was not based on
whether there was a sale by the utility, but rather on the flow of
electric energy either into or out of a state, so long as the energy
crosses state lines.
CL&P, which was decided two years after Jersey Central, is the
leading case interpreting
[[Page 21728]]
the section 201(b) local distribution proviso. In CL&P, the
Commission sought to regulate the accounting practices of
Connecticut Light & Power Company (CL&P). 35 At issue was
whether CL&P was a ``public utility'' under the FPA. The utility's
system encompassed an area solely within a single state
(Connecticut) 36 and did not interconnect with any other
company that operated out of state. 37 ``Its purchases and
sales, its receipts and deliveries of power, (were) all within the
state.'' 38 However, CL&P did purchase energy from companies
that had, in turn, purchased energy from Massachusetts. The company
also sold energy to a municipality that exported a portion of that
energy to Fishers Island, located off the coast of Connecticut but
``territory of New York.'' 39 The Commission based its
jurisdiction on these few transactions.40
---------------------------------------------------------------------------
\35\ CL&P, 324 U.S. at 517.
\36\ Id. at 518.
\37\ Id. at 521.
\38\ Id. at 522.
\39\ Id. at 519-21.
\40\ Id.
---------------------------------------------------------------------------
The Court of Appeals affirmed the Commission, holding that the
Commission's jurisdiction extended to ``electric distribution
systems which normally would operate as interstate businesses.'' The
Court of Appeals found that:
Whether or not the facilities by which petitioner distributes
energy from Massachusetts should be classified as `local' is not
relevant to this case. The sole test of jurisdiction of the
Commission over accounts is whether these facilities, `local' or
otherwise, are used for the transmission of electric energy from a
point in one state to a point in another.( 41)
---------------------------------------------------------------------------
\41\ Id. at 522, quoting Connecticut Light & Power Co. v. FPC,
141 F.2d 14, 18 (D.C. Cir. 1944).
---------------------------------------------------------------------------
The Supreme Court reversed. It held that the statutory language
in section 201(b) of the FPA providing that the Commission ``shall
not have jurisdiction * * * over facilities used in local
distribution'' is a limitation upon Commission jurisdiction that
``the Commission must observe and the courts must enforce.'' 42
In analyzing the statute, the Court stated:
---------------------------------------------------------------------------
\42\ 324 U.S. at 529.
---------------------------------------------------------------------------
It has never been questioned that technologically generation,
transmission, distribution and consumption are so fused and
interdependent that the whole enterprise is within the reach of the
commerce power of Congress, either on the basis that it is, or that
it affects, interstate commerce, if at any point it crosses a state
line.
* * * * *
But whatever reason or combination of reasons led Congress to
put the provision in the Act, we think it meant what it said by the
words ``but shall not have jurisdiction * * * over facilities used
in local distribution.'' Congress by these terms plainly was trying
to reconcile the claims of federal and local authorities and to
apportion federal and state jurisdiction over the industry.43
---------------------------------------------------------------------------
\43\ Id. at 529-31.
---------------------------------------------------------------------------
The Court decided that this limitation on jurisdiction was ``a
legal standard that must be given effect in this case in addition to
the technological transmission test.''44
---------------------------------------------------------------------------
\44\ Id. at 531.
---------------------------------------------------------------------------
The Court stated that whether or not local distribution
facilities carried out-of-state electric energy was irrelevant.
Whatever the origin of the electric energy they carried, so long as
the utility used the lines for local distribution,45 they were
exempt from federal jurisdiction.46 In fact, the Court stated
that local distribution facilities ``may carry no energy except
extra-state energy and still be exempt under the Act.'' Id. at 531.
The Court concluded that the Commission's order:
---------------------------------------------------------------------------
\45\ It appears that while the Company received power (at one
location) at 66 kV, it primarily owned facilities at 13.8 kV and
below.
\46\ 324 U.S. at 531.
---------------------------------------------------------------------------
Must stand or fall on whether this company owned facilities that
were used in transmission of interstate power and which were not
facilities used in local distribution.47
---------------------------------------------------------------------------
\47\ Id. at 531 (emphasis added).
---------------------------------------------------------------------------
Upon reversing the Court of Appeals, the Court commented, in
dictum, on the evidence the Commission had relied upon in finding
that the facilities in question were used for transmission. It noted
that the Commission had relied upon certain gas transportation cases
in concluding that transmission extends from the generator to the
point where the function of conveyance in bulk over distance is
completed and the process of subdividing the energy to serve
ultimate consumers, which is the characteristic of ``local
distribution,'' is begun. The Court cautioned:
But a holding that distributing gas at low pressure to consumers
is a local business is not a holding that the process of reducing it
from high to low pressure is not also part of such local business.
In so far as the Commission found in these cases a rule of law which
excluded from the business of local distribution the process of
reducing energy from high to low voltage in subdividing it to serve
ultimate consumers, the Commission has misread the decisions of this
Court. No such rule of law has been laid down.48
---------------------------------------------------------------------------
\48\ Id. at 534.
---------------------------------------------------------------------------
The Court also noted in its dictum, however, that once a company
is properly found to be a ``public utility'' under the Act, the fact
that a local commission may also have jurisdiction does not preclude
exercise of the Commission's functions. Id. at 533.49 The Court
instructed the lower court to remand the case to the Commission for
a finding regarding whether the facilities in question were used in
local distribution.50
---------------------------------------------------------------------------
\49\ See United States v. Public Utilities Commission of
California, 345 U.S. 295, 316 (1953) (Public Utilities Commission):
Certainly the concrete fact of resale of some portion of the
electricity transmitted from a state to a point outside thereof
invokes federal jurisdiction at the outset, despite the fact that
the power thus used traveled along its interstate route
``commingled'' with other power sold by the same seller and
eventually directly consumed by the same purchaser-distributor.
See also Arkansas Power & Light Co. v. FPC, 368 F.2d 376, 383
(8th Cir. 1966) (``Where a company is in fact a public utility, all
wholesale sales for resale in interstate commerce are subject to the
provisions of sections 205 and 206 of the (FPA), regardless of the
facilities used.''). The Eighth Circuit further noted that the
section 201(b) exemption applies to a company's status as a public
utility and not to the Commission's jurisdiction over sales in
interstate commerce for resale. Id., citing Public Utilities
Commission, Colton, infra, and Wisconsin-Michigan, infra.
\50\ Id. at 536.
---------------------------------------------------------------------------
The CL&P case was ultimately disposed of without the Commission
having made a finding that the facilities were used in local
distribution. While the Commission found that it was ``extremely
doubtful'' that it could find that the facilities in question were
not local distribution facilities, 6 FPC 104, 106 (1947), the
Commission did not articulate a definition of local distribution
facilities.
In Wisconsin-Michigan Power Co. v. Federal Power Commission,
51 the Seventh Circuit held that a utility was a jurisdictional
public utility where it operated two divisions in Wisconsin and
Michigan in a coordinated manner such that electric energy from one
state was transmitted to the other, and vice versa, ``in appreciable
amounts by the power company and by it commingled with energy
generated in the two respective districts and then delivered to the
[wholesale] customers * * *.'' 52 The court also rejected the
notion that the energy changed its form or character when it was
stepped down in voltage before it reached the wholesale purchasers.
53
---------------------------------------------------------------------------
\51\ 197 F.2d 472 (7th Cir. 1952), cert. denied, 345 U.S. 934
(1953) (Wisconsin-Michigan).
\52\ Id. at 474.
\53\ Id. (``Obviously the energy thus transmitted in interstate
commerce is not changed in form or in character except that the
voltage is reduced to an extent consistent with efficient economic
management and operation.'').
---------------------------------------------------------------------------
The court in Wisconsin-Michigan distinguished between
transmission and local distribution by focusing on wholesale sales
of electric energy versus retail sales (``local rates'') of electric
energy. It cited the House Report on the FPA, and characterized the
legislative history as follows:
The legislative history, (H.R. Rep. No. 1318), 74th Cong., 1st
Sess. pages 7, 8 and 27 (1935), discloses that the Congressional
Committee intended that the provisions of the (FPA) should apply to
the transmission of electric energy in interstate commerce, i.e.,
the sale of energy at wholesale in interstate commerce, but not to
the retail sale of any such energy in local distribution; that the
(FPA) left to the state the authority to fix local rates where the
energy is brought in from other states, and that the rate making
power of the (FPC) was to be confined to those wholesale
transmissions which the Supreme Court had held in (Attleboro) to be
beyond the reach of the state. Under that decision, said the
committee, the rates charged in interstate wholesale transactions
could not be regulated by the states. It defined a wholesale
transaction as the sale of electric energy for resale.54
---------------------------------------------------------------------------
\54\ 197 F.2d at 476 (emphasis added).
---------------------------------------------------------------------------
The Seventh Circuit's characterization of the House Report seems
to equate transmission of electric energy in interstate commerce
with the sale of energy at wholesale in interstate commerce.
However, this interpretation is at odds with both the
[[Page 21729]]
plain words of the statute as well as the language of the House
Report, both of which refer to transmission in interstate commerce
separately from sales for resale in interstate commerce.55 In
addition, the Senate Report, which the Seventh Circuit did not
mention, clearly recognized jurisdiction over all interstate
transmission lines, whether or not a sale of energy is carried by
those lines.56
---------------------------------------------------------------------------
\55\ See H.R. Rep. No. 1318 at 27. (``Subsection (b) confers
jurisdiction upon the Commission over the transmission of electric
energy in interstate commerce and the sale of electric energy in
wholesale in interstate commerce * * *.'' emphasis added).
\56\ See S. Rep. No. 621 at 48 (``Jurisdiction is asserted over
all interstate transmission lines whether or not there is a sale of
the energy carried by those lines * * *.'').
---------------------------------------------------------------------------
The Wisconsin-Michigan court also cited analogous natural gas
cases, stating that ``[t]he question is essentially, when does
interstate commerce transportation end and where do the local
distribution facilities first become operative.'' 57 The court
further stated that:
---------------------------------------------------------------------------
\57\ 197 F.2d at 477.
---------------------------------------------------------------------------
(U)pon delivery to (the wholesaler) local distribution begins
when he resells. His sales and distribution at retail are clearly
local in character, and constitute only local distribution; but at
no point before delivery to him has been completed, has interstate
transmission terminated. In other words, ``facilities used in local
distribution'' means facilities used for making resale and
distribution to consumers, jurisdiction over which is left to the
states. It was only because of this conclusion that the Supreme
Court said, (citation omitted), the Act ``cut(s) sharply and cleanly
between sales for resale and direct sales for consumptive uses.'' We
think there is no ground for the position that local distribution
includes any transmission occurring before the wholesaler who
resells at retail is reached.58
---------------------------------------------------------------------------
\58\ Id., citing FPC v. East Ohio Gas Co., 338 U.S. 464 (1950)
(East Ohio).
---------------------------------------------------------------------------
The Seventh Circuit concluded that the sales for resale were
made in interstate commerce; that local distribution had not begun;
that the interstate character of the transmission persisted until
delivery to the wholesaler; that, up to that point, no local
distribution facilities were in operation and that, therefore, the
sales were subject to Commission regulation.
In Federal Power Commission v. Southern California Edison
Company (the Colton case),59 the Supreme Court held that the
FPA provides a clear line of demarcation between jurisdictional
transactions and non-jurisdictional transactions. However, this
case, too, involved bundled sales of electric energy. In the facts
of the c
FR Doc. 96-10694 Promoting Wholesale Competition Through Open Access Non- Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities
ase, Southern California Edison Company (Edison) admitted
that it was a public utility by virtue of owning two interstate
transmission lines.60 At issue was whether its sales of
electric energy to the City of Colton, California, for resale to
Colton's retail customers, were jurisdictional. Included in the
electric energy that Edison sold to Colton was out-of-state electric
energy from Hoover Dam.61 The Commission ruled that the sale to
Colton was a sale of electric energy at wholesale in interstate
commerce subject to regulation under the FPA.62 In upholding
the Commission, the Court held that Edison's importation of out-of-
state electricity for resale to Colton sufficed to confer federal
jurisdiction.
---------------------------------------------------------------------------
\59\ 376 U.S. 205 (1964) (Colton).
\60\ The Supreme Court noted that Edison's status as a public
utility did not decide the question of whether the FPC could assert
jurisdiction over the rates for the Edison-Colton sale. Id. at 208
n.3.
\61\ Id. at 208, 209 & n.5.
\62\ Id. at 208. See Arkansas Electric Cooperative Corp. v.
Arkansas Public Service Commission, 461 U.S. 375, 380 (1983)
(``(Colton) held, among other things, that * * * a California
utility that received some of its power from out-of-state was
subject to federal and not state regulation in its sales of
electricity to a California municipality that resold the bulk of the
power to others.'').
---------------------------------------------------------------------------
The Court, citing an earlier Supreme Court case,63
characterized Congressional intent in the FPA:
---------------------------------------------------------------------------
\63\ Illinois Natural Gas Co. v. Central Illinois Public Service
Co., 314 U.S. 498, 504 (1942).
---------------------------------------------------------------------------
(W)hat Congress did was to adopt the test developed in the
Attleboro line which denied state power to regulate a sale ``at
wholesale to local distributing companies'' and allowed state
regulation of a sale at ``local retail rates to ultimate
consumers.'' 64
---------------------------------------------------------------------------
\64\ 376 U.S. at 214.
---------------------------------------------------------------------------
The Court rejected the argument that FPC jurisdiction was
confined to those interstate wholesale sales constitutionally beyond
the power of state regulation by force of the Commerce Clause, and
was to be determined on a case-by-case analysis of the impact of
state regulation upon the national interest. The Court stated that
in the FPA:
(C)ongress meant to draw a bright-line easily ascertained,
between state and federal jurisdiction, making unnecessary such
case-by-case analysis. This was done in the Power Act by making FPC
jurisdiction plenary and extend[ed] it to all wholesale sales in
interstate commerce except those which Congress has made explicitly
subject to regulation by the States.65
\65\ Id. at 215-216.
---------------------------------------------------------------------------
The Court held that ``(t)here is no such exception covering the
Edison-Colton sale.'' 66
\66\ Id. at 216 (footnote omitted).
---------------------------------------------------------------------------
Parties in the Colton case had raised the question of whether
jurisdiction over the Colton sale was prevented by the ``local
distribution'' proviso of section 201(b). The Court stated that
whether facilities are local distribution facilities is a matter for
the Commission to decide in the first instance. Citing CL&P, supra,
it stated:
Whether facilities are used in local distribution--although a
limitation on FPC jurisdiction and a legal standard that must be
given effect in addition to the technological transmission test * *
*--involves a question of fact to be decided by the FPC as an
original matter.67
\67\ Id. at 210 n.6 (citation omitted).
The Court cited evidentiary support and the Commission's expertise
in such matters in upholding the Commission's determination that
certain facilities owned by Edison were used exclusively to effect
the wholesale sale to Colton and not for local distribution. Such
facilities included 12 kV lines that served an industrial customer,
several lighted highway signs, a residence and a railroad section
house before they reached the transformers in the Colton substation.
The FPC had held that those uses prior to the lines reaching the
Colton substation did not transform the lines into local
distribution facilities.68
---------------------------------------------------------------------------
\68\ Id. at 210 n.6.
---------------------------------------------------------------------------
In Duke Power Company v. Federal Power Commission (Duke),69
the D.C. Circuit held that a public utility's acquisition of
facilities used solely in local distribution, and which would
continue to be used for local distribution, was beyond the
Commission's jurisdiction under section 203. The case involved Duke
Power Company's (Duke's) proposed acquisition of facilities owned by
Clemson University (Clemson), which were used to distribute
electricity off-campus to customers (primarily university personnel)
in two South Carolina counties. Clemson purchased the power at
wholesale from Duke. No one appeared to contest the conclusion that
the 7 miles of distribution line and 418 service connections owned
by Clemson were ``local distribution'' facilities.70 Rather,
the case turned on interpreting section 203 and whether it was
intended to affect only acquisitions of jurisdictional facilities,
or also to affect acquisitions of non-jurisdictional facilities. In
interpreting section 203, however, the D.C. Circuit extensively
analyzed and discussed the fundamental jurisdictional lines that
Congress drew in section 201.
---------------------------------------------------------------------------
\69\ 401 F.2d 930 (D.C. Cir. 1968) (Duke).
\70\ Duke delivered power to Clemson at a distribution voltage
of 4,160 volts. The step-down transformers by which the voltage was
reduced, and the substations at which the delivery was effected,
were owned by Duke. 401 F.2d at 931, n.8.
---------------------------------------------------------------------------
Citing to the CL&P case, the court in Duke stated:
The Act, as we have seen, effectuated federal control over the
transmission and the sale at wholesale of electric energy in
interstate commerce, and established the Commission's regulatory
power over public utilities engaging in either of these
pursuits.\71\
\71\ 401 F.2d at 938-39 (emphasis added, footnotes omitted).
---------------------------------------------------------------------------
However, quoting CL&P, the court further stated:
The expression ``facilities used in local distribution'' is one
of relative generality. But as used in this Act it is not a
meaningless generality in the light of our history and the structure
of our government. We hold the phrase to be a limitation on
jurisdiction and a legal standard that must be given effect in this
case in addition to the technological transmission test.\72\
---------------------------------------------------------------------------
\72\ Id. (footnote omitted).
---------------------------------------------------------------------------
The court further rejected the Commission's concept that, in
order to determine whether jurisdiction over any particular
acquisition existed, the impact of local supervision be measured on
a case-by-case basis. Quoting from Colton, the court stated:
[T]his ``flexible approach''--involving as it does the
consideration, inter alia, of ``the
[[Page 21730]]
effect of the regulation upon the national interest in the
commerce''--has been flatly rejected as a technique for resolving
jurisdictional conflicts between the Commission and state bodies. *
* * We think that like the line ``(i)t cut sharply and cleanly
between sales for resale and direct sales for consumptive uses'' to
facilitate jurisdictional determinations in rate regulation,
``Congress meant to draw a bright line easily ascertained, between
state and federal jurisdiction, making unnecessary such case-by-case
analysis,'' in distributing regulatory power over the acquisition of
facilities.\73\
\73\ Id. at 949 (footnotes omitted).
---------------------------------------------------------------------------
The court rejected the Commission's argument that jurisdiction over
the merger or consolidation of jurisdictional facilities with those
of any other ``person'' under section 203 gave the Commission
jurisdiction over Duke's acquisition. The court stated that the FPA
reflects a policy ``` that matters largely of a local nature, even
though interstate in character, should be handled locally and should
receive the consideration of local [officials] familiar with the
local conditions in the communities involved.' '' \74\
---------------------------------------------------------------------------
\74\ Id. at 936 (quoting from Hearings on H.R. 5423 before the
House Committee on Interstate and Foreign Commerce, 74th Cong., 1st
Sess. 393 (1935) (testimony of then-FPC Commissioner Seavey)).
---------------------------------------------------------------------------
Federal Power Commission v. Florida Power & Light Company \75\
is the last major court case to address the Commission's
transmission jurisdiction. In this case, the Commission sought to
impose its accounting rules upon Florida Power & Light Company
(Florida Power & Light). The company's system lay solely within the
borders of Florida and did not directly connect with any out-of-
state utility.\76\ The Commission held that Florida Power & Light
did own facilities that transmitted electric energy in interstate
commerce, but the Court of Appeals for the Fifth Circuit ruled that
the Commission did not have substantial evidence to support its
finding.
---------------------------------------------------------------------------
\75\ 404 U.S. 453, reh'g denied, 405 U.S. 948 (1972) (Florida
Power & Light).
\76\ 404 U.S. at 456.
---------------------------------------------------------------------------
The Supreme Court reversed. The Supreme Court noted that Florida
Power & Light was a member of the Florida Power Pool along with
Florida Power Corporation (Florida Power Corp.).\77\ In turn,
Florida Power Corp. connected with Georgia Power Company (Georgia
Power) at a ``bus'' \78\ south of the Georgia-Florida border.\79\
Florida Power Corp. regularly exchanged power with Georgia
Power.\80\ In many instances, Florida Power Corp. transferred power
to Florida Power & Light instantly after receiving power from
Georgia Power, and transferred power to Georgia Power immediately
after receiving power from Florida Power & Light.\81\ The Supreme
Court found that power commingled in the bus moved across state
lines, and concluded that Florida Power & Light engaged in
transmission in interstate commerce. The Court held that, to
establish jurisdiction, the Commission need only show that ``some
(Florida Power & Light) power goes out of State.'' \82\ The Court
further explained that ``(i)f any (Florida Power & Light) power has
reached Georgia, or (if Florida Power & Light) makes use of any
Georgia power * * * FPC jurisdiction will attach * * *.''\83\
---------------------------------------------------------------------------
\77\ Id. at 456.
\78\ A ``bus'' is a connector or group of connectors that serves
as a common connection for two or more circuits.
\79\ 404 U.S. at 457.
\80\ Id.
\81\ Id. at 457 & n.8.
\82\ Id. at 461. (emphasis omitted).
\83\ Id. at 461 n.10. (emphasis added).
---------------------------------------------------------------------------
There is also a line of cases that address, among other things,
what constitutes a Commission jurisdictional ``sale of electric
energy at wholesale'' \84\ under section 201 of the FPA.\85\ These
cases all concerned bundled sales. While the issues posed above
involve unbundled wheeling, the ``resale'' cases are helpful to the
extent they suggest that local distribution takes place only after
power is subdivided. See, e.g., 345 U.S. at 316 (``the facilities
supplied `local distribution' only after the current was subdivided
for individual consumers.'').
---------------------------------------------------------------------------
\84\ See Section 201(d), 16 U.S.C. 824(d) (1988).
\85\ Public Utilities Commission, supra note 345; City of
Oakland, California v. FERC, 754 F.2d 1378 (9th Cir. 1985)
(Oakland). See also Alexander v. FERC, 609 F.2d 543 (D.C. Cir. 1979)
(Alexander).
---------------------------------------------------------------------------
4. Natural Gas Act
The Natural Gas Act (NGA) was adopted in 1938. Like the FPA, the
NGA contains language limiting the Commission's jurisdiction in
situations involving local distribution.\86\
---------------------------------------------------------------------------
\86\ Courts often rely on cases construing the NGA when
interpreting the FPA, and vice versa. E.g., Arkansas Louisiana Gas
Co. v. Hall, 453 U.S. 571, 577 n.7 (1981).
---------------------------------------------------------------------------
Section 1(b) of the NGA provides:
The provisions of this Act shall apply to the transportation of
natural gas in interstate commerce, to the sale in interstate
commerce of natural gas for resale for ultimate public consumption
for domestic, commercial, industrial, or any other use, and to
natural gas companies engaged in such transportation or sale, but
shall not apply to any other transportation or sale of natural gas
or to the local distribution of natural gas or to the facilities
used for such distribution or to the production or gathering of
natural.\87\
---------------------------------------------------------------------------
\87\ 15 U.S.C. 717(b) (emphasis added).
---------------------------------------------------------------------------
There is similarity in many respects between the House and
Senate Reports on the FPA and the NGA with respect to the
jurisdiction given the Commission. For example, all four reports
mention Attleboro as placing interstate wholesale transactions
beyond the reach of the States. As indicated in the House Report on
the NGA, the States could ``regulate sales to consumers even though
such sales are in interstate commerce, such sales being considered
local in character and in the absence of congressional prohibition
subject to State regulation.'' (See H.R. Rep. No. 709, 75th Cong.,
1st Sess. 1). However, the House and Senate Reports on the NGA
contain identical language not found in the reports on the FPA:
In view of the importance of section 1(b), which states the
scope of the act, it seems advisable to comment on certain
provisions appearing therein. It will be noted that this subsection
of the bill, after affirmatively stating the matters to which the
act is to apply, contains a provision specifying what the act is not
to apply to, as follows:
But shall not apply to any other transportation or sale of
natural gas or to the local distribution of natural gas or to the
facilities used for such distribution or to the production or
gathering of natural gas.
The quoted words are not actually necessary, as the matters
specified therein could not be said fairly to be covered by the
language affirmatively stating the jurisdiction of the Commission,
but similar language was in previous bills, and, rather than invite
the contention, however unfounded, that the elimination of the
negative language would broaden the scope of the act, the committee
has included it in this bill. That part of the negative declaration
stating that the act shall not apply to ``the local distribution of
natural gas'' is surplusage by reason of the fact that distribution
is made only to consumers in connection with sales, and since no
jurisdiction is given to the Commission to regulate sales to
consumers the Commission would have no authority over distribution,
whether or not local in character. (Emphasis added).88
---------------------------------------------------------------------------
\88\ H.R. Rep. No. 709, 75th Cong., 1st Sess. 3 (1937); S. Rep.
No. 1162, 75th Cong., 1st Sess. 3 (1937).
---------------------------------------------------------------------------
As a result of this language it can be argued that Congress
considered distribution (and local distribution) only in the context
of bundled retail sales of natural gas. In fact, it appears that all
of the court cases affirming the states' right to regulate local
distribution of gas have involved bundled retail sales. See
Panhandle Eastern Pipe Line Co. v. Michigan Public Service
Commission, 341 U.S. 329 (1951) (Panhandle). There the Court, in
affirming the State of Michigan's right to regulate an interstate
pipeline's proposed bundled retail sales of gas to industrial
consumers, noted that the pipeline company proposed to lay pipeline
in ``the streets and alleys of Detroit'' and ignored the local
distribution company's request for additional gas to meet the
increased needs of the industrial consumers. Id. at 333. While the
Court based its holding on a state's authority to regulate direct
(retail) sales to an end-user, rather than on the basis of the
section 1(b) local distribution provision, it also found that the
proposed sales were ``primarily of local interest'' and ``emphasized
the need for local regulation.'' Id. Two years before Panhandle, the
Supreme Court issued its decision in FPC v. East Ohio Gas Co., 338
U.S. 465 (1949) (East Ohio). East Ohio Gas Company owned and
operated a natural gas business wholly within the State of Ohio. The
company sold gas only to Ohio customers but most of the gas was
transported to Ohio from other states by interstate pipelines. These
interstate pipelines connected inside Ohio with East Ohio's large
high pressure lines. The gas then was transported over 100 miles
through East Ohio's system to its local distribution system. East
Ohio argued that it was exempt from Commission jurisdiction because
all of its facilities were local distribution.
The Court disagreed, finding the Commission's jurisdiction
extends over the
[[Page 21731]]
transportation of gas in interstate commerce through high-pressure
transmission lines and that distribution did not begin until the
point where pressure is reduced and gas enters local mains. The
Court stated that: ``[w]hat Congress must have meant by `facilities'
for `local distribution' was equipment for distributing gas among
customers within a particular local community, not the high-pressure
pipelines transporting the gas to the local mains.'' 89
---------------------------------------------------------------------------
\89\ 338 U.S. at 469-70.
---------------------------------------------------------------------------
The Commission relied in part on East Ohio's high pressure/low
pressure distinction in a recent NGA section 7 certificate case
which authorized construction of facilities to bypass the local
distribution company.90 On appeal, the California Commission
argued that under section 1(b) it should at least have
``jurisdiction over the `taps, meters and other tie-in facilities'
that link the pipeline to end users.'' 91 The court disagreed:
---------------------------------------------------------------------------
\90\ See Mojave Pipeline Company, 35 FERC para. 61,199 (1986),
reh'g denied, 41 FERC para. 61,040 (1987), reh'g denied, 42 FERC
para. 61,351 (1988); see also Mojave Pipeline Company, 66 FERC para.
61,194 (1994), reh'g pending.
\91\ See Public Utilities Commission of the State of California
v. FERC, et al., 900 F.2d 269, 273 (D.C. Cir. 1990) (footnote
omitted) (WyCal).
---------------------------------------------------------------------------
While as a matter of ordinary English `local distribution' might
be understood to encompass any delivery to an end user, that is
hardly the only or even more plausible reading. Distribution
conjures up receiving a large quantity of some good and parcelling
it out among many takers.92
---------------------------------------------------------------------------
\92\ Id. at 276.
---------------------------------------------------------------------------
After reviewing the report language discussed above, the court
also stated:
Insofar as congressional committees spoke to the matter * * *
they appear to have viewed distribution as confined to its
parcelling out function and (probably) even more narrowly, to
parcelling out accompanied by retail sales. 93
---------------------------------------------------------------------------
\93\ Id. (emphasis in original).
---------------------------------------------------------------------------
In Cascade Natural Gas Corporation v. FERC, et al. (Cascade),
the court affirmed the Commission's authorizing an interstate
pipeline under section 7 of the NGA ``to construct a tap and meter
facility that would allow it to deliver natural gas directly to two
industrial consumers * * *.''94 To reach the interstate
pipeline, the industrials constructed a nine-mile pipeline.
Together, the facilities bypassed the local distribution
company.95
---------------------------------------------------------------------------
\94\ 955 F.2d 1412, 1414 (10th Cir. 1992).
\95\ Unlike the situation in WyCal where the pipeline made
direct sales to end users, in Cascade the pipeline transported gas
purchased from third parties. See Northwest Pipeline Corporation, 51
FERC para. 61,289 at 61,909 (1990).
---------------------------------------------------------------------------
The court rejected arguments that section 1(b) deprived the
Commission of jurisdiction holding that:
``Local distribution,'' as Congress viewed the term, involves
two components: the retail sale of natural gas and its local
delivery, normally through a network of branch lines designed to
supply local consumers.96
---------------------------------------------------------------------------
\96\ Cascade, 955 F.2d at 1421.
---------------------------------------------------------------------------
5. Analysis
a. What facilities are jurisdictional to the Commission in a
situation involving the unbundled delivery in interstate commerce by
a public utility of electric energy from a third-party supplier to a
purchaser who will then re-sell the energy to an end user?
The case law supports the conclusion that any facilities of a
public utility used to deliver electric energy in interstate
commerce to a wholesale purchaser, whether such facilities are
labeled ``transmission,'' ``distribution'' or ``local
distribution,'' are subject to the Commission's jurisdiction under
sections 205 and 206.
This conclusion is supported by Public Utilities Commission,
supra, in which the Supreme Court, in the section of its opinion
addressing the section 201(b) local distribution provision, held
that local distribution facilities began ``only after the current
was subdivided for individual consumers.'' \97\ Wisconsin-Michigan,
supra, in which the Seventh Circuit held that there is no local
distribution until the wholesaler who re-sells at retail is reached,
is to like effect.
---------------------------------------------------------------------------
\97\ 345 U.S. at 316 (footnote omitted).
---------------------------------------------------------------------------
This conclusion, which results in a ``functional'' line being
drawn to determine Commission jurisdiction, is not only consistent
with the case law under section 201, but is also consistent with our
interpretation of the line drawn under newly amended FPA sections
211 and 212. As long as electric energy is being sold to a
legitimate wholesale purchaser, we believe the Commission has
jurisdiction under sections 201, 205, and 206 of the FPA over the
public utility's facilities used to deliver electric energy to that
purchaser.
b. What facilities are jurisdictional to the Commission in a
situation involving the unbundled delivery in interstate commerce by
a public utility of electric energy from a third-party supplier
directly to an end user?
In analyzing jurisdiction over unbundled retail wheeling, we
believe it is important to distinguish between unbundled wheeling
provided by the public utility who previously provided bundled
retail service to the end user, and unbundled wheeling provided by
other public utilities to the end user. For example, a former
bundled retail customer may need unbundled wheeling services from
its previous public utility generation supplier, as well as
unbundled wheeling from one or more intervening public utilities, in
order to reach a distant generation supplier. In this scenario, the
Commission believes it would have jurisdiction over all of the
facilities used for the unbundled wheeling provided by the
intervening public utilities.\98\ The more difficult issue is
whether some portion of the facilities used to transmit energy from
the transmitting utility in closest proximity to the end user (the
former supplier of the bundled product) is local distribution
facilities. We believe that in most, if not all circumstances, some
portion will be local distribution facilities.
---------------------------------------------------------------------------
\98\ The Commission would not have jurisdiction over the rates
for the sale of generation by the distant supplier because the
transaction would be a retail sale of electric energy.
---------------------------------------------------------------------------
The case law is replete with statements that the local
distribution provision of section 201 must be given effect. However,
the Supreme Court in both CL&P and Colton, supra, has stated that
whether facilities are used in local distribution is a question of
fact to be decided by the Commission as an original matter. Thus,
there is no clear case law on a ``bright line'' between transmission
and local distribution. In addition, regardless of the details of
the chain of delivery services necessary to move electric energy
from the generator to the end user, in most cases the last public
utility in the chain will use facilities that historically were
considered local distribution facilities. Accordingly, unlike the
situation involving unbundled wholesale wheeling, for which the case
law clearly supports a ``functional'' test, the Commission believes
the case law and practical realities of a changing industry support
an analysis of local distribution facilities based on the
facilities' functional as well as technical characteristics.
While it would be preferable to draw an absolutely ``bright''
line (e.g., based on technical characteristics such as voltage), the
Commission does not believe this is required by the case law and,
importantly, would not be a workable approach in all cases because
of the variety of circumstances that may arise and because utilities
themselves classify facilities differently (e.g., one utility may
classify a 69 kV facility as transmission; another may classify it
as distribution).
Therefore, the Commission is adopting several indicators it will
evaluate in determining whether particular facilities are
transmission or local distribution in the case of vertically
integrated transmission and distribution utilities: \99\
---------------------------------------------------------------------------
\99\ In the case of a distribution-only utility, which is
franchised by a State or local government and sells only at retail,
all of the circuits (and related wires, transformers, towers, and
rights of way) which it owns or operates (regardless of voltage)
would be local distribution facilities.
---------------------------------------------------------------------------
Local distribution facilities are normally in close
proximity to retail customers.
Local distribution facilities are primarily radial in
character.
Power flows into local distribution systems, it rarely,
if ever, flows out.
When power enters a local distribution system, it is
not reconsigned or transported on to some other market.
Power entering a local distribution system is consumed
in a comparatively restricted geographical area.
Meters are based at the transmission/local distribution
interface to measure flows into the local distribution system.
Local distribution systems will be of reduced
voltage.\100\
---------------------------------------------------------------------------
\100\ The Commission has analyzed utilities' filings required by
the Commission's regulations. These filings are made on FERC Form
No. 1. While there is no uniform breakpoint between transmission and
distribution, it appears that utilities account for facilities
operated at greater than 30 kV as transmission and that distribution
facilities are usually less than 40 kV.
---------------------------------------------------------------------------
In summary, for unbundled wholesale wheeling the Commission will
apply a
[[Page 21732]]
functional test. The only definitive question will be whether the
entity to whom the power is delivered is a lawful wholesaler. For
unbundled retail wheeling the Commission will apply a combination
functional-technical test that will take into account technical
characteristics of the facilities used for the wheeling. The
Commission concludes that these tests are consistent with the FPA,
---------------------------------------------------------------------------
its legislative history and the case law discussed above.
BILLING CODE 6717-01-P
[GRAPHIC] [TIFF OMITTED] TR10MY96.000
BILLING CODE 6717-01-C
Appendix H.--Table ES-2.--National Emissions of NOX as Projected in Both Base Cases and All Proposed Rule
Scenarios
[Thousand tons]
----------------------------------------------------------------------------------------------------------------
Under assumption that Under assumption that gas prices
relative gas and coal increase compared to coal prices
prices remain constant ----------------------------------------
----------------------------
Year Competition- Competition- Low
Constant favors-gas High-price- favors-coal response
price- proposed differential proposed proposed
differential rule base case rule rule
base case scenario scenario scenario
----------------------------------------------------------------------------------------------------------------
1993....................................... 5,844 5,844 5,844 5,844 5,844
2000....................................... 5,362 5,255 5,672 5,763 5,743
2005....................................... 5,579 5,449 6,053 6,108 6,056
2010....................................... 5,772 5,638 6,426 6,519 6,426
----------------------------------------------------------------------------------------------------------------
[[Page 21733]]
Promoting Wholesale Competition Through Open Access Non- Discriminatory
Transmission Services by Public Utilities
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities
(As corrected April 25, 1996)
[Docket No. RM95-8-000; Docket No. RM94-7-001]
Issued April 24, 1996.
HOECKER, Commissioner, concurring in part and dissenting in
part:
General Observations
A. Four years and untold numbers of conferences, studies, and
speculations after the Energy Policy Act, the Commission today takes
a major step in bringing competition to the wholesale bulk power
market in the United States. Order No. 888 (FERC Stats. & Regs.
para. 31,036), together with our order establishing an open access
same-time information system (OASIS) (Order No. 889, FERC Stats. &
Regs. para. 31,037) and our proposal to conform all transmission
tariffs to a uniform capacity reservation system (FERC Stats. &
Regs. para. 32,517), will set in motion a dynamism seldom witnessed
in the electric power business. In that sense, the organizational,
operational, and economic consequences of the requirements we adopt
today defy prediction. I believe nevertheless that the Commission's
Final Rule today is a sound and reasoned decision about the industry
as we now know it and as we think it may evolve. I therefore
announce my unequivocal support for the order's basic tenets as we
have chosen to implement them--the unbundled wholesale utility
services, open and non-discriminatory access to transmission and to
information about transmission, service comparability, an
opportunity for increased competition among generation sources,
coordination with and deference to state regulatory interests, and
full recovery of eligible stranded investments.
B. Restructuring the electric power industry is a matter of
national interest and priority. Electricity is ubiquitous. Its
benefits are key to the American quality of life. Operating 750,000
MW of generation capacity arrayed across three synchronous regional
transmission grids, the electric industry is the nation's most
capital intensive. The 179 largest investor-owned utilities alone
control nearly $600 billion in assets. And, total electricity
revenues constitute between 3 and 4 percent of the gross domestic
product (GDP)--larger than telecommunications, natural gas pipeline,
and airline revenues combined.
Both the Congress and the President have recognized our
obligation to ensure that these resources are used wisely and
efficiently. We all recognize that systemic change is happening
within the industry and that regulation must change to take maximum
advantage of the most constructive of those forces. ``At the center
of the success of our economy is the market, and at the core of the
success of the market is competition,'' states the President in his
1996 Economic Report to the Congress; ``it is competition that
drives down costs and prices, induces firms to produce the goods
consumers want, and spurs innovation and the expansion of new
markets abroad.'' Yet, as state and local governments consider the
future of industries heretofore heavily regulated in the public
interest, deregulation is not enough, states the President.
Competition must be actively promoted and preserved from the abuses
and distortions associated with monopoly power, as well as from
outdated forms of regulation that provide inappropriate incentives.
In the electric utility restructuring process, several difficult
challenges must still be met here and elsewhere. First, policymakers
must make the tough choices to attack access discrimination and
promote competition while also ensuring reliability and economical
service. Success in these undertakings may require pricing
innovation and structural reforms to attain significant long-run
gains in efficiency and productivity. Economic Report, at 183-185.
Second, no transition to a new regime of operating rules and
assumptions, can be achieved reasonably if regulated companies are
shorn of the opportunity to recover prudently incurred costs.
Utility investments that may become stranded or uneconomic as
competitive choice displaces franchise monopoly are estimated to
represent a $100 billion-plus risk for public utilities. State and
federal regulators must confront this issue in the interest of
equity and a swift readjustment to the new competitive realities. As
the President's Economic Report makes clear, it will be important to
future suppliers of private capital for public use that a regulatory
bargain made must remain a bargain kept. ``Credible government is
key to a successful market economy, because it is so important for
encouraging long-term investments.'' Id., at 186-188. Third,
maintaining competitive parity and environmental protection are key
challenges as well. That means, among other things, that
environmental policy must respond to the environmental risks
associated with restructuring and vice versa. Id., at 188-189. This
assessment of the realities and challenges facing this Commission,
its state counterparts, and the diverse elements of the industry
substantially ratifies the Commission's actions today.
C. The long-run prospect for reform of the wholesale market is
promising, though the task seems daunting. The preamble to the Final
Rule begins by outlining the difficult issues that await this
Commission and the industry: (1) Corporate organizational matters,
including the role of independent system operators (ISOs) in
promoting more efficient operation of the transmission system on a
regional basis; (2) the need for a new merger policy, which I
believe must be predicated on a thorough understanding of emerging
markets and genuine ratepayer protections instead of a subjective
tally of supposed ``benefits''; and (3) further efforts to make
greater use of flow-based pricing where appropriate. In adopting the
OASIS requirements, we have taken a first step in recognizing that
competitive markets do not consist of wires and turbines alone, but
of information also. Full competition requires the consolidation of
the electron transportation system with the electronic information
superhighway.
One thing is abundantly clear: restructuring will require
continued innovation and fortitude from our capable staff,
cooperation from state regulators, patience and foresight from
legislators and, most of all, creativity, responsiveness, and
endurance from both utility management and electric consumers.
II. Concurrence on Specific Issues
The Final Rule resolves certain matters of policy and law in
ways which, despite my fundamental agreement, I would like to offer
some additional perspectives.
A. Coordinating State and Federal Regulatory Interests
Perhaps no single issue will influence the success or failure of
restructuring as will the capacity of the FERC and state regulators
to reach meaningful accommodations as the electric utility industry
becomes increasingly subject to competitive forces. The vertical
organization and technological integration of the electric power
business contributes to the impression of a regulatory system
riddled with gaps and overlaps, interregional inequities, and
uncertainty. To the extent that impression predominates in the
months to come, the pressure from legislators and the financial
community to devise single-minded national solutions to issues of
regional or local significance will likely prove irresistible.
The regulation of this industry is a unique exercise in
federalism. The Deputy Secretary of Energy wisely acknowledged
months ago that, ``the aftermath of FERC's open access rulemaking
will put to the test our ability to evolve improved means for
unsnarling the governance problems of federal and state
authorities.'' Charles B. Curtis, Remarks Before the Third DOE/NARUC
National Symposium, December 4, 1995. I find no shortage of good
ideas on how to achieve better state, federal, and inter-regional
cooperation. But, unanswered questions persist about the
availability of sufficient political will and leadership to achieve
electricity markets that at once satisfy the need for operational
efficiency on a regional level and also provide the ``opportunity
for experimentation and market testing with the flexibility to
comprehend local differences * * * [that is] the very genius of the
federal system.'' Id.
Although it remains unclear today whether this challenge will be
met, I firmly believe that the Final Rule is a sound resolution of
the jurisdictional questions facing this Commission as a result of
competition and open access. State PUC comments reflect enormous
concern about the potential loss of jurisdiction over some wires and
services, if and when ``retail transmission'' becomes unbundled.
States raise legal objections to our claim of jurisdiction. While
reaffirming our view that the Commission has exclusive jurisdiction
over the rate, terms, and conditions of interstate transmission,
today's order addresses state concerns squarely--first, by adhering
to the practical distinctions between transmission and distribution
set forth in the NOPR and, second, by according deference 1 to
states where appropriate when
[[Page 21734]]
retail transmission services become subject to a FERC tariff. These
accommodations will smooth the transition to a seamless competitive
market with full customer choice, if and when individual states
initiate retail competition.
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\1\ The Commission leaves unexplored the precise meaning of
``deference'' in these circumstances. At one extreme, it could mean
courteous regard for another's views and, at the other, binding
submission to another's judgment. I would, for example, accord state
views on cost allocation considerable or presumptive, but not
conclusive, weight.
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While the Final Rule, not unexpectedly, manifests this
Commission's strong interest in preventing balkanization of the
interstate power market, nothing adopted by the Commission today,
including the interpretation of its authority over retail
transmission when retail service is unbundled, is inconsistent with
the traditional state roles in developing regulatory, social, and
environmental requirements and programs suited to the circumstances
of their localities. Section I of the Final Rule is emphatic about
this.
I will conclude with two observations on matters I believe to be
of particular sensitivity to the states. First, it appears to me
that state regulators may impose distribution and other non-
bypassable charges or other retail requirements on direct access
services, even in those circumstances where no distribution
facilities can be identified under the functional/technical test.
The Final Rule ensures that result by acknowledging state authority
over distribution-related services under the FPA.
Second, state authority is traditionally employed to ensure that
power production conforms to local economic, environmental, and
resource diversity policy preferences. A state may wish, for
example, to ensure that a direct access industrial customer is no
less obligated to purchase power consistent with the resource
diversity or environmental requirements than is that customer's
franchise distribution utility. To the extent that state
requirements to own or purchase a certain amount of generation from,
say, renewable sources are enshrined in utility supply portfolios,
those states have direct influence on the economic and environmental
consequences of energy consumption in that jurisdiction. Moreover,
such requirements ought to be compatible with open access
transmission. However, it will be important that state authority
over resource procurement be exercised on a not unduly
discriminatory basis. In other words, a PUC may not treat in-state
and out-of-state suppliers differently. If access over the network
is non-discriminatory in nature, the federal regulatory and
constitutional interests are arguably satisfied.
B. Environmental Effects of Restructuring
1. Last July, we instructed our staff to prepare an
Environmental Impact Statement (EIS) in conjunction with this
rulemaking. The Final EIS (FEIS), issued on April 12, 1996, is an
impressive and, with respect to the air impacts of electric
restructuring, a pioneering work. It considers in detail: (1) The
possible environmental consequences of adopting this Rule, including
a number of additional analyses requested by commenters, (2)
alternative methods of pursuing open access transmission service,
(3) a range of environmental mitigation actions proposed by
commenters, and (4) the Commission's legal and technical ability to
undertake environmental mitigation. On the whole, I find staff's
studies to be analytically sound and generally in conformance with
my understanding of this agency's powers to engage in environmental
mitigation. Moreover, its conclusions and recommendations are
thoughtful and well-reasoned. I therefore believe that consideration
of the FEIS as part of the Commission's actions today meets our
National Environmental Policy Act of 1969 (NEPA) obligations 2
and the requirement of reasoned decisionmaking.
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\2\ NEPA (42 U.S.C. 4321-4370), the Council on Environmental
Quality's (CEQ) regulations promulgated thereunder (40 CFR parts
1500-1508 (1995)), and our own environmental regulations
supplementing those of CEQ (18 CFR part 380 (1995)) together
establish an important procedural mechanism that was designed, not
to impose upon this Commission substantive duties to achieve
particular results, but to infuse our decisional processes with a
broad awareness of the environmental consequences of our actions.
Under NEPA, the Commission must in any applicable instance consider
and weigh its core objectives and responsibilities under the Federal
Power Act and the impacts of its actions on all aspects of the human
environment--economic and social as well as ecological. This
exercise requires the Commission to ascertain the availability and
consider the feasibility of alternative approaches with lesser
impacts. In other words, the Commission's duty is to take a ``hard
look'' at the environmental effects of its major actions. Robertson
v. Methow Valley Citizens Council, et al., 490 U.S. 332 (1988);
Strycker's Bay Neighborhood Council, Inc. v. Karlen, et al., 444
U.S. 223 (1980). The EIS process fulfills that requirement.
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The FEIS highlights a very important public health and social
welfare issue, not to mention a matter of great financial importance
to certain utilities. To be specific, the FEIS examines potential
air quality impacts in the event generation increases from certain
coal-fired units. Open transmission access is expected by some to
stimulate that additional generation and hence additional nitrogen
oxide (NOX) emissions and related ozone formation. From these
projections, a substantive and not altogether constructive debate
has ensued. As Section V of the Final Rule describes more fully, the
Commission conducted additional studies to respond to comments on
the draft EIS, using new recommended baselines for comparison. The
results confirm that the air quality impacts of the rule are within
reason.
The Commission has satisfied itself that the three most pressing
questions have been addressed: (1) What increment of the NOX
emissions problem may be attributable to this Final Rule? (2) Will
Final Rule-induced NOX emission increases be so significant and
their impacts sufficiently adverse to justify an alternative
regulatory approach, such as ``no action'' on utility restructuring?
(3) Short of no action, can the Commission undertake direct actions
that mitigate any potential adverse effects? Based on the FEIS, I
can find no justification in the cause, size, or certainty of near-
term emissions increases for delaying or diluting the Open Access
Rule and no clear basis for a FERC-sponsored emissions control
regime, even on an interim basis.
2. Having discharged our NEPA obligations, I cannot pretend that
this matter of public interest is no longer of any interest or
concern to us. Clean air is a birthright. Air emissions are
therefore an important concern. I would not relegate this issue to
the periphery of our deliberations. If the EIS process accomplishes
nothing else, it has familiarized the FERC with the difficulties of
addressing the seemingly intractable problem of NOX emissions.
The problem engenders interregional economic and environmental
conflicts that can be addressed only by a sophisticated balancing of
interests and a selfless commitment to the greater good. EPA and
several commenters on our Rule express frustration over the progress
being made to reduce NOX emissions. For this and other
environmental issues, such as NOX waivers, resort to the courts
has become customary, and complex technological and economic
disputes are the norm. See e.g., Electric Power Alert, April 24,
1996, at 29-30.
Regions of the country differ, often vehemently, about the
source and effects of ozone-causing emissions and how best to curb
the generation and transport of pollutants that create ozone.
Utilities in some regions have made commitments and invested heavily
to achieve ``attainment'' levels, while the blessings of geography
and circumstance have imposed no such burden on others. We recognize
in essence that reconciling these interests is a task the Congress
has assigned to the EPA. Although the Clean Air Act authorizes EPA
to develop a national program to enforce emissions reduction largely
through state environmental regulatory efforts (the so-called State
Implementation Plans (SIPs)), the statutory process is ponderous in
practice. Moreover, even where gains are expected to be made in the
form of reduced NOX emissions (e.g., under EPA's pending
rulemaking to set NOX emissions limitations for certain types
of utility boilers), those gains might arguably be offset by future
increases in the demand for electricity or, according to some
parties, by the additional power generation some say will be
encouraged by open access transmission.
The inability to guarantee future NOX reductions for a
variety of reasons that range well beyond this Rule presents
formidable challenges. EPA places great faith in the ability of the
Ozone Transport Assessment Group (OTAG), a voluntary multi-state
organization established in part to set up NOX emission
mitigation mechanism, to address these complex issues and achieve a
resolution. It nevertheless appears to me that, for the most part,
consensus remains distant. The alternative appears to be an even
more protracted EPA procedure.
With respect to the gravamen of this issue (i.e., the
establishment of an emissions cap and credit trading system
reminiscent of what Congress ordered for sulphur dioxide
(SO2)), this Commission has no real choice but to defer to
agencies with jurisdiction by law and special expertise. The EPA has
done an outstanding job implementing the market-based SO2
allowance program. It is widely regarded as both creative and
successful.
[[Page 21735]]
OTAG, regardless of any concerns about its processes, brings
together a broad range of regional interests, thereby offering an
unprecedented opportunity for achieving consensus resolution of this
difficult problem.
3. In my view, it behooves this Commission to assist in any way
it can, consistent with its expertise and authority, to find
consensual solutions. I do not think that means denying polluting
utilities access to the transmission system and thereby merely
reinforcing their monopoly power. Rather, we must stand ready to
assist EPA and OTAG in making competition and environmental
responsibility equally attractive. We have begun providing that
assistance by ensuring (see II.A. above) that state regulators
retain their customary authority under state law to structure the
generation and purchase power portfolios of state-regulated
utilities. Moreover, the Commission has in the past addressed
through its rate jurisdiction various public interest goals,
including environmental concerns, intergenerational equities, and
least-cost planning needs. For instance, in order to encourage
capital investment in pollution control equipment and conservation,
the Commission has long allowed utilities to include in rate base
the costs of ``construction work in progress'' (CWIP) for pollution
control devices and fuel conversion measures that discourage use of
certain fossil fuels.3 In addition, utilities are not eligible
for CWIP treatment for plant construction not shown to be the
product of integrated resource planning.4
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\3\ 18 CFR 35.25 (1995).
\4\ 18 CFR 35.13(h)(38) (1995).
---------------------------------------------------------------------------
With respect to the NOX issue specifically, the Commission
is competent to help facilitate an emissions cap and trading system.
For instance, the accounting treatment provided for the cost of
SO2 emissions allowances in rates was done to assist
implementation of the Clean Air Act.5 The same accommodations
could be instituted for a NOX program. Perhaps the greatest
potential for DOE-EPA-OTAG-FERC collaboration and consultation
involves our knowledge of the industry and, after preparing the
FEIS, our familiarity with the NOX problem itself. That
information should be useful beyond the confines of this rulemaking.
In addition, the FEIS indicates (at p. 7-22) that we can structure
the electronic bulletin board systems we require so as to facilitate
the posting of emissions data required by EPA.
---------------------------------------------------------------------------
\5\ Revisions to Uniform Systems of Accounts to Account for
Allowances under the Clean Air Act Amendments of 1990, Order No.
552, III FERC Statutes and Regulations para.30,967 (1993).
---------------------------------------------------------------------------
4. Based upon the mutual concerns and the different but
complementary expertise of the affected agencies, I encourage the
development of consultative mechanisms, memoranda of understanding,
or other procedures that will support and help ensure the success of
OTAG's efforts. Such efforts must be consistent with the goals and
allocation of responsibilities under the Clean Air Act, and our own
regulatory role. Restructuring may pose some environmental risks. We
think they are small and (at least eventually) manageable. Further
experience is likely to demonstrate that restructuring opens up new
possibilities for addressing longstanding environmental problems
associated with utility operations. Open access enhances the
prospects for environmental dispatch on a statewide or regional
basis. It gives isolated renewable plants, particularly
hydroelectric and wind power units that are tied to specific
geographical features, better market access. I must note that
investments in DSM and renewable resources, which offer relatively
stable costs, may be an attractive component of utilities'
generation portfolios because they also minimize risks. And, as
restructuring makes electricity a more customer-driven business, the
public's documented preference for environmentally benign power will
become more powerful. In addition, efficient markets provide the
necessary means to ``marketize'' environmental rules and perhaps to
modify siting and other regulatory processes that are predicated on
the vertical integration of the utility sector. And, finally, energy
services companies that can promote conservation and generation
alternatives require more open and dynamic markets. For the
environment, the prospects offered by restructuring are exciting.
Inhibiting or stopping its development will not help it.
III. Partial Dissent
The Final Rule announces that the Commission will be the
``primary forum'' to hear stranded cost claims where a retail power
customer turns wholesale wheeling customer, usually through a
municipalization (Situation 2). Although the Final Rule recognizes
that states do have authority to deal with stranded costs in
Situation 2, the majority nevertheless instructs parties to bring
their claims to this Commission ``in the first instance.'' However,
where costs are stranded due to state authorized retail wheeling
(Situation 3), the majority takes a different and, I contend,
incongruent approach that effectively denies any forum for those
costs if state regulators possess authority to act but do not do so.
Because I find nothing in policy or law to commend this approach, I
respectfully dissent.6
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\6\ My views conform generally to Commissioner Massey's partial
dissent today.
---------------------------------------------------------------------------
I take issue with the ``primary forum'' approach because I
believe that it: (1) Requires the Commission to second-guess state
determinations on recovery of costs incurred at retail at a time
when many states are addressing the issue; (2) will encourage forum
shopping; and (3) is inconsistent with our approach in the retail
wheeling situation; and (4) involves an unnecessary legal risk for
the Commission.
A. Second-Guessing State Determinations of Retail Stranded Costs is
Unwise and Unnecessary
The Final Rule's stranded cost recovery methodologies and the
underlying jurisdictional assumptions are aimed at achieving full
recovery of all legitimate, verifiable and prudent stranded costs,
consistent with a utility's reasonable expectations and the justness
and reasonableness of the underlying contract. I believe that this
is a worthy objective, but it is not one which requires the
Commission to second-guess state determinations. As state
proceedings now reveal, the Commission's leadership in raising this
issue has borne fruit. Where municipalization is occurring, states
are addressing stranded costs responsibly. In nearby Virginia, for
example, the Virginia State Corporation Commission has interceded
into the dispute between Virginia Electric Power Company and the
City of Falls Church over the City's plans to undertake a ``muni-
lite'' form of municipalization. Moreover, the record before us
today does not endorse the view that municipalization constitutes a
major bypass threat to stranded cost recovery.
Notwithstanding such developments, the Final Rule announces that
the Commission will be the ``primary forum'' to hear stranded cost
claims where a retail power customer turns wholesale wheeling
customer, usually through a municipalization. While declaration of
``primary forum'' status sounds very legalistic, there is in fact no
legal basis for it. The policy is not founded on a concept of
federal preemption in the area. Indeed, the Federal Power Act
provides no basis for preemption. Moreover, the Final Rule
recognizes that states do have authority to deal with stranded costs
in these circumstances. The majority's instruction to bring claims
directly to FERC will, if anything, afford states a reason to avoid
this difficult issue altogether.
B. The ``Primary Forum'' Approach May Encourage Forum Shopping
As a policy matter, the majority's approach is peculiar on its
face. Although the ``primary forum'' approach is intended to
eliminate forum shopping, it will not achieve even that objective.
Indeed, I think the ``primary forum'' approach may encourage parties
to forum shop. State commissions or legislatures will often provide
for stranded cost recovery at the time the wholesale entity is
formed. Similarly, condemnation proceedings may provide for stranded
costs in whole or part. Moreover, standards for stranded cost
recovery are occasionally prescribed by statute. In reality, the
Commission cannot preclude the states from acting on stranded cost
issues and our proposed rule may encourage rather than discourage
forum shopping.
C. The ``Primary Forum'' Approach Covers Fact Situations Largely
Indistinguishable From the Retail Wheeling Scenario
The majority's decision to take primary jurisdiction of costs
where a retail power customer becomes wholesale wheeling customer
through municipalization and to distance itself from virtually any
cost recovery responsibility where retail power customers becomes
retail wheeling customers does not withstand scrutiny. These are not
factually distinguishable cases, insofar as jurisdiction over
stranded costs is concerned. The inadequacy of the majority's
reasoning is palpable because it has adopted very different policies
with respect to two stranded cost situations that, if properly
understood, are virtually indistinguishable.
[[Page 21736]]
First, in both Situations 2 and 3, retail power costs are
stranded by customers who gain access to FERC jurisdictional
transmission tariffs via state action. In Situation 2, state
municipalization law governs. In Situation 3, the state has
authorized retail wheeling by statute or regulation, or both.
Notwithstanding the need for state authorization in both cases, the
majority decides that the Commission should be the ``primary forum''
in Situation 2, but that a much more narrow approach to retail
stranded costs in Situation 3.7 The more aggressive ``primary
forum'' approach to municipalization is predicated on the view that
any strandings are a result of an inducement (i.e., market options)
created by this Commission's Open Access Rule. Yet, since both
wholesale transmission customers and retail transmission customers
are ``eligible customers'' under the tariffs required by this Rule,
if the Rule induces the stranding of retail power costs in one
situation, it obviously does it in both.
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\7\ The policy adopted with respect to Situation 3 is that the
Commission would only be a forum for hearing stranded costs issues
in the narrow circumstance where ``the state regulatory authority
does not have authority under state law to address stranded costs
when the retail wheeling is required.'' The majority fails to
address what would happen if a legislature addresses the issue of
stranded costs directly without delegating the task to a state
regulatory authority. I would hope that the Commission would not set
itself up for confrontation with a state legislature and I would
have preferred that to also exclude those circumstances ``where the
state otherwise addresses the issue'' from the circumstances in
which the Commission would act in Situation 3.
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As commenters have noted, the relationship between FERC-
regulated transmission service and retail power customers is
generally the same in both Situations 2 and 3.8 The similarity
runs first to the actions that actually cause costs to be stranded.
While it is true that retail wheeling will only occur pursuant to
state legislative or regulatory action, it is also true that a
retail customer can only convert to wholesale status (e.g.,
municipalize) pursuant to state law. This process sometimes may
occur in the absence of regulatory or other oversight (e.g.,
municipalization under pre-established statutory scheme), or with
direct and immediate review and approval. The current evidence
reflects active state commission oversight, typically. In this
latter case, there is even less reason to distinguish between these
Situations.
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\8\ This argument is made both by commenters arguing that the
Commission has no jurisdiction over stranded costs in Situation 2 or
3 (California Public Utilities Commission Initial Comments at 7) and
by commenters arguing that the Commission should assert primary
jurisdiction over stranded costs in both Situations (see e.g.,
Edison Electric Institute Initial Comments at IV-13; Coalition For
Economic Competition Initial Comments at 22; Utilities For An
Improved Transition Initial Comments at 16-26).
---------------------------------------------------------------------------
The majority implicitly seeks to delimit the area of appropriate
state authority over stranded costs according to whether the state
acts directly and by current enactments to authorize retail
wheeling, on one hand, or less directly through established state
municipalization laws, on the other. However, costs could be
stranded under state law by either action. Under the former
scenario, however, a state is presumed to be more willing and
capable of dealing with stranded costs. Under the latter, it is
presupposed to be less interested. This distinction is specious.
A second similarity pertains to the jurisdictional status of
transmission service. The Commission has been clear and consistent
that the FPA gives the Commission exclusive jurisdiction over
interstate transmission service, regardless of whether the customer
is a wholesale or a retail wheeling customer. It is this authority
upon which we rely to claim jurisdiction over transmission assets
and related costs originally incurred to provide customers at the
retail level with bundled service. New wheeling customers in both
Situations 2 and 3 will take service under FERC open access tariffs.
There are identical cost-causational facts in Situations 2 and 3,
yet the majority adopts very different outcomes in each case under
the Final Rule.
D. The ``Primary Forum'' Approach is More Subject to Legal
Challenge
In my view, our disagreement involves more than a policy choice.
The majority's chosen approach clearly makes our stranded cost
recovery approach more vulnerable to a legal challenge. The cost
recovery scheme which would result from the majority's approach will
render a FERC-ordered transmission surcharge to recover retail
stranded costs susceptible to legal challenge on the basis that it
is anti-competitive and unduly discriminatory. The ``primary forum''
approach imposes upon a retail-turned-wholesale customer something
akin to double jeopardy. In other words, a departing customer might
have to pay both an exit fee for the retail costs which the state
commission finds it has stranded and, in addition, an entry fee for
wholesale access in the amount of the additional retail stranded
costs which FERC determines are inadequately covered by state
proceedings.
This, in my view, makes the Final Rule more susceptible to
challenges that FERC's transmission surcharge is anti-competitive.
E.g., Cajun Electric Power Cooperative, Inc. v. FERC, 28 F.3d 173
(D.C. Cir. 1994). The second-guessing of states inherent in the
``primary forum'' approach makes any arguments that stranded cost
recovery is anti-competitive more difficult to overcome than if the
stranded costs resulted from wholesale customers simply changing
wholesale suppliers. This is because, unlike wholesale-to-wholesale
strandings, the Commission cannot plausibly argue that the costs
incurred were originally addressed in the context of its own rate
decisions or were previously part of its responsibility for
administering wholesale service obligations.
I am strongly persuaded that the Commission would be on much
stronger legal ground if we were to treat state authority over
stranded costs with the same deference in the municipalization or
``retail-turned-wholesale'' situation in the same manner as the
Final Rule prescribes for situations where retail wheeling occurs.
In the latter case, the Commission ought to provide a forum where
neither the state legislature nor the state commission attempts to
address this important transition issue.
James J. Hoecker,
Commissioner.
Promoting Wholesale Competition Through Open Access Non-Discriminatory
Transmission Services by Public Utilities
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities
[Docket No. RM95-8-000; Docket No. RM94-7-001]
Issued April 24, 1996.
MASSEY, Commissioner, dissenting in part:
I support all of the provisions of this rule save one, the
provision on stranded costs arising from retail competition and from
municipalization. When the Commission issued the Notice of Proposed
Rulemaking, I stated that the Commission should treat stranded costs
arising from retail competition and municipalizations similarly, as
follows:
For either retail competition or municipalization, when the
state commission has authority to address the issue, and uses such
authority to decide the recoverability of the stranded costs, the
state's decision should not be second-guessed by this Commission.
However, when a state commission does not have the authority to
decide the recoverability of stranded costs, or has authority but
does not use it, this Commission should act on requests for stranded
cost recovery.
My approach would assure utilities of getting a decision on the
merits of their claim. Costs would not be stranded for lack of a
regulatory decision. At the same time, this Commission would allow
states to make decisions, when they have authority, on issues of
critical concern to their local utilities and ratepayers. Only if
states lack, or fail to use, such authority would this Commission
step in to assure the utility of receiving a decision on the merits.
For the reasons I stated then, I still disagree with the rule's
approach to stranded costs arising from retail competition or
municipalization. In all other respects, I support this rule.
William L. Massey,
Commissioner.
[FR Doc. 96-10694 Filed 5-9-96; 8:45 am]
BILLING CODE 6717-01-P
Complete official Federal Register PDF
FR Doc. 96-10693 Open Access Same-Time Information System (Formerly Real-Time Information Networks) and Standards of Conduct
[Federal Register Volume 61, Number 92 (Friday, May 10, 1996)]
[Rules and Regulations]
[Pages 21736-21846]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 96-10693]
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[[Page 21737]]
DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 37
[Docket No. RM95-9-000; Order No. 889]
Open Access Same-Time Information System (Formerly Real-Time
Information Networks) and Standards of Conduct
April 24, 1996.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final rule.
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SUMMARY: The Federal Energy Regulatory Commission is adding rules
establishing and governing an Open Access Same-time Information System
(OASIS) (formerly real-time information networks) and prescribing
standards of conduct. Under this final rule, each public utility (or
its agent) that owns, controls, or operates facilities used for the
transmission of electric energy in interstate commerce will be required
to create or participate in an OASIS that will provide open access
transmission customers and potential open access transmission customers
with information, provided by electronic means, about available
transmission capacity, prices, and other information that will enable
them to obtain open access non-discriminatory transmission service.
This final rule requires each public utility subject to the rule to
implement standards of conduct to functionally separate transmission
and wholesale power merchant functions and the creation of a basic
OASIS system. In addition, some of the standards and formats for OASIS
nodes are prescribed in a document entitled OASIS Standards and
Communication Protocols that is being issued with the final rule. The
Commission also is establishing further procedures to complete the
standards for displays and formats. The development of OASIS
requirements will continue in a Phase II, in which the Commission will
continue to develop the requirements for a fully functional OASIS.
Effective Date: This final rule will become effective on July 9,
1996.
Compliance Date: Compliance with the standards of conduct and
operation of an OASIS meeting the requirements of this final rule must
commence on or before November 1, 1996.
Conference Date: A technical conference on any remaining issues
will be held on June 17, 1996.
ADDRESSES: The technical conference will be held at the Commission's
headquarters at 888 First Street, NE., Washington, DC. 20426.
FOR FURTHER INFORMATION CONTACT:
Marvin Rosenberg (Technical Information), Office of Economic Policy,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 208-1283
William C. Booth (Technical Information), Office of Electric Power
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426 (202) 208-0849
Gary D. Cohen (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 208-0321
SUPPLEMENTARY INFORMATION: In addition to publishing the full text of
this document in the Federal Register, the Commission also provides all
interested persons an opportunity to inspect or copy the contents of
this document during normal business hours in the Public Reference Room
at 888 First Street, NE., Washington, DC 20426.
The Commission Issuance Posting System (CIPS), an electronic
bulletin board service, provides access to the texts of formal
documents issued by the Commission. CIPS is available at no charge to
the user and may be accessed using a personal computer with a modem by
dialing 202-208-1397 if dialing locally or 1-800-856-3920 if dialing
long distance. CIPS is also available through the Fed World system (by
modem or Internet). To access CIPS, set your communications software to
19200, 14400, 12000, 9600, 7200, 4800, 2400, or 1200 bps, full duplex,
no parity, 8 data bits and 1 stop bit. The full text of this order will
be available on CIPS indefinitely in ASCII and Wordperfect 5.1 format.
The complete text on diskette in WordPerfect format may also be
purchased from the Commission's copy contractor, La Dorn Systems
Corporation, also located in the Public Reference Room at 888 First
Street, NE., Washington, DC 20426.
Table of Contents
I. Introduction
II. Public Reporting Burden
III. Discussion
A. Background
B. Summary of the Regulations and Their Implementation
C. Section 37.1--Applicability
D. Section 37.2--Purpose
E. Section 37.3--Definitions
F. Section 37.4--Standards of Conduct
1. Requests by Smaller Public Utilities for Exemptions from the
Standards of Conduct
2. Suggested Revisions to the Standards of Conduct and Timing
3. Whether to Require the Separation of Generation and
Transmission Functions
G. Section 37.5--Obligations of Transmission Providers
H. Section 37.6--Information To Be Posted on an Oasis
1. Oasis Objectives
2. Posting Available Transmission Capacity
a. ATC for Network Integration Service
b. Minimizing the Reporting of ATC
c. Methodology for Calculating ATC and TTC
d. Accommodating Flow-Based Pricing
e. Actual Flow Data
f. Providing Supporting Information
g. Long-Term Studies
3. Posting Transmission Service Products and Prices
4. Posting Ancillary Service Offerings and Prices
5. Posting Transmission Service Requests and Responses
a. Posting Curtailments and Interruptions
b. Posting Denials of Requests for Service
c. Transaction Anonymity
6. Posting Facility Status Information
7. Posting Transmission Service Schedules Information
8. Posting Other Transmission-Related Communications
I. Section 37.7--Auditing Transmission Service Information
J. Standards and Communication Protocols
1. Summary of Standards and Communication Protocol Requirements
2. Number of OASIS Nodes
3. Direct Connections to OASIS Nodes
4. Value-Added OASIS Services Provided by Transmission Providers
or Responsible Parties
5. Transmission Services Information Timing Requirements
6. Common Codes
a. Company Codes
b. Common Location Codes
7. Data Definitions and File Formats Not Covered by the How
Report
a. Offers to Provide Ancillary Services Provided by an Entity
Other Than the Transmission Provider
b. Offering of Primary and Secondary Capacity
8. Formats for Downloadable Files Not Covered in the How Report
a. Standard Format for Data Used in Calculating ATC
b. Standard Formats for Transmission Studies
c. Standard Format for Electronic Submission to the Commission
of Transmission Tariffs
9. Communication Protocol Issues
a. Internet Browsers
b. Bandwidth of Node Connections to the Internet
c. Data Compression Standards
d. Other Communication Protocol Issues Raised by Commenters
i. The Requirement to Use FTP for File Transfers
ii. Field Size for Path Names
iii. Files Containing More Than 100,000 Bytes
K. Cost Recovery Issues
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1. Costs of Developing and Running an OASIS
2. Cost of Posting Resales of Capacity on the OASIS
3. Cost of Posting Ancillary Services on the OASIS
L. Section 37.8--Implementation in Phases
1. Phase I Implementation
2. Phase II Implementation
IV. Regulatory Flexibility Act
V. Environmental Statement
VI. Information Collection Statement
VII. Effective Date
Regulatory Text
Attachments
List of Commenters to RIN NOPR
Standards and Communication Protocols for Open Access
Same-time Information System with Appendix A--Data Element
Dictionary and Appendix B--Request (Query) Variables
I. Introduction
The Federal Energy Regulatory Commission (Commission) is
promulgating new regulations amending 18 CFR to add Part 37 containing
rules establishing and governing transmission information networks and
standards of conduct. The Commission is issuing this final rule in
tandem with its final rule on Open Access Transmission and Stranded
Costs (Open Access Final Rule).1 This final rule applies to any
public utility that offers open access transmission services under the
Open Access Final Rule pro forma tariff. Under the Open Access Final
Rule, the open access pro forma tariff may be used by wholesale
transmission customers and by retail transmission customers that are
able to receive unbundled retail transmission either voluntarily from
the public utility or as a result of a state retail access program.
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\1\ See Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities and
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Final Rule, FERC Stats. & Regs. para. 31,036 (April 24,
1996); this document is being published concurrently in the Federal
Register.
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This final rule is being issued after a review of the comments
filed in response to the Commission's notice of proposed rulemaking
issued in this proceeding on December 13, 1995 (RIN NOPR).2
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\2\ Real-Time Information Networks and Standards of Conduct,
Notice of Proposed Rulemaking, 60 FR 66182 (December 21, 1995), FERC
Stats. & Regs. para. 32,516 (December 13, 1995).
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This final rule becomes effective on July 9, 1996. By November 1,
1996, all affected public utilities must file procedures with the
Commission that will enable customers and the Commission to determine
whether they are in compliance with the standards of conduct
requirements contained herein.
Additionally, under this final rule, each public utility as defined
in section 201(e) of the Federal Power Act, 16 U.S.C. 824(e) (1994),
(or its agent) that owns, controls, or operates facilities used for the
transmission of electric energy in interstate commerce (each
Transmission Provider) must develop or participate in an Open Access
Same-time Information System (OASIS).3 This final rule establishes
Phase I OASIS rules that require the creation of a basic OASIS.4
The basic OASIS required by this final rule must be in place and
operational by November 1, 1996. The development of OASIS requirements
will continue in Phase II, during which the Commission will develop the
requirements for a fully functional OASIS.
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\3\ In the notice of technical conference that initiated this
proceeding, see infra n. 12, we chose the term ``Real-Time
Information Network'' to describe the electronic information system
envisioned by that notice. We invited comments on whether we should
substitute another term in place of RIN. In response, a number of
commenters suggested that ``RIN'' was not a suitable name for the
electronic information network envisioned by the RIN NOPR, mainly
because while some RIN postings may be made ``real-time'' most will
not and that, therefore, RIN is a misnomer.
After a review of suggested replacements presented in the
comments, we will abandon the name ``RIN'' in favor of Open Access
Same-time Information System, suggested by Virginia Electric Power
Company (VEPCO), for several reasons. First, as noted above, the
information system being developed in this proceeding actually will
be a ``same-time'' information system, and not a ``real-time''
system. Second, VEPCO correctly points out that the system will be
part of an existing network (the Internet) and not a new network.
Third, the name ``OASIS'' highlights that the system relates to open
access.
\4\ Any entity may, for good cause, seek a waiver of the
requirements established by this final rule, either as to the
creation of an OASIS or for reporting requirements.
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While the final rule set forth in this order is consistent with the
proposal described in the RIN NOPR, it also resolves certain issues
that were described in the RIN NOPR but left undecided, and adds
clarifications and revisions, as suggested by the comments. As proposed
in the RIN NOPR, the final rule describes what information must be
provided on an OASIS, how an OASIS must be implemented and used, and
contains a code of conduct applicable to all transmission providing
public utilities.
As proposed in the RIN NOPR, we are issuing this final rule along
with a separate document entitled OASIS Standards and Communication
Protocols (Standards and Protocols) to help ensure that each OASIS will
provide information in a uniform manner. However, the standards and
protocols are not yet complete. Consequently, we are inviting the How
Group 5 to submit an additional report, on or before May 28, 1996,
to help us resolve these deficiencies. We will also hold a technical
conference on June 17, 1996 to resolve any remaining issues and to
allow input from interested persons. We will issue a revised Standards
and Protocols document as soon as possible thereafter.
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\5\ See, infra, n. 13.
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We are moving promptly to complete the standards and protocols to
ensure that the OASIS will be operational and in compliance with this
final rule by November 1, 1996. In selecting this date, we have
balanced the need to have a functional system of fair and non-
discriminatory information in place to support the Open Access Final
Rule against the comments that argued that implementation of an OASIS
could not be accomplished in 60 days and to avoid implementation during
the peak winter or summer months.
II. Public Reporting Burden
The final rule requires Transmission Providers to participate in an
OASIS designed to provide open access transmission users and potential
open access transmission users with information by electronic means
about available transmission capacity and prices.
The RIN NOPR contained an estimated annual public reporting burden
associated with a final rule consistent with the RIN NOPR. In response
to the RIN NOPR, NRECA 6 filed comments with the Commission that
argued that the Commission's estimated public reporting burden should
have taken into account that Question 45 of the RIN NOPR asked whether
OASIS rules should be extended to apply to non-public utilities that
own or control facilities used for the transmission of electric power
in interstate commerce.7 Based on this inquiry, NRECA argued that
the public burden estimate should have been based on the assumption
that the proposed OASIS rules would be extended to apply to non-public
utilities (even though this was not proposed by the Commission).
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\6\ Attached to this document is a list of the commenters and
the abbreviations used to designate them. Several of the comments
were filed late. We, nevertheless, will consider these comments.
\7\ NRECA also submitted a letter to the Office of Management
and Budget (OMB) that raised the same issue.
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The Commission's task in preparing a public burden estimate at the
NOPR stage was to estimate the annual public reporting burden
associated with a final rule consistent with the RIN NOPR. This is what
the Commission did. An
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estimate based on deviations from the NOPR proposal, as NRECA
suggested, would have been inappropriate. At the same time, however, by
asking Question 45, we identified the issue and gave the commenters an
opportunity to be heard before making a final decision.
Our final rule, like the RIN NOPR, applies only to public
utilities, and not to non-public utilities. However, as discussed in
this order and as commented upon by various non-public utilities, in
the Open Access Final Rule we are including a reciprocity provision in
public utility open access tariffs under which all those who elect to
take service under the open access tariff (including non-public
utilities) will have to offer reciprocal service including an
information network, unless they are granted a waiver of the
reciprocity provision in the tariff.8 Consequently, we have
increased the estimate of number of respondents in this rulemaking to
reflect the additional burden on those non-public utilities that seek
service under open access tariffs. However, this is offset by our
current expectation that there will be far fewer OASIS sites than we
originally anticipated in the RIN NOPR. The How Group estimates there
will be between 20-35 OASIS sites nationwide.9 Using the higher
number, the burden of running each OASIS will be shared, on average, by
four respondents. This is reflected in the burden hour and cost
estimates.
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\8\ As explained in the Open Access Final Rule, non-public
utilities that do not want to meet the reciprocity condition may
choose not to take service under an open access tariff. In that
circumstance, the public utility may, if it chooses, voluntarily
provide transmission service on a unilateral basis to the non-public
utility.
\9\ How Group comments at 19.
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Our burden hour and cost estimates include the information
gathering requirements imposed on public utilities that do not develop
their own OASIS. Additionally, we have refined our estimate of the
annual public reporting burden to account for revisions that this final
rule makes to the RIN NOPR.
Estimated Annual Burden:
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Total
Data collection No. of No. of Hours per annual
respondents responses response hours
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Reporting......................................................... 140 1 1879 263,060
Recordkeeping..................................................... 140 1 418 58,520
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Total Annual Hours for Collection (Reporting + Recordkeeping, (if appropriate)) = 321,580.
Data collection costs: The Commission projects the average annualized cost per respondent to be the following:
Annualized Capital/Startup Costs--$47,500.
Annualized Costs (Operations & Maintenance)--$142,250.
Total Annualized Costs--$189,750.
Internal Review
The Commission has reviewed the collection of information required
by this final rule and has determined that the collection of
information is necessary and conforms to the Commission's plan, as
described in this final rule, for the collection, efficient management,
and use of the required information. The Commission has assured itself,
by means of its internal review, that there is specific, objective
support for the information burden estimate set forth above.10
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\10\ See 44 U.S.C. Sec. 3506(c).
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Persons wishing to comment on the collections of information
required by this final rule should direct their comments to the Desk
Officer FERC, Office of Management and Budget, Room 3019NEOB,
Washington, D.C. 20503, phone 202-395-3087, facsimile: 202-395-7285 or
via the Internet at [email protected]. Comments must be filed
with the Office of Management and Budget within 60 days of publication
of this document in the Federal Register. A copy of any comments filed
with the Office of Management and Budget also should be sent to the
following address at the Commission: Federal Energy Regulatory
Commission, Information Services Division, Room 41-17, 888 First
Street, NE., Washington, DC 20426. For further information, contact
Michael Miller, 202-208-1415.
III. Discussion
A. Background
This proceeding began with the issuance of our proposed Open Access
rule (Open Access NOPR) 11 and a notice of technical conference to
consider whether a RIN (now an OASIS) or some other option would be the
best means to ensure that potential customers of transmission services
could obtain access to transmission service on a non-discriminatory
basis. 12 The notice of technical conference was followed by
procedures and input (described in the RIN NOPR) that led to the
issuance of the RIN NOPR.
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\11\ See Promoting Wholesale Competition Through Open Access
Non-Discriminatory Transmission Services by Public Utilities and
Recovery of Stranded Costs by Public Utilities and Transmitting
Utilities, Notice and Supplemental Notice of Proposed Rulemaking, 60
FR 17662 (April 7, 1995), FERC Stats. & Regs. para.32,514 (March 29,
1995).
\12\ Real-Time Information Networks, Notice of Technical
Conference and Request for Comments, 60 FR 17726 (April 7, 1995).
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Open access non-discriminatory transmission service requires that
information about the transmission system must be made available to all
transmission customers at the same time. This means that public
utilities must make available to others the same transmission
information that is available to their own employees and that is
pertinent to decisions they make involving the sale or purchase of
electricity. The RIN NOPR suggested requirements representing the first
steps towards accomplishing these objectives.
The RIN NOPR addressed four main issues: the types of information
that need to be posted on an OASIS; technical issues concerning the
development and implementation of an OASIS; the development of a basic
OASIS in Phase I and the development of a fully functional OASIS in
Phase II; and proposed standards of conduct to prevent employees of a
public utility (or any of its affiliates) engaged in marketing
functions from obtaining preferential access to OASIS-related
information.
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The Commission's consideration of the first two of these issues
relied heavily on the efforts of two industry-led working groups that
presented recommendations to the Commission. 13
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\13\ The North American Electric Reliability Council (NERC)
acted as a facilitator for an industry-led independent working
group, representing diverse interests, to help participants reach
consensus, and to help them prepare a report to the Commission on
what information should be posted on a RIN (the ``What Group''). The
Electric Power Research Institute (EPRI) facilitated a similar
working group (the ``How Group'') that sought consensus on how to
implement a system that would accomplish these objectives. Both
groups submitted reports to the Commission describing their progress
in reaching consensus on their respective issues. As explained in
the RIN NOPR, after determining that the working groups had balanced
representation from diverse interests and had operated in an open,
inclusive manner, the Commission used the working groups'
recommendations as the starting point for developing the RIN NOPR.
A fuller description of the working groups' composition and
activities is contained in the RIN NOPR and in the reports that
those groups submitted to the Commission for its review (attached to
the RIN NOPR as Appendices ``A'' and ``B'' and made publicly
available at the Commission's offices and through the Commission
Issuance Posting System (CIPS)).
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Additionally, the RIN NOPR invited commenters to address specific
questions on various issues and invited comments generally on the
entire proposal.
As discussed in the RIN NOPR, the handling of various types of
information that might be posted on an OASIS depends on substantive
determinations being made in the Commission's Open Access rulemaking
proceeding.14 For this reason, the RIN NOPR attempted to identify
the issues that might be affected by decisions that would be made in
the Open Access rulemaking and invited comment on the mechanics of
implementing whatever determinations ultimately would be reached in the
Open Access rulemaking, without attempting to prejudge the merits of
the underlying legal and policy issues.
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\14\ For example, the information about ancillary services that
must be posted on an OASIS depends on what ancillary services a
public utility must provide. Likewise, the information about
discounts that must be posted on an OASIS depends on whether
discounting is allowed.
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Additionally, the RIN NOPR included (as Appendix ``C'') a set of
upload and download templates for comment to ensure that all data
definitions are the same and that the information presented on the
OASIS will be uniform and clearly understood.
The Commission's RIN NOPR, issued on December 13, 1995, invited
comments on enumerated questions, along with general comments. Comments
were filed by over 100 commenters. These comments were generally
favorable to the OASIS concept, although numerous disagreements
remained as to the details. The comments will be discussed below on an
issue-by-issue basis.15
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\15\ In the discussion that follows, our references to comments
are illustrative and not inclusive. While we have intended to
identify all of the major issues raised by the commenters, we have
not attempted to identify all commenters in instances where more
than one comment makes the same point.
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In the RIN NOPR, we invited the two industry-led working groups to
continue their efforts to reach consensus and to report to us on their
progress. On March 7, 1996, the How Group submitted a report giving
proposed revisions to their original report.16 The How Group also
submitted a report on April 15, 1996 making recommendations on
additional issues on which the group had reached consensus.
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\16\ The participants in the How Group submitted a report
entitled Consensus Comments of the Wholesale Electric Power Industry
on behalf of the ``industry management process (interim) on how to
implement transmission services information networks?''
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B. Summary of the Regulations and Their Implementation
The Commission is issuing this final rule with the Open Access
Final Rule to implement the legal and policy determinations being made
in the Open Access Final Rule.17 This final rule contains three
basic provisions that, taken together, will ensure that transmission
customers have access to transmission information enabling them to
obtain open access transmission service on a non-discriminatory basis.
This final rule is necessary, therefore, to meet the legal requirement,
discussed in the Open Access Final Rule, that the Commission remedy
undue discrimination in interstate transmission services by public
utilities.
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\17\ For example, a number of smaller public utilities and non-
public utilities have argued that they should be exempted from the
OASIS requirements. The Open Access Final Rule provides that public
utilities may seek waivers of some or all of the requirements of the
Open Access rules. This would include the OASIS requirement.
Similarly, the Open Access Final Rule provides that non-public
utilities may seek waivers of the tariff reciprocity provision as
applied to them.
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The first provision establishes standards of conduct. These
standards are designed to ensure that a public utility's employees (or
any of its affiliates' employees) engaged in transmission system
operations function independently of the public utility's employees (or
of any of its affiliates' employees) who are engaged in wholesale
purchases and sales of electric energy in interstate commerce. Such
separation is vital if we are to ensure that the utility does not use
its access to information about transmission to unfairly benefit its
own or its affiliates' sales. Entities subject to these rules are to
achieve compliance with the standards of conduct by November 1, 1996.
The second provision sets out basic rules requiring that
jurisdictional utilities that own or control transmission systems set
up an OASIS. Under these rules, the utilities are required to provide
certain types of information on that electronic information system as
to the status of their transmission systems and are required to do so
in a uniform manner. With these requirements, we are opening up the
``black box'' of utility transmission system information. When in
place, the OASIS will allow transmission customers to determine the
availability of transmission capacity and will help ensure that public
utilities do not use their ownership, operation, or control of
transmission to deny access unfairly. Entities subject to this rule are
to have a basic OASIS, meeting the requirements of this final rule, in
operation by November 1, 1996.
The third component involves the various standards and protocols
referenced in the regulations that are necessary to ensure that the
OASIS system presents information in a consistent and uniform manner.
As proposed in the RIN NOPR, this final rule references a publication
entitled OASIS Standards and Communication Protocols.18 This
publication contains the above-mentioned standards and communication
protocols. The publication details the Phase I requirements for
technical issues related to the implementation and use of an OASIS
(i.e., a compilation of OASIS standards and communication protocols).
Because of their level of detail, the standards and protocols
referenced in the regulations will be contained in the Standards and
Protocols document and will not be set out in the Code of Federal
Regulations.
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\18\ This title differs slightly from the title we suggested for
this document in the RIN NOPR. We are making this change to reflect
more accurately the contents of the document as it has evolved.
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In developing the standards and protocols, we have been greatly
assisted by the industry. However, more work needs to be done before
the necessary standards and protocols are complete. For this we will
again look to the industry and its working groups. The Commission
believes a standard or uniform set of protocols is essential. The
industry is best situated not only to develop the necessary standards
but to develop them where possible with a consensus. Consequently, we
are asking the How Group to provide us with
[[Page 21741]]
additional recommendations on those technical issues remaining to be
resolved. After receiving this report, we will hold a technical
conference. In the meantime, to enable utilities to begin the process
of implementing their OASIS, we will publish the standards and
protocols that have been developed to date.
We must also provide for the contingency that, over time, the
standards and protocols may need to be revised. To this end, NERC, in
its comments, proposed to continue the industry-based process for
developing OASIS requirements begun by the two industry working groups.
NERC argued that the Commission should abandon its intention to approve
standards developed by industry-wide consensus and to make decisions in
those areas where consensus is not achieved. Instead, NERC argued that
the Commission should authorize an industry group, facilitated by NERC
and EPRI, to set and enforce detailed standards under broad policy
guidelines fixed by the Commission.
As we have needed the contributions of the industry to develop the
standards and protocols, we will continue to need that assistance in
the future to develop a consensus wherever possible. We need to strike
a balance between standardization to make OASIS work and encouraging
innovation. To this end we encourage all industry participants to
continue seeking consensus and reporting proposals to the Commission
for our consideration. We welcome the continued work of all industry
participants on revising and improving standards and establishing
appropriate methods for recommending standards in the future. We will
continue to give careful consideration to all consensus recommendations
presented by the industry group(s), provided that they continue to
invite balanced participation in an open process.
However, we reject entirely the notion that the Commission need not
approve the Standards and Protocols and that these matters can be left
to the industry for implementation and self-policing. Although we
continue to seek industry consensus, the Commission must reserve final
decisions to itself. We cannot turn over the process of approving and
enforcing OASIS requirements to the industry. The Commission does not
believe that resolution of the outstanding issues or future changes
will occur more quickly without Commission oversight.\19\ Nor do we
believe that merely by announcing broad policy guidelines we would be
creating a mechanism that would be sufficient to allow the Commission
to revise regulations quickly. Accordingly, we will not abdicate our
responsibility to decide these issues ourselves; nor shall we delegate
responsibility for making these decisions to anyone else.
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\19\ To the contrary, our experience with the natural gas
pipeline industry persuades us that an expedited schedule is more
likely with active Commission oversight than otherwise.
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With respect to the as yet unresolved technical issues, we invite
the How Group to report to us on or before May 28, 1996 on these issues
(and to attach any comments it has received from any interested person
with opposing views). Prior to issuing a revised Standards and
Protocols document, we will hold a technical conference on these issues
on June 17, 1996. This short time frame is necessary if the OASIS is to
be properly operational by November 1, 1996.
The Commission recognizes that the standards and protocols
necessarily will evolve over time. The Commission is committed to a
process for reviewing and, if necessary, revising and improving the
Standards and Protocols on a regular basis after implementation. We are
sensitive to the fact that business practices and technology will
continue to change under open access and that a mechanism to make
changes to the regulations and to the accompanying standards and
protocols on an expedited basis may be needed. It would be premature at
this time, however, to determine the appropriate mechanism for making
such changes, because the method could vary depending on the type of
change contemplated. In filing its report, we ask that the How Group
advise us on this issue. We will welcome discussions and comments on
mechanisms for revising the standards and protocols on an ongoing basis
at the June 17, 1996 technical conference.
In the sections that follow, we discuss, section-by-section, the
regulations we are adopting with this final rule; how the costs of
implementing the requirements of these regulations are to be recovered;
and the details of implementation.
C. Section 37.1--Applicability
This section is unchanged substantively from what we proposed in
the RIN NOPR. As proposed previously, the rules in Part 37 apply to any
public utility that owns or controls facilities used for the
transmission of electric energy in interstate commerce.\20\
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\20\ We are, however, modifying this provision to clarify that
it is intended to include public utilities that ``operate''
facilities used for the transmission of electric energy in
interstate commerce. We are also clarifying that these regulations
apply to transactions performed under the pro forma tariff required
in Part 35 of the Commission's regulations.
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In proposing these regulations, we stated that issues relating to
potential gaps in providing comparable open access to wholesale
transmission services or to transmission information that may arise
because the requirements do not apply to non-public utilities would be
addressed in the Open Access rulemaking proceeding. We also invited
comment on whether the Commission should extend OASIS requirements to
non-public utilities that own or control facilities used for the
transmission of electric energy in interstate commerce (Question 45)
and on whether the reciprocity condition of the proposed Open Access
rule dictates that a non-public utility should have an OASIS (Question
46).
Comments
The responses to Question 45 split along industry lines. Generally,
public utilities subject to OASIS rules advocated that the Commission
should impose OASIS requirements on non-public utilities. They argued
that applying OASIS requirements to non-public utilities would promote
competition and a ``level playing field.'' These commenters argue that
all companies should pay the costs of developing and operating an OASIS
and should be required to divulge information to their competitors on
it.
Along these lines, Allegheny argued that, in order to provide a
level playing field between public utilities and their competitors, the
proposed standards of conduct should be expanded to include personnel
of any entity that trades on an OASIS. Allegheny suggested, therefore,
that the standards of conduct be rewritten to be applicable to non-
public utilities through a requirement that they sign confidentiality
agreements as a condition of obtaining access to OASIS.
Those favoring applying OASIS rules to non-public utilities argued
that a significant portion of the wholesale transmission market is
owned by non-public utilities (ConEd estimates that non-public
utilities, excluding cooperatives, control about 25 percent of the
circuit miles of transmission lines nationwide). They argued that,
without information about these lines, accurate calculations of
available transmission capability cannot be made. However, those
advocating that the Commission should assert jurisdiction over non-
public utilities were divided between those who maintained that the
Commission has authority to do so directly under Sec. 311 of the
Federal
[[Page 21742]]
Power Act (FPA) \21\ and those who maintained that the Commission does
not have such authority. The latter group suggested that the
Commission's authority is not clearcut and, to avoid needless delay and
litigation, the Commission should rely on the reciprocity condition in
the pro forma tariffs to extend OASIS requirements to non-public
utilities.\22\ ConEd argued that we should state that compliance with
OASIS requirements is required by both Sec. 311 and reciprocity.
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\21\ 16 U.S.C. Sec. 825j. Section 311 authorizes the Commission
to obtain information (and conduct appropriate investigations)
about, among other matters, the transmission of electric energy
throughout the United States, regardless of whether such
transmission is otherwise subject to the Commission's jurisdiction,
and to report to Congress the results of any investigations it
carries out under the authority of this provision.
\22\ See discussion of Question 46, infra.
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The larger non-public utilities argued that, while the Commission
lacks authority to impose OASIS rules under Sec. 311 of the FPA, they
nevertheless will voluntarily comply with the rules because this would
be in their own best interest. By contrast, a number of small non-
public utilities argued that they should be exempt from OASIS rules,
particularly the standards of conduct, for the same reasons that
smaller public utilities argued that they should be exempted from the
requirements of the Open Access Final Rule. The smaller non-public
utilities stressed that they do not ``control'' many of their
transmission lines and that many of their lines lack commercial
interest. They recommended the development of a joint or regional OASIS
that would make participation in an OASIS easier and argued that, as to
smaller non-public utilities, the rules requiring a separation of
functions are unduly burdensome and their scant benefits would be
outweighed by their costs to consumers.
NRECA argued that the availability of transmission service under
Sec. 211 of the FPA is sufficient to prevent abuses. By contrast, Com
Ed argued that Commission orders in Sec. 211 proceedings come too late
to prevent abuses.
In Question 46 of the RIN NOPR, we asked whether, based on
reciprocity, we should require non-public utilities to develop or
participate in an OASIS.\23\ The responses to this question generally
are split along the same lines as the responses to Question 45, with
non-public utilities pointing out that most would participate
voluntarily in an OASIS because it would be in their best interest to
do so.
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\23\ The discussion of questions 45 and 46 by commenters often
overlapped.
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APPA asserted that voluntary participation would suffice to
accomplish the Commission's goals and seeks assurance that compliance
with OASIS requirements by non-public utilities would be deemed by the
Commission to satisfy the reciprocity condition in the pro forma
tariffs. APPA also asserted that participation in a regional OASIS
would make compliance easier for non-public utilities and would help
them deal better with operational issues such as parallel flows. At the
same time, NE Public Power District argued that, although it is willing
to participate in an OASIS voluntarily, the Commission lacks authority
to compel publicly-owned non-public utilities to comply with OASIS
regulations.
In contrast, a number of public utilities maintained that non-
public utilities cannot provide comparable open-access non-
discriminatory service unless they comply with the same OASIS rules as
do public utilities. PJM argued that, although public utilities and
non-public utilities differ in their ownership, this does not provide a
rational basis to exclude non-public utilities from participation in an
OASIS. Carolina P&L argued that the same concerns that motivated the
Commission to propose the standards of conduct dictate that the rules
should apply equally to non-public utilities.
Others argued that, if non-public utilities need not comply with
the same OASIS rules applicable to public utilities, the non-public
utilities would have the benefit of an uneven playing field that would
give them a competitive advantage. Along these lines, EGA argued that,
in pursuing a competitive wholesale market, the Commission should apply
OASIS rules equally to all entities that own wholesale transmission
facilities. Mid-American stressed the need for reciprocity by pointing
out (as others did in response to Question 45) that a significant
portion of wholesale transmission facilities nationwide, including some
in pivotal areas, are owned by non-public utilities. VEPCO urged that
any entity that owns transmission facilities, is affiliated with an
entity that owns transmission facilities, controls transmission
facilities through a lease or contract, or signs a contract for
transmission services, should be required to establish or participate
in an OASIS that is compatible with the industry standards established
by the Commission in the final rule in this proceeding as a condition
of being eligible to use a Transmission Provider's OASIS.
OK Com stated that it would support the Commission's assertion of
jurisdiction over non-public utilities, provided that the Commission
makes a finding that the non-participation of a transmission owning
entity in an OASIS would have a substantial detrimental impact on
potential customers attaining open-access non-discriminatory service
throughout the Nation. Com Ed argued that the Commission needs to
ensure that non-public utilities do not circumvent the rule by making
purchases and sales through intermediaries.
Larger non-public utilities, such as Public Generating Pool,
suggested that the participation of larger non-public utilities is much
more important, in terms of promoting competition in the wholesale
market, than is participation by smaller non-public utilities, whose
systems are predominantly small distribution systems that are not
essential to the larger regional power market. Public Generating Pool
proposed that small non-public utilities should be able to seek an
exemption and that regional transmission groups should decide whether
it is necessary for a small non-public utility to participate in the
regional OASIS. Public Generating Pool also suggested that, if the
Commission prefers, decisions as to who is required to implement an
OASIS could be based on objective factors, such as market share or
concentration. Other non-public utilities, such as Seattle and
Tallahassee, stress the need for flexibility (in providing sufficient
time for compliance and in allowing deviations from the rule) in any
requirement that non-public utilities make changes to their system.
Discussion
After reviewing these comments we have concluded that we will not
directly assert jurisdiction over non-public utilities under Sec. 311
of the FPA to ensure compliance with OASIS requirements. We will,
instead, rely on the reciprocity provision of the pro forma tariff that
requires a non-public utility to offer comparable transmission service
to the Transmission Provider as a condition of obtaining open access
service. If a non-public utility chooses to take open access service,
and therefore is subject to the tariff reciprocity condition, it will
need to meet the OASIS requirements in new Part 37, unless the
Commission grants a waiver of this condition. Although, as pointed out
by ConEd, non-public utilities control a significant percentage of the
circuit miles of transmission lines nationwide, and fully accurate
calculations of available capacity on public utilities' lines cannot be
made without information about these lines,
[[Page 21743]]
we believe reciprocity provides a sufficient incentive for non-public
utilities to meet the OASIS requirements imposed on public utilities.
We note that in our Open Access Final Rule we have concluded that
certain of the requirements we are imposing on public utilities may not
be appropriate for small utilities. This conclusion applies equally to
the treatment of small public utilities and small non-public utilities.
Accordingly, we have established a mechanism in the Open Access
proceeding that allows small public utilities and small non-public
utilities to seek waivers based on the same criteria.24
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\24\ Open Access Final Rule at section IV.K.
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D. Section 37.2--Purpose
Section 37.2 sets out the fundamental purpose of this part--to
ensure that all potential customers of open access transmission service
have access to the information that will enable them to obtain
transmission service on a non-discriminatory basis. Comments in
response to the RIN NOPR did not take issue with the proposed language
of Sec. 37.2 and we are adopting this provision largely without change.
We wish to clarify, however, that while the OASIS requirements
imposed by this final rule establish a mechanism by which Transmission
Customers may reserve transmission capacity, they do not require the
replacement of existing systems for scheduling transmission service and
conducting transmission system operations at this time. We believe that
it may be appropriate to include energy scheduling as part of the OASIS
requirements developed for Phase II. In the meantime, if we conclude
that an existing system is operated in an unduly discriminatory manner,
we will pursue changes to such a system in a separate proceeding.
E. Section 37.3--Definitions
This section defines six terms used throughout this Part--
``Transmission Provider'', ``Transmission Customer'', ``Responsible
Party'', ``Resellers'', ``Wholesale Merchant Function'', and
``Affiliate''. The comments in response to the RIN NOPR did not take
issue with the proposed definitions. 25 Consequently, this final
rule adopts these definitions largely without change. To prevent
confusion, the definition of Transmission Customer has been revised to
include potential customers, i.e., those who can execute service
agreements or can receive services as well as those who actually do so.
And, we have modified the definition of ``Affiliate'' to more closely
track provisions of the FPA and the Public Utility Holding Company Act.
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\25\ MidAmerican Energy suggested, however, that a definition
for ``Transmission System Operator'' be added. We will not do so
because we do not use this term anywhere in the OASIS regulations.
MidAmerican's purpose in making this suggestion may have been to
exclude the posting on the OASIS of transactions involving the use
of transmission for purchases made for native load (this issue was
also brought up by CCEM, EGA, MidAmerican, NYPP, and NIEP). We
address the issue of native load purchases in the Open Access Final
Rule.
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F. Section 37.4--Standards of Conduct
This section sets out the standards of conduct necessary to ensure
that Transmission Providers do not use their unique access to
information unfairly to favor their own merchant functions, or those of
their affiliates, in selling electric energy in interstate commerce.
Although preserving the substance of what was proposed, the final rule
has been reorganized.
Paragraph (a) sets out the general rules that require the
separation of transmission and merchant functions and that recognize in
emergency circumstances system operators may take whatever steps are
necessary to keep the system in operation.
Paragraph (b) sets out the specific rules governing employee
conduct under five headings covering prohibited practices, transfers of
employees, access to information, disclosure, and conduct in
implementing tariffs. These provisions correspond to elements of
paragraph (a), as well as paragraphs (b) through (h) and (j) of the
standards proposed in the RIN NOPR.
Paragraph (c) requires that there be written procedures
implementing the standards of conduct and that these must be kept in a
public place and filed with the Commission. Paragraph (c) corresponds
to paragraph (k) of the standards proposed in the RIN NOPR.
In the RIN NOPR, the Commission proposed standards of conduct for
public utilities patterned after those promulgated for natural gas
pipelines.26 The proposed standards of conduct would require
Transmission Providers to separate their wholesale merchant functions
(i.e., wholesale purchases or wholesale sales of electric energy in
interstate commerce) from their wholesale transmission system
operations and reliability functions. Employees performing wholesale
merchant functions would be required to obtain information on wholesale
transmission services only through an OASIS, on the same basis
available to all other OASIS users. The standards of conduct were
intended to prevent employees of the Transmission Provider that perform
wholesale merchant functions or employees of any affiliate from having
preferential access to any relevant information about the Transmission
Provider's wholesale transmission availability and costs, or uses or
possible uses of the Transmission Provider's transmission system by
non-affiliates.27
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\26\ In the RIN NOPR, the proposed standards of conduct were set
out in Sec. 37.6. See RIN NOPR text at section III.E (60 FR at
66196) and the proposed regulation at 18 CFR Sec. 37.6 (60 FR at
66199). We are renumbering this provision as Sec. 37.4 in this final
rule.
\27\ Because the Open Access Final Rule pro forma tariff may
include certain retail transmission customers, this final rule's
OASIS information requirements will apply to applicable retail as
well as wholesale services and information.
---------------------------------------------------------------------------
We accompanied this proposal with two questions that asked whether
the proposed standards of conduct should be modified and whether they
sufficiently addressed functional unbundling (Questions 41 and 42). We
also asked whether our proposal might interfere with system reliability
(see Question 43).
The responses basically fell into three categories.\28\ First, a
number of smaller public utilities argued that they should be granted
waivers (or be deemed exempt) from the proposed standards of conduct
because these standards would compel them to hire additional staff not
justified by their small market share or by the small revenues they
derive from providing wholesale transmission services. These comments
suggested that the standards should not apply to public utilities that
lack operational control over the facilities used for wholesale
transmission service, or to public utilities that do not exceed given
thresholds for market share, percent of revenues, or total revenues
from wholesale transmission services.
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\28\ Among the over 100 comments filed, only Dayton P&L, among
public utilities, questioned the Commission's underlying authority
to mandate control room unbundling. Dayton P&L's short conclusory
statements in this proceeding were not accompanied by even a cursory
explanation of its reasoning or by any legal analysis or supporting
citations.
Although Dayton P&L offered no support for its position in this
proceeding, it did (along with other parties) devote extensive
discussion to the more general issue of the Commission's authority
to order open access transmission in its initial comments in the
Open Access rulemaking proceeding. We reject Dayton P&L's
unsubstantiated conclusion, urged in this proceeding, that we lack
authority to order control room unbundling for the same reasons that
we reject their more general and more extensive arguments on the
Commission's authority in the Open Access Final Rule. See Open
Access Final Rule at section IV.B.
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Second, a number of large utilities basically were satisfied with
the proposed rules and offered specific suggestions for revisions.
Third, commenters raised the issue of whether to require the separation
of generation
[[Page 21744]]
and transmission functions.\29\ We discuss these three categories
below.
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\29\ A number of comments raised the issue of whether the OASIS
regulations would promote ISOs (independent system operators) and
whether participation in an ISO would exempt an entity from
compliance with OASIS requirements. In this regard, a number of
comments suggested that the proposed standards of conduct will
result in the widespread transfer of transmission functions to the
control of ISOs and predicted that the need for the standards of
conduct will diminish as ISOs become more prevalent. In this
context, IN Com supported the formation of ISOs, because this would
reduce the need for state commissions to monitor functional
unbundling and would help in resolving jurisdictional questions.
The concept of ISOs is addressed in the Open Access Final Rule.
As to the prediction that the rise in the number of ISOs will make
the standards of conduct unnecessary, or should offer a basis for an
exemption from the standards of conduct, we would characterize the
potential of ISOs somewhat differently. In our view, a properly
constituted ISO could be a mechanism, not for an exemption, but as a
means to comply with the standards of conduct.
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1. Requests by Smaller Public Utilities for Waivers From the Standards
of Conduct
Turning first to the arguments of smaller public utilities that
they should be exempt from the standards of conduct, we note that this
issue also arose in the Commission's Open Access rulemaking proceeding.
As described in the Open Access Final Rule, we will publish a list of
jurisdictional public utilities that must comply with these rules. At
the same time, we establish a mechanism that allows small public
utilities to seek a waiver. In appropriate circumstances, the
Commission would waive some or all of the Open Access requirements,
subject to future reconsideration as warranted by circumstances.\30\
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\30\ Open Access Final Rule at section IV.K.
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A related issue involves the concerns of small non-public utilities
about their obligation under the reciprocity condition. We have decided
in the Open Access rulemaking proceeding that we would use these same
criteria to decide whether a small non-public utility should be granted
a waiver from all or part of the reciprocity condition contained in
public utility open access tariffs. Such waivers could be sought of the
requirements to have open access tariffs, provide ancillary services,
establish an OASIS, or separate functions.
A full explanation of the waiver mechanism is contained in the Open
Access Final Rule.\31\ We will use these same standards to determine
whether small public utilities have complied with the OASIS
requirements and to determine whether small non-public utilities have
met their contractual obligation to comply with OASIS requirements as a
condition of service under open access tariff reciprocity provisions.
---------------------------------------------------------------------------
\31\ Id.
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2. Suggested Revisions to the Standards of Conduct and Timing
For the most part, we have adopted the standards of conduct as
proposed, making technical and conforming revisions. In a few
instances, in response to comments, we have made substantive changes.
These changes, and the suggestions that led us to make them, are
discussed below, along with some suggestions that we rejected.
1. As proposed, the regulations would prohibit preferential access
to the system control room and ``other facilities of the public
utility'' that differs from the access available to other potential
transmission users. AEP suggested that it is not clear whether this was
intended to restrict access to all other facilities or is meant to
restrict access to other similar facilities, (i.e., those facilities
that, like the control room, are involved in transmission operations
and reliability functions). Consistent with this latter interpretation,
AEP suggested that the restriction be modified to apply to the system
control room and ``similar facilities used for transmission operations
or reliability functions.'' We agree with AEP's interpretation of the
scope of this restriction and adopt the suggested revision in section
37.4(b)(1)(ii) of the final rule.
2. Section 37.4(c) of the proposed standards of conduct would
prohibit contacts (off OASIS) between employees of the public utility
engaged in transmission system operations and employees of the public
utility engaged in wholesale marketing functions, and employees of any
affiliate no matter how employed. AEP, Com Ed, and Ohio Edison argued
that this provision is too broad and would exclude contacts between
transmission system operators and employees of affiliates engaged in
various activities, many of which are unrelated to a public utility's
merchant functions. For example, an energy services subsidiary might be
engaged in building a power plant in a foreign country. AEP argued that
there would be no reason to deny employees engaged in such an activity
access to utility personnel involved in transmission or reliability
functions. Com Ed suggested that this provision should be modified to
prevent contacts between system operators and employees engaged in
wholesale marketing functions, regardless of whether those marketing
employees are engaged in those activities on behalf of either the
utility or its affiliates. Thus, under this argument, contacts between
system operators and affiliate employees not engaged in wholesale
marketing functions would not be prohibited.
We agree with AEP, Com Ed, and Ohio Edison that our proposed
standards of conduct were overly broad because they prohibited contacts
between system operators and affiliate employees engaged in functions
completely unrelated to a public utility's wholesale power and energy
marketing functions. We will revise the proposed standards of conduct
accordingly.
AEP also argued that employees of the affiliate may be involved in
the wholesale merchant function, but not in the utility's market area.
For example, an employee of an affiliate might be involved in a
different geographic area, far from the system's transmission grid. AEP
argued that there would be no need to isolate such activities from the
utility's transmission operations. To cover such situations, AEP
suggested that the language be modified to read ``employees of any
affiliate of the public utility, to the extent that such employees are
engaged in wholesale merchant functions in the utility's market area.''
We reject AEP's suggestion. Although public utilities may still
have the ability to exert market dominance in particular markets, they
also will now have the ability to participate in transactions across
the nation. We fully expect--and our experience with the WSPP
demonstrates--that in the move to a competitive wholesale bulk power
market, public utilities will have extensive market areas in which to
make offers. Thus, there is no reason to limit the scope of the
standards of conduct as recommended by AEP.
We also have clarified section 37.4(b)(3)(i) to explain that
employees engaged in merchant trading functions must not have
preferential access to any information about the Transmission
Provider's transmission system that is not available to all users of an
OASIS. However, the standards of conduct do not foreclose customers,
including merchant employees, from obtaining information about the
status of their particular contracted for transaction from Transmission
Provider employees engaged in system operation and reliability
functions. The information provided in status reports must present the
same types of information, in the same level of detail, to any customer
presenting a similar request. The standards do, however, preclude
merchant employees from obtaining preferential access to information
about
[[Page 21745]]
the Transmission Provider's system (not directly linked to their
particular transaction) from any nonpublic source as well as market
information acquired from nonaffiliated customers or potential
nonaffiliated customers or developed by the Transmission Provider in
its role as a Transmission Provider (except to the limited extent that
this information is required to be posted on the OASIS).\32\
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\32\ See Sec. 37.4(b)(4)(iii); see text accompanying n. 33,
infra.
---------------------------------------------------------------------------
3. APPA argued that the rules should prohibit preferential
treatment of wholesale purchases or sales by any utility. APPA
interpreted the originally proposed language to mean that preferential
treatment would be permitted, as long as the preference would not be
extended to the public utility itself or an affiliate. APPA and Com Ed
argued that preferential treatment of any wholesale customer over the
interests of any other wholesale customer must not be allowed. Com Ed
adds that absent clarification, relationships of reciprocal favoritism
could develop in the industry, to the detriment of all other customers.
We find this contingency is possible. While the standards of
conduct set guidelines for Transmission Providers and their affiliates
in handling their wholesale merchant functions; public utilities are
also governed by section 205(b) of the Federal Power Act. Section
205(b) prohibits public utilities from granting any undue preference or
advantage to any person or subjecting any person to any undue prejudice
or disadvantage with respect to any transmission or sale subject to the
jurisdiction of the Commission. This provision remains in full force
and effect and prohibits preferential treatment in transactions
regardless of whether those transactions are specifically addressed in
the standards of conduct.
4. In section 37.6(i) of the RIN NOPR we proposed that public
utilities offer customers discounts comparable to those that the public
utility offers to its own power customers or those of an affiliate. AEP
suggested that this limitation on allowable discounts be expressly
limited to discounts on wholesale transmission services. We agree and
are revising this provision accordingly. Discounts for jurisdictional
power sales are not governed by this final rule but by section 205(b)
of the FPA and related precedent on power sales.
5. Allegheny suggested that the Commission should find that there
will no longer be a presumption of discriminatory dealing between
utility affiliates in generation and transmission services when network
owners comply with the standards of conduct. Allegheny has presented no
basis for making such a finding and we decline to do so.
6. Com Ed, Duke, and NEPOOL suggested that the proposed standards
should not be interpreted to prevent employees of the utility engaged
in wholesale marketing functions from obtaining information about their
competitors from non-affiliated third party sources such as the trade
press. Com Ed also suggested that the utility should be allowed freedom
to give out information about its transmission functions off OASIS
(e.g., in briefings at public meetings) as long as the utility's
wholesale marketing employees do not obtain preferential access to
those forums. Ohio Edison suggested that the proposed standards of
conduct should be revised to preclude only ``substantive access'' to
the system control room. Ohio Edison argued that access for matters
unrelated to transmission matters, such as training programs, should be
permitted.
We have two points we wish to make regarding these related
suggestions. First, we clarify that the rules do not prohibit access to
information contemporaneously available without restriction to other
members of the general public. (See section 37.4(b)(1)(ii) dealing with
access to information). Second, these rules are intended to be
interpreted consistent with common sense, prudence, and caution.
Our standards of conduct are intended to prevent preferential
access to information related to transmission prices and availability
by employees of the public utility or any affiliate engaged in
wholesale merchant functions. Preferential access means that
information is obtained from those with access to information about the
public utility's transmission system operations that is not equally
available to other customers. It is obvious, at least to us, that this
does not bar wholesale merchant employees from reading the trade press
or from sitting in the audience of a publicly-announced and available
lecture delivered by the public utility's transmission operator or a
third party in an open forum. However, the onus is on the public
utilities subject to these standards to conduct their affairs in
compliance with these rules, and they should exercise care and prudence
in so doing.
We decline, therefore, to specify in these regulations whether, for
example, a ``public meeting'' must be preceded by advance notice, to
whom that notice must be provided, and what that notice would need to
spell out. We do not believe that it would be appropriate to burden our
rules with this kind of minutiae in a misplaced effort to anticipate
every possible contingency. Such regulatory overkill is unwarranted and
counterproductive. Moreover, those subject to the regulations may, like
other members of the public, call the Enforcement Task Force Hotline to
obtain informal advice on implementing the standards of conduct.
7. VEPCO suggested that, rather than prohibiting contacts between
system operators and employees of the public utility and any affiliates
engaged in wholesale merchant functions, the Commission could reach the
same result by allowing system operators to disclose, through informal
communications, information about the status of the transmission
system, provided that they then post this information on OASIS.
We find this suggestion untenable. First, such disclosures would
necessarily be posted after-the-fact, and thus the information would
not be conveyed to all potential customers at the same time. Second,
such a provision would be very difficult to enforce. Third, the same
information could just as easily be divulged on the OASIS to all
customers, rather than ``reported'' on the OASIS after-the-fact.
8. Com Ed suggested that the reference in subsections (a) and (d)
of the proposed standards to ``reliability functions'' should be
clarified to apply only to transmission functions and not to generation
functions. We disagree. As discussed below, system operations and
reliability functions include both transmission and generation
functions.
9. Con Ed suggested that the standards of conduct should include a
disclaimer that utilities will not be liable for the reliability or
accuracy of data posted on the OASIS as an accommodation to third
parties. We agree that the responsibility for assuring the reliability
and accuracy of data supplied by third parties rests with those third
parties and not with the public utility that posts this information on
the OASIS as an accommodation. We do not, however, view this as a
standard of conduct issue. Instead, we address this point in our
discussion of what information is to be posted under Sec. 37.6(g).
10. Ohio Edison suggested that posting the names of personnel
transferring between departments would make these employees targets for
recruitment by competitors. Notwithstanding this concern, we believe
that this information must be posted on the OASIS to make possible
[[Page 21746]]
``gaming of the system'' through spurious revolving door tactics more
visible.
11. Ohio Edison also suggested that the phrase in subsection (b) of
the proposed standards ``* * * must rely upon the same information
relied upon by the public utility's wholesale transmission customers''
should be modified to read ``* * * must have available only the same
information available to the public utility's wholesale transmission
customers.'' Ohio Edison argued that the Transmission Provider has no
way of knowing what information its customers ``relied upon'' and that
it should not be held to an undefinable subjective standard. We agree.
Accordingly, we adopt Ohio Edison's suggestion in section 37.4(b)(3)(i)
of the final rule and omit the phrase ``rely upon.''
12. Ohio Edison also suggested that if its suggestion (in the
previous item) is adopted, then the language in section 37.4(b)
beginning with the language in parenthesis becomes redundant and should
be deleted. We disagree and will retain that language in section
37.4(b)(3)(ii) of the final rule. We believe the language adds
necessary clarification.
13. Montana Power suggested that, if off-OAS
FR Doc. 96-10693 Open Access Same-Time Information System (Formerly Real-Time Information Networks) and Standards of Conduct
IS communications
between the utility's system operators and wholesale marketing
personnel are prohibited, these kinds of communications should also be
prohibited between system operators and all transmission users. Montana
Power would prefer, however, that these communications be permissible.
Likewise, Duke suggested that we change the regulations so that if an
employee of an unrelated third party calls the transmission-related
employees, for example, to better understand the public utility's
transmission system, such communications should be permitted to be
conducted off the OASIS. Duke maintains that the free flow of
information should not be discouraged so long as functional unbundling
is implemented and affiliate abuse is avoided. NEPOOL suggested that
the rules dictating the Transmission Provider's release of information
should apply to all Transmission Customers, not just to the
Transmission Provider's employees, as affiliates, engaged in wholesale
merchant functions.
Our proposed standards of conduct were designed, and our final
standards are being implemented, to prevent Transmission Providers from
giving themselves an undue preference over their customers through the
exchange of ``insider'' information between the company's system
operators and employees of the public utility, or any affiliate,
engaged in wholesale marketing functions. Thus, the rules place
restrictions on preferential communications from the system operators
to only those merchant employees. The rules were not designed to
prevent system operators from having communications with third parties.
We do not generally see this as an area that needs regulatory
oversight. As discussed above, we have revised the regulations to
ensure no discriminatory treatment and we remind public utilities
subject to these regulations that section 205(b) of the FPA prohibits
undue discrimination. This should suffice.
14. NUSCO suggested that the Commission should distinguish: (1) The
functional separation of generation marketing related to operation of
the transmission system and administration of transmission tariffs
(which are relatively short-term activities); from (2) the coordination
of marketing with the system planning function (a long-term activity
encompassing both generation and transmission). Similarly, the FL Com
is concerned that the standards of conduct might impede system
reliability, and argued that marketers and system operators should be
able to confer concerning the company's long-term planning activities
that require knowledge about the company's generation and transmission
systems. NEPOOL expresses similar concerns.
By contrast, Com Ed suggested that the proposed standards of
conduct will not impair planning because, like a one-way street, they
allow information to be conveyed from employees engaged in merchant
functions to system operators, while at the same time prohibiting
information to be conveyed in the opposite direction. Com Ed submitted
that the inter-relationship between the areas of strategic planning,
resource planning and long-range transmission planning require the flow
of information to transmission personnel. Future acquisitions of
capacity may constitute a resource taken into account in planning and
may have an impact on the transmission system that needs to be
accounted for by transmission planners. Thus, Com Ed argued that there
should be no restriction on the flow of information about future
purchases or sales from the merchant function to the transmission
function, although restrictions on the flow of information to the
merchant function should be adopted as proposed.
We agree with Com Ed that, as we proposed in the RIN NOPR, the flow
of information, through the OASIS, from employees engaged in wholesale
merchant functions to system operators should remain permissible, to
allow proper system planning, while at the same time restricting
information being conveyed off the OASIS from system operators to
utility and affiliate employees engaged in wholesale merchant
functions, to prevent preferential access to transmission information.
Consequently, we reject the proposals offered by NUSCO, FL Com, and
NEPOOL in this regard.
15. Omaha PPD argued that information regarding the scheduling of
power transfers, economic dispatch, and economic conditions have
nothing to do with the information that is needed regarding the
availability of transmission capability. Omaha PPD suggested,
therefore, that any information relating to economic operation or the
commercial state of a utility be removed from the standards of conduct.
By contrast, NUCOR suggested that, since economic dispatch is premised
on real-time marginal production cost data and generating unit
economics, the comparability standard mandates that utilities provide
the same generation cost data to other market participants. Similarly,
NUCOR argued that, because economic dispatch also is dependent on the
economics of off-system purchases and sales, data pertaining to such
purchases and sales also must be made generally available.
Except for postings for certain ancillary services, the RIN NOPR
did not propose the posting on an OASIS of data on generation and we
are not persuaded, at this juncture, to do more. Our decision is based
on a balancing of the need for the information, the claimed commercial
sensitivity of the information, and the desire to avoid, to the extent
possible, having public utilities reporting generation data that their
competitors may not be required to report.
16. VEPCO suggested that the regulations should prohibit system
operators from disclosing information to wholesale marketing employees
or other customers about the ancillary services offered by third
parties because they are not permitted to disclose the same information
about their companies' own products. VEPCO further suggested that the
prohibition against discussing the companies' own products should be
removed.
We find these suggestions inconsistent with the kinds of safeguards
we are trying to provide through these standards of conduct. In any
event, as discussed below in our discussion of items to be posted on
the OASIS, we are requiring that this kind of information be posted on
the OASIS, and thus companies will be able to get
[[Page 21747]]
their message out that these services are available.
17. Duke suggested that the proposed subsection dealing with the
impartial application of tariff provisions should be revised to make
clear it is the customer (and not the employees) who is to be treated
on a fair and impartial basis. We agree and the final rule in section
37.4(b)(5)(ii) adopts this suggestion.
18. VEPCO suggested that the rules requiring a separation of
functions should be suspended if additional employees trained in system
operations (but normally assigned to marketing functions) should be
needed to assist in handling system operation functions during
emergencies affecting system reliability. VEPCO also suggested that the
Commission should allow transmission and generation operators to engage
in emergency energy transactions and hourly non-firm energy
transactions.
It is not the purpose of these rules to compromise reliability. In
emergency circumstances affecting system reliability, system operators
may take whatever steps are necessary to keep the system in operation.
Consequently, we are adding a provision to the standards of conduct
that specifically grants system operators the authority to take
whatever steps are necessary to maintain system reliability during an
emergency, notwithstanding that this could otherwise constitute a
violation of the standards of conduct. Transmission Providers will be
required to report to the Commission and on the OASIS each emergency
that resulted in any deviation from the standards of conduct, within 24
hours of such deviation. If we see a pattern of activities that
suggested that ``emergencies'' are not authentic, we will take strong
action against the offending public utilities.
Because we are adding a provision that allows actions to be taken
in response to emergencies, we are deleting the phrase ``to the maximum
extent practicable'' that had appeared in section 37.6(a) of the
standards of conduct proposed in the RIN NOPR.
19. Continental Power Exchange argued that, just as merchant
traders should be prohibited from access to the control center, system
operators should be prohibited from access to the trading floor. United
Illuminating agreed that separation of functions needs to apply to
separation of transmission and customer supply functions. Continental
Power Exchange also suggested that discounts should be offered
unilaterally to all customers without prior notice and without two-way
negotiation. Continental Power Exchange further suggested that short-
term transactions should be deemed approved upon request, unless the
utility specifically notifies the customer that the transaction will be
denied. Continental Power Exchange argued that this would streamline
the proposed procedures and make OASIS transactions faster and more
manageable.
We will not, at this time, adopt Continental Power Exchange's
suggestion to create an absolute prohibition against system operators
having access to the trading floor because we are concerned about
information divulged by system operators and not about information
acquired by them. However, any non-public contacts between system
operators and merchant traders creates the risk that there will be
improper communications between these employees and the burden is on
Transmission Providers subject to the standards of conduct to devise
procedures that will prevent improper contacts. We expect, therefore,
that the Transmission Providers themselves will devise procedures that
will either prohibit or, at a minimum, severely restrict access to the
trading floor by system operators.
As to Continental Power Exchange's other suggestions, we will not
adopt these suggestions at this time, but may come back to them as the
process evolves and the feasibility of back and forth negotiations is
tested by experience.
20. SoCal Edison and Tucson Power suggested that, while the
proposed 60-day deadline for filing procedures to implement the
standards is adequate, the Commission needs to be flexible on
implementing other changes, such as reconfiguring and relocating
control rooms and other facilities, and training and recruiting new
employees.
Although we originally proposed to require compliance with the
standards of conduct starting 60 days from the publication of this
final rule, on further consideration we have decided to put off the
requirement that they be implemented until the implementation of OASIS,
that is by November 1, 1996. As a practical matter, the standards of
conduct cannot be implemented apart from the electronic communication
systems of a functioning OASIS; the two work together. In addition, the
extra time will permit utilities the opportunity to fully implement the
requirements of the standards of conduct. Although the result will be a
window of time during which open access transmission tariffs will not
be supported by standards of conduct (or OASIS), we must recognize that
the changes we are mandating for the industry cannot be implemented
overnight; a transition period is required.
21. Finally, after a review of the comments, we have added an
additional provision to the standards of conduct (section
37.4(b)(4)(iii) of the final rule) dealing with the posting of any
additional market information developed by a Transmission Provider in
its role as a Transmission Provider and shared with employees of its,
or an affiliate's, merchant function.
We have expressed concern in a number of recent orders about the
possibility of the dissemination of market information by a public
utility with market-based rate authority.33 To guard against the
possibility of affiliate abuse, we have required such public utilities
to commit in their codes of conduct with affiliates to share market
information only if they make the same information publicly available
to non-affiliates at the same time. We have not dictated the means by
which public utilities are to make this information simultaneously
available to all.
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\33\ See, e.g., Illinova Power Marketing, Inc., 74 FERC para.
61,313, slip op. at 4-6 (1996); USGen Power Services, L.P., 73 FERC
para. 61,302 at 61,845 (1995).
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This same concern for the unequal distribution of market
information, in a manner that may benefit select recipients with
commercial or competitive information that is not equally available to
others, leads us, after a review of the comments, to extend the
standards of conduct to cover any market information gathered by
Transmission Providers in the course of responding to transmission or
ancillary service inquiries.
Our concern, based in part on our experience with implementing and
monitoring electronic bulletin boards developed for use by the natural
gas pipeline industry, is that there remains the incentive for a
Transmission Provider to share with its own merchant employees, or
those of an affiliate, any information it has developed (not limited to
transmission system information) in responding to requests made over
the OASIS. This is particularly a concern with respect to market
information developed in the course of denying a request for
transmission service.
While we have developed procedures dealing with the obligations of
Transmission Providers in responding to requests for service, we
believe that these procedures, alone, may not be sufficient to
eliminate the possibility of an unfair competitive advantage to
employees of the Transmission Provider
[[Page 21748]]
(or an affiliate) engaged in merchant functions, by virtue of access to
market information not shared with others.
Accordingly, we will add to the standards of conduct a provision
that precludes a Transmission Provider from sharing market information
acquired from nonaffiliated Transmission Customers or potential
nonaffiliated Transmission Customers or developed in the course of
responding to requests for transmission or ancillary service. In this
manner, we can be better assured that employees of the Transmission
Provider or an affiliate engaged in merchant operations do not develop
a competitive advantage by virtue of operation of an OASIS. The
Transmission Provider may only reveal information about transmission
requests as provided in the provisions of this rule (section 37.6 (e))
dealing, generally, with responses to transmission and ancillary
service requests and, specifically, with transaction confidentiality
(except to the limited extent that this information is required to be
posted on the OASIS).
3. Whether To Require the Separation of Generation and Transmission
Functions
In the RIN NOPR we proposed standards of conduct that would require
Transmission Providers and their affiliates to separate system
operation and reliability functions from wholesale merchant functions.
Both transmission and generation functions are included within system
operation and reliability functions. The RIN NOPR, notwithstanding
Questions 42 and 43, did not propose that these functions (transmission
and generation) be separated. Nor did we propose that Transmission
Providers divest their ownership of generation assets.
We received numerous comments in response to our questions 42 and
43 that asked whether, if the Commission would go beyond unbundling
transmission and generation merchant functions to order the unbundling
of generation and transmission operations, this would necessitate
revision of the proposed standards of conduct and whether this would
adversely affect reliability.\34\ After reviewing the comments, we
conclude that we should require--with these final rules--only the
unbundling of the transmission operations and wholesale marketing
functions of public utilities and their affiliates, as proposed in the
RIN NOPR. We do not extend these rules to require the unbundling of
transmission and generation control functions or to mandate the
divestiture by Transmission Providers of their generation assets.
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\34\ The commenters nearly universally focused their
presentations on why the Commission should not order an unbundling
of generation and transmission operations, rather than addressing
the precise topic we set out. In any event, the issue is now moot,
as we have decided not to order Transmission Providers to separate
their generation and transmission operations at this time. If,
however, with experience we discover that the steps we are ordering
here are not adequate to remedy undue discrimination, we can revisit
this issue.
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We will require the functional unbundling of transmission
operations and wholesale marketing functions because we are persuaded
that this will prevent abuses based on preferential access to
information and other discriminatory behavior, without compromising
system reliability. The standards of conduct are designed to accomplish
this: (a) By requiring that transmission-related information be made
available to all customers (including employees of the public utility,
and any affiliate, engaged in merchant functions) through OASIS
postings available to all customers at the same time and on an equal
basis; and (b) by prohibiting the employees of Transmission Providers
and any affiliates from disclosing (or obtaining) non-public
transmission-related information, through communications not posted on
the OASIS.
G. Section 37.5--Obligations of Transmission Providers
This section of the final rule adopts, without substantive change,
the provisions proposed as section 37.4 (Standardization of Data Sets
and Communication Protocols) and section 37.5 (Obligations of
Transmission Providers) in the RIN NOPR. The final rule requires, in
paragraph (a), that a Transmission Provider must provide for the
operation of an OASIS either individually or jointly with other
Transmission Providers and it must do so in accord with the
requirements of Part 37. Paragraph (b)(1) requires that the OASIS must
give access to relevant standardized information pertaining to the
status of the transmission system as well as to the types and prices of
services. Finally, in paragraph (b)(2), the rule requires that the
OASIS must be operated in compliance with the protocols set out in the
publication, OASIS Standards and Communication Protocols.
In the RIN NOPR, we explained that each Transmission Provider would
be responsible for compliance, regardless of whether it establishes its
own OASIS or participates in a joint OASIS.\35\ The final rule does not
change this. In a related provision, we proposed, in Sec. 37.1, that
Part 37 would apply to any public utility that owns, operates, or
controls facilities used for the transmission of electric energy in
interstate commerce. However, as noted by many commenters, it is quite
probable that individual public utilities may turn the operation of
their transmission system and information system over to an ISO or
other joint or regional entity. (This has been provided for in the
definition of the term ``Responsible Party''). This raises the issue of
the Commission's jurisdiction over such entities.
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\35\ NRECA commented that the Commission should ensure that
expenses by a joint OASIS are subject to the Commission's
jurisdiction and audit authority. We agree. We will treat this as a
normal ratemaking expense issue and will allocate such costs on a
case-by-case basis when such expenses are presented to us for our
review.
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Under section 201(e) of the FPA, a ``public utility'' means,
Any person who owns or operates facilities subject to the
jurisdiction of the Commission under this Part (other than
facilities subject to such jurisdiction solely by reason of section
210, 211, or 212).\36\
\36\ 16 U.S.C. Sec. 824.
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To the extent that anyone is given control and decision making
authority over the transmission operations of a public utility's
transmission facilities, it clearly would ``operate'' public
facilities, within the meaning of section 201(e), and therefore would
be subject to the Commission's jurisdiction.\37\ To the extent that a
public utility turns over its operations to an ISO or any other joint
entity to satisfy the Open Access and OASIS requirements, the ISO or
any other entity would fall within the definition of a ``public
utility'' under Sec. 201 of the FPA and thus would be subject to the
OASIS regulations of Part 37.
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\37\ See, e.g., Bechtel Power Corporation, order granting
declaratory order and disclaiming jurisdiction, 60 FERC para. 61,156
at 61,572 (1992) (on control issue), and FPC v. Florida Power &
Light Company, 404 U.S. 453 (1972) (on defining jurisdictional
facilities).
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H. Section 37.6--Information To Be Posted on an Oasis
In the RIN NOPR, we proposed, in sections 37.7 through 37.14, rules
governing: (1) The information that must be posted on an OASIS; (2) the
procedures for the posting and updating of information on the OASIS;
(3) the posting of discounts; (4) procedures for Transmission Providers
to respond to customer requests for transmission service; (5)
procedures for communicating denials of requests for service and
curtailments; and (6) the posting of information about scheduling and
affiliate transactions. These
[[Page 21749]]
provisions have been consolidated and are now covered in Sec. 37.6 of
the regulations adopted by this final rule.
As discussed in more detail below, section 37.6 has eight
paragraphs. Paragraph (a) lists the objectives of an OASIS. Paragraph
(b) lists what must be posted for public transmission capability--that
is, available transmission capability (ATC) and total transmission
capability (TTC)--as well as how and when this information is to be
updated. Paragraph (c) sets out the requirements for posting
transmission service products, including resold capacity as well as
their prices. Paragraph (d) provides the same for offerings of
ancillary services. Paragraph (e) sets out the requirements for posting
transmission service requests and responses including service denials
and curtailment or interruption of transmission. Paragraph (f) provides
requirements for posting transmission service schedules. Paragraph (g)
deals with posting other transmission-related communications. Finally,
paragraph (h) sets out the requirements for auditing information.
Some of the proposed provisions have not been adopted. These
include requirements concerning an application procedure for requesting
transmission service (Sec. 37.9(b)(5) of the proposed regulations);
requirements imposed on the reseller to notify the Transmission
Provider of certain information (Sec. 37.9(c)(3) of the proposed
regulations); and the steps that must be followed by the Transmission
Provider and Requester in their negotiations (Sec. 37.12 of the
proposed regulations). These did not prescribe information that must be
posted; rather, they were concerned with how parties should conduct
business in an open access environment. These matters are considered in
the Open Access Final Rule.
1. OASIS Objectives (Sec. 37.6(a))
The Commission proposed five objectives for the OASIS in the RIN
NOPR.38 Few comments were received on these objectives; none were
substantive. Thus, we adopt these objectives without substantive
revision in the final rule.
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\38\ See RIN NOPR text at section III.C (60 FR at 66188) and the
proposed regulation at 18 CFR 37.7 (60 FR 66200).
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2. Posting Transmission Capability (Sec. 37.6(b))
a. ATC for Network Integration Service. The RIN NOPR discussed
requiring the posting of available transmission capability for network
service. As we acknowledged in the RIN NOPR,39 before-the-fact
measurement of the availability of network transmission service is
difficult. Nonetheless, it is important to give potential network
customers under the Commission's pro forma tariff (as discussed in the
Open Access Final Rule) 40 an easy-to-understand indicator of
service availability. To this end, the Commission requested comments on
how best to post the availability of network transmission service on
the OASIS (Question 3).
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\39\ See RIN NOPR text at section III.C (60 FR at 66188).
\40\ See Open Access Final Rule at sections IV.G and IV.H.
---------------------------------------------------------------------------
NERC reiterated the statement in the What Group report that ``it
does not seem possible to post the availability of Network Integration
Transmission Service'' on an OASIS. No other commenter disagreed.
NERC went on to describe some of the challenges involved with
calculating available transmission capability (ATC) for network
integration service. Network service is a complex, long-term
relationship between a requester and provider that must be investigated
in detail because it involves the specification of multiple points of
receipt or delivery or both. Because of the long-term nature of network
service, the planning process involves a complex interrelationship of
future loads and resources, with an impact on the network that is
extremely location dependent. A major difficulty in estimating network
ATC is the lack of specific locations for which to calculate an impact
on the network. Each network service request would be unique, with
different sets of integrated loads and generating stations affecting
the network, including its constrained paths, differently.
The Commission also asked if there were any alternative service
that is more suitable to measurement than the current version of
network service. Some commenters said that it might be possible to
devise a concept which supports better measurement of network-like
service availability, but devising and implementing such a new concept
within the proposed initial implementation time line for OASIS is not
feasible. The Commission is not, at this time, persuaded to require the
posting of ATC for network service.
b. Minimizing the Reporting of ATC (Secs. 37.6(b) (1) and (3)). In
the RIN NOPR, the Commission requested comments on ways to minimize the
burden of ATC calculations, while ensuring that wholesale Transmission
Customers have the information they need (Question 5).
Commenters suggested a number of ways to minimize the reporting of
ATC, including less frequent updates, developing standardized methods
for calculating ATC, and encouraging regional efforts. Most of the
comments discussed ways to limit the number of paths for which ATC has
to be posted.
The What Group proposed that ATC be posted only for paths as
``business needs'' arise. This proposal was intended to limit the
number of paths for which ATC must be posted. A ``business need'' was
defined, in part, by a Transmission Customer requesting information
about a path. A number of commenters supported the proposal to limit
paths based on ``business need.'' 41
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\41\ See, e.g., Arizona, ConEd, NEPOOL, NE Public Power
District, NERC and Western Group comments.
---------------------------------------------------------------------------
The Commission suggested in the RIN NOPR a different approach to
the problem. Calculating ATC and updating frequency could be based,
instead, on the level of activity and constraints on a given path. This
approach was supported by a number of commenters.42 A number of
commenters wanted to leave to the Transmission Provider the decision of
which paths to post ATC.43
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\42\ See Basin EC, Duke, NE Public Power District, Tallahassee,
Union Electric, and VEPCO comments. Only Arizona said it was a bad
idea because it would be too subjective and confusing.
\43\ See Central Illinois Public Service, Detroit Edison, Omaha
PPD, PSNM, Texas Utilities, Union Electric, and VEPCO comments.
---------------------------------------------------------------------------
Detroit Edison, Oklahoma G&E and PSNM suggested that customers
could also identify paths, along with a process for deleting them.
NEPOOL and Detroit Edison stated that they will post ATC for all
control area interfaces and any internal constraints. The Western Group
had a similar proposal.
NE Public Power District, NERC and NSP commented that ATCs should
be posted only for constrained paths. PJM and WP&L proposed that, for
unconstrained paths, static numbers or limits could be used and would
be updated infrequently. VEPCO suggested that paths be coded by the
quality of the ATC calculation used and that high quality effort be
used only when ATC is less than 25 percent of the total transmission
capability. ConEd suggested that posting could be sorted by frequency
of update so that busier paths would be at the top of the list.
Dayton P&L suggested mandatory information on ATC be limited to:
(1) Identification of the interface; (2) firm and non-firm ATC (hourly
for the current day, daily for the next seven
[[Page 21750]]
days, weekly for the next four weeks, monthly for the next 12 months);
and (3) price for each service.
MAPP summarized the issue well when it stated ``[t]he burden of ATC
calculations will be determined by the number of paths for which ATC is
being calculated and posted, the accuracy needed and the frequency of
required update.''
The proposed regulations have been modified to implement the
alternative approach suggested by the Commission in the RIN NOPR. The
regulations in Sec. 37.6(b)(1) define the paths for which ATC and TTC
must be posted. These are called ``posted paths.''
A transmission path becomes a ``posted path'' in one of three ways.
First, ATC and TTC must be posted for any path between two control
areas. Second, posting is required for any path for which transmission
service has been denied, curtailed or subject to interruption during
any hour or part of an hour for a total of 24 hours in the last 12
months. In counting up to 24, curtailment for any part of an hour
counts for a whole hour. Finally, Transmission Customers can request
that ATC and TTC be posted for any other transmission path. Customer
requested postings may be dropped if no customer has taken service on
the path in the last 180 days.
The regulations in Sec. 37.6(b)(3) define two classes of posted
paths based on usage: ``unconstrained'' and ``constrained''. A
constrained posted path is one for which ATC has been less than or
equal to 25 percent of TTC for at least one of the last 168 hours or is
calculated to be 25 percent or less of its associated posted TTC during
the next 7 days. An unconstrained posted path is any posted path that
is not a constrained posted path.
For constrained posted paths, ATC and TTC for firm and non-firm
service would have to be posted for the next 168 hours and, thereafter,
to the end of a 30-day period. In addition, ATC and TTC for firm and
non-firm service must be posted for the current month and the next
twelve months. However, this monthly posting for ATC and TTC for non-
firm service is required only if requested by a customer. If the
Transmission Provider charges separately for on-peak and off-peak
periods in its tariff, ATC and TTC will be posted daily for each
period. A posting for a constrained posted path must be updated when
transmission service on the path is reserved or service ends or when
the path's TTC changes by more than 10 percent.
For an unconstrained posted path, ATC and TTC for firm transmission
service and non-firm transmission service would be required to be
posted for the next seven days and for the current month and the next
twelve months.44 If the Transmission Provider charges separately
for on-peak and off-peak periods in its tariff, ATC and TTC will be
posted for the current day and the next six days following for each
period. Postings for an unconstrained posted path must be updated when
the ATC changes by more than 20 percent of the path's TTC.
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\44\ The terms ``firm point-to-point transmission service'' and
``non-firm point-to-point transmission service'' are defined in the
definition section of the pro forma tariff for point-to-point
service.
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We will not require ATC and TTC to be posted on the OASIS more than
thirteen months in advance, with the following exception. If planning
and specific requested transmission studies have been done, seasonal
capability shall be posted for the year following the current year and
for each year following to the end of the planning horizon, but not to
exceed 10 years.
c. Methodology for Calculating ATC and TTC (Sec. 37.6(b)(2)). In
the RIN NOPR, the Commission discussed the requirements for calculating
ATC and TTC.45 Recognizing that formal methods do not currently
exist to calculate ATC and TTC, the Commission requested comment on how
to develop a consistent, industry-wide method of calculation (Question
4).
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\45\ See RIN NOPR text at section III.C (60 FR at 66188) and the
proposed regulation at 18 CFR 37.9(b)(2) (60 FR 66200).
---------------------------------------------------------------------------
Most commenters recommended that the Commission defer to NERC
regarding the development of a consistent, industry-wide method of
calculation. NERC, in turn, recommended that the Commission give
deference to NERC's ongoing, industry-wide effort. NERC's Transmission
Transfer Capability Task Force (TTC Task Force), with an expanded
roster to include representation from all segments of the electric
industry, was formed to develop uniform definitions for determining ATC
and related terms. Because the TTC Task Force will not be finished with
its assignment until May 1996, NERC recommended that the OASIS final
rule not contain specific definitions of terms such as ATC, but instead
be limited to a general framework within which the same information can
be made available to all transmission users at the same time.
The Commission encourages industry efforts to develop consistent
methods for calculating ATC and TTC. Consequently, the final rule
follows the proposed regulations in requiring that ATC and TTC be
calculated based on a methodology described in the Transmission
Provider's tariff and that it be ``based on current industry practices,
standards and criteria.'' (Section 37.6(b)(2)(i)).46
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\46\ The pro forma tariff in the Open Access Final Rule provides
that Transmission Providers must develop a method for calculating
ATC and TTC and must include a description of this methodology in
their tariffs.
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As provided in the pro forma tariff, Transmission Providers may
themselves purchase only transmission capability that is posted as
available. This requirement should create an adequate incentive for
them to calculate ATC and TTC as accurately and as uniformly as
possible.
d. Accommodating Flow-Based Pricing. In the RIN NOPR, the
Commission asked for comment on what requirements would have to be
changed if the electric power industry moves to regional pricing, flow-
based pricing, or other pricing models that depart from the ``contract
path'' approach (Question 2).47
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\47\ See RIN NOPR text at section III.C (60 FR at 66186).
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Many commenters expressed the need for OASIS flexibility to support
both contract path and actual flow models.48 Com Ed stated that,
so long as the OASIS is flexible, appropriate postings involving ATC,
price, and related information will develop for use with tariffs using
flow-based pricing.
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\48\ See, e.g., Consumers Power, Basin EC, ERCOT, NEPOOL, PA
Com, How Group, NIEP, NYPP, NERC, Ohio Com, OK Com, Oklahoma G&E,
PSNM, Texas Utilities, Western Group, PacifiCorp, and PJM comments.
---------------------------------------------------------------------------
The Commission concludes that the proposed regulations were general
enough to accommodate flow-based pricing methods. Therefore, we have
provided no special provision regarding flow-based pricing in the final
rule. Any OASIS-related issue that arises when flow-based proposals are
made can be dealt with at that time. We cannot accurately foresee what
issues may arise concerning flow-based pricing because this is an
evolving area.
e. Actual Flow Data. The RIN NOPR proposed the posting of actual
path flow data to better inform Transmission Customers about the true
network impacts of taking service on a contract path basis.49 The
Commission asked whether there are any difficulties, technical or
otherwise, associated with posting actual path flows (Question 20).
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\49\ See RIN NOPR text at section III.C (60 FR at 66191).
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In response, commenters stated that such posting is technically
difficult, but possible. However, they question the value and
usefulness of such postings.50
[[Page 21751]]
Commenters stated that information on actual path flows is voluminous,
excessive, and burdensome to post.
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\50\ See, e.g., Allegheny, Arizona, Central Illinois Public
Service, Carolina P&L, Florida Power Corp, Montana Power, NERC,
Omaha PPD, Texas Utilities, Union Electric, and VEPCO comments.
---------------------------------------------------------------------------
Allegheny stated that actual flow information could be commercially
sensitive depending on the degree to which a generator's output can be
determined from it. Oklahoma G&E stated that actual flows are
meaningless unless accompanied by voltage, line thermal limits, and
line first contingency incremental transfer capability. NERC commented
that actual path flow postings would be irrelevant or even misleading
to the Transmission Customer and should not be required. NERC added,
however, that the Commission should not preclude such postings either.
The How Group pointed out that, from a technical standpoint, posting
actual path flows significantly increases the level of detail in
information about transmission service. APPA answered that some regions
already have the capability to post actual flows, but functional
separation diminished the need for the Commission to require the
posting of actual flows.
The final rule does not require the posting of actual path flows.
As long as ATC and TTC are calculated to reflect network conditions,
including parallel path constraints, actual flow data need not be
posted. The Commission may reassess this issue after reviewing the
proposals of the TTC Task Force on methods for calculating ATC and TTC
expected in May 1996.
f. Providing Supporting Information (Sec. 37.6(b)(2)(ii)). In the
RIN NOPR, we proposed that public utilities must post all data used in
calculating the ATC and TTC and make such data publicly
available.51 The Commission received a number of comments on this
proposal.
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\51\ See RIN NOPR text at section III.C (60 FR at 66190) and the
proposed regulation at 18 CFR 37.9(b)(6) (60 FR 66200).
---------------------------------------------------------------------------
A majority of commenters stated that supporting data should not be
available on the OASIS.52 About half of the commenters argued that
the data should be available off-line.53 Others suggested that
procedures and software used in calculating ATC and TTC must be
posted.54 NYPP suggested that a bibliography of supporting
information should be maintained on the OASIS.
---------------------------------------------------------------------------
\52\ See, e.g., Allegheny, Central Illinois Public Service,
Continental Power Exchange, EPRI, Florida Power Corp, MAPP, NERC, NE
Public Power District, NYPP, Ohio Edison, PSNM, VEPCO, Western
Group, and WP&L comments.
\53\ See, e.g., Allegheny, ConEd, Detroit Edison, Duke, EPRI,
Idaho, MAPP, NEPOOL, NE Public Power District, Ohio Edison, PSNM,
VEPCO, and Western Group comments.
\54\ See, e.g., Duke, EPRI, Idaho, PSNM, Western Group comments.
---------------------------------------------------------------------------
Having this information available is essential for building and
maintaining trust in the information posted on the OASIS. Transmission
Providers generally seem willing to provide this information after-the-
fact and off-line. Since this information would be used only after-the-
fact and can be voluminous, the final regulations require that ATC and
TTC supporting information be made available by the Responsible Party
within one week of posting, on request, in their original electronic
format and at the cost of reproducing the materials. A requirement
specifying how long the information must be retained also has been
added.
g. Long-Term Studies (Sec. 37.6(b)(2)(iii)). The RIN NOPR proposed
that any planning or specifically requested studies of the transmission
network performed by the Transmission Provider be posted on a same-time
basis.55 This would include only those parts of customer-specific
interconnection studies that relate to network impacts.
---------------------------------------------------------------------------
\55\ See RIN NOPR text at section III.C (60 FR at 66191) and the
proposed regulation at 18 CFR 37.8(c) (60 FR 66200).
---------------------------------------------------------------------------
The majority of commenters responded that transmission planning
studies should not be posted on the OASIS. ConEd and MAPP suggested an
index to be maintained on the OASIS. NEPOOL, Tallahassee, and Montana
Power suggested that summaries should be maintained on the OASIS.
As with the ATC supporting information, having this information
available is essential for building and maintaining trust in the ATC
and TTC posted on the OASIS. Since this information would be used only
after-the-fact and can be voluminous, the final regulations require
that final transmission studies be available from the Responsible Party
on request in original electronic format and at the cost of reproducing
the materials. A list of available studies is to be posted on the
OASIS. A requirement specifying how long the studies must be retained
also has been added.
3. Posting Transmission Service Products and Prices (Sec. 37.6(c))
Paragraph 37.6(c) of the regulations adopts several of the proposed
provisions. It requires Transmission Providers to post prices and a
summary of the terms and conditions of transmission products. In
addition, Transmission Providers must provide a downloadable file of
their complete tariffs. Furthermore, customers who use an OASIS to
resell transmission capacity must submit relevant information about
their resale transactions to the Transmission Provider for posting to
the same OASIS as used by the Transmission Provider in originally
offering that capacity. As proposed in the RIN NOPR, the Transmission
Provider must post this information about resales on the same display
page, using the same tables, as similar capacity being sold by it.
Similarly, the information must be contained in the same downloadable
files as the Transmission Provider's own available capacity. A customer
who does not use an OASIS to arrange a resale of transmission capacity
must, nevertheless, inform the original Transmission Provider of the
transaction within the time limits prescribed by the ``Sale or
Assignment of Transmission Service'' section of the pro forma tariff.
The proposed standards of conduct required a Transmission Provider
that offers any discount on behalf of its power customers or those of
an affiliate, to post offers for similar service containing comparable
discounts, at the same time, to all Transmission Customers.
As to discounts that the Transmission Provider has agreed to give
to any Transmission Customer (affiliated or unaffiliated), the
Commission proposed requiring that these discounts be posted within 24
hours after the agreement is entered (measured from when ATC is
adjusted in response to the agreement), and that they remain posted for
30 days. The Commission sought comment on whether all transmission
discounts should be posted on the OASIS, or only those provided to the
Transmission Provider or its affiliates (Question 14).
Most commenters, including representatives with diverse interests
such as APPA, EEI, Continental Power Exchange, EGA, EEI, NIEP, and
NRECA, argued that discounts must be made available to all customers.
NRECA especially, was concerned about the potential for selective
discounting. The Ohio Com, clearly concerned about allowing
Transmission Providers to negotiate privately, asked that we clarify
how discounting would work, and EGA raised some practical concerns
about how the Commission's proposal would work. EGA asked whether, when
a discount is offered to an affiliate, discounts must be offered to
others on the same path, all paths, or only paths needed to get to the
buyer to whom the affiliate is selling. This issue is addressed in the
Open Access Final Rule, which concludes that such
[[Page 21752]]
discounts must be offered to all customers on all unconstrained paths.
Several commenters were against discounting, but would accept
discounts if they were made available to all customers.\56\ Several
commenters agreed with the proposal to require posting of discounts
offered to affiliates and delaying the reporting of discounts to
others.\57\ However, CCEM wants to change the 24-hour delay period to
30 days.
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\56\ See ERCOT, MidAmerican, NUCOR, and Public Generating Pool
comments.
\57\ See CCEM, OK Com, and Tallahassee comments.
---------------------------------------------------------------------------
SCE&G and Union Electric would allow discounting but not post them
on the OASIS. Central Hudson would post only affiliate discounts. SMUD
argued that selective discounting is good and stated that, if public
utilities must offer discounts to everyone, no discounts would be
offered to anyone.
The question of whether discounts may be offered is discussed in
the Open Access Final Rule.\58\ If a Transmission Provider offers a
discount for transmission service to its own power customers or those
of an affiliate, it must, at the same time, post on the OASIS an offer
to provide the same discount to all eligible customers on the same path
and on all unconstrained transmission paths. As to discounts for
ancillary services, if a Transmission Provider offers a rate discount
to an affiliate, or attributes a discounted ancillary service rate to
its own transactions, the Transmission Provider must, at the same time,
post on the OASIS an offer to provide the same discount to all eligible
customers. If a Transmission Provider offers discounts to non-
affiliates, it must offer to do so on a basis that is not unduly
discriminatory. Any discounts under Sec. 37.6(c)(3) offered to
affiliates or to the Transmission Provider's own power customers must
be posted on the OASIS when they are offered pursuant to
Sec. 37.4(b)(5)(v). Discounts offered to non-affiliates must be posted
within 24 hours of when ATC is adjusted in response to the transaction.
---------------------------------------------------------------------------
\58\ See generally Open Access Final Rule at sections IV.D and
IV.G.
---------------------------------------------------------------------------
4. Posting Ancillary Service Offerings and Prices (Sec. 37.6(d))
Transmission Providers are required to post on the OASIS
information about all ancillary services required by the Open Access
Final Rule to be provided or offered to customers.\59\ A Transmission
Provider may, at its discretion, post information on the OASIS about
other interconnected operation services, offered by itself or third
parties, that are not services required by the Open Access Final Rule
to be offered to customers. However, if a Transmission Provider elects
to post these optional services for any party, including itself, then
it must post on its OASIS, for a reasonable cost based fee, the same
type of information about comparable optional ancillary services
offered by third parties.
---------------------------------------------------------------------------
\59\ See generally Open Access Final Rule at section IV.D.
---------------------------------------------------------------------------
In the RIN NOPR, we proposed the posting of price and other
information about ancillary services.\60\ We requested comment on: (1)
The information needed about ancillary services (Question 12); (2) how
often the information should be updated (Question 13); and (3) where on
the information network offers of ancillary services by entities other
than the Transmission Provider should be placed (Question 9).
---------------------------------------------------------------------------
\60\ See RIN NOPR text at section III.C (60 FR at 66190).
---------------------------------------------------------------------------
While there is near consensus among commenters on the need to
update ancillary services information as it changes, there is
widespread disagreement on what information about ancillary services
should be posted and where on the OASIS offers by other entities to
provide ancillary services should be placed. Some commenters request
that the Commission allow flexibility because the information
requirement may depend upon the industry structure that develops in
response to the Open Access Final Rule. NERC asserted that it is
impractical to expect the initial OASIS to be the vehicle for posting
information on the availability and price of all ancillary services.
Ancillary service providers are required to post all pertinent
information about their ancillary service offerings (e.g., a
description of the service being offered, its availability, and its
price) so that Transmission Customers may compare offers and decide
which offer best suits their needs. Information about ancillary
services should be updated as it changes. Postings by customers and
third parties should be on the same page, and in the same format, as
postings of the Transmission Provider.
5. Posting Transmission Service Requests and Responses (Sec. 37.6(e))
Section 37.6(e) requires that all requests by customers for
transmission service that the Transmission Provider offers under the
pro forma tariff must be made on the OASIS. The Responsible Party is
required to provide to others on the OASIS the essential information
relating to such requests, with the identity of the parties masked, if
requested. Additionally, the section sets out the steps that must be
followed in processing such requests, including the posting of
curtailments, interruptions, or denials of service.\61\ The final OASIS
regulations require that a record of transactions not resulting in
agreements also be kept for audit purposes. We now discuss some special
issues arising under this provision and the comments relating to those
provisions.
---------------------------------------------------------------------------
\61\ The Open Access Final Rule discusses curtailments at
section IV.G and provides that a company's curtailment policy is to
be described in its tariff.
---------------------------------------------------------------------------
a. Posting Curtailments and Interruptions (Sec. 37.6(e)(3)). We
proposed requiring that, when a transaction is curtailed, a
Transmission Provider must post the reason that the transaction was
curtailed and the available options, if any, for adjusting the
operation of the Transmission Provider's system to increase transfer
capability in order to accommodate the transaction.\62\ Since
scheduling and the curtailment of schedules would not be done through
the information network initially, this curtailment data would be for
information purposes only.
---------------------------------------------------------------------------
\62\ ``Curtailments'' are service cutbacks made for system
reliability reasons and are distinguishable from ``interruptions'',
which are made pursuant to tariff conditions.
---------------------------------------------------------------------------
The Commission requested comments on what information about
curtailments should be communicated on an OASIS (Question 7). Only
Union Electric, among the commenters who answered this question, argued
against posting information about curtailments or recording this
information in an audit file. Among those who supported posting or
recording, the differences were in how much information should be
provided, where the information should be placed, and who should have
access to the information.
The comments expressed support for a Transmission Provider setting
out in its tariff, or elsewhere, curtailment or interruption rules or
constraint relief protocols.\63\ This would let a customer know what to
expect when there is a constraint and would allow the Transmission
Provider to be held to a formal set of procedures. Then, when a
curtailment occurs, postings on the OASIS can refer to steps and
reasons defined in the curtailment procedures.
---------------------------------------------------------------------------
\63\ See APS, NERC, and NIEP comments.
---------------------------------------------------------------------------
Many commenters agreed that at least some basic information about
curtailments needs to be posted or documented in the audit file.
Several commenters pointed out that there may
[[Page 21753]]
be some lag before these postings are placed on the OASIS because
control room personnel may need time to determine and resolve the
problem.\64\ Some commenters believed that these postings should be
made available only to those curtailed.\65\
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\64\ See Allegheny, Com Ed, CSW, NERC, NRECA, and SCE&G
comments.
\65\ See, e.g., Allegheny and Central Illinois Public Service
comments.
---------------------------------------------------------------------------
The proposed regulations addressed curtailments and denials of
service together. In this final rule, denials are distinguished from
curtailments of service. Transmission Providers are not required to
offer options for making capacity available to those curtailed, but if
options are offered, they must be offered to curtailed and interrupted
customers at the same time.
As discussed in the Open Access Final Rule, transmission tariffs
must include rules for curtailment and interruption of service,
including clear steps or stages in the process for relieving
constraints, and transmission service agreements must clearly identify
the service's priority relative to concurrent services. Consistent with
these requirements, the final rule here provides that, when
curtailments or interruptions take place, they must be posted as soon
as possible and must include identification of the service (with the
identity of the customer masked), the reason for the curtailment or
interruption, and the tariff-defined step in the curtailment and
interruption process. In the event that an emergency situation
affecting system reliability delays this posting, the posting must be
made as soon as practicable thereafter along with an explanation for
the delayed posting.
Curtailments and interruptions will be recorded for audit purposes.
This audit data should contain enough information about the timing of
superseding requests and changes in ATC to document the reason for a
curtailment or interruption. The final rule also provides that
customers have the right to request an explanation of the reason for a
curtailment or interruption.
b. Posting Denials of Requests for Service (Sec. 37.6(e)(2)). In
the RIN NOPR, we proposed requiring that, when requests for service are
denied, Transmission Providers must communicate to Transmission
Customers through the OASIS: the reason(s) that the transaction(s)
could not be accommodated; and the available options, if any, for
adjusting the operation of the Transmission Provider's system to
increase transfer capability to accommodate the transaction(s). The
Commission requested comments on what information about denials of
requests for service should be communicated on an OASIS (Question 7).
As with curtailments, only Union Electric out of the commenters who
answered this question opposed posting information about denials of
service on the OASIS or recording this information in an audit file.
Many commenters agreed that at least some basic information about
denials should be posted. Some commenters believed that these postings
should be available only to those denied service.\66\
---------------------------------------------------------------------------
\66\ See Allegheny and Central Illinois Public Service comments.
---------------------------------------------------------------------------
Service can be denied for two basic reasons: either (1) the
customer requested more than the posted ATC or (2) after the request
for service was made, conditions changed due to preexisting requests or
unforeseen events reducing capacity. Denials should be handled as part
of the request and response process. A requester should receive a
standardized reason for denial as part of the response. Denials would
not be posted. Instead, denials must be recorded for audit purposes and
maintained as provided in section 37.7(b). This data should contain the
information about a denial needed to explain the reason for a denial.
Under the final rules, customers have the right to request an
explanation of the standardized reason for a denial.
c. Transaction Anonymity (Sec. 37.6(e)(3)(i)). In the RIN NOPR, we
proposed that, generally, information concerning negotiations on
transmission requests need not be posted unless an agreement to provide
the transmission is reached.\67\ This information would be available
only after-the-fact in the audit file. In addition, if an agreement is
reached, the identity of parties to transmission transactions would be
masked until 30 days after the date when the Transmission Provider's
ATC was adjusted in response to the transaction. (This might be after
the date when service begins). After that date, all transaction data
would be made available. In addition, we proposed that transmission
transaction prices be included in the information in the audit file.
Price information concerning cost-based transmission services would not
be considered commercially sensitive.
---------------------------------------------------------------------------
\67\ See RIN NOPR text at section III.C (60 FR at 66191) and the
proposed regulation at 18 CFR 37.14(d) (60 FR 66201).
---------------------------------------------------------------------------
The Commission requested comment on what information should be
considered commercially sensitive, the 30-day release period proposal,
and on how and when commercially sensitive information should be
released to concerned parties before the standard release period and
whether affiliated transactions should be treated differently (Question
24).
Several commenters agreed that information about negotiations that
do not reach agreement should not be reported.\68\ No commenter argued
for making this information public.
---------------------------------------------------------------------------
\68\ See, e.g., Allegheny, Detroit Edison, El Paso, NorAm, and
OK Com comments.
---------------------------------------------------------------------------
A number of commenters supported the 30-day delay on providing
commercially sensitive information.\69\ Several, however, thought the
information should be provided as soon as possible.\70\ Others thought
it should be provided quarterly.\71\ WP&L proposed a 60-day delay.
Dayton P&L said that the delay should depend on contract length. Union
Electric suggested a delay of 30 days after the transaction begins and
not after the ATC is adjusted.
---------------------------------------------------------------------------
\69\ See Allegheny, CCEM, El Paso, Oklahoma G&E, PJM, PSNM, and
Western Group comments.
\70\ See APPA, Continental Power Exchange, MidAmerican Energy,
and NIEP comments.
\71\ See Arizona, ConEd, and NorAm comments.
---------------------------------------------------------------------------
Commenters split on the question of whether price data are
commercially sensitive.\72\ Commenters listed several items as
commercially sensitive that were proposed to be posted. These are ATC
supporting information,\73\ transmission schedule information,\74\
generation run status,\75\ amount provided,\76\ terms and
conditions,\77\ and duration.\78\
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\72\ EGA, NUCOR, NRECA, Omaha PPD, and PJM supported the
proposition that the data are not commercially sensitive. Arizona,
Central Illinois Public Service, Detroit Edison, OK Com, PSNM,
Seattle, and Western Group argued that the data are commercially
sensitive.
\73\ See Carolina P&L and El Paso comments.
\74\ See Central Illinois Public Service and OK Com comments.
\75\ See Allegheny, Carolina P&L, CSW, Detroit Edison, EGA, NE
Public Power District, and PJM comments.
\76\ See, e.g., Allegheny and WP&L comments.
\77\ See Central Illinois Public Service comments.
\78\ See Allegheny comments.
---------------------------------------------------------------------------
NE Public Power District argued for full disclosure of all but
generator information because, as a public entity, it must disclose
such information. NIEP stated that comparability should be the ruling
principle in information disclosure.
The final rule adopts the NOPR proposal and provides that the
identity of parties to an agreement are confidential during ongoing
negotiations and for 30 days from the time ATC is adjusted. Although
not explicitly required in the new Part 37, the price of services
offered on and
[[Page 21754]]
agreed to through the OASIS are not considered commercially
sensitive.79
---------------------------------------------------------------------------
\79\ We note, in this regard, that Sec. 205(c) of the FPA
requires public utilities to have their prices on file with the
Commission and available for public inspection.
---------------------------------------------------------------------------
6. Posting Facility Status Information
The RIN NOPR discussed the fact that the ATC of some transmission
paths depends on generator run status or megawatt output, or both, as
well as on other system elements.80 We proposed requiring
Transmission Providers to post information about those system elements
that have a direct and significant impact on ATC. Such elements could
include generators, transmission lines, phase shifters, series and
shunt capacitors, static VAR compensators, special protection systems
or remedial action schemes. We, therefore, requested comment on whether
it is sufficient to provide information only about planned outages and
(for both planned and forced outages) return dates for system elements
deemed to have a direct and significant impact on ATC and whether
posting this information would cause any confidentiality concerns
(Question 18). We also requested comment on how ``significant and
direct impact'' should be defined (Question 19).
---------------------------------------------------------------------------
\80\ See RIN NOPR text at section III.C (60 FR at 66191).
---------------------------------------------------------------------------
Additionally, we requested comment on whether it would be
sufficient to post the changes to ATC corresponding to the planned
outage or return dates of generators (Question 21); and whether, if
operating guides, nomograms, operating studies, and similar information
were posted, the run status of those generators with a significant and
direct impact on ATC could be deduced (Question 22).
Comments
A number of commenters stated that the posting of facility status
information should not be a requirement.81 These commenters
reasoned that the posted ATC and TTC values would reflect facility
status impacts and that posting status information therefore would be
unnecessary and burdensome, and would render the information network
unmanageable. With regard to generator status and outage information, a
number of respondents argued that generator status and outage-related
information is commercially sensitive and confidential.82 They
stated that posting generator-related information would give an unfair
advantage to competitors. Some opposing the posting of generation-
related information also added that the Commission's proposed standards
of conduct would make it unnecessary to post this information because
the Transmission Customer's and the Transmission Provider's wholesale
marketing functions would rely on the same information.83 A number
of Transmission Providers believed that facility status data can be
archived and made available for after-the-fact audits.84
---------------------------------------------------------------------------
\81\ See Allegheny, Central Illinois Public Service, Com Ed,
CSW, Dayton P&L, Detroit Edison, Duke, Montana Power, NERC, NYPP,
Ohio Edison, PJM, PSNM, Texas Utilities, VEPCO, and WP&L comments.
\82\ See Allegheny, Arizona, Central Illinois Public Service,
ConEd, Carolina P&L, CSW, Dayton P&L, Detroit Edison, Florida Power
Corp, NEPOOL, NE Public Power District, NERC, NYPP, Oklahoma G&E,
Omaha PPD, PJM, Texas Utilities, Union Electric, VEPCO, and WP&L
comments.
\83\ See Central Illinois Public Service, Carolina P&L, and Ohio
Edison comments.
\84\ See ConEd, CSW, Florida Power Corp, NYPP, Ohio Edison, and
PSNM comments.
---------------------------------------------------------------------------
A second group of commenters believed that facility status
information should be posted on the OASIS.85 With regard to
generator status and outage data, Seattle responded that planned
generator outage data should be updated as it changes and that an
explanation of the impact of typical outage configurations should be
made available to all transmission users in advance. APPA stated that
the run status (on-line or off-line) of any generating unit should not
be kept confidential. APPA argued that keeping such information
confidential, under the guise of competitive necessity, is an excuse to
protect opportunities to game the market. NCEMC stated that, because
the transmission user needs to be able to do a reliability and risk
assessment of various available power supply sources and transmission
paths, it probably is not sufficient to post ATC changes corresponding
to generation outages.
---------------------------------------------------------------------------
\85\ See APPA, CCEM, EGA, NCEMC, NIEP, OK Com, Seattle,
Tallahassee, and United Illuminating comments.
---------------------------------------------------------------------------
A third group of commenters suggested that, while generator status-
related information should not be posted, information about
transmission facilities with direct and significant impact on ATC and
TTC could be posted.86 There were diverging views among the
commenters as to whether posted ATC or TTC values would reveal the run
status of generators if operating guides, nomograms, operating studies,
and similar information were posted. A number of commenters responded
that ATC and TTC are affected by many variables and, even though in
some cases it may be possible to deduce the run status of certain
generators from the posted ATC or TTC, these deductions would be
uncertain.87
---------------------------------------------------------------------------
\86\ See Arizona, Dayton P&L, MidAmerican, NEPOOL, PJM, and
Western Group comments.
\87\ See Arizona, CCEM, Central Illinois Public Service, Com Ed,
ConEd, CSW, Detroit Edison, NEPOOL, NE Public Power District, VEPCO,
and WP&L comments.
---------------------------------------------------------------------------
NERC responded that it may be possible, over time, to recognize
patterns and supporting data that would indicate which generator went
off-line, but not whether the reason is a planned outage, forced
outage, reserve shutdown, or other reasons. NERC explained that a run
status so deduced would itself be an estimate and not as commercially
sensitive as knowing the reason for that status. Florida Power Corp and
Montana Power responded that customers will be able to deduce
generation-related information from changes in ATC if guides,
nomograms, or studies are posted and, therefore, such information
should not be posted.
By contrast, a number of commenters stated that nomograms, derating
tables, and operating studies can be used to identify equipment that
has a direct and significant impact on ATC and TTC. 88 The Western
Group responded that, where study results have been summarized in
nomograms, derating tables, and operating guidelines and procedures,
these summary forms should be made available as information on the
OASIS.
---------------------------------------------------------------------------
\88\ See APPA, Arizona, CCEM, Idaho, NEPOOL, Oklahoma Com,
Seattle, and SoCal Edison comments.
---------------------------------------------------------------------------
A number of respondents answered that it is not necessary to define
``significant and direct impact'' because ATC and TTC are the only
quantities that need to be posted. 89 ConEd stated that the
definition of ``significant'' should be consistent with local and
regional procedures. Duke and Florida Power Corp commented that the
Commission should work through NERC in developing appropriate
definitions. NYPP, on the other hand, stated that ``significant and
direct impact'' can be determined only on a case-by-case basis. Montana
Power defined the term as a reduction of ATC that results in the denial
of service. Continental Power Exchange proposed that any system element
affecting ATC more than 10 percent should be considered significant.
CSW proposed a 50 percent threshold. CSW further proposed to include
those elements that can cause a reduction of more than 25 percent of
the normal flows across an interface.
---------------------------------------------------------------------------
\89\ See Allegheny, Com Ed, Detroit Edison, NERC, NE Public
Power District, Ohio Edison, SCE&G, Texas Utilities, Union Electric,
and VEPCO comments.
---------------------------------------------------------------------------
[[Page 21755]]
Discussion
Additional information about the state of the transmission system
will enable Transmission Customers to make better decisions about the
quality of the transmission service they intend to purchase. However,
the development and implementation of Phase I OASIS, in what is a
relatively short period of time, requires that we limit the posting
requirements of the OASIS to the essentials. We believe that audit data
and information required to be provided about the reasons for
curtailments and interruptions will make it possible to document unduly
discriminatory practices concerning facilities critical to transmission
capability. Also, as pointed out by APPA, the standards of conduct that
we put in place with this rule lessen the urgency of posting additional
information concerning generating unit status and transmission
component status. Consequently, the Commission will not require the
posting of information about the run status of generation and
transmission facilities for a Phase I OASIS. We may reconsider this
subject for Phase II OASIS depending on the Phase I experience.
7. Posting Transmission Service Schedules Information (Sec. 37.6(f))
The final rule consolidates and renumbers Secs. 37.14(b) and (c) of
the RIN NOPR as Sec. 37.6(f). This provision requires information on
scheduled transmission service to be recorded by the entity scheduling
the transmission service and requires that the information be made
availab
FR Doc. 96-10693 Open Access Same-Time Information System (Formerly Real-Time Information Networks) and Standards of Conduct
le for download on the OASIS by interested parties. It also
provides that postings must be made within one week of the start of the
transmission service schedule agreed upon by the parties. The comments
in response to the RIN NOPR did not take issue with the proposal. Thus,
the provision is adopted without substantial revision.
8. Posting Other Transmission-Related Communications (Sec. 37.6(g))
Section 37.6(g) basically adopts what we proposed for the posting
of ``want ads'' and ``other communications'' in Sec. 37.9(f) of the RIN
NOPR. Postings made in this section carry no obligation to respond on
the part of any market participant.
This section provides that ``other communications related to
transmission services'' (such as using the OASIS as a transmission-
related conference space or to provide transmission-related messaging
services between OASIS users) and ``want ads'' must be posted by the
Responsible Party.
We received comments that urged the Commission to issue a
disclaimer to the effect that, although Transmission Providers are
responsible for posting other transmission-related communications at
the request of third parties, it is the responsibility of the third
parties requesting such postings to ensure the accuracy of the
information to be posted. We agree that such a disclaimer is
appropriate. We provide it in Sec. 37.6(g)(2).
In addition, the final rule requires that transfers of personnel
between the transmission and marketing functions are to be posted on
the OASIS (Sec. 37.6(g)(3)). This incorporates the requirements of the
standards of conduct at Sec. 37.4(b)(2).
I. Section 37.7--Auditing Transmission Service Information
In the RIN NOPR, we proposed procedures that would govern the
availability of records about auditing transmission service
transactions. 90 The Commission proposed requiring that historical
data on postings, updates, and request/response communications be
recorded for audit purposes, be downloadable from the OASIS in an
appropriate format for 60 days, and be available for download on a
rolling basis for three years from entry on the OASIS. These provisions
are now contained in Sec. 37.7 of the final rule. However, we have
increased the time during which audit data must be available for
download from 60 days to 90 days because this provides greater
protection to customers.
---------------------------------------------------------------------------
\90\ See RIN NOPR text at section III.C (60 FR at 66191) and the
proposed regulation at 18 CFR 37.14 (60 FR 66201).
---------------------------------------------------------------------------
ConEd suggested that the Commission should provide assurance to
Transmission Providers that they will not be liable if they post data
under the proposed audit provisions that is considered confidential by
their customers. We do not believe that it would be appropriate for the
Commission to issue this sort of blanket disclaimer in the absence of
any particular facts or controversy. However, to the extent that a
Transmission Provider posts data because this is required by the
Commission's regulations, the Transmission Provider may, of course,
assert this as a defense against any legal action brought against it
based on the disclosure.
J. Standards and Communication Protocols
In this section, we discuss the major issues raised in response to
our proposed standards and protocols. As proposed, these are being
issued in the separate Standards and Protocols document that we are
issuing together with this final rule. As already described, the final
rule states explicitly that information is to be posted on the OASIS in
conformance with the specifications of the Standards and Protocols.
The most recent How Report (filed on April 15, 1996) shows great
strides toward reaching consensus on a set of implementable standards.
However, it needs to be augmented in two ways.
First, there are some internal inconsistences. For example, there
are data elements that appear in the data dictionary that do not appear
in the templates and vice versa. The data elements for DUNS numbers
that appear in the data dictionary need to be added to the appropriate
templates. Data elements for DUNS numbers for resellers need to be
added to both the data dictionary and the appropriate templates. The
October 16, 1995 How Report contained standards for Transmission
Services Information Timing Requirements. The most recent report
substantially changed these requirements. We request that the report we
are asking the How Group to submit by May 28, 1996 reinstate these
requirements or explain why they should be changed.
Second, and not surprisingly, the standards and protocols must now
be conformed to the requirements of the final rule. For example,
necessary changes include developing file and display templates for
curtailments and interruptions, developing file and display templates
to place primary and resale capacity on the same displays and in the
same downloadable files, and developing file and display templates to
place ancillary services provided by the primary provider and others on
the same display page and in the same downloadable files.
Under procedures we are instituting today, we expect the
recommendations for standards and protocols to be conformed to the
requirements of the final rule and for inconsistencies to be corrected
in the next few months. We are issuing portions of the standards and
protocols now to provide as much information as possible to allow the
industry to begin the work of building necessary systems to make their
OASIS nodes operational. This information, coupled with the
requirements of the Open Access Final Rule and our additional
procedures to complete the Standards and Protocols, should result in
the OASIS nodes being operational
[[Page 21756]]
within six months of the publication of this final rule in the Federal
Register.
The April 15, 1996 How Report contains references to a yet to be
established industry group, the [OASIS] Management Organization, that
will maintain a registry of [OASIS] node names and perhaps perform
other functions associated with maintaining a functioning [OASIS]. We
agree that there is a need for an industry group to maintain a registry
of OASIS node names and perform similar functions and expect that such
a group will be established by the industry prior to the implementation
of the OASIS requirements. The Standards and Protocols, therefore,
contains a reference to this function. We expect that such a group
would be composed of representatives of all segments of the electric
industry and we expect to be apprised of the group's activities.
1. Summary of Standards and Communication Protocol Requirements
The Standards and Protocols, which we are adopting together with
this final rule, require Transmission Providers to make their OASIS
nodes accessible through the Internet. Each Responsible Party's OASIS
is considered to be a separate node. An OASIS operated jointly by
several utilities would be considered one node. By connecting each node
through the Internet, transmission service information provided by each
utility becomes part of a network.
We are requiring that nodes must support the use of Internet tools.
The specific tools are described in the Standards and Protocols. OASIS
users will access nodes using World Wide Web (WWW) browsers.91
Each node will display information using the Hypertext Mark-up Language
(HTML) protocol required by World Wide Web browsers. Screen displays
will consist of a series of pages that may be viewed by customers
without requiring the page to be downloaded and viewed by separate
software. The information on each page, but not the actual displays,
will be standardized. Information must also be made available for
downloading, in a standardized ASCII 92 format.
---------------------------------------------------------------------------
\91\ The World Wide Web is a system of computer resources that
are accessed through the Internet.
A Browser is a computer program for retrieving and reading
hypermedia documents from the WWW. A hypermedia document can contain
text, graphics, video, sound or data. These documents are often
linked to other documents.
\92\ ASCII refers to the American Standard Code for Information
Interchange, a code for character representation.
---------------------------------------------------------------------------
In Phase I, customers will have access to the information required
to be posted by this rule and will be able to use the OASIS to reserve
transmission capacity. They will be able to request capacity either by
completing a standardized form contained in an on-line HTML page or by
uploading a filled-out form using HTTP. Customers who want to resell
transmission capacity will upload (post) the relevant information to
the same OASIS node used by the primary provider from whom they
purchased the ATC. Customers will also be able to upload other
communications (e.g., Want Ads) containing such information as requests
to purchase transmission capacity.
OASIS nodes must provide direct connections to private networks if
requested to do so. The cost of the connections will be paid for by the
requestor and the networks are required to use Internet tools.
The Standards and Protocols contain a model of the information
requirements that must be provided at each OASIS node. Customers are
limited to obtaining information from HTML text displays and selecting
from menus of downloadable files. Customers will receive the
information either as HTML pages or as ASCII files in a predetermined
form and layout.
For security purposes, and as an aid in auditing performance and
transactions, all customers are required to register with the
Responsible Party before they are permitted access to the utility's
transmission service information on the OASIS. As registered
subscribers, they will be allowed to read and download information,
make requests for transmission service, place ``Want Ads'' and offer
transmission service for resale. Commission staff and staff of state
regulatory authorities are to obtain free ``read only'' access to the
OASIS and members of the general public will also be provided ``read
only'' access to the OASIS for the same usage fee paid by customers,
once they have complied with the requisite registration procedures.
Responsible Parties are required to meet a number of performance
standards and security precautions. Performance requirements include
sizing OASIS nodes to handle the loading of registered subscribers,
responding to subscriber requests, backing up the system, and other
areas that are necessary for the system to function as desired.
2. Number of OASIS Nodes (Question 35)
The Commission proposed that Transmission Providers be permitted to
combine their separate OASIS nodes into a single node. Thus, while
there could be as many nodes as there are transmission-owning
utilities, if utilities choose to combine together to create joint
nodes, we could end up with a small number of nodes.
A small number of nodes would minimize the networking management
requirements for the OASIS and would help ensure access to the
information systems. On the other hand, the advantages of a small
number of separate nodes must be weighed against the greater complexity
and size of a joint node that would handle transactions for several
large transmission-owning utilities at one node. The Commission
requested comments on whether a small or large number of OASIS nodes
should be encouraged.
The majority of commenters preferred a small number of nodes, but
would not necessarily have the Commission require a small number of
nodes.93 Some commenters advocated regional nodes.94 PJM
speculated that, even if the Commission does not encourage a small
number of nodes, economies of scale and market efficiencies will lead
to smaller numbers in the normal course of events. The How Group
reported that significant consolidation is already occurring:
\93\ See, e.g., Allegheny, Central Hudson, Central Illinois
Public Service, Com Ed, Continental Power Exchange, How Group,
Florida Power Corp, Montana Power, NERC, NYPP, Ohio Edison, OK Com,
PJM, PSNM, Seattle, Texas Utilities, and VEPCO comments.
\94\ See APPA, CCEM, ConEd, CSW, and MAPP comments.
---------------------------------------------------------------------------
it appears there may be 1 node in ERCOT, 13-14 nodes in the Eastern
Interconnection, and 6-20 nodes in the Western Interconnection. The
resulting 20-35 nodes [nationwide] is a manageable number for
Customers maneuvering through the system and at the same time
minimizes the impact of possible security breaches or system
failures by being sufficiently distributed.95
\95\ How Group comments at 19.
---------------------------------------------------------------------------
Given these comments, we believe that the question of whether there
should be a small number of nodes is one best left to the industry. At
this stage, flexibility in such matters is important.
3. Direct Connections to OASIS Nodes (Question 36)
The Commission explained in the RIN NOPR that private networks and
third party services can provide valuable contributions to the
successful operation of an OASIS.96 The Commission, therefore,
proposed to
[[Page 21757]]
require utilities to provide direct connections to the OASIS without
the need to obtain access through the Internet. We also proposed that
the cost of these connections be paid for by the customers making the
requests and that the networks be required to use the same Internet
tools as the Internet connections.
---------------------------------------------------------------------------
\96\ For example, a private network could connect to one or more
OASIS nodes and offer users off-the-Internet connections at faster
speeds. Third parties could gather OASIS information and repackage
it into customized displays favored by individual users.
---------------------------------------------------------------------------
Most commenters preferred that the Commission not require third-
party connections to the OASIS in Phase I.97 Com Ed asserted that
direct connections would provide only marginal benefits to the
development of an OASIS, and that adding such non-essential goals to
OASIS requirements would jeopardize utilities' ability to implement an
OASIS on time. Montana Power argued that direct connections would
provide affluent large marketers with information ahead of smaller
users, and thus would give them market power.
---------------------------------------------------------------------------
\97\ See, e.g., Allegheny, Com Ed, Montana, NERC, Ohio Edison,
OK Com, PJM, PSNM, and VEPCO comments.
---------------------------------------------------------------------------
On the other hand, other commenters argued that such connections
are important. ConEd argued that direct connections would help minimize
the number of different connections customers must have. Continental
Power Exchange sees direct connections as allowing third parties to
provide services that will add valuable contributions to the successful
operation of an OASIS. The How Group reported that discussions among
the parties in the group indicated that direct connections would not be
a problem as long as the Responsible Party is compensated for the
additional service and given a reasonable time to make the connection.
All commenters addressing the subject of who should pay for direct
connections agreed that the cost should be paid by the requesting
party.98
---------------------------------------------------------------------------
\98\ See APPA, CCEM, ConEd, Continental Power Exchange, How
Group, and PJM comments.
---------------------------------------------------------------------------
CCEM and OK Com agreed that the direct connections should be
required to use the Internet tools required for the Internet
connection.
Finally, APPA asserted that, if private networks are created to
provide direct connections that are operated by partners or affiliates
of utilities, these networks could provide significant performance
advantages for the Transmission Provider's merchant affiliates. APPA
would require full public disclosure of such partnership or affiliate
relationships by the service provider.
We find that the How Group's position is reasonable. Direct
connections are feasible if the provider is compensated for the
additional service and is given a reasonable time to make the
connection. We will, therefore, require direct connections in Phase I,
upon request.
Moreover, such connections must be made available on an equal basis
to all requesting customers. We note, however, that to the extent that
the Transmission Provider is not the Responsible Party, a direct
connection is available only from the Responsible Party. This being the
case, APPA's concern that the Transmission Provider's merchant services
may gain an advantage from an affiliate with a direct connection or
private network does not appear to be warranted, as anyone can obtain a
direct connection or the services of a private network.
4. Value-Added OASIS Services Provided by Transmission Providers or
Responsible Parties
The Commission proposed in the RIN NOPR to permit Transmission
Providers or Responsible Parties to provide value-added OASIS services,
such as higher speed connections and automatic notification of changed
data.
NTEC argued that, unless these services are offered on a non-
discriminatory basis, public utilities could gain a competitive
advantage by offering these services solely to affiliates. NTEC also
requested the Commission to monitor the ``basic'' and ``premium''
service packages to ensure that customers need not pay a ``premium''
price to obtain basic services.
TAPS argued against any offering of value-added services. They
argued that smaller customers may not be able to afford such services
and that price could be used to discriminate against them. TAPS
proposed that instead of permitting value-added services, the
Commission should include all OASIS costs in transmission rates.
We agree with NTEC that value-added OASIS services should be
offered on a non-discriminatory basis. If a value-added service is
offered to anyone, it should be offered to everyone on the same terms
and conditions. Regarding NTEC's concern over basic and premium
services, we believe that the standards setting process will ensure
that the basic package of OASIS services will provide all pertinent
information and the means to retrieve it that are necessary for the
functioning of the Open Access program.
The Commission will allow these services on a non-discriminatory
basis. Such services will remain cost-based until the Commission is
satisfied that market-based (value added) rates should be allowed for
such services. Requests for market-based rates for such services will
be addressed on a case-by-case basis.
5. Transmission Services Information Timing Requirements (Question 37)
In the NOPR, the Commission requested comments on several timing
requirements for posting transmission service information. These are:
(1) Transmission Service Information Availability: The most recent
Provider transmission service information, including updates reflecting
power system changes, shall be available to all Customers within 5
minutes of its scheduled posting time at least 98 percent of the time.
The remaining 2 percent of the time the transmission service
information shall be available within 10 minutes of its scheduled
posting time;
(2) Notification of Posted or Changed Transmission Service
Information: Notification of transmission service information posted or
changed by a Provider shall be made available within 60 seconds to all
subscribed Customers who are currently connected; and
(3) Acknowledgment by the Transmission Service Information
Provider: Acknowledgment by the transmission service information
provider of the receipt of Customer purchase request/response requests
shall occur within 1 minute for Phase I. The actual negotiations and
agreements on purchase request/response requests do not have time
constraints. For Phase II, acknowledgment shall occur within 30
seconds.
Most commenters supported the Commission's proposals as proposed
99 or with some modification.100 CCEM asserted that the
proposed requirements for updating transmission service information
contained in Item (1) would lead to stale information, and would result
in customers using the telephone and not the OASIS. CCEM asserted that
the Phase I tolerances should be reduced to 30 seconds and one minute
respectively.
---------------------------------------------------------------------------
\99\ See, e.g., APPA, Duke, How Group, Florida Power Corp, NYPP,
and OK Com comments.
\100\ See CCEM, Com Ed, Continental Power Exchange, PSNM, and
Western Group comments.
---------------------------------------------------------------------------
Continental Power Exchange asserted that items (1) and (2) are good
starting points. The Western Group suggested that Item (1) would be
adequate if it can be accomplished automatically. Otherwise, it would
recommend reducing the 98 percent compliance requirement to 85 percent.
Some commenters agreed with the need for such standards, but
opposed
[[Page 21758]]
incorporating timing performance standards in Phase I standards. VEPCO
asserted that these standards are too ambitious for Phase I.
Tallahassee argued that these timing requirements may be too
restrictive for small utilities whose staff and technology capabilities
will be strained by this rule. Central Hudson proposed that response
times be determined after OASIS is implemented and users are
comfortable with what they would expect as adequate performance.
Most commenters agreed on the need for standards for how quickly
providers should post transmission service information. Commenters
argued that the requirements should be stricter, that they are too
strict, or that they are just right.
The Commission stated that information posting performance
requirements are needed to ensure that information is disseminated in a
timely manner by Transmission Providers. The comments do not persuade
us to change the proposed requirements. We note that the April 15, 1996
How Report drops these requirements. We request the How Group to
reinstate these requirements in the report we are inviting them to file
on or before May 28, 1996, or to explain why these requirements should
be dropped.
Commenters raise several additional points that need to be
addressed. First, Com Ed and others argued that these requirements
should not be in force during emergencies. The Commission agrees.
Second, several commenters pointed out that the phrase ``available
to all Customers'' contained in Item (1) is ambiguous and request that
it should be replaced by ``available on the [OASIS].'' We agree.
Third, some commenters suggested that transmission service requests
and schedules be approved automatically, on a first come, first served
basis. The industry does not generally do business in this manner
today, and the Commission will not require it in Phase I. We request
the industry to address this issue when developing requirements for
Phase II.
6. Common Codes
a. Company Codes
The Commission's experience with implementing standards for file
transfers and electronic bulletin boards in the natural gas industry
shows that the use of a common system of identifying companies enhances
the efficiency of data transfers. The Commission is satisfied with the
results of using DUNS numbers 101 as the standard to uniquely
identify pipelines and shippers in the natural gas
transactions.102 The Commission proposed to require the use of
DUNS numbers to identify transmission-owning utilities and customers on
OASIS nodes.
---------------------------------------------------------------------------
\101\ DUNS numbers refer to the Data Universal Numbering System,
maintained by Dun and Bradstreet.
\102\ See Standards for Electronic Bulletin Boards Required
Under Part 284 of the Commission's Regulations, Docket No. RM93-4-
001, Order 563-A, FERC Stats. & Regs., Regulations Preambles, para.
30,994 at 31,034 (1994).
---------------------------------------------------------------------------
Most commenters believed that DUNS numbers alone or DUNS numbers in
combination with names should be used.103 The How Group asserted
that using DUNS numbers will enhance the management of data from a
computer perspective and allow flexibility of business applications of
OASIS in the future. The How Group also asserted that having commonly
used names is more user friendly and proposed that the list of names
and DUNs numbers be maintained on a centralized registry.
---------------------------------------------------------------------------
\103\ See, e.g., Allegheny, CCEM, Com Ed, Continental Power
Exchange, How Group, OK Com, and PJM comments.
---------------------------------------------------------------------------
Others believed that names alone would be sufficient.104 NERC
and Ohio Edison believed that such standardization should be left to
the industry.
---------------------------------------------------------------------------
\104\ See Seattle, VEPCO, and Western Group comments.
---------------------------------------------------------------------------
APPA asserted that DUNS numbers are primarily for private companies
and do not include many public power systems. Instead of using DUNS
numbers, APPA recommended using a numbering system derived from Energy
Information Administration forms: EIA-861 (``Annual Electric Utility
Report'') and EIA-867 (``Annual Nonutility Power Producer Report'') as
these forms appear to be the most all-encompassing existing numbering
system that could be used for OASIS identification. Dun and Bradstreet
have informed staff that they will assign DUNS numbers, free of charge,
to any entity requesting a number.
The Commission will require the DUNS numbers as the unique
numerical identification of OASIS participants. The industry can
proceed to develop a naming convention as suggested in the comments.
b. Common Location Codes
The Commission's experience in the natural gas industry
demonstrates that a common method of uniquely identifying location
points will be needed to facilitate movement of power across the grid.
The Commission proposed to use a system to identify locations and paths
on the electric transmission grid.
Nearly all commenters who discussed the issue argued that the
Commission should not require common location codes.\105\ Several
commenters argued that providing longitude and latitude information for
power plants and substations raises serious national security
issues.\106\
---------------------------------------------------------------------------
\105\ See Allegheny, APPA, CCEM, Continental Power Exchange,
Duke, How Group, ERCOT, Florida Power Corp, NERC, PJM, VEPCO, and
Western Group comments.
\106\ See How Group, FPC, and NERC comments.
---------------------------------------------------------------------------
Many commenters see the need for a common naming convention for
paths and other facilities, such as that currently under development by
the How Working Group.\107\
---------------------------------------------------------------------------
\107\ See How Group, PSNM, and Western Group comments.
---------------------------------------------------------------------------
The Commission is persuaded to drop the requirement for a system
for location codes and requests the industry to continue development of
a common naming convention to be implemented as soon as practicable.
7. Data Definitions and File Formats Not Covered by the Revised How
Report
a. Offers to Provide Ancillary Services Provided by an Entity Other
Than the Transmission Provider (Question 11)
In the RIN NOPR, the Commission requested the specifications needed
to post this information in HTML displays and the formats needed to
standardize uploadable and downloadable files containing this
information. This final rule requires that information about ancillary
services provided by an entity other than the Transmission Provider be
posted on the OASIS by Responsible Parties and be displayed on the same
page and in the same file format as that of the Transmission Provider.
Although we did receive comments on this issue from various
parties, this was not an issue resolved by the revised How Report. We
would prefer that the How Group attempt to reach consensus on this
issue before we impose our own solution. Therefore, we will include
this issue among those that we are requesting further input on before
we address this issue in the Standards and Protocols.
b. Offering of Primary and Secondary Capacity
The Commission requested comments on how to redesign the download
templates in Appendix C of the NOPR so that primary and secondary
capacity can be offered through downloadable files that have the same
format. The Commission also requested comments on how primary and
secondary capacity
[[Page 21759]]
can be displayed in the same tables on an OASIS node. Posting secondary
capacity requires more information than for primary capacity and, thus,
using the same formats would require many more fields. We need
information on the design of those fields before we can set standards
for the display of this information.
Although we did receive comments on this issue from various
parties, this was not an issue resolved by the revised How Report. We
would prefer that the How Group attempt to reach consensus on this
issue before we impose our own solution. Therefore, we will include
this issue among those that we are requesting further comment on before
we address this issue in the Standards and Protocols.
8. Formats for Downloadable Files Not Covered in the How Report
a. Standard Format for Data Used in Calculating ATC (Question 16)
The Commission requested comments on how the data used in
calculating ATC should be formatted and asked whether the information
should be in free form text, predefined tables, or comma delimited
ASCII files. We also asked whether, if the information is in free form
text, it should be in plain ASCII text or in a word processor format,
such as WordPerfect or Word. We deal with both of these issues in
section H(2)(f) of this final rule and in the regulations at
Sec. 37.6(b)(2)(ii).
b. Standard Formats for Transmission Studies (Question 23)
The Commission requested comments on how transmission studies
should be formatted for download from the OASIS. We deal with this
issue in section H(2)(g) of this final rule and in the regulations at
Sec. 37.6(b)(2)(iii).
c. Standard Format for Electronic Submission to the Commission of
Transmission Tariffs (Question 6)
In the RIN NOPR, the Commission proposed requiring that
Transmission Providers provide downloadable files of their complete
tariffs on the OASIS.\108\ The Commission requested that commenters
propose a standard format for electronic submission of transmission
tariffs to the Commission.
---------------------------------------------------------------------------
\108\ See RIN NOPR text at section III.C (60 FR at 66186) and
the proposed regulation at 18 CFR 37.9(c)(1) (60 FR 66200).
---------------------------------------------------------------------------
New formats continually are being developed by the computer
industry and it would be worthwhile to address this issue again when
the Commission addresses Phase II or remaining OASIS issues.
We will require utilities to provide tariff downloads from their
OASIS in the same format that they use to file with the Commission.
9. Communication Protocol Issues
a. Internet Browsers
There are a large number of Internet browsers available
commercially and in the public domain. The How Report proposed that
browsers support ``at least'' HTML version 3 and ``optionally'' support
Secure Sockets Layer. The HTML standards used by browsers change from
time to time, and, in addition, various browsers can support different
extensions to the standards. The Commission does not want to stifle
innovation, but at the same time it does want uniformity on the OASIS.
The Commission does not want customers to be forced to use different
browsers for different OASIS nodes. The Commission wants to ensure that
a customer will be able to choose a browser and use it to access all
OASIS nodes.
To this end, the Commission requested comments on how to ensure
that a customer will be able to choose a browser and use it to access
all OASIS nodes.
Most commenters agreed that requiring browsers to support HTML 3
would be sufficient to meet the needs of OASIS nodes and customers at
this time.\109\
---------------------------------------------------------------------------
\109\ See, e.g., Allegheny, APPA, CCEM, and How Group comments.
---------------------------------------------------------------------------
CSW reported that while the specifications for HTML 3 are still in
draft mode, it is the first version of HTML to support the table
feature for browsing that the How Working Group wants to use. NYPP
would add encryption capabilities to the list of standards. Ohio Edison
would require JAVA-enabled browsers.\110\
---------------------------------------------------------------------------
\110\ JAVA is a language that enables a browser to run programs
embedded in a WWW page.
---------------------------------------------------------------------------
OK Com recommended that the Commission adopt a primary browser and
two alternative browsers for use on OASIS nodes. PJM asserted that, by
requiring OASIS nodes to accommodate browsers in common use, OASIS
nodes would be able to become more sophisticated as the Internet itself
becomes more sophisticated.
Com Ed, ConEd and PSNM would leave the standard to the How Group or
an industry-wide OASIS Management Organization.
Most commenters agreed with the How Report that, requiring OASIS
nodes to support HTML 3 will allow browsers supporting this standard to
view documents on the OASIS. The Commission will adopt the
recommendation for HTML 3 contained in the How Report.
b. Bandwidth of Node Connections to the Internet
At issue is the speed at which OASIS users will receive information
from OASIS nodes. A major determinant of the speed are the bandwidth
connections between the OASIS node and the Internet. The How Report
proposed a formula to compute the required minimum bandwidth based on
the number of registered users of the node and the number of bits per
second to be received by users during HTML displays and downloads of
files.\111\ These information transfers would include both the receipt
of HTML displays and downloads of files. The How Report proposed to use
a rate of 8,000 bits per second to determine bandwidth. In the RIN
NOPR, the Commission noted that an 8,000 bit per second transfer rate
is a much slower rate than the 28,800 bit per second transfer rate for
telephone connections that many private individuals and customers use
to connect to the Internet. The Commission expressed concern that using
8,000 bit per second as the basis for the bandwidth calculation will
lead to connections that are too slow and proposed to use 28,800 bits
per second.
---------------------------------------------------------------------------
\111\ How Report at Sec. 3.4.3.
---------------------------------------------------------------------------
Many commenters agreed with the Commission.\112\ Com Ed reported
that a T1 communications line (1.54 million bits per second) could
support 500 simultaneous customers using the Commission's proposal of
using 28,800 bits per second in the bandwidth formula. Com Ed concluded
that it is unlikely that an OASIS node will experience 500 simultaneous
users and that a T1 line is a reasonable upper limit, at this time. The
How Group reported that its members are currently paying between $1,500
and $3,000 per month for T1 connections and concludes that it may be
cost effective to oversize the bandwidth even though a high bandwidth
does not automatically translate into higher access speeds or download
rates.
---------------------------------------------------------------------------
\112\ See, e.g., Allegheny, APPA, CSW, OK Com, PJM, and Seattle
comments.
---------------------------------------------------------------------------
Several commenters preferred the 8,000 bits per second originally
proposed by the How Group.\113\ Ohio Edison suggested that using a
speed of 28,800 will dramatically increase costs and may make joint
OASIS nodes less attractive. The How Group asserted that experience has
shown that 8,000 bits per second is a reasonable average rate
[[Page 21760]]
for users of the Internet. VEPCO stated that, while many customers will
initially use modems rated at 28,800 bits per second, their average
data transfer rate will be lower due to a number of factors.
Nevertheless, VEPCO asserted that an average of 8,000 bits per second
is on the low end of acceptability, especially if large files are to be
downloaded or if graphics files are to be viewed. Continental Power
Exchange proposed that the 19,200 bits per second be used in the
formula. It asserted that this is the fastest modem speed achievable
with Microsoft's Windows 3.1.
---------------------------------------------------------------------------
\113\ See ConEd, How Group, and Ohio Edison comments.
---------------------------------------------------------------------------
APPA speculated that there may some areas in remote locations that
cannot secure a connection to the Internet with adequate bandwidth to
support the 28,800 bit per second standard.
After considering the comments, the Commission continues to believe
that 8,000 bits per second is too slow, especially when large files
must be transferred and when information is needed promptly for
business decisions. The Commission, therefore, will require that a rate
of 28,800 bits per second be used in the minimum bandwidth calculation.
c. Data Compression Standards
In the RIN NOPR, the Commission expressed agreement with the How
Report that data compression will speed up the transmission of
files.114 We also expressed the belief that communication of OASIS
information would be enhanced if every OASIS node used the same
compression techniques. The Commission requested comments on what data
compression technique or techniques should be made standard for all
OASIS nodes.
---------------------------------------------------------------------------
\114\ How Report Sec. 3.3.8(c).
---------------------------------------------------------------------------
Most commenters recommended that the ``ZIP'' file compression
standard be adopted as the common OASIS standard.115 The How Group
pointed out that the ZIP format is available for most computer
platforms. Some commenters, however, suggested that setting a common
compression technique is too detailed for a Commission
rulemaking.116
---------------------------------------------------------------------------
\115\ See APPA, CCEM, ConEd, and PSNM comments.
\116\ See NERC and Ohio Edison comments.
---------------------------------------------------------------------------
Most commenters supported using the ``ZIP'' file compression
standard on OASIS. This format is widely used for data communication
and the necessary software is available for most computer platforms.
The Commission will, therefore, require that the ZIP standard be the
data compression standard on OASIS nodes. The Commission agrees that
requiring compression for files created for each HTTP request may be
too complex for Phase I. However, utilities may want to compress large
files that would be infrequently updated, such as tariffs. These files
will benefit from file compression and will not be subject to the
complexities of compressing the dynamically created HTTP files. The
Commission will require that static files residing on OASIS nodes be
compressed.
d. Other Communication Protocol Issues Raised by Commenters
i. The Requirement to Use FTP for File Transfers
The October 16, 1995 How Report recommended requiring OASIS nodes
to use the Internet File Transfer Protocol (FTP) for file uploads and
downloads. In its comments, the How Group recommended changing the file
transfer method originally proposed in the How Report from the FTP to
the HTTP for data access, including files upload and download to and
from OASIS nodes. We will accept this recommendation.
ii. Field Size for Path Names
The How Report proposed that path names be a 12-character
alphanumeric string. The March 7, 1996 filing by its How Group
recommends that the 12 characters be changed to 50 alphanumeric
characters. Subsequent to the How Report, the How Group found that 12
characters were insufficient to accommodate path names and the
associated regional identifiers.
We will await final recommendations concerning file formats before
ruling on this issue.
iii. Files Containing More Than 100,000 Bytes
The How Report recommended that customers not be required to
download any single file that is larger than 100,000 bytes in order to
access transmission information in electronic form. The implication is
that all files larger than 100,000 bytes must be broken into sub-files.
Detroit Edison argued that there is no easy way to download only a
section of a file and that customers may prefer to download one large
file rather than 20 small ones.
We agree and will not require files to be broken into 100,000 byte
segments at this time. In the event that a restriction on file size
becomes needed, it can be addressed in Phase II.
K. Cost Recovery Issues
1. Costs of Developing and Running an OASIS (Question 34)
Transmission-owning public utilities are entitled to recover the
costs of developing and running an OASIS. Generally, these costs will
be fixed costs not attributable to individual users. In the NOPR, the
Commission proposed to include these costs in wholesale transmission
rates. The Commission also proposed to allow costs that can be
identified as varying with usage to be charged as usage fees to
individual customers.
The commenters were nearly evenly split between those favoring and
opposing the Commission's proposals. NIEP argued that rolling-in OASIS
costs would distribute costs among all transmission users equally and
would be the only fair method of allocating the cost of an OASIS. NIEP
concludes that, if costs were directly assigned to individual
transmission users, these users would be penalized by forcing them to
pay the cost of providing information which is available to, and used
by, all transmission users.
Many commenters objected to including OASIS costs in wholesale
transmission rates. They argued that it is inappropriate to require
network service customers (who may not participate in wholesale sales
transactions) to absorb the cost of the OASIS. Indianapolis P&L claimed
that it has no significant, unique transmission paths and uses its
transmission assets to serve its native load customers. Consequently,
most of its OASIS costs would be borne by its native load customers.
Many commenters suggested alternatives to rolling in OASIS costs.
ConEd argued that, if all OASIS costs were included in wholesale
transmission rates, OASIS costs might not be fully recovered since
transmission use varies. To remedy this, ConEd proposed rolling in part
of the costs with the remainder to be recovered through a monthly
access fee. MAPP suggested usage fees based on cost causation, such as
time access charges, fixed fees for transmission requests and fees
based on energy scheduled over transmission secured on the OASIS. NSP
suggested a fee structure like other on-line information services, such
as America On Line, CompuServe, and Prodigy.
Several commenters saw other problems associated with utility
recovery of OASIS costs. Some called attention to potential problems in
recovering the costs of a joint OASIS. MAPP pointed out that a jointly
[[Page 21761]]
operated OASIS will not have composite transmission tariffs from which
to recover costs and that a method was needed for utilities to recover
joint expenses.
Detroit Edison speculated that a large number of the general public
could be connected to an OASIS at one time and thus limit OASIS access
to transmission users. To prevent this problem, Detroit Edison proposed
that fees be established to prevent misuse or overuse of an OASIS.
It is appropriate that all wholesale transmission customers and all
unbundled retail transmission customers should pay a share of OASIS
development costs in their rates. Therefore, the Commission concludes
that the cost of developing an OASIS should be included in unbundled
transmission rates with variable costs of operating an OASIS to be
recovered, to the extent possible, in usage fees. Individual rate
proceedings will determine which OASIS costs can be identified as
varying with usage and how to set the fees.
2. Costs of Posting Resales of Capacity on the OASIS (Question 40)
The Commission proposed that resales of capacity be posted on the
same page, and using the same display and downloadable tables, as
capacity being sold by the Transmission Provider. This posting incurs
an expense on the part of the Responsible Party. The Commission
proposed that each reseller must, therefore, pay the costs of posting
its own offering.
Most commenters believed that those posting secondary services
should pay the cost of posting. APPA proposed that the incremental cost
of posting should be recovered as a special fee in the primary contract
of transmission service. Ohio Edison proposed a fee for each posting
with a ``true up'' mechanism to ensure that over time actual costs are
recovered. Com Ed and WP&L suggested a fee that is a percentage of
revenue received from the secondary postings.
NEPOOL suggested that this expense is unlikely to be significant
and, therefore, could be included in rates. NRECA and NCEMC warned that
posting fees not be set so high as to discourage resale of capacity. OK
Com argued that it would be inappropriate to charge resellers of
transmission capacity for posting if the Transmission Provider is not
also required to pay a fee for posting.
After considering the comments, we have decided that there should
be no added fee for posting capacity resales. All OASIS users,
including the Transmission Provider, who post capacity pay all the
fixed costs of OASIS in wholesale rates and pay usage-related variable
costs in access fees. Thus, the costs of posting resale capacity are
already recovered. To require resellers to pay additional fees for
posting their products would provide OASIS operators with a cost
advantage.
3. Costs of Posting Ancillary Services on the OASIS
The Commission proposed that entities posting offers to provide
ancillary services on the OASIS should pay the costs associated with
posting this information and requested comments on how to determine
these costs.
Commenters proposed various fee schemes to recover these costs.
Some were based on the cost of developing and maintaining posting
services, others were based solely on the incremental cost of posting a
notice. Some proposed to roll the costs into wholesale transmission
rates. Others proposed that utilities be allowed make a profit from
this service.
Arizona proposed an incentive scheme to keep costs down, while
Continental Power Exchange suggested that the method of calculating
these costs be left to the industry. PJM proposed a fee based on the
amount of person-hours and computer usage required by such posting.
ConEd argued that utilities should be allowed to earn a profit on this
service.
CSW submitted that posting costs cannot be broken out individually
and proposed that the costs for an OASIS should be borne by all market
participants on a fair basis. Florida Power Corp argued that an OASIS
is not a newspaper, and that Transmission Providers are not in the
publishing business; therefore, OASIS services, including the posting
of ancillary services, should not be sold like classified ads. It
proposed that the cost of operating an OASIS should be rolled into
wholesale transmission rates. VEPCO also suggested that the cost of
posting ancillary services should be included in the cost of the OASIS,
with costs of specific evaluations of ancillary service offers to be
determined and posted on the OASIS.
After assessing the comments, we find that the cost of developing
the facilities needed to post ancillary services required to be
provided by the Open Access Final Rule should be recovered through
unbundled transmission rates. Any variable costs of posting these
services will be included in the general OASIS usage fees. As for those
ancillary services not required to be provided,117 OASIS operators
may charge a cost based fee to those offering these services for the
cost of posting.
---------------------------------------------------------------------------
\117\ See Open Access Final Rule generally at section IV.D.
---------------------------------------------------------------------------
L. Section 37.8--Implementation in Phases
1. Phase I Implementation
Implementation of this rule and the initial standards and protocols
will ensure that sufficient information is available to transmission
customers to achieve comparable access to transmission information.
They do not, however, provide all the desired performance requirements.
Because of the complexity of developing an OASIS, and the need to
begin the transmission open access program promptly, the Commission
proposed a phased approach to OASIS implementation. We proposed to
require implementation of a Phase I OASIS as of the effective date of
the final rule on non-discriminatory open access transmission and
stranded costs (i.e., 60 days from publication of this order in the
Federal Register).
Comments
Many commenters argued that the proposed 60-day implementation
period is unrealistic in light of the amount of work that must be done.
ERCOT suggested that only portions of the Phase I implementation could
be accomplished within the 60-day period. A vast majority of commenters
suggested that an implementation period of six months would be
required.
Arizona and ConEd pointed out that, while plans for implementation
can begin in advance of the final rule, final specifications and
designs depend on the resolution of several major Open Access Final
Rule issues. ConEd also argued that all new systems require a ``Beta''
test stage in which the system can be tested before it is used in a
production environment, and that a 60-day implementation period will
not permit such testing. Similarly, NERC argued that more time is
needed to make sure workable administrative procedures are in place for
consistency in calculating, posting, and coordinating ATC. NEPOOL
echoed these comments, reporting that an implementation period of less
than six months would result in the development of OASIS nodes across
the nation that lack uniformity as each region complies within a short
deadline without time to coordinate with other areas.
Duke argued that a full six months will be needed because, in
addition to
[[Page 21762]]
the difficult task of implementing OASIS, the Open Access Final Rule
will change the way the industry does business. Duke argued that the
coordination of resources necessary to accommodate all of the
discussions and decisions in developing joint OASIS nodes is a more
lengthy process than development of an OASIS by each individual
company. Duke asserted that a six-month implementation period is needed
to permit joint OASIS projects to develop. 118
---------------------------------------------------------------------------
\118\ NERC made this same point in its comments.
---------------------------------------------------------------------------
SoCal Edison requested that the Commission delay implementation
until the requirements of the CA Com's California Restructuring Order
have been fully identified. Public Generating Pool argued that the
Northwest governors have organized a review of the Northwest Power Act,
the Bonneville Power Act, and the northwest electric system in general,
to be completed by November 1996. Public Generating Pool argued that
the Commission should consider possible contributions to be made by
this forthcoming report and urged that the Commission not ignore this
work based on a need to meet self-imposed unreasonable and unrealistic
OASIS implementation dates.
The How Group, the Western Group and VEPCO suggested that, if the
Commission cannot extend the implementation period to six months, then
Phase I should itself be implemented in stages. The How Group suggested
a three-stage process that would begin with a requirement for primary
providers, within 120 days after issuance of the final rule, to post
estimates of ATC and secondary capacity for resale that might not be
accurate. This would be followed, within 180 days after issuance of the
final rule, by the posting of fully accurate secondary capacity
information and ATC information, and with Transmission Providers
certifying, within 210 days of the final rule, that all functionality
and performance requirements for OASIS have been met.
ConEd and Carolina P&L noted that OASIS implementation will cause
changes to utility operations, and requested that the Commission
schedule implementation during off-peak seasons, such as the spring or
fall, when they claim transmission systems are under less stress.
Public Generating Pool and Tallahassee speculated that, if
publicly-owned utilities are considered to be under the Commission's
jurisdiction for OASIS purposes, they will need more than a six-month
implementation period because they may be required to obtain funding
approval from state or local oversight commissions.
Discussion
Commenters make persuasive arguments for permitting a six-month
implementation period. They raise concerns that a shorter period will
not permit adequate time to design, build and thoroughly test an OASIS.
They also raise concerns that a shorter period will inhibit the
development of joint OASIS and OASIS with a common look and feel. The
Commission shares these concerns. We also want to take into account
commenters' requests that implementation not be required during the
peak winter or summer months. For this reason, we are requiring
compliance by November 1, 1996, a specific date about six months from
when we expect this final rule to become effective, chosen to avoid the
winter and summer peak months. This date is provided in Sec. 37.8 of
the final rule, which modifies the provision originally set out in
Sec. 37.15 of the RIN NOPR.
In addition, we will provide additional procedures to allow the
development of the remaining initial standards and protocols. As
described above, we invite the How Group to report to us on or before
May 28, 1996 on these issues (and to attach any comments it has
received from any interested person with opposing views).
For these reasons, the Commission will require implementation of
Phase I of OASIS to be operational by November 1, 1996.
2. Phase II Implementation
Once Phase I becomes operational, and the industry and public gain
experience with it, the full information and functional requirements
needed to support open access transmission service will become clearer.
In the RIN NOPR, the Commission stated that it envisioned that Phase II
would build on Phase I and requested that the industry continue the
process of developing standards, and provide a consensus report to the
Commission on Phase II recommendations by January 1, 1997.
Most commenters argued that the proposed January 1997 date is too
ambitious. Southern argued that this date does not provide enough time
for the industry to gain experience with Phase I. Tallahassee and
others suggested that Phase II should not be implemented until at least
one year after Phase I is implemented. Continental Power Exchange
asserted that Phase II will be a continuum of development from the
first day of Phase I implementation. NRECA suggested that, if Phase I
turns out to be inadequate, then Phase II should be accelerated.
We are sensitive to commenters' concerns about the time between the
implementation of Phase I and Phase II. At the same time, the need for
the additional functions and performance requirements proposed for
Phase II will, we believe, need to be implemented quickly. Accordingly,
the industry should continue the process of developing standards, and
attempt to develop a consensus report on Phase II recommendations by no
later than seven months after implementation of Phase I June 4, 1997.
We anticipate that this report would be the basis for supplemental
OASIS proceedings to Phase II OASIS requirements. The additional time
should permit the industry to obtain sufficient experience with Phase I
before it recommends specifications for Phase II.
We believe that it may be appropriate to require the scheduling of
energy transfers on the OASIS in Phase II. Electronic scheduling of
energy transfers over the OASIS would increase efficiency. We,
therefore, request that the industry incorporate standards for the
scheduling of energy transfers on OASIS into the Phase II report.
IV. Regulatory Flexibility Act
The Regulatory Flexibility Act (RFA) 119 requires the
Commission to describe the impact that any proposed or final rule would
have on small entities or to certify that the rule, if promulgated,
will not have a significant economic impact on a substantial number of
small entities. The entities that would have to comply with the final
rule are public utilities and transmitting utilities that do not fall
within the RFA's definition of small entities.120 Therefore, under
section 605(b) of the RFA, the Commission hereby certifies that this
final rule will not have a significant economic impact on small
entities within the meaning of the RFA. Accordingly, no regulatory
[[Page 21763]]
flexibility analysis is required pursuant to section 603 of the RFA.
---------------------------------------------------------------------------
\119\ 5 U.S.C. Secs. 601-612.
\120\ See 5 U.S.C. Secs. 601(3) and 601(6) and 15 U.S.C.
Sec. 632(a). The RFA defines a small entity as one that is
independently owned and not dominant in its field of operation. See
15 U.S.C. Sec. 632(a). In addition, the Small Business
Administration defines a small electric utility as one that disposes
of 4 million MWh or less of electric energy in a given year. See 13
CFR 121.601 (Major Group 49-Electric, Gas and Sanitary Services)
(1995).
In the Open Access Final Rule, issued contemporaneously with
this final rule, we conclude that, under these definitions, the Open
Access Final Rule would not have a significant economic impact on a
significant number of small entities. As this final rule only
implements the OASIS requirements of the Open Access Final Rule, the
same conclusion is warranted here, for the same reasons.
---------------------------------------------------------------------------
In its comments, NRECA questioned the Commission's conclusion that
the RIN NOPR did not need to be accompanied by an RFA analysis. NRECA's
argument was based on its concern that the Commission might extend
OASIS requirements to non-public, not-for-profit cooperative utilities.
NRECA argued that, if this were to happen, the Commission would then
have to analyze the effect of the OASIS requirements on these utilities
and show that the requirements would not have a substantial economic
impact upon them. However, as proposed in the RIN NOPR, the
Commission's OASIS regulations will apply only to public utilities that
own, operate, or control transmission facilities subject to the
Commission's jurisdiction. As noted immediately above, public utilities
do not fall within the RFA's definition of a ``small entity.'' In
addition, as discussed earlier, and as discussed in the Open Access
Final Rule, there will be a provision for a waiver for small entities.
This responds to NRECA's concerns.
V. Environmental Statement
Commission regulations require that an environmental assessment or
an environmental impact statement be prepared for a Commission action
that may have a significant effect on the human environment. 121
Although this final rule does not directly affect any physical
transmission facilities, but merely requires the electronic posting by
computers of certain information about transmission availability and
prices, it nevertheless is covered by the Final Environmental Impact
Statement issued in the Open Access NOPR proceeding in Docket Nos.
RM95-8-000 and RM94-7-001 on April 12, 1996. Thus, no separate
environmental assessment or environmental impact statement has been
prepared in this proceeding.
---------------------------------------------------------------------------
\121\ Regulations Implementing National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987); 1986-90 Regulations
Preambles, FERC Stats. & Regs. para.30,783 (Dec. 10, 1987) (codified
at 18 CFR Part 380).
---------------------------------------------------------------------------
VI. Information Collection Statement
There are now approximately 328 public utilities, including
marketers and wholesale generation entities. The Commission estimates
that approximately 166 of these utilities own, operate, or control
facilities used for the transmission of electric energy in interstate
commerce and thus are subject to this rule. However, since the
operation of an OASIS will be closely associated with control areas, we
assume that an OASIS will be developed at the control area level and
not by each public utility that owns, operates, or controls interstate
transmission facilities. We also expect that some additional OASIS
nodes will be created voluntarily by non-public utilities subject to
these regulations under the reciprocity condition of the pro forma
tariffs. We estimate, therefore, that 140 respondents will be required
to collect information. We believe that this estimate is conservative
(on the high side) because some regions are likely to develop a region-
wide OASIS that will cover more than one control area. 122
---------------------------------------------------------------------------
\122\ See supra (discussion quoted from How Report at 80).
---------------------------------------------------------------------------
This estimate is higher than the one we included in the RIN NOPR,
where we estimated that there would be 84 respondents. We have adjusted
our estimate in response to the arguments advanced by NRECA and NE
Public Power District, in separate letters to OMB, that the
Commission's Information Collection Statement contained in the RIN NOPR
failed to account for the proposal in the Open Access NOPR that,
because of the reciprocity requirement, non-public utilities and
cooperatives entering contracts for open access transmission services
would be required to establish their own OASIS nodes or participate in
a regional OASIS node.
NRECA also argued that the Commission's analysis must include not
only those entities that are developing their own OASIS node, but also
those entities who, while they are not developing and operating their
own OASIS node, nevertheless will contribute data to their control area
operators or regional OASIS operators. NRECA argued, therefore, that
the Commission's estimate of the number of respondents should have
taken this into account. It did.
Although not explicitly stated in the RIN NOPR, the Commission's
Information Collection Statement, both in this final rule and in the
RIN NOPR, has been based not only on the efforts by the respondents who
will directly operate OASIS nodes but also reflects the collection of
information from all significant participants in the transmission
market.
Information Collection Statement
Title: FERC-717, Real-Time Information Network Standards.
Action: Final Rule
OMB Control No: 1902-0173.
Respondents: Public Utilities that own and/or control facilities
used for the transmission of electric energy in interstate commerce.
Frequency of Responses: On Occasion
Necessity of the information: The final rule requires affected
public utilities to comply with requirements for an Open Access Same-
time Information System (OASIS) established by the Commission to give
potential customers access to information, by electronic means, that
would ensure the availability of open access wholesale transmission
service on a non-discriminatory basis. These requirements would support
arrangements made for wholesale sales and purchases for third parties.
Public utilities or their agents will be required to give competitors
and other users of the transmission system access to the same
information available to public utility personnel who initiate the
acquisition or disposition of power in the wholesale market and at the
same time. The Commission will use the information to monitor the
networks to ensure that potential purchasers of transmission services
obtain the services on a non-discriminatory basis. This final rule was
developed after a review of comments filed in response to issuance of a
notice of public rulemaking.
The Office of Management and Budget's (OMB) regulations, 123
require OMB to approve certain information collection requirements
imposed by agency rule. The information collection requirements in the
final rule will be reported directly to transmission users and will be
subject to subsequent audit by the Commission. The distribution of
these data will help the Commission carry out its responsibilities
under Part II of the FPA.
---------------------------------------------------------------------------
\123\ 5 CFR 1320.11.
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The Commission is submitting notification of this final rule to
OMB. Interested persons may obtain information on the reporting
requirements by contacting the Federal Energy Regulatory Commission,
888 First Street, N.E., Washington, D.C. 20426 [Attention Michael
Miller, Information Services Division, (202) 208-1415], and to the
Office of Management and Budget [Attention: Desk Officer for the
Federal Energy Regulatory Commission (202) 395-3087].
VII. Effective Date
The regulations of new part 37 will become effective on July 9,
1996. The Commission has determined, with the concurrence of the
Administrator of the Office of Information and Regulatory Affairs of
OMB, that the Open Access Final Rule and the OASIS final rule together
constitute a ``major rule'' as
[[Page 21764]]
defined in section 351 of the Small Business Regulatory Enforcement Act
of 1996.124 The rule will be submitted to both Houses of Congress
and the Comptroller General prior to its publication in the Federal
Register. All of the requirements prescribed in the standards of
conduct must be complied with and Phase I OASIS sites that meet the
requirements prescribed in this final rule must be in operation by
November 1, 1996.
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\124\ 5 U.S.C. Sec. 804(2).
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List of Subjects in 18 CFR Part 37
Electric power plants, Electric utilities.
By the Commission.
Lois D. Cashell,
Secretary.
In consideration of the foregoing, the Commission amends chapter I
of title 18, Code of Federal Regulations, to add a new part 37, as set
forth below:
PART 37--OPEN ACCESS SAME-TIME INFORMATION SYSTEMS AND STANDARDS OF
CONDUCT FOR PUBLIC UTILITIES
Sec.
37.1 Applicability.
37.2 Purpose.
37.3 Definitions.
37.4 Standards of conduct.
37.5 Obligations of Transmission Providers and Responsible Parties.
37.6 Information to be posted on an OASIS.
37.7 Auditing Transmission Service Information.
37.8 Implementation schedule for OASIS requirements; phases.
Authority: 16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7352.
Sec. 37.1 Applicability.
This part applies to any public utility that owns, operates, or
controls facilities used for the transmission of electric energy in
interstate commerce and to transactions performed under the pro forma
tariff required in part 35 of this chapter.
Sec. 37.2 Purpose.
(a) The purpose of this part is to ensure that potential customers
of open access transmission service receive access to information that
will enable them to obtain transmission service on a non-discriminatory
basis from any Transmission Provider. These rules provide standards of
conduct and require the Transmission Provider (or its agent) to create
and operate an Open Access Same-time Information System (OASIS) that
gives all users of the open access transmission system access to the
same information.
(b) The OASIS will provide information by electronic means about
available transmission capability for point-to-point service and will
provide a process for requesting transmission service. OASIS will
enable Transmission Providers and Transmission Customers to communicate
promptly requests and responses to buy and sell available transmission
capacity offered under the Transmission Provider's tariff.
Sec. 37.3 Definitions.
(a) Transmission Provider means any public utility that owns,
operates, or controls facilities used for the transmission of electric
energy in interstate commerce.
(b) Transmission Customer means any eligible customer (or its
designated agent) that can or does execute a transmission service
agreement or can or does receive transmission service.
(c) Responsible party means the Transmission Provider or an agent
to whom the Transmission Provider has delegated the responsibility of
meeting any of the requirements of this part.
(d) Reseller means any Transmission Customer who offers to sell
transmission capacity it has purchased.
(e) Wholesale merchant function means the sale for resale, or
purchase for resale, of electric energy in interstate commerce.
(f) Affiliate means:
(1) For any exempt wholesale generator, as defined under section
32(a) of the Public Utility Holding Company Act of 1935, as amended,
the same as provided in section 214 of the Federal Power Act; and
(2) For any other entity, the term affiliate has the same meaning
as given in Sec. 161.2(a) of this chapter.
Sec. 37.4 Standards of conduct.
A Transmission Provider must conduct its business to conform with
the following standards:
(a) General rules. (1) Except as provided in paragraph (a)(2) of
this section, the employees of the Transmission Provider engaged in
transmission system operations must function independently of its
employees, or the employees of any of its affiliates, who engage in
Wholesale Merchant Functions.
(2) Notwithstanding any other provisions in this section, in
emergency circumstances affecting system reliability, Transmission
Providers may take whatever steps are necessary to keep the system in
operation. Transmission Providers must report to the Commission and on
the OASIS each emergency that resulted in any deviation from the
standards of conduct, within 24 hours of such deviation.
(b) Rules governing employee conduct. (1) Prohibitions. Any
employee of the Transmission Provider, or any employee of an affiliate,
engaged in wholesale merchant functions is prohibited from:
(i) Conducting transmission system operations or reliability
functions; and
(ii) Having access to the system control center or similar
facilities used for transmission operations or reliability functions
that differs in any way from the access available to other open access
Transmission Customers.
(2) Transfers. Employees engaged in either wholesale merchant
functions or transmission system operations or reliability functions
are not precluded from transferring between such functions as long as
such transfer is not used as a means to circumvent the standards of
conduct of this section. Notices of any employee transfer to or from
transmission system operations or reliability functions must be posted
on the OASIS as provided in Sec. 37.6(g)(3). The information to be
posted must include: the name of the transferring employee, the
respective titles held while performing each function (i.e., on behalf
of the Transmission Provider and wholesale merchant or affiliate), and
the effective date of the transfer. The information posted under this
section must remain on the OASIS for 90 days.
(3) Information access. Any employee of the Transmission Provider,
or of any of its affiliates, engaged in wholesale merchant functions:
(i) Shall have access to only that information available to the
Transmission Provider's open access transmission customers (i.e., the
information posted on an OASIS), and must not have preferential access
to any information about the Transmission Provider's transmission
system that is not available to all users of an OASIS; and
(ii) Is prohibited from obtaining information about the
Transmission Provider's transmission system (including information
about available transmission capability, price, curtailments, ancillary
services, and the like) through access to information not posted on the
OASIS that is not otherwise also available to the general public
without restriction, or through informat
FR Doc. 96-10693 Open Access Same-Time Information System (Formerly Real-Time Information Networks) and Standards of Conduct
ion through the OASIS that is
not also publicly available to all OASIS users.
(4) Disclosure. A Transmission Provider is responsible for ensuring
compliance with the following provisions:
[[Page 21765]]
(i) Any employee of the Transmission Provider, or any employee of
an affiliate, engaged in transmission system operations or reliability
functions may not disclose to employees of the Transmission Provider,
or any of its affiliates, engaged in wholesale merchant functions any
information concerning the transmission system of the Transmission
Provider or the transmission system of another (including information
received from non-affiliates or information about available
transmission capability, price, curtailments, ancillary services, etc.)
through non-public communications conducted off the OASIS, through
access to information not posted on the OASIS that is not at the same
time available to the general public without restriction, or through
information on the OASIS that is not at the same time publicly
available to all OASIS users (such as E-mail).
(ii) If an employee of the Transmission Provider engaged in
transmission system operations or reliability functions discloses
information not posted on the OASIS in a manner contrary to the
requirements of the standards of conduct, the Transmission Provider
must immediately post such information on the OASIS.
(iii) A Transmission Provider may not share any market information,
acquired from nonaffiliated Transmission Customers or potential
nonaffiliated Transmission Customers, or developed in the course of
responding to requests for transmission or ancillary service on the
OASIS, with its own employees (or those of an affiliate) engaged in
merchant functions, except to the limited extent information is
required to be posted on the OASIS in response to a request for
transmission service or ancillary services.
(5) Implementing tariffs. (i) Employees of the Transmission
Provider engaged in transmission system operations or reliability
functions must strictly enforce all tariff provisions relating to the
sale or purchase of open access transmission service, if these
provisions do not provide for the use of discretion.
(ii) Employees of the Transmission Provider engaged in transmission
system operations must apply all tariff provisions relating to the sale
or purchase of open access transmission service in a fair and impartial
manner that treats all customers (including the public utility and any
affiliate) in a non-discriminatory manner, if these provisions involve
discretion.
(iii) The Transmission Provider must keep a log, available for
Commission audit, detailing the circumstances and manner in which it
exercised its discretion under any terms of the tariff.
(iv) The Transmission Provider may not, through its tariffs or
otherwise, give preference to wholesale purchases or sales made on
behalf of its own power customers, or those of an affiliate, over the
interests of any other wholesale customer in matters relating to the
sale or purchase of transmission service (including issues of price,
curtailments, scheduling, priority, ancillary services, etc.).
(v) If the Transmission Provider offers a discount on purchases of
transmission service made on behalf of its own power customers or those
of any affiliate, then, at the same time, it must post on the OASIS an
offer to provide the same discount to all Transmission Customers on the
same path and on all unconstrained transmission paths.
(vi) If the Transmission Provider offers a rate discount on
ancillary services to an affiliate, or attributes a discounted
ancillary service rate to its own transactions, the Transmission
Provider must, at the same time, post on the OASIS an offer to provide
the same discount to all eligible customers.
(6) Books and records. A Transmission Provider must maintain its
books of account and records (as prescribed under parts 101 and 125 of
this chapter) separately from those of its affiliates and these must be
available for Commission inspection.
(c) Maintenance of written procedures. The Transmission Provider
must maintain in a public place, and file with the Commission, current
written procedures implementing the standards of conduct in such detail
as will enable customers and the Commission to determine that the
Transmission Provider is in compliance with the requirements of this
section.
Sec. 37.5 Obligations of Transmission Providers and Responsible
Parties.
(a) Each Transmission Provider is required to provide for the
operation of an OASIS, either individually or jointly with other
Transmission Providers, in accordance with the requirements of this
Part. The Transmission Provider may delegate this responsibility to a
Responsible Party such as another Transmission Provider, an Independent
System Operator, a Regional Transmission Group, or a Regional
Reliability Council.
(b) A Responsible Party must:
(1) Provide access to an OASIS providing standardized information
relevant to the availability of transmission capacity, prices, and
other information (as described in this part) pertaining to the
transmission system for which it is responsible; and
(2) Shall operate the OASIS in compliance with the standardized
procedures and protocols found in OASIS Standards and Communication
Protocols, which can be obtained from the Public Reference and Files
Maintenance Branch, Room 2A, Federal Energy Regulatory Commission, 888
First Street NE., Washington, DC 20426.
(c) Transmission Providers must provide ``read only'' access to the
OASIS to Commission staff and the staffs of State regulatory
authorities, at no cost, after such staff members have complied with
the requisite registration procedures.
Sec. 37.6 Information to be posted on an OASIS.
(a) The information posted on the OASIS must be in such detail as
to allow Transmission Customers to:
(1) Make requests for transmission services offered by Transmission
Providers, Resellers and other providers of ancillary services;
(2) View and download in standard formats, using standard
protocols, information regarding the transmission system necessary to
enable prudent business decision making;
(3) Post, view, upload and download information regarding available
products and desired services;
(4) Clearly identify the degree to which their transmission service
requests or schedules were denied or interrupted; and
(5) Obtain access, in electronic format, to information to support
available transmission capability calculations and historical
transmission service requests and schedules for various audit purposes.
(b) Posting transmission capability. The transmission capability
that is expected to be available on the Transmission Provider's system
(ATC) and the total transmission capability (TTC) of that system shall
be calculated and posted for each Posted Path as set out in this
section.
(1) Definitions. For purposes of this section the terms listed
below have the following meanings:
(i) Posted path means any control area to control area
interconnection; any path for which service is denied, curtailed or
interrupted for more than 24 hours in the past 12 months; and any path
for which a customer requests to have ATC or TTC posted. For this last
category, the posting must continue for 180 days and thereafter until
180 days have elapsed from the most recent request for service over the
requested path. For purposes of this definition, an
[[Page 21766]]
hour includes any part of an hour during which service was denied,
curtailed or interrupted.
(ii) Constrained posted path means any posted path having an ATC
less than or equal to 25 percent of TTC at any time during the
preceding 168 hours or for which ATC has been calculated to be less
than or equal to 25 percent of TTC for any period during the current
hour or the next 168 hours.
(iii) Unconstrained posted path means any posted path not
determined to be a constrained posted path.
(2) Calculation methods, availability of information, and requests.
(i) Information used to calculate any posting of ATC and TTC must be
dated and time-stamped and all calculations shall be performed
according to consistently applied methodologies referenced in the
Transmission Provider's transmission tariff and shall be based on
current industry practices, standards and criteria.
(ii) On request, the Responsible Party must make all data used to
calculate ATC and TTC for any constrained posted paths publicly
available (including the limiting element(s) and the cause of the limit
(e.g., thermal, voltage, stability)) in electronic form within one week
of the posting. The information is required to be provided only in the
electronic format in which it was created, along with any necessary
decoding instructions, at a cost limited to the cost of reproducing the
material. This information is to be retained for six months after the
applicable posting period.
(iii) System planning studies or specific network impact studies
performed for customers to determine network impacts are to be made
publicly available in electronic form on request and a list of such
studies shall be posted on the OASIS. A study is required to be
provided only in the electronic format in which it was created, along
with any necessary decoding instructions, at a cost limited to the cost
of reproducing the material. These studies are to be retained for two
years.
(3) Posting. The ATC and TTC for all Posted Paths must be posted in
megawatts by specific direction and in the manner prescribed in this
subsection.
(i) Constrained posted paths--(A) For Firm ATC and TTC. (1) The
posting shall show ATC and TTC for a 30-day period. For this period
postings shall be: by the hour, for the current hour and the 168 hours
next following; and thereafter, by the day. If the Transmission
Provider charges separately for on-peak and off-peak periods in its
tariff, ATC and TTC will be posted daily for each period.
(2) Postings shall also be made by the month, showing for the
current month and the 12 months next following.
(3) If planning and specific requested transmission studies have
been done, seasonal capability shall be posted for the year following
the current year and for each year following to the end of the planning
horizon but not to exceed 10 years.
(B) For Non-Firm ATC and TTC. The posting shall show ATC and TTC
for a 30-day period by the hour and days prescribed under paragraph
(b)(3)(i)(A)(1) of this section and, if so requested, by the month and
year as prescribed under paragraph (b)(3)(i)(A) (2) and (3) of this
section.
(C) Updating Posted Information for Constrained Paths.
(1) The capability posted under paragraphs (b)(3)(i) (A) and (B) of
this section must be updated when transactions are reserved or service
ends or whenever the TTC estimate for the Path changes by more than 10
percent.
(2) All updating of hourly information shall be made on the hour.
(ii) Unconstrained Posted Paths. (A) Postings of ATC and TTC shall
be by the day, showing for the current day and the next six days
following and thereafter, by the month for the 12 months next
following. If the Transmission Provider charges separately for on-peak
and off-peak periods in its tariff, ATC and TTC will be posted for the
current day and the next six days following for each period. These
postings are to be updated whenever the ATC changes by more than 20
percent of the Path's TTC.
(B) If planning and specific requested transmission studies have
been done, seasonal capability shall be posted for the year following
the current year and for each year following until the end of the
planning horizon but not to exceed 10 years.
(c) Posting Transmission Service Products and Prices. (1)
Transmission Providers must post prices and a summary of the terms and
conditions associated with all transmission products offered to
Transmission Customers.
(2) Transmission Providers must provide a downloadable file of
their complete tariffs in the same electronic format as the tariff that
is filed with the Commission.
(3) A Transmission Provider, within 24 hours of agreeing to sell
transmission service to a non-affiliate at a discount (as measured from
when ATC must be adjusted in response to the transaction), must post on
the OASIS (and make available for download) information describing the
transaction (including price, quantity, and any other relevant terms
and conditions) and shall keep such information posted on the OASIS for
at least 30 days. A record of the transaction must be retained and kept
available as part of the audit log required in Sec. 37.7. With respect
to any discount offered to its own power customers or its affiliates,
the Transmission Provider must, at the same time, post on the OASIS an
offer to provide the same discount to all Transmission Customers on the
same path and on all unconstrained transmission paths.
(4) Customers choosing to use the OASIS to offer for resale
transmission capacity they have purchased must post relevant
information to the same OASIS as used by the one from whom the Reseller
purchased the transmission capacity. This information must be posted on
the same display page, using the same tables, as similar capability
being sold by the Transmission Provider, and the information must be
contained in the same downloadable files as the Transmission Provider's
own available capability. A customer reselling transmission capacity
without the use of an OASIS must, nevertheless, inform the original
Transmission Provider of the transaction within the time limits
prescribed by the ``Sale or Assignment of Transmission Service''
section of the pro forma tariff.
(d) Posting Ancillary Service Offerings and Prices. (1) Any
ancillary service required to be provided or offered under the pro
forma tariff prescribed by part 35 of this chapter must be posted with
the price of that service.
(2) A Transmission Provider, within 24 hours of agreeing to sell an
ancillary service to a non-affiliate at a discount, must post on the
OASIS (and make available for download) information describing the
transaction (including price, quantity, and any other relevant terms
and conditions) and shall keep such information posted on the OASIS for
at least 30 days. A record of the transaction must be retained and kept
available as part of the audit log required in Sec. 37.7. As to
discounts for ancillary services, if a Transmission Provider offers a
rate discount to an affiliate, or attributes a discounted ancillary
service rate to its own transactions, the Transmission Provider must,
at the same time, post on the OASIS an offer to provide the same
discount to all eligible customers.
(3) Any other interconnected operations service offered by the
Transmission Provider may be posted, with the price for that service.
[[Page 21767]]
(4) Any entity offering an ancillary service shall have the right
to post the offering of that service on the OASIS if the service is one
required to be offered by the Transmission Provider under the pro forma
tariff prescribed by part 35 of this chapter. Any entity may also post
any other interconnected operations service voluntarily offered by the
Transmission Provider. Postings by customers and third parties must be
on the same page, and in the same format, as postings of the
Transmission Provider.
(e) Posting Specific Transmission Service Requests and Responses.
(1) General rules. (i) All requests for transmission service
offered by Transmission Providers under the pro forma tariff must be
made on the OASIS. Requests for transmission service, and the responses
to such requests, must be conducted in accordance with the Transmission
Provider's tariff, the Federal Power Act, and Commission regulations.
(ii) In processing a request for transmission or ancillary service,
the Responsible Party shall post the following information: the date
and time when the request is made, its place in any queue, the status
of that request, and the result (accepted, denied, withdrawn).
(iii) The identity of the parties will be masked--if requested--
during the negotiating period and for 30 days from the date when the
request was accepted, denied or withdrawn.
(2) Posting when a request for transmission service is denied. (i)
When a request for service is denied, the Responsible Party must
provide the reason for that denial as part of any response to the
request.
(ii) Information to support the reason for the denial, including
the operating status of relevant facilities, must be maintained for 60
days and provided, upon request, to the potential Transmission
Customer.
(iii) Any offer to adjust operation of the Transmission Provider's
System to accommodate the denied request must be posted and made
available to all Transmission Customers at the same time.
(3) Posting when a transaction is curtailed or interrupted.
(i) When any transaction is curtailed or interrupted, the
curtailment or interruption must be posted (with the identities of the
parties masked as required in Sec. 37.6(e)(1)(iii)) and must state the
reason why the transaction could not be continued or completed.
(ii) Information to support any such curtailment or interruption,
including the operating status of the facilities involved in the
constraint or interruption, must be maintained for 60 days and
provided, upon request, to the curtailed or interrupted customer.
(iii) Any offer to adjust the operation of the Transmission
Provider's system to restore a curtailed or interrupted transaction
must be posted and made available to all curtailed and interrupted
Transmission Customers at the same time.
(f) Posting Transmission Service Schedules Information. Information
on transmission service schedules must be recorded by the entity
scheduling the transmission service and must be available on the OASIS
for download. Transmission service schedules must be posted no later
than seven calendar days from the start of the transmission service.
(g) Posting Other Transmission-Related Communications. (1) The
posting of other communications related to transmission services must
be provided for by the Responsible Party. These communications may
include ``want ads'' and ``other communications'' (such as using the
OASIS as a Transmission-related conference space or to provide
transmission-related messaging services between OASIS users). Such
postings carry no obligation to respond on the part of any market
participant.
(2) The Responsible Party is responsible for posting other
transmission-related communications in conformance with the
instructions provided by the third party on whose behalf the
communication is posted. It is the responsibility of the third party
requesting such a posting to ensure the accuracy of the information to
be posted.
(3) Notices of transfers of personnel shall be posted as described
in Sec. 37.4(b)(2).
Sec. 37.7 Auditing Transmission Service Information.
(a) All OASIS database transactions, except other transmission-
related communications provided for under Sec. 37.6(g)(2), must be
stored, dated, and time stamped.
(b) Audit data must remain available for download on the OASIS for
90 days. The audit data are to be retained and made available upon
request for three years from the date when they are first posted.
Sec. 37.8 Implementation schedule for OASIS requirements; phases.
Each Transmission Provider must develop or participate in an OASIS
that meets the requirements of this part and that is in operation by
November 1, 1996. Each Transmission Provider must be in compliance with
the standards of conduct prescribed in Sec. 37.4 by November 1, 1996.
[Note: This attachment will not appear in the Code of Federal Regulations.]
Attachment 1.--List of Commenters to RIN NOPR
--------------------------------------------------------------------------------------------------------------------------------------------------------
Number Commenter name Abbreviation
--------------------------------------------------------------------------------------------------------------------------------------------------------
1..................................... ABB Systems Control................................. (ABB)
2..................................... Allegheny Power Service Corporation................. (Allegheny)
3..................................... American Electric Power............................. (AEP)
4..................................... American Public Power Association................... (APPA)
5..................................... City of Anaheim, CA................................. (Anaheim)
6..................................... Arizona Public Service Company...................... (Arizona)
7..................................... Bangor Hydro-Electric Company....................... (Bangor)
8..................................... Basin Electric Power Cooperative.................... (Basin EC)
9..................................... Bonneville Power Administration..................... (BPA)
10.................................... California PUC...................................... (CA Com)
11.................................... Carolina Power & Light Company...................... (Carolina P&L)
12.................................... Central Hudson Gas & Electric Corp.................. (Central Hudson)
13.................................... Central Illinois Public Service Company............. (Central Illinois Public Service)
14.................................... CINergy Corporation................................. (CINergy)
15.................................... Coalition for a Competitive Electric Market......... (CCEM)
16.................................... Colorado Springs Utilities.......................... (CSU)
17.................................... Commonwealth Edison Company......................... (Com Ed)
18.................................... Consolidated Edison Company......................... (ConEd)
[[Page 21768]]
19.................................... Consumers Power Company............................. (Consumers Power)
20.................................... Continental Power Exchange.......................... (Continental Power Exchange)
21.................................... CSW Companies....................................... (CSW)
22.................................... Dayton Power and Light Company...................... (Dayton P&L)
23.................................... Detroit Edison Company.............................. (Detroit Edison)
24.................................... Duke Power Company.................................. (Duke)
25.................................... Edison Electric Institute........................... (EEI)
26.................................... El Paso Electric Company............................ (El Paso)
27.................................... Electric Generation Association..................... (EGA)
28.................................... Electric Reliability Council of Texas............... (ERCOT)
29.................................... Entergy Services, Inc............................... (Entergy)
30.................................... Florida Electric Power Coordinating Group........... (Florida CG)
31.................................... Florida Power Corporation........................... (Florida Power Corp)
32.................................... Florida PSC......................................... (FL Com)
33.................................... Fuel Managers Association........................... (Fuel Managers)
34.................................... ``How'' Industry Working Group (EPRI)............... (How Group)
35.................................... Idaho Power Company................................. (Idaho)
36.................................... Indiana Utility Regulatory Commission............... (IN Com)
37.................................... Indianapolis Power & Light Company.................. (Indianapolis P&L)
38.................................... Klein, Stanley A.................................... (Klein)
39.................................... Long Island Lighting Company........................ (LILCO)
40.................................... Madison Gas and Electric Company.................... (Madison G&E)
41.................................... Maine Public Service Company........................ (Maine Public Service)
42.................................... MidAmerican Energy Company.......................... (MidAmerican)
43.................................... Mid-Continent Area Power Pool....................... (MAPP)
44.................................... Minnesota Power & Light Company..................... (Minnesota P&L)
45.................................... Missouri Public Service Commission.................. (MO & AK Com's)
46.................................... Montana Power Company............................... (Montana Power)
47.................................... National Association of Regulatory Utility (NARUC)
Commissioners.
48.................................... National Independent Energy Producers............... (NIEP)
49.................................... National Rural Electric Cooperative Association..... (NRECA)
50.................................... Nebraska Public Power District...................... (NE Public Power District)
51.................................... New England Power Pool.............................. (NEPOOL)
52.................................... New York Mercantile Exchange........................ (NYMEX)
53.................................... New York Power Pool................................. (NYPP)
54.................................... New York State Electric & Gas Corp.................. (NYSEG)
55.................................... New York State PSC.................................. (NY Com)
56.................................... NorAm Energy Services, Inc.......................... (NorAm)
57.................................... North American Electric Reliability Council......... (NERC)
58.................................... North Carolina Electric Membership Corp............. (NCEMC)
59.................................... Northeast Texas Electric Cooperative, Inc........... (NTEC)
60.................................... Northeast Utilities................................. (NU)
61.................................... Northern States Power Companies..................... (NSP)
62.................................... Nucor Corporation................................... (Nucor)
63.................................... Oak Ridge National Lab, Energy Division............. (Oak Ridge)
64.................................... Ohio Edison Company................................. (Ohio Edison)
65.................................... Ohio PUC............................................ (Ohio Com)
66.................................... Oklahoma Corporation Commission..................... (OK Com)
67.................................... Oklahoma Gas & Electric............................. (Oklahoma G&E)
68.................................... Omaha Public Power District......................... (Omaha PPD)
69.................................... Ontario Hydro....................................... (Ontario Hydro)
70.................................... Orange and Rockland Utilities, Inc.................. (Orange & Rockland)
71.................................... Oregon Trail Electric Consumers Cooperative......... (Oregon EC)
72.................................... Otter Tail Power Company............................ (Otter Tail)
73.................................... Pacific Gas and Electric Company.................... (PG&E)
74.................................... PacifiCorp.......................................... (PacifiCorp)
75.................................... Pennsylvania--New Jersey--Maryland Power Pool....... (PJM)
76.................................... Pennsylvania Public Utility Commission.............. (PA Com)
77.................................... Public Generating Pool.............................. (Public Generating Pool)
78.................................... Public Service Company of New Mexico................ (PSNM)
79.................................... Sacramento Municipal Utility District............... (SMUD)
80.................................... Salt River Project.................................. (Salt River)
81.................................... San Diego Gas & Electric Company.................... (San Diego G&E)
82.................................... Seattle City Light.................................. (Seattle)
83.................................... Services-Oriented Open Network Technologies, Inc.... (SONETECH)
84.................................... Sierra Pacific Power Company........................ (Sierra)
85.................................... South Carolina Electric & Gas Company............... (SCE&G)
86.................................... South Carolina Public Service Authority............. (SC Public Service Authority)
87.................................... Southern California Edison Company.................. (SoCal Edison)
88.................................... Southern Company Services, Inc...................... (Southern)
89.................................... Southwest Transmission Dependent Utility Group...... (Southwest TDU Group)
[[Page 21769]]
90.................................... Southwestern Public Service Company................. (Southwestern)
91.................................... Sunflower Electric Power Cooperative................ (Sunflower)
92.................................... City of Tallahassee, FL............................. (Tallahassee)
93.................................... Tampa Electric Company.............................. (Tampa)
94.................................... Tennessee Valley Authority.......................... (TVA)
95.................................... Texas Utilities Electric Company.................... (Texas Utilities)
96.................................... Transmission Access Policy Study Group.............. (TAPS)
97.................................... Tucson Power Electric Power Company................. (Tucson Power)
98.................................... Union Electric Company.............................. (Union Electric)
99.................................... United Illuminating Company......................... (United Illuminating)
100................................... U.S. Department of Energy, Office of Energy Research (DOE)
101................................... UTC, The Telecommunications Association............. (UTC)
102................................... Virginia Electric and Power Company................. (VEPCO)
103................................... Western Group....................................... (Western Group)
104................................... Wisconsin Power & Light............................. (WP&L)
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[FR Doc. 96-10693 Filed 5-9-96; 8:45 am]
BILLING CODE 6717-01-C
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