Tenaska Clear Creek Wind, LLC v. Federal Energy Regulatory Commission

United States Court of Appeals
FOR THE DISTRICT OF COLUMBIA CIRCUIT
Argued April 9, 2024 Decided July 19, 2024
No. 22-1059
TENASKA C LEAR CREEK W IND, LLC,
PETITIONER
v.
FEDERAL ENERGY REGULATORY COMMISSION ,
RESPONDENT
BRIGHT CANYON ENERGY CORPORATION, ET AL .,
I NTERVENORS
Consolidated with 22-1336, 23-1076
On Petitions for Review of Orders of the
Federal Energy Regulatory Commission
David A. Super argued the cause for petitioner. With him
on the briefs were Tyler S. Johnson and Stephen J. Hug.
Beth G. Pacella, Deputy Solicitor, Federal Energy
Regulatory Commission, argued the cause for respondent.
With her on the brief were Matthew R. Christiansen, General
Counsel, and Robert H. Solomon, Solicitor. Matthew W. Estes,
Attorney, entered an appearance.

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Matthew J. Binette argued the cause for respondent-
intervenors. With him on the brief were Marnie A.
McCormick, Mark Strain, Peter K. Matt, Jecoliah R. Williams,
Elizabeth P. Trinkle, William R. Hollaway, Ph.D., Lucas C.
Townsend, and Max E. Schulman.
Before: CHILDS and GARCIA, Circuit Judges, and
GINSBURG, Senior Circuit Judge.
Opinion for the Court filed by Circuit Judge CHILDS .
CHILDS , Circuit Judge: Petitioner Tenaska Clear Creek
Wind, LLC (“Clear Creek”) wants to generate energy by wind
turbine for sale to parts of Missouri, southeast Iowa, and
northeast Oklahoma. In these consolidated petitions for review
of orders of the Federal Energy Regulatory Commission
(“Commission”), Clear Creek maintains that the Commission
acted arbitrarily, capriciously, and contrary to precedent when
it allowed Southwest Power Pool, Inc. (“SPP”), a regional
transmission organization (“RTO”), to assign costs of more
than $100 million to Clear Creek to pay for upgrades required
on SPP’s system to accommodate the interconnection of Clear
Creek’s wind turbine-powered electrical generation project
(the “Project”). For the reasons set forth below, the court
denies Clear Creek’s petitions for review.
I.
A.
The Federal Power Act of 1920, 16 U.S.C. §§ 791a–828c
(the “Act”), vests the Commission with regulatory authority
over the “transmission of electric energy in interstate
commerce and . . . the sale of electric energy at wholesale in
interstate commerce,” id. § 824(b)(1), and requires all rates

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subject to the Commission’s jurisdiction to “be just and
reasonable,” id. § 824d(a). As part of the enforcement of the
“just and reasonable” requirement, “section 205 [of the Act]
requires that utilities file tariffs reflecting their rates and service
terms with the Commission for review.” Green Dev., LLC v.
FERC, 77 F.4th 997, 1000 (D.C. Cir. 2023) (citing 16 U.S.C.
§ 824d(c)). “A negatively affected party may challenge a
Commission-approved rate by filing a complaint with the
Agency, and it carries the burden of demonstrating that the rate
is unjust or unreasonable.” Constellation Mystic Power, LLC
v. FERC, 45 F.4th 1028, 1035 (D.C. Cir. 2022).
When a power generator like Clear Creek builds a new
facility, it must connect that location to the power grid. Green
Dev., 77 F.4th at 1001. To create a new connection to the
electric grid, the power generator asks to “interconnect” to the
transmission system by submitting an interconnection request
to a transmission system operator, at which point the generator
is assigned a position in a queue. Standardization of Generator
Interconnection Agreements & Procs. (“Order No. 2003”), 104
FERC ¶ 61,103 at P 35 (July 24, 2003). Transmission system
operators review the requests in the queue in chronological
order, either individually or in clusters. During the review
process, the transmission system operator conducts studies to
assess the impact of the new energy source on the preexisting
electric grid. These studies identify any new facilities and
equipment that may be needed to accommodate the new
interconnection. In some instances, the interconnection has an
impact beyond the local system. When this occurs, an affected
system operator will conduct a study to evaluate the impact of
the interconnection on its system. Throughout this entire
process, a study may be revised or redone if the generator
cancels its proposed project, thereby impacting the upgrades
required for the other proposed projects in the queue.

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When completing an interconnection request, power
generators are required to choose the level of interconnection
service they require. There are two levels for interconnection
service that power generators may choose from: Network
Resource Interconnection Service (“NRIS”), or “firm” service,
and Energy Resource Interconnection Service (“ERIS”), or
“non-firm” or “interruptible” service. As we have previously
explained,
Electric utilities often distinguish between
“firm” service, under which customers can
demand power or transmission at any time, and
“interruptible” service, which the utility is
entitled to shut off at any point when there is not
enough excess capacity beyond that required to
guarantee the needs of the utility’s firm
customers. Interruptible service is typically
offered at a significant discount because the
utility’s ability simply to cut off service at peak
demand periods alleviates its need to plan for
and finance additional capacity to offer the
service.
Fort Pierce Utils. Auth. v. FERC, 730 F.2d 778, 785–86
(1984).
B.
The Project is a 242-megawatt facility in northwest
Missouri and comprises 111 Vestas turbines across
approximately 31,000 acres. Prior to beginning operation,
Clear Creek sought to connect the Project to the electric grid.
It submitted an interconnection request to transmission system
operator Associated Electric Cooperative, Inc. (“AECI”), an
electric generation and transmission cooperative based in
Springfield, Missouri that provides wholesale power to parts of

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Missouri, southeast Iowa, and northeast Oklahoma. The level
of interconnection service Clear Creek requested was NRIS.
While conducting its interconnection study, AECI
identified two RTOs, 1 SPP and Midcontinent Independent
System Operator, Inc. (“MISO”), that could be affected by
Clear Creek’s interconnection.2 AECI directed Clear Creek to
coordinate affected system studies with SPP and MISO. On
August 20, 2018, Clear Creek asked SPP to conduct an affected
system study of the interconnection.3 SPP informed Clear
Creek that the affected system study should take between four
to five weeks to complete.
SPP’s interconnection study procedures are outlined in its
Tariff. See SPP, Open Access Transmission Tariff, attach. V
(“Tariff”). When an interconnection request is submitted to
SPP, SPP assigns an initial queue position and evaluates all
valid interconnection requests submitted in the same 180-
calendar-day window in a Definitive Interconnection System
Impact Study (“DISIS”) cluster. Requests in the same DISIS
cluster are evaluated together at equal priority for SPP to
determine if upgrades are needed to fulfill the requests. To
1 RTOs “are independent organizations that manage the transmission
of electricity over the electric grid and ensure electricity is reliably
available for consumers.” Advanced Energy Mgmt. All. v. FERC,
860 F.3d 656, 659 (D.C. Cir. 2017).
2 SPP is a non-profit RTO that provides transmission service in
fourteen states: “Arkansas, Iowa, Kansas, Louisiana, Minnesota,
Missouri, Montana, Nebraska, New Mexico, North Dakota,
Oklahoma, South Dakota, Texas, and Wyoming.” Comm’n’s Br. 9.
“MISO is an RTO that serves the central United States.” City of
Lincoln v. FERC, 89 F.4th 926, 934 n.10 (D.C. Cir. 2024).
3 MISO determined that no network upgrades were necessary on its
transmission system to accommodate the interconnection to the
AECI transmission system.

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perform each study, SPP evaluates the base case and transfer
case. The base case shows SPP’s system before any
interconnection is done, while the transfer case shows SPP’s
system after the interconnection.
If the transfer case indicates constraints and that
network upgrades are necessary to alleviate
those constraints to accommodate the
interconnection of a project or projects, SPP
determines the cost allocation of those network
upgrades and assigns costs to each
interconnection customer that contributed to the
need for a specific network upgrade on a pro
rata basis.
Order Granting in Part and Denying in Part Complaint,
177 FERC ¶ 61,200 at P 2 (Dec. 16, 2021) (“Complaint
Order”) (JA222).
SPP performs the study of each interconnection request on
the level of interconnection service the requester asked for
from the host system, ERIS or NRIS. After the studies are
completed, SPP “assigns responsibility for network upgrades
needed to mitigate a constraint based on whether an
interconnection request impacts the constraint by at least the
applicable [transfer distribution factor (TDF)] threshold and if
the transmission facility is overloaded greater than 100% of its
line rating.” Order Addressing Arguments Raised on
Rehearing and Denying Motion for Stay, 182 FERC ¶ 62,090
at P 9 (Feb. 16, 2023) (“Rehearing Order”) (JA575). The TDF
threshold is based on the customer’s request on the host system
for ERIS or NRIS service. “If the impact of an interconnection
request is below the TDF threshold, then SPP considers the
generating facility’s impact de minimis (even if a transmission
line is overloaded beyond its line rating) and does not assign

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network upgrades for that transmission facility to the
interconnection customer.” Id.
SPP issued its first affected system impact study regarding
Clear Creek on October 5, 2018, identifying $31.2 million in
upgrades required on its system using 2017 integrated
transmission planning (ITP) models. On November 5, 2018,
SPP issued a revised study, which did not make any substantive
changes to the results of the first study. Thereafter, SPP issued
affected system studies on February 12, 2019 ($16.3 million in
upgrades), March 21, 2019 ($33.017 million in upgrades), and
April 8, 2019 ($33.535 million in upgrades).
Clear Creek requested NRIS on the AECI transmission
system, so SPP conducted the study under both ERIS and NRIS
as was their practice for those requests. SPP did not find any
NRIS-related network upgrades in their initial study, only
upgrades related to ERIS. Believing the system studies were
ending, Clear Creek began construction of the Project in the
spring of 2019.
On November 1, 2019, SPP notified Clear Creek that SPP
was going to restudy the Project using 2019 ITP models
because of the withdrawal of several higher-queued projects in
the cluster. At this point, Clear Creek had already installed 50
wind turbines and committed $266 million pursuant to their
belief the studies were ending. On November 2, 2020, SPP
provided the initial results of the restudy, which stated system
upgrade costs of $763 million. “The dramatic increase in
upgrade costs reflected the assignment of cost responsibility to
Tenaska Clear Creek for approximately 20 additional network
upgrades.” Compl. at 13–14 (JA036–JA037). On December
18, 2020, SPP provided an updated study lowering the cost of
upgrades to $106.8 million. Entering 2021, SPP continued to
make adjustments to the upgrade amount, lowering it to $93

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million on January 9, 2021, then to $91 million on February 26,
2021, and raising it to $99 million on March 25, 2021.
On May 5, 2021, Clear Creek filed a complaint with the
Commission to end SPP’s “multi-year affected system study
process” and direct it “to respect the results of the initial studies
of the Clear Creek Project.” Id. at 1 (JA024), 3 (JA026). Seven
months later, the Commission granted in part and denied in part
Clear Creek’s complaint, finding that
SPP appropriately applied its authority under
the SPP Tariff to restudy the Project after the
withdrawal of one or more higher-queued
projects; that correcting the omission of 4.5 GW
of higher-queued generation was appropriate;
and that SPP appropriately used the NRIS
standard to evaluate the impacts of the Project
on the SPP system.
Complaint Order at P 18 (JA227). The Commission also found
that “SPP’s use of the 2019 ITP models in the restudy was
unduly discriminatory or preferential,” id., because SPP was
“continuing to use the 2017 ITP models for similarly situated
customers,” id. at P 62 (JA247). Thus, the Commission
required SPP “to restudy the Project using the 2017 ITP
models” updated to incorporate “the 4.5 GW of missing
generation,” and “to make a compliance filing” after “the
completion of the restudy.” Id. at P 18 (JA227). After the
Commission denied Clear Creek’s request for rehearing by
operation of law, see Notice of Denial of Rehearing by
Operation of Law and Providing for Further Consideration,
178 FERC ¶ 62,087 (Feb. 14, 2022) (“Denial Order 1”)
(JA309), SPP submitted compliance filings with the results of
the restudy in March 2022 (“2022 Restudy”), which stated that

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necessary upgrades assigned to Clear Creek were reduced to
$88 million.
In April 2022, Clear Creek filed an amended complaint
with the Commission and then filed its first petition in this
court seeking review of the Complaint Order and Denial Order
1. Subsequently, SPP filed an amended restudy reducing
network upgrade costs to $79 million on May 13, 2022, and a
notice raising costs to $102 million on August 16, 2022.
In September 2022, the Commission issued an Order
finding that SPP complied with the Commission’s directive to
restudy the Project and that the “assignment of network
upgrade costs to the Project pursuant to the 2022 Restudy [wa]s
just and reasonable, not unduly discriminatory or preferential,
and consistent with the ‘but for’ cost allocation.” Order on
Compliance and Addressing Arguments Raised on Rehearing,
180 FERC ¶ 61,160 at P 30 (Sept. 9, 2022) (“Compliance
Order”) (JA491). After the Commission denied Clear Creek’s
request for rehearing by operation of law, see Notice of Denial
of Rehearing by Operation of Law and Providing for Further
Consideration, 181 FERC ¶ 62,090 (Nov. 7, 2022) (“Denial
Order 2”) (JA569), Clear Creek filed its second petition in this
court seeking review of the Compliance Order and Denial
Order 2.
Again, in February 2023, the Commission determined that
SPP’s assignment of network upgrade costs to Clear Creek was
“just and reasonable, not unduly discriminatory or preferential,
and consistent with ‘but for’ cost allocation.” Rehearing
Order at P 31 (JA584). Clear Creek timely filed a third petition
for review of the Compliance Order, Denial Order 2, and the
Rehearing Order.

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II.
The court has jurisdiction to review the Commission’s
orders pursuant to § 313(b) of the Act. 16 U.S.C. § 825l(b)
(“Any party to a proceeding . . . aggrieved by an order issued
by the Commission . . . may obtain a review of such order in
the . . . United States Court of Appeals for the District of
Columbia” and “[u]pon the filing of such petition such court
shall have jurisdiction.”). The court reviews the Commission’s
orders under the familiar arbitrary and capricious standard of
the Administrative Procedure Act. See Entergy Servs., Inc. v.
FERC, 568 F.3d 978, 981 (D.C. Cir. 2009) (citing 5 U.S.C.
§ 706(2)(A)). The court is empowered “to reverse any agency
action that is ‘arbitrary, capricious, an abuse of discretion, or
otherwise not in accordance with law.’” Hoopa Valley Tribe v.
FERC, 913 F.3d 1099, 1102 (D.C. Cir. 2019) (citation
omitted). However, the court will uphold the Commission’s
determination if it “examine[d] the relevant data and
articulate[d] a satisfactory explanation for its action including
a ‘rational connection between the facts found and the choice
made.’” Motor Vehicle Mfrs. Ass’n of U.S. v. State Farm Mut.
Auto. Ins. Co., 463 U.S. 29, 43 (1983) (quoting Burlington
Truck Lines, Inc. v. United States, 371 U.S. 156, 168 (1962)).
The Commission “must demonstrate that it has made a
reasoned decision based upon substantial evidence in the
record, and the path of its reasoning must be clear.” Seminole
Elec. Coop., Inc. v. FERC, 861 F.3d 230, 234 (D.C. Cir. 2017)
(cleaned up).
A.
Before turning to the merits of Clear Creek’s claims, we
first address whether we lack subject matter jurisdiction
because the appeal is moot. AECI, SPP, and several other
companies (collectively “Respondent-Intervenors”) argued

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that the court should deny Clear Creek’s petitions as moot
because: (1) Clear Creek voluntarily downgraded to ERIS and,
as a result, no longer must pay the $102 million in current
upgrade costs associated with NRIS; and (2) in the event Clear
Creek reinstates NRIS, that $102 million upgrade total would
be void and the reinstatement would require a new
interconnection study which would not necessarily result in the
same mix of upgrades and costs.4 At oral argument, the
Commission agreed with Respondent-Intervenors that
mootness provided another basis for denying the petitions.
Clear Creek responds that its petitions are not moot because a
favorable decision can reverse harm caused by an unjust
Commission policy that allows the use of the more-demanding
NRIS standard in affected system studies.
“Article III, Section 2 of the Constitution permits federal
courts to adjudicate only ‘actual, ongoing controversies.’”
McBryde v. Comm. to Rev. Cir. Council Conduct & Disability
Ords. of the Jud. Conf. of the U.S., 264 F.3d 53, 55 (D.C. Cir.
2001) (quoting Honig v. Doe, 484 U.S. 305, 317 (1988)). “If
events outrun the controversy such that the court can grant no
meaningful relief, the case must be dismissed as moot.” Id.;
see also Pub. Utils. Comm’n of the State of Cal. v. FERC, 236
F.3d 708, 714 (D.C. Cir. 2001) (“For that reason, if events
occur while a case is pending on appeal that make it impossible
for the court to grant any effectual relief whatever to a
prevailing party, the appeal must be dismissed as moot.”
4 Respondent-Intervenors also argue that we lack jurisdiction,
characterizing Clear Creek’s argument as a time-barred collateral
challenge to the Commission’s settled “but for” policy. Intervenors’
Br. 34–35. But Clear Creek’s challenge is not to the “but for”
standard generally; instead, Clear Creek challenges a particular result
of SPP’s de minimis threshold cost allocation. Accordingly, this
poses no obstacle to our exercise of jurisdiction in this appeal. See
S. Co. Servs., Inc. v. FERC, 416 F.3d 39, 44 (D.C. Cir. 2005).

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(cleaned up)). “This requirement applies independently to each
form of relief sought.” McBryde, 264 F.3d at 55. The “heavy
burden of proving mootness” is with the party asserting a case
is moot. Maldonado v. District of Columbia, 61 F.4th 1004,
1006 (D.C. Cir. 2001).
Here, Respondent-Intervenors and the Commission have
not shown that the events have outrun the controversy such that
we could not grant meaningful relief. First, when Clear Creek
downgraded its level of service to ERIS to avoid bankruptcy, it
negotiated with AECI a contractual right to re-open the matter
of its service level if its present petitions were to prevail.
Indeed, our granting of Clear Creek’s petitions would
undoubtedly bring it “effectual relief,” because it would allow
Clear Creek to obtain NRIS service without taking on the $88
million in upgrade costs assigned to it in SPP’s second restudy.
The prospect of such substantial relief therefore demonstrates
that Clear Creek’s voluntary downgrade to ERIS service has
not mooted this case.
Second, SPP’s assertion that it will do an interconnection
restudy if Clear Creek renews its request for NRIS service
similarly would not impact this court’s ability to grant effectual
relief. SPP’s argument that the upgrade costs of NRIS or ERIS
in a restudy will change is not effective. Clear Creek is not
only disputing the costs SPP imposed, but additionally is
disputing the method used to calculate those costs. Since SPP
and the Commission have stated intentions to allocate costs in
the same way Clear Creek challenges in this appeal, the issue
cannot be moot. Since Respondent-Intervenors and the
Commission are unable to meet their burden of proving
mootness, we turn to the merits of Clear Creek’s petitions.

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B.
Clear Creek makes several challenges to the
Commission’s orders. None persuade us.
1.
First, Clear Creek argues that the Commission’s orders
violate the cost causation principle, thereby allowing SPP to
assign upgrade costs for “transmission facilities that were
overloaded prior to the interconnection of the Project.” Pet’r’s
Br. 19. Clear Creek further complains that the Commission’s
orders are inconsistent with cost causation because they cast
“Clear Creek as the sole cause and beneficiary of the[]
upgrades,” id. 25, when the payments of costs “to remedy
preexisting overloads . . . bring[s] disproportionate benefits to
others,” id. 30.
The Act incorporates a cost causation principle in its just
and reasonable standard. See City of Lincoln v. FERC, 89 F.4th
926, 930 (D.C. Cir. 2024). This principle requires that “[t]he
cost of transmission facilities . . . be allocated to those within
the transmission planning region that benefit from those
facilities in a manner that is at least roughly commensurate with
estimated benefits.” S.C. Pub. Serv. Auth. v. FERC, 762 F.3d
41, 53 (D.C. Cir. 2014) (per curiam). “And undue
discrimination occurs when similarly situated entities are
charged different rates for no good reason.” Consol. Edison
Co. of N.Y., Inc. v. FERC, 45 F.4th 265, 282 (D.C. Cir. 2022).
“But nothing requires the Commission to ensure full or perfect
cost causation.” S.C. Pub. Serv. Auth., 762 F.3d at 88. “Rather,
the cost causation principle requires that ‘all approved rates
reflect to some degree the costs actually caused by the customer
who must pay them.’” Id. (citation omitted).

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In response to Clear Creek’s cost causation challenge, the
Commission explains why it did not find Clear Creek’s
arguments persuasive. First, the Commission cites to
“longstanding policy” that “interconnection customers are
responsible for network upgrade costs that would not be needed
‘but for’ the interconnection customer’s request to reliably
interconnect its generating facility.” Rehearing Order at P 32
(JA584); see also Reform of Generator Interconnection Procs.
& Agreements, 166 FERC ¶ 61,137 at P 78 (Feb. 21, 2019)
(“[I]t would be inconsistent with the cost causation principle to
exempt an interconnection customer from interconnection
facility and network upgrade costs that would not be necessary
but for that interconnection request.”). Next, the Commission
specified that
the network upgrades identified in the 2022
Restudy were necessary for the Project to
interconnect to the transmission system. As
such, allocating the costs of the network
upgrades to [Clear Creek] is consistent with the
cost causation principle and the Commission’s
policy of assigning network upgrade costs to the
interconnection customer who caused the need
for the network upgrades. Clearly, it is [Clear
Creek] that has caused these costs and,
therefore, [Clear Creek] who should bear them.
Rehearing Order at P 32 (JA585). The Commission’s
reasoning is simply that the Project caused operational issues
for SPP that did not arise prior to its operation, so it is
reasonable to assign the costs of mitigation to Clear Creek, the
initiator of those costs. It is clear from the record that SPP’s
system is functional in the pre-transfer case, even though it is
technically “overloaded.” In the pre-transfer case, therefore,
the upgrades at issue were not “necessary” to the continued

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functioning of SPP’s system. Put differently, if SPP were to
install no upgrades at all, then nothing would change for those
prior customers whose interconnections were deemed de
minimis; the current capability of the system would remain
sufficient for their needs. It therefore follows that Clear Creek
is the “but for” cause (and the chief beneficiary) of the system
upgrades for which SPP made it responsible.
Clear Creek argues that two of our recent cases support its
position: Consol. Edison, 45 F.4th 265, and Old Dominion
Elec. Coop. v. FERC, 898 F.3d 1254 (D.C. Cir. 2018). Reply
Br. 15. Neither case does, as the Commission explained.
Rehearing Order at PP 34 (JA586–JA587 & n.81), 37 (JA588–
JA589). Consolidated Edison involved a de minimis threshold,
but one that operated wholly differently from SPP’s here. 45
F.4th at 281–82. And, in contrast to Old Dominion, the
upgrades here are not part of the regional transmission plan
(base case), nor did the Commission find the upgrades here
would provide significant regional benefits. 898 F.3d at 1256–
59. These distinctions demonstrate why neither case indicates
that cost causation is violated here and neither prevents the
Commission from approving SPP’s de minimis cost allocation
methodology. Therefore, because the Commission’s
explanation for its findings comports with its precedent and the
cost causation principle, the Commission’s decision is based
on reasoned decision-making.
2.
Clear Creek next complains that SPP’s allocation of costs
is inconsistent with the Commission’s “but for” policy.
Under the “but for” standard, “generation developers are
to be allocated the costs for transmission system upgrades that
would not have been made but for the interconnection of the

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developers, minus the cost of any facilities that the
[transmission operator]’s regional plan dictates would have
been necessary anyway for load growth and reliability
purposes.” Midwest Indep. Transmission Sys. Operator, Inc.,
129 FERC ¶ 61,019 at P 23 (Oct 9, 2009) (citation omitted).
The Commission’s opposition to this challenge starts with
Order No. 2003, wherein the Commission reasoned that “it is
appropriate for the Interconnection Customer to pay initially
the full cost of . . . Network Upgrades that would not be needed
but for the interconnection.” Id. at P 694. The Commission
then can resort to its explanation of how “SPP assigns
responsibility for network upgrades needed to mitigate a
constraint based on whether (1) an interconnection request
impacts the transmission facility by at least the applicable TDF
threshold; and (2) if the transmission facility is overloaded
greater than 100% of its line rating.” Compliance Order at P
98 (JA526). “If the impact of an interconnection request is
below the TDF threshold, then SPP considers the generating
facility’s impact de minimis (even if a transmission line is
overloaded beyond its line rating), and SPP does not assign
network upgrades for that transmission facility to the
interconnection customer.” Id.
Relying on this method, the Commission reasonably
extrapolated that (1) “SPP’s practice of assigning network
upgrades when a transmission facility is overloaded in the pre-
transfer case prior to the addition of the interconnection request
under study is just and reasonable,” id. at P 99 (JA527); (2) “the
assignment of costs for the network upgrades to mitigate . . .
Overloaded NRIS Facilities to Tenaska is just and reasonable,”
id. at P 100; and (3) “the costs of the network upgrades
necessary to mitigate constraints on the . . . Overloaded NRIS
Facilities are [Clear Creek]’s ‘but for’ costs because such
network upgrades are required to interconnect the Project and,

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absent the Project, those network upgrades would not be
required,” id. at P 101.
The Commission also reasonably explained why it found
SPP’s methodology just and reasonable. The Commission
reasoned that Clear Creek was assigned costs only for
overloads that have “significant impacts on the transmission
system” and that were not based on upgrades required by
regional transmission system planning. Compliance Order at
P 103 (JA528). As for SPP setting the NRIS threshold at 3%,
the Commission concluded that “[s]ome form of distribution
factors to determine cost responsibility for network upgrades is
a common practice among public utilities,” id., and that the 3%
threshold “cuts both ways,” including for Clear Creek here, id.
at P 104 (JA528–JA529); see also Rehearing Order at P 33
(JA585).
In response to Clear Creek’s argument that the
Commission failed to distinguish its “but for” precedent in
Jeffers South, LLC v. Midwest Indep. Transmission Sys.
Operator, Inc., 139 FERC ¶ 63,002 (2012), order on initial
decision, 144 FERC ¶ 61,033 (2013), order on reh’g, 153
FERC ¶ 61,190 (2015), and Midwest Indep. Transmission Sys.
Operator, Inc., 122 FERC ¶ 61,113 (2008), the Commission
explained that those decisions identify violations of the “but
for” principle on the basis that the interconnection customer
was being assigned upgrades intended in part to resolve
regional transmission needs, i.e., needs not related to that
customer’s interconnection. Rehearing Order at P 39 (JA591);
Compliance Order at PP 42–44 (JA498–JA500 & n.70), 103
(JA528). Substantial evidence supports the Commission’s
determination here that the disputed upgrades were not
intended to address regional transmission planning (base case),
as opposed to interconnection, needs. Rehearing Order at
PP 38–40 (JA589–JA592 & nn.102–104). Citing to affidavits

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from two SPP experts, id., and the 2022 Restudy, which
included only upgrades required to address SPP’s cost-
allocation criteria, the Commission reasoned that this
“definitionally excludes costs of transmission constraints
existing in the base case model,” id. at P 38 (JA590). Clear
Creek’s argument, Pet’r’s Br. 50–51, that SPP should
nonetheless have identified these upgrades in its regional
planning process and violated North American Electric
Reliability Corporation standards by failing to do so does not
change that analysis because Clear Creek did not offer any
evidence of such a violation, Rehearing Order at P 40 (JA591–
JA592), and SPP’s expert affidavit indicated the contrary, id.
Accordingly, the Commission concluded that SPP’s
methodology comports with the “but for” principle and that
determination is consistent with reasoned decision-making.
3.
Finally, Clear Creek contends that the Commission failed
to address the fact that SPP’s interconnection study and cost
allocation practices used NRIS when “Clear Creek is neither
taking service on the SPP system nor seeking deliverability on
the SPP system.” Pet’r’s Br. 53. Clear Creek further asserts
that the Commission’s failure has allowed SPP to artificially
inflate upgrade costs and foist them “onto a generator outside
SPP’s system and where those upgrades will provide
substantial benefits to SPP by addressing well documented
issues in a heavily congested region within SPP’s grid.” Id.
53–54.
As to this challenge, the Commission reasonably explains
why Clear Creek cannot meet its burden of demonstrating that
SPP’s use of NRIS in its interconnection study is unjust,
unreasonable, unduly discriminatory, or preferential. First, the

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Commission identified precedent finding that it is just and
reasonable for SPP to use NRIS modeling criteria for a NRIS
interconnection request arising from a neighboring
transmission system. See Midcontinent Indep. Sys. Operator,
Inc., 171 FERC ¶ 61,275 at P 59 (June 30, 2020). That order
explained why SPP’s use of NRIS standards in its affected
system study was not unjust or unreasonable, id. at PP 59–60,
and Clear Creek provides no substantive response to that
reasoning in this appeal.
Next, the Commission expertly pointed out how Clear
Creek’s own conduct—specifically its request for NRIS on
AECI’s system and acknowledgement that the Project’s energy
output flows onto SPP’s transmission system—supports SPP’s
stated justification for conducting its interconnection study at
the NRIS level if that is the level of interconnection service
requested:
Interconnection customers requesting NRIS
expect the interconnected transmission system
to be capable of providing that level of service
whether the wires are in SPP or the neighboring
transmission system. To study all neighboring
system NRIS requests using ERIS thresholds
would expose SPP’s members to negative
impacts, could undermine reliability, and result
in inappropriate and discriminatory cost
allocation to SPP Interconnection Customers
who have requested a comparable level of
service. If SPP were to evaluate neighboring
NRIS interconnection requests using ERIS
standards and thresholds, the studies could
understate their impact because doing so would
not take into account the impacts of the higher
level of service being requested. This could

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disadvantage other Interconnection Customers
or other Transmission System users in SPP and
result in the inappropriate allocation of costs to
other customers or users rather than to the
appropriate Interconnection Customer.
Answer, Kelley Aff. ¶ 11 (JA169–JA170). Because SPP’s
focus is on how to avoid undermining reliability, the
Commission’s support for SPP’s NRIS standard is supported
by substantial evidence and is consistent with reasoned
decision-making.5 Cf. Big Sandy Peaker Plant, LLC v. PJM
Interconnection, LLC, 154 FERC ¶ 61,216 at P 50 (Mar. 17,
2016) (“The Commission has recognized that it may be
appropriate to provide operational and reliability-related
5 About six months after issuing its rehearing order in this case, the
Commission issued a final rule that substantially revised its pro
forma interconnection request procedures in 18 C.F.R. Part 35. The
new procedures specify, among other things, that a transmission
provider should not use the NRIS level of service when it studies an
“affected system” interconnection request. See Order No. 2023,
Improvements to Generator Interconnection Procs. & Agreements,
184 FERC ¶ 61,054 at P 1277 (July 28, 2023). Clear Creek asserts
this new rule demonstrates the error in the Commission’s decision to
allow SPP to study its affected system request under the NRIS
standard. Clear Creek is mistaken. We have repeatedly held “[a]n
agency’s decision is not arbitrary and capricious merely because it is
not followed in a later adjudication.” Xcel Energy Servs. Inc. v.
FERC, 41 F.4th 548, 560 n.2 (D.C. Cir. 2022); Brooklyn Union Gas
Co. v. FERC, 409 F.3d 404, 406 (D.C. Cir. 2005); MacLeod v. ICC,
54 F.3d 888, 892 (D.C. Cir. 1995). For similar reasons, an agency’s
adoption of a new rule does not retroactively invalidate a prior
adjudication that followed the prior rule. Altamont Gas
Transmission Co. v. FERC, 965 F.2d 1098, 1102 (D.C. Cir. 1992)
(“[A] later change . . . cannot retroactively invalidate a decision that
was sound when made.”). Thus, the Commission’s new rule casts
no doubt upon the reasonableness of its decision in this matter.

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discretion to independent system operators, and to not second-
guess their decisions in that regard.”).
*****
For the foregoing reasons, Clear Creek fails to demonstrate
that the Commission’s decision regarding the assignment of
costs to Clear Creek was arbitrary, capricious, or contrary to
precedent. We therefore deny Clear Creek’s consolidated
petitions.
So ordered.

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