FTC Comment Before the Federal Energy Regulatory Commission Concerning the Integration of Variable Energy Resources (VERs) (Docket No. RM10-11-000)

UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Integration of Variable Energy Resources 	) 	Docket No. RM10-11-000
COMMENT OF THE FEDERAL TRADE COMMISSION
April 8, 2010
I. 	Introduction and Summary
The Federal Trade Commission (FTC) appreciates this opportunity to comment on the
Federal Energy Regulatory Commission’s (FERC’s) Notice of Inquiry (NOI) on integration of
variable energy resources (VERs).1 The NOI focuses on (1) potential discrimination against
VERs; (2) existing provisions that could serve as barriers to VERs and to their integration; and
(3) reliability.2 FERC intends the NOI to initiate a general review of how FERC can (or should)
support the integration of intermittent power sources3 into reliable grid operations.4
Electric systems need to balance the quantity of power produced with the quantity
consumed second-by-second to avoid brownouts and surges. Traditional “thermal” generating
technology – including fossil-fueled and nuclear plants – produces power predictably, following
a schedule and a system operator’s instructions to adjust the schedule to deal with equipment
failures, transmission conditions, and fluctuations in consumption. VERs, such as wind and
solar generators, are now becoming increasingly important, and FERC is exploring whether and
how to modify markets and operating procedures to allow such resources to compete to serve
consumer needs at the lowest cost to society5 and to “integrate” them into the carefully
choreographed process of keeping the quantity of power produced in balance with the quantity
consumed. The following comment addresses, inter alia, ways in which FERC might make
electricity market institutions a closer match for VERs’ costs and constraints. We discuss how
this could be accomplished by, for example, establishing new, intermittent electricity products,
1 75 Fed. Reg. 4316 (Jan. 27, 2010), available at http://frwebgate1.access.gpo.gov/cgi-
bin/PDFgate.cgi?WAISdocID=922305154694+1+2+0&WAISaction=retrieve.
2 NOI P 10.
3 “Intermittent” resources such as wind farms are a type of VER. This comment uses the two
terms “variable” and “intermittent” interchangeably.
4 NOI P 13.
5 Costs to society include both (1) the direct costs of building and operating the power system
that are charged to customers and (2) indirect costs from pollution (i.e., externalities).

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or by allowing the aggregation of geographically dispersed VERs in order to make the generation
patterns of the VER aggregation more predictable.
In the NOI, FERC forswears any changes that would discriminate in favor of specific
types of generation6 but notes that the power industry developed with generation sources that
could store their respective fuels (e.g., coal, nuclear fuel, natural gas). As a result, existing rules
– which reflect that historical development – may not be a good match to a future fuel mix that
relies less on storable fuels.7 The NOI describes several recent instances in which FERC has
revised its policies and regulations to allow an increased role for power from renewable
resources. FERC states that it will use responses to the NOI to help determine what more should
be done in recognition of this potential shift in generation sources.
The NOI specifically identifies the following areas for examination: (1) data and
reporting requirements, including the use of accurate weather forecasting tools; (2) scheduling
practices, flexibility, and incentives for accurate scheduling of VERs; (3) forward market
structure8 and reliability commitment processes; 9 (4) coordination and/or consolidation of
balancing authorities;10 (5) the suitability of reserve products,11 together with reforms necessary
to encourage the efficient use of such products; (6) reforms to the capacity markets tasked with
ensuring that enough generation is available to prevent blackouts or brownouts; and (7) changes
in power plant operation on short notice (“redispatch and curtailment”) necessary to
accommodate VERs in real time.
6 NOI P 10.
7 FERC mentions concerns about environmental impacts and the sustainability of the Nation’s
current electricity supply portfolio. Id. P 2. Sustainability concerns can include the balance of
trade and the reliability of fuel supply from nations that are politically unstable or frequently
express views antagonistic to those of the United States.
8 Forward market structures govern trading of power in advance.
9 Reliability commitment processes choose the generators to run (on a minute-by-minute basis),
considering both their cost and the engineering challenges of ensuring that the system stays in
balance even when a generator or transmission line fails.
10 Balancing authorities are the entities that give operating instructions to generating units on a
minute-by-minute basis.
11 Reserve products consist of generating capacity (or customer participation, i.e., “demand
response”) that can be brought on line quickly in order to address unscheduled changes in supply
or demand.

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For the first time, the electricity system is adding a significant number of VERs. FERC
should examine opportunities that would make electricity markets better represent the costs,
constraints, and realities of VERs so as to encourage cost-reducing operational choices and
investments. As FERC points out, VERs face markets for power that developed almost entirely
with generation based on storable fuels. The trading of power generation services that more
closely align with the generation patterns for VERs could enable markets to do a more efficient
job of using VERs and compensating them for their generation. For example, electricity markets
could trade a commodity consisting of a contract to provide (on average) a megawatt of power
over an hour that allows significant flexibility about when the power will arrive within that hour.
Some retail electricity customers may be quite willing to buy this kind of energy for applications
such as recharging electric vehicles and pumping and heating water. We encourage FERC to
consider changing commodity definitions in connection with several aspects of the NOI,
including reserve commitment intervals, imbalance charges, and participation in day-ahead and
in capacity markets.
If FERC chooses not to adjust the portfolio of commodities, another policy option to
facilitate integration of VERs could be to allow geographically dispersed VERs (or combinations
of VERs and dispatchable, renewable generation sources or energy storage devices) to bid as
single units in order to bring the predictability of their generation patterns closer to that of
conventional generators. Of course, if this approach is taken, care must be exercised to avoid a
level of cooperation among VERs that would raise antitrust concerns.
We also discuss elements of the NOI pertaining to improved weather forecasting,
coordination or consolidation of balancing areas, and capacity market reforms. Our comment
indicates that detailed wind forecasting may improve the efficiency of wind generation and the
utilization of reserves. Coordination or consolidation of balancing areas should be keyed to the
geographic scale needed to include VERs whose low-generation periods seldom overlap.
Aggregations of VERs may be positioned to participate in capacity markets more effectively
than individual facilities if the VERs in the aggregation have low-generation periods that are
unlikely to overlap.
II. 	Interest of the Federal Trade Commission
The FTC is an independent agency of the United States Government responsible for
maintaining competition and safeguarding the interests of consumers, both through enforcement
of the antitrust and consumer protection laws and through competition policy research and
advocacy. The FTC often analyzes regulatory or legislative proposals that may affect
competition or allocative efficiency in the electric power industry. The FTC also reviews
proposed mergers that involve electric and natural gas utility companies, as well as other parts of
the energy industry. In the course of this work, as well as in antitrust and consumer protection

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research, investigation, and litigation, the FTC applies established legal and economic principles
and recent developments in economic theory and empirical analysis. The energy sector,
including electric power, has been an important focus of the FTC’s antitrust enforcement and
competition advocacy.12 The FTC’s competition advocacy program has produced two staff
reports on electric power industry restructuring issues at the wholesale and retail levels.13 The
FTC staff also contributed (as did FERC staff) to the work of the Electric Energy Market
Competition Task Force, which issued a Report to Congress in 2007.14 In addition, the FTC has
held public conferences on energy topics, including Energy Markets in the 21st Century (April
10-12, 2007) 15 and Carbon Offsets & Renewable Energy Certificates (January 8, 2008). 16
The FTC and its staff have filed numerous competition advocacy comments with FERC
and participated in FERC technical conferences on market power issues. For example, in March
2007, the Deputy Director for Antitrust in the FTC’s Bureau of Economics served as a panelist
for a technical conference on FERC’s merger and acquisition review standards under Federal
Power Act (FPA) Section 203 (Docket No. AD07-2-000). Similarly, the FTC submitted
12 See, e.g. Opening Remarks at the FTC Conference on Energy Markets in the 21st Century:
Competition Policy in Perspective (Apr. 10, 2007), available at
http://www.ftc.gov/speeches/majoras/070410energyconferenceremarks.pdf. 	FTC merger cases
involving electric power markets have included the DTE Energy/MCN Energy (2001) (consent
order), available at http://wwwftc.gov/os/2001/05/dtemcndo.pdf; and PacifiCorp/Peabody
Holding (1998) (consent agreement), available at
http://www.ftc.gov/os/1998/02/9710091.agr.htm. (The FTC subsequently withdrew the
PacifiCorp settlement when the seller accepted an alternative acquisition offer that did not pose a
threat to competition.)
13 FTC Staff Report, Competition and Consumer Protection Perspectives on Electric Power
Regulatory Reform: Focus on Retail Competition (Sept. 2001), available at
http://www.ftc.gov/reports/elec/electricityreport.pdf; FTC Staff Report, Competition and
Consumer Protection Perspective on Electric Power Regulatory Reform (July 2000), available at
http://www.ftc.gov/be/v000009.htm (compiling previous comments from the FTC staff provided
to various state and federal agencies).
14 See http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-fina-rpt.pdf.
15 Conference materials available at
http://www.ftc.gov/bcp/workshops/energymarkets/index.shtml.
16 Conference materials available at
http://www.ftc.gov/bcp/workshops/carbonoffsets/index.shtml. Other programs have included the
FTC’s public workshop on Market Power and Consumer Protection Issues Involved with
Encouraging Competition in the U.S. Electric Industry, held on September 13-14, 1999
(workshop materials available at http://www/ftc.gov/bcp/elecworks/index.shtm); and the
Department of Justice and FTC workshop on Electricity Policy, held on April 23, 1996.

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comments in December 2009 in FERC’s proceedings on possible elements of a National Action
Plan on Demand Response (Docket No. AD09-10-000)17 and on transmission planning processes
(Docket No. AD09-8-000),18 and in March 2010 on performance metrics for regional
transmission organizations (RTOs) and independent system operators (ISOs) (AD10-5-000).19
The FTC also has commented on FERC’s initiatives to promote wholesale electricity
competition and on various state issues associated with restructuring the electric power
industry.20
III. 	Issues Involved in the Integration of VERs
In this section, we discuss two general observations on the policy setting of the NOI and
then comment briefly on specific aspects of the NOI.
A. FERC’s policies should support competition among technologies to
deliver desired outcomes at the lowest cost to society.
FERC should structure electricity markets to accommodate VERs so that the electricity
system will allow existing generators and new technologies to compete to deliver the greatest net
benefits to society. In the short term, efficient markets require existing plants and firms to
compete to supply power and meet environmental goals and renewable portfolio requirements21
at the lowest cost to ratepayers. In the long term, emerging demand- and supply-side
technologies should be able to compete with incumbent thermal and renewable technologies.
Markets must compensate each technology based on its costs and benefits to society. VERs pose
challenges for electricity markets that differ from the challenges raised by traditional generation
technologies.
17 This comment is available at http://www.ftc.gov/os/2009/12/V100002ferc.pdf.
18 This comment is available at http://www.ftc.gov/os/2009/12/V100001ferc.pdf.
19 This comment is available at http://www.ftc.gov/os/2010/03/100319performancemetrics.pdf.
20 See, e.g., Federal Trade Commission, Comment before the Federal Energy Regulatory
Commission on Wholesale Competition in Regions with Organized Electric Markets, FERC
Docket Nos. RM07-19-000 and AD07-7-000 (Apr. 17, 2008), available at
http://www.ftc.gov/be/v070014b.pdf. A listing of FTC and FTC staff competition advocacy
comments to federal and state regulatory agencies (in reverse chronological order) is available at
http://www.ftc.gov/opp/advocacy_date.shtm.
21 Renewable portfolio standards and other environmental policies are efforts to reduce costs to
society and to make costs to ratepayers better reflect costs to society.

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Historically, electricity markets traded commodities suitable for a system dominated by
predictable thermal generators. The keystone commodity traded on these markets is the
megawatt-hour of power, which consists of one megawatt of energy flowing during every
moment within an hour. In fact, however, this commodity is a bundle of several components,
including (1) a total amount of energy, (2) temporal certainty about when that energy will be
delivered, and (3) the assurance that there will be no need to respond quickly to a change in
output. The move to establish open access transmission and wholesale power markets began the
disaggregation of this energy commodity. The introduction of locational marginal pricing
(LMP) disaggregated the megawatt-hours of power sold in a region into smaller markets that
were split by the physical limits on moving power over the grid. LMP ensures that the
commodities traded on electricity markets better reflect the physical realities of the system.
The expansion of VERs may require further disaggregation or the addition of new
commodities (services) to power markets. This could enable markets to dispatch the system
more efficiently by rewarding the facilities and programs that can supply power and ancillary
services at least cost to society. This, in turn, should prompt more efficient investment decisions.
For example, electricity markets could trade a commodity (service) consisting of a contract to
provide (on average) a megawatt of power over an hour that allows significant flexibility about
when the power will arrive. A 4-megawatt wind farm that is experiencing gusty winds – and
thus expects to produce at an average of 25 percent of its capacity (i.e., one megawatt) during an
hour – could sell this contract. Such a contract could be paired with contracts sold to buyers with
variable demands, so that the system operator could utilize both variable supplies and variable
demands to ensure system stability and reliability. Within this example, buyers could contract
for the lower-cost, variable supply to run hot water heaters, create stockpiles of crushed rock that
can be mixed with concrete, charge plug-in electric or hybrid vehicles, or pursue similar flexible
end-uses. As discussed at several points in the remainder of this comment, trading an electricity
commodity that better reflects the output patterns of VERs could improve integration of VERs in
several aspects of power markets. Demand-side purchases of power with an uncertain schedule
may be an effective way for customers to participate in keeping electricity systems in balance. It
might be more effective than existing approaches that allow customers to sell (as a separate
service) their ability and willingness to reschedule consumption.
Just as RTOs use LMP to address transmission congestion, FERC may wish to consider
whether RTOs should develop nuanced ways to compensate temporal flexibility and certainty.
LMP uses an exquisitely detailed portrait of conditions on the transmission system to price
power in specific places each hour. It increases compensation to the generators that can deliver
power where it is needed most; it also tracks the costs of transmission congestion. LMP is an
economic institution that addresses the physical reality that each transmission line has a limited
ability to move power. Status quo, real-time markets often experience price spikes when there is
a large need for adjustments in power output because only a few plants in the market are capable

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of changing output (“ramping”) quickly enough to meet the change in demand. Further, the
current economic model may not be nuanced enough to optimally deploy and compensate
resources that can react quickly. A comparable economic institution may be needed that
addresses the physical limits on how quickly conventional generators can ramp.
Plants operating at 100 percent of capacity cannot increase output even if they are
capable of ramping quickly. Similarly, energy storage facilities that are not charged cannot
deliver power. A resource can solve a problem only if transmission grid conditions allow it to
get power to the area that needs it. Rapid reaction is likely to have greater value when weather
conditions (such as gusty winds or broken clouds) create greater fluctuations in VERs’ output. A
good institution will both (1) improve incentives to invest in generation, demand response, and
storage resources located in areas where rapid changes in power output are valuable and (2)
encourage resources’ owners to operate them in ways that deliver the greatest benefit to
ratepayers.
Section III.C.2 of FERC’s NOI directly addresses a flaw in current commodity
definitions when it explores a possible change in the current practice of acquiring reserves
(standby generating capacity) in the form of 24-hour (i.e., round-the-clock) commitments. This
requirement for a 24-hour commitment precludes certain intermittent generators from
participating in markets for reserves and unnecessarily raises costs, wasting ratepayers’ money.
For example, solar thermal facilities – which use heat from the sun to boil water to drive
generators – may be able to sell reserves whenever they have heat available, but typically are
unable to generate during the early morning hours. We agree that shortening reserve
commitment intervals would yield a more appropriate commodity to trade that would facilitate
VERs’ participation in reserve markets, increase competition, and thus benefit ratepayers.
Similarly, with regard to NOI Section III.E, FERC should consider the implications of
how electricity markets trade and pay for reserves. Such trades affect both existing generation
and the incentives to develop and introduce new generation and substitute technologies. For
example, energy storage devices that can respond quickly for a limited duration may be less
expensive per unit than those whose response lasts longer. Availability requirements that make
sense for reserves from thermal generators may not make sense for storage devices that need
time to recharge or even hydroelectric plants with a limited amount of water in their reservoirs.
Although it makes sense to price the availability of a thermal plant to provide reserves, it may
make more sense to trade the option to inject a set amount of energy into the grid from a
portfolio that includes energy-limited hydroelectric facilities or storage devices. There are
scenarios in which rapid response by reserves has significant value to grid operators. Prices that
do not reflect the value of both the speed and the duration of response can distort the
development and installation of reserve technologies. Indeed, fast-responding technologies may

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be particularly valuable because, while wind and solar output can drop suddenly, many
conventional generating technologies ramp gradually.
As it considers changing the basic commodities traded in electricity markets, FERC
should evaluate both the benefits of the changes and the one-time cost of altering the
considerable software, institutional and regulatory infrastructure, and human knowledge that
have developed to run the existing system. It may make sense to bear significant short-run costs
to modify markets because running an advanced electricity system with the existing price-setting
rules and muted price signals is likely to be quite inefficient. Future electricity systems will
likely have much more wind generation and empower millions of consumers to save by helping
to solve power system problems through smart grid technologies.
Existing electricity markets already experience price spikes when they need to increase
output from some plants suddenly, and that situation may become far more common when VERs
play a more active role in generation. This suggests paying greater attention to the institutions
that value and compensate generators (and customers) for their ability to deal with sudden
changes in the need for power. Adjusting pricing to reflect the costs to the power system of
abrupt, unpredictable changes in either consumption or generation may create significant social
savings. At the same time, the price charged for consumption that is unusually flexible (in
accepting abrupt changes in supply) might be relatively low because of the lower reliability costs
associated with supplying it.
The NOI does not mention either various forms of dispatchable renewable generation or
alternative ways to achieve policy goals that often prompt investment in VERs. Inappropriate
pricing of VERs that fails to capture the whole social cost of integrating and balancing such
resources may lead to the use of VERs even when renewable, dispatchable generation, 22 energy
efficiency programs, or demand response could meet the same goals at a lower cost to society.
Well-structured electricity markets are technology-neutral systems that reach social goals at the
lowest social cost.
1. 	Scheduling incentives (Section III.B.2) 23
Section III.B.2 of the NOI focuses on FERC’s new approach to imbalance penalties.
Electricity markets charge a facility an imbalance penalty when the facility’s actual output
diverges from its scheduled output. Unexpected changes in a generator’s output create
22 Generation based on some renewable energy sources (including geothermal, biomass, tidal,
and some other hydrokinetic and conventional hydroelectric sources) is not dependent on
weather conditions or time of day and may be dispatchable, much like conventional generation.
23 References to “Section” in the remainder of this comment are to sections of the NOI.

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significant costs and risks for grid operators. Inflexible demand exacerbates these costs.
Imbalance penalties were introduced to discourage the imposition of such costs when a
generator’s deviation from the grid operator’s schedule was an anomaly that might reflect
questionable maintenance and operating decisions. By contrast, wind and solar photovoltaic
output typically varies from minute to minute. The cost of managing output intermittency may
affect the cost effectiveness of investments in wind and photovoltaic facilities. These new
technological realities may justify the consideration of more nuanced and accurate ways to price
unexpected changes in generation output.
FERC’s new approach sets higher penalties for large real-time imbalances and creates a
cap on imbalance penalties faced by intermittent resources. Numerous real-world experiences
corroborate the economic theory’s lesson that charging different prices for the same product
leads to adverse consequences. Trading a new commodity – namely, a megawatt of power over
an hour (on average) that allows flexibility about when the power will arrive – would sidestep
the assumption that sellers promise and buyers expect continuous, uniform delivery, which
necessitates imbalance charges. FERC could consider charging each plant’s contribution to the
cost of keeping the system in balance, determined roughly as follows:
 	Each plant could pay for its share of the system’s physical capacity to respond
to a sudden change in its output by buying options on fast-reacting resources
that can make offsetting changes. Plants would buy these options based on an
analysis of (1) the frequency and magnitude of (and the required speed of
response to) unscheduled output changes from that plant or similar plants and
(2) how these deviations correlate with other deviations from similar plants in
the system. Making this work is likely to require careful and complete
definitions of property rights – a potentially difficult exercise that nonetheless
could be worthwhile if analysis suggested that the benefits of doing so will
outweigh the costs.24
 	A plant would pay the actual cost of increasing or decreasing generation at
other plants when its output changed suddenly. These costs would include
reimbursing customers for the value of lost load should a sudden drop in the
plant’s output cause a blackout.
2. 	Participation in day-ahead market and reliability commitments (Section III.C.1)
24 For example, the combination of the output from a new wind farm and an adjacent, existing
wind farm creates a correlated output fluctuation risk to the system. Appropriate property rights
determine who pays for the new correlated output fluctuation risk in a way that gives wind
developers the right incentives to build new plants.

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FERC asks whether there is any reasonable way for VERs to participate in RTO/ISO day-
ahead markets, given the financial risks entailed and the uncertainty about future weather
conditions. As we noted above, VERs often produce commodities different from those produced
by conventional generators. VERs could easily trade a commodity that better matches their
intermittent output both on day-ahead markets and, potentially, even long-term. For example,
they could engage in bilateral transactions with buyers that can accommodate intermittent
consumption. VERs could sign forward contracts with entities capable of “shaping” intermittent
production to make it predictable (e.g., using onsite energy storage capability).
If it chooses not to adjust the portfolio of commodities, FERC may wish to consider
whether portfolios of geographically dispersed VERs could confidently participate in existing
day-ahead markets, even though individual facilities would have difficulty doing so without a
paired energy storage facility or a demand response partner. If economies of massed reserves25
are significant, networks of VERs could be an effective substitute for pairings of VERs with
energy storage devices at every location. FERC should explore whether there are regulatory
barriers to aggregating such portfolios and whether there should be joint consideration of
transaction costs and antitrust concerns.
B. Efficient institutions create rules and commodities that let consumers and
suppliers play a role in keeping supply and demand balanced.
FERC invites commenters to take a broad perspective on the issue of integrating
intermittent renewable generation.26 Although this NOI understandably focuses on the supply-
side elements of generation and reserves, FERC must keep in mind that integration and
reliability depend on the interaction of supply with demand. Consumers can help balance the
system by responding either to accurate, frequently-varying prices or to signals from system
operators. Such consumer participation programs are likely to be important in integrating VERs.
Consumer participation may be less costly than balancing the system by building and
maintaining fast-reacting power plants. Electric systems generally pay to operate such plants at
their minimum capacity while they are on standby. Demand- and supply-side solutions compete,
and good markets allow them to do so on their respective merits. A policy that puts the entire
onus on the supply side to integrate intermittent generation is likely to be inefficient and more
costly than a balanced approach that uses both sides of the market. The increasing role of VERs
is likely to change the role of demand response by creating more frequent, shorter, and less
predictable opportunities for consumers to adjust or reschedule their consumption in order to
25 James Mulligan, “Economies of Massed Reserves,” 73 Am. Econ. Rev. 725 (1983).
26 NOI P 13.

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help solve challenges facing electricity system operators. For this reason, we encourage active
demand-side involvement as a technique for integrating VERs into the electric power system.
FERC should integrate analysis of how markets and institutions can best harness demand- and
supply-side resources in this context. 27
For example, the value of integrated analysis is apparent in considering FERC’s request
for comments about the implications of using finer intervals in power plant operation schedules.
Shorter intervals are likely not only to accommodate VERs, but also to better match demand
response technologies. Some demand response providers might be unwilling to reduce
consumption over an hour interval but agreeable to commit to such a reduction over a shorter
interval. For example, a customer with a food refrigeration system might be willing to provide
demand response for 15-minute intervals but unwilling to respond for an hour if such a
prolonged shutoff risked exceeding the maximum allowed temperature for foodstuffs.28
C. 	Other Elements of the NOI.
1. 	Data and forecasting (Section III.A)
FERC offers suggestions for better weather forecasting as a way to ease the task of
integrating intermittent generation (and thus to lower costs for consumers). The premise is that
better warnings about fluctuations in renewable generation will facilitate the use of lower-cost
reserves to integrate this generation. We applaud efforts to improve supply forecasts where the
benefits are found to exceed the costs. We note that better micro-forecasting reportedly can be
used to increase the efficiency of wind generation.29 This also could increase productivity and
reduce consumer costs.
A broader perspective is that variability at any stage of production in the power industry
can pose a problem for reliability, because the stability of the system requires that consumption
match generation continuously in real time. Moreover, as we noted in our recent comment on
27 The original FTC staff report on retail electricity markets, issued nearly a decade ago, included
a chapter entitled “Supply and Demand: The Sound of One Hand Clapping” to portray the long-
lived and 	lingering problems created by widespread non-dynamic retail pricing of electric
power. FTC Staff Report, Competition and Consumer Protection Perspectives on Electric
Power Regulatory Reform: Focus on Retail Competition, supra note 13. This has been a theme
of several FTC comments to FERC and to state regulators.
28 This example was previously presented in Section IV of the FTC comment to FERC on
Wholesale Competition in Regions with Organized Electric Markets, supra note 20.
29 Tyler Hamilton, “Laser Sensors for Wind Turbines,” Tech. Rev. (MIT, Nov. 6, 2008),
available at http://www.technologyreview.com/energy/21643.

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the National Action Plan on Demand Response, 30 better forecasting of demand – including the
level and persistence of consumer participation in demand response – would help maintain
reliability at the lowest cost.
2. 	Balancing authority coordination/consolidation (Section III.D)
FERC asks whether small balancing authorities lead to higher integration costs for VERs
and, if so, what should be done. Two potential solutions would be (1) coordination between
small balancing areas and (2) consolidation of small balancing areas into larger areas. We
encourage FERC to examine this question from the perspective that integration of VERs can be
less costly if the geographic scale of the balancing authority is sufficient to include VERs whose
low-generation periods are unlikely to coincide with each other. In practice, selectively
coordinating or combining existing control areas may be a feasible and practical approach to
reducing the costs of integrating VERs.
3. 	Capacity markets (Section III.F)
FERC points out that VERs typically receive less revenue per unit of output than other
sources of generation, both because of their operating characteristics and because they seldom
participate in day-ahead markets (due to the risk associated with VERs’ intermittent character).
The NOI asks whether the existing payment system discriminates against VERs and thereby
constitutes a barrier to VERs’ entry. Although output from a single wind farm is sensitive to the
weather conditions in its location, which vary enormously from day to day, the output of groups
of geographically dispersed VERs acting together as a single generation source is more
predictable. With this increase in predictability, portfolios of output from geographically
dispersed VERs, if allowed to bid as a group, may be sufficiently certain to participate in
capacity markets. Allowing entry into capacity markets should increase competition, but
aggregating facilities raises obvious antitrust concerns. FERC should do appropriate antitrust
analysis of any policies that allow aggregation of firms or outputs.
FERC should consider ways in which capacity markets can support a transition from the
status quo thermal system (with limited demand-side participation and aggressive price
mitigation that substitutes for demand elasticity) to a future system in which VERs and consumer
participation in demand response play a larger role, and in which administrative interventions
such as price caps and capacity markets are less important.
30 Federal Trade Commission, Comment before the Federal Energy Regulatory Commission,
Discussion Draft of Possible Elements of a National Action Plan on Demand Response (Dec. 11,
2009), available at http://www.ftc.gov/os/2009/12/V100002ferc.pdf.