FTC Staff Comment Before the Public Utility Commission of Texas Concerning Rulemaking Regarding Demand Response in the Electric Reliability Council of Texas Market

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PUBLIC UTILITY COMMISSION
OF TEXAS
Rulemaking Regarding Demand Response in the 	) 	Project No. 41061
Electric Reliability Council of Texas (ERCOT) Market 	)
COMMENT OF THE STAFF OF THE FEDERAL TRADE COMMISSION1
March 11, 2013
I. 	Introduction
The staff of the Federal Trade Commission (FTC) welcomes this opportunity to comment on
the Public Utility Commission of Texas (PUC) “Rulemaking Regarding Demand Response in the
Electric Reliability Council of Texas (ERCOT) Market.”2 The PUC invited public comments to
answer a series of questions regarding demand response (DR) as one aspect of the PUC’s
ongoing reliability review. This comment addresses those questions.
The Brattle Group (Brattle),3 the FTC, 4 and many other observers5 have made the case that
DR can improve the efficiency and reliability of electricity markets. For many of the reasons
cited by those observers, the FTC and its staff have long supported allowing DR to compete with
more conventional resources to solve energy market challenges. DR programs give participants
an incentive to reduce or reschedule power consumption when electricity is scarce and
1 This comment expresses the views of the FTC’s Bureau of Economics and Office of the
General Counsel. The comment does not necessarily represent the views of the FTC or of any
individual Commissioner. The Commission, however, has voted to authorize the filing of this
comment.
2 Public Utility Commission of Texas, Project No. 41061, Request for Comments – PUC
Rulemaking Regarding Demand Response in the Electric Reliability Council of Texas (ERCOT)
Market (Jan. 15, 2013), available at
http://interchange.puc.state.tx.us/WebApp/Interchange/Documents/41061_3_747361.PDF.
3 The Brattle Group, ERCOT Investment Incentives and Resource Adequacy (June 1, 2012),
available at
http://www.ercot.com/content/news/presentations/2012/Brattle%20ERCOT%20Resource%20Ad
equacy%20Review%20-%202012-06-01.pdf.
4 See, e.g., Comment of the Federal Trade Commission Before the Arizona Corporation
Commission, Workshop on Retail Electric Competition (Jan. 26, 2009), available at
http://www.ftc.gov/os/2009/01/V090001electricityadvocacy.pdf.
5 See, e.g., S. Borenstein, “The Long Run Efficiency of Real Time Pricing,” 26:3 Energy J. 93
(2005); A. Faruqui and J. Palmer, “The Discovery of Price Responsiveness – A Survey of
Experiments Involving Dynamic Pricing of Electricity” (Mar. 12, 2012), available at
http://ssrn.com/abstract=2020587.

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expensive. DR thereby helps manage peak demand, encourages companies to bid competitively
(by making it less profitable for generators with market power to attempt to raise price by
reducing supply), and reduces price volatility. The considerable untapped DR potential of the
United States is well documented.6 Other organized electricity markets have enrolled a
considerably greater percentage of their potentially responsive consumption in DR than has
ERCOT under the direction of the PUC.7
We encourage the PUC to adopt DR policies that use standard market approaches, allow
competition, and offer accurate price signals to all entities that can contribute to balancing the
quantity consumed and the quantity supplied. One of ERCOT’s fundamental tasks is to balance
demand and supply on a continuous basis. ERCOT can deliver the greatest benefit to Texas
consumers by allowing DR, generators, and energy storage to compete in the energy and
ancillary services markets.8 Established microeconomic principles favor allowing demand to
participate in electricity markets in the tried and true way that demand participates in markets for
other goods. In markets for other goods, price-responsive demand plays a crucial role in
efficiently allocating scarce goods and services. The value of the marginal (incremental) unit of
DR is the cost of using the next cheapest technology to provide the last increment of electric
energy that is needed to match production with customer demand (consumption). A well-
structured market will compensate DR at that value.
Texas’s unique combination of employing smart meters and facilitating competition among
sophisticated retailers allows it to pursue options in ERCOT that may not be feasible or
appropriate elsewhere. Texas has an impressive record of developing and using economic
incentives, retail competition, and smart meters in ERCOT – well-advised practices that we
encourage Texas to continue. Texas’s policy options also differ because, unlike the rest of the
organized markets in the United States, ERCOT has a single regulator overseeing its regional
transmission organization (RTO) and its retail sector, which may facilitate efforts to coordinate
retail and wholesale policy.9 In particular, if Texas offers good incentives for retailers to enroll
consumers in DR programs, it can then harness competition among retailers to offer innovative
DR programs that provide the greatest benefits to electricity consumers.
6 See, e.g., Federal Energy Regulatory Commission (FERC) Staff Report, A National Assessment
of Demand Response Potential (June 2009), available at http://www.ferc.gov/legal/staff-
reports/06-09-demand-response.pdf.
7 Brattle at 91; see also D. Kathan et al., Federal Energy Regulatory Commission Staff Report,
2012 Assessment of Demand Response and Advanced Metering (Dec. 2012), available at
http://www.ferc.gov/legal/staff-reports/12-20-12-demand-response.pdf.
8 Brattle (at 88) makes this well-established point from competition policy.
9 This comment does not attempt to evaluate the advantages and disadvantages of different
divisions of responsibility between state and federal regulators and of different sizes of regional
energy markets. As a practical matter, Texas has a different regulatory model from the rest of
the country – a difference that is unlikely to change soon and is worth remembering when
considering policy decisions.

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Despite Texas’s unique infrastructure and tradition of harnessing competition and economics,
we concur with Brattle that there are opportunities to better accommodate DR in ERCOT. For
example, ERCOT is already pursuing the opportunity to integrate demand bids into its power
market optimization process. These bids allow the buyer to make certain purchases contingent
on the price’s being below a level the buyer specifies. We discuss these opportunities further in
responding to the PUC staff’s DR questions below. Much of this comment encourages the PUC
to give serious consideration to constructive ideas already identified in the Brattle report.
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. The FTC does so through
law enforcement, policy research, and advocacy. For example, in the field of consumer
protection, the FTC enforces Section 5 of the Federal Trade Commission Act, which prohibits
unfair or deceptive acts or practices. In its competition mission, the FTC enforces antitrust laws
regarding mergers and unfair methods of competition that harm consumers. In addition, the FTC
often analyzes regulatory or legislative proposals that may affect competition, allocative
efficiency, or consumer protection, and also engages in considerable consumer education
through its Division of Consumer and Business Education.10 In the course of all of this work, the
FTC applies established legal and economic principles as well as recent developments in
economic theory and empirical analysis.
The energy sector, including electric power, has been an important focus of the FTC’s
merger review and other antitrust enforcement, competition advocacy, and consumer protection
efforts.11 The FTC’s competition advocacy program has produced two staff reports on electric
power industry restructuring issues at the wholesale and retail levels.12 The FTC staff also
10 For an overview of the FTC’s education efforts, see the FTC staff’s comment to the Consumer
Financial Protection Bureau concerning “Request for Information on Effective Financial
Education,” Docket No. CFPB-2012-0030 (Nov. 2, 2012), available at
http://www.ftc.gov/os/2012/11/1211cfpb.pdf.
11 See, e.g., Opening Remarks of the FTC Chairman at the FTC Conference on Energy Markets
in the 21 st 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 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.
12 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 that the FTC staff provided
to various state and federal agencies).

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contributed to the work of the Electric Energy Market Competition Task Force, which issued a
Report to Congress in the spring of 2007. 13
The FTC and its staff have filed numerous comments advocating competition and consumer
protection principles with state utility commissions, state legislatures, professional organizations,
the Federal Communications Commission, and FERC. 14 In particular, we have filed a number of
advocacy comments concerning DR.15 The FTC comments to state policymakers in support of
policies that allow or foster competition and thus benefit consumers.16 The FTC staff submitted
an electricity market comment to the PUC in 1998.17
III. 	Increasing DR in ERCOT
The PUC staff asks: “What additional products and programs could ERCOT develop
to facilitate DR? How should the programs be designed?”
13 That report is available at http://www.ferc.gov/legal/fed-sta/ene-pol-act/epact-final-rpt.pdf.
14 A listing, in reverse chronological order, of FTC and FTC staff competition advocacy
comments to federal and state electricity regulatory agencies is available at
http://www.ftc.gov/opp/advocacy_subject.shtm#uttg.
15 The FTC discussed the implications of microeconomics for DR compensation in Comment of
the Federal Trade Commission Before the Federal Energy Regulatory Commission on Demand
Response Compensation in Organized Wholesale Energy Markets, FERC Docket No. RM10-17-
000 (May 13, 2010), available at http://www.ftc.gov/os/2010/05/100521fercdemand.pdf ; see
also the FTC’s October 13, 2010, follow-up comment in the same FERC proceeding, available
at http://www.ftc.gov/os/2010/10/1010wholesaleenegrymarkets.pdf. The previous year, the FTC
submitted a comment to FERC on FERC staff’s “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.
16 See, e.g., FTC Staff Letter to Hon. Stephen LaRoque, North Carolina House of
Representatives, Concerning North Carolina House Bill 698 and the Regulation of Dental
Service Organizations and the Business Organization of Dental Practices in North Carolina (May
25, 2012), available at http://www.ftc.gov/os/2012/05/1205ncdental.pdf; FTC and U.S.
Department of Justice Comments to Hon. Helene E. Weinstein Regarding New York Assembly
Bill A05596 (To Establish that Certain Services Related to Real Estate Transactions May Be
Provided Only by Attorneys) (June 21, 2006), available at
http://www.ftc.gov/os/2006/06/V060016NYUplFinal.pdf.
17 FTC Staff Comment Before the Public Utility Commission of Texas Concerning Relationships
Between Regulated Electric Utilities and Affiliates Operating in Unregulated Markets (June 19,
1998), available at http://www.ftc.gov/be/v980013.shtm.

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The PUC can reduce costs and increase reliability by ensuring that demand can participate in
its electricity markets, that ERCOT defines relevant property rights appropriately,18 and that
ERCOT’s markets compensate DR accurately. Reducing costs and increasing reliability will
benefit consumers.
DR involves offering incentives for retail customers to reschedule, curtail, or even increase
their electricity consumption to address regional operating (wholesale) challenges such as
scarcities and surpluses. Efforts to get retail customers to address wholesale challenges require
complementary, harmonized approaches in the retail and wholesale markets. Harmonization
allows the development of coordinated products that, for example, give retail consumers
incentives to respond in short order to rapidly evolving wholesale market conditions.19
The Brattle report states: “Enabling large amounts of DR to contribute to efficient price
formation in real-time will require significant changes in market design.”20 We encourage the
PUC to make such changes a priority. We agree with Brattle that “[a] good market structure
provides multiple revenue opportunities, allows DR to compete on a level playing field with
generators to provide the same services, and allows each resource to find its highest-value
combination of uses.” 21 Good policies will allow flexible loads to receive compensation not only
when they help reduce peak demand, but also when they respond to fluctuating output from wind
turbines,22 address temporary scarcities caused by “ramping” constraints on how fast generators
can change output, and offer ancillary services that help keep supply and demand balanced
continuously.
ERCOT runs a sophisticated “security constrained economic dispatch” (SCED) algorithm
that seeks to balance electricity demand and supply at the lowest cost, subject to reliability
(“security”) constraints that require that the system be able to respond to a sudden, unanticipated
increase in consumption or to contingencies such as the loss of a generator. As operated in
ERCOT, SCED generates LMPs every five minutes at each node (i.e., major electric facility) on
the power grid. We suggest that ERCOT configure its SCED to allow DR, energy storage, and
18 For example, correctly defined property rights imply that DR should be compensated at the
locational marginal price (LMP) less the retail price of power. See Comment of the Federal
Trade Commission Before the Federal Energy Regulatory Commission on Demand Response
Compensation in Organized Wholesale Energy Markets (May 13, 2010), supra note 15.
19 Our references to “the market” throughout this comment usually refer to the combined
wholesale and retail electric markets and encompass actions taken at both levels of the market.
20 Brattle at 96.
21 Id. at 95.
22 DR is already under contract to address fluctuating output from wind turbines in the Pacific
Northwest. S. Stroud, Sustainable Industries Blog, “Bonneville Power Taps EnerNOC for
Demand Response” (Feb. 1, 2011), available at
http://www.sustainableindustries.com/blogs/sustainable-industries-blog/2011/02/bonneville-
power-administration-taps-enernoc-demand-respon.

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generation sources to participate and compete on equal terms. We recognize, however, that
ERCOT must consider the cost and feasibility of incorporating such improvements into the
SCED algorithms. SCED algorithms must solve computationally difficult problems quickly
enough for ERCOT to run its market.
New networking and electronics technologies allow smaller loads to receive price signals or
respond to grid conditions at reasonable costs. The PUC should consider how aggregations of
small loads (such as air conditioners) could prove their ability to help balance ERCOT’s
electricity markets reliably enough to participate in SCED. The PUC may wish to consider
whether it is necessary to treat load participating in SCED like generation. Such a requirement
would mean that DR participants would “have to have real-time telemetry, nodal dispatch and
settlement, and probably continuous controllability.” 23 We note that “ERCOT is also
considering allowing aggregated resources (not at a single node) and virtual telemetry.”24 The
PUC’s approach to incorporating DR in ERCOT should reflect clearly defined goals such as
economic efficiency and the avoidance of involuntary blackouts. The best rules to accomplish
these goals can be adopted, given existing technology and future technologies that power
suppliers and retailers could readily develop if there were a supportive market and market rules.
The PUC staff asks: “What mechanisms could ensure that DR deployments
appropriately contribute to price formation rather than price reversal?”
As the Brattle report recommends, the strategies that system operators use to reduce demand
during times of scarcity should be bid into the market at specific strike (activation) prices.
Whenever possible, the strike prices should reflect accurate estimates of the strategies’ costs to
the electric system and to society as a whole. Reducing the generating reserves available to
handle contingencies like equipment failures has costs because it increases the risk of a blackout.
Calling emergency DR that shuts down energy-hungry equipment temporarily denies the owners
the benefit of running that equipment. Emergency DR providers receive compensation (albeit
often a fixed, annual payment) for the possibility that they will bear these costs.
If system operators instead deploy these strategies “out-of-market” (i.e., simply activating
programs that reduce demand by decree), prices will be artificially low, which will reduce the
incentive for demand to participate.25 Brattle rightly emphasizes the importance of “[n]ever
deploying emergency DR at a zero price.”26
As in a conventional market, market participants in ERCOT should be able to get accurate
information about current and expected future market prices and should be able to trade at prices
based on that information. Brattle emphasizes the importance of “timely, ex-ante pricing
23 Brattle at 97.
24 Id.
25 Id. at 99.
26 Id. at 97.

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information that enables price-responsive demand to adjust its consumption.”27 Part of this goal
might be achieved by having smaller or less flexible loads participate in the day-ahead market.
Brattle notes that there already is a proposal for “look ahead” SCED, which is designed to reduce
some DR price uncertainty.28
Brattle also emphasizes the importance of finding a scheme such that “DR that is not in
SCED can respond to prices without depressing prices to levels far below” the strike price at
which they are willing to sell power back to the grid.29 As Brattle observes, ERCOT’s existing
“generation fleet” results in a supply stack (or supply curve) that features an unusually abrupt
transition from typical conditions to scarcity conditions. This supply stack complicates efforts to
obtain timely and robust DR, because there is little warning of scarcity situations. Brattle
elaborates: “Prices are particularly unstable at the edge of scarcity conditions because there is no
width to the power balance penalty curve [in ERCOT], and the rest of the scarcity price schedule
is flat at the price cap. A mere 50 MW change in load caused prices to jump from low non-
scarcity prices to the price cap. Therefore, any shift in system conditions can move prices from
one extreme to the other, no matter what any price-responsive load does.”30 Having a significant
amount of demand bid into the market with an explicit maximum willingness to pay is likely to
ameliorate this situation.
We concur with Brattle that conditions in ERCOT could lead to insufficient incentives for
customers to provide DR if they might provide enough DR to push the price to a non-scarcity
level.31 We are concerned, however, that Brattle failed to mention a subtle but important
inefficiency associated with potential buyer-side market power that cuts in the opposite direction.
If the DR provider remains a major buyer of power, even after some of its facilities provide DR,
then it can have an incentive to provide more than the efficient amount of DR in order to reduce
wholesale electric prices. This result follows directly from the well-known incentive for large
buyers to reduce their consumption relative to what they would consume if they were instead
numerous, small decision-makers.32 Large buyers forgo some purchases in order to reduce the
price they pay for their remaining purchases. Specifically, load-serving entities (LSEs) and other
major power buyers often will have an incentive to keep prices artificially low during periods of
actual scarcity. This could prompt them to buy more than the socially optimal amount of DR
from third-party suppliers. In order to do so, they would have to write contracts with DR
suppliers to make it profitable (on average) to provide DR during hours when the market might
clear at a non-scarcity price. The greater the amount of price-sensitive demand in the real-time
market, the weaker either of these harmful incentives will be. Nonetheless, the PUC should be
27 Id. at 96-98.
28 Id. at 96.
29 Id.
30 Id. at 98.
31 Id. at 96.
32 See, e.g., R. PINDYCK AND D. RUBINFELD, M ICROECONOMICS 373-81 (7th ed. 2009).

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aware of these contrasting incentives and stand ready to take action should either become a
problem.
Some proposals would allow qualified scheduling entities (QSEs) to submit demand curves
that make some purchases contingent on a market-clearing price below a level that the buyer
specifies.33 This is an important step toward making the ERCOT electricity market far more like
a conventional market. Conventional markets focus companies on providing value to consumers
and generally require far less regulatory intervention than is typical in organized electricity
markets.
Typical baseline-rebate approaches to retail DR are intrinsically difficult to operate because
baseline energy use typically is not a well-defined property right. Baseline-rebate DR programs
assign each participating customer a baseline level of power rights based on the customer’s past
consumption and compensate participants who use less than their baseline during scarcity
periods. Typical baseline rights come free, bundled with power use in other periods. This
encourages customers to game the system by using more power during the baseline-setting
periods than they would normally use. 34 Allowing QSEs to express a maximum willingness to
pay is one of several ways around this problem. All of the solutions are fairly similar in
operation. In “buy-your-own-baseline” (“block-and-index”) arrangements, electricity customers
buy the right to use power in the future; each customer then pays or gets refunds at the real-time
price for the difference between the amount of power the customer reserved in advance and the
amount the customer actually consumed. 35 These approaches are easier to implement, offer
better incentives, and are more likely to be sustainable in the long term than having curtailment
service providers (CSPs) bid reductions relative to baseline property rights that were obtained for
free.
33 ERCOT Market Enhancement Task Force on the Technical Advisory Subcommittee, “Real
Time Market Enhancement Strawman V0.1” (Aug. 24, 2012), available at
http://www.ercot.com/content/meetings/metf/keydocs/2012/0830/05_real_time_mkt_enhanceme
nt_strawman_8_24_2012.doc.
34 For further discussion and evidence that even small consumers can respond to these incentives,
see F.A. Wolak, “Residential Customer Response to Real-Time Pricing: The Anaheim Critical-
Peak Pricing Experiment,” Stanford Univ. Working Paper (May 2006), available at
http://www.stanford.edu/group/fwolak/cgi-
bin/sites/default/files/files/Residential%20Customer%20Response%20to%20Real-
Time%20Pricing,%20The%20Anaheim%20Critical-
Peak%20Pricing%20Experiment_May%202006_Wolak.pdf.
35 Letzler proposed incentive-preserving rebates that create incentives nearly identical to Critical
Peak Pricing by creating well-defined, accurately priced property rights. R. Letzler, “Using
Incentive Preserving Rebates to Increase Acceptance of Critical Peak Electricity Pricing,” Center
for Study of Energy Markets Working Paper 162R (2010), available at
http://www.ucei.berkeley.edu/PDF/csemwp162r.pdf.

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The Brattle report raised serious questions about the need for CSPs to bid DR (namely,
demand reductions) as supply into the ERCOT market. According to Brattle, “Given the healthy
retail competition in ERCOT, it may be less important to accommodate CSPs than in other
jurisdictions. It may be that the most appropriate role for a CSP in an energy-only market is as a
subcontractor to an LSE.” 36 Brattle also observed that, compared to CSPs, retail electricity
marketers “can much more easily monetize the expected value of DR if physical hedging through
curtailments allows them to manage their exposure [to periodic extreme prices spikes] with less
financial hedging.”37 Markets for goods other than electricity in which customers offer demand
reductions as a source of supply based on inappropriately priced property rights are extremely
rare.38
Admittedly, allowing CSPs to bid to supply energy and capacity appears to have facilitated
the development of DR in the PJM Interconnection and other organized U.S. electricity markets.
Others have expressed concerns about the rules and incentives for CSPs in those markets39
similar to the concerns that Brattle expressed about the potential regime for CSPs in Texas. The
CSPs that have taken root in the rest of the United States earn much of their revenue from
administratively designed capacity markets.
The PUC staff asks: “How do price-based DR incentives offered by LSEs contribute to
load forecasting errors? What other pricing and rate structures impact the wholesale
market?”
Failure by ERCOT or LSEs to revise load forecasting models to reflect price-responsive
demand can lead to forecasting errors and inefficient dispatch decisions. We note that PJM
already incorporates price-responsive demand into its load forecasts.40 It makes sense to keep
forecasting models up-to-date. It is likely to be far cheaper to generate new demand models than
to discourage price-responsive demand in order to keep old demand models accurate.
Ultimately, nearly all pricing and rate structures at the retail level impact wholesale markets,
because nearly all wholesale demand for electric power is derived from retail demand at any
36 Brattle at 97.
37 Id. at 94 (emphasis in original).
38 Airlines do pay their customers to reduce or reschedule consumption when a flight is oversold.
This is perhaps not surprising, because – as in electricity markets – the commodity (seats on a
particular flight) is considered impractical to store, and the production equipment (airplanes) has
fixed maximum capacity. Rights to airline seats are well defined.
39 See, e.g., J. Bushnell, B.F. Hobbs, and F.A. Wolak, “When It Comes to Demand Response, Is
FERC Its Own Worst Enemy?,” 22:8 Electricity J. 9 (2009).
40 PJM Manual 19: Load Forecasting and Analysis, Revision: 21 (effective Oct. 1, 2012),
available at http://www.pjm.com/~/media/documents/manuals/m19.ashx.

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point in time. 41 Electricity customers typically respond to any dynamic prices they face, such as
by cutting consumption when electricity prices increase. Further, more customers may respond
in the future, and participants may learn to respond more intensively, as they gradually acquire
energy management expertise, equipment, and software.
The PUC staff asks: “Is load participation in the real-time market feasible when
compared to voluntary price response? How does voluntary price response help set pricing
or skew scarcity pricing signals?”
ERCOT proposes to use three models of demand participation that have good incentives and
long track records in other markets. These models are: (1) bidding a maximum willingness to
pay (“load participation”), (2) passively adjusting demand in response to prices (“voluntary price
response”), and (3) direct load control.
Electricity buyers could place explicit bids that offer to buy power at any price below a
maximum willingness to pay. ERCOT can use such bids in its SCED algorithm to allocate
available power as well as to determine the market-clearing price.42 Stock markets, eBay,43 and
second-price, sealed-bid auctions ask buyers to specify a maximum willingness to pay. These
mechanisms can sell items to interested buyers for the lowest price that matches the amount
demanded with the amount supplied at that price. Active bidding by demand also makes explicit
the demand curves that represent potential customers’ combined bids. We emphasize the value
of using a single, integrated market to set electricity prices and deploy resources, which means
there is considerable value in including demand-side resources in the SCED real-time price
formation process.
Decision makers adjust the quantity they demand in response to changes in prices – i.e., they
engage in voluntary price response – in many familiar markets. For example, consumers visit
the grocery store, check prices, consider their preferences, and then decide how much of which
items to buy. Consumers buy fewer grapes when they cost $3.99 a pound than when identical
grapes cost $0.99 a pound. The grocery chain can employ an algorithm to predict volume
41 Energy storage is a minor, albeit growing, example of a source of demand that is not a retail
customer. ERCOT and the PUC could help secure benefits for consumers by taking the growing
role of energy storage into account.
42 To the extent that explicit bidding reduces the need for spending to handle uncertainty about
demand, sharing savings with customers who bid could create an incentive to bid.
43 eBay explains its bidding process as follows: “[W]e suggest that you bid the maximum
amount that you're willing to pay for an item. . . . As the listing proceeds, we compare your bid
to those of other bidders. When you're outbid, we automatically bid on your behalf up to your
maximum bid. We increase your bid by increments only as much as necessary to maintain your
position as highest bidder.” See http://pages.ebay.com/help/buy/bidding-overview.html
(emphasis in original). (Note that eBay uses the term “bid” in the first sentence to mean the
secret maximum price the bidder is willing to pay. Later references to “bid” mean the price
publicly offered into the auction.)

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purchased as a function of price and adjust prices to maximize profits, subject to competition.
Perishable grocery items need to be sold soon after the grocer acquires them. This is similar to
electricity, which must be sold as soon as it is produced because it has generally been cost-
prohibitive to store. Aside from issues of tardy communication of pricing signals and lags in
voluntary DR, there is nothing inherently distortionary in the effects of voluntary price response
on scarcity pricing signals.
Direct load control is an “option” in the financial market sense. 44 A company pays the
electricity consumer a fixed amount to buy the well-defined right (option) to use direct load
control to turn off the consumer’s equipment a few times a year.
The PUC staff asks: “Should economic incentives be developed to stimulate large DR
programs and if so, should the incentives be market based or load-ratio share based
obligations?”
Our discussion above implies that there is a correct economic value of DR and that DR
resources should be compensated at the value they provide (at the margin) in all of the markets in
which they participate. We believe that this is an appropriate foundation for DR policy
development and implementation.
The ERCOT area within Texas is transitioning from a traditional electric market – where
controllable generators handled fluctuations in demand – to a smart-grid-enabled system in
which demand has incentives to respond to fluctuations in supply relative to demand. As we
have noted before, “Future electricity systems will likely have much more wind generation [that
is not as readily controlled as conventional, thermal generators] and empower millions of
consumers to save by helping to solve power system problems through smart grid
technologies.”45 Reasonable policies will obtain the full benefits of DR, smart grid technology,
and demand participation over the next decade. There is far less reason to think that even the
best market design policies can achieve this in the next year or two. Transition policies may
therefore be appropriate.
To the extent that the PUC perceives a need to adopt administrative policies to jump-start
demand participation, it should consider whether it would be appropriate to plan to phase out
those transitional, “jump-starting” policies or to structure them so that they allow a gradual
transition to a more conventional market structure. For example, if Texas were to adopt a
capacity market that allowed demand to participate appropriately, expanded demand
participation could eventually drive capacity prices close to zero and make the capacity market
irrelevant.46 The capacity markets developed by other RTOs have found that, under their
44 Such options are common in financial and energy markets.
45 Comment of the Federal Trade Commission Before the Federal Energy Regulatory
Commission on Integration of Variable Energy Resources, FERC Docket No. RM10-11-000, at
8 (Apr. 8, 2010), available at http://www.ftc.gov/s/2010/04/V100009ferccomment.pdf.
46 Brattle at 113.

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administrative rules, DR can often provide the capacity to handle infrequent, severe scarcity
events more efficiently than conventional generation.
Similarly, as demand-side participation improves, ERCOT and the PUC may be able to phase
out rules and regulations that they adopted initially because the demand side neither received nor
reacted to price signals. These rules often have unintended, undesirable consequences. If an
active demand side eliminates the strongest justification for such rules, then phasing them out
may benefit consumers.
Given that residential and small commercial load accounts for 70 percent of peak load in
ERCOT, 47 it may be constructive for public policy to reduce impediments to cost-effective
investments in DR-enabling equipment for residential customers. Enabling equipment includes
“smart thermostats, switches on pool pumps, and other controls [that] dramatically increase
residential customers’ ability to respond.”48 There is considerable evidence that many electricity
customers are reluctant to make substantial upfront energy investments because they lack funds
or credit to do so, and because many customers will invest only in energy management
equipment that pays for itself quite quickly.49 It seems efficient for public policy to facilitate
utilities’ or electricity retailers’ efforts to offer cost-effective energy management equipment on
terms that consumers find attractive. In a related area, we note that renewable distributed
generation installations by residential customers – investments that can help shave peak
consumption – appear to be more popular with such customers when private firms offer to
finance the investments.50 There is, however, strong reason to believe that customers care about
more factors than just the interest rate.51
Fortunately, competition among retailers is likely to spur innovation in technology, customer
experience, and financing (including on-bill financing). For example, Reliant Energy already
47 Id. at 93.
48 Id. at 94.
49 See, e.g., J. Hausman, “Individual Discount Rates and the Purchase and Utilization of Energy-
using Durables,” 10:1 Bell J. Econ. 33 (1979); S. Frederick, G. Loewenstein, and T.
O’Donoghue, “Time Discounting and Time Preference: A Critical Review,” 40:2 J. Econ. Lit.
351 (2002); K. Gillingham, R.G. Newell, and K. Palmer, “Energy Efficiency Economics and
Policy,” NBER Working Paper 15031 (2009), available at
http://www.nber.org/papers/w15031.pdf.
50 J. Montgomery, “Third-Party Residential Solar Surging in California; Nearly a Billion-Dollar
Business” (Feb. 15, 2013), available at
http://www.renewableenergyworld.com/rea/news/article/2013/02/third-party-residential-solar-
surging-in-california-nearly-a-billion-dollar-business.
51 P.C. Stern, L.G. Berry, and E. Hirst, “Residential Conservation Incentives,” 13:2 Energy Pol’y
133 (1985); S. Benartzi and R.H. Thaler, “Save More Tomorrow: Using Behavioral Economics
to Increase Employee Savings,” 112:1 J. Pol. Econ. S164 (2004).

13
offers the Nest thermostat to some of its customers.52 If an enabling technology offers annual
savings that exceed the annual payments required to pay for it, then there is room for an on-bill
financing deal in which consumers “pay for” installations using a portion of their savings on
energy charges.53 Retailers with good incentives will focus on cost-effective investments, such
as targeting larger residential customers.
The local monopoly transmission and distribution service provider could acquire the not-yet-
paid portion of the cost of standards-compliant enabling equipment from the retail firm when
customers move. The local distribution company could then provide on-bill financing for the
remaining cost of the equipment to the next tenant. This might be a fairer alternative to contracts
with early termination fees that charge customers for equipment that they leave behind. Retailers
could compete to offer products that interface with any installed, standards-compliant equipment.
In the mid-term, the rise of DR will require rethinking the role of generation reserve margins.
Traditional generation reserve margin calculations assume that demand is neither controllable
nor responsive to price, and thus regulators using these calculations historically emphasized the
need for enough physical infrastructure to deal with the highest realization of electricity demand
when most customers pay a time-invariant price. When scarcities and constraints lead to higher
prices that prompt many customers to reduce or reschedule demand, those assumptions are no
longer valid. A market with a functional demand side has far more tools to avoid involuntary
blackouts without the need for regulatory intervention. As the Brattle report suggests, “We
expect [LSEs] to implement these [DR] options more as price caps increase and reserve margins
tighten.”54 Efforts to keep the reserve margin inefficiently high may keep energy prices
artificially low, stunt the deployment of DR, and force electricity customers to pay for excessive
generating capacity. Exposing customers to efficient scarcity prices will encourage them both to
learn appropriate response procedures and to invest in DR equipment. By contrast, allowing the
reserve margin to drop in a market with limited DR exposes customers to the risks of high
electricity prices and blackouts.
The PUC staff asks: “What regulations are needed to ensure residential and small
commercial customers are adequately protected when participating in aggregated DR
programs?”
The rise of consumer-facing electricity technologies poses the kinds of consumer protection
issues that arise in many markets for new technologies. They include protecting consumers from
unscrupulous firms or individuals and ensuring that consumers can make appropriately informed
choices. The FTC addresses such challenges using a variety of tools, including enforcing laws
prohibiting deceptive practices, mandating disclosures and labels, and consumer education.
Interested readers should review FTC comments about consumer protection approaches in
52 Reliant Learn & Conserve Plan (retrieved Feb. 14, 2013), available at www.reliant.com/nest.
53 Letzler, supra note 35, explores a situation in which consumers are likely to have quite
different perceptions of two ways to present economically identical incentives.
54 Brattle at 94.

14
specific contexts relating to retail electricity markets55 and to demand response,56 as well as
general comments the FTC has submitted about consumer testing of disclosures57 and consumer
education.58 We encourage the PUC to consider similar approaches to protecting customers who
participate in aggregated DR programs.
Consumer education can be a public good that benefits all DR retailers and customers
regardless of whether they pay for it. Without public intervention, education is likely to be
undersupplied, since each retailer may not capture the benefits of its education campaign that
accrue to its rivals.59
A competitive retailer that offers a DR program will seek to recruit customers by claiming
that its DR program offers savings. We recommend that Texas consumer protection authorities
take action if advertisements or disclosures regarding savings are misleading or deceptive.
Consumer protection authorities in Texas may find it helpful to consider developing simple, clear
model disclosures that describe actual cost savings, measured fairly. We also recommend that,
to the extent that DR programs produce savings in regulated transmission and distribution
charges, the PUC approve distribution rates that appropriately pass these savings on to residential
customers. These steps will help ensure that smaller customers benefit from DR opportunities.
55 Comment of the FTC Staff Before the New York State Public Service Commission
Concerning Proceeding on the Motion of the Commission to Assess Certain Aspects of the
Residential and Small Non-residential Retail Energy Markets in New York State (Jan. 24, 2013),
available at http://www.ftc.gov/os/2013/01/130125nypsccomment.pdf.
56 FTC comment on FERC staff’s “Discussion Draft of Possible Elements of a National Action
Plan on Demand Response,” supra note 15.
57 Comment of the Staff of the Federal Trade Commission in the Matter of Request for Comment
on Notice of Proposed Rulemaking: Integrated Mortgage Disclosures under the Real Estate
Settlement Procedures Act (Regulation X) and the Truth in Lending Act (Regulation Z), Docket
No. CFPB-2012-0028 (Sept. 25, 2012), available at
http://www.ftc.gov/os/2012/09/1209cfpbmortgagedisclosures.pdf.
58 For an overview of the FTC’s education efforts, see the FTC staff’s comment to the Consumer
Financial Protection Bureau concerning “Request for Information on Effective Financial
Education,” Docket No. CFPB-2012-0030 (Nov. 2, 2012), available at
http://www.ftc.gov/os/2012/11/1211cfpb.pdf.
59 There are additional results about situations in which markets underprovide education that
allows consumers to pay fewer hidden fees to the firm. See X. Gabaix and D. Laibson,
“Shrouded Attributes, Consumer Myopia, and Information Suppression in Competitive
Markets,” 12 Q.J. Econ. 505 (2006).

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IV. 	Conclusion
The FTC staff appreciates the opportunity to submit this comment. If you have any questions
or comments, please feel free to contact John H. Seesel, Office of the General Counsel, at (202)
326-2702, or Robert Letzler, Bureau of Economics, at (202) 326-2912.