Amicus Curiae Brief — Fed. Energy Regulatory Comm'n v. Elec. Power Supply Ass'n, 135 S. Ct. 2049 (2015) (No. 14-840)

ee

|

FILED

Nos. 14-840 & 14-841

ll 6 2015

7 OF i _ HE CLERK

Supreme Court of the United States

FEDERAL ENERGY REGULATORY COMMISSION,

Petitioner,

v.

ELECTRIC POWER SUPPLY ASSOCIATION, ET AL.,

Respondents.

ENERNOC, INC. ET AL.,

Petitioners,

v.

ELECTRIC POWER SUPPLY ASSOCIATION, ET AL.,

Respondents.

ON WRITS OF CERTIORARI TO THE

UNTTED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

BRIEF FOR ELECTRICITY CONSUMERS AND

DEMAND RESPONSE PROVIDERS AS AMICI

CURIAE IN SUPPORT OF PETITIONERS

SETH P. WAXMAN

Counsel of Record

MARK C. KALPIN

DAVID M. LEHN

SAURABH H. SANGHVI

WILMER CUTLER PICKERING

HALE AND DORR LLP

1875 Pennsylvania Ave., NW

Washington, DC 20006

(202) 663-6000

seth.waxman@wilmerhale.com

TABLE OF CONTENTS

Page

TABLE OF AUTHORITIES ........:cscsscsssscssssecssnessssesessees iii

INTEREST OF AMICI CURIAE..u....0-cccssssssssessseseseseeen 1

SUMMARY OF ARGUMENT ..0....:cccccscscssecsssesscsessssseereve 2

SE AT 6

I. THE STATES’ INABILITY TO EFFECTIVELY

REPLICATE FERC’S EFFORTS CONFIRMS

THAT FERC HAS JURISDICTION To ISSUE

EEN Er eer a eS eee 6

A. The Federal Power Act Provides For

Comprehensive And Effective Federal

Authority Except Where It Reserves

Authority To The States ..0..........ccccccsccsseeceseerseees 7

B. States Cannot Regulate Wholesale

Demand Response...............csscsssssssssserseeseeseseeessers 8

1. Economic demand response ......................-.. 9

2. Reliability-based demand response .......... 15

Il. FERC REASONABLY DECIDED THAT DE-

MAND RESPONSE SHOULD BE PAID THE

LOCATIONAL MARGINAL PRICE ..........-ccccccescceeeeeeeee 19

A. The LMP System Pays Resources

Based On Value Provided And Does

B. Demand Response Provides Equal

Value To Generation In Balancing The

Markets And Thus FERC Reasonably

Decided Not To Discriminate Against

iP csesdaensessenssemnnsansennscenianserenesnrananicentenenantiinmenienenedl 22

rH

TABLE OF CONTENTS—Continued

Page

C. FERC Reasonably Recognized That

Uniform Pricing Would Remove An

Improper Barrier To Demand Re-

sponse Participation .....................-csecseseseeseeeeees 29

D. FERC Properly Rejected EPSA’s Ar-

guments About Potential Abuse..................00+ 31

ee taitcieitseehivsciionshinenisminiiansbbeieninaiasnaisociinieiniciii 32

‘ii

TABLE OF AUTHORITIES

CASES

Page(s)

Arkansas Louisiana Gas Co. v. Hall, 453 U.S.

aT ara iatnctinnrcninciinnsnneccstiincanieanninicnnniantanemninniaiatibeeimnetine 6

FPC v. Louisiana Power & Light Co., 406 US.

Ga ei iteeecncareseseresennsemcosnnnegiesonenesnmissenmeenes 7,8

FPC v. Transcontinental Gas Pipe Line Corp.,

ee I dtiestnreeninsetenritindicniionnininteittinnsescenniinins 8

Morgan Stanley Capital Group, Inc. v. Public

Utility District No. 1 of Smohomish

County, 554 U.S. 527 (2008) .........ccceccscceccsessccsecceseess 27

New York v. FERC, 535 U.S. 1 (2002) .........csccseceseeserees 10

Northwest Central Pipeline Corp. v. State

Corporation Commission, 489 U.S. 493

SET ticnedesiceniceneneeneitsieuituesiniatidianiaateiatiiasedinintaiatadiaeneel 6

Oneok v. Learjet, No. 13-271, slip op. (U.S. Apr.

Si TIITTI si enschoctadieaiinentnrtinicnaeuniatanmainianinaitiiaemasdeabiinpiamastinais 7

Panhandle Eastern Pipe Line Co. v. Public

Service Commission, 332 U.S. 507 (1947)............-+- 7

Permian Basin Area Rate Cases, 390 U.S. 747

oe Wctcscssinsinceniniecnnnceiensinssirncenetninaianmaeninsiinmmainesenneesies 26

ADMINISTRATIVE PROCEEDINGS

Comments of the Electric Power Supply

Association, FERC Docket No. EL15-21-

Fe es St settrctereensmessecesnnemenenemansnmnses 15

iv

TABLE OF AUTHORITIES—Continued

Page(s)

Delaware Public Service Commission

Comments to FERC Regarding D.C.

Circuit May 23, 2014 Opinion Vacating

FERC Order No. 745, FERC Docket No.

RM10-17-000 (July 2, 2014) .20.......eecscsseseseeeereees 14, 17

Notice of Proposed Rulemaking, FERC Docket

Nos. RM10-17-000, EL09-68-000 (Mar. 18,

SRE <tennennrepseemnmeesspeontenssnninenenmmenmnanannens 29, 30

PJM Interconnection, L.L.C., Revisions to the

Reliability Pricing Market and Related

Rules in the PJM Open Access

Transmission Tariff and _ Reliability

Assurance Agreement Among Load

Serving Entities, FERC Docket No. ER15-

RE ee 18

Response of Robert L. Borlick to Professor

Alfred E. Kahn, FERC Docket No. RM10-

I I itinincriciintininitaiiiemnainicisiiatiainpetnicmnnteii 22

ADMINISTRATIVE MATERIALS

SP a cieicncnithinsantersnisinisisenscanscndtanensiintitenenens passim

oS aE 30

Order Accepting Tariff Sheets As Modified,

95 FERC 4 61,306 (May 30, 2001) 200.0... cceeeeeeeees 10

a

TABLE OF AUTHORITIES—Continued

Page(s)

STATUTES AND REGULATIONS

16 U.S.C.

a 6

EERE EER SS anEnmane ren ner one n elm mn meee ey 6

ER eee NERC ee 26

ESE Sree r oe ee ee eee EC EST MONT a TE 6

TEE er ee a Re eT 6

Energy Policy Act of 2005, Pub. L. No. 109-58,

§ 1252(f), 119 Stat. 594, 966 (16 U.S.C.

RE SESE eee en a ee CN 6, 31

I i a 31

RR 10

OTHER AUTHORITIES

Boshart, Glen, Navigant: Absent DR

Participation, PJM Capacity Prices Could

Jump up to 3-fold, SNL Financial (Oct. 6,

2014), at https://www.snl.com/Interactive

X/Article.aspx?cdid=A-29411194-12081.................. 16

FERC, 2010 Assessment of Demand Response

and Advanced Metering (Feb. 2011), at

http//www.ferc.gov/legal/staff-reports/2010

FERC, Assessment of Demand Response and

Advanced Metering (Aug. 2006, rev. Dec.

2008), at http:/Avww-ferc.gov/legal/staff-

reports/demand-response. pdf,..............sseeeeseeee 11, 28

vi

TABLE OF AUTHORITIES—Continued

FERC, Energy Primer: A Handbook of

Energy Market Basics (July 2012), at

Monitoring Analytics, Analysis of _ the

2015/2016 RPM Base Residual Auction

(Sept. 24, 2013), at http//www-.monitoring

analytics.com/reports/Reports/2013/Analysi

s_of_2015 2016 RPM_Base_Residual_Auc

Monitoring Analytics, Analysis of the

2016/2017 RPM Base Residual Auction

(Apr. 18, 2014), at http//www.monitoring

analytics.com/reports/Reports/2014/IMM _

Analysis_of_the_20162017_RPM_Base_Re

sidual_Auction_20140418.pdf................-000s-s-00

Navigant, Carbon Dioxide Reductions from

Demand Response (Nov. 25, 2014), at

http://www.us.com/wp-content/uploads/Car

bon-Dioxide-Reductions-from-Demand-Res

ponse_Navigant_11.25.14.pdf.............csssseseses

NERA Economic Consulting, Jistributed

Resources: Incentives (May 2006), at

http://www.nera.com/content/dam/nera/pub

lications/archivel/PUB_distributed_resour

CEE cnnecrincinnnennnemiinnntennee

PJM, 2012 Economic Demand Response

Performance Report, at http//www.pjm

.com/~/media/markets-ops//-order-745-impa

Ct-ON-ECOMOMIC-AP.ASNX ............0cccccccceceeeceeseeeeees

Page(s)

panene 16

vii

TABLE OF AUTHORITIES—Continued

Page(s)

PJM Manual 11 Energy & Ancillary Services

Operations (Apr. 9, 2015), at http//www.

pjm.com/~/media/documents/manuals/m11.

Synapse Energy Economics, LMP Electricity

Markets: Market Operations, Market

Power, and Value for Consumers (Feb. 5,

2006), at http://www.publicpower.org/files/

PDFs/SynapseLMP Electricity Markets013

INTEREST OF AMICI CURIAE'

Amici curiae Aqua America, Inc., Colonial Pipeline

Co., Comverge, Inc., Cpower Corp., the Calvert County

Board of Education, the Electricity Consumers Re-

source Council, EnergyHub, Inc., Ferrite International

Co., Icetec Energy Services, Industrial Energy Con-

sumers of America, SolarCity Corp., and the University

of Maryland, College Park, submit this brief in support

of petitioners.

Amici are a diverse group unified by a common

theme: the tremendous value of demand response. The

group includes a public school system, a state universi-

ty, an energy pipeline company, a water utility, a solar

power and energy storage provider, an industrial met-

als manufacturer, and two associations representing

industrial businesses. The group also includes demand

response providers, i.e., companies that enable millions

of commercial, industrial, institutional, and residential

electric power consumers to participate in demand re-

sponse programs.

Amici and their customers participate in demand

response in various ways. For example, a factory may

delay a manufacturing process until night, a school may

reduce its lighting in the middle of the day, or a collec-

tion of numerous residential customers may lower their

air conditioning usage remotely on a hot day. The com-

pensation amici have received for their participation in

demand response programs has allowed them to keep

factories open, maintain educational programs that oth-

' No counsel for a party authored this brief in whole or in

part, and no person, other than amici or their counsel, made any

monetary contribution to the preparation or submission of this

brief. Letters consenting to the filing of this brief have been filed

with the Clerk of the Court.

2

erwise would have been eliminated, and lower house-

hold electric bills.

Amici’s participation in demand response has also

promoted important system-wide benefits. Through

demand response, amici help market operators bring

demand into balance with supply on a real-time basis.

Whether by saving a particular regional energy market

hundreds of millions of dollars on a single hot summer

day, lowering a capacity market’s costs by billions of

dollars annually, or making the electricity system more

robust and reliable, demand response provides signifi-

cant value to the electricity markets in which amici par-

ticipate.

For these reasons, amici have a strong interest in

this Court reversing the decision below in its entirety.

SUMMARY OF ARGUMENT

Amici do not repeat all of petitioners’ arguments

but rather expand on two key points. First, States

cannot step into the void left by the decision below.

They are legally incapable of regulating wholesale de-

mand response programs and practically unable to rep-

licate the benefits of such programs through retail-level

programs. Under longstanding precedent of this Court,

this reality strongly supports FERC’s assertion of ju-

risdiction. Second, FERC’s compensation decision

amounts simply to a determination that market opera-

tors should not dispatch more expensive generation

when demand response can cost-effectively balance

supply and demand at the wholesale level. FERC’s

judgment merits substantial deference.

1. The Federal Power Act establishes a comple-

mentary system of state and federal regulation of the

nation’s electricity markets. Stakeholders thus benefit

3

from the relative advantages that both States and

FERC can provide in making the system more effi-

cient, effective, and reliable. In accordance with this

arrangement, this Court has held that it will not inter-

pret the Act to create a regulatory gap. That is, if

States cannot “practicably regulate a given area,” then

federal authority must be available.

The decision below would create precisely such a

gap. Over the last twenty years, large parts of the na-

tion’s wholesale electricity system have come to be ad-

ministered on an interstate basis by independent sys-

tem operators (“ISOs”). These FERC-regulated enti-

ties have achieved significant efficiencies by balancing

supply and demand and ensuring reliability across state

lines. Demand response is a critical tool that ISOs have

used to address challenges in achieving these objectives

in wholesale markets.

States, however, are legally and practically incapa-

ble of regulating these programs in wholesale markets.

In markets administered by interstate ISOs, States

cannot replicate the benefits of wholesale demand re-

sponse programs through programs of their own on the

retail level. It is only at the ISO level that the appro-

priate price signals, dispatch flexibility, and balancing

can occur to realize fully the benefits of demand re-

sponse. Under this Court’s precedent, this inability of

the States to regulate or replicate these ISO programs

supports the reasonableness of FE RC’s jurisdiction.

2. Order 745 is not arbitrary or capricious.

Wholesale energy markets pay resources based on the

value those resources provide, not based on the re-

sources’ costs or profits in offering the services. In this

case, FERC determined that when demand response is

as capable of balancing supply and demand as genera-

tion and is cost effective, an ISO should value it the

same as generation and thus it should be paid the same

amount that generation is paid: locational marginal

price (“LMP”).

This is a reasonable choice. The Electric Power

Supply Association, et al. (“EPSA”) instead asserts

that demand response providers should be paid “LMP-

G,” where “G” represents the retail cost of electricity

that demand response participants do not buy, i.e.,

their cost savings as a result of providing demand re-

sponse. By substantially reducing the compensation

that demand response providers would receive below

the amount that generation receives, EPSA’s approach

would require ISOs to dispatch expensive generation

when demand response was capable of balancing supply

and demand at a cheaper price, thus raising prices for

consumers overall. The Federal Power Act does not

require FERC to adopt such an approach, especially

given that it would result in price discrimination

against demand response providers, and in higher pric-

es for consumers.

EPSA suggests that demand response should be

devalued because purportedly society would lose the

benefit of the productive use to which the demand re-

sponse customer would have put that electricity. But

FERC’s mandate is not to maximize social welfare gen-

erally; it is to ensure just, reasonable, and not unduly

discriminatory rates. This is difficult in light of the

unique and complex challenges of administering nation-

al electricity markets, and so Congress entrusted

FERC with significant discretion in weighing compet-

ing priorities. Because a central mechanism by which

FERC carries out its mandate is facilitating the effi-

cient balancing of supply and demand by ISOs, it is ap-

5

propriate for FERC to focus on the ability to balance

supply and demand in assessing value.

EPSA’s social-welfare argument is flawed in other

respects as well. In many cases demand response

merely shifts productive activity to off-peak hours and

in other cases its effects are entirely intangible. Fur-

thermore, demand response has many positive exter-

nalities that, if anything, make it more socially valuable

than generation, including i increasing system reliability,

lowering wholesale price volatility, and decreasing

strain on the transmission system during peak times.

FERC’s decision is further supported by its deter-

mination that certain barriers, including previous inad-

equate compensation, had been stifling demand re-

sponse participation in wholesale markets. Based on

years of actual experience, FERC reasonably conclud-

ed that compensating demand response in accordance

with its value is necessary to address this under-

utilization and thereby ensure just and reasonable

rates.

Finally, EPSA hypothesizes that Order 745 will in-

crease incentives for abuse, but even if that somehow

were true, it only presents a reason to ensure ISO pro-

tocols are robust to address potential problems—which

is exactly what Order 745 did. It is no reason to under-

compensate beneficial activity.

In sum, Order 745 was well within FERC’s juris-

diction and discretion, and therefore the decision below

should be reversed.

6

ARGUMENT

Il. THE STATES’ INABILITY TO EFFECTIVELY REPLICATE

FERC’s EFrorts CONFIRMS THAT FERC Has Juris-

DICTION TO ISSUE ORDER 745

Petitioners have cogently explained how Order 745

clearly falls within FERC’s “exclusive” authority under

the Federal Power Act to ensure that wholesale rates

and “rates{] and practices ... affecting [wholesale]

rates[] are just and reasonabie,” rather than within the

States’ exclusive authority to regulate retail sales.

Northwest Cent. Pipeline Corp. v. State Corp. Comm’n,

489 U.S. 498, 506 (1989); 16 U.S.C. §§ 824(a), (b)(1),

824d(a) & 824e(a).’ Even if it were unclear hc w these

provisions of the Act applied to Order 745, however,

the Act’s broader structure and the realities of the na-

tion’s energy system would lead to the same conclusion.

Through the Federal Power Act, Congress intend-

ed to create a comprehensive and effective structure

for regulating the nation’s energy system, with FERC

and the States having complementary authorities that

avoided the creation of any regulatory gaps. There is

no exception for demand response. Quite the contra-

ry—Congress has declared that “the policy of the Unit-

ed States [is] that ... unnecessary barriers to demand

response participation in energy, capacity and ancillary

service markets”—that is, the wholesale markets regu-

lated by FERC—“shall be eliminated.” Energy Policy

Act of 2005, Pub. L. No. 109-58, § 1252(f), 119 Stat. 594,

966 (16 U.S.C. § 2642 note). Because fulfilling this in-

tent legally and practically requires demand response

>This Court has an “established practice of citing inter-

changeably decisions interpreting the pertinent sections” of the

Natural Gas Act and the Federal Power Act. Arkansas La. Gas

Co. v. Hall, 453 U.S. 571, 577 n.7 (1981).

7

to exist at the wholesale level, a level at which the

States have no authority or ability to regulate, the de-

cision below would create the very kind of regulatory

“no man’s land” that Congress intended to avert.

FERC, therefore, must have authority under the Act

to regulate demand response at the wholesale level.

At bottom, EPSA is arguing that demand response,

in all its aspects in all its forms, is categorically a mat-

ter of exclusive State concern. This Court has taken a

much more nuanced approach to determining in whose

regulatory domain a particular activity falls. Cf. Oneok

v. Learjet, No. 13-271, slip op. 13 (Apr. 21, 2015). Be-

cause States are necessarily limited in their ability to

fully regulate demand response, it is entirely consistent

with congressional intent that certain aspects of de-

mand response, including those at issue here, be regu-

lated by FERC while others are regulated by the

States.

A. The Federal Power Act Provides For Com-

prehensive And Effective Federal Authority

Except Where It Reserves Authority To The

States

In enacting the Federal Power Act, Congress

““meant to create a comprehensive and effective regula-

tory scheme’ of dual state and federal authority.” F'PC

v. Louisiana Power & Light Co., 406 U.S. 621, 631

(1972) (quoting Panhandle E. Pipe Line Co. v. Public

Serv. Comm’n, 332 U.S. 507, 520 (1947) (citation omit-

ted)). Under this scheme, Congress intended federal

authority “to be broadly complementary to that re-

served to the States, so that there would be no ‘gaps.””

Id.

Thus, “in a borderline case where congressional au-

thority is not explicit [the Court] must ask whether

8

state authority can practicably regulate a given area

and, if ... it cannot, then [the Court is] impelled to de-

cide that federal authority governs,” lest “a “no man’s

land” ... be created.” Louisiana Power, 406 U.S. at 631

(quoting FPC v. Transcontinental Gas Pipe Line

Corp., 365 U.S. 1, 19-20 (1961)). “This congressional

blueprint has guided judicial interpretation of the broad

language defining [FERC] jurisdiction.” /d.

B. States Cannot Regulate Wholesale Demand

Response

A dual approach to demand response not only was

prescribed by Congress but also makes good sense.

Both FERC and the States bring their own relative

advantages to bear on the regulation of demand re-

sponse. On the one hand, States are properly posi-

tioned to make policy judgments regarding the retail

pricing schemes that allow demand response programs

to suit their local needs. On the other hand, demand

response is a critical tool in wholesale markets that only

FERC can regulate.

Consistent with congressional policy, over the past

two decades electricity markets have became more ef-

fective and reliable through the creation of FERC-

regulated interstate ISOs.’ These ISOs are charged by

FERC with balancing supply and demand within the

markets they administer—known as “organized mar-

kets”—on both a real-time and prospective basis, and

with ensuring efficient reliability of the electric grid.

Demand response is a market resource for address-

ing two fundamental problems that have impaired

’ For ease of reference, this brief includes within the category

of ISOs the closely related regional transmission organizations

(“RTOs”).

9

ISOs’ ability to achieve these objectives: the relative

inelasticity of retail demand for electric power, and the

inefficiency of relying solely on generation to ensure

system reliability and resource adequacy. The basic

challenge in solving these problems is to create market

structures for consumers that achieve efficient levels of

demand. In this arena, the States, as discussed below,

are legally and practically unable to function as an ef-

fective substitute for FERC.

1. Economic demand response

Energy markets are characterized by relative ine-

lasticity of electricity demand because consumers gen-

erally pay fixed rates, which respond to wholesale price

changes only long after the fact. As a result, instead of

consumers naturally modulating their consumption in

response to retail price changes to maintain an efficient

balance of supply and demand, ISOs have had to call on

increasingly expensive marginal supply in times of high

demand, which eventually raises retail electricity pric-

es. To remedy this problem, FERC-regulated ISOs

have established economic demand response programs,

in which demand response providers bid into wholesale

energy markets, typically on a day-ahead basis, to re-

duce demand if the market clears at or above their par-

ticular bid price. Such programs thus increase elastici-

ty of demand by enabling the provider’s customers to

experience wholesale price changes and compensating

them at the clearing price for reducing electricity con-

sumption.

States are free to implement, and do implement,

their own demand response programs at the retail lev-

10

el.‘ Such programs generally involve some limited var-

iation in retail pricing that creates a price incentive for

customers to reduce demand in peak hours.’ These

programs are often salutary, but they cannot supplant

wholesale demand response programs in the interstate

markets operated by ISOs. The States are constitu-

tionally incapable of regulating interstate electricity

markets. Indeed, Congress’ motivation for enacting the

Federal Power Act was to address that limitation and

the “gap” in the regulation of electricity markets it cre-

ated. See New York v. FERC, 535 U.S. 1, 5-6 (2002)

(explaining the “Attleboro gap”).

All that States could muster in the absence of fed-

eral regulation of demand response would be a patch-

work of potentially inconsistent regulations and local

demand response programs that could not replicate the

benefits of wholesale economic demand response pro-

* Moreover, FERC has been respectful of the States’ efforts

to regulate retail demand response when approving demand re-

sponse programs at the wholesale level. See 18 C.F.R.

§ 35.28(g 1 iA) (limiting requirement that [SOs accept demand

response bids when “not permitted by the laws or regulations of

the relevant electric retail regulatory authority”); Order Accept-

ing Tariff Sheets As Modified, 95 FERC 61,306, 62,043 (May 30,

2001) (same in approving [SO tariff).

> State-administered demand response programs at the retail

level could include, for example: “critical-peak pricing,” in which

customers pay lower prices in most hours in exchange for paying

very high prices during peak events; “peak time rebates” where

customers are given rebates for reducing demand in certain peak

hours; “time-of-use pricing,” which charges customers different

fixed rates depending on the time of day that the power is con-

sumed; and “real-time pricing,” which exposes the consumer to

changes in wholesale prices directly. See generally FERC, Energy

Primer: A Handbook of Energy Market Basics 47-48 (July 2012),

at http//www.ferc.gov/market-oversight/guide/energy-primer.pdf.

11

grams regulated by FERC and implemented by [SOs

at the interstate level.

The critical question in facilitating economic de-

mand response is determining how to pay for the com-

pensation to customers that is necessary to reduce de-

mand throughout the wholesale market. Demand re-

sponse in a given regional organized market benefits all

of its ratepayers. An ISO, therefore, is ideally posi-

tioned to account for the total costs and benefits of such

compensation.

EPSA argues that this compensation could come

from state-regulated load-serving entities (“LSEs”)—

entities that supply power to end-use consumers—

which could set up demand response programs with

their retail customers. See EPSA Br. in Opp. 31 (argu-

ing that “traditional public utilities and competitive

power suppliers that purchase power in the wholesale

market and then re-sell it to their retail customers can

contract with retail customers and offer them incen-

tives to reduce their demand consistent with state reg-

ulation, which will in turn, allow those load-serving en-

tities to reduce their purchases in the wholesale mar-

ket”). But this simplistic assertion ignores key practi-

cal realities of the markets. As other amici have recog-

nized, the scheme EPSA lays out likely could not be

dispatched by the ISO or directly integrated into the

market-clearing price, limiting the ability of such a de-

mand response program to compete with generation

effectively. See NRG Cert. Amicus Br. 9; EnerNOC

Br. 40.

Moroever, FERC has recognized the “long-

standing” and “difficult to address” problem that utili-

ties are unlikely to encourage their customers to reduce

demand. FERC, Assessment of Demand Response and

12

Advanced Metering 72 (Aug. 2006, rev. Dec. 2008)

(“2006 FERC Report”), at http//www-ferc.gov/legal/

staff-reports/demand-response.pdf; see also FERC,

2010 Assessment of Demand Response and Advanced

Metering 47 (Feb. 2011), at http//www_-ferc.gov/legal/

staff-reports/2010-dr-report.pdf (reiterating concern).

Utilities are generally paid as a function of the total

power they distribute; accordingly, reducing power

sales will either reduce their revenue, which they obvi-

ously do not want, or cause them to petition for rate in-

creases. Furthermore, even LSEs that are not utilities

may not have the necessary price incentives. LSEs are

often indifferent to short-term wholesale price increas-

es because they either own their generation (if vertical-

ly integrated), enter into fixed-price contracts with

generators, or have otherwise largely hedged their

power purchases. Thus, LSEs may not immediately

see the necessary price signals for their customers to

reduce demand.

As even a major generator and LSE has noted, in-

dependent demand response providers create essential

competition to overcome the traditional reluctance of

utilities and LSEs to facilitate demand response. See

NRG Cert. Amicus Br. 10. In wholesale markets, third-

party demand response providers have enabled cus-

tomers to manage their electricity usage and coordinat-

ed their participation in demand response programs in

order to provide significant benefits to their customers

and all ratepayers in those markets. However, LSEs

have a financial disincentive to allow third-party provi-

sion of services in their service territory in addition to

the disincentive to reduce demand for electricity. It is

13

not clear how EPSA’s scheme would permit any com-

petition in the aggregation of demand response.°

Nor would the States within organized interstate

markets be positioned to provide this compensation

themselves. The benefits of such compensation would

be diffused across all States within the same organized

market but the cost would be concentrated within the

single State implementing the program. States are

generally reluctant to impose the full costs of demand

response programs on their own ratepayers when those

ratepayers will not capture all the benefits of the in-

vestments. See NERA Economic Consulting, Distrib-

uted Resources: Incentives 11 (May 2006), at http://

www.nera.com/content/dam/nera/publications/archive 1/

PUB_distributed_resources_8.2006.pdf (discussing in-

efficiencies due to the misalignment of costs and bene-

fits of demand response).’

State-level dynamic pricing programs, whereby re-

tail prices vary somewhat based on the time of day or

market conditions, would not solve the problem, either.

Most of these dynamic pricing programs are generally

economically equivalent to a compensation-based pro-

gram, in that a utility or LSE pays the consumer a re-

bate for reducing demand during a peak period. Thus,

these programs would suffer from the same problems

° And even if somehow, against their economic interest, LSEs

did permit participation by third-party demand response provid-

ers, a diverse multitude of LSE programs with potentially conflict-

ing requirements would severely hinder any such participation.

"A State served by a vertically integrated utility could pro-

vide such an incentive, as the State’s ratepayers would also fully

internalize the benefits of lower prices and reduced congestion

resulting from the demand reduction. But these States lose out on

the efficiencies that sparked creation of the [SOs in the first place.

14

just discussed. Indeed, to the extent that these pro-

grams exist today in States that are part of organized

markets, the relevant LSE or utility often acquires the

compensation for the consumer by offering that con-

sumer’s demand response into the ISO’s wholesale en-

ergy markets."

More generally, fully dynamic pricing (that is,

where consumers are exposed to the full volatility in

wholesale prices) is neither feasible nor desirable from

a policy perspective. Large and small consumers alike

tend to prefer stable pricing because of their aversion

to price spikes, and States support that preference. In

addition, consumers are always free to contract around

a dynamic pricing scheme by purchasing their power at

a fixed price. Such hedging limits the potential effec-

tiveness of dynamic pricing as a long-term solution.

Moreover it demonstrates that inelasticity of retail de-

mand is not a temporary phenomenon, but rather a

* EPSA disingenuously claims that somehow the elimination

of wholesale demand response programs “may benefit State de-

mand response initiatives.” EPSA Br. in Opp. 29-30. EPSA sup-

ports this assertion with concerns by certain States regarding

FERC’s proposed compensation scheme. Jd. But whether a State

may express concerns with a particular wholesale compensation

scheme is entirely distinct from whether the State would prefer to

see the wholesale demand response programs eliminated altogeth-

er. In fact, some of the very States on which EPSA relies express-

ly confirm the importance of wholesale demand response to their

initiatives. See C.A.J.A. 386 (recognition by Public Utilities Com-

mission of Ohio of numerous benefits of “demand response re-

sources participating in the real-time energy market”); Delaware

Public Service Commission Comments to FERC Regarding D.C.

Circuit May 23, 2014 Opinion Vacating FERC Order No. 745,

FERC Docket No. RM10-17-000 (July 2, 2014) (urging FERC “to

pursue vigorously all available means for seeking reversal” of the

decision below).

15

fixed feature of the electricity market that must be ad-

dressed by wholesale-level demand response programs.

2. Reliability-based demand response

Electricity supply must be available when needed.

To ensure short-term reliability and long-term adequa-

cy of supply, many ISOs manage not only energy mar-

kets, but also capacity markets.’ In capacity markets,

LSEs traditionally pay generators, through an auction,

for the commitment to produce power on the ISO’s re-

quest. The auctions generally occur long before the ca-

pacity is needed, to encourage the maintenance or

building of sufficient generation capacity. Fulfilling

these commitments can be expensive, and the resulting

generation is often inefficient. In some cases, genera-

tors are paid substantial sums to maintain or build

power plants that might run only a few hours in an en-

tire year.

ISOs have created other demand response pro-

grams to help ensure short-term reliability and long-

term resource adequacy in their electricity markets. In

these programs, demand response providers commit,

months or years in advance, to reduce demand when

called. These commitments can then be offered into the

capacity markets for compensation, just like genera-

7 Although Order 745 directly addressed only the energy

markets, neither the decision below nor the generators before this

Court expressly limited their reasoning to demand response com-

pensation in those markets. Indeed, following the Court of Ap-

peals’ decision, generators rushed to FERC to argue that that de-

cision also deprived FERC of authority to allow demand response

resources to participate in capacity markets. See, e.g., Comments

of the Electric Power Supply Association, FERC Docket No.

EL15-21-000 (Dec. 4, 2014). It is therefore appropriate for this

Court to consider the impact its decision will have on demand re-

sponse participation in the capacity markets.

16

tion. ISOs appropriately have recognized that having

demand response providers on stand-by to reduce de-

mand during periods of high usage is more efficient

than building excess power plants that may run only a

few hours in a year.’°

As with economic demand response, States are le-

gally incapable of regulating reliability-based demand

response in organized markets. See supra p. 10.

And again, States are unable to replicate the bene-

fits of reliability-based demand response programs

through programs of their own. Currently, ISOs decide

whether to ensure system reliability by dispatching

marginal generation or demand response, and they do

so on an interstate basis. For example, PJM can com-

pensate for a temporarily downed generator in Penn-

sylvania by calling on commitments by customers in

Maryland to lower their consumption. Similarly,

'° This benefit of demand response is most visible in its effect

on capacity market prices. One independent analysis calculated

that, without demand response, capacity prices for the 2017/2018

delivery year could have tripled in certain PJM zones. See

Boshart, Navigant: Absent DR Participation, PJM Capacity

Prices Could Jump up to $-fold, SNL Financial (Oct. 6, 2014), at

https://www.snl.com/Interactive X/Article.aspx ?edid=A-29411194-

12081. Moreover, removing demand response in PJM would in-

crease system-wide capacity costs by up to $9 billion for that same

year. See FERC Pet. 32; EnerNOC Pet. 29-30. Having to redo

capacity auctions in PJM for 2016/17 and 2015/16 would potentially

increase costs by $10 billion and $14 billion, respectively. See Mon-

itoring Analytics, Analysis of the 2016/2017 RPM Base Residual

Auction 37 (Apr. 18, 2014), at http://www.monitoringanalytics.com/

reports/Reports/2014/IMM_Analysis_of_the_20162017_RPM_Base

_Residual_Auction_20140418.pdf; Monitoring Analytics, Analysis

of the 2015/2016 RPM Base Residual Auction 5 (Sept. 24, 2013), at

http//www.monitoringanalytics.com/reports/Reports/2013/Analysis

_of_2015_2016_RPM_Base_Residual_Auction_20130924.pdf. And

these figures are just for a single organized market.

17

through the capacity market mechanism, an interstate

ISO can ensure long-term resource adequacy by balanc-

ing a lack of generation capacity in one State with de-

mand response resources in another State. Thus, to be

effective in ensuring reliability in an organized market,

demand response resources must participate at the

ISO-level.

For this reason, while States in organized markets

may have their own reliability-based programs, those

programs likely could not exist if demand response

could not participate in FERC-regulated capacity mar-

kets. Those programs, generally operated by state util-

ities, function much as private demand response aggre-

gators at the wholesale level, permitting their custom-

ers to act as demand response resources and then offer-

ing the aggregated resources into ISO capacity auc-

tions in return for compensation. Such programs are

cost-effective largely because this capacity market par-

ticipation offsets the state utilities’ capacity obligations

in ISO auctions.

Indeed, recognizing that the decision below has en-

dangered States’ ability to fund their own programs,

States in organized markets have voiced strong opposi-

tion to the decision. See, e.g., Joint States Br. 23-24

(explaining that Maryland’s and Pennsylvania’s demand

response programs have relied in significant part on

PJM capacity market revenues for funding); Delaware

Public Service Commission Comments to FERC Re-

garding D.C. Circuit May 23, 2014 Opinion Vacating

FERC Order No. 745, FERC Docket No. RM10-17-000

(July 2, 2014) (noting that Delaware’s $26 million Del-

marva program and statutory efficiency goals are now

18

in jeopardy because of potential inability to access de-

mand response in wholesale markets).''

+ * *

Before the decision below, the implementation of

various kinds of demand response programs reflected

the approach Congress envisioned of complementary

state and federal regulation. Those programs also built

on the tremendous advances of the past decades, in

which interstate ISOs have realized substantial effi-

ciencies across state lines. States cannot regulate these

ISO demand response programs, nor can they replicate

them with programs of their own. Thus, the decision

below creates a regulatory no-man’s land and threatens

to unravel the progress that these ISOs have achieved.

The Federal Power Act does not require this result.

'' After the Court of Appeals’ ruling, PJM proposed allowing

LSEs to use demand response to offset their ISO capacity obliga-

tions, while barring independent demand response aggregators

from bidding into the market. See PJM Interconnection, L.L.C.,

Revisions to the Reliability Pricing Market and Related Rules in

the PJM Open Access Transmission Tariff and Reliability Assur-

ance Agreement Among Load Serving Entities, FERC Docket

No. ER15-852-000 (Jan. 14, 2015). FERC rejected this proposal,

which PJM conceded would have eliminated the providers that

“have historically accounted for a majority of the demand response

registered in PJM.” Jd. at 3. The proposal was both legally and

practically defective. There is no basis in the Federal Power Act

to conclude that FERC has authority to regulate demand response

programs provided at the wholesale level by LSEs but not by oth-

er entities. Moreover, as discussed above, demand response pro-

viders create essential competition to overcome the reluctance of

LSEs and utilities to offer demand response. PJM itself described

its proposal as only a “stop-gap” program that is inferior to the

status quo, and recognized that demand response participation

“could be substantially lower under this proposal than it has been

historically.” Jd. at 2-3.

19

I. FERC REASONABLY DECIDED THAT DEMAND RE-

SPONSE SHOULD BE PAID THE LOCATIONAL MARGINAL

PRICE

Order 745 is reasonable. FERC properly deter-

mined that when demand response is as capable as gen-

eration of balancing supply and demand and is cost-

effective, an ISO should value it the same as generation

and thus it should be paid the same amount that gener-

ation is paid: the LMP, or locational marginal price.

EPSA instead argues that, even when the above

conditions are met, FERC was required to value de-

mand response less than generation, namely, as a LMP

minus the avoided retail cost of electricity, G. But

EPSA’s argument rests on a cramped characterization

of economic efficiency—which includes the factors it

wants but ignores the rest—that is not required by the

Federal Power Act. Particularly in light of the com-

plexities of the electricity markets, FERC has ample

discretion in weighing different considerations in its

ratemaking. FERC’s judgment was based on its rele-

vant expertise and experience; it merits substantial

deference.

A. The LMP System Pays Resources Based On

Value Provided And Does Not Inquire Into

Costs

EPSA insists that the price paid to demand re-

sponse participants in wholesale energy markets should

reflect those participants’ costs. But that is not how

pricing in wholesale energy markets works. The stand-

ard wholesale price paid to power generators reflects

the value of the electricity they provide, not their costs.

Under the locational marginal pricing system in de-

regulated markets, generators typically provide offers

20

that indicate the minimum price they would need to be

paid to generate a particular quantity of load at a par-

ticular location and at a particular moment in time.”

Based on these signals and other constraints like

transmission availability, the ISO identifies the lowest

cost method of serving the load throughout the inter-

state electricity grid it manages. It does so by calculat-

ing, at every point in the system, the instantaneous

marginal cost of serving the last unit of load required at

that location, even if some proportion of the load (be-

fore the last unit) could be served at a lower cost. This

is referred to as the locational marginal price, or

“LMP.” The LMP then serves both as a dispatch signal

and the market-clearing price: any generator whose of-

fer at a particular location is at or below the LMP is

dispatched by the ISO and paid LMP by the LSE for

the electricity they receive from the generator.

Because costs of generation vary significantly

across generators, the marginal cost of supply can be

steeply increasing, particularly during times of peak

load. In these circumstances, most generators in the

system—certainly those that bid below the market-

clearing price—will be paid more than their original of-

fers, and thus more than their cost, upon dispatch.” As

FERC explains, in determining appropriate compensa-

tion it generally does not “inquire into the costs or ben-

efits of production for the individual resources partici-

pating as supply resources.” Order 745 62 (EnerNOC

'2 See generally Synapse Energy Economics, LMP Electrici-

ty Markets: Market Operations, Market Power, and Value for

Consumers (Feb. 5, 2006), at http//www.publicpower.org/files/

PDF s/SynapseL MP Electricity Markets013107.pdf.

'3 Thus, even though [SOs may generally require generators

to base their offers on their actual costs, that does not mean that

generators are paid on the basis of their actual costs.

21

Pet. App. 186a). As a result, if the LMP is $150/MW, an

efficient baseload plant that produces power for

$15/MW will receive the same compensation as the inef-

ficient plant producing it for $150/MW. The more-

efficient generators get to pocket the difference be-

tween their cost and the LMP as profit.

Therefore, the LMP system in deregulated mar-

kets compensates resources based on the value they

provide, not the costs they incur. LMP is a measure of

that value because it represents the amount the system

would have to pay the next resource to offer the same

generation if the cheaper one were to disappear.

EPSA is wrong to focus on whether demand re-

sponse customers in essence “do better” than genera-

tors because they also avoid the retail cost of electricity

not bought, “G.” The avoided electricity cost for de-

mand response participants is just one part of the in-

ternal calculus that a customer will consider when as-

sessing whether to offer demand response, alongside

numerous other costs such as comfort and convenience

(especially for residential customers), business inter-

ruptions, investment in metering technology, and over-

time. Indeed, everyone in the market has costs and

benefits associated with their participation, and so

more-efficient generators “do better” than less-efficient

ones since all generators are paid LMP. Just as FERC

generally “does not inquire into the costs or benefits of

production” of generation resources, it should not “sin-

gle out demand response resources for adjustments to

compensation,” so long as the value of the resource to

the ISO is the same. Order 745 ¢ 62 (EnerNOC Pet.

App. 186a).

22

B. Demand Response Provides Equal Value To

Generation In Balancing The Markets And

Thus FERC Reasonably Decided Not To Dis-

criminate Against It

The question FERC grappled with, then, was

whether demand response offers equal value to genera-

tion to the ISO in the relevant sense. FERC rightly

and reasonably determined that it does, and so pay-

ment of LMP is appropriate.

1. Demand response provides equal value to the

ISO because an incremental megawatt of load can

equally be supplied by one megawatt of generation or

one megawatt of demand response. See Order 745 4 55

(EnerNOC Pet. App. 181a) (“Generation and load must

be balanced by the RTOs and ISOs when clearing the

day-ahead and real-time energy markets, and such bal-

ancing can be accomplished by changes in either supply

or demand.”). Or, as even an expert supporting EPSA,

Dr. Robert Borlick, put it before FERC, “economic de-

mand response and generation are equivalent balancing

resources.” Response of Robert L. Borlick to Professor

Alfred E. Kahn 4, FERC Docket No. RM10-17-000 (Oct.

9, 2010) (capitalization omitted).

As discussed above, FERC has encouraged the de-

velopment of ISOs in deregulated markets because

their ability to balance supply and demand across state

lines improves efficiency and thus helps ensure just and

reasonable rates. So FERC reasonably can focus on

the resource’s ability to balance supply and demand in

assessing its value. Providing for demand response to

be compensated at less than generation would improp-

erly force ISOs to discriminate against demand re-

sponse, requiring ISOs to choose a more expensive way

23

to balance supply and demand. The Federal Power Act

does not require that result.

An example helps to demonstrate how an LMP-G

approach improperly would force the ISO to discrimi-

nate against demand response, ultimately to the detri-

ment of consumers. Suppose that after using genera-

tion to balance 1000 MW of load, an ISO must procure

resources for an additional 10 MW of load. Incremental

generation offers are $110/MW for the next 5 MW and

$120/MW for the next 5 MW after that. There is also a

demand response resource that, after considering the

costs of an interruption to its operations, is willing to

provide 10 MW of demand reduction in return for

$100/MW. G is $30/MW.

Under Order 745, the ISO would see that the

$100/MW demand response offer provides the cheapest

resource to balance the load. But before dispatching it,

the ISO would confirm, pursuant to Order 745, that the

demand response offer passes the net benefits test.

FERC required this test to address the “billing unit

effect,” in which in certain circumstances, it may be in-

efficient to dispatch demand response, even if it is the

cheapest resource, because it would reduce the load

base. See Order 745 4¥ 51-53 (EnerNOC Pet. App.

178a-179a) (explaining billing unit effect). If the test is

passed, the demand response will be dispatched, and

LMP will be $100/MW, whereas LMP would be

$120/MW without demand response. The 1000 MW of

generation and 10 MW of demand response will be paid

this $100/MW, while the 1000 MW of load receiving the

generation will pay $100/MW plus an additional $1/MW

“uplift” to account for the reduction in load base by de-

24

mand response.’ The net benefits test ensures that

this uplift will be lower than the reduction in LMP

caused by the demand response—here, the $1/MW up-

lift would be less than the $20/MW increase in LMP ab-

sent demand response—and thus that demand response

is dispatched only when it results in lower costs for the

system overall.

EPSA suggests that under its LMP-G approach,

the demand response resource would be paid $70/MW

in this example, rather than $100/MW. But that’s not

what would actually happen. Rather, the demand re-

sponse resource had determined that it was willing to

provide demand response only if it is paid at least

$100/MW—that was the basis of its prior hypothetical

offer—and that position would not be any different un-

der EPSA’s approach. So, under EPSA’s approach, the

demand response resource would have to increase its

offer from $100/MW to $130/MW, ensuring that it will

'* The reason for the uplift payment is, in short, that supply

counts both generation and demand response, but load counts only

the demand for generation. Without demand response, there

would be 1010 MW of supply (all generation) paid for by 1010 MW

of load, and so a perfect match between the two sides. If demand

response is dispatched, however, the supply side remains 1010 MW

(now 1000 MW of generation plus 10 MW of demand response), but

the load side is reduced by the amount of demand response and is

thus just 1000 MW—since, by definition, demand response re-

sources are not using the supply of power. Because demand re-

sponse resources cannot be charged for the power they are not

using, but all supply resources must still be paid LMP even if de-

mand response is dispatched, the load base has to cover the differ-

ence. This difference is the uplift, and it is calculated by evenly

allocating the amount of the payment owed to the demand re-

sponse providers across the load base. In this example, the total

payment to demand response would be $1000 (10 MW x $100/MW).

Allocating that payment over 1000 MW of load yields an uplift

payment of $1/MW.

25

be dispatched only when its compensation would at

least match its requirement of netting $100/MW. The

result is that the two incremental generation offers will

be dispatched instead of demand response, LMP will be

$120/MW, and the load receiving the generation will

pay $19/MW more than under Order 745.

Properly understood, then, the issue is not whether

demand response should be paid more as a general mat-

ter; as the example shows, demand response customers

will invariably adjust their offers so that they are paid

at least what they need to justify the interruption. In-

stead, the question is whether an ISO should discrimi-

nate between two equivalent ways of balancing supply

and demand, valuing demand response less and thus

increasing system costs by dispatching demand re-

sponse at the price it is willing to be paid only when the

next unit of generation is more expensive by at least G.

There is no reason for such discrimination. As dis-

cussed, demand response is as capable of balancing

supply anc demand as generation is. Moreover, alt-

hough demand response lowers the load base, the net

benefits test ensures that the uplift would be more than

offset by the reduction in LMP, and the dispatch of de-

mand response is thus efficient.

2. In arguing that FERC unreasonably deter-

mined that ISOs should not discriminate against de-

mand response, EPSA and its supporters fixate on one

particular sense in which the dispatch of demand re-

sponse may differ from the dispatch of generation:

when demand response is dispatched, society may in

some cases lose the value of whatever productive use

the demand response provider (or more precisely, its

customers) would otherwise have made of that electric-

ity. Thus, using highly stylized examples, amici sup-

26

porting EPSA below speculated that Order 745 would

cause customers to “forgo socially valuable activity.”

Borlick et al. C.A. Amicus Br. 18. Under EPSA’s ap-

proach, this activity is valued at G because that is the

amount that the demand response provider otherwise

would have paid to engage in that activity.

This argument is flawed. FERC’s mandate is not

to maximize social welfare generally, nor is FERC obli-

gated to adhere to EPSA’s interpretation of economics

textbooks. See Permian Basin Area Rate Cases, 390

U.S. 747, 776-777 (1968) (“rate-making agencies are not

bound to the service of any single regulatory formula;

they are permitted, unless their statutory authority

otherwise plainly indicates, to make the pragmatic ad-

justments which may be called for by particular cir-

cumstances” (quotation marks omitted)); see also Order

745 ¥ 46 (EnerNOC Pet. App. 175a) (noting that FERC

‘is not limited to textbook economic analysis of the

markets subject to our jurisdiction, but also may ac-

count for the practical realities of how those markets

operate”). Rather, in addition to ensuring that rates

are not unduly discriminatory or preferential (which as

discussed, Order 745 does), FERC must ensure that

wholesale electricity rates are just and reasonable. See

16 U.S.C. § 824d.

This is no easy feat: unlike any other market in the

world, electricity markets require continuous and in-

stantaneous balancing of supply and demand, feature a

steeply increasing marginal supply curve, and demand

the utmost reliability in operation in light of electrici-

ty’s importance for basic human necessities. See Order

745 { 56 (EnerNOC Pet. App. 181la) (recognizing “dis-

tinctive” characteristics of electricity markets in ex-

plaining decision). In these complex circumstances,

FERC ensures just and reasonable rates in significant

27

part by relying on ISOs in organized markets to bal-

ance supply and demand effectively and éfficiently

across state lines. Thus, it is entirely appropriate for

FERC to focus on the value demand response provides

in balancing supply and demand when assessing its val-

ue as a supply resource. This determination is owed

“great deference.” Morgan Stanley Capital Grp., Inc.

v. Public Util. Dist. No. 1 of Snohomish Cty., 554 U.S.

527, 532 (2008) (the “statutory requirement that rates

be ‘just and reasonable’ is obviously incapable of pre-

cise judicial definition”).’°

In any event, EPSA is wrong in thinking that dis-

patch of demand response causes the systematic loss of

social value. In many cases, such loss would not occur

or would be entirely speculative. For example, many

businesses have supplies or inventory to accommodate

just such curtailment of electricity consumption. And if

the demand response merely shifts an industrial pro-

duction process from one particularly hot summer

weekday to a cooler weekend, then the social benefits

of that process will still be realized while sparing the

system the costs of highly expensive peak-time power.

In other cases, the social value lost when the demand

response customer reduces consumption may be entire-

ly intangible, such as students sitting in classrooms that

are 1 degree warmer in the summer or an office build-

ing’s decorative water fountain being off for an hour.

'S For the same reason, EPSA missed the point below when it

argued that the LMP-G approach is necessary to ensure that de-

mand response customers see the same price signal as if the elec-

tricity markets had full real-time retail pricing. See EPSA C.A.

Br. 52. Nothing in the Federal Power Act requires FERC to rep-

licate retail pricing signals. FERC is free to determine that an-

other signal better comports with its mandate to ensure just and

reasonable wholesale rates.

28

Nothing in the Federal Power Act requires FERC to

discriminate against demand response because of these

unlikely, speculative, or intangible effects.

EPSA also ignores the countless positive externali-

ties of dispatching demand response and negative ex-

ternalities of dispatching generation that FERC recog-

nized in Order 745. Demand response lowers wholesale

price volatility by reducing the hourly variation in con-

sumption patterns.'© By reducing peak load, demand

response limits strain on shared resources like the

transmission system. It mitigates generators’ market

power by developing an alternative means to supply

load. See Order 745 J 10 (EnerNOC Pet. App. 147a). It

increases reliability by giving ISOs another tool to bal-

ance supply and demand in emergencies that is qualita-

tively different from generation. See id. (EnerNOC

Pet. App. 147a-148a).'’ To the extent it reduces total

load, demand response benefits the environment, and it

also helps promotes the use of renewables like wind and

1 See Order 745 | 10 n.16 (EnerNOC Pet. App. 147a) (“De-

mand response tends to flatten an area’s load profile, which in turn

may reduce the need to construct and use more costly resources

during »eriods of high demand; the overall effect is to lower the

average cost of producing energy.” (quoting ISO-RTO Council Re-

port, Harnessing the Power of Demand How RTOs and [SOs Are

Integrating Demand Response into Wholesale Electricity Mar-

kets)).

'7 FERC has recognized that demand response can be more

effective than generation in responding to emergencies. First, it

can be much quicker. it is often easier to turn off consumption than

to start a new generator. Second, it can be more reliable, because

it is a “statistical resource.” See 2006 FERC Report 119-120. That

is, whereas the failure of a few consumers to fulfill their commit-

ments to reduce consumption when requested has a amall effect on

the relationship between supply and demand, the failure of a gen-

erator to provide power on request has a substantial effect.

29

solar power because it can efficiently plug gaps in those

sources’ otherwise intermittent generation. '® °

Thus, if FERC were to account for the full range of

costs and benefits of demand response, it could well

conclude that LMP undercompensates demand re-

sponse participation in organized markets. Instead,

FERC has decided to focus simply on the value that

demand response provides in balancing supply and de-

mand. That focus, though more specific than it could

be, is reasonable.

C. FERC Reasonably Recognized That Uniform

Pricing Would Remove An Improper Barrier

To Demand Response Participation

FERC’s experience with demand response also

shows that valuing demand response equally to genera-

tion is essential to achieving successful demand re-

sponse programs and is therefore reasonable.

In the notice of proposed rulemaking, FERC found

that despite the benefits they offer, at that point “de-

mand response providers collectively play[ed] a small

role in wholesale markets.” Notice of Proposed Rule-

making { 9, FERC Docket Nos. RM10-17-000, ELO09-

68-000 (Mar. 18, 2010) (“NPRM”) (J.A. 32). With the

experience of “several years of observing demand re-

sponse participation in ISO and RTO markets with dif-

ferent, and often evolving, demand response struc-

tures,” FERC expressed concern that “some existing[]

18 Por example, a recent Navigant study concluded that de-

mand response could reduce carbon dioxide emissions by 2%,

which is 10% of the Environmental Protection Agency’s target of

20% reductions by 2030. See Navigant, Carbon Dioxide Reduc-

tions from Demand Response 1 (Nov. 25, 2014), at http//www.

ieca-us.com/wp-content/uploads/Carbon-Dioxide-Reductions-from-

Demand-Response_Navigant_11.25.14.pdf.

30

inadequate compensation structures have hindered the

development of demand response” Jd. For example,

FERC noted that when PJM went from essentially an

LMP mechanism,’’ demand response dropped by 36.8%.

Id. f 10 (J.A. 33). With Order 745, then, FERC reason-

ably concluded that uniform compensation at LMP was

necessary to spur development of this valuable re-

source. See Order 745 ¥ 57 (EnerNOC Pet. App. 181a-

183a); Order 745-A 4 74 (EnerNOC Pet. App. 92a) (ex-

plaining need for uniform approach).”°

This does not mean, as amici for EPSA claimed be-

low, that FERC “assume[d] that more demand re-

sponse is always better, regardless of the amount.”

Borlick et al. C.A. Amicus Br. 18 (quotation marks

omitted). FERC simply recognized that demand re-

sponse had (at least) equal value to generation in bal-

ancing supply and demand, that existing compensation

schemes discriminating against demand response were

underutilizing this value, and that adjusting the com-

pensation for demand response to be equal to the com-

pensation for generation would thereby ensure more

just and reasonable rates. This is precisely the kind of

policy judgment Congress entrusted FERC to make,

particularly in light of its policy directive that “unnec-

'9 DIM provided for payment of LMP when LMP was at least

$765/MWh and paid LMP minus the generation and transmission

components of the retail rate when LMP was less than $75/MWh.

NPRM f 10 n.33 (J.A. 33).

- Experience has proven FERC prescient. In a report ana-

lyzing the first several months of implementation of Order 745,

PJM found that demand response participation had significantly

increased and that the performance of demand response had “dra-

matically improved.” PJM, 2012 Economic Demand Response

Performance Report, at http://www.pjm.com/~/media/markets-

ops/dsr/20160701-order-745-impact-on-economic-dr.ashx.

31

essary barriers to demand response participation in en-

ergy, capacity and ancillary service market’ shall be

eliminated.” Energy Policy Act of 2005, Pub. L. No.

109-58, § 1252(f), 119 Stat. 594, 965-966 (16 U.S.C.

§ 2642 note).

D. FERC Properly Rejected EPSA’s Arguments

About Potential Abuse

Finally, some of EPSA’s arguments amount to a

claim that Order 745 could be abused, by encouraging

parties to take steps to profit from the compensation

approach in a way that does not lead to actual demand

reductions. This is a red herring. Whenever a regulato-

ry scheme compensates beneficial activity, there will be

possibilities of abuse, whether that activity is demand

response, generation, or something else. It is unre-

markable that compensating demand response provid-

ers substantially less, as EPSA’s proposed LMP-G pric-

ing would do, might reduce the incentive for abuse. But

that is no reason to undercompensate demand response.

Rather, the proper way to address such concerns is

verification and enforcement. As FERC recognized in

Order 745, “demand reductions that are not genuine

may be violations of the Commission’s anti-

manipulation rules.” Order 745 ¢ 95 (EnerNOC Pet.

App. 208a); see 17 C.F.R. § 1.c.2 (prohibiting fraud, false

statements, and manipulation in connection with pur-

chase or sale of electric energy). Moreover, every ISO

has specific measurement and verification protocols de-

signed to ensure that demand response reductions are

genuine. For example, PJM will only compensate those

demand reductions that are “executed in response to

the real-time and/or day-ahead LMP or as dispatched

by PJM and that are not implemented as part of normal

operations.” PJM Manual 11 Energy & Ancillary Ser-

32

vices Operations (Apr. 9, 2015), ch. 10.1, at http//www.

pjm.com/~/media/documents/manuals/m11l.ashx. PJM

further enumerates examples of ineligible demand re-

duction, which include “[slettlements based on On-Site

Generator data if the On-Site Generation is not sup-

porting demand reductions executed in response to ...

LMP,” and “[cjonsecutive daily settlements that are

the result of a change in normal demand patterns.” /d.

Repeat offenders can be suspended and referred to

FERC’s Office of Enforcement. /d.

EPSA in essence argues that Order 745 will in-

crease the likelihood of violations of these rules, and

now wants FERC to throw out the baby with the

bathwater. But FERC is well within its power to be

more exacting, as it is in allowing other beneficial prac-

tices that nonetheless could be abused. Indeed, genera-

tion likewise is vulnerable to market manipulation, and

appropriately subject to compliance monitoring and en-

forcement. Thus, Order 745 properly directed ISOs to

review their protocols in light of the change in compen-

sation, and either explain how their protocols are ade-

quate or propose any necessary changes in their com-

pliance filings. See Order 745 94 (EnerNOC Pet. App.

207a). FERC’s approach is reasonable.”

CONCLUSION

For the foregoing reasons, the decision of the Court

of Appeals should be reversed.

7! EPSA is free to raise any concerns it has with an ISO’s

measurement and verification protocols in those separate proceed-

ings.

JULY 2015

33

Respectfully submitted.

SETH P. WAXMAN

Counsel of Record

MARK C. KALPIN

DAVID M. LEHN

SAURABH H. SANGHVI

WILMER CUTLER PICKERING

HALE AND DORR LLP

1875 Pennsylvania Ave., NW

Washington, DC 20006

(202) 663-6000

seth.waxman@wilmerhale.com