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

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Nos. 14-840 & 14-841

In the Supreme Court of the Ehrited States

FEDERAL ENERGY REGULATORY COMMISSION,

Petitioner,

Vv.

ELECTRIC POWER SUPPLY ASSOCIATION, et ai.,

Respondents.

ENERNOC, INC., et ai.,

Petitioners,

Vv.

ELECTRIC POWER SUPPLY ASSOCIATION, et ai.,

Respondents.

On Writs of Certiorari to the United States

Court of Appeals for the D.C. Circuit

BRIEF OF AMICUS CURIAE

CHARLES J. CICCHETTI

IN SUPPORT OF PETITIONERS

JUSTIN M. GUNDLACH

Hope M. BABCOCK*

Institute for Public Representation

Georgetown University Law Center

600 New Jersey Avenue, NW

Washington, D.C. 20001

(202) 662-9535

babcock@law.georgetown.edu

*Counsel of record

i

TABLE OF CONTENTS

Re SO GRAF BIE EME ceccetnseninsisecinenetinnssinneiien 1

SS GI CITE IID occetnstescvsseccossevsteesentnteseseeste 1

SUMMARY OF ARGUMENT......00000.0....ecceee eens 3

TECHNICAL BACKGROUND ..............cccceceesseeseenes 4

IT ceccetiestcncinentiiinnibeihiaiaiinbiaiiceiccéaiiamtinapicitinanien 16

I. Ordering ISO/RTOs to Compensate

Qualifying Dispatched Demand Reduction at

New LMP Will Yield Economically Efficient

Outcomes for Wholesale Markets. ............... 19

Il. Ordering [SO/RTOs to Compensate All

Dispatched Demand Reduction at a Price

Equal to “LMP-G” Would Yield

Economically Inefficient Outcomes for

a cscemeunionmanaalie 27

III. The Fundamental Economic issue in this

Case Is How Best to Encourage Competition

and Efficiency in Wholesale Markets. ......... 34

I baictinecasonsantiiencumeniinstinsiasdsnimauasinienetl 36

ss

TABLE OF AUTHORITIES

CASES

Am. Paper Inst., Inc. v. Am. Elec. Power Serv.

Corp., 461 U.S. 402 (1983) .......ccccccecsesesseceeseseeees 18

Citizens to Preserve Overton Park v. Volpe, 401 U.S.

Ge EP circsccisnnsinnessnsenssniiannmieniilaaiai 18

Illinois Commerce Comm ’n v. FERC, 576 F.3d 470

Sea eee eh 6

Jersey Cent. Power & Light Co. v. FERC, 810 F.2d

es MN, Se iicicretccnetitnisiintiniesnesuantals 18

New York v. FERC, 535 U.S. 1 (2002)......0..0000000000.. 7

S. Carolina Pub. Serv. Auth. v. FERC, 762 F.3d 41

Sah, CRIA. CEIIE io nncascesinissicnssomesentelsseuisusisijlanaeaaaennaaaennanea 5

STATUTES

Be eee: He icnseccdsnieniaiemiventioisidiiiaeaaee 5, 7

Energy Policy Act of 1992,

Pub. L. No. 102-486, 106 Stat. 2776 ..........00.00000.. 7

Public Utility Regulatory Policy Act of 1978,

Pub. L. No. 95-617, 92 Stat. 3117 «2.0.0.0... eee 7

Regulations

rr ae ES nicerisincisininsibiinitibicniscnteriaiia 13

Order No. 719, Wholesale Competition in Regions

with Organized Electric Markets, 125 FERC 4

61,071, 73 Fed. Reg. 64,100 (Oct. 17, 2008) ...... 13

1

REGULATIONS (CONTINUED)

Order No. 888, Promoting Wholesale Competition

Through Open Access Non-Discriminatory

Transmission Services by Public Utilities;

Recovery of Stranded Costs by Public Utilities

and Transmitting Utilities, FERC Stats. & Regs

§ 31,036, 61 Fed. Reg. 21,540 (1996)................... 9

Order No. 890, Preventing Undue Discrimination

and Preference in Transmission Service, FERC

Stats. & Regs 9 31,241, 72 Fed. Reg. 12,266

ES )

ADMINISTRATIVE MATERIALS

Affidavit of Alfred E. Kahn, attached to Reply

Comments of the Demand Response

Supporters, FERC Docket No. RM10-17-000

ST = TO 17

Comments of Robert J. Borlick, Energy

Consultant, FERC Docket No. RM10-17-000

EE rn 29

Demand Response Compensation in Organized

Wholesale Energy Markets (Supplemental

Notice of Proposed Rulemaking and Notice of

Technical Conference), 75 Fed. Reg. 47,499 (Aug.

eect ddiadanitininasnnsunesdonte 29

Demand Response Compensation in Organized

Wholesale Energy Markets, 75 Fed. Reg. 15,362

(proposed Mar. 18, 2010)........................ 13, 17, 20

1V

OTHER AUTHORITIES

Amory B. Lovins, Saving Gigabucks with

Negawatts, 115 Pub. Utilities Fortnightly, Mar.

Stas Tae incsdenitseuinceenanteceiieniidepnmlitieiplasaniaieniatedatapinaibitataias 11

Amory B. Lovins, The Negawatt Revolution, Conf.

gE ees ae ee ieee 11

Charles J. Cicchetti, Jeffrey Dubin & Colin Long,

The California Electricity Crisis: What, Why, and

| SITS ES Se eee ce 2 ee 5

Electric Power Research Institute, Smart Grid

Demonstration Initiative: 5 Year Update

EERE y VN Serer trees evo etones ere eT 35

Girish Ghatikar et al., Lawrence Berkeley Nat’!

Lab’y, Analysis of Open Automated Demand

Response Deployments in California and

Guidelines to Transition to Industry Standards,

LBNL-6560E (Jan. 2014) ..................ccccccecceseeeees 12

James C. Bonbright, Principles of Public Utility

PRESS NRO ORE TEN fee 5, 6, 21

M.A. Pietter & E. Koch, Lawrence Berkeley Nat’!

Lab’y, Direct Versus Facility Centric Load

Control for Automated Demand Response,

LBNL-2905E (Nov. 2009)..............cccceeccceeeceeseeees 12

Mahdi Behrangrad, A Review of Demand Side

Management Business Models in the Electricity

Market, 47 Renewable & Sustainable Energy

ITEMS HREM Le RE ae 12

New York State Pub. Serv. Comm’n, Staff Report &

Proposal: Reforming the Energy Vision, Case No.

14-M-0101 (Apr. 24, 2014) ........cccccccsceceseseseeceeeees 35

v

OTHER AUTHORITIES (CONTINUED)

Peter Cappers et al., Demand Response in U.S.

electricity markets: Empirical evidence, 35

TEE eR ae 20, 33

Peter Cappers et al., Lawrence Berkeley Nat'l

Lab’y, Market and Policy Barriers for Demand

Response Providing Ancillary Services in U.S.

Markets, LBNL-6155E (Mar. 2013)................... 12

Rahul Walawalkar et al., Evolution and Current

Status of Demand Response (DR) in Electricity

Markets: Insights from PJM and NYISO, 35

I a ee 20

Richard J. Pierce, Jr., A Primer on Demand

Response and a Critique of FERC Order 745, 3

Geo. Wash. J. Energy & Envtl. L. 102 (2012) ... 19

Scott Hempling, Regulating Public Utility

Performance: The Law of Market Structure,

Pricing and Jurisdiction (2013)........................0. 7

U.S. Dep’t of Energy, Benefits of Demand Response

in Electricity Markets and Recommendations for

Achieving Them (Feb. 2006) ......................:..0000 20

INTEREST OF AMICUS!

Charles J. Cicchetti, Ph.D has spent his long

career as an academic and regulator developing

ways to make the provision of electricity more

efficient and cost-effective. Since the early 1970s,

he has advocated for increasing the extent to which

market mechanisms guide resource allocation and

price specification. He has proposed and supported

policies that replace regulation with competition,

with particular emphasis on increasing customer

choices and encouraging competitive market entry

on a level playing field.

Dr. Cicchetti’s career has included positions

as a Professor of Economics and Environmental

Studies at the University of Wisconsin, Chairman

of the Wisconsin Public Service Commission,

Deputy Director of the Energy and Environmental

Policy Center at Harvard University’s John F.

Kennedy School, and the Jeffrey and Paula Miller

Chair of Government, Business and Economics at

the University of Southern California. His most

relevant publications include: Perspective on Power:

A Study of the Regulation and Pricing of Electric

Power, published in 1974; The Marginal Cost and

! As required by Supreme Court Rule 37.6, amicus states that

no counsel for a party authored this brief in whole or in part,

and no counsel or party made a monetary contribution

intended to fund the preparation or submission of this brief.

Pursuant to Supreme Court Rule 37.3(a), amicus curiae states

that all parties have consented in writing to the filing of this

brief.

2

Pricing of Electricity, published in 1977; Including

Unbundled Demand-Side Options in Electric Utility

Bidding Programs (an article co-authored with

William W. Hogan), published in_ 1989;

Restructuring Electricity Markets, published in

2003; and, Going Green and Getting Regulation

Right, published in 2009. Over the past forty-five

years, he has also testified before state, federal,

and international energy regulatory commissions

about how to promote economic efficiency and

competition while also promoting cost causality,

marginal cost, and beneficiaries pay pricing.

Dr. Cicchetti’s interest in the Federal Energy

Regulatory Commission (“FERC” or _ the

“Commission”)’s Order No. 745, Demand Response

Compensation in Organized Wholesale Energy

Markets (“Order 745” or “the Order”), has been and

continues to be that of an unaffiliated observer

with deep expertise regarding how best to increase

competition in electricity services markets and

thereby improve consumers’ access to abundant

and affordable energy resources. He submitted two

sets of written comments in FERC’s Order No. 745

proceedings without a client or outside financial

support. With this amicus brief, Dr. Cicchetti

continues to participate on his own behalf and not

on behalf of industry players, environmental

advocates, or any other organization or entity.

The case before the Court addresses, in part,

whether Order 745 stands on firm economic

ground. Dr. Cicchetti’s explanation of the economic

principles and logic underlying the Order's

3

instructions to wholesale electricity market

participants will aid the Court by articulating the

logical steps that link generally accepted economic

fundamentals to the particular features of FERC's

Order.

SUMMARY OF ARGUMENT

Amicus curiae submits this brief to assist the

Court in understanding the sound economic

reasoning that informed the level of compensation

specified in Order 745. This brief leaves aside the

jurisdictional question posed by the Court and

addresses whether the Court of Appeals for the

D.C. Circuit erred in holding that Order 745 is

arbitrary and capricious. In particular, this brief

focuses on a narrow aspect of that question:

whether, according to economic principles, FERC

reasonably concluded that the locational marginal

price (“LMP”) is the appropriate level of

compensation for demand response resources

dispatched in FERC-authorized wholesale markets

where LMP satisfies the buyers’ cost-effectiveness

criterion set forth in the Order. It endorses FERC’s

reasoning and also its conclusion, namely that

compensating demand response resources as Order

745 instructs will foster both economic efficiency

and energy efficiency—and that failing to do so will

impede market and operational efficiencies, and

thereby pull wholesale rates away from what is just

and reasonable. Amicus presents this brief to

demonstrate that FERC’s economic reasoning

regarding compensation for dispatched demand

4

response resources in wholesale markets after

satisfying a buyers’ cost-effectiveness criterion is

consistent with accepted economic principles, and,

therefore, that the D.C. Circuit erred in concluding

that FERC had failed to justify its Order vis-a-vis

counterarguments rooted in economics.

TECHNICAL BACKGROUND

FERC Order No. 745 contains technical

instructions to the entities responsible for

managing the United States’ wholesale electricity

marketplaces. Simply put, those instructions direct

that wholesale markets should make use of—and

pay for—a particular form of _ electricity

curtailment, but only when doing so would save

money, or at least not be an additional cost, for

buyers in the wholesale market. Because the

institutional, physical, and economic background of

FERC’s Order, and thus of this case, is complex,

Amicus precedes its arguments by articulating

several terms and concepts that are indispensible

to a fluent discussion of FERC’s Order. Those

descriptions summarize the following: economic

efficiency; “just and reasonable” pricing; retail and

wholesale electricity; Independent System

Operators and Regional Transmission

Organizations; locational marginal pricing,

“congestion,” and “LMP-G”; demand-side

management and demand response resources; and

“Old LMP,” “New LMP,” as well as Order 745’s

“adder” and Net Benefits Test.

5

Economic efficiency and “just and

reasonable” pricing. Several commenters have

emphasized the relevance of economic efficiency to

FERC’s Order. In keeping with the shared view of

courts and economists, this brief takes economic

efficiency in the regulatory context like the one at

issue as broadly equated to “just and reasonable”

pricing, such as FERC must maintain in wholesale

electricity markets. See 16 U.S.C. § 824e(a) (“the

Commission shall determine the just and

reasonable rate. to be thereafter observed and in

force, and shall fix the same by order’).

This brief interprets “just and reasonable” as

describing outcomes consistent with several

regulatory principles: “cost causality,” “beneficiary

pays,” and “no unjustified price discrimination.”?

Cost causality broadly means maintaining prices

that allocate costs introduced into a system to the

party or parties responsible for introducing them.

Similarly, the “beneficiary pays” principle holds

that costs arising from a given investment or

approach should be allocated to those who benefit

as a result. See S. Carolina Pub. Serv. Auth. v.

FERC, 762 F.3d 41, 87 (D.C. Cir. 2014) (“The cost

causation principle requires costs to be allocated to

those who cause the costs to be incurred and reap

the resulting benefits.”) (internal quotations

2 See generally James C. Bonbright, Principles of Public

Utility Rates, Ch. XIX (1961); see also Charles J. Cicchetti,

Jeffrey Dubin & Colin Long, The California Electricity Crisis:

What, Why, and What’s Next (2004) (discussing these

principles in the context of recent events).

6

omitted); /llinots Commerce Comm'n v. FERC, 576

F.3d 470, 476 (7th Cir. 2009) (“To the extent that a

utility benefits from the costs of new facilities, it

may be said to have ‘caused’ a part of those costs to

be incurred, as without the expectation of its

contributions the facilities might not have been

built, or might have been delayed.”). Finally,

preventing unjustified price discrimination means

ensuring that prices assigned to a product or

service do not vary for reasons other than

differences in costs, and in how well that product or

service satisfies consumer demand in a particular

market or regulatory context. Prices that satisfy

these three principles should be considered just and

reasonable. Price reduction subsidies can,

however, sometimes be justified when the party

that pays the subsidy is left better off because she

ultimately pays a lower price than she would

otherwise, even after paying to provide the subsidy.

Retail and wholesale electricity. Broadly

speaking, electricity generators sell their product

wholesale, where it is purchased by entities (chiefly

utilities and competitive retail energy service

providers) that then resell it to end-users at retail.

Electricity sold at retail generally flows to end-

users through distribution systems. Utilities’

delivery of electricity to retail customer premises is

mostly treated as a natural monopoly, which is

granted an exclusive franchise in exchange for

accepting comprehensive state regulation of prices

3 See Bonbright, supra note 2, at 291.

7

charged, profits, and terms’ of _ service.‘

Traditionally, most electric utilities have owned

electricity generation and transmission facilities,

and states’ public utility commissions have

regulated these vertically integrated utilities

within their borders.§

FERC regulates the wholesale electricity

tariffs that determine the price of electricity

generation and transmission services sold to

utilities and others (but almost never end-users) at

wholesale. See 16 U.S.C. § 824e(a). Prior to passage

of the Public Utility Regulatory Policy Act of 1978

(“PURPA”), Pub. L. No. 95-617, 92 Stat. 3117,

FERC’s role was mostly limited to sales between

utility companies and interstate affiliates. PURPA

established independently owned power generation

as a viable source of competition to traditional,

vertically owned utilities. Pushed by PURPA, as

well as the Energy Policy Act of 1992, Pub. L. No.

102-486, 106 Stat. 2776, and ongoing technological

changes, FERC has since steered the evolution of

wholesale electricity markets to accommodate still

more competition for supplying the electricity,

transmission, and ancillary services needed to

insure reliable and efficient outcomes in the bulk

power system. See New York v. FERC, 535 U.S. 1,

6-13 (2002) (describing congressionally mandated

4 See generally Scott Hempling, Regulating Public Utility

Performance: The Law of Market Structure, Pricing and

Jurisdiction, 14—30 (2013).

5 Td. at 14-15.

8

and FERC-led changes to wholesale markets in

1990s).

The competitive wholesale markets

established by FERC are designed to replace the

traditional cost plus return regulatory model

(known as “cost of service”) with a model designed

to establish electricity prices based on _ the

interaction of demand and supply. Competitive

markets dispatch “least cost” supply resources by

calling only on the least expensive available

generating units and transmission pathways, i.e.

those with the lowest marginal operating costs. The

supply of electricity services in this market-based

model is thus conceptually the same as the least

cost marginal operating cost curve, which

prioritizes supply resources from those with the

least to the greatest marginal costs. It follows that,

if demand increases, market prices also increase,

because the resources dispatched to meet that

demand have higher marginal operating costs.

Independent System Operators (“ISOs”) and

Regional Transmission Organizations (“RTOs”).

The chief subjects of FERC’s wholesale market

regulatory efforts are ISOs and RTOs.’ These

6 While conceptually straightforward, operational

complications also require ISO/RTOs to establish other

distinct products known as ancillary services, which improve

system reliability, reduce congestion, and improve the

efficiency of wholesale market operations.

’ Orders 888 and 890, which define the roles of ISOs and

RTOs, are codified at 28 CFR pts. 35 and 37. Order No. 888,

Promoting Wholesale Competition Through Open Access Non-

9

entities—referred to hereafter as ISO/RTOs—can

be thought of as combining the role of air traffic

controllers and a stock exchange for regional

segments of the interstate bulk power system. They

conduct wholesale market auctions among

generators, transmission facility owners, buyers

(chiefly retail utilities), and others; these auctions

establish wholesale market prices. ISO/RTOs also

maintain from moment-to-moment the regional

balance between the supply of electricity and

aggregate end-user demand or “load.” Over the past

thirty years, FERC has issued numerous Orders to

ISO/RTOs instructing them to accommodate and

encourage competition, including by incorporating

new products and services into wholesale markets.

Some states continue to employ comprehensive

traditional cost of service regulation. Nevertheless,

in significant swaths of the country, the utilities

they regulate typically also participate in the

FERC-regulated wholesale’ electricity and

transmission markets. Accordingly, the electric

industry in the United States is currently governed

by both FERC and state utility regulators.

The Locational Marginal Price (“LMP”),

“congestion,” and “LMP-G” Entities that supply

generating resources to wholesale markets for

Discriminatory Transmission Services by Public Utilities;

Recovery of Stranded Costs by Public Utilities and

Transmitting Utilities, FERC Stats. & Regs 4 31,036, 61 Fed.

Reg. 21,540 (1996), affd in relevant part sub nom. New York

v. FERC, 535 U.S. 1 (2002); Order No. 890, Preventing Undue

Discrimination and Preference in Transmission Service,

FERC Stats. & Regs 4 31,241, 72 Fed. Reg. 12,266 (2007).

10

electric energy, capacity, and ancillary services

receive a market-clearing price, often called LMP,

in compensation. ISO/RTOs, with approval from

FERC, specify the parameters for qualifying

resources. LMP thus reflects the marginal cost of

supplying an additional increment of a qualifying

resource at a particular location and point in time.

LMP varies as competing suppliers bid units into

the market to satisfy demand. All generators that

supply a particular market or particular node or

location within a market are paid the same market-

clearing prices.

Transmission line network “congestion”

sometimes affects LMP. Congestion refers to the

result of network constraints that restrict end-user

access to some supply resources beyond particular

locations or nodes. Network congestion causes LMP

to exceed the price for similar resources elsewhere

in the broader competitive market. By boosting

LMP, congestion also encourages several types of

investment: by transmission line owners in

additional transmission cepacity; by suppliers in

more generation; and by consumers in the form of

substitutes for the resources supplied via congested

network lines. Such responsive investments ensure

that LMP continues to be “just and reasonable” and

reflective of cost causality, beneficiary pays, and no

unjustified discrimination principles.

LMP minus G, or “LMP-G,” uses “G” as

shorthand to describe the portion of what retail

consumers pay to utilities, often on a volumetric

basis, to cover the costs of electricity generation

11

and transmission. The remaining costs. that

customers pay for retail electricity include, chiefly,

those arising from the maintenance and operation

of distribution infrastructure. As explained in

subsequent sections of this brief, G is also used to

refer to costs avoided by retail consumers who

curtail their electricity usage.

Demand Side Management (“DSM”) and

Demand Response Resources (“DRR”). DSM

describes various approaches that curb demand for

electricity or “load.” (Units of DSM are sometimes

called “negawatts” to convey that they are

conceptually the inverse of megawatts of

electricity.®)

DSM encompasses passive conservation or

energy efficiency, which allows electricity users to

do what they normally do in terms of space

conditioning, appliance and machinery use,

lighting, etc. while using less electricity. Passive

DSM thus includes installing energy efficient

equipment, improving insulation, and _ similar

measures. DSM also encompasses active reductions

or curtailment in use in response to relative prices,

congestion, reliability, and external conditions.

End-use electric customers can control their own

load in response to such factors; more likely, such

customers’ utility or a third-party electric services

8 The term was famously coined by Amory Lovins. Amory B.

Lovins, Saving Gigabucks with Negawatts, 115 Pub. Utilities

Fortnightly, Mar. 21, 1985, at 24; see also Amory B. Lovins,

The Negawatt Revolution, Conf. Bd. Mag., Sept. 1990.

12

provider will provide load control or active energy

efficiency services.? The particulars of such active

DSM, arrangements (referred to herein as demand

reduction), vary, but they generally entail

residential, commercial, and/or industrial end-users

receiving price discounts or other compensation in

return for giving up the unrestricted ability to use

however much electricity they want at any point in

time.!°

Dispatchable demand reduction is a specific

type of active DSM that allows ISO/RTOs to

determine when to employ or “dispatch” a reduction

in load instead of additional units of electricity in

order to maintain the balance between electricity

and load. Order 745 is concerned only with this

® See, e.g., Girish Ghatikar et al, Lawrence Berkeley Nat'l

Lab’y, Analysis of Open Automated Demand Response

Deployments ir California and Guidelines to Transition to

Industry Standards, LBNL-6560E, 4-14 (Jan. 2014)

(describing examples of DRR arrangements managed by

utilities or third-party energy service providers in California);

Peter Cappers et al., Lawrence Berkeley Nat'l Lab’y, Market

and Policy Barriers for Demand Response Providing Ancillary

Services in U.S. Markets, LBNL-6155E, at 22—26 (Mar. 2013)

(describing entities and arrangements involved in active

demand reduction provision more generally).

10 See M.A. Pietter & E. Koch, Lawrence Berkeley Nat'l Lab’'y,

Direct Versus Facility Centric Load Control for Automated

Demand Response, LBNL-2905E, at 1 (Nov. 2009) (“Much of

DR today is managed as a set of programs in which the

participants enter into some contractual agreement about

how they will get compensated by participating in the DR

Events”); see also Mahdi Behrangrad, A Review of Demand

Side Management Business Models in the Electricity Market,

47 Renewable & Sustainable Energy Reviews 270 (2015).

13

specific type of active demand reduction, which,

following the lead of the U.S. Department of

Energy, it calls a “demand response resource,” or

DRR. Pet. App. 54a (citing 18 C.F.R. pt.

35.28(b)(5)).

“Old LMP,” “New LMP,” and the “adder.” In

its initial Notice of Proposed Rulemaking for Order

745, FERC recognized that dispatchable DRR could

be a cost-effective alternative to electricity supply

resources, and that dispatching DRR could cause

wholesale markets to clear at a lower LMP.!'! Call

this expected lower ex post price “New LMP” to

distinguish it from the ex ante “Old LMP,” the

equilibrium price if ISO/RTOs dispatch only

electricity to clear the market. But FERC also

recognized that paying electricity suppliers the

New LMP would leave ISO/RTOs without any

money to also pay DRR providers, a problematic

deficit termed “the billing unit effect.” Pet. App.

55a—56a. To make up the deficit, FERC instructed

'! Demand Response Compensation in Organized Wholesale

Energy Markets, 75 Fed. Reg. 15,362, 15,363~-64 (proposed

Mar. 18, 2010) [hereafter “NOPR”] (noting comparable

applications of dispatchable DRR and downward pressure on

prices resulting from its presence in wholesale markets); id.

at 15,367 (“we ask for comment on whether a reduction in

consumption is comparable to an increase in electricity

production for purposes of balancing supply and demand”); see

also Order No. 719, Wholesale Competition in Regions with

Organized Electric Markets, 125 FERC 9 61,071, 73 Fed. Reg.

64,100, 64,107 (Oct. 17, 2008) (explaining that operational

comparability of DRR is part of basis for FERC’s

determination regarding compensation in wholesale market

for ancillary services).

14

ISO/RTOs to include an “adder” in the price

charged to buyers whenever DRR is sold in addition

to electricity. That adder would be equal to New

LMP multiplied by the volume of dispatched units

of demand reduction, then divided by the volume of

all the remaining units of electricity sold. Order

745 also instructs ISO/RTOs to allocate the cost of

the adder proportionally to all buyers that

purchase electricity from the wholesale market

during times when ISO/RTOs dispatch DRR. Id. at

128a—129a.

The Net Benefits Test. FERC recognized that

allocating the adder in this way would only be

worthwhile if the combined cost of electricity and

dispatched demand reduction would be less than

that of electricity at Old LMP /d. At times when

the combined cost would be more, buyers would

have been better off if the ISO/RTO excluded DRR

from the wholesale market. FERC’s Order

answered this concern by imposing a buyers’ cost-

effectiveness criterion, the Net Benefits Test, on

ISO/RTOs’ dispatch of DRR. In circumstances

where paying Old LMP for electricity would cost

less than paying both New LMP and the adder for a

mix of electricity and DRR, that DRR fails the Net

Benefits Test. In such circumstances, Order 745

does not require ISO/RTOs to dispatch DRR or

compensate its provider. Imposing the Net Benefits

Test thus ensures that paying for DRR dispatched

in wholesale markets would make at least some

buyers better off and no buyer would be worse off,

because paying the New LMP plus an adder to

15

compensate dispatched DRR would be less than the

Old LMP !2 (This brief refers to this feature of the

Net Benefits Test as the “buyers’ cost effectiveness

criterion.”)

The Net Benefits Test can also be understood

in terms of what economists call price elasticity,

which measures how responsive demand for a

product or service is to changes in its price.

Demand is “elastic” when it responds

disproportionately to a change in price; it is

“inelastic” when it responds little or not at all to a

change in price. The Net Benefits Test allows or

disallows payment ffor dispatched demand

reduction based on the price elasticity of demand in

wholesale electricity markets. Thus, [SO/RTOs

must exclude dispatched demand reduction from

receiving minimum payments via_ wholesale

markets if demand is price elastic—meaning that

the percent reduction in the quantity of electricity

demanded at New LMP is less than the percent

reduction in price from Old to New LMP. Similarly,

if electricity supply bids are flat or nearly so when

the competitive market clears, there is little

potential for New LMP to be lower than Old and

the Net Benefits Test would exclude DRR.

'2 FERC’s Order initially calls for a Net Benefits Test based

on a rolling monthly procedure that identifies the threshold

below which DRR should be excluded from wholesale markets

in that month. The Order also provides ISO/RTOs the

opportunity to study the impacts of dispatched demand

reduction on the underlying ISO/RTO dispatch algorithm, and

to propose an alternative to the monthly determination of

breakeven LMP prices for DRR. Pet. App. 56a—57a.

16

ARGUMENT

FERC Order No. 745 specifies how and when

ISO/RTOs should compensate active demand

reduction that can be dispatched, measured and

verified, and the Order explains why those

specifications will save some wholesale buyers

money without costing any buyer more. FERC

arrived at the Order’s various specifications after a

lengthy series of proposals, comment periods, and a

technical conference. As noted above, the crux of

FERC’s Order is that, when dispatching demand-

reducing resources as well as electricity would be

cost-effective for wholesale buyers, wholesale

markets should compensate providers of dispatched

demand reduction at the same price, New LMP,

that wholesale markets pay for conventional

electricity services.

The D.C. Circuit’s opinion offers several

reasons for rejecting FERC’s Order, all of them

wrong. To begin, the opinion insists that FERC

should not be allowed to assign the same price to

ostensibly dissimilar products. It supports this view

with the observation that providers of demand

response resources are not “saddled” with the same

costs as electricity suppliers. Pet. App. 16a. But

this facile reasoning requires mis-defining the

product at issue as a physical flow of electrons,

rather than defining it accurately as reliable

electricity services delivered at just and reasonable

prices.

17

The opinion below also wrongly concludes

that FERC did not “engage the arguments raised

before it,” specifically the argument made by

Commissioner Moeller in his dissent that paying

LMP for dispatched demand reduction is

necessarily “overcompensation,” which “cannot be

just and reasonable.” Pet. App. 16a. This conclusion

strangely fails to note two things. First, that

numerous commenters and FERC answered these

points by describing how dispatched, measured and

verified demand reduction is operationally

comparable to electricity and that its providers are

indeed “saddled” with costs, just different ones. Pet.

App. 69a—82a, 104a (summarizing commenters’

rival arguments regarding comparability and

explaining reasons for Commission's final

decision).!3 And second, that FERC expressly

sought to avoid overcompensating demand

reduction dispatched in wholesale markets by

modifying its initial proposal and embedding a

buyers’ cost-effectiveness criterion in the Order’s

Net Benefit Test. Compare NOPR, 75 Fed. Reg. at

15,367 (“. paying LMP in all hours to the demand

response resources that can participate in the

organized wholesale energy markets is the correct

approach at this time, ”), with Order 745, Pet.

App. 92a—93a (describing comments received in

13 See also Affidavit of Alfred E. Kahn at 4—13, attached to

Reply Comments of the Demand Response Supporters, FERC

Docket No. RM10-17-000 (Aug. 26, 2010) (expressly rebutting

arguments of Robert L. Borlick and Professor William W.

Hogan that paying LMP amounts to “overcompensation” or

“double payment’).

18

response to NOPR and FERC’s responsive

revisions, including Net Benefits Test). Notably,

FERC also required the ISO/RTOs to revisit

existing protocols for measuring and verifying DRR

dispatched into wholesale markets, and to ensure

that these adequately capture the performance, or

non-performance of DRR, consistent with the

Order’s parameters. Pet. App. 124a. For these

reasons, FERC’s issuance of Order 745 satisfies the

relevant standard of review, which requires FERC’s

Order to be both reasoned and reasonable.'4

‘4 The Administrative Procedure Act requires FERC to show

the Court that its Order was reasonable—meaning that its

logic was relevant and sound—and reasoned-—meaning that it

articulated that logic sufficiently and offered adequate

answers to questions and criticisms raised in response. Am.

Paper Inst., Inc. v. Am. Elec. Power Serv. Corp., 461 U.S. 402,

413 (1983) (“To decide whether the Commission's action was

‘arbitrary, capricious, [or] an abuse of discretion,’ we must

determine whether the agency adequately considered the

factors relevant to choosing a rate that will best serve the

purposes of the statute, and whether the agency committed ‘a

clear error of judgment.’ Citizens to Preserve Overton Park v.

Voipe, 401 U.S. 402, 416 (1971).”); Jersey Cent. Power & Light

Co. v. FERC, 810 F.2d 1168 (D.C. Cir. 1987) (“where the

Commission has reached its determination by flatly refusing

to consider a factor to which it is undeniably required to give

some weight, its decision cannot stand.”) (citing Overton Park,

401 U.S. at 416). See also Richard J. Pierce, Jr., A Primer on

Demand Response and a Critique of FERC Order 745, 3 Geo.

Wash. J. Energy & Envtl. L. 102, 108 (2012) (“I agree with

Commissioner Moeller’s view and would have joined his

[dissenting] opinion had I been a member of FERC. Yet, if I

were instead a judge reviewing Order 745, I would uphold

FERC's rule on the basis that the agency provided reasoning

19

Most important for this brief’s purposes, the

D.C. Circuit’s conclusion is wrong because sound

economic principles—principles on which FERC

and other commenters expressly relied when

explaining Order 745’s logic—do not support

Commissioner Moeller’s characterization of LMP as

“overcompensation” for dispatched demand

reduction. Pet. App. 161a—162a (Moeller, Comm’r,

dissenting). The following sections explain those

principles and the logic that informs Order 745’s

prescription for compensating cost-effective

dispatched demand reduction at LMP.

I. Ordering ISO/RTOs to Compensate

Qualifying Dispatched Demand

Reduction at New LMP Will Yield

Economically Efficient Outcomes for

Wholesale Markets.

Competitive markets rely on the interaction

of demand and supply to establish an economically

efficient market-clearing price; such a price equals

the marginal cost of the last unit dispatched to

satisfy market demand (i.e., “clear the market”).

Suppliers with lower marginal costs receive that

price and earn a surplus that economists call

economic rent. Comparable or substitute products

compete with each other. If the products are

comparable and receive the same market-clearing

adequate to support each step in its decision-making

process.”).

20

price, the market will determine how much of each

type of product suppliers provide.

Dispatched demand reduction is a proven

operational substitute for electric energy in a

variety of scenarios.'° FERC’s initial proposal for

Order 745 would have treated electricity and

dispatchable demand reduction as_ generally

comparable, 75 Fed. Reg. at 15,367, but

commenters identified problems’ with this

approach, including the “billing unit effect.” In

response, FERC narrowed the circumstances in

which electricity and dispatched demand reduction

would be understood to serve comparable

operational and economic functions in wholesale

markets. Order 745, Pet. App. 94a—95a.

Specifically, it instructed ISO/RTQs to allocate the

18 See, e.g., Peter Cappers et al., Demand Response in U.S.

electricity markets: Empirical evidence, 35 Energy 1526 (2010)

(describing ISO/RTOs’ integration of DRR into wholesale

market’s menu of supply resources); Rahul Walawalkar et al.,

Evolution and Current Status of Demand Response (DR) in

Electricity Markets: Insights from PJM and NYISO, 35

Energy 1553 (2010) (similar); U.S. Dep’t of Energy, Benefits of

Demand Response in_ Electricity Markets and

Recommendations for Achieving Them (Feb. 2006); see also

Order 745-A, Pet. App. 21la—212a (“While we agree that

[DRR] dofes] not create electricity that can be used to serve

load, that fact is not dispositive here. Because the

balancing of generation and load when clearing the RTO and

ISO day-ahead and real-time energy markets can be

accomplished by changes in either supply or demand, demand

response resources that clear in the day-ahead and real-time

energy market should receive the same market-clearing LMP

as compensation when those resources meet the

conditions established in the Final Rule... .”).

21

adder across all buyers, and to dispatch and

compensate dispatched demand reduction only

after determining—using the Net Benefits Test—

that doing so would be a more economical

operational non-discriminatory choice than

dispatching generation that is more expensive, 1.e.

that has a higher marginal operating cost. /d.

In keeping with competitive market

principles, dispatched, measured and verified DRR

that can substitute operationally and economically

for electricity should enter the wholesale market

whenever its marginal cost is less than the

marginal cost of supplying electricity. Similarly,

DRR should not be dispatched if its marginal cost

exceeds that of supplying electricity. The price that

will achieve an economically efficient mix of

electricity and DRR is, therefore, New LMP, which

reflects the marginal cost of electricity in a

competitive wholesale market when dispatchable

demand reduction is available..6 Order 745

establishes these parameters to ensure that an

operationally comparable service receives

economically comparable compensation.

16 See Bonbright, note 2, supra, at 174 (“While rate structure

regulation is complex, there is general agreement that

charging different rates when (marginal) costs are identical is

discriminatory.”).

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23

The diagram shown in Figure 1 above helps

to explain these points by depicting the workable

economic tradeoff contemplated in Order 745

between electricity and DRR. That Figure refers to

a unit of electricity as a megawatt hour (“MWh”);

and to a unit of demand reduction as a “negawatt”

hour (“NWh”). This simplified conceptual approach

assumes that the amounts of supply-side megawatt

hours and demand-side negative megawatt hours—

negawatt hours—change in response to the amount

of each substitute that the ISO/RTO dispatches.

With more electricity supply, the marginal cost of

electricity, (labeled “MCmwn” in Figure 1),

increases. Increasing amounts of negawatt hours

also have increasing marginal costs, (labeled

“MCnwn’). The increases in electricity are measured

from left to right, and vice versa for negawatts.

Figure 1 shows in percentage terms the

optimal mix of the operational substitutes,

megawatt and negawatt hours, that [SO/RTOs

wou id dispatch to achieve operational and economic

efficiency. With no DRR available and thus no

negawatts, the market would be 100% electricity

dependent and the price would be P»,, or Old LMP.

As the percentage share of negawatt hours

increases, the price of electricity declines to New

LMP The optimal mix occurs when the marginal

cost schedules intersect and New LMP equals the

market-clearing price, P” The optimal percent of

the market that relies on electricity, or megawatt

hours, then shrinks by X% to 1 — X%.

24

New LMP, or P*, corresponds to the new

market price based on the reduced quantity of

electricity needed to clear the market at times

when negawatts are admitted into the marketplace.

As negawatt hours are sold in the wholesale

market, the initial demand for megawatt hours

falls by X%. Order 745 requires the ISO/RTO to pay

DRR providers New LMP for each negawatt hour

sold. Thus, when negawatts are available,

wholesale electricity buyers pay a combined

amount for megawatt and negawatt hours equal to

P*Qo. Order 745’s Net Benefits Test limits such

transactions to circumstances where customers’

aggregated savings from the lower New LMP

exceed the aggregate amount paid to DRR

providers. '?

Consider the following illustrative example

of how pricing these substitutes at New LMP—

subject to Order 745’s requirements that the

demand reduction’ substitute product be

dispatchable and satisfy the Net Benefits Test—

would yield an efficient outcome. FERC authored

this implementation of the logic depicted in Figure

'7 The results of including cost-effective DRR are as follows:

wholesale electricity consumers save (Po — P*)Qo before

paying for DRR; generators receive P*Q* (instead of PoQo) for

the reduced volume of megawatt hours they supply; and DRR

providers receive P*(1 — X%)Qo for their negawatt hours. The

payment for DRR would then be added to the New LMP, or

P*, with the condition that the combined payment would

always be less than PoQo. Generators also avoid the costs

related to the production of Qo minus Q*

25

1; it appears in Order 745’s footnote 119, Pet. App.

94a.

Assume that:

In the absence of DRR, buyers would pay

for 100 megawatts of load in a specific

hour at an Old LMP of $50 per megawatt

hour; thus, buyers would pay $5,000 for

100 megawatts;

But 5 megawatts of DRR is dispatched,

and its providers and the suppliers of the

remaining 95 megawatts of electricity

are paid a New LMP of $40 per

megawatt hour.

It follows that:

Electricity suppliers will be paid $40 x

95 megawatts, or $3,800;

DRR providers will be paid $40 x 5

megawatts, or $200;

Buyers, therefore, pay $4,000 ($3,800 +

$200) to clear the market;

The adder imposed by Order 745 equals

($40 x 5 megawatts) / 95 megawatts, or

$2.11 per megawatt;

Thus, the unit price of electricity (New

LMP) plus the adder equals $42.11 per

megawatt or negawatt hour, less than

the Old LMP of $50 per megawatt hour.

The Net Benefits Test is satisfied and

economic efficiency improved in this example

26

because buyers would pay less for a reduced volume

of electricity and the adder that compensates

providers of dispatched DRR—$42.11 per megawatt

or negawatt hour—than for electricity and no

DRR—$50 per megawatt hour. Put another way,

there are no losers among electricity buyers here.

Wholesale market prices and economic rents

decline. This result signals that dispatched,

measured and verified demand reduction is

economically more efficient, i.e. has lower costs,

than relying exclusively on electricity, some of

which has higher marginal costs. This illustration

also helps to show how imposing the Net Benefits

Test ensures that no wholesale market buyer would

pay more than they would in the absence of DRR,

and that whenever dispatched demand reduction

enters the market buyers of wholesale electricity

will pay less.

Providers of dispatched, measured and

verified DRR, like electricity generators, may earn

econo.uic rent. One role of economic rent in a

competitive market is to signal opportunities for

entry by new sources of supply. The level of rent

and rate of entry in a given market reflect that

market's efficiency: in an efficient market, slower

rates of entry should attend resources with lower

expected economic rents, and faster rates of entry

should attend resources with higher expected rents.

Paying LMP for DRR that satisfies Order 745’s

parameters, as well as for electricity, ensures

economically efficient results, in both the short

term, and over time as market actors adjust by

27

investing in the means to supply an economically

more optimal mix of megawatt and negawatt hours.

In sum, DRR cannot be overcompensated, if

it is both operationally comparable to electricity

and the result of its dispatch is a lower market-

clearing price. Importantly, FERC’s Order narrowly

defines the eligible DRR product to be limited to

DRR that can be dispatched, measured and

verified. The Order also requires such DRR to

satisfy the Net Benefits Test, which prohibits the

dispatch of DRR that is not cost-effective from a

buyer’s perspective and limits the payment of New

LMP in the wholesale market to DRR resources

with marginal costs that are less than those of

resources that would have been paid Old LMP

Accordingly, Order 745’s implementation cannot

result in overcompensation for electricity or the

DRR product.

Il. Ordering ISO/RTOs to Compensate All

Dispatched Demand Reduction at a Price

Equal to “LMP-G” Would Yield

Economically Inefficient Outcomes for

Wholesale Markets.

Some have argued that the correct level of

compensation for DRR is not LMP, but LMP

reduced by an amount equal to costs a retail end-

user avoids when that user “supplies” demand

reduction to a DRR provider by not purchasing

electricity. Order 745, Pet. App. 16la—165a

(Moeller dissent); 99a—100a (“Another issue raised

by a number of commenters, largely representing

28

generators, is whether a lower payment based on

LMP-G is the economically-efficient price that

sends the proper price signal to a potential demand

response provider.”). These critics suggest that the

generation and transmission portions of a retail

tariff, symbolized as “G,” best approximate those

avoided costs. Not reducing LMP by G, they say,

would result in DRR providers being “paid twice,”

once when they avoid paying the retail rate for

electricity by curtailing usage, and “again” when

they receive LMP from an ISO/RTO for doing so. Jd.

at 162a—-163a (Moeller dissent), 73a—74a (“As

described by Dr. William W. Hogan on behalf of

EPSA, this is sometimes called a double-payment

for demand reductions, because demand response

providers would ‘receive’ both the cost savings from

not consuming an increment of electricity at a

particular price, plus an LMP payment for not

consuming that same increment of electricity.”).

Compensating DRR at LMP-G is

economically inefficient and thus inferior to FERC’s

chosen approach, namely allocating the adder to all

buyers and restricting compensation of DRR by

imposing the Net Benefits Test before dispatching

cost-effective demand reduction products in

wholesale markets. Before turning to the economic

reasons for this inferiority, the Court should take

note of two points not related to pricing. First,

LMP-G was proposed chiefly as a way to address

concerns about paying more for dispatched DRR

29

than would be saved by dispatching it.!8 And

second, FERC considered and rejected LMP-G in

favor of superior alternatives for dealing with that

concern, and explained its reasons for that choice.

Pet. App. 100a—-104a (explaining rejection of

various arguments offered in favor of LMP-G); see

also id. at 93a—95a (describing “the net benefits

test through which [the billing unit affect] is

addressed”). That is, contrary to the D.C. Circuit’s

statement that “FERC failed to properly consider—

and engage—Commissioner Moeller’s reasonable

(and persuasive) arguments,” Pet. App. 15a, FERC

did not ignore the risk of “overcompensating”

negawatts, whether by simply paying MP for DRR

products in wholesale markets, or paying more for

negawatts than wholesale buyers would save as a

result of negawatts’ availability, Pet. App. 91a—95a

(explaining decision to impose two conditions on

compensation of dispatched DRR at LMP).

Rather, FERC considered several options,

including LMP-G, and explained its reasons for

ultimately adopting allocation of a charge per unit

‘8 Comments of Robert J. Borlick, Energy Consultant, FERC

Docket No. RM10-17-000, at 7 (May 13, 2010) (arguing for

LMP-G on the grounds that DRR is best understood as the

unexercised call option of a curtailing end-user, and payment

for such an “option” should subtract its “strike price”); see also

Demand Response Compensation in Organized Wholesale

Energy Markets (Supplemental Notice of Proposed

Rulemaking and Notice of Technical Conference), 75 Fed.

Reg. 47,499, 47,500—-01 (Aug. 6, 2010) (conference prompted

by commenters’ overlapping concerns about overpayment and

cost allocation).

30

purchased (i.e., the adder) across all buyers and the

Net Benefits Test to exclude DRR that would not be

cost-effective to buyers. Jd. at 91a—95a (explaining

adoption of Net Benefits Test), 126a—129a

(explaining choice from among five methods for

allocating adder).'9

Compensating DRR at LMP-G would lead to

unjustified price discrimination. The value of “G”

depends on diverse state regulations that affect the

marginal costs of supply resources. Thus, the

argument for compensating dispatched demand

reduction at LMP-G implicitly requires FERC to

take into account the effect of state regulations on

the marginal costs of DRR but no other supply

resources sold in wholesale markets. Applied to the

DRR_ product alone, this is economically

discriminatory. Applied across the board, this

would make FERC responsible for offsetting the

effects of myriad state programs, ranging from

renewable portfolio standards to tax credits for

particular installations to state preferences that

favor a particular type of fuel. FERC does not do

this, and for good reason. It would present a

significant informational challenge, and it would

18 Amid the flurry of comments, responses, and reasons

ultimately given by FERC for its decision, the Net Benefits

Test and LMP-G came to occupy the positions of pseudo-

substitutes. It would oversimplify to say that FERC chose

between them to address the potential problem of

“overcompensation,” but it is accurate to say that both were

proposed as ways to avoid paying too much for DRR. See, e.g.,

Order 745, Pet. App. at 86a—87a & 117a (commenters argue

that LMP-G obviates Net Benefits Test).

31

improperly orient FERC’s maintenance of “just and

reasonable” rates within its jurisdiction to decisions

made by other regulators outside its jurisdiction.

FERC relies on wholesale market prices and

quantities exchanged to determine economic

efficiency. Any requirement from FERC that

wholesale markets should take the cost

implications of diverse state regulations into

account when valuing wholesale supply resources

would result in unjustifiable discrimination among

resources and impede the normal operation of

wholesale markets. What’s more, importing a non-

marginal sunk state regulatory cost effect into

competitive wholesale markets would make

wholesale market outcomes less economically

efficient, and it would also be a clear contravention

of FERC’s responsibility to ensure that wholesale

markets yield just and reasonable outcomes by

eliminating non-economic considerations and

influences.

Consider also that not compensating cost-

effective DRR at New LMP would mean inviting

wholesale market participants to pay less than that

DRR is worth and thereby to free-ride on the

investments made by its providers. Order 745

eliminates such free-riding concerns by ensuring

that those who benefit from a lower New LMP also

pay for the cost-effective dispatched demand

reduction that caused LMP to be lower. Paying less

than New LMP would also cause an economically

inefficient amount of DRR because the Net Benefits

Test limits only permits dispatched demand

32

reduction in wholesale markets to earn New LMP if

it has a lower marginal cost than the electricity it

displaces.

LMP-G would not avoid “overcompensation”

or undercompensation. Unlike applying the Net

Benefits Test, simply reducing LMP by “G” would

not avoid some situations where wholesale buyers

pay for dispatched demand reduction but receive no

net benefit. This conflicts with a basic premise of

the LMP-G approach, namely that it would prevent

paying more for DRR than it is worth to wholesale

market participants.

The flip side of this point is no less

important: in addition to sometimes

overcompensating DRR providers, LMP-G would

frequently also undercompensate them, causing

them to stay out of wholesale markets and, in turn,

causing wholesale market participants to pay more

than they would if cost-effective DRR products were

available. This is inefficient, and it unfairly

discriminates in favor of megawatt hours and

against operationally equivalent negawatt hours.

LMP does not lead to “double payment” for

DRR products. Some of Order 745’s critics insist

that compensating DRR providers at LMP means

paying them twice, once in the form of saving on

electricity not purchased, and again by receiving a

payment of LMP This is simply wrong. When

wholesale market participants pay LMP for

dispatched demand _ reduction in_ wholesale

markets, no one is paid twice. End-users that give

33

up some measure of control over their electricity

use typically receive price discounts for the

electricity they consume.”° Another entity, such as

a utility or energy service provider, effectively pays

the end-user an amount equal to those discounts.?!

That intermediary entity must attempt to recover

its costs from the wholesale market, which it can do

when the aggregated demand reduction it bid into

the market is selected, dispatched, and paid for by

wholesale electricity buyers. The end-users that

give up partial load control in exchange for price

discounts have no immediate economic stake in the

prices paid for and the amount of demand reduction

dispatched in the wholesale market. And, the

intermediary utility or energy service provider

makes or loses money based on whether the

wholesale market prices for dispatched demand

reduction exceed what it paid in the form of

discounts to end-users plus what it invested in the

capital and organizational assets that enable it to

aggregate demand reduction for dispatch. Thus, it

might be fair to say that two payments are made—

one via wholesale markets to intermediaries, and

one via the intermediaries’ contracts with end-

users—but neither of those parties receives both

payments. This is no different than electricity

20 Nationwide retail tariff specifications are diverse, but those

that invite retail customers to accept supply interruption or

agree to load control generally provide discounts or

compensation not available to nonparticipating customers.

See Cappers et al. (2010), supra note 15, at 1526-27.

21 Large industrial end-users that buy directly from wholesale

markets are an exception to this point.

34

where generators receive payment for megawatt

hours sold into wholesale markets, and

intermediary utilities or energy service providers

purchase the electricity from wholesale markets for

the purpose of reselling it to retail customers.

Ill. The Fundamental Economic Issue in this

Case Is How Best to Encourage

Competition and Efficiency in Wholesale

Markets.

FERC’s effort to find efficiencies in wholesale

markets by clearing a path toward buying less

electricity and more DRR is no mere intellectual

exercise. This Court’s decision about whether to

allow that effort to proceed will inevitably make

some wholesale market participants winners and

others losers. That fact informs not only who is

arguing before this Court but also the arguments

they choose to present. Most notably, those who

stand to lose from implementation of FERC’s Order

have reason to frame it as FERC’s attempt to boost

the price to be paid for DRR beyond what

maintaining “just and reasonable” pricing allows.

From the viewpoint of an _ economist

concerned with the efficient operation of wholesale

electricity markets, the underlying debate in this

case is not solely about finding the right price for

DRR. It also concerns the correct—meaning the

economically efficient—quantity of both megawatt

and negawatt hours. Accordingly, the economic

question at the root of this case is whether and

under what terms to allow and _ encourage

35

competition between alternatives that ISO/RTOs—

using the Net Benefits Test and other means—

insure are economically efficient operational

substitutes.

Economic efficiency increases, and society

benefits, when customers have more choices and

entrepreneurs are free to take risks and enter

markets occupied by incumbents on a level playing

field. Currently, most electricity generated in the

U.S. is acquired in the wholesale markets managed

by ISO/RTOs. Some states are encouraging and/or

allowing retail energy service providers and firms

that provide energy management services on

customer premises to engage with end-users

beyond their electricity meters—that is, regarding

end-users’ use of heating and cooling systems,

lighting, and other’ electrically powered

equipment.?2 FERC’s Order facilitates such efforts

by enabling DRR providers to translate the efforts

of those end-users who are willing and able to use

22 Examples of such engagement are diverse, ranging from

traditional load interruption arrangements, to pre-cooling and

other HVAC use adjustments in commercial buildings, to

installing smart appliances that adjust electricity usage based

on price signals relayed by a smart meter or a retail energy

service provider. See New York State Pub. Serv. Comm'n,

Staff Report & Proposal: Reforming the Energy Vision, Case

No. 14-M-0101, at 38-41 (Apr. 24, 2014) (summarizing

current and potential roles of energy service companies or

ESCOs in managing energy use by end-user facilities and

buildings); see also generally Electric Power Research

Institute, Smart Grid Demonstration Initiative: 5 Year

Update (2013) (presenting diverse examples of such

engagements).

36

electricity more efficiently into cost-effective DRR

in wholesale markets, and thereby lower LMP

When ISO/RTOs dispatch cost-effective

demand reduction, everyone is better off except

generators, some of which are dropped from the

supply stack because they are uneconomic

(although dropped generators do avoid higher

marginal operating costs). Others with lower

marginal operating costs still supply electricity but

earn a lower economic rent because competitive

market prices are lower. Thus, in_ general,

generators lose as DRR provider participation

increases, and with it wholesale market efficiency.

Nonetheless, no supplier should be guaranteed any

economic rent, which, in competitive markets,

should guide more efficient future decisions by

signaling when to invest in competing products or

services, whether they draw their value from

changes to energy use on end-users’ premises or

from supply-side resources with lower operating

costs, such as nuclear plants or wind farms.

CONCLUSION

For the foregoing reasons, amicus

encourages the Court to recognize that Order 745’s

prescription for compensating cost-effective

demand response that can be _ dispatched,

measured, and verified stands on sound economic

principles and coherent reasoning. As it is logically

valid, and as FERC has made its logic clear, Order

745 cannot be considered arbitrary and capricious

37

and the decision of the D.C. Circuit should be

overturned. More practically, the Court should also

reverse the decision below because FERC’s Order

promises to be a source of efficiency in wholesale

markets, both in terms of energy and economics.

Respectfully submitted,

Justin M. Gundlach

Hope M. Babcock (counsel of record)

Institute for Public Representation

Georgetown University Law Center

600 New Jersey Ave. NW, Suite 312

Washington, D.C. 20001

(202) 662-9535

babcock@law.georgetown.edu

July 2015