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

Supreme Court, US.

14-8 4 {) JAN 15-208

OFFICE OF THE CLERK

No.

In the Supreme Court of the United States

FEDERAL ENERGY REGULATORY COMMISSION,

PETITIONER

Vv.

ELECTRIC POWER SUPPLY ASSOCIATION, ET AL.

ON PETITION FOR A WRIT OF CERTIORARI

TO THE UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

APPENDIX TO THE PETITION

FOR A WRIT OF CERTIORARI

DONALD B. VERRILLI, JR.

Solicitor General

Counsel of Record

DAVID L. MORENOFF EDWIN S. KNEEDLER

General Counsel Deputy Solicitor General

ROBERT H. SOLOMON JOHN F. BASH

Solicitor Assistant to the Solicitor

HOLLY E. CAFER General

A P a ar as a) a

Federal Energy Regulatory ashington, D.C. 20530-0001

Commission SupremeCtBrie{s@usdoj.gov

Washington, D.C. 20426 (202) 514-2217

TABLE OF CONTENTS

Appendix A — Court of appeals opinion

| ee la

Appendix B — Order of the Federal Energy

Regulatory Commission

(Mar. 15, 2011)... ‘ieeneieenaetnenand 49a

Appendix C — Order of the Federal Energy.

Regulatory Commission on

rehearing and clarification

ee 173a

Appendix D — Order of the Federal Energy

Regulatory Commission denying

rehearing (Feb. 29, 2012)..............--.. 276a

Appendix E — Court of appeals order denying

rehearing (Sept. 17, 2014).................. 282a

Appendix F — Court of appeals order denying

rehearing (Sept. 17, 2014).................. 284a

(I)

APPENDIX A

UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

Nos. 11-1486, 11-1489, 12-1088, 12-1091, 12-1093

ELECTRIC POWER SUPPLY ASSOCIATION, PETITIONER

Vv.

FEDERAL ENERGY REGULATORY COMMISSION,

RESPONDENT

MADISON GAS AND ELECTRIC COMPANY, ET AL.,

INTERVENORS

Argued: Sept. 23, 2013

Decided: May 23, 2014

Before: BROWN, Circuit Judge, and EDWARDS and

SILBERMAN, Senior Circuit Judges.

Opinion for the Court by Circuit Judge BROWN.

Dissenting opinion filed by Senior Circuit Judge Ep-

WARDS.

BROWN, Circuit Judge:

Electric Power Supply Association and four other

energy industry associations (“Petitioners”) petition

this court for review of a final rule by the Federal

Energy Regulatory Commission (“FERC” or “the

Commission”) governing what FERC calls “demand

(la)

2a

response resources in the wholesale energy market.”

The rule seeks to incentivize retail customers to re-

duce electricity consumption when economically effi-

cient. Petitioners complain FERC’s new rule goes

too far, encroaching on the states’ exclusive jurisdic-

tion to regulate the retail market. We agree and

vacate the rule in its entirety.

I

Under the Federal Power Act (“FPA” or “the Act”)

the Commission is generally charged with regulating

the transmission and sale of electric power in inter-

state commerce. The FPA “split([s] [jurisdiction over

the sale and delivery of electricity] between the federal

government and the states on the basis of the type of

service being provided and the nature of the energy

sale.” Niagara Mohawk Power Corp. v. FERC, 452

F.3d 822, 824 (D.C. Cir. 2006). Section 201 of the Act

empowers FERC to regulate “the sale of electric en-

ergy at wholesale in interstate commerce.” 16 U.S.C.

§ 824(b)(1) (emphasis added). Thus, “FERC’s juris-

diction over the sale of electricity has been specifically

confined to the wholesale market.” New York v.

FERC, 535 U.S. 1, 19, 122 S. Ct. 1012, 152 L. Ed. 2d 47

(2002).

The Commission concedes that “demand response is

a complex matter that lies at the confluence of state

and federal jurisdiction.” See Demand Response

Compensation in Organized Wholesale Energy Mar-

kets, 134 FERC 9% 61,187, 2011 WL 890975, at *30

(Mar. 15, 2011) [hereinafter Order 745]. For more

than a decade, FERC has permitted demand-side re-

sources to participate in organized wholesale markets,

3a

allowing Independent System Operators (ISOs) and

Regional Transmission Organizations (RTOs) to use

demand-side resources to meet their systems’ needs

for wholesale energy, capacity, and ancillary services.

As this court has noted, Congress in 2005 declared

“the policy of the United States that time-based pric-

ing and other forms of demand response

shall be encouraged and unnecessary barri-

ers to demand response participation in energy, ca-

pacity and ancillary service markets shall be eliminat-

ed.” Ind. Util. Reg. Comm’n v. FERC, 668 F.3d 735,

736 (D.C. Cir. 2012) (citing 16 U.S.C. § 2642). The

Commission has issued dozens of orders on demand-

side resource participation, and ISOs and RTOs main-

taining economic demand response programs could file

tariffs with the Commission and accept bids for ancil-

lary services and from aggregators of retail customers

directly into the wholesale energy markets. See Whole-

sale Competition in Regions with Organized Electric

Markets, 73 Fed. Reg. 1 64,100, 64,101 (Oct. 28, 2008)

(to be codified at 18 C.F.R. pt. 35) [Order 719].

Order 745 establishes uniform compensation levels

for suppliers of demand response resources who par-

ticipate in the “day-ahead and real-time energy mar-

kets.” Order 745, 2011 WL 890975, at *1. The order

directs ISOs and RTOs to pay those suppliers, includ-

ing aggregators of retail customers, the full locational

marginal price (LMP), or the marginal value of re-

sources in each market typically used to compensate

generators. The Commission conditioned the pay-

ment of full LMP on the ability of a demand response

resource to replace a generation resource and required

demand response to be cost effective. Cost effec-

4a

tiveness would be determined by a newly devised “net

benefits test,” which FERC directed ISOs and RTOs

to implement. FERC acknowledged that the cost of

payments to retail customers to encourage reduced

energy consumption would have to be subsidized by

load-serving entities participating in the wholesale

market. Jd. 1 99, 2011 WL 890975, at *27; see also id.

7102. Finally, the rule allocated the costs of demand

response payments proportionally to all entities that

purchase from the relevant energy markets during

times when demand response resources enter the mar-

ket. Commissioner Moeller dissented, arguing the

Commission’s retail customer compensation scheme

conflicted both with FERC’s efforts to promote com-

petitive markets and with its statutory mandate to

ensure supplies of electric energy at just, reasonable,

and not unduly preferential or discriminatory rates.

See id., 2011 WL 890975, at *34-39.

Requests for rehearing and clarification were filed

by ISOs, RTOs, state regulatory commissions, trade

associations, publicly owned utilities, transmission

owners, suppliers, and others. The Commission, in

another 2-1 decision, confirmed its approach and Peti-

tioners filed timely petitions for review.

II

The Administrative Procedure Act (APA) directs us

to “hold unlawful and set aside agency action

in excess of statutory jurisdiction, authority, or limita-

tions.” 5 U.S.C. § 706(2)(C). “FERC is a creature of

statute” and thus “has no power to act unless and until

Congress confers power upon it.” Cal. Indep. Sys.

Operator Corp. (CAISO) v. FERC, 372 F.3d 395, 398

5a

(D.C. Cir. 2004) (citing La. Pub. Serv. Comm'n v. FCC,

476 U.S. 355, 374, 106 S. Ct. 1890, 90 L. Ed. 2d 369

(1986)). If FERC lacks authority under the Federal

Power Act to promulgate a rule, its action is “plainly

contrary to law and cannot stand.” See Michigan v.

EPA, 268 F.3d 1075, 1081 (D.C. Cir. 2001).

We address FERC’s assertion of its statutory au-

thority under the familiar Chevron doctrine. See City

of Arlington, Tex. v. FCC, —U.S.—, 133 S. Ct. 1863,

1870-71, —L. Ed. 2d— (2013). The question is

“whether the statutory text forecloses the agency’s

assertion of authority.” Jd. at 1871. If, however, the

statute is silent or ambiguous on the specific issue, we

must defer to the agency’s reasonable construction of

the statute. /d. at 1868.

FERC claims when retail consumers voluntarily

participate in the wholesale market, they fall within

the Commission’s exclusive jurisdiction to make rules

for that market. Petitioners protest that retail sales

of electricity are within the traditional and “exclusive

jurisdiction of the States” and regulating consumption

by retail electricity customers is a regulation of retail,

not wholesale, activity. Reply Br. 11-12. The prob-

lem, Petitioners say, is the Commission has no author-

ity to draw retail customers into the wholesale markets

by paying them not to make retail purchases.

Initially, we note the regulations have a single defi-

nition of “demand response”—a “reduction in the con-

sumption of electric energy by customers from their

expected consumption in response to an increase in

the price of electric energy or to incentive payments

designed to induce lower consumption of electric

6a

energy.” 18 C.F.R. § 35.28(b)(4) (emphasis added);

see also Order 745, 2011 WL 890975, at *1n.2. High

retail rates will reduce demand. Conversely, if con-

sumers are paid to reduce demand, prices fall. FERC

acknowledges the first case, “price-responsive demand”

is a “retail-level” demand response. See Order 745,

2011 WL 890975, at *1-3 & n.2 (citing 18 C.F.R.

§ 35.28(b)(4)). In contrast, FERC dubs a reduction

in the consumption of energy in response to incentive

payments a “wholesale demand response.” See FERC

Br. 5, 34; see also Order 745, 2011 WL 890975, at *1-3

& n.2 (citing 18 C.F.R. § 35.28(b)(4)). The Commis-

sion draws this distinction between “wholesale demand

response” and “retail demand response” in an attempt

to narrow the logical reach of its rule. See, e.g.,

FERC Br. 5 (“{T]he Commission has made plain that

its focus is narrow and that it addresses only wholesale

demand response.”); id. (“States remain free to au-

thorize and oversee retail demand response pro-

grams.”); id. at 14-15. Yet FERC acknowledges

“wholesale demand response” is a fiction of its own

construction. See Oral Arg. Tape, No. 11-1486, at

27:31 (Sept. 23, 2013) (conceding “selling” demand

response resources in the wholesale market “is a bit of

a fiction”). Demand response resources do not actu-

ally sell into the market. Demand response does not

involve a sale, and the resources “participate” only by

declining to act.

As noted, and as the Commission concedes, demand

response is not a wholesele sale of electricity; in fact, it

is nota sale atall. See Order 745, 2011 WL 890975, at

*18 (“[T]he Commission does not view demand re-

sponse as a resale of energy back into the energy mar-

7a

ket.”). Thus, FERC astutely does not rely exclusive-

ly on its wholesale jurisdiction under § 201(b)(1) for

authority. See Niagara Mohawk Power Corp., 452

F.3d at 828 & n.7.

Instead, FERC argues §§ 205 and 206 grant the

agency authority over demand response resources in

the wholesale market. These provisions task FERC

with ensuring “all rules and regulations affecting

rates” in connection with the wholesale sale of

electric energy are “just and reasonable.” 16 U.S.C.

§ 824d(a) (emphasis added); see also id. § 824e(a).

Thus, the Commission argues it has jurisdiction over

demand response because it “directly affects wholesale

rates.” FERC Br. 32-34; see also Order 745, 2011 WL

890975, at *30.

We agree with the Commission that demand re-

sponse compensation affects the wholesale market.

Because of the direct link between wholesale and retail

markets, compare FERC Br. 32, with Pet’rs Br. 11-14

(describing the “direct” relationship between whole-

sale and retail rates), and Reply Br. 12 (“(T]here is

undeniably a link between wholesale rates and retail

sales”), a change in one market will inevitably beget a

change in the other. Reducing retail consumption—

through demand response payments—will lower the

wholesale price. See Oral Arg. Tape, at 33:13. De-

mand response will also increase system reliability.

FERC Br. 33. Because incentive-driven demand re-

sponse affects the wholesale market in these ways, the

Commission argues §§ 205 and 206 are clear grants of

agency power to promulgate Order 745.

8a

The Commission’s rationale, however, has no limit-

ing principle. Without boundaries, §§ 205 and 206

could ostensibly authorize FERC to regulate any num-

ber of areas, including the steel, fuel, and labor mar-

kets. FFERC proposes the “affecting” jurisdiction can

be appropriately limited to “direct participants” in jur-

isdictional wholesale energy markets. See FERC Br.

37. But, as this case demonstrates, the directness of

participation may be a function of the richness of the

incentives FERC commands. The commission’s au-

thority must be cabined by something sturdier than

creative characterizations. See Altamont Gas Trans-

mission Co. v. FERC, 92 F.3d 1239, 1248 (D.C. Cir.

1996) (noting FERC cannot “do indirectly what it could

not do directly”). The “direct participant” theory also

assumes FERC can “lure” non-jurisdictional resources

into the wholesale market in the first place to create

jurisdiction, see Oral Arg. Tape, at 29:52, which is the

heart of the Petitioners’ challenge.

The limits of §§ 205 and 206 are best determined in

the context of the overall statutory scheme. See FDA

v. Brown & Williamson Tobacco Corp., 529 U.S. 120,

132-33, 120 S. Ct. 1291, 146 L. Ed. 2d 121 (2000).

Congressional intent is clearly articulated in § 201’s

text: FERC’s reach “extend{s] only to those matters

which are not subject to regulation by the States.” 16

U.S.C. § 824(a). States retain exclusive authority to

regulate the retail market. See Niagara Mohawk

Power Corp., 452 F.3d at 824. Absent a “clear and

specific grant of jurisdiction” elsewhere, see New York,

535 U.S. at 22, 122 S. Ct. 1012, the agency cannot reg-

ulate areas left to the states. The broad “affecting”

language of §§ 205 and 206 does not erase the specific

9a

limits of § 201.’ See generally RadLAX Gateway Ho-

tel, LLC v. Amalgamated Bank, —U.S.—, 182 S. Ct.

2065, 2071, 182 L. Ed. 2d 967 (2012); sections 205 and

206 do not constitute a “clear and specific grant of

jurisdiction.” Indeed, the Commission agrees its jur-

isdiction to regulate practices “affecting” rates does

not “trump|| the express limitation on its authority to

regulate non-wholesale sales.” FERC Br. 34-35.

Otherwise, FERC could engage in direct regulation of

the retail market whenever the retail market affects

the wholesale market, which would render the retail

market prohibition useless. Cf Morpho Detection,

Inc. v. TSA, 717 F.3d 975, 981 (D.C. Cir. 2013) (declin-

ing to “adopt a reading that would render the

general rule a nullity”).

' The Dissent focuses extensively on § 201(b)(1), positing that the

“jurisdictional issue turns on a rather straightforward question of

statutory interpretation: whether a promise to forgo consumption

of electricity that would have been purchased in the retail electricity

market unambiguously constitutes a “sale of electric energy” under

section 201(b)(1).” Dissenting Op. at 227. The jurisdictional issue

is not quite so narrow. In fact, even the Commission does not char-

acterize the challenge this way and never offers an interpretation of

§ 201(b)(1), arguing instead that demand response resources are

direct participants in wholesale markets. See FERC Br. 3440.

Though our review is deferential, even if we reached Chevron step

two, we could not defer to an interpretation the agency has not

offered.

In any event, we do not base our conclusion on the “any other

sales” language of § 201(b)1). Rather, we look to the statutory

scheme as a whole and find that demand response, while not neces-

sarily a retail sale, is indeed part of the retail market, which, as the

statute and case law confirm, is exclusively within the state’s juris-

diction.

10a

In addition, if FERC’s arguments are followed to

their logical conclusions, price-responsive demand

response—retail demand response in “FERC speak”—

would also affect jurisdictional rates in the same way

as the type of demand response at issue in FERC’s

rule here, and FERC’s authority regarding demand re-

sponse would be almost limitless. Although the cur-

rent rule leaves price-responsive demand untouched,

nothing would stop FERC from expanding this regula-

tion and encroaching further on state authority in the

future.

Thus, FERC can regulate practices affecting the

wholesale market under §§ 205 and 206, provided the

Commission is not directly regulating a matter subject

to state control, such as the retail market. Cf Conn.

Dep't of Pub. Util. Control v. FERC, 569 F.3d 477, 479

(D.C. Cir. 2009) (finding FERC could regulate the in-

stalled capacity market under its affecting jurisdiction

because FERC did not engage in direct regulation of

an area subject to exclusive state control).’

* Connecticut Department of Public Utility Control v. FERC, 569

F 3d 477 (D.C. Cir. 2009), does not sanction FERC’s rule. In Con-

necticut, FERC raised the capacity requirement and incidentally in-

centivized construction of more generation facilities, which are sub-

ject to state control; here, the Commission’s rule reaches directly in-

to the retail market to draw retail consumers into its scheme. Here,

FERC’s incentive is not merely a logical by-product of the rule; it is

the rule. According to the Dissent, “FERC can indirectly incentiv-

ize action that it cannot directly require so long as it is otherwise

acting within its jurisdiction.” Dissenting Op. at 234. We agree

Connecticut cannot control where FERC has directly incentivized

action it cannot directly require.

lla

The fact that the Commission is only “luring” the

resource to enter the market instead of requiring en-

try does not undercut the force of Petitioners’ chal-

lenge. The lure is change of the retail rate. Demand

response—simply put—is part of the retail market.

It involves retail customers, their decision whether to

purchase at retail, and the levels of retail electricity

consumption. If FERC had directed ISOs to give a

credit to any consumer who reduced its expected use of

retail electricity, FERC would be directly regulating

the retail rate. At oral argument, the Commission

conceded crediting would be an impermissible intru-

sion into the retail market. See Oral Arg. Tape, at

27:15. Ordering an ISO to compensate a consumer

for reducing its demand is the same in substance and

effect as issuing a credit.’ Thus, while it is true de-

mand response can occur in two ways—through a re-

sponse to either price change or incentive oayments—

nothing about the latter makes it “wholesale.” A

buyer is a buyer, but a reduction in consu:nption can-

not be a “wholesale sale.” FERC’s metaphysical dis-

tinction between price-responsive demand arid incentive-

based demand cannot solve its jurisdictional quandary.

Nor does FERC’s reliance on a statement of con-

gressional policy from the Energy Policy Act of 2005

save its rule. FERC insists its actions “ar2 consistent

with Congressional policy requiring federal level facil-

itation of demand response, because this ‘inal rule is

* The agency’s concession contradicts the Dissert’s contention

that FERC can regulate demand response here »ecause “non-

consumption [does not] constitute an ‘other sale,” Dissenting Op.

at 233.

12a

designed to remove barriers to demand response par-

ticipation in the organized wholesale energy markets.”

Order 745, 2011 WL 890975, at *30. FERC’s reliance

on this language is perplexing; if anything, the policy

statement supports the opposite conclusion, that Con-

gress intended demand response resources to be reg-

ulated by states, as part of the retail market.

The Energy Policy Act of 2005 confirms the nation-

al policy of encouraging and facilitating “the deploy-

ment of [time-based pricing and other demand re-

sponse] technology and devices that enable electricity

customers to participate in such pricing and demand

response systems and [eliminating] unnec-

essary barriers to demand response participation in

energy, capacity and ancillary service markets.” Pub.

L. No. 109-58, § 1252(f), 119 Stat. 594, 966 (2005). As

an initial matter, even if § 1252(f) supports FERC’s

authority, the Commission cannot rely on the section

for an independent source of power. Policy state-

ments like § 1252(f) “are just that—statements of pol-

icy. They are not delegations of regulatory authori-

ty.” See Comcast Corp. v. FCC, 600 F.3d 642, 654

(D.C. Cir. 2010); cf New York, 535 U.S. at 22, 122 S.

Ct. 1012 (finding that a “mere policy declaration

cannot nullify a clear and specific grant of

jurisdiction”). Thus, the relevant sections of the

Energy Policy Act of 2005 can only be used to “help

delineate the contours of statutory authority.” Com-

cast Corp., 600 F.3d at 654. And here, those contours

do not encompass federal regulation of demand re-

sponse.

13a

FERC latches onto the language in § 1252(f) re-

quiring elimination of “unnecessary barriers to de-

mand response participation in energy ser-

vice markets” to support its claim that Order 745 ad-

vances congressional! policy. See FERC Br. 40. In

Order 745, however, FERC went far beyond removing

barriers to demand response resources. Instead of

simply “removing barriers,” the rule draws demand

response resources into the market and then dictates

the compensation providers of such resources must

receive.

We think the title of the section is noteworthy:

“Federal Encouragement of Demand Response De-

vices.” (emphasis added). Pub. L. No. 109-58,

§ 1252(f), 119 Stat. 594, 966. “To encourage” is not

“to regulate.” Although the title is “not dispositive of

the provision’s meaning,” “it is not too much to expect

that it has something to do with the subject matter” of

the section. See CAISO, 372 F.3d at 399. And

here, “review of the statutory text reveals that [the

title} has everything to do with the subject matter.”

See id. The section dictates demand response is to be

“encouraged” and “facilitated,” not directly regulated

as Order 745 proposes.

This is obvious when § 1252(f) is read in tandem

with § 1252(e), “Demand Response and Regional Co-

ordination,” which declares it the “policy of the United

States to encourage States to coordinate, on a regional

basis, State energy policies to provide reliable and

affordable demand response services to the public.”

Pub. L. No. 109-58, § 1252(e), 119 Stat. 594, 966. This

language underscores that states, not the Commission,

l4a

regulate demand response. Indeed, § 1252(e) goes

on to note FERC should “provide technical assistance

to States and regional organizations in

developing plans and programs to use demand

response to respond to peak demand or emergency

needs.” Jd. The Commission is also to prepare an

annual report, assessing demand response resources.

Id. Thus, the Energy Policy Act clarifies FERC’s

authority over demand response resources is limited:

its role is to assist and advise state and regional pro-

grams.

Even more importantly, the Energy Policy Act

statements show Congress understood the importance

of demand response resources to the wholesale market

—an importance Petitioners do not dispute. Yet, de-

spite this significant impact on the wholesale market,

Congress left regulation of this aspect of retail demand

up to the states, rather than to the federal govern-

ment.

Because the Federal Power Act unambiguously re-

stricts FERC from regulating the retail market, we

need not reach Chevron step two. But even if we

assumed the statute was ambiguous—as Judge Ed-

wards argues, we would find FERC’s construction of it

to be unreasonable for the same reasons we find the

statute unambiguous. Because FERC’s rule entails

direct regulation of the retail market—a matter exclu-

sively within state control—it exceeds the Commis-

sion’s authority.

15a

IV

Alternatively, even if we assume FERC had statu-

tory authority to execute the Rule in the first place,

Order 745 would still fail because it was arbitrary and

capricious.

Under the APA, we must set aside orders that are

“arbitrary, capricious, an abuse of discretion, or other-

wise not in accordance with law.” 5 U.S.C. § 706(2)(A).

In particular, “it most emphatically remains the duty

of this court to ensure that an agency engage the ar-

guments raised before it,” NorAm Gas Transmission

Co. v. FERC, 148 F.3d 1158, 1165 (D.C. Cir. 1998),

including the arguments of the agency’s dissenting

commissioners, Am. Gas Ass’n v. FERC, 593 F.3d 14,

19 (D.C. Cir. 2010); see also Kamargo Corp. v. FERC,

852 F.2d 1392, 1398 (D.C. Cir. 1988) (“We recognize

that this case presents a difficult problem for the Com-

mission, but we think it has no alternative but to con-

front the questions raised by the [commissioner’s] dis-

sent.”).

A review of the record reveals FERC failed to

properly consider—and engage—Commissioner Moel-

ler’s reasonable (and persuasive) arguments, reiterat-

ing the concerns of Petitioners and other parties, that

Order 745 will result in unjust and discriminatory

rates. Moeller argued Order 745 “overcompensatjes}”

demand response resources because it “requires that

demand resource[s] be paid the full LMP plus be al-

lowed to retain the savings associated with [the pro-

vider’s}] avoided retail generation cost.” Demand Re-

sponse Compensation in Organized Wholesale Energy

Markets: Order on Rehearing and Clarification, 137

16a

FERC {4 61,215, 2011 WL 6523756, at *38 (Dec. 15,

2011) [hereinafter Order 745-A] (Moeller, dissenting);

see also Pet’rs Br. 45-50. The Commission then re-

sponded that demand response resources are compa-

rable to generation resources and should therefore re-

ceive the same level of compensation. Order 745-A,

2011 WL 6523756, at *14-15. Yet comparable contri-

butions cannot be the reason for equal compensation,

when generation resources are incomparably saddled

with generation costs. Nor can FERC justify its cur-

rent overcompensation by pointing to past under-

compensation.‘ Although we need not delve now into

the dispute among experts, see, e.g., Br. of Leading

Economists as Amicus Curiae in Support of Pet’rs, the

potential windfall to demand response resources seems

troubling, and the Commissioner’s concerns are cer-

tainly valid. Indeed, “overcompensation cannot be

just and reasonable,” Order 745-A, 2011 WL 6523756, at

*38 (Moeller; dissenting), and the Commission has not

adequately explained how their system results in just

compensation.

The Commission cannot simply talk around the ar-

guments raised before it; reasoned decisionmaking re-

quires more: a “direct response,” which FERC failed

to provide here. See Am. Gas Ass’n, 593 F.3d at 20.

Thus, if FERC thinks its jurisdictional struggles are

its only concern with Order 745, it is mistaken. We

‘ Similarly, the hope that demand response resources will use the

expected windfall for “capital improvements,” see Dissenting Op. at

237, does not respond to Petitioner’s concerns that the overcompen-

sation is unfair and discriminatory.

17a

would still vacate the Rule if we engaged the Petition-

ers’ substantive arguments.

V

Ultimately, given Order 745’s direct regulation of

the retail market, we vacate the rule in its entirety as

ultra vires agency action.

For the reasons set forth above, we vacate and re-

mand the rulings under review.

So ordered.

EDWARDS, Senior Circuit Judge, dissenting:

Under the Federal Power Act, regulatory authority

over the nation’s electricity markets is bifurcated

between the States and the federal government. In

simplified terms, the Federal Energy Regulatory

Commission (“FERC” or “Commission”) has authority

over wholesale electricity sales but not retail electrici-

ty sales, with the latter solely subject to State regula-

tion. See 16 U.S.C. § 824(a), (b)(1). The consolidat-

ed petitions before the court call on us to parse this

jurisdictional line between FERC’s wholesale jurisdic-

tion and the States’ retail jurisdiction—a line which

this court and the Supreme Court have recognized is

neither neat nor tidy. See New York v. FERC, 535

U.S. 1, 16, 122 S. Ct. 1012, 152 L. Ed. 2d 47 (2002)

(“(TJhe landscape of the electric industry has changed

since the enactment of the [Federal Power Act], when

the electricity universe was ‘neatly divided into

spheres of retail versus wholesale sales.’” (quoting

Transmission Access Policy Study Grp. v. FERC, 225

F.3d 667, 691 (D.C. Cir. 2000))).

18a

Petitioners challenge Order 745, a rule imposing

certain compensation requirements on the administra-

tors of the nation’s wholesale electricity markets. See

Order 745, Demand Response Compensation in Orga-

nized Wholesale Energy Markets, 134 FERC 4 61,187,

2011 WL 890975, at *1 (Mar. 15, 2011). The rule re-

quires these wholesale-market administrators—called

Regional Transmission Organizations (“RTOs”) and

Independent System Operators (“ISOs”)—to compen-

sate so-called “demand response resources” at a speci-

fied price when certain conditions are met. As rele-

vant here, “demand response resources” are essen-

tially electricity consumers, often bundled together by

a third-party aggregator, who agree to reduce their

electricity consumption in exchange for incentive pay-

ments. See 18 C.F.R. § 35.28(b)(4)-(5). The pun

scattered throughout the record is that while genera-

tors produce megawatts, consumers produce “nega-

watts.” In effect, Order 745 requires that, at certain

times, megawatts and negawatts receive the same

amount of payment in wholesale markets, an amount

called the “locational marginal price” or “LMP.”

Although the challenged rule requires ISOs and

RTOs to pay demand response resources a specified

compensation (LMP), this requirement is applicable

only when two conditions are met: (1) when the de-

mand response resource is capable of balancing supply

and demand in the wholesale market, and (2) when

compensating the demand response resource is cost-

effective under a “net benefits test” prescribed by the

rule. The specific mechanics of these conditions and

of the “net benefits test” are less important than what

they accomplish. The critical point here is that, be-

19a

cause of the specified conditions, Order 745 requires

compensation of demand response resources only

when their participation in a wholesale electricity mar-

ket actually lowers the market-clearing price for

wholesale electricity.

With these basics in hand, it is easy to see why

FERC stated in its rulemaking that “jurisdiction over

demand response is a complex matter that lies at the

confluence of state and federal jurisdiction.” Order

745, 2011 WL 890975, at *30. On one view, the de-

mand response resources subject to the rule directly

affect the wholesale price of electricity. That is, the

final rule’s conditions operate to ensure that every

negawatt of forgone consumption receiving compensa-

tion reduces both the quantity of electricity produced

and its wholesale price. Focusing on this direct effect

—direct, it bears repeating, because under the rule’s

conditions all demand response resources receiving

compensation reduce the market-clearing price—it is

easy to conceive of Order 745 as permissibly falling on

the wholesale side of the wholesale-retail jurisdictional

line. On another view, however, the electricity not

consumed thanks to the rule’s compensation payments

would have been consumed first in a retail market.

Focusing on the market in which the consumption

would have occurred in the first instance, one can

conceive of Order 745 as impermissibly falling on the

retail side of the jurisdictional line.

The task for this court, of course, is not to divine

from first principles whether a demand response re-

source subject to Order 745 is best considered a matter

of wholesale or retail electricity regulation. Rather,

20a

our task is one of statutory interpretation within the

familiar Chevron framework. See Chevron U.S.A.

Inc. v. Natural Res. Def. Council, Inc., 467 U.S. 837,

842-44, 104 S. Ct. 2778, 81 L. Ed. 2d 694 (1984); see

also Cal. Indep. Sys. Operator Corp. (CAISO) v.

FERC, 372 F.3d 395, 399-400 (D.C. Cir. 2004). The

Commission has interpreted the Federal Power Act to

permit it to issue Order 745. And it falls to this court

to determine whether the Act unambiguously “sp[{eaks]

to the precise question,” 467 U.S. at 842, 104 S. Ct.

2778 (Chevron step one), and, if not, whether the Com-

mission’s interpretation is a permissible construction

of the statute, zd. at 843, 104 S. Ct. 2778 (Chevron step

two).

Though the rule and its operation are highly tech-

nical, the primary jurisdictional issue raised in these

consolidated petitions turns on a rather straightfor-

ward question of statutory interpretation: whether a

promise to forgo consumption of electricity that would

have been purchased in a retail electricity market un-

ambiguously constitutes a “sale of electric energy”

under section 201(b)(1) of the Federal Power Act. 16

U.S.C. § 824(b)(1). If so, the Commission lacked

jurisdiction to issue Order 745 because section 201(b)(1)

of the Act states, in relevant part, that the “provisions

of this subchapter shall apply to the sale of

electric energy at wholesale in interstate commerce,

but shall not apply to any other sale of elec-

tric energy.” Id. (emphasis added).

The statute, to my mind, is ambiguous regarding

whether forgone consumption constitutes a “sale”

under section 201(b)(1). Because of this ambiguity,

2la

the Act is also ambiguous as to whether a rule requir-

ing administrators of wholesale markets to pay a spec-

ified level of compensation for such forgone consump-

tion constitutes “direct regulation” of retail sales that

would contravene the limitations of section 201. Conn.

Dep't of Pub. Util. Control v. FERC, 569 F.3d 477,

481-82 (D.C. Cir. 2009) (holding that FERC’s approval

of an Installed Capacity Requirement was not “direct

regulation” of electrical generation facilities and, thus,

did not violate section 201 (emphasis added)). Be-

cause the Act is ambiguous regarding FERC’s author-

ity to require ISOs and RTOs to pay demand response

resources, we are obliged to defer under Chevron to

the Commission’s permissible construction of “a stat-

utory ambiguity that concerns the scope of the agen-

cy’s statutory authority (that is, its jurisdiction).”

City of Arlington v. FCC, —U.S.—, 133 S. Ct. 1863,

1868, 1874-75, —L. Ed. 2d— (2013).

Absent an affirmative limitation under section 201,

there is no doubt that demand response participation

in wholesale markets and the ISOs’ and RTOs’ market

rules concerning such participation constitute “prac-

tice[s]} affecting” wholesale rates under sec-

tion 206 of the Act. 16 U.S.C. § 824e(a); see also id.

§ 824d(a) (providing that “all rules and regulations

affecting or pertaining to [wholesale] rates or charges

shall be just and reasonable”). Petitioners’ argu-

ments to the contrary ignore the direct effect that the

ISOs’ and RTOs’ market rules have on wholesale elec-

tricity rates squarely within FERC’s jurisdiction.

The Commission has authority to “determine the just

and reasonable practice” by setting a level of

compensation for demand response resources that, in

22a

its expert judgment, will ensure that the rates charged

in wholesale electricity markets are “just and reasona-

ble.” Jd. § 824e(a). It was therefore reasonable for

the Commission to conclude that it could issue Order

745 under the Act’s “affecting” jurisdiction. See id.

§§ 824e(a), 824d(a).

In addition to challenging FERC’s jurisdiction, Pe-

titioners argue that its decision to mandate compensa-

tion equal to the LMP was arbitrary and capricious.

Petitioners believe that the LMP overcompensates de-

mand response resources since they also realize sav-

ings from not having to purchase retail electricity.

The Commission, Petitioners insist, should have set

the compensation level at the LMP minus the retail

cost of the forgone electricity. But the Commission’s

decision in this regard was reasonable and adequately

explained.

For these reasons, explained below in greater de-

tail, I respectfully dissent.

I BACKGROUND

A. The Problem

To understand this case, one must appreciate the

scope and significance of the problem FERC sought to

address in Order 745. Three characteristics of the

nation’s electricity market go a long way toward fram-

ing the problem. First, electricity, unlike most com-

modities, cannot be stored for later use. There must

instead be a continual, contemporaneous matching of

supply to meet current electricity demand. Second,

not all power plants are created equal: some are effi-

cient and cheap; others, inefficient and expensive.

23a

Third, most retail consumers are charged a fixed price

for electricity that does not adjust in the moment to

temporary spikes in the cost of producing electricity.

The first two characteristics, in tandem, cause sig-

nificant fluctuations in the cost of supplying electricity

at different times of day. During periods of regular

electricity consumption, only the efficient and cheap

power plants need be deployed. But at hours of peak

usage (¢.g., a summer afternoon in Washington, D.C.

when countless air conditioners toil against the humid-

ity and heat), the suppliers of electricity must marsha)

the least efficient and most costly power plants to

match the soaring demand for electricity. It is be-

cause electricity cannot be efficiently stored that these

periods of peak demand must be met with new genera-

tion and not stockpiled supply.

In a perfect market, or even in a well-functioning

market, the skyrocketing cost of producing additional

electricity at hours of peak usage would be reflected in

temporarily higher prices charged to consumers. In

turn, this increased price would reduce the megawatts

of electricity demanded, as some individuals and busi-

nesses would, for example, turn off their air condi-

tioners to save money. The market would thereby

reach an efficient equilibrium.

But here is where the third characteristic of elec-

tricity markets comes in. Retail electricity prices are

generally regulated to remain constant over longer

periods of time. That is, consumers do not pay dif-

ferent amounts during different hours of the day, not-

withstanding the sharply vacillating cost of producing

electricity. Electricity demand thus does not respond

24a

to time-sensitive price signals. As a result, there are

times when people and businesses consume electricity

that costs more to produce than it is worth to them to

consume. This is inefficient.

Wholesale electricity markets, which are under

FERC’s jurisdiction, suffer the same inefficiency. Since

retail demand is not price-responsive, the aggregate

amount of electricity demanded in the wholesale mar-

ket by the entities that serve retail customers is also

uncoupled from the time-specific price of supplying

electricity. In economic terms, the demand for elec-

tricity in the wholesale market is inelastic. See Order

745-A, Demand Response Compensation in Organized

Wholesale Energy Markets, 137 FERC 9% 61,215, 2011

WL 6523756, at *9 (Dec. 15, 2011).

The Commission recognizes the problem. As it ob-

served in its order denying requests for rehearing of

Order 745,

[a] properly functioning market should reflect both

the willingness of sellers to sell at a price and the

willingness of buyers to purchase at a price. In an

RTO- or [SO-run market, however, buyers are

generally unable to directly express their willing-

ness to pay for a product at the price offered. As

discussed later, RTOs and ISOs cannot isolate indi-

vidual buyers’ willingness to pay which results in

extremely inelastic demand.

Id.; see also Order 745, 2011 WL 890975, at *1 (“[A]

market functions effectively only when both supply

and demand can meaningfully participate.” (emphasis

added)).

25a

B. FERC’s Solution

Having identified a problem in the wholesale elec-

tricity market, the Commission has a statutory obliga-

tion to do what it can to fix it. That is because FERC

is charged under the Federal Power Act with ensuring

that wholesale electricity rates are “just and reasona-

ble.” 16 U.S.C. §§ 824d(a), 824e(a). It must ensure

that all “rates and charges made, demanded, or re-

ceived by any public utility for or in connection with

the sale of electric energy subject to the

jurisdiction of the Commission” are “just and reasona-

ble.” Jd. § 824d(a) (emphasis added); see also id.

§ 824(a). And when FERC determines that a “prac-

tice affecting” such a rate is unjust or un-

reasonable, it must itself determine and fix “the just

and reasonable practice to be

thereafter observed.” Jd. § 824e(a).

Consistent with its statutory duty and in view of

the market distortions caused by inelastic wholesale

demand, the Commission has initiated a series of re-

forms to open wholesale markets to “demand response

resources.” For our purposes, “demand response

resources” are resources that are capable of reducing

“the consumption of electric energy by customers from

their expected consumption in response to

incentive payments designed to induce lower consump-

tion of electric energy.” 18 C.F.R. § 35.28(b)(4)-(5).

Put simply, demand response resources agree not to

purchase electricity in exchange for payment.

The basic premise of FERC’s demand-response re-

forms is that there are two ways that wholesale-

market administrators (i.e., ISOs and RTOs) can bal-

26a

ance wholesale supply and demand: by increasing the

supply of electricity or by decreasing the demand for

it. See Order 745-A, 2011 WL 6523756, at *14. An

ISO or RTO reduces wholesale demand when it pays a

demand response resource because that resource will

forgo electricity consumption in the retail market,

which, in turn, will lead to fewer megawatts of elec-

tricity being demanded in the aggregate in that ISO’s

or RTO’s wholesale market. At certain times (e.g.,

summer afternoons in Washington, D.C.), paying in-

centive payments to induce consumers not to consume

electricity may be cheaper than paying generators to

produce more power; negawatts, in such circumstanc-

es, are the cheaper alternative. And because, func-

tionally, there is little difference to wholesale-market

administrators between a megawatt and a negawatt

(both assist equally in the administrator’s task of

bringing wholesale demand and supply into equipoise),

demand response resources are capable of competing

directly with traditional generation resources so long

as the appropriate market rules are in place.

For some years now, FERC has recognized that the

direct participation of demand response resources in

wholesale markets improves the functioning of these

markets in several respects. First, it lowers whole-

sale prices because “lower demand means a lower

wholesale price.” Order 719-A, Wholesale Competi-

tion in Regions with Organized Electric Markets, 128

FERC 4% 61,059, 2009 WL 2115220, at *12 (July 16,

2009). Second, it mitigates the market power of sup-

pliers of electricity because they have to compete with

demand response resources and adjust their bidding

strategy accordingly. See id. (“[T]he more demand

27a

response is able to reduce peak prices, the more down-

ward pressure it places on generator bidding strate-

gies by increasing the risk to a supplier that it will not

be dispatched if it bids a price that is too high.”).

Third, demand response “enhances system reliability,”

for example, by “reducing electricity demand at criti-

cal times (e.g., when a generator or a transmission line

unexpectedly fails).” Jd. at *12 & n.76; see also Order

745-A, 2011 WL 6523756, at *6 (“[D]jemand response

generally can be dispatched by the [ISO or RTO] with

a minimal notice period, helping to balance the electric

system in the event that an unexpected contingency

occurs.”).

The benefits of demand response participating in

wholesale markets are beyond reproach. Commis-

sioner Moeller, who dissented in Order 745, put it best:

While the merits of various methods for compen-

sating demand response were discussed at length in

the course of this rulemaking, nowhere did I review

any comment or hear any testimony that questioned

the benefit of having demand response resources

participate in the organized wholesale energy mar-

kets. On this point, there is no debate. The fact

is that demand response plays a very important role

in these markets by providing significant economic,

reliability, and other market-related benefits.

Order 745, 2011 WL 890975, at *34 (emphasis added)

(Moeller, dissenting).

It is no surprise, then, that FERC has initiated a

series of reforms to open up its markets to demand

response, on the theory that doing so helps to ensure

28a

“just and reasonable” wholesale rates by improving

how these markets function in the three ways just

mentioned. See Order 890, Preventing Undue Dis-

crimination and Preference in Transmission Service,

72 Fed. Reg. 12,226, 12,378 (Mar. 15, 2007); Order

719, Wholesale Competition in Regions with Orga-

nized Electric Markets, 73 Fed. Reg. 64,100 (Oct. 28,

2008); see also Br. for Resp’t at 11-13 (providing over-

view of these rulemakings); id. at 12 (noting that, be-

fore Order 719, FERC had approved proposals by

various ISOs and RTOs “to allow demand response

participation in their ancillary services markets” (cita-

tions omitted)).

In particular, in Order 719 FERC required ISOs

and RTOs to “accept bids from demand response re-

sources in RTOs’ and ISOs’ markets for certain ancil-

lary services on a basis comparable to other resources”

and, in certain circumstances, to “permit an aggrega-

tor of retail customers to bid demand re-

sponse on behalf of retail customers directly into the

organized energy market.” Order 719-A, 2009 WL

2115220, at *1. But FERC placed an important con-

dition on this requirement; ISOs and RTOs were re-

quired to accept bids from demand response “unless

not permitted by the laws or regulations of the rele-

vant electric retail regulatory authority.” 18 C.F.R.

§ 35.28(g)(1)(iA), (iii); Order 719-A, 2009 WL 2115220,

at *13. Finally, recognizing that “further reforms

may be necessary to eliminate barriers to demand

response in the future,” FERC further ordered ISOs

and RTOs to “assess and report on any remaining

barriers to comparable treatment of demand response

29a

resources that are within the Commission’s jurisdic-

tion.” Order 719-A, 2009 WL 2115220, at *1.

And further reforms were indeed necessary. Prior

to issuing Order 745, ISOs and RTOs had differing

practices concerning the level of compensation to be

paid to demand response resources in their markets.

Order 745, 2011 WL 890975, at *4. The Commission

found that many [ISOs and RTOs undercompensated

demand response resources in certain circumstances.

See id. at *16. It reached this finding in light of ex-

isting barriers to demand response participation in

wholesale markets, including “the lack of market in-

centives to invest in enabling technologies that would

allow electric customers and aggregators of retail

customers to see and respond to changes in marginal

costs of providing electric service as those costs change.”

Id.; see also id. (“[T]he inadequate compensation

mechanisms in place today in wholesale energy mar-

kets fail to induce sufficient investment in demand

response resource infrastructure and expertise that

could lead to adequate levels of demand response pro-

curement Without sufficient investment in the devel-

opment of demand response, demand response re-

sources simply cannot be procured because they do not

yet exist as resources. Such investment will not occur

so long as compensation undervalues demand response

resources.” (emphasis added) (quoting a commenter)).

Order 745 sought to correct the under-compensation

problem by mandating that ISOs and RTOs pay de-

mand response resources the same market price that

they pay to generators, i.e, LMP. But it limited this

compensation requirement to circumstances where two

30a

specific conditions are met. LMP-compensation would

be required only when (1) “the demand response re-

source [is} able to displace a generation resource in a

manner that serves the RTO cr ISO in balancing sup-

ply and demand,” and (2) “the payment of LMP

[is] cost-effective, as determined by [a] net

benefits test.” Jd. at *13; see also 18 C.F.R.

§ 35.28(g)(1)(v)(A).

FERC understood that it had authority to correct

the under-compensation problem because, in the ab-

sence of adequate compensation, too few demand re-

sponse resources affirmatively bid into the wholesale

markets. And such participation is necessary for the

market to function rationally and reach “just and rea-

sonable” rates. As FERC stated:

We find, based on the record here that, when a de-

mand response resource has the capability to bal-

ance supply and demand as an alternative to a gen-

eration resource, and when paying LMP

to that demand response resource is shown to be

cost-effective as determined by the net benefits test

described herein, payment by an RTO or ISO of

compensation other than the LMP is unjust and

unreasonable. When these conditions are met, we

find that payment of LMP to these resources will

result in just and reasonable rates for ratepayers.

Order 745, 2011 WL 890975, at *13 (emphasis added).

Il. ANALYSIS

A. Jurisdiction

Petitioners argue that Order 745 is “in excess” of

FERC’s “statutory jurisdiction.” Br. of Pet’rs Elec.

3la

Power Supply Ass’n, et al. (“Br. of Pet’rs”) at 27 (citing

5 U.S.C. § 706(2)(C)). We evaluate this contention

under Chevron and defer to FERC’s permissible con-

struction of its authorizing statute, regardless of

“whether the interpretive question presented is ‘juris-

dictional.’” City of Arlington, 133 S. Ct. at 1874-75;

see also Connecticut, 569 F.3d at 481. The proper

question is thus whether the Act unambiguously fore-

closes FERC from issuing Order 745 under its “af-

fecting” jurisdiction. See 16 U.S.C. § 824e; Chevron,

467 U.S. at 842, 104 S. Ct. 2778.

FERC’s explanation of its jurisdiction under the

Federal Power Act is straightforward and sensible.

FERC has the authority and responsibility to correct

any “practice affecting” wholesale electricity

rates that the Commission determines to be “unjust”

or “unreasonable.” 16 U.S.C. § 824e(a); see also id.

§ 824d(a). In its view, the ISOs’ and RTOs’ rules

governing the participation of demand response re-

sources in the nation’s wholesale electricity markets

are “practices affecting [wholesale electricity] rates.”

Order 745-A, 2011 WL 6523756, at *10 (quoting 16

U.S.C. §§ 824d, 824e). That is, an ISO’s or RTO’s

market rules governing how a demand response re-

source may compete in its wholesale market, including

the terms by which 2 demand response resource is to

be compensated in the market, are “practices affect-

ing” that wholesale market’s rates for electricity.

And FERC has determined that an ISO’s or RTO’s

“practice” is unjust and unreasonable to the degree

that it inadequately compensates demand response re-

sources capable of supplanting more expensive gener-

ation resources. See id. at *36. As explained above,

32a

FERC has found that demand response improves the

functioning of wholesale markets by (1) lowering the

wholesale price of electricity, (2) exerting downward

pressure on generators’ market power, and (3) en-

hancing system reliability.

FERC’s explanation is consistent with our case law.

In Connecticut, we considered whether FERC has jur-

isdiction to review an ISO’s capacity charges. 569

F.3d at 478-79. Capacity is not electricity but the

ability to produce it when needed, and in Connecticut

the ISO had established a market where capacity

providers—generators, prospective generators, and

demand response resources—competitively bid to meet

the ISO’s capacity needs three years in the future.

Id. at 479-81. Generation, like retail sales, is expres-

sly the domain of State regulation under section 201,

16 U.S.C. § 824(b)(1), and the petitioners argued that

by increasing the overall capacity requirement the ISO

was improperly requiring the installation of new gen-

eration resources. 569 F.3d at 481. We disagreed

and held that FERC had “affecting” jurisdiction under

section 206 because “capacity decisions af-

fect FERC-jurisdictional transmission rates for that

system without directly implicating generation facili-

ties.” Jd. at 484. That the capacity requirement

helped to “find the right price” was enough of an effect

to satisfy section 206. Jd. at 485.

Petitioners’ specific arguments against FERC’s

exercising jurisdiction are unpersuasive. First, Peti-

tioners note that section 201 of the Act establishes a

clear jurisdictional line between “the sale of electric

energy at wholesale in interstate commerce,” which is

33a

properly the subject of FERC’s jurisdiction, and “any

other sale of electric energy.” Br. of Pet’rs at 27-28

(citing 16 U.S.C. § 824(a), (b)(1)). According to Peti-

tioners, the Commission has transgressed this line

because it “has ordered ISOs and RTOs to pay retail

customers for reducing their retail purchases of elec-

tricity.” Id. at 28.

But this argument mischaracterizes the rule and

papers over a key ambiguity. First, the mischarac-

terization: Petitioners are wrong inasmuch as they

imply that FERC requires ali ISOs and RTOs to pay

demand response resources a minimum level of com-

pensation (LMP). The compensation requirement

promulgated in Order 745 does not apply unless an

ISO or RTO “has a tariff provision permitting demand

response resources to participate as a resource in the

energy market.” 18 C.F.R. § 35.28(g)(1)(v). And the

regulation’s requirement that ISOs and RTOs accept

bids from demand response resources comes with a

key caveat: the requirement applies “unless not per-

mitted by the laws or regulations of the relevant elec-

tric retail regulatory authority.” Jd. § 35.28(g)(1)(iXA);

see also id. § 35.28(g)(1)(iii). In other words, there is a

carve-out from the compensation requirement for ISOs

and RTOs in States where local regulatory law stands

in the way. Thus, the Order preserves State regula-

tion of retail markets. This is hardly the stuff of

grand agency overreach.

More fundamentally, Petitioners’ argument found-

ers on a statutory ambiguity they ignore. Section 201

makes clear that FERC may regulate “the sale of

electric energy at wholesale in interstate commerce”

34a

but not “any other sale of electric energy.” 16 U.S.C.

§ 824(b)(1) (emphasis added). The demand response

at issue here is forgone consumption, which is no

“sale” at all. Perhaps the phrase “any other sale of

electric energy” could be interpreted to include non-

sales that would have been sales in the retail market,

but it certainly does not require such a reading. It is

reasonable to categorize demand response as neither a

retail sale nor wholesale sale under the Federal Power

Act. And on this understanding, section 201 “says

nothing about” FERC’s power to review compensation

rates for demand response in wholesale electricity

markets. Connecticut, 569 F.3d at 483.

Nor is Petitioners’ argument under section 201

made any stronger by reference to subsection (a).

This prefatory subsection states that while “Federal

regulation of electric energy in interstate

commerce and the sale of such energy at wholesale in

interstate commerce is necessary in the public inter-

est,” federal regulation should “extend only to those

matters which are not subject to regulation by the

States.” 16 U.S.C. § 824(a). But the Supreme Court

has made clear that “the precise reserved state powers

language in § 201(a)” is a “mere policy declaration

that cannot nullify a clear and specific grant of juris-

diction, even if the particular grant seems inconsistent

with the broadly expressed purpose.” New York, 535

U.S. at 22, 122 S. Ct. 1012 (emphasis added) (interna!

quotation marks omitted). And, as I discuss below,

section 206’s specific grant of “affecting” jurisdiction

quite clearly authorized FERC to issue Order 745.

35a

The most that can be said of section 201 is that it

commits regulation of retail sales to the States and

regulation of wholesale sales to the Commission. And

while it is true that the forgone consumption would

have been purchased in the first instance in the retail

market, it does not follow from this fact that non-

consumption constitutes an “other sale” under section

201(b). There was no sale, period. And the statute

does not give a clear indication that Congress intended

to foreclose FERC from regulating non-sales that have

a direct effect on the wholesale markets under FERC’s

jurisdiction.

Even assuming that the Federal Power Act re-

quires demand response resources to be considered

inextricably part of retail “sales” subject solely to

State regulation, Order 745 does not engage in the

type of “direct regulation” that would violate section

201. See Connecticut, 569 F.3d at 481. Order 745

does not require anything of retail electricity consum-

ers and leaves it to the States to decide whether to

permit demand response. Al) Order 745 says is that if

a State’s laws permit demand response to be bid into

electricity markets, and if a demand response resource

affirmatively decides to participate in an ISO’s or

RTO’s wholesale electricity market, and if that de-

mand response resource would in a particular circum-

stance allow the ISO or RTO to balance wholesale sup-

ply and demand, and 7f paying that demand resource

would be a net benefit to the system, then the ISO or

RTO must pay that resource the LMP. That is it.

This requirement will no doubt affect how much elec-

tricity is consumed by a small subset of retail consum-

ers who elect to participate as demand response re-

36a

sources in wholesale markets. But that fact does not

render Order 745 “direct regulation” of the retail mar-

ket. Authority over retail rates and over whether to

permit demand response remains vested solely in the

States.

In this respect, Order 745 is similar to the capacity

rule in Connecticut that we found did not directly reg-

ulate generation facilities. 569 F.3d at 482. Even

though increasing the capacity requirement incentiv-

ized the procurement of additional resources, including

new generation facilities, to meet the higher require-

ment, we recognized that States retained their ulti-

mate authority over the construction of new genera-

tion facilities. /d. at 481-82. And because the ca-

pacity requirements could be met in other ways aside

from building new generators (e.g., through demand

response or capacity contracts), it was irrelevant that

“public utilities overwhelmingly responded

to [increased capacity requirements] by choosing to

allow construction of new facilities over other alterna-

tives.” Id. at 482. The lesson of Connecticut is that

FERC can indirectly incentivize action that it cannot

directly require so long as it is otherwise acting within

its jurisdiction—and that doing so does not constitute

impermissible direct regulation of an area reserved to

the States. So too here: Order 745 may encourage

more demand response, but States retain the ultimate

authority to approve the practice.

Second, Petitioners argue that the FERC’s “affect-

ing” jurisdiction under sections 205 and 206 of the Act

“does not extend so far as to allow the Commission to

regulate directly the retail services that are expressly

37a

carved out from the scope of its jurisdiction.” Br. of

Pet’rs at 30-31 (citing 16 U.S.C. § 824(a), (b)(1)). To a

large degree, this argument simply rehashes Petition-

ers’ erroneous reading of section 201 and fails for the

reasons just described. Demand response resources

are promises to forgo consumption of electricity and

therefore are not retail “sales.” This is not changed

by the fact that forgone consumption would have taken

place in the first instance in a retail market. Because

of this, the Commission’s asserting “affecting” juris-

diction over demand response does not, as Petitioners

suggest, “nullify[]” a limitation set forth in section 201.

Id. at 32.

To.be sure, section 206 cannot be read to displace

unambiguous jurisdictional limits imposed by section

201(b). Suppose, for example, that FERC issued a

rule requiring ISOs and RTOs to condition all whole-

sale sales of electricity on load-serving entities’ agree-

ing to charge retail customers with real-time pricing

that adjusted hourly for variations in the cost of pro-

ducing electricity. Such a rule would unambiguously

regulate each retail “sale” because it would mandate

a particular form of compensation for actwal—not

counter-factual—retail sales. Thus, while price-

responsive retail pricing would no doubt “affect” the

wholesale rate, FERC could not claim jurisdiction

under sections 205 and 206 because the subchapter

which includes these sections “shall not apply to any

other sale of electric energy.” 16 U.S.C. § 824(b)(1)

(emphasis added). This example plainly differs from

the present case because demand response resources

are forgone sales or non-sales, and therefore it is at

best ambiguous whether the limitation in section 201(b)

38a

applies. See Connecticut, 569 F.3d at 483 (“Section

201 prohibits the Commission from regulating genera-

tion facilities but says nothing about its power to re-

view the capacity requirements that an [ISO] imposes

on member [utilities].”).

To bolster their case, Petitioners invoke the specter

of limitless federal authority if FERC is permitted to

exercise “affecting” jurisdiction to issue Order 745.

They caution that “the Commission’s expansive inter-

pretation of its ‘affecting’ jurisdiction would allow it to

regulate any number of activities—such as the pur-

chase or sale of steel, fuel, labor, and other inputs

influencing the cost to generate or transmit electricity

—merely by redefining the activities as ‘practices’ that

affect wholesale rates.” Br. of Pet’rs at 33.

This argument cannot carry the day be-cause it ig-

nores at least two important limits. It first ignores

section 201’s limit proscribing any “direct regulation”

of retail sales (which would bar the hypothetical rule,

discussed above, in which FERC tries to mandate that

retail sales have dynamic, time-responsive pricing).

See Connecticut, 569 F.3d at 481. It also ignores the

limitations we announced in CA/SO, 372 F.3d 395.

There, we held that FERC exceeded its jurisdiction

when it replaced the board members of an ISO on the

theory that the composition of the ISO’s board was a

“practice affecting [a] rate” under section

206(a). Jd. at 399. We held that “section 206’s em-

powering of the Commission to assess the justness and

reasonableness of practices affecting rates of electric

utilities is limited to those methods or ways of doing

things on the part of the utility that directly affect the

39a

rate or are closely related to the rate, not all those

remote things beyond the rate structure that might in

some sense indirectly or ultimately do so.” /d. at 403

(emphasis added).

These limits foreclose the parade of horribles mar-

shaled by Petitioners. Like replacing the ISO's board

of directors in CAJSO, FERC could not, consistent

with Circuit precedent, regulate markets in steel, fuel,

labor, and other inputs for generating electricity,

which constitute “remote things beyond the rate struc-

ture that might in some sense indirectly or ultimately”

affect the wholesale rate of electricity. Jd.; see also

Calpine Corp. v. FERC, 702 F.3d 41, 47 (D.C. Cir.

2012) (affirming FERC’s determination that it lacked

“affecting” jurisdiction over station power, which is a

necessary input to energy production, because there

‘was not a “sufficient nexus with wholesale transac-

tions” (internal quotation marks omitted) (citing City

of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir.

1985))); City of Cleveland, 773 F.2d at 1376 (“[T]here is

an infinitude of practices affecting rates and service.

The statutory directive must reasonably be read to

require the recitation of only those practices that affect

rates and service significantly. ” (emphasis

added)).

Order 745 passes the CAISO test quite comfortably

because the demand response resources subject to the

rule have a quintessentially “direct” effect on whole-

sale rates. The rule’s compensation requirement ap-

plies only when an ISO or RTO can use the demand

response resource in lieu of a generation resource to

balance supply and demand, and only when paying a

40a

demand response resource is cost-effective under the

rule’s net benefits test. 18 C.F.R. § 35.28(g)(1)(v)(A).

Order 745 thus does not purport to regulate demand

response writ large; its compensation requirement

applies only when the demand response by definition

alters the wholesale electricity price. That is about as

“direct” an effect and as clear a “nexus” with the

wholesale transaction as can be imagined. See Cal-

pine Corp., 702 F.3d at 47; CAIJSO, 372 F.3d at 403;

City of Cleveland, 773 F.2d at 1376. There can be

little doubt that FERC has the authority to review the

justness and reasonableness of rates that are so close-

ly connected with the healthy functioning of its juris-

dictional markets; this, as we said in Connecticut, is

the “heartland of the Commission’s section 206 juris-

diction.” 569 F.3d at 483.

Third, Petitioners argue that the Commission’s or-

ders exceed its jurisdiction because “they unreasona-

bly interfere with existing state and local programs

addressing retail customer ‘demand response.’” Br.

of Pet’rs at 41. Any such effect, however, is merely

incidental. As the Commission correctly observed,

Order 745 “does not directly affect retail-level demand

response programs, nor does it require that demand

response resources offer into the wholesale market

only. Indeed, the organized wholesale energy mar-

kets can and do operate simultaneously with retail-

level programs. ”" Order 745-A, 2011 WL

6523756, at *19. FERC’s reforms in Order 745 run on

a parallel track with State-level reforms. And to

the degree that FERC’s reforms incidentally affect

parallel State-level initiatives, that does not render

FERC’s actions improper. See Natl Ass'n of Regula-

4la

tory Util. Comm'rs v. FERC, 475 F.3d 1277, 1280 (D.C.

Cir. 2007) (observing that FERC’s authority to act

within its statutory scope of jurisdiction “may, of

course, impinge as a practical matter on the behavior

of non-jurisdictional” entities).

* * *

To summarize: FERC’s jurisdiction turns on two

issues: (1) whether demand response is a retail “sale”

or is otherwise unambiguously committed to State reg-

ulation under the Federal Power Act, and (2) whether

sections 205 and 206 clearly grant jurisdiction to

FERC to regulate how wholesale-market administra-

tors compensate demand response resources that

“directly affect” wholesale prices. Unless we inject

quasi-philosophy into our Chevron analysis (what is

the sound of one hand clapping? what is the true na-

ture of a sale that was never made? of megawatts

never consumed?), I think it clear that the Federal

Power Act does not precisely address the first ques-

tion; forgone consumption is not unambiguously a

“sale,” nor does the statute dictate that demand re-

sponse be treated solely as a matter of retail regula-

tion. And the second question is resolved, in my view,

by the terms of Order 745 which narrowly apply only

to demand response resources that by definition di-

rectly affect the wholesale rates of electricity. This

falls squarely within the Commission’s “affecting” jur-

isdiction. See 16 U.S.C. §§ 824d, 824e. The proper

course for this court is to defer to the Commission's

well-reasoned and permissible interpretation of its

authority under the statute.

42a

B. Level of Compensation

Petitioners also argue that Order 745 is arbitrary

and capricious under 5 U.S.C. § 706(2)(A). In re-

viewing such claims, we consider whether FERC

“examine[d] the relevant data and articulate[d] a sat-

isfactory explanation for its action including a rational

connection between the facts found and the choice

made.” Motor Vehicle Mfrs. Ass’n of the U.S. v. State

Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43, 103 S. Ct.

2856, 77 L. Ed. 2d 443 (1983) (internal quotation marks

omitted). We also afford significant deference to

FERC in light of the highly technical regulatory land-

scape that is its purview. Indeed, “the Commission

enjoys broad discretion to invoke its expertise in bal-

ancing competing interests and drawing administra-

tive lines.” Am. Gas Ass’n v. FERC, 593 F.3d 14, 19

(D.C. Cir. 2010). And we “afford great deference to

the Commission” in cases involving ratemaking deci-

sions as the “statutory requirement that rates be ‘just

and reasonable’ is obviously incapable of precise judi-

cial definition.” Morgan Stanley Capital Grp. Inc.

v. Pub. Util. Dist. No. 1, 554 U.S. 527, 532, 128 S. Ct.

2733, 171 L. Ed. 2d 607 (2008). Finally, to the extent

that the Commission bases its actions on factual find-

ings, such findings are conclusive if supported by sub-

stantial evidence. 16 U.S.C. § 8251 (b).

Petitioners’ chief complaint is that Order 745 sets

the required compensation level for demand response

at the LMP (recall: locational marginal price). LMP

equals “the marginal value of an increase in supply or a

reduction in consumption at each node within” an

ISO’s or RTO’s wholesale market, and is the compen-

43a

sation generation resources generally receive. Order

745-A, 2011 WL 6523756, at *20. Petitioners com-

plain that demand response resources already get the

benefit of the forgone expense of retail electricity

(abbreviated in the record as “G”). Therefore, Peti-

tioners contend that, under FERC’s rule, demand re-

sponse resources effectively receive a “double pay-

ment”: LMP plus G. Br. of Pet’rs at 47. According

to Petitioners, requiring LMP compensation thus re-

sults in unjust and discriminatory overcompensation of

demand response resources. /d. at 45-50; see also

Order 745-A, 2011 WL 6523756, *38 (Moeller, dissent-

ing).

It is of course true, as the majority observes, that

FERC is “bounded by the requirements of reasoned

decision making.” Am. Gas Ass’n, 593 F.3d at 19.

Therefore, FERC was required to provide a “direct

response” to the Petitioners’ and the dissenting Com-

missioner’s concerns about overcompensation. Jd. at

20. This is precisely what the Commission did in

carefully explaining how Order 745’s setting compen-

ation at the LMP was neither discriminatory nor

unjust.

_ To begin with, FERC provided a thorough explana-

tion for why compensating demand response at the

LMP (and not LMP-G) was neither unjust nor over-

Compensatory. It explained that such compensation

Was necessary to encourage an adequate level of de-

mand response participation in wholesale markets in

light of existing market barriers. See Order 745-A,

2011 WL 6523756, at *15 (noting that Petitioners “fail

to acknowledge the market imperfections caused by

44a

the existing barriers to demand response”). That last

part—the market barriers—is the key. The Commis-

sion has identified numerous barriers preventing ade-

quate participation of demand response in wholesale

markets. Order 745, 2011 WL 890975, at *16 & n.122

(citing study). Indeed, citing record evidence, the

Commission explained that “the inadequate compensa-

tion mechanisms in place today in wholesale energy

markets fail to induce sufficient investment in demand

response resource infrastructure and expertise that

could lead to adequate levels of demand response pro-

curement.” Jd. at *16 (quoting a commenter). FERC

further explained that “a lack of incentives to invest in

enabling technologies can be addressed by making

additional investment resources available to market

participants” and that paying LMP “to demand re-

sponse will provide the proper level of investment re-

sources available for capital improvements.” Order

745-A, 2011 WL 6523756, at *16. In view of these

barriers, and the value of demand response participa-

tion to ensuring “just and reasonable” wholesale rates,

the Commission concluded that LMP was the appro-

priate level of compensation.

FERC sums it up well:

The Commission acknowledged that noted experts

differed on whether paying LMP in the current cir-

cumstances facing the wholesale electric market is a

reasonable price. In determining that LMP is the

just and reasonable price to pay for demand re-

sponse, the Commission examined some of the pre-

viously recognized barriers to demand response

that exist in current wholesale markets. These

45a

barriers create an inelastic demand curve in the

wholesale energy market that results in higher

wholesale prices than would be observed if the de-

mand side of the market were fully developed.

The Commission found that paying LMP when cost-

effective may help remove these barriers to entry of

potential demand response resources, and, thereby,

help move prices closer to the levels that would re-

sult if all demand could respond to the marginal

price of energy.

Id. at *17. This is a “direct response” to the points

raised by the Petitioners. Am. Gas Ass’n, 593 F.3d at

20.

With respect to the argument that utilizing the

LMP is somehow discriminatory because incomparable

resources are paid comparable amounts, the Commis-

sion offered reasonable grounds for treating demand

response as comparable to generation resources. The

Commission observed that, from the perspective of an

ISO or RTO, a demand response resource was compa-

rable to a generation resource inasmuch as demand

response is equally capable of balancing wholesale

supply and demand. Order 745-A, 2011 WL 6523756,

at *14. This is not the sum total of the explanation,

however. In the same section of its order, the Com-

mission explained that “examining cost avoidance by

demand response resources is not consistent with the

treatment of generation. In the absence of market

power concerns, the Commission generally does not

examine each of the costs of production for individual

resources participating as supply resources in the

organized wholesale electricity markets.” /d. at *17;

46a

see also id. at *21. FERC continued: “we note that

certain generators may receive benefits or savings in

the form of credits or in other forms. In these cases,

the generators realize a value of LMP plus the credit

or savings, but ISOs or RTOs do not take such benefits

or savings into account in determining how much to

pay those resources.” /d. at *17n.122. The point is

that the comparability of compensation is assessed

without regard to outside costs and credits; just as two

generators are both compensated at the LMP even

though only one might be receiving a tax credit for

producing energy, so too with comparing demand re-

sponse resources to generation resources. This was

clearly explained, and it is reasonable.

This court has no business second-guessing the

Commission’s judgment on the level of compensation.

See La. Pub. Serv. Comm’n v. FERC, 551 F.3d 1042,

1045 (D.C. Cir. 2008) (noting that “[wJhere the subject

of our review is a predictive judgment by

FERC about the effects of a proposed remedy

, our deference is at its zenith”); Pub. Serv.

Comm'n of Ky. v. FERC, 397 F.3d 1004, 1009 (D.C.

Cir. 2005) (holding that “more than second-guessing

close judgment calls is required to show that a rate

order is arbitrary and capricious” (citation omitted));

Envtl. Action, Inc. v. FERC, 939 F.2d 1057, 1064 (D.C.

Cir. 1991) (“{I]t is within the scope of the agency’s

expertise to make a prediction about the

market it regulates, and a reasonable prediction de-

serves our deference notwithstanding that there might

also be another reasonable view.”).

47a

Whatever policy disagreements one might have

with Order 745 ’s decision to compensate demand re-

sponse resources at the LMP (and there are legitimate

disagreements to be had), the rule does not fail for

want of reasoned decisionmaking. FERC’s judgment

is owed deference because it has put forth a reasonable

multistep explanation of its decision to mandate LMP

compensation. First, responsive demand is a neces-

sary component of a well-functioning wholesale mar-

ket, and FERC understood that its obligation to en-

sure just and reasonable rates required it to facilitate

an adequate level of demand response particivation in

its jurisdictional markets. See Order 745, 2011 WL

890975, at *16. Second, FERC concluded that market

barriers were inhibiting an adequate level of demand

response participation. See id. Third, FERC con-

cluded that mandating LMP would provide the proper

incentives for demand response resources to overcome

these barriers to participation in the wholesale market.

See id.; see also Notice of Proposed Rulemaking, De-

mand Response Compensation in Organized Whole-

sale Energy Markets, reprinted in J.A. 208, 220-21

(stating that “demand response resources react cor-

fespondingly to increases or decreases in payment”

and citing study showing that switching from LMP to

LMP-G compensation resulted in a 36.8% decrease in

demand response participation in the ISO being stud-

ied).

III. CONCLUSION

FERC had jurisdiction to issue Order 745 because

demand response is not unambiguously a matter of re-

tail regulation under the Federal Power Act, and be-

48a

cause the demand response resources subject to the

rule directly affect wholesale electricity prices. See

16 U.S.C. §§ 824d, 824e. And the Commission’s deci-

sion to require compensation equal to the LMP, rather

than LMP-G, was not arbitrary or capricious. The

majority disagrees on both points. The unfortunate

consequence is that a promising rule of national

significance—promulgated by the agency that has

been authorized by Congress to address the matters in

issue—is laid aside on grounds that I think are incon-

sistent with the statute, at odds with applicable prec-

edent, and impossible to square with our limited scope

of review. I therefore respectfully dissent.

49a

APPENDIX B

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 C.F.R. Part. 35

[Docket No. RM10-17-000; Order No. 745)

Demand Response Compensation in Organized

Wholesale Energy Markets

(Issued Mar. 15, 2011)

AGENCY: Federal Energy Regulatory Commission.

ACTION: Final Rule.

SUMMARY: In this Final Rule, the Federal Energy

Regulatory Commission (Commission) amends its reg-

ulations under the Federal Power Act to ensure that

when a demand response resource participating in an

organized wholesale energy market administered by a

Regional Transmission Organization (RTO) or Inde-

pendent System Operator (ISO) has the capability to

balance supply and demand as an alternative to a gen-

eration resource and when dispatch of that demand re-

sponse resource is cost-effective as determined by the

net benefits test described in this rule, that demand

response resource must be compensated for the ser-

vice it provides to the energy market at the market

50a

price for energy, referred to as the locational marginal

price (LMP). This approach for compensating de-

mand response resources helps to ensure the competi-

tiveness of organized wholesale energy markets and

remove barriers to the participation of demand re-

sponse resources, thus ensuring just and reasonable

wholesale rates.

EFFECTIVE DATE: This Final Rule will become

effective on [INSERT DATE 30 DAYS AFTER DATE

OF PUBLICATION IN THE FEDERAL REGIS-

TER]. Dates for compliance and other required fil-

ings are provided in the Final Rule.

FOR FURTHER INFORMATION CONTACT:

David Hunger (Technical Information)

Office of Energy Policy and Innovation

Federal Energy Regulatory Commission

888 First Street, NE, Washington, DC 20426

(202) 502-8148

david. hunger@ferc.gov

Dennis Hough (Legal Information)

Office of the General Counsel

Federal Energy Regulatory Commission

888 First Street, NE, Washington, DC 20426

(202) 502-8631

dennis. hough@ferc.gov

SUPPLEMENTARY INFORMATION:

5la

134 FERC 4 61,187

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Demand Response Compensation in Organized

Wholesale Energy Markets

ITI.

Docket No. RM10-17-000

ORDER NO. 745

TABLE OF CONTENTS

(Issued Mar. 15, 2011)

Paragraph Numbers

III i scacreseceeeneinmnesiinnsiehlinibiapilanieeeaneeaised 1.

Sun i iaitiecchansinionceiiipeiunbbidabianiouaticnddtte 8.

ET II ss crencsaeeeneseseinotetpenianeienmassis 15.

iii cdactereerrneenseinniaininancenimiaiinaigia 17.

Be, CRBROMBREESR LGUOL..n.ccccccccesccccscscescescsees 18.

i, I Sisccnicciinninenicioneniinderosomenadligs 18.

Be Si diniinidiscnciiniiicnnsistsiinsimnnicnienased 20.

a) Capability of Demand Response

and Generation Resources to Balance

Se TIED seireesisenicnsssitcnenslcsiiteiiendsenid 20.

b) Appropriateness of a Net Benefits

p ERE eee een eee ae 38.

c) Standardization or Regional

Variations in Compensation................. 43.

3. Commission Determination ................. 45.

B. Implementation of a Net Benefits Test....68.

is A cite iticinitniiis pnieniimesiamnatiie 68.

52a

C. Measurement and Verification.................. 86.

DFR ee FE cccccsicrsicsterenninesaiiteail 86.

a aticsininsciicnietctictancineccdenin 88.

3. Commission Determination ................. 93.

BO CR Bl cninttiiitineniintinenedemennensaninn 96.

eg fg 96.

GS Soin cinsiivsetiieone 97.

3. Commission Determination ................. 99.

E. Commission Jurisdiction ...............s0eceee 103.

5. GER cnn 103.

2. Commission Determination ............... 112.

V. Information Collection Statement................ 116.

VI. Environmental Analysis....................:c.sseeees 121.

VII. Regulatory Flexibility Act 0.0.0.0... 122.

RT 130.

IX. Effective Date and Congressional

I sicicccnsteccitbuiciasiactialinabiiieiiitmiiuaiadaehal 133.

Regulatory Text

APPENDIX: List of Commenters

53a

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Before Commissioners: Jon Wellinghoff, Chairman;

Mare Spitzer, Philip D.

Moeller, John R. Norris,

and Chery! A. LaFleur.

Demand Response Compensation in Organized

Wholesale Energy Markets

Docket No. RM10-17-000

FINAL RULE

ORDER NO. 745

(Issued Mar. 15, 2011)

I. Introduction

1. This Final Rule addresses compensation for de-

mand response in Regiona) Transmission Organization

(RTO) and Independent System Operator (ISO) orga-

nized wholesale energy markets, i.e., the day-ahead

and real-time energy markets. As the Commission

has previously recognized, a market functions effec-

tively only when both supply and demand can mean-

ingfully participate. The Commission, in the Notice

of Proposed Rulemaking (NOPR) issued in this pro-

ceeding on March 18, 2010, proposed a remedy to con-

cerns that current compensation levels inhibited mean-

ingful demand-side participation.' After nearly 3,800

pages of comments, a subsequent technical conference,

Notice of Proposed Rulemaking, 75 FR 15362 (Mar. 29,

2010), FERC Stats. & Regs. 1 32,656 (2010) (NOPR).

54a

and the opportunity for additional comment, we now

take final action.

2. We conclude that when a demand response’ re-

source’ participating in an organized wholesale energy

market‘ administered by an RTO or ISO has the capa-

bility to balance supply and demand as an alternative

to a generation resource and when dispatch of that de-

mand response resource is cost-effective as deter-

mined by the net benefits test described herein, that

demand response resource must be compensated for

the service it provides to the energy market at the

market price for energy, referred to as the locational

* Demand response means a reduction in the consumption of elec-

tric energy by customers from their expected consumption in re-

sponse to an increase in the price of electric energy or to incentive

payments designed to induce lower consumption of electric energy.

18 CFR 35.28(b)(4) (2010).

* Demand response resource means a resource capable of pro-

viding demand response. 18 CFR 35.28(b)(5).

‘ The requirements of this final rule apply only to a demand re-

sponse resource participating in a day-ahead or real-time energy

market administered by an RTO or ISO. Thus, this Final Rule does

not apply to compensation for demand response under programs

that RTOs and ISOs administer for reliability or emergency condi-

tions, such as, for instance, Midwest ISO’s Emergency Demand Re-

sponse, NYISO’s Emergency Demand Response Program, and

P.JM’s Emergency Load Response Program. This Final Rule also

does not apply to compensation in ancillary services markets, which

the Commission has addressed — eg

No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¥ aie

(2008) (Order No. 719).

55a

marginal price (LMP).° The Commission finds that

this approach to compensation for demand response

resources is necessary to ensure that rates are just

and reasonable in the organized wholesale energy

markets. Consistent with this finding, this Final Rule

adds section 35.28(g)(1)(v) to the Commission’s regula-

tions to establish a specific compensation approach for

demand response resources participating in the orga-

nized wholesale energy markets administered by RTOs

and ISOs. The Commission is not requiring the use

of this compensation approach when demand response

resources do not satisfy the capability and cost-

effectiveness conditions noted above.*®

3. This cost-effectiveness condition, as determined

by the net benefits test described herein, recognizes

that, depending on the change in LMP relative to the

size of the energy market, dispatching demand re-

sponse resources may result in an increased cost per

unit ($/MWh) to the remaining wholesale load associ-

ated with the decreased amount of load paying the bill.

This is the case because customers are billed for en-

ergy based on the units, MWh, of electricity consumed.

We refer to this potential result as the billing unit

* LMP refers to the price calculated by the ISO or RTO at partic-

ilar locations or electrical nodes or zones within the ISO or RTO

footprint and is used as the market price to compensate generators.

There are variations in the way that RTOs and ISOs calculate LMP;

however, each method establishes the marginal value of resources in

that market. Nothing in this Final Rule is intended to change RTO

and ISO methods for calculating LMP.

.* The Commission’s findings in this Final Rule do not preclude

the Commission from determining that other approaches to compen-

gation would be acceptable when these conditions are not met.

56a

effect of dispatching demand response. By contrast,

dispatching generation resources does not produce this

billing unit effect because it does not result in a de-

crease of load. To address this billing unit effect, the

Commission in this Final Rule requires the use of the

net benefits test described herein to ensure that the

overall benefit of the reduced LMP that results from

dispatching demand response resources exceeds the

cost of dispatching and paying LMP to those re-

sources. When the net benefits test described herein

is satisfied and the demand response resource clears in

the RTO’s or ISO’s economic dispatch, the demand re-

sponse resource is a cost-effective alternative to gen-

eration resources for balancing supply and demand.

4. To implement the net benefits test described

herein, we direct each RTO and ISO to develop a

mechanism as an approximation to determine a price

level at which the dispatch of demand response re-

sources will be cost-effective. The RTO or ISO should

determine, based on historical data as a starting point

and updated for changes in relevant supply conditions

such as changes in fuel prices and generator unit

availability, the monthly threshold price corresponding

to the point along the supply stack beyond which the

overall benefit from the reduced LMP resulting from

dispatching demand response resources exceeds the

cost of dispatching and paying LMP to those re-

sources. This price level is to be updated monthly, by

57a

each ISO or RTO, as the historic data and relevant

supply conditions change.’

5. This Final Rule also sets forth a method for allo-

cating the costs of demand response payments among

all customers who benefit from the lower LMP result-

ing from the demand response.

6. The tariff changes needed to implement the com-

pensation approach required in this Final Rule, in-

cluding the net benefits test, measurement and verifi-

cation explanation and proposed changes, and the cost

allocation mechanism must be made on or before July

22,2011. All tariff changes directed herein should be

submitted as compliance filings pursuant to this Final

Rule, not pursuant to section 205 of the Federal Power

Act (FPA).* Accordingly, each RTO’s or ISO’s com-

pliance filing to this Final Rule will become effective

prospectively from the date of the Commission order

addressing that filing, and not within 60 days of sub-

mission.

7. In addition, we believe that integrating a deter-

mination of the cost-effectiveness of demand response

resources into the dispatch of the ISOs and RTOs may

be more precise than the monthly price threshold and,

therefore, provide the greatest opportunity for load to

benefit from participation of demand response in the

organized wholesale energy market administered by

an RTO or ISO. However, we acknowledge the posi-

"In its compliance filing an RTO or ISO may attempt to show, in

whole or in part, how its proposed or existing practices are con-

sistent with or superior to the requirements of this Final Rule.

® 16 U.S.C. 824d (2006).

58a

tion of several of the RTOs and ISOs that modification

of their dispatch algorithms to incorporate the costs

related to demand response may be difficult in the

near term. In light of those concerns, we require

each RTO and ISO to undertake a study examining the

requirements for and impacts of implementing a dy-

namic approach which incorporates the billing unit

effect in the dispatch algorithm to determine when

paying demand response resources the LMP results in

net benefits to customers in both the day-ahead and

real-time energy markets. The Commission directs

each RTO and ISO to file the results of this study with

the Commission on or before September 21, 2012.°

Il. Background

8. Effective wholesale competition protects custom-

ers by, among other things, providing more supply op-

tions, encouraging new entry and innovation, and spur-

ring deployment of new technologies.” Improving

the competitiveness of organized wholesale energy

markets is therefore integral to the Commission ful-

filling its statutory mandate under the FPA to ensure

* We note that this report is for informational purposes only and

will neither be wane nor nn rorya action,

10

a — Ban Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC

Stats. & Regs. 7 31,281, at P 1 (2008) (Order No. 719); see also Re-

gional Transmission Organizations, Order No. 2000, FERC Stats. &

Regs. 7 31,089, at P 1 (1999), order on reh’g, Order No. 2000-A,

FERC Stats. & Regs. 1 31,092 (2000), aff'd sub nom. Pub. Util. Dist,

No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607, 348

U.S. App. D.C. 205 (D.C. Cir. 2001).

59a

supplies of electric energy at just, reasonable, and not

unduly discriminatory or preferential rates."

9. As the Commission recognized in Order No. 719,

active participation by customers in the form of de-

mand response in organized wholesale energy markets

helps to increase competition in those markets.” De-

mand response, whereby customers reduce electricity

consumption from normal usage levels in response to

price signals, can generally occur in two ways:

(1) customers reduce demand by responding to retail

rates that are based on wholesale prices (sometimes

called “price-responsive demand”); and (2) customers

provide demand response that acts as a resource in

organized wholesale energy markets to balance supply

and demand. While a number of states and utilities

are pursuing retail-level price-responsive demand ini-

tiatives based on dynamic and time-differentiated re-

tail prices and utility investments in demand response

enabling technologies, these are state efforts, and,

thus, are not the subject of this proceeding. Our

focus here is on customers or aggregators of retail

customers providing, through bids or self-schedules,

demand response that acts as a resource in organized

wholesale energy markets.

10. As the Commission stated in Order No. 719," and

emphasized in the NOPR,” there are several ways in

" 16 U.S.C. 824d (2006); Order No. 719, FERC Stats. & Regs.

31,281 at P 1.

» See Order No. 719, FERC Stats. nthe 4 31,281 at P 48.

Markets, Order No. 719-A, FERC ute & Regs. 1 31,292, at P 48

(2009).

60a

which demand response in organized wholesale energy

markets can help improve the functioning and compet-

itiveness of those markets. First, when bid directly

into the wholesale market, demand response can facil-

itate RTOs and ISOs in balancing supply and demand,

and thereby, help produce just and reasonable energy

prices.“ This is because customers who choose to re-

spond will signal to the RTO or ISO and energy mar-

ket their willingness to reduce demand on the grid

which may result in reduced dispatch of higher-priced

resources to satisfy load.” Second, demand response

can mitigate generator market power.’ This is be-

cause the more demand response that sees and re-

sponds to higher market prices, the greater the com-

petition, and the more downward pressure it places on

generator bidding strategies by increasing the risk to

‘* NOPR, FERC Stats. & Regs. 9 32,656 at P 4.

‘* For example, a study conducted by PJM, which simulated the

effect of demand response on prices, demonstrated that a modest

three percent load reduction in the 100 highest peak hours corre-

sponds to a price decline of six to 12 percent. ISO-RTO Council Re-

port, Harnessing the Power of Demand How RTOs and ISOs Are In-

tegrating Demand Response into Wholesale Electricity Markets,

found at http://www.isorto.org/atf/cf/*%7B5B4E85C6-7EAC-40A0

-8DC3-003829518EBD®%7D/IRC DR Report 101607.pdf.

‘© Id. (“Demand response tends to flatten an area’s load profile,

which in turn may reduce the need to construct and use more costly

resources during periods of high demand; the overall effect is to

lower the average cost of producing energy.”).

'T See Comments of NYISO’s Independent Market Monitor filed

in Docket No. ERO9-1142-000, May 15, 2009 (Demand response “con-

tributes to reliability in the short-term, resource adequacy in the

long-term, reduces price volatility and other market costs, and miti-

gates supplier market power.”).

6la

a supplier that it will not be dispatched if it bids a price

that is too high.” Third, demand response has the

potential to support system reliability and address re-

source adequacy’ and resource management chal-

lenges surrounding the unexpected loss of generation.

This is because demand response resources can pro-

vide quick balancing of the electricity grid.”

11. Congress has recognized the importance of de-

mand response by enacting national policy requiring

its facilitation.** Consistent with that policy, the

iF]

Id.

® See ISO-RTO Council Report, Harnessing the Power of De-

mand How RTOs and ISOs Are Integrating Demand Response into

Wholesale Electricity Markets at 4, found at http://www. isorto.org/

atf/cf/%7B5B4E85C6-7E AC-40A0-8DC3-003829518E BD%7D/IRC

_DR_Report_101607.pdf (“Demand response contributes to main-

taining system reliability. Lower electric load when supply is es-

pecially tight reduces the likelihood of load shedding. Improve-

ments in reliability mean that many circumstances that otherwise

result in forced outages and rolling blackouts are averted, resulting

in substantial financial savings.

™ For instance, in ERCOT, on February 26, 2008, through a com-

bination of a sudden loss of thermal! generation, drop in power sup-

plied by wind generators, and a quicker-than-expected ramping up of

demand, ERCOT found itself short of reserves. The system opera-

tor called on all demand response resources, and 1200 MW of Load

acting as Resource (LaaRs) responded quickly, bringing ERCOT

back into balance. OAK RIDGE NATL LAB., NATL RENEWABLE

ENERGY LAB., TECH. REP. NREL/TP-500-43373, ERCOT EVENT

ON FEB. 26, 2008: LESSONS LEARNED (JUL. 2008).

"™ See Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(f),

119 Stat. 594, 965 (2005) (“It is the policy of the United States that

:; unnecessary barriers to demand response participation in

energy, capacity, and ancillary service markets shall be eliminat-

ed.”).

62a

Commission has undertaken several reforms to sup-

port competitive wholesale energy markets by remov-

ing barriers to participation of demand response re-

sources. For example, in Order No. 890, the Commis-

sion modified the pro forma Open Access Transmission

Tariff to allow non-generation resources, including de-

mand response resources, to be used in the provision

of certain ancillary services where appropriate on a

comparable basis to service provided by generation re-

sources.~ Order No. 890-A further required trans-

mission providers to develop transmission planning

processes that treat all resources, including demand

response, on a comparable basis.”

12. In Order No. 719, the Commission required RTOs

and ISOs to, among other things, accept bids from de-

mand response resources in their markets for certain

ancillary services on a basis comparable to other re-

sources.“ The Commission also required each RTO

and ISO “to reform or demonstrate the adequacy of its

existing market rules to ensure that the market price

for energy reflects the value of energy during an op-

erating reserve shortage,”"” for purposes of encour-

= ndue Discrimination and Preference in

sion Service, Order No. 890, FERC Stats. & Regs. 4 31,241, at P

887-88 (2007), order on reh’g, Order No. 890-A, FERC Stats. &

Regs. 4 31,261 (2007), order on reh’g and clarification, Order

No. 890-B, 123 FERC 4 61,299 (2008), order on reh’g, Order

No. 890-C, 126 FERC 4 61,228 (2009), order on clarification, Order

No. 890-D, 129 FERC 4 61,126 (2009).

“ Order No. 890-A, FERC Stats. & Regs. 31,261 at P 216.

* Order No. 719, FERC Stats. & Regs. 131,281 at P 47-49.

% Order No. 719, FERC Stats. & Regs. 131,281 at P 194.

63a

aging existing generation and demand resources to

continue to be relied upon during an operating reserve

shortage, and encouraging entry of new generation

and demand resources.”

13. Additionally, in recent years several RTOs and

ISOs have instituted various types of demand response

programs. While some of these programs are admin-

istered for reliability and emergency conditions, other

programs allow wholesale customers, qualifying large

retail customers, and aggregators of retail customers

to participate directly in the day-ahead and real-time

energy markets, certain ancillary service markets and

capacity markets.”

14. To date, the Commission has allowed each RTO

and ISO to develop its own compensation methodolo-

gies for demand response resources participating in its

day-ahead and real-time energy markets. Asa result,

* Order No. 719, FERC Stats. & Regs. 1 31,281 at P 247.

* Other demand response programs allow demand response to be

tused as a capacity resource and as a resource during system emer-

gencies or permit the use of demand response for synchronized re-

serves and regulation service. See, e.g., PJM Interconnection,

LL.C., 117 FERC 1 61,331 (2006); Devon Power LLC, 115 FERC

4 61,340, order on reh’g, 117 FERC 1 61,133 (2006), appeal pending

sub nom. Maine Pub. Utils. Comm’n v. FERC, No. 06-1403 (D.C. Cir.

2007); New_York Indep, Sys. Operator, Inc., 95 FERC 1 61,136

(2001); NSTAR Services Co. v. New England Power Pool, 95 FERC

‘T 61,250 (2001); N P P d ISO N

Inc,, 100 FERC 1 61,287, order on reh’g, 101 FERC 1 61,344 (2002),

order on reh’g, 103 FERC 9 61,304, order on reh’g, 105 FERC

‘1 61,211 (2003); PJM_Interconnection, L.L.C., 99 FERC 4 61,227

(2002); California Independent System Operator Corp., 132 FERC

1 61,045 (2010).

64a

the levels of compensation for demand response vary

significantly among RTOs and ISOs.” For example,

PJM Interconnection, L.L.C. (PJM) pays the LMP

minus the generation and transmission portions of the

retail rate.” ISO New England Inc. (ISO-NE) and

New York Independent System Operator, Inc. (NYI-

SO) pay LMP when prices exceed a threshold level,

with the levels differing between the RTOs.” The

Midwest Independent Transmission System Operator,

Inc.’s (Midwest ISO) demand response programs” pay

* See New England, Inc., Docket No. ER09-1051-000; ISO New

England, Inc., Docket No. ER08-830-000; Midwest Indep. Transmis-

sion Sys. Operator, Inc., Docket No. ER09-1049-000.

*“ See sections 3.3A.4 and 3.34.5 (Market Settlements in the Real-

Time and Day-Ahead Energy Markets) of the Appendix to Attach-

ment K of the PJM Tariff.

*® For example, under ISO-NE’s Real-Time Price Response Pro-

gram, the minimum bid is $100/MWh and a demand response re-

source is paid the higher of LMP or $100/MWh. For the Day-

Ahead Load Response Program, the minimum offer level is calcu-

lated on a monthly basis and is the Forward Reserve Fuel Index

($/MM 8tu) multiplied by an effective heat rate of 11.37 MMBtu/

MWh. The maximum offer level is $1,000/MWh. See sections

IIL.E.2.1 and III.E.3.2 of Appendix E of the ISO New England

Transmission, Markets and Services Tariff. NYISO implements a

day-ahead demand response program by which resources bid into

the market at a minimum of $75/MWh and can get paid the LMP.

See section 4.2.2.9 (“Day-Ahead Bids from Demand Reduction Pro-

viders to Supply Energy from Demand Reductions”) of NYISO’s

Market Services Tariff.

Midwest ISO FERC Electric Tariff characterizes Demand Re-

sponse Resources (DRR) as either DRR-Type I or DRR-Type IL.

DRR-Type I are capable of supplying a specific quantity of energy or

contingency reserve through physical load interruption. DRR-Type

65a

LMP for demand response resources in the day-ahead

and real-time energy markets.” The California Inde-

pendent System Operator Corporation (CAISO) pays

LMP at pricing nodes, or sub-load aggregation points

(Sub-LAP) in its Proxy Demand Resource program

that allows qualifying resources to provide day-ahead

and real-time energy.” CAISO also provides for de-

mand response resources to participate in its Partici-

pating Load program, which enables certain resources

to provide curtailable demand in the CAISO market.

CAISO pays nodal real-time LMP for its Participating

Load program. The Southwest Power Pool, Inc.

(SPP) has filed revisions to its tariff to facilitate de-

mand response in the Energy Imbalance Service Mar-

ket.™

II are capable of supplying energy and/or operating reserves over a

dispatchable range. See sections 39.2.5A and 40.2.5 of the Tariff.

-® See Charges and Payments for Purchases and Sales for De-

mand Response Resources. Midwest ISO FERC Electric Tariff,

section 39.3.2C.

-™ See section 11.2.1.1 IFM Payments for Supply of Energy,

CAISO FERC Electric Tariff. CAISO notes that for a Proxy De-

mand Resource that is made up of aggregated loads, the Resource is

paid the weighted average of the LMPs of each pricing node where

the underlying aggregate loads reside. See CAISO, 182 FERC

1 61,045, at P 26 n.14 (2010).

';™ The Commission has directed SPP to report on ways it can

incorporate demand response into its imbalance market. Southwest

Power Pool, Inc., 128 FERC 1 61,085 (2009). As of September 1,

2010, SPP has submitted seven informational status reports regard-

ing its efforts to address issues related to demand response re-

sources. In orders addressing SPP’s compliance with Order

No. 719, the Commission also directed SPP to make another com-

pliance filing addressing demand response participation in its orga-

66a

lil. P Hi

15. As noted above, the Commission issued the

NOPR in this proceeding on March 18, 2010.” The

NOPR proposed to require RTOs and [SOs to pay the

LMP in all hours for demand reductions made in re-

sponse to price signals. The Commission sought com-

ments on the compensation proposal and, in particular,

on the comparability of generation and demand re-

sponse resources; alternative approaches to compen-

sating demand response in organized wholesale energy

markets; whether payment of LMP should apply in all

hours, and, if not, any criteria that should be used for

establishing hours when LMP should apply; and

whether to allow for regional variations concerning

approaches to demand response compensation.”

16. After receiving the first round of comments, the

Commission issued a Supplemental Notice of Proposed

Rulemaking and Notice of Technical Conference (Sup-

plemental NOPR) in this proceeding on August 2,

2010." The Supplemental NOPR sought additional

comment on: whether the Commission should adopt a

nized markets. Southwest Power Pool, Inc., 129 FERC 4 61,168, at

P 51 (2009). On May 19, 2010, SPP submitted revisions to its Open

Access Transmission Tariff in Docket Nos. ERO9-1050-004 and

ER09-748-002 to comply with the Commission’s requirements estab-

lished in Order Nos. 719 and 719-A. These filings are pending be-

fore the Commission.

* NOPR, FERC Stats. & Regs. 11 32,656.

* See Appendix for a list of commenters.

* Supplemental Notice of Proposed Rulemaking and Notice of

Technical Conference, 75 FR 47499 (Aug. 6, 2010), 1832 FERC

" 61,094 (2010) (Supplemental NOPR).

67a

net benefits test for determining when to compensate

demand response providers, and, if so, what, if any,

requirements should apply to the methods for deter-

mining net benefits; and what, if any, requirements

should apply to how the costs of demand response are

allocated. The Commission further directed Staff to

hold a technical conference focused on these two is-

sues, which occurred on September 13, 2010.*

IV. Discussion

17. Based upon the record in this proceeding, the

Commission herein requires greater uniformity in com-

pensating demand response resources participating in

organized wholesale energy markets. This Final

Rule also addresses the allocation of costs resulting

from the commitment of demand response, directing

that such costs be allocated among those customers

who benefit from the lower LMP resulting from the

demand response.

A. Compensation Level

1. NOPR Proposal

18. The NOPR proposed to require RTOs and ISOs

to pay the LMP in all hours for demand reductions

made in response to price signals. The NOPR sought

to provide comparable compensation to generation and

demand response providers, based on the premise that

both resources provide a comparable service to RTOs

and ISOs for purposes of balancing supply and demand

and maintaining a reliable electricity grid.” Also as

* See Notice of Technical Conference (Aug. 27, 2010).

* NOPR, FERC Stats. & Regs. 9 32,656 at P 15.

68a

stated in the NOPR, the proposed compensation level

was designed to allow more demand response re-

sources to cover their investment costs in demand

response-related technology (such as advanced meter-

ing) and thereby facilitate their ability to participate in

organized wholesale energy markets.“ The Commis-

sion sought comments on the compensation proposal

and, in particular, on the comparability of generation

and demand response resources; alternative ap-

proaches to compensating demand response in orga-

nized wholesale energy markets; whether payment of

LMP should apply in all hours, and, if not, any criteria

that should be used for establishing hours when LMP

should apply; and whether to allow for regional varia-

tions concerning approaches to demand response com-

pensation.

19. In the Supplemental NOPR, the Commission

sought additional comments and directed staff to hold

a technical conference regarding various net benefits

tests. In particular, the Commission sought comment

on: whether the Commission should adopt a net ben-

efits test applicable in all or only some hours and what

the criteria of any such test would be; how to define

net benefits; what costs demand response providers

and load serving entities incur and whether they

should be included in a net benefits test; whether any

net benefits methodology adopted should be the same

for all RTOs and ISOs; proposed methodologies for

implementing a net benefits test and the advantages

and limitations of any proposed methodologies.“ The

” Id. at P 16,

* Supplemental NOPR, 132 FERC 1 61,094 at P 8-9.

69a

September 13, 2010 Technical Conference included an

eleven-member pane! discussion of net benefits tests

representing a wide range of interests and viewpoints.”

The Commission subsequently received additional writ-

ten comments addressing these issues.

2. Comments

a) Capability of Demand Response and Gen-

eration Resources to Balance Energy Markets

20. Various commenters address the comparability of

demand response and generation resources for pur-

poses of compensation in the organized wholesale en-

ergy markets. To begin, numerous commenters ad-

dress the physical or functional comparability of de-

mand response and generation, agreeing that an incre-

ment of generation is comparable to a decrement of

load for purposes of balancing supply and demand in

the day-ahead and real-time energy markets.* Equat-

ing generation and demand response resources, Dr.

Alfred E. Kahn states:

[Demand response] is in all essential respects eco-

nomically equivalent to supply response

[so] economic efficiency requires that it

should be rewarded with the same LMP that clears

the market. Since [demand response] is actually—

and not merely metaphorically—equivalent to sup-

ply response, economic efficiency requires that it be

regarded and rewarded, equivalently, as a resource

® See Sept. 13, 2010 Tr.

* DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 2);

Verso May 13, 2010 Comments at 3-4; Occidental May 13, 2010

Comments at 11; Viridity June 18, 2010 Comments at 5.

70a

proffered to system operators, and be treated

equivalently to generation in competitive power

markets. That is, all resources—energy saved

equivalently to energy supplied— should

receive the same market-clearing LMP in remu-

neration.“

Indeed, some commenters believe that, from a physicai

standpoint, demand response can provide superior

services to generation, such as providing a guick re-

sponse in meeting system requirements and service

without having to construct major new facilities.“

Occidental asserts that the fungibility of demand re-

sponse and generation output creates greater opera-

tional flexibility that, in turn, offers hTOs and ISOs

multiple options to solve system issues both in energy

and ancillary service markets, and that the fungible

nature of demand response and generation supports

comparable compensation for each as proposed in the

NOPR.*

21. Viridity states that attempts to distinguish the

physical characteristics of generation and demand re-

sponse ignore bid-based security-constrained economic

dispatch as the foundation for LMP and are based on

the assumption that the value of load management on

the grid is limited to periods when the system is

stressed, i.e., traditional “super peak shaving.” Vi-

“ DR Supporters August 30, 2010 Reply Comments (Kahn Affi-

davit at 2 (footnote omitted)).

* Verso May 13, 2010 Comments at 3-4; Alcoa May 13, 2010

Comments at 9.

“ Occidental May 13, 2010 Comments at 11.

Tla

ridity states that, while these arguments might have

been valid 15 years ago, today competitive markets can

offer proactively-managed load control and compara-

ble and non-discriminatory treatment of load-based

energy resources.

Therefore, Viridity asserts that all resources should be

paid LMP if the grid operator accepts their bid to

achieve grid balance.”

22. At the same time, other commenters argue that

generation and demand response are not physically

equivalent, pointing out that demand response reduces

consumption, whereas generators serve consumption.“

They argue that a MW reduction in demand does not

turn on the lights.“ EPSA adds that a load reduction

does not provide electrons to any other load and, in-

stead, allows the marginal electron to serve a different

customer.” Some commenters assert that a power

system can function solely and reliably on generating

plants and without any reliance on demand response,

while the system cannot rely exclusively on demand

response because demand response by itself cannot

keep the lights on. Ultimately, some commenters

point out, megawatts produced by generators need to

be placed on the system in order for power to flow.”

Battelle additionally argues that a reduction in con-

" Viridity June 18, 2010 Comments at 5

* ISO-NE May 13, 2010 Comments at 3.

* See, e.g., APPA May 13, 2010 Comments at 12; Capital Power

May 13, 2010 Comments at 2.

® EPSA May 13, 2010 Comments at 72.

“= See, e.g., PSEG May 13, 2010 Comments at 8.

72a

sumption is not exactly the same as an increase in pro-

duction, because elastic demand often comes with

attendant future consequences, such as rebound, by

virtue of substitution in time.”

23. Some commenters who argue that the physical

characteristics of demand response are not comparable

to generation frame their arguments in terms of the

ability of the system operator to call on demand re-

sponse and generation resources to provide balancing

energy. They argue that generation resources pro-

vide superior service to demand response providers,

positing that demand response is not intended for long

periods of balancing needs,” and that, moreover, con-

tracts with demand response providers limit the num-

ber of hours and times a customer may be called upon

to curtail. For example, ODEC asserts that the de-

gree of physical comparability depends on the extent

to which demand response resources can be dispatched

similar to a generator.” Calpine adds that traditional

generators provide system support features that de-

mand response cannot, such as ancillary services in-

cluding governor response or reactive power voltage

support, which are necessary for reliable operation of

the electric system.”

24. Numerous commenters also address the compa-

rability of demand response and generation in eco-

nomic terms. For example, EEI states that, in fi-

* Battelle May 13, 2010 Comments at 3.

“AEP May 13, 2010 Comments at 7-8.

* ODEC May 13, 2010 Comments at 12.

*® Calpine May 13, 2010 Comments at 4-5.

T3a

nance terms, the demand response product is, unlike

generation, essentially an unexercised cal] option on

spot market energy, and the value of that option is

well-established in finance theory as the value of the

resource (LMP) minus the “strike price,” which EEI

contends in this case is the retail tariff rate.” EEI

and like-minded commenters support, therefore, al-

ternative compensation for demand response to equal

LMP minus the generation (or G) component of the re-

‘tail rate.” They posit that payment of LMP without

an offset for some portion of the retail rate does not

send the proper economic signal to providers of de-

mand response, because it fails to take into account the

retail rate savings associated with demand response,

and thereby overcompensates the demand response

provider. As described by Dr. William W. Hogan on

behalf of EPSA, this is sometimes called a double-

® EEI May 13, 2010 Comments at 4-5. See also Robert L. Bor-

lick May 13, 2010 Comments at 4. Mr. Borlick argues that the

correct price is LMP minus the Marginal Foregone Retail Rate

(MFRR), describing the economically efficient price that should be

paid to a demand response provider as “its offer price minus the

price in its retail tariff at which it would have purchased the curtailed

energy.” Mr. Borlick asserts that this amount accurately repre-

gents the forgone opportunity costs that result when a demand

response provider reduces its load. Id.

" See May 13, 2010 Comments of: APPPA; AEP; The Brattle

Group; Calpine; ConEd; Consumers Energy; CPG; Detroit Edison;

Direct Energy; Dominion; Duke Energy; Edison Mission; EEI;

EPSA; Exelon; FTC; GDF; NYISO on behalf of the ISO RTO Coun-

dil; ICC; IPPNY; Indicated New York TOs; IPA; ISO-NE; Midwest

TDUs; Mirant; Midwest ISO TOs; NEPGA; NYISO; ODEC; OMS;

PJM; PJM IMM; P3; Potomac Economics; PG&E; Ohio Commis-

sion; Robert L. Borlick; Roy Shanker; and RRI Energy.

74a

payment for demand reductions, because demand re-

sponse providers would “receive” both the cost savings

from not consuming an increment of electricity at a

particular price, plus an LMP payment for not con-

suming that same increment of electricity.” Viewing

LMP as a double-payment, these commenters argue

that paying LMP will result in more demand response

than is economically efficient.” For example, Dr.

Hogan states that paying LMP might motivate a com-

pany to shut down even though the benefits of con-

suming electricity outweigh the cost at LMP® In-

deed, P3 argues that compensation in excess of LMP-G

is unjust and unreasonable, because such a payment

level imposes costs on customers that are not com-

mensurate with benefits received.”

25. ISO-NE argues that paying full LMP to demand

response providers without taking into account the bill

savings produced by demand response provides a sig-

* See Attachment to Answer of EPSA, Providing Incentives for

Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009,

submitted in Docket No. EL09-68-000.

® EPSA May 13, 2010 Comments at 23. See also May 13, 2010

Comments of APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at

2; New York Commission at 5; PJM at 6; PSEG at 5; and Potomac

Economics at 6-8.

® Attachment to Answer of EPSA, Providing Incentives for Effi-

cient Demand Response, Dr. William W. Hogan, Oct. 29, 2009, sub-

mitted in Docket No. EL09-68-000. In Dr. Hogan’s view, supply

should produce when the price of electricity exceeds its cost of pro-

duction and demand should decline to consume when the costs in

terms of convenience of delaying use are jess than the price of elec-

tricity.

t P3 June 14, 2010 Comments at 2, 7-8.

75a

nificant financial incentive to dispatch demand re-

sponse with marginal costs exceeding LMPs. By dis-

patching higher-cost demand response, ISO-NE as-

serts, lower-cost generation resources are displaced.”

At the same time, ISO-NE argues, generation is not

dispatched and paid for only when the generation re-

duces LMP—generation is dispatched and paid for

when it is cost-effective.™

26. Dr. Hogan further disputes arguments equating a

MW of energy supplied to a MW of energy saved on

economic grounds. Dr. Hogan draws a distinction be-

tween reselling something that one has purchased, and

selling something that one would have purchased with-

out actually purchasing it. Dr. Hogan argues that

from the perspective of economic efficiency and wel-

fare maximization, the aggregate effect of demand re-

sponse is a wash producing no economic net benefit.

Dr. Hogan asserts that Commission policy citing the

benefits of price reduction in support of demand re-

sponse compensation would amount to no less than an

application of regulatory authority to enforce a buyers’

cartel. He states that the Commission has been vigi-

lant and aggressive in preventing buyers and sellers

from engaging in market manipulation to influence

prices, and it would be fundamentally inconsistent for

the Commission to design demand response compen-

sation policies that coordinate and enforce such price

manipulation.

® ISO-NE May 13, 2010 Comments at 3-4.

® Id. at 28.

76a

27. Dr. Hogan argues that the ideal and economically

efficient solution regarding demand response compen-

sation is to implement retail real-time pricing at the

LMP, thereby eliminating the need for demand re-

sponse programs. Realizing that this is unattainable

at the present time, Dr. Hogan goes on to propose a

next-best solution, which he believes is to pay demand

response compensation in the amount of LMP-G, or

some amount that simulates explicit contract demand

response (such as “buy-the-baseline” approach discus-

sed below). These options, he argues, more than pay-

ing LMP, better support notions of comparability be-

tween demand response resources and generation.™

28. The New York Commission, however, argues that

requiring payment of LMP-G would result in an ad-

ministrative burden of tracking retail rates for the

multiple utilities, ESCOs and power authorities and

create undue confusion for retail customers and ad-

ministrative difficulties for state commissions and

ISOs and RTOs.”

29. Consistent with Dr. Hogan’s arguments, some

commenters assert that demand response providers

should actually own or pay for electricity prior to, what

commenters characterize as, an effective reselling of

the electricity back to the market in the form of de-

mand response. For example, these commenters sug-

gest that the demand response provider purchase the

power in the day-ahead market and resell it in the

“ Hogan Affidavit, (SO RTO Council May 13, 2010 Comments at 5.

New York Commission May 13, 2010 Comments at 8.

77a

real-time markets.” EPSA argues that there must be

some purchase requirement or representative offset to

allow a demand response provider to “sell” a commod-

ity that it owns to the ISO or RTO.” EPSA argues

that such a requirement would send an efficient price

signal, reduce incentives for gaming the system, and

help address difficulties with measurement and verifi-

cation of a demand reduction. EPSA highlights an

ISO-NE IMM recommendation that, if the Commis-

sion permits LMP payment, it should also adopt a

“buy-the-baseline” approach requiring demand re-

sponse resources to purchase an expected amount of

energy consumption in the day-ahead energy market

and subsequently sell any demand reduction from that

level in the real-time market.™

30. Viridity, on the other hand, argues that forcing

customers to buy and then resell electricity will lead to

too little demand response and that adopting a “buy-

the-baseline” approach would constitute an inappro-

priate exercise of Commission authority to effectively

force parties into contracts. Viridity and DR Sup-

porters state that any characterization of demand re-

sponse as a purchase and then resale of energy is

erroneous™ and based on the flawed assumption that

demand response resources are reselling energy.

They state that the description of demand response as

® See, e.g, ISO-NE IMM May 13, 2010 Comments at 4-5; Mid-

west ISO TOs May 13, 2010 Comments at 14; PJM May 13, 2010

Comments at 5; and Duke Energy May 13, 2010 Comments at 2.

© EPSA June 30, 2010 Comments at 3.

® EPSA June 30, 2010 Comments at 23.

* Viridity Energy June 18, 2010 Comments at 25.

78a

a reselling of energy has been correctly rejected by

the Commission in EnergyConnect, where the Com-

mission stated that it was establishing a policy of

treating demand response as a service rather than a

purchase and sale of electric energy.”

31. DR Supporters further argues that, despite

claims to the contrary, paying full LMP to demand re-

sponse providers does not constitute a subsidy for de-

mand response any more than the remunerations of

generators for the power that they sell. As Dr. Kahn

states:

Does this plan involve double compensation, as [Dr.]

Hogan asserts, at the expense of power generators

—of successful bidders promising to induce efficient

demand curtailment and of consumers induced to

practice it? Certainly not: the decrease in the rev-

enue of the generators is (and consequent savings

by consumers are) matched by the savings in their

(marginal) costs of generating that power; the suc-

cessful bidders for the opportunity to induce that

consumer response are compensated for the costs of

those efforts by the pool, whose (marginal) costs

they save by assisting consumers to reduce their

purchases.”

32. Viridity further disputes Dr. Hogan’s argument

that payment of LMP for demand response will distort

an otherwise optimal market. Viridity posits that

™ DR Supporters Aug. 30, 2010 Reply Comments at 10 (citing

EnergyConnect, Inc., 130 FERC 9 61,031 at P 30-31 (2010)).

"DR Supporters Aug. 30, 2010 Reply Comments, Kahn Affidavit

at 10.

79a

such arguments ignore dislocations in the wholesale

power markets, the existence of market power that

must be mitigated, imperfect information available to

customers, barriers to entry and uneconomic resources

dispatched to fulfill must-run requirements.” Viridi-

ty further states that Dr. Hogan’s arguments fail to

acknowledge the limits of the Commission’s jurisdic-

tion and widespread dislocations and distortions in

virtually all economic aspects of relevant energy mar-

kets (including fuels, facilities, pricing, environmental

attributes, information and participation) and fail to

account for any market benefits of demand response.”

Finally, Viridity argues that Dr. Hogan’s arguments

fail to reflect the many complex interactions between

price, equipment operational requirements, and cus-

tomer processes, which point to a complex demand re-

sponse decision.”

33. In addition to physical and economic comparabil-

ity, some commenters contrast the environmental

effects of generation and demand response resources.

EDF notes that current market prices fail to internal-

ize environmental externalities—including toxic air

pollution, greenhouse gas pollution, and land and wa-

™ Viridity June 18, 2010 Comments at 13 (“Importantly, Dr. Ho-

gan (and others) in opposing the proposed rulemaking fails to ac-

knowledge the limits of the Commission's jurisdiction, and wide

spread dislocations and distortions in virtually all economic aspects

of relevant energy markets (including fuels, facilities, pricing, envi-

ronmental attributes, information and participation).” (Affidavit of

John C. Tysseling, Ph.D.)).

® Viridity Reply Comments at 13.

™ Viridity Reply Comments at 14.

80a

ter use impacts—and other social costs. EDF asserts

that the social impact of these environmental external-

ities is especially acute at peak times, positing that

generation sources used for marginal! supply at such

times (“peaker plants”) are among the oldest, dirtiest,

and most inefficient in the fleet.” The American

Clean Skies Foundation contends that fossil-fuel gen-

erators are typically mispriced because wholesale

prices radically understate the full environmental and

health costs associated with such generators.” In-

deed, some commenters, such as Alcoa, argue that

because demand response does not result in the ex-

ternal costs associated with generation (e.g., green-

house gas emissions), instead resulting in less green-

house gas emissions than generation, it should be com-

pensated at more than LMP.”

34. Taking the opposite view concerning environ-

mental externalities, EPSA states that paying LMP

for demand response will merely encourage load to

switch to off-grid power (or behind-the-meter genera-

tion), while still being compensated, and that such

behind-the-meter generation produces more green-

house gases and other air emissions than electricity

from the regional energy market.”

35. Some commenters discuss comparability of gen-

eration and demand response in terms of the market

rules that apply to each resource, arguing that both

EDF Oct. 13, 2010 Comments at 2.

American Clean Skies Foundation May 13, 2010 Comments at 4.

Alcoa May 13, 2010 Comments at 9.

EPSA May 13, 2010 Comments at 60.

23a2a

Sla

resources should be comparably compensated only if

the same rules for participation apply to both re-

sources, and both resources are held to the same stan-

dards for dispatchability.” They also argue that simi-

lar penalty structures should apply to demand re-

sponse resources as apply to generation, and that de-

mand response participation must be subject to mar-

ket monitoring.” Calpine adds that to the extent de-

mand response resources are used and treated on par

with generators for purposes of compensation, they

should be subject to the same performance testing,

penalties, and other similar requirements as genera-

tors.”!

36. Some commenters address the comparability of

demand response providers and generators in terms of

maintaining system reliability. PIO argues that re-

ductions in consumption provide additional reliability.”

According to the NEMA, North American Electric Re-

liability Corporation (NERC) standards suggest that,

from a reliability perspective, load reductions are

equivalent or even superior to generator increases for

balancing purposes. For example, while specific to

the Western Interconnection, BAL-002-WECC-1 lists

interruptible load as comparable to generation deploy-

able within 10 minutes.“ EPSA maintains that de-

mand response resources are not full substitutes based

® ODEC May 13, 2010 Comments at 12; Westar May 13, 2010

Comments at 5-6.

”

* Calpine May 13, 2010 Comments at 5.

* PIO May 13, 2010 Comments at 8.

" NEMA May 13, 2010 Comments at 2.

82a

on the nature of their participation and the rules appli-

cable to each resource in the energy markets, pointing

out, for example, that, unlike generators, demand re-

sponse providers are not subject to regional and NERC

mandatory reliability standard: “

37. On the other hand, PSEG argues that a MW of

demand response does not make the same contribution

towards system reliability as a MW of generation, be-

cause demand response committed as a capacity re-

source is only required to perform for a limited num-

ber of times over the peak period. PSEG refers to

PJM’s capacity market, for example, in which demand

response only has to perform 10 times during the en-

tire summer peak period, and then only for six hours

per response. In contrast, PSEG argues, generators

are available for dispatch, 24 hours a day, 365 days per

year, except for a small percentage of time for forced

and planned outages. PSEG further asserts that ad-

ditional reliability standards—applicable to generating

facilities, but not to demand response—increase the

relative reliability value of generating resources to the

system.”

b) Appropriateness of a Net Benefits Test

38. Some commenters assert that demand response

providers should be paid LMP only when the benefits

of demand response compensation outweigh the ener-

gy market costs to consumers of paying demand re-

sponse resources, i.e., when cost-effective, as determined

by some type of net benefits or cost-effectiveness

* EPSA May 13, 2010 Comments at 7.

* PSEG May 13, 2010 Comments at 8.

83a

test.” They maintain that paying LMP for demand

response in all hours, including off-peak hours, might

not result in net benefits to customers, because the

payments might be substantially more than the sav-

ings created by reducing the clearing price at that

time.” According to these commenters, net benefits

are most likely to be positive and greatest when the

supply curve is steepest, which typically occurs in

highest-cost, peak hours. They argue that experi-

ence to date has shown positive benefits from demand

response as a peak system resource, and that, during

peak periods, the positive economics of demand re-

sponse are generally very clear and a cost-benefit

analysis may not be needed.“ Furthermore, some

commenters suggest that limiting the hours in which

® See generally May 13, 2010 Comments of NYSCPB; NECA;

Capital Power; NECPUC; Maryland Commission; New York Com-

mission; NSTAR; National Grid; NE Public Systems.

* Capital Power May 13, 2010 Comments at 5; P3 May 13, 2010

Comments at 5.

® NECPUC May 13, 2010 Comments at 13; see also Sept. 13,

2010 Tr. 13:6-19 (Mr. Keene); Maryland Commission May 13, 2010

Comments at 4-5.

® See, eg., ACEEE Oct. 13, 2010 Comments 3-4. See also Na-

tional Grid May 13, 2010 Comments at 4-5; NSTAR Electric Com-

pany (NSTAR) May 14, 2010 Comments at 3; Maryland Commission

May 13, 2010 Comments, submitting Analysis of Load Payments and

under Different Demand Response Compensation

Sehemes at 10-11 (discussing PJM analysis showing that paying de-

mand response providers LMP for all hours after compensating

LSEs for lost revenues would not benefit customers in general but

that positive economic benefits results when demand response pro-

viders receive LMP during at least the top 100 hours (the highest

priced energy hours)).

84a

demand response resources are paid LMP could help

establish better baselines for measuring whether a de-

mand response prwvider has, in fact, responded.”

39. Some commenters who oppose paying LMP in all

hours for demand response also suggest various ap-

proaches, including net benefits tests, for determining}

when LMP should apply. The stated purpose of any

of these tests would be to determine the point at which

the incremental payment for demand response equals

the incremental benefit of the reduction in load; pay-

ment of LMP would apply only up to that point.”

40. Opposition to use of a net benefits test comes

from several directions. Numerous commenters, pri-

marily industrial consumers and some consumer ad-

vocates, argue that a net benefits test will reduce com-

petition,” have a “chilling effect” on the development

of demand response,” and be costly and complex to

” See, e.g., CDWR May 13, 2010 Comments at 11; National Grid

May 13, 2010 Comments at 8; ISO-NE May 13, 2010 Comments at

34; ACEEE Oct. 13, 2010 Comments 4. But see ISO-NE May 13,

2010 Comments at 32-33 (contending that no baseline estimation

methodology that relies upon historical customer meter data can

accurately and reliably estimate an individual customer’s normal

energy usage pattern if that customer responds frequently to price

signals).

* NECAA May 13, 2010 Comments at 11; NYSCPB May 13, 2010

Comments at

5; National Grid May 13, 2010 Comments at 4-5.

* Viridity Oct. 13, 2010 Comments at 14.

* NAPP Oct. 13, 2010 Comments at 2.

85a

implement.“ Some commenters further state that no

net benefits test is needed because the merit-order bid

stack and market clearing function in a wholesale

market, by definition, assures that the benefits to the

system of demand response exceed the costs, and that

the resource that clears is the lowest cost resource;

otherwise, demand response would not dispatch ahead

of competing alternatives.”

41. Another set of commenters argues that a net

benefits test is unnecessary and inappropriate for dif-

ferent reasons.” These commenters assert that a net

benefits test would be very costly and difficult to im-

plement, that RTOs and ISOs cannot implement a net

benefits test,” and that such a test is unnecessary

with the economically efficient compensation level for

demand response resources. According to Andy Ott

™* Viridity Oct. 13, 2010 Comments at 14; NAPP Oct. 13, 2010

Comments at 3; AMP Oct. 13, 2010 Comments at 4; CAISO Oct. 13,

2010 Comments at 5 and 16.

® EDF Oct. 13, 2010 Comments at 2; Viridity Oct. 13, 2010 Com-

ments at 10; ELCON Oct. 13, 2010 Comments at 3.

* See, e.g., Oct. 13, 2010 Comments of: Midwest TDUs at 4-5;

NEPGA at 8, NJBPU at 2-3; NAPP at 2-3; P3; SPP at 3-4; SDG&E,

SoCal Edison, and PG&E at 4-6; Viridity Energy at 2; ELCON at 2;

AMP at 2; CDWR at 1, 4-5; CAISO at 4, 15; Detroit Edison at 2;

Smart Grid Coalition at 2; Duke Energy at 2; EDF at 2; FTC at 1;

EPSA at 4; Indicated New York TOs at 3; Midwest ISO at 9; Steel

Manufacturers Ass’n at 3.

* P3 Oct. 13, 2010 Comments at 5.

* Sept. 13, 2010 Tr. 155:21-24 (Mr. Robinson); Sept. 13, 2010 Tr.

141-42 (Mr. Centolella); Dr. Hogan Sept. 13, 2010 Comments at 5;

Sept. 13, 2010 Tr. 60 (Dr. Shanker); Sept. 13, 2010 Tr. 27 (Mr. New-

ton); SDG&E May 13, 2010 Comments at 4.

86a

of PJM, “[{tjJhe implicit assumption in developing a

benefits test for purposes of compensation would be

that you could actually determine individual custom-

ers, whether they benefitted or not. That type of anal-

ysis would be very costly to implement.”"” Midwest

ISO TOs further assert that it would be difficult to

prescribe by regulation the hours in which demand

response provides net benefits because system condi-

tions and load patterns change across seasons and over

time.” NEPGA argues that compensating demand

response resources at LMP whenever a reduction in

consumption suppresses energy prices enough to pro-

vide net benefits to load is neither just and reasonable,

nor in the public interest."". NEPGA states that the

Commission recognized in Amaranth Advisors™ that,

if prices are suppressed below competitive, market

levels, society as a whole is worse off. According to

NEPGA, the goal is to get the right price—the eco-

nomically efficient price produced by competitive mar-

kets.

42. NYISO posits that a rule mandating payment of

LMP-G avoids the need to develop a net benefits test.

NYISO further states, however, that if the Commis-

sion decides to move forward with LMP for demand

response, it should craft a net benefits test that mini-

mizes any opportunities for distorting market prices or

exploiting market inefficiencies. Citing support for

Dr. Hogan’s arguments, NYISO states that “a net

* Sept. 13, 2010 Tr. 19 (Mr. Ott).

‘© Midwest ISO TOs May 13, 2010 Comments at 16.

‘! NEPGA June 21, 2010 Comments at 1-2.

‘® 120 FERC 1 61,085 (2007).

87a

benefits test should ensure that the demand response

program does not have negative net benefits compared

to no program at all. The criterion to apply would

focus on the bid-cost savings of generation and load,

with the load bids adjusted for the effects of avoidance

of the retail rate.”

c) izati r ional riati

inc r

43. With regard to potential regional variations for

tompensation mechanisms across RTO and ISO mar-

kets, many commenters, mostly those in support of the

NOPR’s proposed compensation level, endorse stand-

ardization."“ Some parties, primarily industrial cus-

tomers and some customer advocates, argue that, re-

gardless of location, both demand response providers

and generators provide a comparable service in terms

of balancing supply and demand, as discussed above,

‘and therefore should be comparably compensated at

the LMP." They argue that fair, non-discriminatory

.

»—

i ~NYISO Oct. 13, 2010 Comments at 3-4.

* See May 13, 2010 Comments of: ArcelorMittal; Alcoa; ACENY;

ACC; AFPA; CDWR; Mayor Bloomberg; Consert; CDRI; CPower;

‘DR Supporters; Derstine’s; Durgin; Electricity Committee; EL-

CON; Electrodynamics; ECS; EnerNOC; ICUB; IECA; [ECPA;

Trving Forest; Joint Consumers; Limington; Madison Paper; Massa-

¢husetts AG; NEMA; National Energy; National League of Cities;

NJBPU; NAPP; Occidental; Okemo; Partners; Pennsylvania De-

partment of Environment; Pennsylvania Commission; Rep. Chris

Ross; Precision; PRLC; Raritan ; SDEG, SoCal; PG&E; Schneider;

Governor O'Malley; Steel Manufacturers Ass’n; Verso; Viridity; Vir-

ginia Committee; Wal-Mart; Waterville.

™ See. e.g. Steel Manufacturers Ass’n May 13, 2010 Comments

at 12; NEMA May 13, 2010 Comments at 5.

88a

markets must adapt and eliminate barriers to entry to

the use and incorporation of traditional and non-

traditional resources—where non-traditional resources

include actively-managed demand—in the dispatch and

management of the electric system.” They further

posit that the lack of a unified policy itself represents a

regulatory barrier to demand response,’ and that a

consistent set of rules reduces the costs and complexi-

ties of demand response participation and facilitates

training and transfer of personnel across regions.”

To that end, many commenters argue that adopting a

unified approach to demand response compensation at

the LMP, as opposed to allowing regional variation

including payment of something less than LMP, is

necessary to overcome the barriers to entry of demand

response providers.'” Reciting the many benefits of

demand reductions in energy use, these commenters

support a compensation level that will provide a cata-

lyst for private sector engagement in improved energy

management practices. Viridity argues that the near

absence of demand response participating in energy

markets is powerful empirical proof that current, var-

ying levels of compensation are inadequate—especially

in markets that start with a market-based level of

© Steel Manufacturers Ass’n May 13, 2010 Comments at 12.

'‘* PIO May 13, 2010 Comments at 9; DR Supporters Aug. 30,

2010 Comments at 6-7.

8 See, e.g., Alcoa May 13, 2010 Comments at 13.

\@ NECPUC May 13, 2010 Comments at 4; NYISO May 13, 2010

Comments at 16.

89a

compensation and then reduce it by the generation

portion of a customer’s retail rate (LMP-G)."”

44. Other commenters caution against standardizing

the compensation level for demand response, pointing

to regional differences in market structure, state reg-

ulatory environment, and resource mix."

ae —

45. The Commission acknowledges the diverging

opinions of commenters regarding the appropriate

level of compensation for demand response resources.

As discussed above, commenters are split on this issue,

with some in favor of paying the LMP for demand re-

ductions in the day-ahead and real-time energy mar-

kets in all hours, others arguing that paying the LMP

for demand reductions under any conditions will result

in over-compensation or distortions in incentives to re-

duce consumption, and still others arguing that paying

the LMP for demand reductions is only appropriate

when it is reasonably certain to be cost-effective.

46. In the face of these diverging opinions, the Com-

mission observes that, as the courts have recognized,

“issues of rate design are fairly technical and, insofar

as they are not technical, involve policy judgments that

49 Viridity Energy May 13, 2010 Comments at 4.

"See, e.g., May 13, 2010 Comments of: ConEd at 3-4; Consum-

ers Energy at 2; California Commission at 9; CMEEC at 2-3, 14-15;

Detroit Edison at 3-5; Dominion at 8; Duke Energy at 4; EPSA at 6;

Hess at 4; Indicated New York TOs at 3; Maryland Commission at 5;

Midwest TDUs at 2, 6; Midwest ISO TOs at 16; National Grid at 5-6;

11-12; New York Commission at 4, 11; NCPA at 3; NYISO at 2-3;

ODEC at 27; PJM at 5-6; SPP at 1.

90a

lie at the core of the regulatory mission.’”"* We also

observe that, in making such judgments, the Commis-

sion 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."

47. As discussed further below, the Commission

agrees with commenters who support payment of LMP

under conditions when it is cost-effective to do so, as

determined by the net benefits test described herein."

We have previously accepted a variety of ISO and RTO

proposals for compensation for demand response re-

sources participating in organized wholesale energy

markets. We find, based on the record here that,

2 Elec. Consumers Res. Council v. FERC, 407 F.3d 1232, 1236

(D.C. Cir. 2005) (quoting Pub. Util. Comm'n of the State of Cal. v.

FERC, 254 F.3d 250, 254 (D.C. Cir. 2001)); see also Town of Nor-

wood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992).

"See Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 872 (D.C.

Cir. 1993) (“It is the FERC’s established policy to consider equitable

factors in designing rates, and to allow for phasing in of changes

where appropriate. It is hardly arbitrary or capricious so

to temper the dictates of theory by reference to their consequences

in practice.”); Vermont Dep’t of Pub. Serv. v. FERC, 817 F.2d 127,

135 (D.C. Cir. 1987) (“Indeed, ‘the congressional grant of authority

to the agency indicates that the agency’s interpretation typically will

be enhanced by technical knowledge.”” (quoting Nat'l Fuel Gas Sup-

ply Corp. v. FERC, 811 F.2d 1563, 1570 (D.C. Cir. 1987))); Columbia

Gas Transmission Corp. v. FERC, 750 F.2d 105, 112 (D.C. Cir. 1984)

(“the Commission is vested with wide discretion to balance compet-

ing equities against the backdrop of the public interest”).

'4 See generally May 13, 2010 Comments of NYSCPB; NECA;

Capital Power; NECPUC; Maryland Commission; New York Com-

mission; NSTAR; National Grid; NE Public Systems.

Sla

when a demand response resource has the capability to

balance supply and demand as an alternative to a gen-

eration resource, and when dispatching and paying

LMP to that demand response resource is shown to be

cost-effective as determined by the net benefits test

described herein, payment by an RTO or ISO of com-

pensation other than the LMP is unjust and unrea-

sonable. When these conditions are met, we find that

payment of LMP to these resources will result in just

and reasonable rates for ratepayers.’ As stated in

the NOPR, we believe paying demand response re-

sources the LMP will compensate those resources in a

manner that reflects the marginal value of the re-

source to each RTO and ISO."

48. The Commission emphasizes that these findings

reflect a recognition that it is appropriate to require

compensation at the LMP for the service provided by

demand response resources participating in the orga-

nized wholesale energy markets only when two condi-

tions are met:

¢ The first condition is that the demand response

resource has the capability to provide the service,

i.e., the demand response resource must be able to

cisplace a generation resource in a manner that

serves the RTO or ISO in balancing supply and de-

mand.

"@ The Commission’s findings in this Final Rule do not preclude

the Commission from determining that other approaches to com-

pensation would be acceptable when these conditions are not met.

6 NOPR at P 12.

92a

* The second condition is that the payment of

LMP for the provision of the service by the demand

response resource must be cost-effective, as deter-

mined by the net benefits test described herein.

49. With respect to the first, capability-related condi-

tion, we note that a power system must be operated so

that there is real-time balance of generation and load,

supply and demand. An RTO or ISO dispatches just

the amount of generation needed to match expected

load at any given moment in time. The system can

also be balanced through the reduction of demand.’

Both can have the same effect of balancing supply and

demand at the margin either by increasing supply or

by decreasing demand.

50. With respect to the second cost-effectiveness con-

dition, the record leads us to alter the proposal set

forth in the NOPR in this proceeding. As various

commenters explain, dispatching demand response re-

sources may result in an increased cost per unit to load

associated with the decreased amount of load paying

the bill, depending on the change in LMP relative to

the size of the energy market. As stated above, this

is the billing unit effect of dispatching demand re-

'’ Andrew L. Ott Sept. 13, 2010 Statement at 1.

Economic and Capacity-based demand response clearly provides

benefits to regional grid operation and the wholesale market op-

eration. . . These demand resources provide benefits by

providing valuable alternatives to PJM in maintaining operation-

al reliability and in promoting efficient market operations.

Id. at 1; see also CDRI May 13, 2010 Comments at 10; CDWR May

13, 2010 Comments at 5; NJPBU May 13, 2010 Comments at 2.

93a

sponse resources.'* However, when reductions in

LMP from implementing demand response results in a

reduction in the total amount consumers pay for re-

sources that is greater than the money spent acquiring

those demand response resources at LMP, such a pay-

ment is a cost-effective purchase from the customers’

standpoint."” In comparison, when wholesale energy

market customers pay a reduced price attributable to

demand response that does not reduce total costs to

customers more than the costs of paying LMP to the

demand response dispatched, customers suffer a net

loss. Implementation of the net benefits test de-

scribed herein will allow each RTO or ISO to distin-

guish between these situations.

51. This billing unit effect and the net benefits test

through which it is addressed herein, warrant more

detailed discussion. In the organized wholesale en-

ergy markets, the economic dispatch organizes offers

from lowest to highest bid in order to balance supply

and demand, taking into account other parameters

such as requirements for a generator to operate at a

48 As stated above, dispatching generation resources does not

produce this billing unit effect because it does not result in a de-

crease of load.

"® As a simple example, assume a market of 100 MW, with a cur-

rent LMP of $50/MWh without demand response, and an LMP of

$40/MWh if 5 MW of demand response were dispatched. Total pay-

ments to generators and load would be $4,000 with demand response

compared to the previous $5,000. Even though, the reduced LMP is

now being paid by less load, only 96 MW compared to 100 MW, the

price paid by each remaining customer would decrease from $50/

MWh to $42.11/MWh ($4,000/95). Therefore, the payment of LMP

to demand resources is cost-effective.

94a

minimum level of output or minimum amount of time,

reserve requirements and so forth. With dispatch of

a demand response resource, the load also goes down,

that is, the level of remaining load falls. However,

the “supply” of resources deployed—which includes

both generation and demand response—does not fall.

The total costs to the system for these resources must

then be allocated among the reduced quantity of re-

maining load.

52. In the absence of the net benefits test described

herein, the RTO’s or ISO’s economic dispatch ordinar-

ily would select demand response when it is the incre-

mental resource with the lowest bid. However, if the

next unit of generation is not sufficiently more expen-

sive than the demand response resource, the decrease

in LMP multiplied by the remaining load would not be

greater than the costs of dispatching the demand re-

sponse resource. In this situation, dispatching the

demand response resource would result in a higher

price to remaining customers than the dispatch of the

next unit of generation in the bid stack. While the

demand response resource appears cost competitive in

the dispatch order, selection of the demand response

resource increases the total cost per unit to remaining

load, and it would not be cost-effective to dispatch the

demand response resource.

53. For this reason, the billing unit effect associated

with dispatch of a demand response resource in an

energy market must be taken into account in the eco-

nomic comparison of the energy bids of generation re-

sources and demand response resources. Therefor2,

rather than requiring compensation at LMP in all

95a

hours, the Commission requires the use of the net ben-

efits test described herein to ensure that the overall

benefit of the reduced LMP that results from dis-

patching demand response resources exceeds the cost

of dispatching those resources. When the above-

noted conditions of capability and of cost-effectiveness

are met, it follows that demand response resources

that clear in the day-ahead and real-time energy mar-

kets should receive the LMP for services provided, as

do generation resources. LMP represents the mar-

ginal value of an increase in supply or a reduction in

consumption at each node within an ISO or RTO, i.e.,

LMP reflects the marginal value of the last unit of

resources necessary to balance supply and demand.

Indeed, LMP has been the primary mechanism for

compensating generation resources clearing in the

organized wholesale energy markets since their for-

mation.™

54. The Commission finds that demand response re-

sources that clear in the day-ahead and real-time en-

ergy markets should receive the same market-clearing

LMP as compensation in the organized wholesale en-

ergy markets when those resources meet the condi-

tions established here as a cost-effective alternative to

the next highest-bid generation resources for purposes

of balancing the energy market. We discuss below

the comments filed on these issues.

55. Some commenters dispute that the foregone con-

sumption of energy by demand response resources

® See DR Supporters Aug. 30, 2010 Reply Comments (Kahn

Affidavit at 2 (footnote omitted)).

96a

performs the service of balancing supply and demand

in the energy market as would energy supplied by gen-

erators in the day-ahead and real-time energy mar-

kets, arguing that it is inappropriate to pay electric

consumers to not consume.™ The Commission disa-

grees. Generation and load must be balanced by the

RTOs and ISOs when clearing the day-ahead and real-

time energy markets, and such balancing can be ac-

complished by changes in either supply or demand.

The Commission finds that in the organized wholesale

energy markets demand response can balance supply

and demand as can generation.

56. Commenters that oppose this finding do not ade-

quately recognize a distinctive and perhaps unique

characteristic of the electric industry. The electric

industry requires instantaneous balancing of supply

and demand at all times to maintain reliability. It is

in this context that the Commission finds that demand

response can balance supply and demand as can gen-

eration when dispatched, in the organized wholesale

energy markets.

57. Due to a variety of factors, demand responsive-

ness to price changes is relatively inelastic in the elec-

tric industry and does not play as significant a role in

setting the wholesale energy market price as in other

industries. The Commission has recognized that bar-

riers remain to demand response participation in or-

| See, e.g., ISO-NE May 13, 2010 Comments at 3; APPA May 13,

2010Comments at 12; Capital Power May 13, 2010 Comments at 2;

EPSA May 13, 2010 Comments at 72.

97a

ganized wholesale energy markets. For example, in

Order No. 719, the Commission stated:

[DJespite previous Commission and RTO and ISO

efforts to facilitate demand response, regulatory

and technological barriers to demand response par-

ticipation persist, thereby limiting the benefits that

would otherwise result. A market functions effec-

tively only when both supply and demand can mean-

ingfully participate, and barriers to demand re-

sponse limit the meaningful participation of demand

in electricity markets.™

Barriers to demand response participation at the

wholesale level identified by commenters include the

lack of a direct connection between wholesale and re.

tail prices," lack of dynamic retail prices (retail pric-

es that vary with changes in marginal wholesale costs),

the lack of real-time information sharing, and the lack

of market incentives to invest in enabling technologies

that would allow electric customers and aggregators of

retail customers to see and respond to changes in mar-

ginal costs of providing electric service as those costs

change. For example, Dr. Kahn states:

“ Order No. 719, FERC Stats. & Regs. 4 31,281 at P 83 (citing

Federal Energy Regulatory Commission Staff, A National Asses-

sment of Demand Response Potential (June 2009), found at http-/

www .ferc.gov/legal/staff-refports/06-09-demand-response.pdf; Barri-

ers to Demand Side Response in PJM (2009)). In compliance filings

submitted by RTOs and ISOs and their market monitors pursuant to

Order No. 719, as well as in responsive pleadings, parties have men-

tioned additional barriers, such as the inability of demand response

resources to set LMP, minimum size requirements, and others.

™ See. e.g., Monitoring Analytics May 13, 2010 Comments at 4-6.

98a

These circumstances—specifically, the fact that

pass-through of the LMP is costly and (perhaps)

politically infeasible, the possibly prohibitive cost of

the metering necessary to charge each ultimate us-

er, moment-by-moment, the often dramatic changes

in true marginal costs for each—can justify direct

payment at full LMP to distributors and ultimate

customers who promise to guarantee their immedi-

ate response to such increases in true marginal

costs of supplying them.™

Furthermore, EnerNOC states:

On a more fundamental level, the inadequate com-

pensation mechanisms in place today in wholesale

energy markets fail to induce sufficient investment

in demand response resource infrastructure and

expertise that could lead to adequate levels of de-

mand response procurement. Without sufficient

investment in the development of demand response,

demand response resources simply cannot be pro-

cured because they do not yet exist as resources.

Such investment will not occur so long as compen-

sation undervalues demand response resources.™

‘4 DR Supporters Sept. 16, 2009 Comments filed in Docket

No. EL-09-68-000 (Kahn Affidavit at 6). See also id, at 4 (Custom-

ers offering to reduce consumption should be induced “to behave as

they would if market mechanisms alone were capable of rewarding

them directly for efficient economizing.”).

‘8 EnerNOC May 13, 2010 Comments at 4; see also Alcoa May 13,

2010 Comments at 4; Viridity May 13, 2010 Comments at 5-6.

99a

58. The Commission concludes that paying LMP can

address the identified barriers to potential demand re-

sponse providers.

59. Removing barriers to demand response will lead

to increased levels of investment in and thereby par-

ticipation of demand response resources (and help lim-

it potential generator market power), moving prices

closer to the levels that would result if all demand

could respond to the marginal cost of energy. To that

end, the Commission emphasizes that removing barri-

ers to demand response participation is not the same

as giving preferential treatment to demand response

providers; rather, it facilitates greater competition,

with the markets themselves determining the appro-

priate mix of resources, which may include both gen-

eration and demand response, needed by the RTO and

ISO to balan

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