137 FERC ¶ 61,215 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Demand Response Compensation in Organized 

Wholesale Energy Markets 

Docket No. RM10-17-001 

ORDER NO. 745-A 

ORDER ON REHEARING AND CLARIFICATION 

(Issued December 15, 2011) 

TABLE OF CONTENTS

Paragraph Numbers

I. Introduction ............................................................................................................................2.

II. Requests for Rehearing and Clarification.............................................................................6.

III. Discussion............................................................................................................................11.

A. Commission Jurisdiction and Authority to Regulate Demand Response Resources.......11.

1. Requests for Rehearing.................................................................................................12.

2. Commission Determination..........................................................................................20.

B. Demand Response Resource Compensation Level..........................................................36.

1. Requests for Rehearing.................................................................................................37.

2. Commission Determination..........................................................................................54.

a. LMP Compensation..................................................................................................54.

b. Effect on Retail Demand Response Programs .........................................................71.

c. Need for a Uniform Requirement.............................................................................72.

d. Effect on Market Power ...........................................................................................76.

e. Costs of Generation Resources.................................................................................79.

C. Net Benefits Test and Determination of the Threshold Price Level ................................81.

1. Requests for Rehearing.................................................................................................85.

2. Commission Determination..........................................................................................91.

D. Cost Allocation.................................................................................................................98.

1. Requests for Rehearing.................................................................................................100.

2. Commission Determination..........................................................................................111.

E. Measurement and Verification .........................................................................................121.

1. Requests for Rehearing.................................................................................................122.

2. Commission Determination..........................................................................................123.
Docket No. RM10-17-001 ii 

F. Study Regarding the Dynamic Implementation of the Net Benefits Test into the 

Dispatch Algorithm................................................................................................................124.

1. Requests for Rehearing.................................................................................................125.

2. Commission Determination..........................................................................................127.

G. Applicability of Order No. 745 to Circumstances When it is not Cost-Effective to 

Dispatch Demand Response Resources .................................................................................129.

1. Requests for Rehearing.................................................................................................130.

2. Commission Determination..........................................................................................131.

H. Effect of Order No. 745 on CAISO’s Demand Response Programs ...............................132.

1. Requests for Rehearing.................................................................................................134.

a. Proxy Demand Resource Product.............................................................................135.

b. Reliability Demand Response Products...................................................................138.

c. Participating Load Program......................................................................................139.

2. Commission Determination..........................................................................................140.

I. Compliance with the Regulatory Flexibility Act...............................................................142.
137 FERC ¶ 61,215 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Philip D. Moeller, John R. Norris, 

 and Cheryl A. LaFleur. 

Demand Response Compensation in Organized 

Wholesale Energy Markets 

Docket No. RM10-17-001 

ORDER NO. 745-A 

ORDER ON REHEARING AND CLARIFICATION 

(Issued December 15, 2011) 

1. In this order the Commission denies rehearing of Order No. 745 (Final Rule),1

 and 

grants in part and denies in part clarification regarding certain provisions of the order. 

Order No. 745 amended Commission regulations to require that a demand response 

resource participating in an organized wholesale energy market must be compensated for 

the service it provides at the market price for energy when the demand response resource 

has the capability to balance supply and demand as an alternative to a generation resource 

and when the dispatch of demand response resource is cost-effective. 

I. Introduction

2. On March 15, 2011, the Commission issued Order No. 745, a Final Rule 

amending its regulations under the Federal Power Act (FPA) regarding demand response 

compensation in the Regional Transmission Organization (RTO) and Independent 

System Operator (ISO) day-ahead and real-time organized wholesale energy markets. 

The Commission determined that the Final Rule would help improve the functioning and 

competitiveness of organized wholesale energy markets, thereby ensuring just and 

reasonable rates in those markets. In the Final Rule, the Commission requires each RTO 

and ISO in which demand response participates in its energy market to pay a demand 

 1 Demand Response Compensation in Organized Wholesale Energy Markets, 

Order No. 745, 76 Fed. Reg. 16,658 (Mar. 24, 2011), FERC Stats. & Regs. ¶ 31,322 

(2011). 
Docket No. RM10-17-001 - 2 - 

response resource the market price for energy, also referred to as the locational marginal 

price (LMP), when two conditions are met. First, the demand response resource must 

have the capability to balance supply and demand as an alternative to a generation 

resource. Second, dispatch of the demand response resource must be cost-effective as 

determined by a net benefits test.2

3. The Commission in the Final Rule also provided guidance about the net benefits 

test that it required RTOs and ISOs to include in their respective compliance filings, and 

on the formulation of such a test. As explained in the Final Rule, the net benefits test 

begins with an analysis of a RTO’s or ISO’s historical supply curves grouped into 

monthly periods, from which a threshold point can be calculated. This threshold point 

corresponds to a point on the supply curve at which the benefit to load from the reduced 

LMP resulting from dispatching demand response resources exceeds the increased cost to 

load associated with the billing unit effect. The Commission stated in the Final Rule that 

it expects that the net benefits test would be satisfied, thereby requiring payment of LMP, 

where the supply curve is shaped such that small decreases in generation that is used to 

serve load will result in price decreases sufficient to offset the billing unit effect. 

4. The Commission also required each RTO and ISO to review their current 

measurement and verification requirements in light of the changes in this Final Rule and 

develop appropriate revisions and modifications, if necessary, to ensure that their 

baselines remain accurate and that they can verify that demand response resources have 

performed. 

5. Finally, the Final Rule set forth cost allocation requirements applicable to the costs 

incurred by RTOs and ISOs when paying demand response compensation. The 

Commission noted that, as a result of the billing unit effect, the difference between the 

amount owed by the RTO or ISO to both generation and demand response resources, and 

the revenue derived from load, results in a negative balance that must be addressed 

through cost allocation. Allocation of costs, as explained by the Final Rule, is reasonable 

when costs are allocated proportionally to all entities that purchase from the relevant 

 2

 The Commission explained that a net benefits test is necessary because the 

dispatch of demand response resources may result in an increased cost per unit to load 

associated with the decreased amount of load that pays for the cost of energy purchased 

in the organized wholesale energy market. The Commission further explained that when 

the LMP is reduced and consumers realize a cost savings because of the participation of 

demand response resources in the energy market, and where this cost savings is of a 

sufficient amount to overcome the total amount that consumers pay for demand response 

resources at the LMP and the effect of the reduced quantity of load paying for the 

purchased supply resources, such a purchase of demand response resources is costeffective. 
Docket No. RM10-17-001 - 3 - 

energy market in the area(s) that benefit from the lower LMPs that result from demand 

response resource participation in the organized wholesale energy markets. 

II. Requests for Rehearing and Clarification

6. The following entities have filed timely requests for rehearing of the Final Rule: 

Edison Electric Institute (EEI); Electric Power Supply Association (EPSA), Independent 

Power Producers of New York, Inc. (IPPNY), Electric Power Generation Association 

(EPGA), and New England Power Generators Association, Inc. (NEPGA) (collectively, 

Competitive Supplier Associations or CSA); EPSA, American Public Power Association 

(APPA), EPGA, and National Rural Electric Cooperative Association (NRECA) 

(collectively, Joint Petitioners); Midwest Transmission Dependent Utilities (Midwest 

TDUs); Organization of MISO States (OMS); PJM Power Providers Group (P3); and 

PPL Parties. The following entities have filed timely requests for clarification and/or 

rehearing of the Final Rule: California Department of Water Resources State Water 

Project (SWP); California Independent System Operator Corporation (CAISO);3

 Demand 

Response Supporters (DR Supporters);4

 Public Utilities Commission of the State of 

California (CPUC); Midwest ISO Transmission Owners (Midwest ISO TOs); and 

Old Dominion Electric Cooperative (ODEC), APPA, and NRECA (collectively, Joint 

Parties). The Illinois Commerce Commission (ICC) filed a timely request for 

clarification. 

7. Occidental Permian Ltd. and Occidental Chemical Corporation (collectively, 

Occidental), filed a motion for leave to answer and answer responding to the request for 

clarification or rehearing filed by the DR Supporters.5

 ISO New England Inc. (ISO-NE) 

and the New England Power Pool (NEPOOL) Participants Committee filed a motion for 

leave to answer and answer responding to the request for clarification filed by the 

ICC and the request for clarification or rehearing filed by the DR Supporters.6

 

 3

 California Independent System Operator Corporation (CAISO) requests that the 

Commission issue a substantive order within 30 days after the April 14, 2011 deadline for 

petitioners to file requests for rehearing. The Office of the Secretary issued an Order 

Granting Rehearing for Further Consideration on May 13, 2011. Accordingly, CAISO’s 

issues are addressed in this order. 

4

 Members of the Demand Response Supporters include: American Forest & 

Paper Association, Consumer Demand Response Initiative, EnerNOC, Inc., Project for 

Sustainable FERC Energy Policy, and Viridity Energy, Inc. 

5

 Occidental Permian Ltd. and Occidental Chemical Corporation (Occidental) 

April 29, 2011 Answer. 

6

 ISO New England Inc. (ISO-NE) April 29, 2011 Answer. 
Docket No. RM10-17-001 - 4 - 

Viridity Energy, Inc. filed a motion for leave to answer and answer responding to the 

request for rehearing filed by EEI, the request for clarification or rehearing filed by the 

CPUC, and the request for clarification and rehearing filed by CAISO.7

 The Industrial 

Energy Consumer Group (IECG) filed a motion for leave to answer and answer to the 

motion for leave to answer and answer filed by ISO-NE.8

 The NEPOOL Participants 

Committee filed an answer responding to the motion for leave to answer and answer filed 

by IECG.9

 Wal-Mart Stores, Inc., along with a collection of retail end-use customer 

demand response participants, filed a letter supporting the Final Rule, and answering the 

request for clarification or rehearing filed by the CPUC and the request for clarification 

and rehearing filed by CAISO.10 

8. Rule 713(d)(1) of the Commission’s Rules of Practice and Procedure, 18 C.F.R. 

§ 385.713(d)(1) (2011), prohibits an answer to a request for rehearing. Accordingly, the 

answers from Occidental, ISO-NE and NEPOOL Participants Committee, Viridity, and 

Wal-Mart Stores, Inc. are rejected. IECG’s and NEPOOL Participants Committee’s 

answers to an answer are dismissed. 

9. CAISO filed a motion to lodge, and an errata to that motion, seeking to include in 

the record a CAISO Market Surveillance Committee opinion regarding the Final Rule, as 

well as a concurring opinion by Steven Stoft of the Market Surveillance Committee, both 

issued on June 6, 2011, to supplement its request for clarification and rehearing.11 

CAISO notes that it included a draft of the opinion in its request for clarification and 

rehearing, indicating that it would supplement the filing with the final opinion once 

issued. CAISO indicated that it was unable to submit the final opinion with its request 

for clarification and rehearing because the Market Surveillance Committee procedures 

require draft opinions to be posted before they may be finalized. 

10. We deny CAISO’s motion to lodge. Although CAISO indicated in its request for 

clarification and rehearing that a final version of the Market Surveillance Committee 

opinion would be forthcoming, the draft submitted with the request for clarification and 

rehearing bears little resemblance to the final opinion submitted on June 22, 2011. The 

 7

 Viridity Energy, Inc. (Viridity) May 6, 2011 Answer. 

8

 Industrial Energy Consumer Group May 13, 2011 Answer. 

9

 New England Power Pool (NEPOOL) Participants Committee May 24, 2011 

Answer. 

10 Wal-Mart Stores, Inc. June 8, 2011 Letter. 

11 CAISO June 22, 2011 Motion to Lodge. 
Docket No. RM10-17-001 - 5 - 

draft opinion included with the request for clarification and rehearing was two pages 

long. The final opinion submitted with the motion to lodge consists of 21 pages, and the 

Stoft opinion, which was not included with the request for clarification and rehearing, is 

an additional 24 pages. The CAISO filing does not respond to any arguments raised by 

other parties on rehearing, but rather adds supplemental material to its rehearing request, 

more than two months following the deadline for filing requests for rehearing. As such, 

we will reject it as an out-of-time rehearing request.12

III. Discussion

A. Commission Jurisdiction and Authority to Regulate Demand Response 

Resources

11. In the Final Rule, the Commission explained that it has jurisdiction over demand 

response in the organized wholesale energy markets due to the direct effect demand 

response resources have on wholesale energy prices.13 The Commission stated that its 

actions in issuing the Final Rule arise out of its responsibility to ensure just, reasonable, 

and not unduly discriminatory or preferential wholesale energy market rates.14 The 

Commission further noted that the Final Rule does not affect a state’s authority over retail 

rates, nor does it preclude state-administered demand response programs.15 Lastly, the 

Commission stated that its actions are consistent with the policy set forth by Congress 

calling for the removal of barriers to demand response resource participation in the 

energy markets.16

1. Requests for Rehearing

12. Joint Petitioners, Midwest TDUs, PPL Parties, and P3 request rehearing arguing 

that the Commission does not have jurisdiction over the compensation paid to demand 

response providers.17 The petitioners argue that demand response providers’ actions, 

 12 PJM Interconnection, L.L.C., 135 FERC ¶ 61,018, at P 19-21 (2011). 

13 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 112. 

14 Id. P 115. 

15 Id. P 114. 

16 Id. P 113. 

17 Joint Petitioners Request for Rehearing at 7; Midwest TDUs Request for 

Rehearing at 8; PPL Parties Request for Rehearing at 7; P3 Request for Rehearing at 5-6. 
Docket No. RM10-17-001 - 6 - 

characterized by the petitioners as retail non-purchases, are not wholesale sales as 

described in section 201(b)(1) of the FPA.18 The petitioners assert that because 

sections 20519 and 20620 of the FPA apply only to actions subject to the Commission’s 

jurisdiction, the Commission is powerless to act on demand response compensation.21 

The petitioners analogize demand response services to non-jurisdictional retail rates 

applicable to retail purchases and conclude that demand response compensation falls 

within the realm of state jurisdiction.22

13. Joint Petitioners, Midwest TDUs, PPL Parties, and P3 assert that the Commission, 

by way of its order in EnergyConnect, Inc. (EnergyConnect),23 has previously established 

that demand response providers are not engaged in a sale for resale of energy back into 

the energy market, and therefore are not subject to the Commission’s jurisdiction because 

the terms of section 201(b)(1) are not met.24

14. Joint Petitioners, Midwest TDUs, PPL Parties, and P3 argue that the Commission 

is in error to the extent that it believes it has jurisdiction over demand response 

compensation through the “affecting” clause of sections 205(a) and 206(a) of the FPA.25 

The petitioners argue that Commission jurisdiction, obtained where certain rules and 

regulations affect rates or charges pertaining to the wholesale sale of electric energy, is 

not broad enough to overcome the fact that demand response is not a jurisdictional sale 

 18 16 U.S.C. § 824(b)(1) (2006). 

19 16 U.S.C. § 824d. 

20 16 U.S.C. § 824e. 

21 Joint Petitioners Request for Rehearing at 7; Midwest TDUs Request for 

Rehearing at 8; PPL Parties Request for Rehearing at 7-8; P3 Request for Rehearing 

at 5-6. 

22 Joint Petitioners Request for Rehearing at 7. 

23 EnergyConnect, Inc., 130 FERC ¶ 61,031 (2010) (EnergyConnect). 

24 Joint Petitioners Request for Rehearing at 6; Midwest TDUs Request for 

Rehearing at 9; PPL Parties Request for Rehearing at 7-8; P3 Request for Rehearing at 5. 

25 Joint Petitioners Request for Rehearing at 8-9; Midwest TDUs Request for 

Rehearing at 10-11; PPL Parties Request for Rehearing at 8; P3 Request for Rehearing 

at 5. 
Docket No. RM10-17-001 - 7 - 

under section 201(b)(1) of the FPA.26 As stated by the Joint Petitioners, the terms of 

sections 205(a) and 206(a) do not trump those of section 201(b)(1).27

15. Joint Petitioners request rehearing arguing that that Commission is prohibited from 

regulating non-jurisdictional entities (demand response resources) through the exercise of 

its authority over public utilities (RTOs and ISOs).28 The petitioners assert that the 

Commission is attempting to indirectly, and wrongly, exercise authority over demand 

response resources, entities it claims are non-jurisdictional under section 201(b)(1) of the 

FPA, by requiring RTOs and ISOs to pay demand response resources the LMP.29 Joint 

Petitioners also assert that prior case law concerning Commission jurisdiction over 

capacity markets is unsupportive in the context of the Final Rule.30 Joint Petitioners 

further argue that demand response resources, when offered into the organized wholesale 

energy market, have no greater effect on the rates generated by the market, than does the 

cost of cement, steel, or coal.31 Petitioners’ reasoning is that if the Commission were 

able to assert jurisdiction over demand response compensation in this manner, then it 

would also be able to do so with respect to any other non-jurisdictional factor that may 

affect rates. 

 

16. Joint Petitioners also argue that that the Commission may not assert jurisdiction 

over demand response compensation even where demand response compensation is 

construed as a component of a jurisdictional, market-based rate for energy in organized 

markets.32 Joint Petitioners assert that demand response does not qualify for Commission 

review even under a situation where the Commission may review a non-jurisdictional rate 

that is a component of a jurisdictional rate. 

17. Petitioners assert that the Commission does not have implied jurisdiction over 

demand response compensation because “[demand response] is a retail non-purchase, and 

26 Joint Petitioners Request for Rehearing at 9; Midwest TDUs Request for 

Rehearing at 10. 

27 Joint Petitioners Request for Rehearing at 9. 

28 Joint Petitioners Request for Rehearing at 9. 

29 Id. 

30 Id. at 9-10. 

31 Id. at 11. 

32 Id. at 12. 
Docket No. RM10-17-001 - 8 - 

retail rates have traditionally been subject to State or local regulation.”33 The petitioners 

argue that courts are reluctant to infer jurisdiction in an agency over an area it seeks to 

regulate where the area to be regulated has traditionally been regulated by the states.34

18. Joint Petitioners and Midwest TDUs argue that the Commission erred in citing the 

Energy Policy Act of 2005 (EPAct 2005)35 as support for its jurisdiction to regulate 

demand response compensation.36 The petitioners argue that EPAct 2005 is a mere 

policy statement, and does not expand the Commission’s jurisdiction or authority to 

implement that policy.37

19. Joint Petitioners, Midwest TDUs, CAISO, and CPUC argue that the Commission 

is interfering with existing retail demand response programs, and therefore is intruding on 

state jurisdiction.38 Midwest TDUs argue that this constitutes a barrier, in the form of a 

financial disincentive, to participation in retail demand response programs.39

2. Commission Determination

20. We deny the requests for rehearing regarding the Commission’s jurisdiction over 

demand response participation in organized wholesale energy markets. We continue to 

find that Commission regulation of demand response participation in the organized 

wholesale energy markets and the market rules governing that participation is essential to 

the Commission fulfilling its statutory responsibility to ensure that jurisdictional rates are 

just and reasonable. 

 33 Joint Petitioners Request for Rehearing at 13. 

34 Id.

35 Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(f), 119 Stat. 594, 965 

(2005) (EPAct 2005). 

36 Joint Petitioners Request for Rehearing at 14; Midwest TDUs Request for 

Rehearing at 11-12. 

37 Joint Petitioners Request for Rehearing at 14; Midwest TDUs Request for 

Rehearing at 11-12. 

38 Joint Petitioners Request for Rehearing at 13; Midwest TDUs Request for 

Rehearing at 20-21; CAISO Request for Rehearing at 31-32; CPUC Request for 

Rehearing at 13-16. 

39 Midwest TDUs Request for Rehearing at 20. 
Docket No. RM10-17-001 - 9 - 

21. Under section 201 of the FPA40 the Commission has jurisdiction over the 

transmission of electric energy in interstate commerce, as well as the wholesale sale (or 

sale for resale) of electric energy in interstate commerce, and it has jurisdiction over all 

facilities used for such transmission or sale of electric energy. Section 201 also defines a 

public utility as “any person who owns or operates facilities subject to the jurisdiction of 

the Commission.”41 Sections 20542 and 20643 of the FPA provide the Commission with 

jurisdiction over all rates and charges made, demanded, or received by any public utility 

for or in connection with the transmission or sale of electric energy subject to the 

jurisdiction of the Commission. Those sections also provide the Commission with 

jurisdiction over all rules, regulations, practices, or contracts that affect jurisdictional 

rates, charges, or classifications. 

22. In EnergyConnect,

44 the Commission found that a company engaged solely in 

offering demand response services would not be a public utility and would not be making 

wholesale sales of electric energy. However, the Commission also found that it would 

still have jurisdiction to regulate certain aspects of demand response “as a practice that 

affects rates in organized wholesale electric markets under sections 205(a) and (c) and 

section 206(a) of the FPA.”45 In Order Nos. 71946 and 719-A, the Commission reached 

the same conclusion, including with respect to its jurisdiction over demand response in 

RTO and ISO ancillary service markets. Speaking generally, the Commission found that 

within RTO and ISO markets, demand response “affects wholesale markets, rates, and 

practices.”47 

 40 16 U.S.C. § 824. 

41 16 U.S.C. § 824(e). 

42 16 U.S.C. § 824d. 

43 16 U.S.C. § 824e. 

44 EnergyConnect, 130 FERC ¶ 61,031. 

45 Id. P 32. 

46 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719, FERC Stats. & Regs. ¶ 31,281 (2008), order on reh’g, Order No. 719-A, FERC 

Stats. & Regs. ¶ 31,292 (2009), order on reh’g, Order No. 719-B, 129 FERC ¶ 61,252 

(2009). 

47 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 46. 
Docket No. RM10-17-001 - 10 - 

23. In support of this assertion of jurisdiction, the Commission in Order No. 719-A 

described a direct effect on wholesale prices caused by demand response participation in 

RTO and ISO markets.48 The Commission stated that this direct effect occurs when 

demand response is offered directly into the wholesale market, causing a reduction in 

demand to occur, thereby resulting in a lower wholesale price.49 In addition, the 

Commission found that such demand response participation helps to mitigate generator 

market power and strengthen system reliability.50 Demand response resources that 

participate in a wholesale market, especially when market prices are high, tend to lower 

the market clearing price placing downward pressure on generator offer strategies by 

making it more likely that a higher offer from a generator will not be accepted when the 

market clears.51 Moreover, system reliability realizes a benefit because demand response 

generally can be dispatched by the system operator with a minimal notice period, helping 

to balance the electric system in the event that an unexpected contingency occurs.52

24. The Final Rule reiterated many of these findings in explaining the Commission’s 

basis for jurisdiction with respect to demand response participation in organized 

wholesale energy markets.53 We now reaffirm our previous findings on how demand 

response has a direct effect on wholesale rates subject to Commission jurisdiction under 

FPA section 201(b)(1), as well as our conclusion that these findings support Commission 

jurisdiction with respect to demand response participation in the organized wholesale 

energy markets and the market rules governing that participation.54 

 

(continued...) 

48 Id. P 47. 

49 Id.

50 Id.

51 Id. In addition, demand response can reduce transmission rates by relieving 

congestion on transmission lines that leads to higher transmission charges. In RTO and 

ISO markets, these higher transmission charges are reflected in the congestion costs that 

wholesale customers are required to pay. 

52 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 47. 

53 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 112-15. 

54 The Commission’s finding of this direct effect on wholesale rates is important in 

light of the statement of the U.S. Court of Appeals for the District of Columbia Circuit 

that the Commission is empowered under section 206 to assess practices that directly 
Docket No. RM10-17-001 - 11 - 

25. This jurisdictional analysis is consistent with precedent in which the courts have 

found that the Commission has jurisdiction over aspects of RTO services that affect 

wholesale rates. For example, in Connecticut Dep’t of Pub. Util. Control v. FERC,

55

petitioner challenged the Commission’s authority to review, approve, or modify the 

Installed Capacity Requirement (ICR), a key input into ISO-NE’s forward capacity 

market. Petitioner argued that any Commission-ordered increase in the ICR would be 

equivalent to the Commission directing the installation of new capacity, thereby violating 

the FPA’s limit of Commission jurisdiction over generation facilities. The court rejected 

this argument, holding that the ICR is subject to the Commission’s authority because it is 

a “practice affecting rates” under sections 205 and 206 of the FPA. Specifically, the 

court upheld the Commission’s assertion of jurisdiction because it found that “[w]here 

capacity decisions about an interconnected bulk power system affect FERC-jurisdictional 

transmission rates for that system without directly implicating generation facilities, they 

come within the Commission’s authority.”56 The court found that the ICR was not a 

direct regulation of generation, nor a requirement as to the amount of generation that had 

to be constructed.57 Acknowledging that capacity is not electricity, the court nonetheless 

found that the Commission may “directly establish prices for capacity—or much the 

same, prices for failing to acquire enough capacity—even for the express purpose of 

incentivizing construction of new generation facilities.”58 These holdings reinforce wellestablished precedent with respect to Commission jurisdiction based on the “practice 

affecting rates” language of sections 205 and 206.59 Similarly, if demand response 

 

(continued...) 

affect or are closely related to a public utility’s rates and “not all those remote things 

beyond the rate structure that might in some sense indirectly or ultimately do so.” 

California Indep. Sys. Operator v. FERC, 372 F.3d 395, 403 (D.C. Cir. 2004). 

55 Connecticut Dep’t of Pub. Util. Control v. FERC, 569 F.3d 477 (D.C. Cir. 2009) 

(Connecticut). 

56 Connecticut, 569 F.3d at 484. 

57 Id. at 483. 

58 Id. at 482.

59 See Groton v. FERC, 587 F.2d 1296, 1302 (D.C. Cir. 1978) (capacity deficiency 

charge, just as the capacity adjustment charge “must be deemed to be within the 

Commission's jurisdiction because it too represents a charge for the power and service the 

overloaded participant receives or it is at least a rule or practice affecting the charge for 

these services”); Mississippi Industries v. FERC, 808 F.2d 1525, 1542 (D.C. Cir. 1987) 

(while capacity allocation costs “do not fix wholesale rates, their terms do directly and 

significantly affect the wholesale rates at which the operating companies exchange 
Docket No. RM10-17-001 - 12 - 

participation in the organized wholesale energy market “help[s] to find the right price,” 60

as the Commission has found repeatedly, then that demand response participation and the 

corresponding RTO and ISO market rules “would still amount to a ‘practice . . . 

affecting’ rates.”61

26. Joint Petitioners contend that the capacity market cases are not controlling because 

capacity markets are subject to Commission jurisdiction under section 201 of the FPA 

even though capacity itself is not mentioned. The Commission rejects this argument. 

Joint Petitioners fail to support their contention that some practices that directly affect 

jurisdictional rates but are not mentioned in section 201 (e.g., market rules with respect to 

capacity) are subject to the Commission’s jurisdiction, while other such practices 

affecting rates (e.g., market rules with respect to demand response participation in an 

organized wholesale energy market) are not. As discussed above, the Commission finds 

court precedent on capacity markets and the “practice affecting rates” language of 

sections 205 and 206 to be analogous to the issues presented here with respect to demand 

response participation in organized wholesale energy markets and the market rules of the 

various ISOs and RTOs that govern that participation. 

27. Joint Petitioners, Midwest TDUs, PPL Parties, and P3 argue that section 201(b) of 

the FPA does not invest the Commission with jurisdiction over demand response 

compensation because demand response providers are not public utilities. In making this 

argument, petitioners rely on the Commission’s findings in EnergyConnect. Joint 

Petitioners, Midwest TDUs, PPL Parties, and P3 argue that the Commission cannot claim 

jurisdiction over demand response resources through section 205’s and 206’s “affecting” 

clause when section 201(b) has not been satisfied. The Commission rejects these 

arguments. The Commission’s findings that demand response does not involve a 

wholesale sale of energy, and that entities engaged solely in demand response are not 

 

energy”); Maine Pub. Utils. Comm’n v. FERC, 520 F.3d 464, 479 (D.C. Cir. 2008), rev’d 

in part sub nom. NRG Power Marketing, LLC v. Me. Pub. Utils. Comm’n, 130 S. Ct. 693 

(2010), remanded, Me. Pub. Utils. Comm’n v. FERC, 625 F.3d 754 (D.C. Cir. 2010) 

(concluding that the Commission had jurisdiction over capacity markets, because the “the 

protracted litigation over Must-Run agreements, the locational installed capacity market, 

and the Forward Market is fundamentally a dispute over the rates that will be paid to 

suppliers of capacity.”). 

60 Connecticut, 569 F.3d at 485. 

61 Id. The court in Connecticut, in fact, observed that one of the methods of 

responding to the incentives produced by increases in the ICR short of building new 

generation facilities included the use of “demand response contracts where users are 

compensated for committing to use less electricity during shortages.” Id. at 482. 
Docket No. RM10-17-001 - 13 - 

public utilities, do not void the Commission’s jurisdiction with respect to demand 

response participation in organized wholesale energy markets and the market rules of 

various RTOs and ISOs that govern that participation. As noted above, the Commission 

discussed this issue, as well as the Commission’s jurisdictional conclusion with respect to 

the “practice affecting rates” language of sections 205 and 206, in detail in 

EnergyConnect.

62 A demand response resource that, as discussed in EnergyConnect, 

may not be a public utility, nonetheless may choose to participate in the RTO- and ISOadministered organized wholesale energy markets, therefore making it a market 

participant. The Commission has repeatedly found that market rules governing such 

participation by demand response resources in an organized wholesale energy market are 

a practice that directly affects rates in those jurisdictional markets.63 The rules regarding 

compensation required by the Final Rule are one example of those market rules. Much as 

the forward capacity markets at issue in the court cases discussed above determine rates 

to be paid to capacity resources, the organized wholesale energy markets determine the 

rates (market-clearing prices) that are paid to participants in those markets. 

28. It is also relevant that in Sacramento Municipal Utility District v. FERC,64 the 

court affirmed the Commission’s jurisdiction to impose marginal line losses on a nonpublic utility. In that case, a non-public utility argued that by approving CAISO’s 

assessment of marginal loss charges to transactions involving the non-public utility’s use 

of transmission ownership rights, the Commission unlawfully dictated rates, terms or 

conditions of service to a non-public utility's use of its own transmission facilities and 

effectively compelled such entity to transfer control over its transmission facilities to the 

CAISO. The court found, to the contrary, that the charges assessed to the non-public 

utility involved nothing more than charges for using the CAISO’s facilities. The court 

concluded that the Commission did not exceed its jurisdiction: 

Far from compelling Imperial to become a participating 

transmission owner of [CAISO], FERC merely permitted the 

ISO to charge Imperial for the costs incurred by the ISO when 

Imperial conducts transactions that cause transmission losses 

on the ISO’s grid. The Commission’s proper exercise of its 

power to regulate [CAISO’s] rates was not transformed into a 

 62 EnergyConnect, 130 FERC ¶ 61,031. 

63 As discussed above, the courts have recognized the breadth of the Commission’s 

jurisdiction under sections 205 and 206 of the FPA. See Connecticut, 569 F.3d at 484-85; 

City of Cleveland v. FERC, 773 F.2d 1368, 1376 (D.C. Cir. 1985) (“there is an infinitude 

of practices affecting rates and service”). 

64 Sacramento Mun. Util. Dist. v. FERC, 616 F.3d 520 (D.C. Cir. 2010). 
Docket No. RM10-17-001 - 14 - 

violation of its statutory jurisdiction by dint of its incidental 

effect on Imperial.65

In United Distribution Companies v. FERC,

66 the court likewise affirmed the 

Commission’s jurisdiction to regulate resales of natural gas transportation capacity by 

non-jurisdictional entities.67 The court concluded that the Commission had jurisdiction 

because the “the transaction itself controls access to interstate transportation capacity, 

entirely independent of the jurisdictional nature of the releasing and replacement 

shippers.”68 Similarly, the Commission has jurisdiction over the way in which RTOs and 

ISOs operate jurisdictional markets, including the market rules that govern demand 

response participation in those markets, to assure that the rates resulting from those 

markets are just and reasonable. 

 65 Id. at 536. See also Transmission Agency of N. Cal. v. FERC, 628 F.3d 538, 

540 (D.C. Cir. 2010) (TANC) (finding Commission jurisdiction to regulate 

interconnections with non-public utilities when these transactions “impact the CAISOcontrolled grid [and] only a party that chooses to use the CAISO-controlled grid is 

affected”). 

66 United Distribution Cos. v. FERC, 88 F.3d 1105, 1151-1154 (D.C. Cir. 1996). 

67 Id.

68 Id. at 1153. We also note the statement of the U.S. Supreme Court in Colorado 

Interstate Gas Co. v. FPC, 324 U.S. 581, 602-03 (1945), in interpreting a similar 

jurisdictional limitation in § 1(b) of the Natural Gas Act with respect to gathering: 

That does not mean that the part of § 1(b) which provides that 

the Act shall not apply “to the production or gathering of 

natural gas” is given no meaning. Certainly that provision 

precludes the Commission from any control over the activity 

of producing or gathering natural gas. . . . We only decide that 

it does not preclude the Commission from reflecting the 

production and gathering facilities of a natural gas company 

in the rate base and determining the expenses incident thereto 

for the purposes of determining the reasonableness of rates 

subject to its jurisdiction. 

See also Northern Natural Gas Co. v. FERC, 929 F.2d 1261, 1269 (8th Cir. 1991) 

(finding that Colorado Interstate also permits the Commission to directly regulate rates 

for transportation over a pipeline’s own gathering facilities performed in connection with 

admittedly jurisdictional interstate transportation). 
Docket No. RM10-17-001 - 15 - 

29. Joint Petitioners argue that demand response resources, when offered into the 

organized wholesale energy market, have no greater effect on the rates generated by the 

market than does the cost of cement, steel, or coal. Petitioners express concern that if the 

Commission may assert jurisdiction over demand response compensation, then it would 

also be able to do the same with respect to any other factor that may affect rates. 

30. We disagree with Joint Petitioners’ argument and find that demand response 

resources are not similar to an input cost for generation. 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 ISO-run market, however, buyers are 

generally unable to directly express their willingness to pay for a product at the price 

offered. As discussed later, RTOs and ISOs cannot isolate individual buyers’ willingness 

to pay which results in extremely inelastic demand. Including demand response as a 

resource in RTO and ISO markets provides a way for buyers to indicate the price at 

which they are willing to stop consumption. 

31. We recognize that merely because an input to generation may affect a wholesale 

rate, our jurisdiction does not extend to the regulation of the input itself. Demand 

response resources that participate in an RTO- or ISO-administrated organized wholesale 

energy market, however, are not merely an input cost for generation that indirectly affects 

wholesale rates. Rather, in the circumstances covered by the Final Rule, demand 

response resources are direct participants in the organized wholesale energy markets over 

which we have jurisdiction (just as is generation), and that participation has a direct and 

substantial effect on rates in those markets.69 In light of this distinction, we disagree with 

Joint Petitioners’ claim that the Commission’s actions in the Final Rule create a slippery 

slope that will lead to limitless Commission jurisdiction. As discussed above, the 

Commission’s statutory authority extends to those rules, regulations, practices, or 

contracts that directly affect the jurisdictional rates charged by public utilities. 

32. Joint Petitioners, Midwest TDUs, CAISO, and CPUC argue that the Commission 

is interfering with existing retail demand response programs and, therefore, is intruding 

on state jurisdiction. The Commission rejects this argument. As the Commission stated 

in the Final Rule, demand response is a complex matter that lies at the confluence of state 

and federal jurisdiction.70 Respecting that state interest, the Commission made clear in 

the Final Rule that we are not intruding into the province of state regulation and are “not 

 69 See Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC, 475 F.3d 1277, 1282 

(D.C. Cir. 2007) (affirming Commission’s assertion of jurisdiction over interconnections 

with dual-use facilities, when the facilities are included in a jurisdictional rate and the 

transaction facilitates a wholesale sale of electric energy). 

70 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 114. 
Docket No. RM10-17-001 - 16 - 

regulating retail rates or usurping or impeding state regulatory efforts concerning demand 

response.”71 The fact that participation in a Commission-jurisdictional RTO or ISO 

market may indirectly affect incentives in a state demand response initiative does not 

deprive the Commission of the ability to act within the jurisdictional boundaries 

discussed above. 

33. Joint Petitioners and Midwest TDUs claim that the Commission cannot rely on 

section 1252(f) of EPAct 200572 as a basis for its jurisdiction to regulate demand 

response compensation. Petitioners base their argument on Comcast Corp. v. FCC,

73

asserting that this statutory language is a mere policy statement and does not expand the 

Commission’s jurisdiction or authority to implement policy. 

34. Neither the Final Rule nor this order relies on section 1252(f) of EPAct 2005 as an 

independent basis for Commission jurisdiction. The court in Comcast recognized that 

while statements of Congressional policy do not establish jurisdiction, “statements of 

congressional policy can help delineate the contours of statutory authority.” 74 To that 

end, we cited section 1252(f) of EPAct 2005 because it sheds light on the contours of the 

Commission’s statutory authority. Section 1252(f) of EPAct 2005 states that it is the 

policy of the United States that unnecessary barriers to demand response participation in 

energy, capacity, and ancillary services markets shall be eliminated. No commenter in 

this proceeding questions that such markets, including the organized wholesale energy 

markets addressed in the Final Rule, are subject to the Commission’s jurisdiction. 

35. In light of the Commission’s jurisdiction, under section 201 of the FPA, over rates 

established in the organized wholesale energy markets, and for the reasons discussed in 

detail above, the Commission concludes that demand response participation in the 

organized wholesale energy markets and the market rules governing that participation are 

“practices affecting rates” pursuant to sections 205 and 206 of the FPA. 

 71 Id.

72 EPAct 2005, Pub. L. No. 109-58, § 1252(f), 119 Stat. 594, 965 (“It is the policy 

of the United States that . . . unnecessary barriers to demand response participation in 

energy, capacity, and ancillary service markets shall be eliminated.”). 

73 Comcast Corp. v. FCC, 600 F.3d 642 (D.C. Cir. 2010) (Comcast). 

74 Comcast, 600 F.3d at 654. 
Docket No. RM10-17-001 - 17 - 

B. Demand Response Resource Compensation Level

36. Separate from its findings as to the basis for Commission jurisdiction with respect 

to demand response participation in the organized wholesale energy markets and the 

market rules governing that participation, the Final Rule requires that each RTO and ISO 

that has a tariff provision permitting demand response resources to participate as a 

resource in the energy market must pay to those demand response resources the market 

price when the demand response resource has the capability to balance supply and 

demand and when payment is cost-effective. The Commission found that LMP is the 

appropriate compensation level because LMP reflects the marginal value of the demand 

response resource to each RTO and ISO. The Commission explained that the marketclearing LMP is the appropriate compensation level where demand response resources 

are a cost-effective alternative to generation for balancing the energy market.75

1. Requests for Rehearing

37. ICC requests clarification that the Commission is basing the comparability of 

demand response resources and generation resources on the competition of the two 

resources in the dispatch model, i.e., as they are used to balance electricity supply and 

demand in the economic dispatch and not based on economic comparability. ICC argues 

that demand response is not comparable to generation in terms of the aggregate economic 

impact, financial settlement, and incentives associated with compensation paid at LMP. 

ICC expresses concern that LMP compensation will cause demand response providers to 

disengage from economic production, whereas generation resources do not have the same 

incentive.76

38. CSA, P3, and PPL Parties request rehearing arguing that demand response 

resources are not equivalent to generation in terms of physical characteristics, marginal 

value, planning, economics, performance requirements, operational security, penalties, 

and reliability services. CSA further argues that a demand response resource is not a 

resource like generation because it cannot power residences, commercial establishments 

or industrial facilities, and LMP payment to demand response resources, unlike LMP 

payment to generation, causes the RTO or ISO to incur a net loss. 

39. Joint Parties request rehearing and clarification arguing that demand response 

resources and generation resources are not comparable, even for the purpose of balancing 

supply and demand, because demand response resources have less stringent performance 

requirements and do not have as a part of their core business the generation of electricity. 

 75 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 47. 

76 Illinois Commerce Commission (ICC) Request for Rehearing at 5. 
Docket No. RM10-17-001 - 18 - 

40. CSA, EEI, Midwest TDUs, Joint Parties, Organization of MISO States, PPL 

Parties, and P3 argue that the Final Rule conflicts with Commission efforts to promote 

competitive markets because, according to these petitioners, compensating demand 

response at LMP is a subsidy, or overcompensation, resulting in the suppression of LMPs 

in the energy market.77

41. Petitioners explain that the suppression of LMPs will distort price signals, causing 

customers to reduce or increase their energy purchases at other than optimal levels.78 

CSA further asserts that a suppression of the LMP will delay the construction of new 

generation while accelerating the retirement of current facilities.79

42. CSA further argues that the Final Rule is a violation of a regulated utility’s right to 

just and reasonable compensation for jurisdictional wholesale sales.80 CSA states that the 

Commission failed to quantify or identify the amount by which jurisdictional rates are 

excessive, or would be excessive, absent the Final Rule.81 CSA asserts that the 

Commission has improperly assumed that an increase in demand response resource 

participation leading to a lower market price for energy is “always better”82 without 

regard to whether the corresponding lower rate and reduced revenue for regulated entities 

will be compensatory or confiscatory. CSA asserts that the Commission, by mandating 

compensation at LMP, has violated the Takings Clause of the Fifth Amendment of the 

U.S. Constitution and failed to satisfy its duty under the FPA to ensure that rates for 

 77 Competitive Power Supplier Associations (CSA) Request for Rehearing 

at 16, 40; Edison Electric Institute (EEI) Request for Rehearing at 13; Midwest 

Transmission Dependent Utilities (Midwest TDUs) Request for Rehearing at 15; 

American Public Power Association, National Rural Electric Cooperative Association, 

and Old Dominion Electric Cooperative (collectively, Joint Parties) Request for 

Rehearing at 18; Organization of MISO States (OMS) Request for Rehearing at 4; PPL 

Parties Request for Rehearing at 20; PJM Power Providers Group (P3) Request for 

Rehearing at 8. 

78 See, e.g., CSA Request for Rehearing at 44; EEI Request for Rehearing at 13. 

79 CSA Request for Rehearing at 43. 

80 CSA Request for Rehearing at 51 (citing FPC v. Hope Natural Gas Co., 320 

U.S. 591, 607 (1944)). 

81 Id. at 49. 

82 Id. at 49-50. 
Docket No. RM10-17-001 - 19 - 

jurisdictional sales are just and reasonable as to jurisdictional public utilities making 

those sales.83

43. Petitioners rely on Dr. Hogan and others in support of their position that paying 

LMP is overcompensation.84 EEI refers to Dr. Hogan’s argument that a compensation 

payment of LMP causes a demand response resource to receive a double payment for its 

curtailment. Dr. Hogan contends that a double payment results from the fact that the 

demand response resource does not pay for the energy that it would have consumed and 

also receives full LMP compensation from the RTO or ISO for its curtailment. Likewise, 

EEI and Midwest TDUs cite Potomac Economics, Ltd. for the position that the Final Rule 

allows “[demand response] resource[s] to sell energy in the wholesale market that it is not 

required to purchase at the retail rate. Hence, one can clearly see in this case that the 

[demand response] resource is receiving a subsidy to curtail equal to the retail rate. This 

will manifest itself in potentially significant economic inefficiencies.”85

44. EEI argues that large industrial or commercial customers that use behind-themeter generation to satisfy their energy needs can receive compensation in the amount of 

two times the LMP.86 Large industrial customers with behind-the-meter generation that 

purchase their energy requirements at the LMP set in the relevant RTO or ISO energy 

markets have the option to self-supply when it is less expensive to do so.87 EEI and CSA 

argue that customers with behind-the-meter generation that reduce their load on the grid 

and are paid LMP as a result actually realize a payment of twice the LMP because they 

also avoided purchasing the energy.88 EEI states that in essence, the customer is a 

generator that is now directly competing with other wholesale generators.89

 83 Id. at 50. 

84 EEI Request for Rehearing at 13-15; Joint Parties Request for Rehearing at 18; 

Midwest TDUs Request for Rehearing at 11. 

85 EEI Request for Rehearing at 14; see also Midwest TDUs Request for 

Rehearing at 11. 

86 EEI Request for Rehearing at 21. 

87 Id.

88 EEI Request for Rehearing at 21; CSA Request for Rehearing at 24 n.80. 

89 EEI Request for Rehearing at 21. 
Docket No. RM10-17-001 - 20 - 

45. CSA, EEI, and Joint Parties state that the Commission is erroneously relying on a 

presumption that compensation at LMP is the correct payment level.90 CSA argues that 

the Final Rule relies on a number of faulty assumptions and policy judgments including: 

(1) current levels of demand response participation are inadequate; (2) current levels of 

compensation paid to demand response resources are inadequate; (3) paying LMP will 

mitigate barriers to entry faced by demand response resources; (4) the “required subsidy” 

should be equal to the avoided costs of retail purchases; and (5) standardization of 

demand response compensation is the only solution available.91

46. CSA, EEI, Midwest TDUs, Joint Parties, OMS and PPL Parties argue that paying 

LMP-G is the appropriate payment level because it accounts for the avoided cost that the 

retail customer retains by curtailing its consumption.92 Stated another way, EEI argues 

that a retail customer actually has a property right to consume energy, and that it is this 

property right, or call option, that it is selling to the RTO or ISO.93 EEI states that the 

RTO or ISO should be required to pay for the market value of the call option, rather than 

the market value of the foregone energy.94

47. Midwest ISO TOs and Joint Parties request rehearing arguing that the Commission 

erred in stating that factoring retail rates into wholesale compensation payments presents 

problems for state public utility commissions, ISOs, and RTOs.95 Petitioners point out 

that several state public utility commissions, ISOs, and RTOs filed comments explaining 

that a methodology that properly accounts for “G” (generation) does not impose an 

administrative burden on the RTOs and ISOs, and does not improperly impact state 

public utility commissions. Petitioners further assert that the Commission’s observation 

that RTOs and ISOs do not subtract a cost component from the compensation paid to 

 90 CSA Request for Rehearing at 28; EEI Request for Rehearing at 11; Joint 

Parties Request for Rehearing at 11. 

91 CSA Request for Rehearing at 30. 

92 CSA Request for Rehearing at 77-78; EEI Request for Rehearing at 11; Midwest 

TDUs Request for Rehearing at 18; Joint Parties Request for Rehearing at 17; OMS 

Request for Rehearing at 4; PPL Parties Request for Rehearing at 19; P3 Request for 

Rehearing at 14. 

93 EEI Request for Rehearing at 11. 

94 Id. at 12. 

95 Midwest ISO Transmission Owners (Midwest ISO TOs) Request for Rehearing 

at 20-21; Joint Parties Request for Rehearing at 18. 
Docket No. RM10-17-001 - 21 - 

generators misses their point, because, while RTOs and ISOs pay generators full LMP, 

generators do in fact incur production costs that result in a reduced net compensation 

amount; in contrast they argue that demand response resources pay nothing for the “call 

option” associated with retail energy not consumed.96

48. CSA, EEI, Midwest ISO TOs, and Joint Parties request rehearing arguing that the 

Final Rule does not establish a rational connection between the perceived problem and 

the Commission’s solution. Petitioners argue that the Final Rule does not explain how 

the barriers to entry that demand response resources face with respect to organized 

wholesale energy markets will be mitigated or resolved by requiring RTOs and ISOs to 

pay demand response resources the LMP.97

49. CSA and EEI request rehearing arguing that the Final Rule will have the opposite 

of its intended effect because it will hinder the development of retail dynamic price 

responsive demand programs, along with other state reforms.98 Their argument relies on 

the notion that paying LMP compensation is a subsidy that will inappropriately 

encourage demand response resource participation in wholesale, rather than retail, 

programs. 

50. CSA, EEI, Midwest TDUs, Midwest ISO TOs, Joint Parties, PPL Parties, P3, and 

CAISO further assert that the Commission failed to address, or dismissed entirely, 

arguments opposing the LMP compensation level.99 Petitioners emphasize arguments in 

favor of LMP-G and a region-by-region approach. Petitioners assert that the Commission 

fails to distinguish the standardization in the Final Rule from the region-by-region 

approach permitted by the Commission in Order No. 719.100 

 

(continued...) 

96 Midwest ISO TOs Request for Rehearing at 21. 

97 CSA Request for Rehearing at 28; EEI Request for Rehearing at 17-18; Midwest 

ISO TOs Request for Rehearing at 19; Joint Parties Request for Rehearing at 12-13. 

98 CSA Request for Rehearing at 46-47; EEI Request for Rehearing at 20. 

99 CSA Request for Rehearing at 25-26; EEI Request for Rehearing at 8-9; 

Midwest TDUs Request for Rehearing at 6; Midwest ISO TOs Request for Rehearing at 

10; Joint Parties Request for Rehearing at 7; PPL Parties Request for Rehearing at 10; P3 

Request for Rehearing at 7; CAISO Request for Rehearing at 48-49. 

100 Petitioners argue that Order No. 719 specifically directed RTOs and ISOs to 

develop technical requirements, tailored to their individual circumstances, to facilitate the 

participation of demand response resources in the ancillary services market. See, e.g., 
Docket No. RM10-17-001 - 22 - 

51. CSA requests rehearing arguing that the Final Rule makes the erroneous and 

unsupported suggestion that LMP compensation is needed because current RTO and ISO 

market power mitigation rules are inadequate.101 Petitioners argue that the Commission 

failed to engage in reasoned decision-making and cast doubt on RTO and ISO market 

rules that the Commission previously approved. Petitioners claim that paying LMP 

compensation will lead to a case of over-mitigation because energy markets will now be 

subject to both existing market manipulation rules and demand response resource 

participation resulting in suppressed LMPs. Petitioners state that the Commission’s 

previous approvals of supplier market power rules were made without reference to the 

level of demand response participation in the market, thus demonstrating that demand 

response is not necessary to maintain fair and competitive markets. 

52. Joint Petitioners, Midwest TDUs, PPL Parties, EEI, and P3 argue that the 

Commission failed to make a reasoned finding, as required by section 206 of the FPA, 

that the existing demand response compensation paid by RTOs and ISOs, on a region-byregion basis, is unjust and unreasonable.102

53. CSA requests rehearing based on Dr. Hogan’s testimony, arguing that the Final 

Rule will facilitate or mandate the exercise of buyer market power, including a buyers’ 

cartel, which will lead to artificially-suppressed prices.103 Petitioners assert that the Final 

Rule will facilitate buyer market power, artificially reducing prices below competitive 

levels. 

2. Commission Determination

a. LMP Compensation

54. The Commission denies the requests for rehearing and affirms its finding that 

LMP is the appropriate compensation level for demand response resources for service 

 

CSA Request for Rehearing at 73 (citing Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 50, 59). 

101 CSA Request for Rehearing at 54. 

102 Electric Power Supply Association, American Public Power Association, 

Electric Power Generation Association, and National Rural Electric Cooperative 

Association (collectively, Joint Petitioners) Request for Rehearing at 8; Midwest TDUs 

Request for Rehearing at 11; PPL Parties Request for Rehearing at 11; EEI Request for 

Rehearing at 7; P3 Request for Rehearing at 12-13. 

103 CSA Request for Rehearing at 57-58. 
Docket No. RM10-17-001 - 23 - 

provided in the organized wholesale energy markets when these resources have the 

capability to balance supply and demand as an alternative to generation and when 

dispatch of demand response is cost-effective as determined by the net-benefits test 

described in the Final Rule. The Commission continues to find, as explained in the Final 

Rule, that LMP is the appropriate compensation level when the aforementioned two 

conditions are satisfied because LMP reflects the marginal value of demand response 

resources and generation resources to each RTO and ISO.104 The rehearing requests 

generally reiterate arguments that were considered in the Final Rule and, for the reasons 

stated therein, are rejected here. 

55. As the requests for rehearing indicate, there continue to be diverging opinions, 

including among noted experts, regarding the appropriate level of compensation for 

demand response resources participating in the organized wholesale energy markets. In 

the face of diverging opinions, the Commission in the Final Rule observed that, as the 

courts have recognized, “issues of rate design are fairly technical and, insofar as they are 

not technical, involve policy judgments that lie at the core of the regulatory mission.”105 

The Commission also observed that, in making such judgments, it takes into account both 

the economic analysis of the markets subject to our jurisdiction, and the practical realities 

of how those markets operate.106 With this framework in mind, the Commission on 

balance agreed with commenters that supported payment of LMP under conditions when 

it is cost-effective to do so, as determined by the net benefits test described in the Final 

Rule. 

56. Petitioners argue on rehearing that demand response is not comparable to 

generation and contend that a number of differences justify paying demand response 

resources a different price than the market clearing price. We disagree. As the 

Commission explained in the Final Rule, a power system must be operated so that there is 

real-time balance of generation and load, supply and demand. When balancing supply 

and demand, an RTO or ISO therefore can rely on the dispatch of a generation resource 

to increase supply or a demand response resource to decrease demand.107 Petitioners 

nonetheless argue that demand response resources are not physically comparable to 

 104 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 47. 

105 Id. P 46 (citing Elec. Consumer Res. Council v. FERC, 407 F.3d 1232, 1236 

(D.C. Cir. 2005); Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992)). 

106 Id. (citing Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 872 (D.C. Cir. 1993); 

Vermont Dep’t of Pub. Serv. v. FERC, 817 F.2d 127, 135 (D.C. Cir. 1987); Columbia 

Gas Transmission Corp. v. FERC, 750 F.2d 105, 112 (D.C. Cir. 1984)). 

107 Id. P 49. 
Docket No. RM10-17-001 - 24 - 

generation because they do not produce electricity and cannot serve load. While we 

agree that demand response resources do not create electricity that can be used to serve 

load, that fact is not dispositive here. The electric industry requires near instantaneous 

balancing of supply and demand at all times to maintain reliability, and it is in that 

context that the Commission found that demand response can balance supply and demand 

as can generation when dispatched in the organized wholesale energy markets.108 

Because the balancing of generation and load when clearing the RTO and ISO day-ahead 

and real-time energy markets can be accomplished by changes in either supply or 

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

market should receive the same market-clearing LMP as compensation in the organized 

wholesale energy markets when those resources meet the conditions established in the 

Final Rule as a cost-effective alternative to the next highest-bid generation resources for 

purposes of balancing the energy market.109

57. Petitioners also argue that demand response and generation do not have the same 

marginal value because demand response has less stringent performance requirements. In 

Order No. 719, the Commission refrained from assigning a strict definition to 

comparability; nevertheless, the Commission required that demand response resources 

be: (1) “technically capable of providing the ancillary service and meet the necessary 

technical requirements; and (2) submit a bid under the generally-applicable bidding rules 

. . . .”110 Thus the Commission linked comparability to the technical capability of a 

demand response resource to provide a particular service, not to whether the performance 

requirements of a demand response resource are identical to a generation resource. While 

demand response and generation may not be identical resources in every respect, both 

types of resources are equally able to assist RTOs and ISOs in maintaining a balance 

between supply and demand when they meet an RTO’s or ISO’s requirements to deliver 

their product or service when and where needed on the margin. Commenters have not 

demonstrated that the differences between generation and demand response render one 

superior to the other for purposes of balancing the system. 

58. Petitioners further argue that the Final Rule’s requirement to pay LMP 

compensation is a subsidy, double payment, or overcompensation, provided to demand 

response resources. Petitioners contend that paying LMP, rather than LMP-G, leads to 

distorted price signals and thus causes some customers to reduce energy usage to belowoptimal levels, or others to increase usage to above-optimal levels. In the Final Rule, the 

Commission rejected these arguments and explained that demand response resources 

 108 Id. P 56. 

109 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 54. 

110 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 47. 
Docket No. RM10-17-001 - 25 - 

participating in the organized wholesale energy markets can be cost-effective, as 

determined by the net benefits test described therein, for balancing supply and demand 

and, in those circumstances, it follows that the demand response resource should also 

receive compensation at LMP.111 Moreover, petitioners’ arguments fail to acknowledge 

the market imperfections caused by the existing barriers to demand response discussed in 

the Final Rule and again below. In Order No. 719, the Commission found that allowing 

demand response to bid into organized wholesale energy markets “expands the amount of 

resources available to the market, increases competition, helps reduce prices to 

consumers and enhances reliability.”112 Moreover, as Dr. Kahn noted in this proceeding, 

paying demand response LMP sets “up an arrangement that treats proffered reductions in 

demand on a competitive par with positive supplies; but the one is no more a [case of 

overcompensation] than the other: the one delivers electric power to users at marginal 

costs – the other – reductions in costs – both at competitively determined levels.”113 

59. Petitioners challenge the Commission’s consideration of market imperfections 

caused by existing barriers to demand response as relevant to the level of appropriate 

compensation for demand response resources participating in the organized wholesale 

energy markets. We continue to find that the barriers to demand participation in the 

wholesale market, such as the lack of a direct connection between wholesale and retail 

prices, lack of dynamic retail prices (retail prices that vary with changes in marginal 

wholesale costs), lack of real-time information sharing, and the relative lack of sufficient 

retail metering technology,114 demonstrate that customers do not have the ability to 

respond to the often volatile price changes in the wholesale market and demonstrate the 

need for including demand response as part of wholesale market design. If the price 

responsiveness of demand is not fully reflected in the wholesale market, the price, a 

fortiori, will be higher than it would be in a competitive market.115 To establish just and 

 111 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 61. 

112 Id. (citing Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154). 

113 Id. (citing DR Supporters August 30, 2010 Reply Comments (Kahn Affidavit 

at 9-10)). 

114 Id. P 57. See also Monitoring Analytics, The Independent Market Monitor for 

PJM, Comments, Docket No. RM10-17-000, at 4-6 (filed May 13, 2010); Monitoring 

Analytics, Barriers to Demand Side Response in PJM, Docket No. ER09-1063-000 (filed 

July 1, 2009); Federal Energy Regulatory Commission Staff, A National Assessment of 

Demand Response Potential (June 2009), found at http://www.ferc.gov/legal/staffreports/06-09-demand-response.pdf). 

115 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 59. 
Docket No. RM10-17-001 - 26 - 

reasonable prices under such circumstances, we find that the demand response that can 

participate in the wholesale market should be paid the marginal value of its contribution. 

60. Some petitioners argue that the Commission improperly relied on a finding that 

insufficient demand response resources exist as a justification for paying LMP. The Final 

Rule was not based on a pre-determined assessment of the amount of demand response 

that is necessary in the market. Rather, given the barriers that clearly exist to full 

participation of demand in the wholesale market, the Commission determined that 

payment of LMP is appropriate as it represents the value of the contribution of demand to 

the market during those periods in which demand response provides net benefits. 

61. The Commission similarly rejects arguments made by CSA, EEI, Midwest ISO 

TOs, and Joint Parties stating that the Commission failed to explain how paying 

compensation at LMP will help reduce barriers. As indicated above, the existence of 

barriers helps to explain why payment of LMP as the market value of demand response 

services helps to produce just and reasonable wholesale energy prices. Paying LMP to 

demand resources will help address the lack of a direct connection between wholesale 

and retail prices and the lack of dynamic retail prices by providing those customers that 

can respond to price signals with the accurate market price signal for such response. 

Paying LMP, the marginal cost of energy, when demand response is a capable alternative 

to a generation resource, also will encourage more demand-side participation. As stated 

in the Final Rule, more demand-side participation will cause wholesale and retail prices 

to converge on a price level reflecting demand’s ability to respond to the marginal cost of 

energy.116

62. Lack of real-time information sharing and a lack of incentives to invest in enabling 

technologies can be addressed by making additional investment resources available to 

market participants.117 Paying the full marginal value of energy to demand response will 

provide the proper level of investment resources available for capital improvements. 

63. The Commission acknowledged that noted experts differed on whether paying 

LMP in the current circumstances facing the wholesale electric market is a reasonable 

price. In determining that LMP is the just and reasonable price to pay for demand 

response, the Commission examined some of the previously recognized barriers to 

demand response that exist in current wholesale markets. These barriers create an 

inelastic demand curve in the wholesale energy market that results in higher wholesale 

prices than would be observed if the demand side of the market were fully developed. 

The Commission found that paying LMP when cost-effective may help remove these 

 116 Id.

117 Id. P 57 (quoting EnerNOC May 13, 2010 Comments at 4). 
Docket No. RM10-17-001 - 27 - 

barriers to entry of potential demand response resources, and, thereby, help move prices 

closer to the levels that would result if all demand could respond to the marginal price of 

energy.118 Furthermore, the Commission found that since LMP reflects the marginal 

value of the demand response resource to the RTO or ISO, it is a just and reasonable rate 

to be paid to demand response resources. RTOs and ISOs already pay LMP 

compensation to generation resources because LMP represents their marginal value.119 

Thus, demand response resources, where capable of balancing supply and demand as an 

alternative to generation and when dispatch of demand response resources is costeffective, also should be compensated for the marginal value they provide. The 

Commission recognized that in some circumstances paying the LMP to demand response 

would not be cost-effective and therefore determined that payment of LMP in 

conjunction with a net benefits test will ensure a just and reasonable rate by resulting in 

the cost-effective dispatch of demand response resources. 

64. Dr. Kahn took note of these considerations in supporting the payment of LMP 

without reduction: 

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 user, 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 immediate response to such 

increases in true marginal costs of supplying them.120

Many of those seeking rehearing maintain that the only correct price to be paid load must 

reflect the savings load realizes from not having to purchase electricity. However, as the 

Commission found in the Final Rule, in circumstances in which the net benefits test is 

satisfied, paying LMP to demand response resources does not reflect a double payment; 

 118 Id. P 57-59 (recognizing factors unique to the electric industry, including the 

need for instantaneous balancing of supply and demand and that demand responsiveness 

to price changes is relatively inelastic). 

119 See DR Supporters August 30, 2010 Reply Comments (Kahn Affidavit at 2). 

120 DR Supporters September 16, 2009 Comments filed in Docket No. EL-09-68-

000 (Kahn Affidavit at 6). 
Docket No. RM10-17-001 - 28 - 

indeed, where cost effective, demand response resources should be paid the same price 

received by generation.121 

65. Moreover, the Commission pointed out, 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.122 The Commission has long held that payment of LMP to 

supply resources clearing in the day-ahead and real-time energy markets encourages 

more efficient supply and demand decisions in both the short run and long run, 

notwithstanding the particular costs of production of individual resources. 

66. EEI and CSA argue that the possibility that some demand resources that normally 

purchase energy needs from the RTO or ISO energy market may possess and run behindthe-meter generation in order to continue operation and still collect payments for demand 

response is a sufficient reason to avoid setting demand response compensation at LMP 

for all demand response. We do not agree that the existence of behind the meter 

generation or the potential manner in which behind the meter generation is treated by the 

RTOs and ISOs invalidates the payment of LMP. As discussed previously, in an RTO or 

ISO market, payment of LMP is the marginal value of a load reduction in the wholesale 

market and therefore is reasonable payment for such reduction. From the perspective of 

the grid, the manner in which a customer is able to produce such a load reduction from its 

validly established baseline (whether by shifting production, using internal generation, 

consuming less electricity, or other means) does not change the effect or value of the 

reduction to the wholesale grid.123 Details associated with the use and measurement of 

 

(continued...) 

121 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 61. 

122 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 62. In this regard, 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. See Viridity Comments, at 8 (“examples of those benefits 

include tax credits for kilowatt-hours produced by generators combusting municipal solid 

waste and other specified generators under Section 45(a) of the Internal Revenue Code 

(“IRC”), reductions in fuel costs for generators combusting refined coal due to tax credits 

under Section 45(e)(8) of the IRC, and the value of renewable energy certificates earned 

by eligible generators under state renewable portfolio standards”); September 13, 2010 

Tr. 67:3-14 (Mr. Peterson). 

123 The Final Rule required RTOs and ISOs to address measurement and 

verification issues in their compliance filings. Order No. 745, FERC Stats. & Regs. 

¶ 31,322 at P 94. Additionally, the Commission’s anti-manipulation regulation continues 
Docket No. RM10-17-001 - 29 - 

behind the meter generation to facilitate demand response are already part of some RTO 

and ISO tariffs, and any changes to such rules are properly considered either as part of 

the individual RTO and ISO compliance filings or separate section 205 or 206 filings, as 

appropriate. 

67. We reject the argument that suppression of the LMP will result in unjust and 

unreasonable prices for generation, causing delay in the construction of new generation 

while accelerating the retirement of current facilities. First, generation resources will not 

be subject to unfavorable treatment relative to demand response resources, because both 

types of resources will receive compensation at the LMP when the conditions of 

capability and cost-effectiveness are met. Demand response resource participation helps 

to balance supply and demand, helping to produce just and reasonable energy prices by 

lowering the amount of higher-cost generation dispatched to satisfy system demand.124 

Second, petitioners’ argument ignores the fact that demand response resources increase 

competition among supply-side resources in the context of balancing supply and demand. 

In other words, the Final Rule ensures that RTOs and ISOs treat demand response 

resources in a manner similar to a generation resource that is introduced into a pool of 

supply-side resources. Accordingly, the Final Rule treats demand response as an 

alternative to generation in the context of balancing supply and demand in the energy 

market. 

68. CSA’s argument that paying LMP to demand response when cost-effective will 

result in prices that are too low from the supply standpoint, and even violative of the Fifth 

Amendment, is unconvincing. As explained above, paying LMP reflects the marginal 

value of a resource’s contribution to the market, regardless of whether that resource 

provides generation or demand response. By ensuring that both types of resources, when 

dispatched, receive the same compensation for the same service, we expect the Final Rule 

to enhance the competitiveness of organized wholesale energy markets and result in just 

and reasonable rates in accordance with the Commission’s mandate under the FPA.125

 

(continued...) 

to prohibit fraudulent demand response schemes in which no genuine load reduction 

occurs. 18 C.F.R. § 1c (2011); see, e.g., North America Power Partners, 133 FERC 

¶ 61,089 (2010). 

124 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 10. 

125 The remedy for an alleged taking by the federal government lies in a suit 

brought in the United States Court of Federal Claims pursuant to the Tucker Act. 

28 U.S.C. § 1346(a)(2) (2006); see Wisconsin Valley Improvement Co. v. FERC, 236 

F.3d 738, 743 (D.C. Cir. 2001) (citing Transmission Access Policy Study Group v. FERC, 
Docket No. RM10-17-001 - 30 - 

69. CSA, EEI, and Joint Parties argue that the Commission erroneously relies on a 

presumption that compensation at LMP is the correct payment level. The Commission, 

as described in the Final Rule, did not simply presume that LMP is the correct level. As 

detailed in the Final Rule, the Commission carefully considered the effects of demand 

response resources on the energy market and found that LMP is warranted when demand 

response resources can balance supply and demand and are determined to be costeffective. Under these conditions—that are reasonably tailored to address the capabilities 

and effects of demand response—demand response resources should be paid the marginal 

value of energy. 

70. While Midwest ISO TOs and Joint Parties dispute whether calculating LMP-G 

would impose an administrative burden on RTOs and ISOs, the Commission’s 

determination in the Final Rule did not rest primarily on the imposition of such a burden 

and thus their arguments do not supplant the primary reasoning upon which the Final 

Rule is based. 

b. Effect on Retail Demand Response Programs

71. CSA and EEI argue that the Final Rule may have a detrimental effect on retaillevel reforms, such as price-responsive demand programs. As stated in the Final Rule, 

the pricing reform adopted is directed at demand response participation in organized 

wholesale energy markets and aims to ensure that rates in those markets are just and 

reasonable. The Final Rule 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 markets can and do operate 

simultaneously with retail-level programs, and each can inform the design of the other. 

As stated in the Final Rule, the Commission “is not regulating retail rates or usurping or 

impeding state regulatory efforts concerning demand response.”126 The effect, if any, 

experienced by a retail-level program is incidental to the reforms adopted in the Final 

Rule. 

c. Need for a Uniform Requirement

72. Several petitioners argue that the Commission failed to justify why a uniform rule 

for demand response compensation is needed. This argument is a corollary to the 

argument that the Commission did not satisfy the requirements of section 206 of the FPA 

 

225 F.3d 667, 690 (D.C. Cir. 2000); Railway Labor Executives’ Ass’n v. United States, 

987 F.2d 806, 815-16 (D.C. Cir. 1993) (citing Williamson County Regional Planning 

Comm’n v. Hamilton Bank, 473 U.S. 172, 195 (1985))). 

126 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 114. 
Docket No. RM10-17-001 - 31 - 

because it failed to make a finding that current demand response compensation is unjust 

and unreasonable. Therefore, we address them together. 

73. The Commission complied with the requirements of section 206. The 

Commission, on its own motion, initiated the section 206 action that resulted in the Final 

Rule. In the Final Rule, we found that: 

[W]hen a demand response resource has the capability to 

balance supply and demand as an alternative to a generation 

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 compensation other than the LMP is 

unjust and unreasonable.127

As explained in the Final Rule and affirmed above, LMP represents the marginal value of 

an increase in supply or a reduction in consumption at each node within an RTO or ISO, 

i.e., LMP reflects the marginal value of the last unit of resources necessary to balance 

supply and demand. LMP has therefore been the primary mechanism for compensating 

generation resources clearing in the organized wholesale energy markets since their 

formation.128 As a result, we continue to believe that requiring all RTOs and ISOs to pay 

demand response resources the LMP under the conditions set forth in the Final Rule is 

appropriate to ensure that those resources are compensated in a manner that reflects the 

marginal value of those resources to the RTO or ISO. 

74. Petitioners state that the Commission, up to this point, evaluated RTO and ISO 

demand response programs on an individual basis and without reference to a standardized 

compensation level. We disagree. Order No. 719 was clear that demand response 

resources participating in competitive ancillary service markets would receive the market 

clearing price.129 Petitioners state that the Final Rule is a departure from past 

Commission practice of encouraging regional variations in RTO and ISO market design. 

Petitioners cite Order No. 719 as an example of the Commission’s support for regional 

variation, where it directed RTOs and ISOs to work with their stakeholders to address 

issues involving ancillary services markets. Again, we disagree. In Order No. 719, the 

Commission recognized the need for RTOs and ISOs to ensure that the technical 

requirements of allowing demand response resources to offer into the ancillary services 

 127 Id. P 47. 

128 Id. P 120. 

129 Order No. 719, FERC Stats. & Regs. ¶ 31,281 P 47. 
Docket No. RM10-17-001 - 32 - 

markets required each RTO and ISO to examine this question from their own unique 

perspective, given the differences in markets, but still required comparable pricing 

between demand response and other resources.130 The Commission acknowledged in the 

Final Rule that it previously accepted a variety of RTO and ISO proposals for 

compensation for demand response resources participating in organized wholesale energy 

markets.131 Nonetheless, based on the record of the proceeding, and balancing the 

diverging opinions of noted experts, the Commission determined it was necessary in this 

instance to adopt a uniform compensation rule for demand response resources 

participating in the organized wholesale energy markets under the conditions set forth in 

the Final Rule. We are not convinced by petitioners that this decision was in error. 

Indeed, our action here is consistent with Order No. 719 that determined RTOs and ISOs 

must pay the market clearing price to all accepted bids in ancillary services markets. 

75. Moreover, the Final Rule allows RTOs and ISOs to exercise discretion with 

respect to their demand response programs, while balancing the level of prescriptive 

detail. For example, the Final Rule recognizes that there will be “inherent differences” in 

the supply curves determined by each RTO or ISO under the net benefits test, and thus 

varying threshold prices among RTOs and ISOs, attributable to each region’s unique 

supply data, mathematical methods, generation mix, local generation heat rates, and fuel 

price indices.132 The Final Rule also recognized that RTOs and ISOs may have different 

cost allocation and measurement and verification programs. Each of these elements can 

be addressed on an individual basis through the RTO and ISO compliance filings. 

d. Effect on Market Power

76. CSA argues that the Final Rule seeks to justify the payment of LMP on the ground 

that current generator market power mitigation rules are inadequate but failed to make a 

finding that existing market power mitigation rules indeed are inadequate. CSA also 

cautions that over-mitigation of market power is as harmful as under-mitigation. 

77. CSA, however, misinterprets the Commission’s reference in the Final Rule to 

generator market power and the effect of demand response resources on it. The Final 

Rule states that “[r]emoving barriers to demand response will lead to increased levels of 

investment in and thereby participation of demand response resources (and help limit 

potential generator market power), moving prices closer to the levels that would result if 

 130 Order No. 719, FERC Stats. & Regs. ¶ 31,281 see, e.g., P 59. 

131 Id. P 47. 

132 Id. n.160. 
Docket No. RM10-17-001 - 33 - 

all demand could respond to the marginal cost of energy.”133 The Commission 

emphasized that it sought to facilitate greater competition, with the markets themselves 

determining the appropriate mix of resources needed by the RTO and ISO to balance 

supply and demand based on relative bids in the energy markets.134 The Final Rule does 

not make a finding that existing generator market power mitigation rules are inadequate, 

nor was that issue the subject of the rulemaking. The reference to market power was to 

illustrate the general principle that the greater competition in the market helps to limit 

potential opportunities for the exercise of market power. 

78. CSA further argues that the Final Rule facilitates the exercise of buyer market 

power. The Final Rule addresses arguments concerning a buyers’ cartel and cooperative 

price setting, finding that the requirements of the Final Rule do not convert the unit 

commitment process into collusion among bidders, whether generation or demand 

response.135 CSA has not shown how buyers could in any way collude in setting bids or 

prices under the Final Rule. Moreover, the market rules implementing the requirements 

of the Final Rule must be approved by the Commission and demand response resources 

will be subject to those Commission-approved rules, just like any other participant in the 

organized wholesale energy markets. 

e. Costs of Generation Resources

79. Midwest ISO TOs and Joint Parties argue that the Commission erred when it 

refused to account for the costs incurred by generator resources to produce electricity. 

They argue that because generator resources incur costs for fuel, plant operation, etc., 

when generating electricity, that they are entitled to LMP compensation. In contrast, they 

claim that because a demand response resource incurs no costs associated with providing 

its service to an RTO or ISO, that it should receive LMP-G compensation. Again we 

disagree. 

80. As explained in the Final Rule, in the absence of market power concerns the 

Commission does not inquire into the costs or benefits of production for the individual 

resources, either generation or demand response resources, participating as supply 

resources in the organized wholesale energy markets.136 Just as the Commission found 

with regard to arguments made in response to the NOPR, we conclude that petitioners 

 133 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 59. 

134 Id.

135 Id. P 65. 

136 Id. P 62. 
Docket No. RM10-17-001 - 34 - 

have failed to justify why it would be appropriate for the Commission to continue to pay 

generation resources in a manner that reflects the marginal value of the service provided 

yet depart from this approach for demand response resources. 

C. Net Benefits Test and Determination of the Threshold Price Level

81. In the Final Rule, the Commission found that when a demand response resource 

participating in an organized wholesale energy market administered by an RTO or ISO 

has the capability to balance supply and demand as an alternative to a generation resource 

and when dispatch of that demand response resource is cost-effective as determined by 

the net benefits test, that demand response resource must be compensated for the service 

it provides to the energy market at the LMP. 

82. The Commission stated that the cost-effectiveness condition, as determined by the 

net benefits test, recognizes that, depending on the change in LMP relative to the size of 

the energy market, dispatching demand response resources may result in an increased 

cost per unit ($/MWh) to the remaining wholesale load associated with the decreased 

amount of load paying the bill. This is because the use of demand resources produces 

both effects, a reduction in the use of generation and a reduction in load.137 We refer to 

this potential result as the billing unit effect of dispatching demand response. By 

contrast, generation resources do not produce this billing unit effect because they do not 

result in a decrease of billing determinants. To address this billing unit effect, the 

Commission in the Final Rule requires the use of the net benefits test to ensure that the 

overall benefit of reduced LMPs that result from dispatching demand response resources 

exceeds the cost of dispatching and paying LMP to those resources. When the net 

benefits test is satisfied, and the demand response resource clears in the RTO’s or ISO’s 

economic dispatch, the demand response resource is a cost-effective alternative to 

generation resources for balancing supply and demand. 

83. To implement the net benefits test, the Commission directed RTOs and ISOs to 

make two compliance filings. First, each RTO and ISO is required to develop a 

mechanism as an approximation to determine a price level at which the dispatch of 

demand response resources 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 at which the overall 

benefit from the reduced LMP resulting from dispatching demand response resources 

exceeds the cost of dispatching and paying LMP to those resources. 

 137 If the replacement of generation does not produce a reduction in the LMP 

(price per unit) then the effective unit price to each remaining customer would go up 

because the same resource cost is now spread over fewer megawatt hours. 
Docket No. RM10-17-001 - 35 - 

84. Second, the Commission indicated that integrating a determination of the costeffectiveness of demand response resources into the dispatch of the RTOs and ISOs may 

be more precise than the monthly price threshold. The Commission required each ISO 

and RTO to conduct a study to determine whether the net benefits test could be integrated 

into its dispatch. Those studies are required to be filed by September 21, 2012. 

1. Requests for Rehearing

85. ICC asks whether the determination of the threshold price level should consider 

demand response resource offers individually, in aggregate, or by some other means. 

86. CAISO and P3 argue the Final Rule is arbitrary and capricious and fails to 

demonstrate reasoned decision making because the net benefits test, which RTOs and 

ISOs universally opposed, is, according to these petitioners, unworkable. The petitioners 

state that the Commission ignored significant amounts of record evidence in imposing the 

net benefits test. Joint Parties also argue that the Commission’s net benefits test does not 

resolve concerns that such a test would be difficult and costly to administer. Midwest 

TDUs similarly maintain a net benefits test that is too complicated to work. With respect 

to the integration of demand response into dispatch, Joint Parties quote Andy Ott of PJM 

Interconnection, L.L.C. (PJM) who, during the technical conference in this proceeding 

stated that, “an iterative process to look at impacts on market price, my opinion is that 

would be very costly and difficult to do, if we could even do it.”138 They further state 

that in requiring compliance filings for the monthly net benefits test, as well as the study 

of a dynamic process, the Commission did not consider or resolve whether the test is 

feasible for implementation or whether the cost and burden on RTOs and ISOs of 

complying with this aspect of the Final Rule is reasonable. They conclude that every 

indication from the record in this proceeding is that developing a net benefits 

methodology will be very difficult, if not impossible. 

87. CAISO argues that implementing the net benefits test results in similarly-situated 

resources being treated differently.139 For example, CAISO states that its tariff 

provisions governing demand response require that the same methodology be used to 

evaluate bids from both demand response resources and other supply resources. CAISO 

argues that the Final Rule requires CAISO to unduly discriminate against demand 

response resources because such resources must now pass the net benefits test. SWP 

similarly claims undue discrimination, contending that prior to the Final Rule, no market 

 138 September 13, 2010 Tr. 82:16-21 (Mr. Ott). 

139 CAISO Request for Rehearing at 38. 
Docket No. RM10-17-001 - 36 - 

participant offering in supply was required to make a showing that its offer is costeffective.140

88. CSA and Joint Parties maintain that the monthly net benefits test will not be 

sufficiently accurate to perform the function for which it was adopted. The petitioners 

cite to the Commission’s acknowledgement that the test may result in Type I and Type II 

errors,141 resulting in circumstances where demand response resources may be dispatched 

even though doing so is not cost-effective.142 

89. Midwest ISO TOs maintain the net benefits test adopted by Order No. 745 ignores 

the fact that demand response will provide different benefits to different customers in 

different locations, and therefore the Final Rule is arbitrary and capricious because, they 

argue, it ignores significant arguments raised in NOPR comments and fails to articulate a 

rational connection between the facts found and the decision made.143

90. Midwest TDUs state that the net benefits test will be biased because the “over 

compensation” required under the rule will result in shifting demand response from state 

programs to the federal program.144 As a result, they contend the shift from retail to 

wholesale demand response programs would drive up the baseline from which the net 

benefits test measures costs and benefits in the wholesale market. Specifically, they 

assert that the net benefits test will show consumer cost “savings” associated with the 

non-consumption behavior that consumers are already enjoying at a lower cost, thus 

raising total consumer bills. 

2. Commission Determination

91. We affirm our determination that a net benefits test is appropriate and workable. 

As the Commission explained in the Final Rule, dispatching demand response resources 

may result in an increased cost per unit to load associated with the decreased amount of 

load paying the bill (the billing unit effect), depending on the change in LMP relative to 

the size of the energy market. When reductions in LMP from implementing demand 

 140 California Department of Water Resources State Water Project (SWP) Request 

for Rehearing at 10. 

141 See Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 80. 

142 CSA Request for Rehearing at 63; Joint Parties Request for Rehearing at 23-24. 

143 Midwest ISO TOs Request for Rehearing at 26-27. 

144 Midwest TDUs Request for Rehearing at 19-20. 
Docket No. RM10-17-001 - 37 - 

response results in a reduction in the total amount consumers pay for resources that is 

greater than the money spent acquiring those demand response resources at LMP, such a 

payment 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.145 Therefore, we find no 

undue discrimination as alleged by CAISO, since there is a reasonable basis for paying 

demand response depending on whether it satisfies the net benefits test. When demand 

response produces a sufficient reduction in LMP to cover the increased billing costs 

imposed on remaining customers, it is beneficial to customers; when the reduction does 

not cover costs, the demand response is not beneficial. 

92. We also find that it is similarly reasonable to differentiate between demand 

response and generation as to this issue since only demand response produces the billing 

unit effect.146 As the Commission stated in the Final Rule, in the absence of the net 

benefits test, the RTO’s or ISO’s economic dispatch ordinarily would select demand 

response when it is the incremental resource with the lowest bid. However, if the 

avoided cost of the next unit of generation is not sufficient to offset the billing unit effect 

of the demand response resource, the decrease in LMP multiplied by the remaining load 

would not be greater than the costs of dispatching the demand response resource. In such 

a 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.147

93. We reject the arguments that the net benefits test we are requiring is unworkable. 

In the Final Rule, we provided an explanation of how to conduct that test. Indeed, five of 

the six RTOs and ISOs (including CAISO) have submitted compliance filings related to 

the calculation of the price threshold and the implementation of the net benefits tests, 

with what they assert are workable versions of the net benefits test, contrary to CAISO, 

 145 See Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 50. 

146 Undue discrimination does not exist when “a rational, non-discriminatory basis 

existed for the difference.” Consol. Edison Co. v. FERC, 165 F.3d 992, 1013 (D.C. Cir. 

1999); Bethany v. FERC, 727 F.2d 1131, 1139 (D.C. Cir. 1984) (the “mere fact of a rate 

disparity [between customers receiving the same service] does not establish unlawful rate 

discrimination” under the NGA, and that “rate differences may be justified and rendered 

lawful by facts – cost of service or otherwise”). 

147 See Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 52. 
Docket No. RM10-17-001 - 38 - 

P3, Joint Parties and Midwest TDUs’ assertions.148 The Commission will address 

implementation of the net benefits tests when it acts on those filings. 

94. CSA and Joint Parties maintain that the Commission cannot justify implementing 

the net benefits test when the Commission itself recognized that it is not perfectly 

accurate. We recognize that the test we are requiring may result in instances both when 

demand response is not paid the LMP but would have been cost-effective and when 

demand response is paid the LMP but is not cost-effective; however, we find that the test 

we are requiring is reasonably calculated to identify the hours in which it is reasonable to 

pay demand response LMP for participation in the day-ahead and real-time energy 

markets.149 As we acknowledged in the Final Rule, a more accurate method would be to 

include demand response, including the concomitant reduction in demand, as part of the 

RTO or ISO dispatch algorithm. However, it was not clear that RTOs and ISOs could 

implement the required changes to the dispatch algorithm, so as a practical 

accommodation we adopted a reasonable, and more easily administered mechanism for 

the net benefits test. 

95. We deny Midwest ISO TOs’ request for rehearing arguing that the net benefits test 

does not acknowledge the fact that demand response provides different benefits to 

different customers in different locations, and therefore the Final Rule is arbitrary and 

capricious. Midwest ISO TOs’ argument is raised here in the abstract, however, we have 

specific compliance filings before us that propose methods of determining the price 

threshold based on historical data in the RTOs. Midwest ISO TOs’ argument is more 

appropriate for the Midwest ISO Order No. 745 compliance filing, where we can 

 148 We note that Southwest Power Pool, Inc. (SPP) did not submit a net benefits 

test in its Order No. 745 compliance filing because it argues that its existing demand 

response program is consistent with or superior to the demand response programs 

required by Order No. 745, and does not require a net benefits test to determine the hours 

when to pay full LMP to demand response resources because it pays full LMP in all 

hours. We will address the merits of that argument in the order on compliance. 

Likewise, we also addressed CAISO’s, Midwest Independent Transmission System 

Operator, Inc’s (MISO), and PJM’s net benefits tests in their respective orders on 

compliance. See CAISO, 137 FERC ¶ 61,217 (2011); MISO, 137 FERC ¶ 61,212 (2011); 

PJM, 137 FERC ¶ 61,216 (2011). 

149 See Batavia v. FERC, 672 F.2d 64, 84 (D.C. Cir. 1982) (the billing design need 

only be reasonable, not theoretically perfect); North Carolina v. FERC, 112 F.3d 1175, 

1190 (D.C. Cir. 1997) (“An agency need not have perfect information . . . [it] need only 

explain the evidence which is available, and . . . offer a rational connection between the 

facts found and the choice made.” (internal quotation and citation omitted)). 
Docket No. RM10-17-001 - 39 - 

determine whether the net benefits test filed by the Midwest ISO appropriately measures 

the benefits of demand response. 

96. Midwest TDUs argue that demand response resources shifting from retail to 

wholesale demand response programs caused by “over compensation” would drive up the 

baseline from which the net benefits test measures costs and benefits in the wholesale 

market leading to phantom benefits. As discussed previously, we do not find that paying 

LMP is over compensation; rather, it fairly compensates demand resources at the 

marginal value of their contribution. The net benefits test determines whether paying 

demand response at the LMP is cost-effective. The Final Rule does not attempt to 

measure what would have happened in a retail program absent the wholesale program. 

Rather, it is focused on the net price effect of paying the demand response resources the 

LMP in the wholesale market. 

97. We believe ICC is asking whether the RTO or ISO is supposed to consider small 

changes (1 MW) changes or the full amount of demand response when it looks for the 

point where the price elasticity of supply is one. This issue is more appropriately raised 

in the individual compliance filings in which the RTOs sought to comply with the 

requirement. Additionally, we note that the Commission’s directive to smooth the 

representative supply curve,150 thus employing a calculus-based operation into the 

threshold determination which looks at very small movements along the supply curve 

when calculating the elasticity, addresses ICC’s concern. 

D. Cost Allocation

98. The Final Rule explained that when a demand response provider curtails, the RTO 

or ISO experiences a reduction in load with a corresponding reduction in billing units 

through which the RTO or ISO derives revenue (billing unit effect). When the two 

conditions described in the Final Rule are met, however, the RTO must pay LMP to both 

generators and demand response providers for the resources that clear the energy market. 

The difference between the amount owed by the RTO or ISO to resources, including 

demand response providers, and the revenue it derives from load results in a negative 

balance that must be addressed through cost allocation. Therefore, the Final Rule 

concluded that a method is needed to ensure that RTOs and ISOs recover the costs of 

obtaining demand response.151

99. The Final Rule requires each RTO and ISO to include in their compliance filing a 

proposed method of allocating the costs associated with demand response compensation 

 150 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at n.161. 

151 Id. P 99. 
Docket No. RM10-17-001 - 40 - 

proportionally to all entities that purchase from the relevant energy market in the area(s) 

where the demand response reduces the market price for energy at the time when the 

demand response resource is committed or dispatched.152

1. Requests for Rehearing

100. DR Supporters seeks clarification that the costs associated with demand response 

compensation include the costs of paying all resources LMP and the wholesale costs 

associated with deviations to the load of load serving entities (LSEs) who host demand 

response.153 DR Supporters argues that the reduction in load attributable to demand 

response shows up as a deviation in the load of the LSE who hosts the demand response. 

DR Supporters therefore requests that the Commission explicitly define the need to settle 

at wholesale for deviations to LSE load caused by demand response as a cost associated 

with demand response compensation.154

101. DR Supporters contends that LSEs scheduling load in the day-ahead market take 

on a binding settlement obligation for a specified amount of load, which is matched by an 

obligation to settle in real-time for deviations from load scheduled day-ahead.155 DR 

Supporters argues that when negative real-time deviations arise from the operation of 

demand response that was scheduled as a day-ahead resource, a settlement imbalance 

 152 Id. P 102. 

Since the dispatch of demand response resources affects the 

LMP charged, and will result in a lower LMP, the customers 

benefitting from that lower LMP depends upon transmission 

constraints, and the price separation such constraints cause 

within the RTO [or ISO]. In some hours in which 

transmission constraints do not exist, RTOs [and ISOs] 

establish a single LMP for their entire system (a single 

pricing area) in which case the demand response would result 

in a benefit to all customers on the system. When 

transmission constraints are present, however, LMPs often 

vary by zone, or other geographic [area]. 

Id. P 100. 

153 DR Supporters Request for Rehearing at 4-6, 10-11. 

154 Id. at 2. 

155 Id. at 4-5. 
Docket No. RM10-17-001 - 41 - 

results. According to DR Supporters, the ISO must collect enough money to not only pay 

all resources LMP, but also to settle for any negative real-time deviations caused by 

demand response scheduled day-ahead. DR Supporters argues that this collection is 

necessary to hold the LSE harmless and prevent the imposition of a penalty to LSEs 

whose customers engage in demand response.156

102. CSA requests clarification, or rehearing, that the Final Rule requires that costs 

associated with demand response compensation should be allocated to net purchasers 

(i.e., market participants whose net cleared demand exceeds their net cleared supply).157 

CSA asserts that it is indisputable that market participants that self-supply their energy 

needs do not benefit from lower LMPs resulting from dispatching demand response, and, 

as such, should not be allocated any demand response costs.158 CSA states that to 

allocate costs to an entity that does not benefit from demand response would be 

inconsistent with the reasoning in the Final Rule that costs associated with demand 

response compensation should be allocated among those who benefit from the resultant 

lower LMP. Furthermore, CSA argues that such cost allocation would also undermine 

the operation of the net benefits test by understating the billing unit effect by allocating 

costs to self-supply, which does not benefit from price decreases.159

103. A number of parties request rehearing based on assertions that the cost allocation 

method approved in the Final Rule does not adequately account for operational 

realities,160 is vague,161 or is too complicated to implement.162

104. Joint Parties request rehearing arguing that the Commission failed to clarify the 

cost allocation methodology. Joint Parties argue that the Final Rule does not define “all 

entities” as well as the “area(s)” subject to paying for the demand response compensation. 

Nor does the Final Rule, according to Joint Parties, explicitly state whether the areas for 

cost allocation must follow the designation of LMPs and thus is not sufficiently clear. 

 156 Id. at 5. 

157 CSA Request for Rehearing at 64. 

158 Id. at 65. 

159 Id. at 66. 

160 OMS Request for Rehearing at 7-8. 

161 Joint Parties Request for Rehearing at 26-27. 

162 EEI Request for Rehearing at 25. 
Docket No. RM10-17-001 - 42 - 

Joint Parties request that the Commission clarify that it will address these issues on a 

case-by-case basis in the compliance filing.163

105. OMS requests rehearing arguing that the Commission’s determination to allocate 

the costs of load reductions across an indefinite region is not just and reasonable because 

the approved cost allocation provides no incentive for LSEs to improve their rate 

structures and, furthermore, the Final Rule is not clear with respect to how the regions to 

which costs will be allocated will be determined.164 OMS argues the Final Rule does not 

describe how “relevant market area(s)” will be determined. OMS contends that by their 

very nature RTO energy markets are dynamic and the algorithms used to compute LMPs 

are complex. OMS believes it may be impossible to conduct an after-the-fact analysis to 

determine the effect of a load reduction on hundreds or thousands of pricing nodes in 

order to make a determination as to where and when nodal LMPs were affected by a load 

reduction.165

106. EEI contends that the cost allocation methodology fails to account for the 

complexities that can arise from transmission congestion by overlooking the reality that 

demand response can relieve congestion, thereby changing the boundaries of one or more 

transmission congested areas.166 EEI argues that the benefits to each wholesale buyer as 

a result of the demand response participation must be calculated through computer 

simulation of the counterfactual case of no demand response and compared with the 

actual case. EEI contends that allocating recovery of the demand response payments in 

proportion to wholesale buyers’ benefits will then be complex and cannot be 

accomplished through the methodology in the Final Rule.167 EEI reasserts its support for 

the bifurcated methodology168 for cost allocation that the Commission argued in the Final 

 163 Joint Parties Request for Rehearing at 27. 

164 OMS Request for Rehearing at 8. 

165 Id. at 7-8. 

166 EEI Request for Rehearing at 24-25. 

167 Id. at 25. 

168 Under a bifurcated methodology, a portion of the total cost is allocated to the 

load serving entity (LSE) that serves the demand response resource, while the balance is 

allocated to the remaining LSE(s) that serve the zone that harbors the demand response 

resource. See, e.g., PJM May 13, 2010 Comments at 12; ISO-NE May 13, 2010 

Comments at 5. 
Docket No. RM10-17-001 - 43 - 

Rule represented an arbitrary division of cost responsibility without regard to the degree 

to which each received benefits. 

107. Midwest TDUs request rehearing arguing that the Final Rule’s cost allocation 

requirement is very difficult and time-consuming because it will require RTOs and ISOs 

to estimate, on an ongoing basis, hypothetical LMPs that would have existed but for the 

participation of demand response resources in the organized wholesale energy market.169

108. ICC requests clarification that costs should be allocated according to the degree to 

which each load benefits from price reductions and not simply based on each benefiting 

load’s portion of total load. ICC argues that when a transmission constraint exists, a 

demand response resource may reduce the price in one pricing node, but not at another. 

Furthermore, ICC contends that the magnitude of the price decrease at two pricing nodes 

that experience a price decrease may be significantly different.170 Therefore, ICC argues 

that, in order to determine those entities that benefit from lower LMPs, the RTO or ISO 

must be able to identify which LMPs will be reduced when demand response 

participates.171 ICC states that in order to determine the pricing nodes at which LMPs are 

decreased, RTOs and ISOs need to simulate a scenario where demand response did not 

participate in order to determine the prices at each node under the assumption that 

demand response was not allowed to participate. The RTO or ISO could compare those 

prices to the actual prices to determine which pricing nodes actually benefited as a ratio 

of total benefits. 

109. Midwest ISO TOs request rehearing arguing that Order No. 745 contravenes the 

Commission’s cost causation policy that costs should be allocated to entities that cause or 

benefit from the incurrence of the costs.172 Midwest ISO TOs argue that the net benefits 

test established in the Final Rule ignores the fact that significant benefits of demand 

response are realized at the local or nodal level.173 Midwest ISO TOs argue that a 

market-wide net benefits test allocates costs equally to all market participants, 

notwithstanding the fact that market participants located in the same area as the demand 

response resource will realize a greater benefit from the reduction in LMP resulting from 

 169 Midwest TDUs Request for Rehearing at 14. 

170 ICC Request for Rehearing at 14. 

171 Id. at 15. 

172 Midwest ISO TOs Request for Rehearing at 27. 

173 Id.
Docket No. RM10-17-001 - 44 - 

the demand response resource’s participation in the energy market.174 Midwest ISO TOs 

assert that to the extent that the Final Rule ignores the locational impact that demand 

response has on different components of LMP and mandates allocation of costs based on 

a market-wide net benefits test, the Final Rule represents a lack of reasoned decisionmaking. Midwest ISO TOs request clarification that RTOs and ISOs can develop cost 

allocation mechanisms that consider the respective regional and localized benefits 

provided by deployment of demand response resources.175

110. EEI requests rehearing arguing that the cost allocation methodology required in 

the Final Rule produces cross-subsidies among wholesale buyers and thus violates the 

cost causation principle of assigning costs in proportion to benefits received.176 EEI 

further argues that the cost allocation methodology thwarts the ability of retail regulatory 

authorities to offset at the retail level what is, according to EEI, inefficient wholesale 

pricing because the cross-subsidies are broadly spread over LSE and retail jurisdictional 

boundaries.177 Furthermore, EEI states that the cross-subsidies created by the cost 

allocation methodology effectively disconnect LSE payments for purchased energy from 

the payments their respective retail customers enjoy by providing demand response.178

Thus, even if retail regulators could recapture the payments to these retail customers 

through retail rates, EEI believes doing so will not make their LSEs indifferent because 

of the cross-subsidies created by the Final Rule.179

2. Commission Determination

111. The Commission denies the requests for rehearing and affirms its finding that each 

RTO and ISO allocate the costs associated with demand response compensation 

proportionally to all entities that purchase from the relevant energy market in the area(s) 

where the demand response resource reduces the market price for energy at the time 

when the demand response resource is committed or dispatched. As the Commission 

explained in the Final Rule, when a demand response provider curtails, the RTO 

experiences a reduction in load with a corresponding reduction in billing units through 

 174 Id. at 28. 

175 Id.

176 EEI Request for Rehearing at 22. 

177 Id. at 23. 

178 Id. at 28. 

179 Id. at 29. 
Docket No. RM10-17-001 - 45 - 

which the RTO derives revenue.180 When the demand response resource has the 

capability to provide the service and when payment of the service is cost effective, 

however, the RTO must pay LMP to both generators and demand response providers for 

the resources that clear the energy market. The difference between the amount owed by 

the RTO to resources, including demand response providers, and the revenue it derives 

from load results in a negative balance that must be addressed through cost allocation. 

The Commission continues to find its cost allocation method just and reasonable as it will 

reasonably allocate the costs of demand response to those who benefit from the lower 

prices produced by dispatching demand response. 

112. We deny DR Supporters’ request for clarification as to whether the demand 

response costs to be allocated by the Final Rule should include costs associated with 

deviations from day-ahead market commitments made by an LSE that supplies energy to 

demand response providers, which it incurred as a result of serving those demand 

response providers. However, DR Supporters’ argument assumes that an LSE is 

obligated to procure its full load (without taking into account the reduction in load from 

demand response) thus leaving it with a potential deficiency that would carry over to the 

real-time market.181 

113. DR Supporters recognize that different RTOs and ISOs treat real-time settlement 

imbalances differently at present, where these imbalances may be positive or negative. 

Because of the differences in the way RTO’s or ISO’s operate their energy markets, we 

cannot resolve this issue on a generic basis. To the extent DR Supporters or other parties 

raise this issue in the compliance filings, we will address the issue on a case-by-case basis 

in the individual compliance proceedings. 

114. Petitioners also challenge the allocation of costs associated with compensation for 

demand response resources to market participants that primarily self-supply. The cost 

allocation methodology required in the Final Rule is based upon the benefits of demand 

response to wholesale load. As explained in the Final Rule, and under the principle of 

cost causation, purchasers are allocated the costs of demand response because they 

receive a benefit through the lower LMP that results from demand response resource 

participation in the organized wholesale energy markets.182 We reiterate here that cost 

allocation proposals must satisfy the cost causation principle. However, we find that the 

record in this proceeding is insufficient to resolve on a generic basis the issue of cost 

allocation to participants that self-supply. We further find that the issue is better 

 180 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 99. 

181 DR Supporters Request for Rehearing at 7-8. 

182 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 100. 
Docket No. RM10-17-001 - 46 - 

addressed in the individual RTO and ISO compliance proceedings, to the extent concerns 

have been raised there. We therefore deny the requests for rehearing on this issue. 

115. The Commission also denies OMS’ and Joint Parties’ requests for rehearing 

regarding clarification and definition of the terms “all entities” and the “area(s)” subject 

to paying for the demand response compensation. The cost allocation methodology 

required by the Final Rule was designed to allow sufficient flexibility for each individual 

RTO and ISO to determine, in consultation with their stakeholders, an appropriate cost 

allocation methodology that complies with the Final Rule.183 In this way, the 

Commission is allowing for regional variation in the determination of the “area(s)” in 

which market participants benefit from demand response participation based on the 

unique energy market design in each RTO and ISO. The Commission will analyze and 

evaluate each RTO’s and ISO’s proposed cost allocation methodology on a case-by-case 

basis in its compliance filing. 

116. We further deny EEI’s, OMS’, and Midwest TDUs’ requests for rehearing 

asserting that the cost allocation methodology prescribed in the Final Rule will be overly 

complex to implement. OMS argues that RTOs and ISOs will have to conduct after-thefact analysis to determine the effect of demand response on hundreds or thousands of 

pricing nodes. EEI and Midwest TDUs claim that RTOs and ISOs will have to calculate 

hypothetical counterfactual LMPs that would have occurred with no demand response 

participation in order to determine the benefits of demand response participation. 

117. The Final Rule requires no such specific actions on the part of RTOs and ISOs. 

The Final Rule allows each RTO and ISO to tailor its cost allocation methodology to the 

circumstances on its system.184 Any issues with respect to the allocation of costs 

resulting from these proposals, or the feasibility of conducting the analysis, can be raised 

on a case-by-case basis in the compliance filing proceedings. 

118. We deny ICC’s, Midwest ISO TOs’, and EEI’s rehearing requests relating to the 

proper allocation of costs as more appropriately addressed in the individual compliance 

filing proceedings. 

119. The Final Rule does not require, as ICC suggests, that RTOs and ISOs simulate a 

scenario to calculate what the prices at each node would have been if demand response 

had not participated in order to determine which pricing nodes actually benefited as a 

ratio of total benefits. Each RTO or ISO can propose a methodology that reasonably 

 183 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 102. 

184 Id.
Docket No. RM10-17-001 - 47 - 

allocates the costs of demand response, consistent with the requirements of the Final 

Rule. 185

120. Finally, we reject Midwest ISO TOs’ and EEI’s requests for rehearing arguing that 

the cost allocation methodology prescribed by the Final Rule violates the cost causation 

policy which requires that costs should be allocated to those entities that benefit from the 

incurrence of the costs. Contrary to Midwest ISO TOs’ and EEI’s assertions, the cost 

allocation methodology prescribed in the Final Rule does not prevent an RTO or ISO 

from accounting for the regional or local benefits provided by deploying demand 

response resources. As the Final Rule explained, in some hours in which transmission 

constraints do not exist, RTOs establish a single LMP for their entire system (a single 

pricing area) in which case the demand response would result in a benefit to all customers 

on the system. When transmission constraints are present, however, LMPs often vary by 

zone, or other geographic areas.186 The RTOs and ISOs need to look at their systems and 

determine what methodology best allocates cost to the customers benefitting from the 

lower LMP resulting from demand response. 

E. Measurement and Verification

121. In the Final Rule, the Commission agreed with commenters that measurement and 

verification are critical to the integrity and success of demand response programs but 

found that, because it was not requiring payment of LMP in all hours, but, rather, subject 

to a net benefits test, the Final Rule did not directly implicate measurement and 

verification issues. Nevertheless, the Commission noted the importance of baseline 

calculation methodologies and the measuring and verifying of demand response resource 

performance. Therefore, the Final Rule directed each RTO and ISO to review their 

current requirements in light of the changes required therein and develop appropriate 

revisions and modifications, if necessary, to ensure that their baselines remain accurate 

and that they can verify that demand response resources have performed. Each RTO and 

ISO was required to include as part of its compliance filing an explanation of how its 

measurement and verification protocols will continue to ensure that appropriate baselines 

are set, and that demand response will continue to be adequately measured and verified. 

Additionally, the Commission stated that each RTO and ISO should propose any changes 

necessary to ensure that their measurement and verification will adequately capture the 

performance or non-performance of each participating demand response resource, 

consistent with the Final Rule. 

 185 Id.

186 Id. P 100. 
Docket No. RM10-17-001 - 48 - 

1. Requests for Rehearing

122. CSA and Midwest TDUs request rehearing arguing that the Commission’s 

determination to adopt the Final Rule in the absence of measurement and verification 

standards capable of preventing gaming and manipulation is arbitrary and capricious. 

The petitioners argue that the Final Rule creates significant, and perhaps insurmountable, 

difficulties and costs for RTOs and ISOs in measuring customers’ demand reductions and 

verifying that they have reduced consumption in response to price signals. The 

petitioners assert that current measurement and verification standards are not capable of 

performing the functions they are intended to serve, in particular preventing 

manipulation. The petitioners further assert that evidence in the record unequivocally 

indicates that current North American Energy Standards Board (NAESB) standards and 

RTO and ISO rules cannot prevent fraud and abuse. The petitioners conclude that the 

Commission’s determination that RTOs and ISOs will be able to solve the problems 

created by the Final Rule regarding measurement and verification is arbitrary and 

capricious decision making. 

2. Commission Determination

123. We deny the requests for rehearing on this issue. Petitioners reiterate the same 

general concerns regarding deficits in the RTO and ISO demand response measurement 

and verification programs as they did in their comments to the NOPR. In response, the 

Commission in the Final Rule required RTOs and ISOs to evaluate their measurement 

and verification protocols taking into account the effect of the Final Rule’s directives and 

develop modifications as necessary, and include any such modifications in the required 

compliance filing. The Commission did not find that the compensation-related 

requirements of the Final Rule fundamentally changed the measurement and verification 

standards that the RTOs and ISOs have been using. Petitioners will have additional 

opportunities to address specific concerns about particular aspects of individual RTO or 

ISO measurement and verification programs in the compliance filing proceedings.187

F. Study Regarding the Dynamic Implementation of the Net Benefits Test 

into the Dispatch Algorithm

124. In the Final Rule, the Commission stated that it believed that integrating a 

determination of the cost-effectiveness of demand response resources into the dispatch of 

RTOs and ISOs may be more precise than the monthly price threshold and, therefore, 

 187 In addition, we note that petitioners may participate in the proceedings 

considering NAESB Phase II measurement and verification standards development. See

NAESB, Measurement and Verification of Demand Response Products Phase II Report, 

Docket No. RM05-5-020 (filed May 3, 2011). 
Docket No. RM10-17-001 - 49 - 

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. The 

Commission acknowledged the position 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, the Commission 

required each RTO and ISO to undertake a study examining the requirements for and 

impacts of implementing a dynamic 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 directed each RTO and ISO to file the results of this study with the 

Commission on or before September 21, 2012. 

1. Requests for Rehearing

125. ICC argues that, unlike in the case of the static model, in the dynamic model, 

demand-side bidders will not know whether their bids will be cost-effective when they 

place their bids. ICC states that bidders will have to include a risk premium to account 

for this uncertainty, which will lead to inefficient prices and levels of demand response 

resource participation in the RTO and ISO markets. Therefore, ICC asks the 

Commission to clarify that the dynamic cost-effectiveness model produces uncertainty 

regarding the offer level at which a demand response resource decides to submit its 

demand response. ICC also asks the Commission to clarify that this aspect of the 

dynamic model could have adverse impacts for the development of demand response in 

the RTO and ISO markets. 

126. Joint Parties argue that the Commission’s net benefits test does not resolve 

concerns that such a test would be difficult and costly to administer. Joint Parties cite to 

a statement by Andy Ott of PJM during the technical conference in this proceeding, “an 

iterative process to look at impacts on market price, my opinion is that would be very 

costly and difficult to do, if we could even do it.” They further state that in requiring 

compliance filings for the study of a dynamic process, the Commission does not consider 

or resolve whether the test is feasible for implementation or whether the cost and burden 

on RTOs and ISOs of complying with this aspect of the Final Rule is reasonable. They 

conclude that every indication from the record in this proceeding is that development of a 

net benefits methodology will be very difficult, if not impossible, to do. 

2. Commission Determination

127. ICC contends that the dynamic cost-effectiveness model will produce uncertainty 

regarding the level at which demand response resources will offer into the market, but the 

requirement in the Final Rule is simply that RTOs and ISOs make a compliance filing 

that includes the results of a study examining the requirements of, costs of, and impacts 

of implementing a dynamic cost-effectiveness model. The Commission does not expect 

that a demand response provider will know the magnitude of the billing unit effect 
Docket No. RM10-17-001 - 50 - 

associated with its demand reduction ex ante, but if it bids its marginal opportunity cost 

(as we would expect in a competitive market), it will only be called when it is in the 

demand response provider’s economic interest to reduce consumption. All resources, 

both supply side and demand side, face some degree of uncertainty as to whether they 

will be dispatched but if a resource bids its marginal opportunity cost it will not be 

dispatched unless it is in its economic interest. Furthermore, the Commission will not 

speculate, as ICC would have us do, as to the specific results that a dynamic costeffectiveness model may produce. The Final Rule required the study to permit a further 

comprehensive evaluation of the impacts associated with implementing a dynamic 

approach, therefore we find it appropriate to refrain from making findings in response to 

ICC’s assertions at this time. 

128. We reject Joint Parties argument that in requiring compliance filings for the study 

of a dynamic process, the Commission did not consider or resolve whether the test is 

feasible for implementation or whether the cost and burden on RTOs and ISOs of 

complying with this aspect of the Final Rule is reasonable. Further exploration of these 

issues is precisely the reason the Final Rule required a study rather than imposing this 

condition at this time.188 We are asking the RTOs and ISOs to study the feasibility and 

giving them sufficient time to do so; the RTOs and ISOs will assess the difficulty of 

implementing such a plan and report back to the Commission. The Commission can 

assess the feasibility of implementing a dynamic process in RTOs and ISOs after it 

receives the studies. 

G. Applicability of Order No. 745 to Circumstances When it is not CostEffective to Dispatch Demand Response Resources

129. In the Final Rule, the Commission stated that it was not requiring the 

compensation of full LMP when demand response resources do not satisfy the capability 

and cost-effectiveness conditions noted above.189 The Commission’s findings in the 

Final Rule do not preclude the Commission from determining that other approaches to 

compensation would be acceptable when these conditions are not met.190

1. Requests for Rehearing

130. ICC requests that the Commission clarify how the price threshold will work for a 

demand response resource that bids below the threshold. Specifically, ICC asks whether 

 188 See Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 84. 

189 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 3. 

190 Id. P 3 n.6. 
Docket No. RM10-17-001 - 51 - 

such a resource would be dispatched if the LMP were below the price threshold, but 

above the resource’s bid. If so, ICC asks how such a demand resource should be 

compensated. 

2. Commission Determination

131. As noted above, in Order No. 745 the Commission, acting pursuant to section 206 

of the FPA, required each RTO and ISO to revise its tariff to pay a demand response 

resource the market price for energy (i.e., the LMP) when two conditions are met. First, 

the demand response resource must have the capability to balance supply and demand as 

an alternative to a generation resource. Second, dispatch of the demand response 

resource must be cost-effective as determined by a net benefits test.191 We clarify that 

pursuant to this section 206 directive, each RTO and ISO must revise its tariff to provide 

that when the LMP is greater than or equal to the threshold price, all demand resources 

that qualify for compensation192 will receive the LMP payment. The Commission’s 

section 206 action in Order No. 745 did not extend, however, to situations where the 

LMP is not greater than or equal to the threshold price. Thus, if LMP is less than the 

threshold price, the Final Rule does not apply to determine the payment to a demand 

response resource, and any payment will be governed by the existing RTO or ISO tariff. 

H. Effect of Order No. 745 on CAISO’s Demand Response Programs

132. In the Final Rule, the Commission explained that the cost-effectiveness condition 

for dispatching and compensating demand response resources at the LMP, as determined 

by the net benefits test, recognizes that, depending on the change in LMP relative to the 

size of the energy market, dispatching demand response resources may result in an 

increased cost per unit ($/MWh) to the remaining wholesale load associated with the 

decreased amount of load paying the bill.193

133. The Commission further required each RTO and ISO to allocate the costs 

associated with demand response compensation proportionally to all entities that 

purchase from the relevant energy market in the area(s) where the demand response 

 191 See supra P 54. 

192 For example, a qualification may include a requirement that the demand 

response resource submit a successful supply offer, whether that successful bid is below, 

at or above the threshold price. 

193 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 3. 
Docket No. RM10-17-001 - 52 - 

reduces the market price for energy at the time when the demand response resource is 

committed or dispatched.194 

1. Requests for Rehearing

134. Rehearing requests were received on three basic issues: the California Proxy 

Demand Resource Product, Reliability Demand Response Resource Products, and its 

Participating Load Program. 

a. Proxy Demand Resource Product

135. CAISO and CPUC request clarification and rehearing that the Final Rule does not 

require any change to195 nor does it expressly or implicitly modify or overturn196 the 

default load adjustment feature of CAISO’s FERC-approved demand response tariff 

provisions.197 CAISO states that although the Final Rule contains no directives that 

squarely address the default load adjustment, or the wholesale double payment issue, it 

believes that the Final Rule could be read to indirectly require the elimination of it.198 

CAISO contends that the operation of the net benefits test, required in the Final Rule, 

appears to be inconsistent with the default load adjustment.199 The net benefits test, 

described in the Final Rule, considers whether demand response resources should receive 

full LMP, based on a consideration of overall decreased energy cost spread over the 

decreased metered load, but the default load adjustment function of CAISO’s existing 

market rules prevents a decrease in an LSE’s metered load due to a cleared Proxy 

Demand Resource bid. 

136. CAISO similarly requests clarification arguing that the provisions of the Final 

Rule relating to cost allocation could also be read as indirectly requiring elimination of 

the default load adjustment.200 CAISO argues that the cost allocation methodology for 

 194 Id. P 102. 

195 CAISO Request for Rehearing at 21. 

196 Public Utilities Commission of the State of California (CPUC) Request for 

Rehearing at 5. 

197 Cal. Indep. Sys. Operator Corp., 132 FERC ¶ 61,045 (2010). 

198 CAISO Request for Rehearing at 21-22. 

199 Id. at 21. 

200 Id. at 23. 
Docket No. RM10-17-001 - 53 - 

payments made to Proxy Demand Resources under the existing CAISO tariff satisfies and 

complies with the Commission’s directive in the Final Rule because LMP payments 

made to Proxy Demand Resources are allocated to the load that benefits, i.e., to all load 

day-ahead and to deviations in real-time.201

137. CAISO and the CPUC request rehearing arguing that the Final Rule does not 

include any factual or legal analysis as to why CAISO’s FERC-approved Proxy Demand 

Resource is no longer just and reasonable and thus FERC’s decision was arbitrary, 

capricious, and not the product of reasoned decision-making because FERC has failed to 

explain its inconsistency with its own precedent.202 

b. Reliability Demand Response Products

138. CAISO and CPUC seek clarification as to whether Reliability Demand Response 

Resources are subject to the requirements of the Final Rule.203 CAISO states that this 

product occupies a gray area under the definition of programs subject to the Final 

Rule.204 According to CAISO, Reliability Demand Response Resources will be 

participating in the day-ahead and real-time energy markets administered by CAISO 

pursuant to bids submitted for their energy.205 CAISO states that the product is built on 

the same platform as, and will have many similarities to, the Proxy Demand Reso

Product.

urce 

ity 

time. 

206 However, CAISO states that its proposed tariff provisions for Reliabil

Demand Response Resources will provide compensation for demand response providing 

reliability and emergency relief in real- 207

c. Participating Load Program

139. SWP seeks clarification or rehearing arguing that to the extent Order No. 745 

imposes a net benefits test on demand response from Participating Loads, the order fails 

to address SWP’s evidence and argument which it contends shows that a net benefits test 

 201 Id. at 23-24. 

202 CPUC Request for Rehearing at 10-11; CAISO Request for Rehearing at 26. 

203 CAISO Request for Rehearing at 32. 

204 Id. at 33. 

205 Id.

206 Id. at 15. 

207 Id. at 33. 
Docket No. RM10-17-001 - 54 - 

is not necessary for wholesale Participating Loads, which unlike retail demand response, 

do not use an administrative baseline against which curtailments are measured.208 SWP 

states that it requested an exemption from any net benefits test for wholesale demand 

response that, unlike retail demand response, is modeled as negative generation by 

CAISO, buys its baselines and is scheduled and settled at nodal LMP levels comparable 

to generation while retail load uses an averaged or zonal LMP.209 

2. Commission Determination

140. We find that we cannot assess these individual aspects of CAISO’s demand 

response program on rehearing in a Final Rule. Other parties need the opportunity to 

respond to these issues, which are best resolved in CAISO’s compliance and Reliability 

Demand Response Resource proceedings.210 These issues were raised by various parties 

in CAISO’s compliance and Reliability Demand Response Resource proceedings, and the 

Commission will respond appropriately in those proceedings. Under the exercise of the 

Commission’s authority under section 206 of the FPA, the Commission determined that 

any energy market demand response program is unjust and unreasonable if it does not 

pay LMP to demand resources when a net benefits test is satisfied and does not allocate 

costs appropriately to those parties that benefit from the reduction in LMP occasioned by 

the demand response. As discussed above, we had an adequate basis for making these 

determinations on a generic basis. 

141. Whether the current contours of CAISO’s demand response program meets these 

criteria can be determined only upon review of CAISO’s compliance filing and the full 

record developed in that proceeding. For example, the Final Rule required that RTOs and 

ISOs allocate the costs of demand response to those parties that benefit from the 

reduction in LMP. We cannot determine on this record whether the existing cost 

allocation in the CAISO market meets these criteria. We similarly cannot determine 

whether CAISO’s Reliability Demand Response Resource program or its wholesale 

Participating Load Program is covered by the Final Rule without the full record 

developed in the compliance filing and Reliability Demand Response Resource 

proceedings. 

 208 SWP Request for Rehearing at 4. 

209 SWP Request for Rehearing at 5; see also SWP October 13, 2010 Comments 

at 2-3. 

210 CAISO’s Reliability Demand Response Resource proposal is pending before 

the Commission in Docket Nos. ER11-3616-000 and 001. 
Docket No. RM10-17-001 - 55 - 

I. Compliance with the Regulatory Flexibility Act

142. The Regulatory Flexibility Act of 1980211 (RFA) generally requires an 

administrative agency to perform an analysis of rulemakings that will have a significant 

economic impact on a substantial number of small entities. The RFA mandates 

consideration of regulatory alternatives that accomplish the stated objectives of a 

proposed rulemaking while minimizing any significant economic impact on a substantial 

number of small entities. The Small Business Administration’s (SBA) Office of Size 

Standards develops the numerical definition of a small business.212 The SBA has 

established a size standard for electrical utilities, stating that a firm is small if, including 

its affiliates, it is primarily engaged in the transmission, generation, and/or distribution of 

electric energy for sale and its total electric output for the preceding twelve months did 

not exceed four million MWh.213

143. In the Final Rule, the Commission noted that the regulations promulgated in the 

Final Rule directly impact only RTOs and ISOs. Because RTOs and ISOs are not small 

entities as defined by the SBA, the Commission certified that the Final Rule would not 

have a significant economic impact on a substantial number of small entities. 

144. Competitive Power Supplier Associations, PPL Parties, and P3 all assert that the 

Final Rule will, contrary to the Commission’s assessment, have an impact on small 

entities as defined by the SBA. The petitioners assert that the Final Rule will affect small 

generators, marketers, LSEs, and demand response providers. The petitioners state that 

the Commission failed to recognize, simply ignored, or did not support its conclusion 

regarding the impacts that the Final Rule would have on small entities.214 

145. The only entities subject to the requirements of the Final Rule are the RTOs and 

ISOs, which as demonstrated in the Final Rule are not classified as small entities.215 

Furthermore, courts have held that the RFA does not require an agency to perform a 

regulatory flexibility analysis of impacts on small entities when a rule only indirectly 

 211 5 U.S.C. §§ 601-612. 

212 13 C.F.R. § 121.101 (2011). 

213 13 C.F.R. § 121.201, Sector 22 Utilities & n.1. 

214 Competitive Power Supplier Associations Request for Rehearing at 81; PPL 

Parties Request for Rehearing at 22; P3 Request for Rehearing at 16. 

215 Order No. 745, FERC Stats. & Regs. ¶ 31,322 at P 122-28. 
Docket No. RM10-17-001 - 56 - 

impacts them.216 In the context of the organized wholesale energy markets, any effects 

on other entities, such as generators or marketers, are indirect and are the result of 

competition in the energy market. 

The Commission orders: 

 (A) The requests for rehearing are hereby denied, as discussed in the body of 

this order. 

 (B) The requests for clarification are hereby granted in part, and denied in part, 

as discussed in the body of this order. 

By the Commission. Commissioner Moeller is dissenting with a separate statement 

 attached. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

 216 Indirect effects do not fall within the ambit of the RFA. Am. Trucking Ass’ns 

v. EPA, 175 F.3d 1027, 1044 (D.C. Cir. 1999), aff’d in part and rev’d in part on other 

grounds, Whitman v. Am. Trucking Ass’ns, 531 U.S. 457 (2001); Mid-Tex Elec. Coop. 

v. FERC, 773 F.2d 327, 342-43 (D.C. Cir. 1985) (“Congress did not intend to require that 

every agency consider every indirect effect that any regulation might have on small 

businesses in any stratum of the national economy.”). 
Docket No. RM10-17-001 - 57 - 

APPENDIX 

List of Petitioners 

Abbreviation Petitioner 

CAISO California Independent System Operator 

Corporation 

Competitive Power Suppliers (CSA) Electric Power Supply Association 

Independent Power Producers of New York, Inc.

Electric Power Generation Association 

New England Power Generators Association, 

Inc. 

CPUC Public Utilities Commission of the State of 

California 

DR Supporters Demand Response Supporters (members include 

American Forest & Paper Association, 

Consumer Demand Response Initiative, 

EnerNOC, Inc., Project for Sustainable FERC 

Energy Policy, and Viridity Energy, Inc.) 

EEI Edison Electric Institute 

ICC Illinois Commerce Commission 

Joint Parties American Public Power Association 

National Rural Electric Cooperative Association 

Old Dominion Electric Cooperative 

Joint Petitioners Electric Power Supply Association 

American Public Power Association 

Electric Power Generation Association 

National Rural Electric Cooperative Association 

Midwest ISO TOs Midwest ISO Transmission Owners 

Midwest TDUs Midwest Transmission Dependent Utilities 

OMS Organization of MISO States 
Docket No. RM10-17-001 - 58 - 

P3 PJM Power Providers Group 

PPL Parties PPL Parties 

SWP California Department of Water Resources State 

Water Project 

Parties Filing Answers 

Abbreviation Petitioner 

IECG Industrial Energy Consumer Group 

ISO-NE ISO New England Inc. 

NEPOOL Participants Committee New England Power Pool Participants 

Committee 

Occidental Occidental Permian Ltd. 

Occidental Chemical Corporation 

Viridity Viridity Energy, Inc. 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

 

Demand Response Compensation in Docket No. RM10-17-001 

Organized Wholesale Energy Markets 

 (Issued December 15, 2011) 

 

MOELLER, Commissioner, dissenting: 

Demand response plays a very important role in markets by providing significant 

economic, reliability, and other market-related benefits when properly deployed. 

However, it has become clear since the issuance of Order No. 745 that my earlier 

concerns in this proceeding were justified.1

 Namely, rather than impose a nationwide 

approach to demand response compensation, the Commission’s objective of promoting 

demand response would have been better served if the regions were free to propose 

compensation methods that recognize the very real differences in the structures of the 

regional markets. In addition, the evidence now shows that the Net Benefits Test will be 

so costly to develop and so difficult to administer that it can be expected to result in an 

allocation of the costs of demand response to the parties that do not benefit from demand 

response.2

 Therefore, rather than continuing to pursue demand response compensation at 

full LMP only when the Net Benefits Test is passed, I would have changed that decision 

and put in its place compensation at LMP – G, where “G” is the avoided retail cost of 

generation. 

While consumers may pay lower rates if some consumers voluntarily agree to use 

less electricity, the Federal Power Act requires this Commission to establish just and 

 1 Demand Response Compensation in Organized Wholesale Energy Markets, 134 

FERC ¶ 61,187 (2011) (Moeller Dissenting) (“Order No. 745”). 

2 See e.g., Requests for Rehearing, PJM Power Providers Group (P3) at 12; 

Organization of MISO States (OMS) at 4; California Department of Water Resources 

State Water Project (SWP) at 4 – 7; Old Dominion Electric Cooperative (ODEC), 

American Public Power Association (APPA), National Rural Electric Cooperative 

Association (NRECA) at 23 – 25; PPL Parties at 15 – 16. 
Docket No. RM10-17-001 - 2 -

reasonable rates that are not discriminatory.3

 If the Commission requires the RTOs 

and ISOs to overcompensate for providing demand response, the resulting rates are both 

discriminatory and not just and reasonable. 

The Case Has Not Been Made 

 Both the Final Rule and the current rehearing order fail to justify the imposition of 

a national standard for demand response compensation. Rather than address the 

legitimate concerns that were raised in this proceeding4

 about (1) the difficulties with 

implementing this rule and (2) the disruptions to existing demand response programs, this 

order simply refers to the individual RTO and ISO compliance proceedings --- as if these 

problems were not fundamental to the viability of the rule. 

 As I recognized in my earlier dissent in this proceeding, organized markets have 

already demonstrated that they can develop demand response compensation rules. RTOs 

and ISOs have been working with their market participants through stakeholder processes 

to design demand response compensation rules that are tailored to suit the needs of their 

individual energy markets. I would have allowed these efforts to continue. However, 

despite warnings about disruptions from some parties,5

 the majority is proceeding with 

generic rules that may actually discourage demand response products. 

 Furthermore, I would have accepted the Motion to Lodge submitted by CAISO6

and do not believe that sufficient rationale was given for denying the motion in this 

proceeding.7

 The majority claims the request was made out-of-time, despite CAISO’s 

internal procedures that require draft opinions to be posted before they are finalized. The 

motion by CAISO and its Market Surveillance Committee illustrates many of the 

difficulties stakeholders are having with their efforts to comply with this rule. By 

 3

 16 U.S.C. § 824d (2006). 

4 See e.g., Requests for Rehearing, Midwest ISO Transmission Owners at 3; 

CAISO at 1 – 2; Edison Electric Institute (EEI) at 3; Competitive Power Supplier 

Associations (CSA) at 3; ODEC, APPA, NRECA at 5 – 11. 

5 See California Independent System Operator Corporation (CAISO), Request for 

Rehearing, April 14, 2011 at 5, 29. See also Affidavit of Peter Scala on behalf of the 

California Public Utilities Commission (CPUC). 

6

 CAISO, Motion to Lodge, June 17, 2011 and Errata, June 22, 2011. 

7

 Order No. 745-A at P 9 – 10. 
Docket No. RM10-17-001 - 3 -

rejecting the motion, the majority did not counter the litany of arguments that 

assailed the workability of the final rule in CAISO. 

The Net Benefits Test

As currently presented, the Net Benefits Test uses backward looking data to 

predict market rates a year later, when thousands of variables related to economic 

conditions and weather will surely result in different market rates and conditions. 

Therefore, it cannot define the benefits of demand response with any accuracy. As a 

consequence, the costs of demand response compensation will necessarily be inaccurate, 

and therefore, not just and reasonable. To be clear, I do not fault the RTOs and ISOs and 

their stakeholders who are trying to develop this unwieldy test. The difficulties inherent 

in developing a Net Benefits Test will be present regardless of whether the test for 

benefits is conducted dynamically8

 or statically. 

 However, instead of acknowledging the overwhelming opposition—often by the 

very stakeholders tasked with developing the Net Benefits Test—the majority points to 

the fact that required compliance filings have been submitted and avoids addressing the 

substantive arguments about whether the Net Benefits Test is actually workable.9

 

 Moreover, this order should have evaluated the costs of compliance, including the 

development of a static Net Benefits Test as well as studying and reporting on the 

development of a dynamic Net Benefits Test.10

 While I would have preferred to allow the regions to continue to develop their own 

demand response compensation programs, absent that outcome, using LMP – G would 

have at least negated the need to develop and conduct the Net Benefits Test.11 

 

(continued...) 

8

 The unchallenged evidence in this case is that, “the ISO is unaware of a 

technological solution that exists and there is no reason to believe that it is practically 

possible for the ISO to incorporate a dynamic net benefits test as part of the ISO’s 

optimization in the foreseeable future.” See CAISO, Request for Rehearing at 40 – 41. 

See also Declaration of Khaled Abdul-Rahman on behalf of the California Independent 

System Operator Corporation. 

9

 Order No. 745-A at P 93. 

10 Order No. 745-A at P 84. “The Commission required each ISO and RTO to 

conduct a study to determine whether the net benefits test could be integrated into its 

dispatch. Those studies are required to be filed by September 2, 2012.” 

11 “No such test would be necessary if instead a payment of LMP-G was made to 
Docket No. RM10-17-001 - 4 -

Demand Response Compensation 

The order continues to effectively find that demand resources being compensated 

at the value of full LMP is not enough, so instead requires that demand resource be paid

the full LMP plus be allowed to retain the savings associated with its avoided retail 

generation cost. Plainly speaking, this is overcompensation to demand response 

resources. And overcompensation cannot be just and reasonable. The majority insists 

that demand response is “comparable” to generation, and therefore, deserves the same 

amount and type of compensation as generation.12 However, commenters have noted that 

by not accounting for the contributions of behind-the-meter generation, some demand 

response resources will receive a rate equal to double the LMP rate.13 Nothing 

distinguishes a generator that is behind-the-meter from one that is in front-of-the-meter 

such that it is just and reasonable to pay one generator double the rate that is paid to 

another. 

Because measurement and verification is essential to the integrity and 

effectiveness of demand response compensation,14 it should have been more directly 

addressed in this order. Commenters raise valid concerns about the current lack of 

 

fully verified DR. Genuine DR that can be profitable under this payment is efficient 

(increases market surplus) while any DR that cannot make money under that price 

reduces market surplus. With the correct payment, no separate screen, such as the 

Order’s benefit-cost test, is needed.” See CAISO Motion to Lodge, June 22, 2011, 

Exhibit A, “Opinion on Economic Issues Raised by FERC Order 745” at 12. 

12 See Order No. 745-A at P 56. 

13 “For example, Severstal Steel’s Sparrows Point plant purchases its electricity 

directly from PJM’s day-ahead and real-time markets. The plant has a peak load of 230 

MW and has 150 MW of [behind-the-meter generation] that it uses to reduce its 

purchases when PJM’s LMPs are greater than the running costs of its own generation. 

Clearly, Severstal Steel’s generators are directly competing with wholesale generators in 

the PJM footprint but they are being compensated exactly twice LMP for the energy that 

the wholesale generators can produce at half that price. Paying one generator twice the 

price that is paid to another generator for delivering an identical, fungible product is 

clearly unduly discriminatory.” Request for Rehearing, EEI at 21 (footnote omitted). 

14 See Order No. 745 at P 93. See also Order No. 745-A at P 123. 
Docket No. RM10-17-001 - 5 -

 

effective measurement and verification standards, and about the cost and time needed 

to develop these standards.15 The order dismisses these concerns and passes off this 

challenge to the RTOs and ISOs to figure out measurement and verification in their 

compliance proceedings without regard to the costs of developing these programs. 

 For the reasons given, I cannot support this order as it violates the Commission’s 

statutory mandate to ensure supplies of electric energy at just, reasonable, and not unduly 

discriminatory or preferential rates. 

 _______________________ 

 Philip D. Moeller 

 Commissioner 

15 See Request for Rehearing, Midwest TDUs at 15. See also Request for 

Rehearing, CSA at 66 – 70. “...the Commission’s decision to adopt the Final Rule, 

before meaningful measurement and verification standards have been developed, was 

arbitrary and capricious. The evidence in the record unequivocally indicates that current 

NAESB standards and ISO/RTO rules cannot prevent fraud and abuse.”