134 FERC ¶ 61,187 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

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

Demand Response Compensation in Organized Wholesale Energy Markets 

(Issued March 15, 2011) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Final Rule. 

SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission 

(Commission) amends its regulations under the Federal Power Act to ensure that when a 

demand response resource participating in an organized wholesale energy market 

administered by a Regional Transmission Organization (RTO) or Independent System 

Operator (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 described in this rule, that demand response 

resource must be compensated for the service it provides to the energy market at the 

market price for energy, referred to as the locational marginal price (LMP). This 

approach for compensating demand response resources helps to ensure the 

competitiveness of organized wholesale energy markets and remove barriers to the 

participation of demand response resources, thus ensuring just and reasonable wholesale 

rates. 
Docket No. RM10-17-000 - 2 - 

EFFECTIVE DATE: This Final Rule will become effective on [INSERT DATE 30 

DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Dates for 

compliance and other required filings are provided in the Final Rule. 

FOR FURTHER INFORMATION CONTACT: 

David Hunger (Technical Information) 

Office of Energy Policy and Innovation 

Federal Energy Regulatory Commission 

888 First Street, NE, Washington, DC 20426 

(202) 502-8148 

david.hunger@ferc.gov 

Dennis Hough (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, NE, Washington, DC 20426 

(202) 502-8631 

dennis.hough@ferc.gov 

SUPPLEMENTARY INFORMATION:
134 FERC ¶ 61,187 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Demand Response Compensation in Organized 

Wholesale Energy Markets 

Docket No. RM10-17-000 

ORDER NO. 745 

TABLE OF CONTENTS

(Issued March 15, 2011) 

Paragraph Numbers

I. Introduction ............................................................................................................................1.

II. Background...........................................................................................................................8.

III. Procedural History...............................................................................................................15.

IV. Discussion ...........................................................................................................................17.

A. Compensation Level.........................................................................................................18.

1. NOPR Proposal.............................................................................................................18.

2. Comments ....................................................................................................................20.

a) Capability of Demand Response and Generation Resources to Balance Energy 

Markets..........................................................................................................................20.

b) Appropriateness of a Net Benefits Test ..................................................................38.

c) Standardization or Regional Variations in Compensation.......................................43.

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

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

1. Comments.....................................................................................................................68.

2. Commission Determination..........................................................................................78.

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

1. NOPR Proposal.............................................................................................................86.

2. Comments.....................................................................................................................88.

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

D. Cost Allocation.................................................................................................................96.

1. NOPR Proposal.............................................................................................................96.

2. Comments.....................................................................................................................97.

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

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

1. Comments.....................................................................................................................103.
Docket No. RM10-17-000 ii 

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

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

VI. Environmental Analysis ......................................................................................................121.

VII. Regulatory Flexibility Act .................................................................................................122.

VIII. Document Availability .....................................................................................................130.

IX. Effective Date and Congressional Notification...................................................................133.

Regulatory Text 

APPENDIX: List of Commenters 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Jon Wellinghoff, Chairman; 

 Marc Spitzer, Philip D. Moeller, 

 John R. Norris, and Cheryl A. LaFleur. 

Demand Response Compensation in Organized 

Wholesale Energy Markets 

Docket No. RM10-17-000 

FINAL RULE 

ORDER NO. 745 

(Issued March 15, 2011) 

I. Introduction

1. This Final Rule addresses compensation for demand response in Regional 

Transmission Organization (RTO) and Independent System Operator (ISO) organized 

wholesale energy markets, i.e., the day-ahead and real-time energy markets. As the 

Commission has previously recognized, a market functions effectively only when both 

supply and demand can meaningfully participate. The Commission, in the Notice of 

Proposed Rulemaking (NOPR) issued in this proceeding on March 18, 2010, proposed a 

remedy to concerns that current compensation levels inhibited meaningful demand-side 

participation.1

 After nearly 3,800 pages of comments, a subsequent technical conference, 

and the opportunity for additional comment, we now take final action. 

 1 Demand Response Compensation in Organized Wholesale Energy Markets, 

Notice of Proposed Rulemaking, 75 FR 15362 (Mar. 29, 2010), FERC Stats. & Regs. 

¶ 32,656 (2010) (NOPR). 
Docket No. RM10-17-000 - 2 - 

 

2. We conclude that when a demand response2

 resource3 participating in an 

organized wholesale energy market4

 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 

described herein, that demand response resource must be compensated for the service it 

provides to the energy market at the market price for energy, referred to as the locational 

marginal price (LMP).5

 The Commission finds that this approach to compensation for 

2

 Demand response means a reduction in the consumption of electric energy by 

customers from their expected consumption in response to an increase in the price of 

electric energy or to incentive payments designed to induce lower consumption of electric 

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

3

 Demand response resource means a resource capable of providing demand 

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

4

The requirements of this final rule apply only to a demand response resource 

participating in a day-ahead or real-time energy market administered by an RTO or ISO. 

Thus, this Final Rule does not apply to compensation for demand response under 

programs that RTOs and ISOs administer for reliability or emergency conditions, such as, 

for instance, Midwest ISO’s Emergency Demand Response, NYISO’s Emergency 

Demand Response Program, and PJM’s Emergency Load Response Program. This Final 

Rule also does not apply to compensation in ancillary services markets, which the 

Commission has addressed elsewhere. See, e.g., Wholesale Competition in Regions 

with Organized Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC 

Stats. & Regs. ¶ 31,281 (2008) (Order No. 719). 

5

 LMP refers to the price calculated by the ISO or RTO at particular locations or 

electrical nodes or zones within the ISO or RTO footprint and is used as the market price 

to compensate generators. There are variations in the way that RTOs and ISOs calculate 

LMP; however, each method establishes the marginal value of resources in that market. 

Nothing in this Final Rule is intended to change RTO and ISO methods for calculating 

LMP. 
Docket No. RM10-17-000 - 3 - 

 

demand response resources is necessary to ensure that rates are just and reasonable in the 

organized wholesale energy markets. Consistent with this finding, this Final Rule adds 

section 35.28(g)(1)(v) to the Commission’s regulations to establish a specific 

compensation approach for demand response resources participating in the organized 

wholesale energy markets administered by RTOs and ISOs. The Commission is not 

requiring the use of this compensation approach when demand response resources do not 

satisfy the capability and cost-effectiveness conditions noted above.6

3. This cost-effectiveness condition, as determined by the net benefits test described 

herein, recognizes that, depending on the change in LMP relative to the size of the energy 

market, dispatching demand 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 the case because customers are billed for energy based on the 

units, MWh, of electricity consumed. We refer to this potential result as the billing unit 

effect of dispatching demand response. By contrast, dispatching generation resources 

does not produce this billing unit effect because it does not result in a decrease of load. 

To address this billing unit effect, the Commission in this Final Rule requires the use of 

the net benefits test described herein to ensure that the overall benefit of the reduced 

6

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

from determining that other approaches to compensation would be acceptable when these 

conditions are not met. 
Docket No. RM10-17-000 - 4 - 

 

LMP that results from dispatching demand response resources exceeds the cost of 

dispatching and paying LMP to those resources. When the net benefits test described 

herein is satisfied and the demand response resource clears in the RTO’s or ISO’s 

economic dispatch, the demand response resource is a cost-effective alternative to 

generation resources for balancing supply and demand. 

4. To implement the net benefits test described herein, we direct each RTO and ISO 

to develop a mechanism as an approximation to determine a price level at which the 

dispatch of demand response 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 beyond which 

the overall benefit from the reduced LMP resulting from dispatching demand response 

resources exceeds the cost of dispatching and paying LMP to those resources. This price 

level is to be updated monthly, by each ISO or RTO, as the historic data and relevant 

supply conditions change.7

7

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

how its proposed or existing practices are consistent with or superior to the requirements 

of this Final Rule. 
Docket No. RM10-17-000 - 5 - 

 

5. This Final Rule also sets forth a method for allocating the costs of demand 

response payments among all customers who benefit from the lower LMP resulting from 

the demand response. 

6. The tariff changes needed to implement the compensation approach required in 

this Final Rule, including the net benefits test, measurement and verification explanation 

and proposed changes, and the cost allocation mechanism must be made on or before 

July 22, 2011. All tariff changes directed herein should be submitted as compliance 

filings pursuant to this Final Rule, not pursuant to section 205 of the Federal Power Act 

(FPA).8

 Accordingly, each RTO’s or ISO’s compliance filing to this Final Rule will 

become effective prospectively from the date of the Commission order addressing that 

filing, and not within 60 days of submission. 

7. In addition, we believe that integrating a determination of the cost-effectiveness of 

demand response resources into the dispatch of the ISOs and RTOs may be more precise 

than the monthly price threshold and, therefore, provide the greatest opportunity for load 

to benefit from participation of demand response in the organized wholesale energy 

market administered by an RTO or ISO. However, we acknowledge the 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 

8

 16 U.S.C. 824d (2006). 
Docket No. RM10-17-000 - 6 - 

light of those concerns, we require 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 directs each RTO and ISO to file the results 

of this study with the Commission on or before September 21, 2012.9

 

II. Background

8. Effective wholesale competition protects customers by, among other things, 

providing more supply options, encouraging new entry and innovation, and spurring 

deployment of new technologies.10 Improving the competitiveness of organized 

wholesale energy markets is therefore integral to the Commission fulfilling its statutory 

mandate under the FPA to ensure supplies of electric energy at just, reasonable, and not 

unduly discriminatory or preferential rates.11 

 9

 We note that this report is for informational purposes only and will neither be 

noticed nor require Commission action. 

10 See, e.g., Wholesale Competition in Regions with Organized Electric Markets, 

Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281, at P 1 

(2008) (Order No. 719); see also Regional Transmission Organizations, Order No. 2000, 

FERC Stats. & Regs. ¶ 31,089, at P 1 (1999), order on reh'g, Order No. 2000-A, FERC 

Stats. & Regs. ¶ 31,092 (2000), aff'd sub nom. Pub. Util. Dist. No. 1 of Snohomish 

County, Washington v. FERC, 272 F.3d 607, 348 U.S. App. D.C. 205 (D.C. Cir. 2001). 

11 16 U.S.C. 824d (2006); Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 1. 
Docket No. RM10-17-000 - 7 - 

 

9. As the Commission recognized in Order No. 719, active participation by 

customers in the form of demand response in organized wholesale energy markets helps 

to increase competition in those markets.12 Demand response, whereby customers reduce 

electricity consumption from normal usage levels in response to price signals, can 

generally occur in two ways: (1) customers reduce demand by responding to retail rates 

that are based on wholesale prices (sometimes called “price-responsive demand”); and 

(2) customers provide demand response that acts as a resource in organized wholesale 

energy markets to balance supply and demand. While a number of states and utilities are 

pursuing retail-level price-responsive demand initiatives based on dynamic and timedifferentiated retail prices and utility investments in demand response enabling 

technologies, these are state efforts, and, thus, are not the subject of this proceeding. Our 

focus here is on customers or aggregators of retail customers providing, through bids or 

self-schedules, demand response that acts as a resource in organized wholesale energy 

markets. 

10. As the Commission stated in Order No. 719,13 and emphasized in the NOPR,14

there are several ways in which demand response in organized wholesale energy markets 

12 See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 48. 

13 Wholesale Competition in Regions with Organized Electric Markets, Order 

No. 719-A, FERC Stats. & Regs. ¶ 31,292, at P 48 (2009). 

14 NOPR, FERC Stats. & Regs. ¶ 32,656 at P 4. 
Docket No. RM10-17-000 - 8 - 

 

can help improve the functioning and competitiveness of those markets. First, when bid 

directly into the wholesale market, demand response can facilitate RTOs and ISOs in 

balancing supply and demand, and thereby, help produce just and reasonable energy 

prices.15 This is because customers who choose to respond will signal to the RTO or ISO 

and energy market their willingness to reduce demand on the grid which may result in 

reduced dispatch of higher-priced resources to satisfy load.16 Second, demand response 

can mitigate generator market power.17 This is because the more demand response that 

sees and responds to higher market prices, the greater the competition, and the more 

downward pressure it places on generator bidding strategies by increasing the risk to a 

supplier that it will not be dispatched if it bids a price that is too high.18 Third, demand 

15 For example, a study conducted by PJM, which simulated the effect of demand 

response on prices, demonstrated that a modest three percent load reduction in the 100 

highest peak hours corresponds to a price decline of six to 12 percent. ISO-RTO Council 

Report, Harnessing the Power of Demand How RTOs and ISOs Are Integrating Demand 

Response into Wholesale Electricity Markets, found at 

http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-

003829518EBD%7D/IRC_DR_Report_101607.pdf. 

16 Id. (“Demand response tends to flatten an area’s load profile, which in turn may 

reduce the need to construct and use more costly resources during periods of high 

demand; the overall effect is to lower the average cost of producing energy.”). 

17 See Comments of NYISO’s Independent Market Monitor filed in Docket No. 

ER09-1142-000, May 15, 2009 (Demand response “contributes to reliability in the shortterm, resource adequacy in the long-term, reduces price volatility and other market costs, 

and mitigates supplier market power.”). 

18 Id.
Docket No. RM10-17-000 - 9 - 

response has the potential to support system reliability and address resource adequacy19

and resource management challenges surrounding the unexpected loss of generation. 

This is because demand response resources can provide quick balancing of the electricity 

grid.20 

11. Congress has recognized the importance of demand response by enacting national 

policy requiring its facilitation.21 Consistent with that policy, the Commission has 

undertaken several reforms to support competitive wholesale energy markets by 

removing barriers to participation of demand response resources. For example, in Order 

No. 890, the Commission modified the pro forma Open Access Transmission Tariff to 

 19 See ISO-RTO Council Report, Harnessing the Power of Demand How RTOs 

and ISOs Are Integrating Demand Response into Wholesale Electricity Markets at 4, 

found at http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-

003829518EBD%7D/IRC_DR_Report_101607.pdf (“Demand response contributes to 

maintaining system reliability. Lower electric load when supply is especially tight 

reduces the likelihood of load shedding. Improvements in reliability mean that many 

circumstances that otherwise result in forced outages and rolling blackouts are averted, 

resulting in substantial financial savings . . . .”). 

20 For instance, in ERCOT, on February 26, 2008, through a combination of a 

sudden loss of thermal generation, drop in power supplied by wind generators, and a 

quicker-than-expected ramping up of demand, ERCOT found itself short of reserves. 

The system operator called on all demand response resources, and 1200 MW of Load 

acting as Resource (LaaRs) responded quickly, bringing ERCOT back into balance. OAK 

RIDGE NAT’L LAB., NAT’L RENEWABLE ENERGY LAB., TECH. REP. NREL/TP-500-43373,

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

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

965 (2005) (“It is the policy of the United States that . . . unnecessary barriers to demand 

response participation in energy, capacity, and ancillary service markets shall be 

eliminated.”). 
Docket No. RM10-17-000 - 10 - 

 

allow non-generation resources, including demand response resources, to be used in the 

provision of certain ancillary services where appropriate on a comparable basis to service 

provided by generation resources.22 Order No. 890-A further required transmission 

providers to develop transmission planning processes that treat all resources, including 

demand response, on a comparable basis.23 

12. In Order No. 719, the Commission required RTOs and ISOs to, among other 

things, accept bids from demand response resources in their markets for certain ancillary 

services on a basis comparable to other resources.24 The Commission also required each 

RTO and ISO “to reform or demonstrate the adequacy of its existing market rules to 

ensure that the market price for energy reflects the value of energy during an operating 

reserve shortage,”25 for purposes of encouraging existing generation and demand 

resources to continue to be relied upon during an operating reserve shortage, and 

encouraging entry of new generation and demand resources.26 

22 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241, at P 887-88 (2007), order on reh’g, Order 

No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g and clarification, Order 

No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC 

¶ 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009). 

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

24 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 47-49. 

25 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194. 

26 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 247. 
Docket No. RM10-17-000 - 11 - 

 

13. Additionally, in recent years several RTOs and ISOs have instituted various types 

of demand response programs. While some of these programs are administered for 

reliability and emergency conditions, other programs allow wholesale customers, 

qualifying large retail customers, and aggregators of retail customers to participate 

directly in the day-ahead and real-time energy markets, certain ancillary service markets 

and capacity markets.27 

14. To date, the Commission has allowed each RTO and ISO to develop its own 

compensation methodologies for demand response resources participating in its dayahead and real-time energy markets. As a result, the levels of compensation for demand 

response vary significantly among RTOs and ISOs.28 For example, PJM Interconnection, 

L.L.C. (PJM) pays the LMP minus the generation and transmission portions of the retail 

27 Other demand response programs allow demand response to be used as a 

capacity resource and as a resource during system emergencies or permit the use of 

demand response for synchronized reserves and regulation service. See, e.g., PJM 

Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006); Devon Power LLC, 115 FERC 

¶ 61,340, order on reh’g, 117 FERC ¶ 61,133 (2006), appeal pending sub nom. Maine 

Pub. Utils. Comm’n v. FERC, No. 06-1403 (D.C. Cir. 2007); New York Indep. Sys. 

Operator, Inc., 95 FERC ¶ 61,136 (2001); NSTAR Services Co. v. New England Power 

Pool, 95 FERC ¶ 61,250 (2001); New England Power Pool and ISO New England, Inc., 

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

103 FERC ¶ 61,304, order on reh’g, 105 FERC ¶ 61,211 (2003); PJM Interconnection, 

L.L.C., 99 FERC ¶ 61,227 (2002); California Independent System Operator Corp., 

132 FERC ¶ 61,045 (2010). 

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

Docket No. ER08-830-000; Midwest Indep. Transmission Sys. Operator, Inc., Docket 

No. ER09-1049-000. 
Docket No. RM10-17-000 - 12 - 

 

rate.29 ISO New England Inc. (ISO-NE) and New York Independent System Operator, 

Inc. (NYISO) pay LMP when prices exceed a threshold level, with the levels differing 

between the RTOs.30 The Midwest Independent Transmission System Operator, Inc.’s 

(Midwest ISO) demand response programs31 pay LMP for demand response resources in 

the day-ahead and real-time energy markets.32 The California Independent System 

Operator Corporation (CAISO) pays LMP at pricing nodes, or sub-load aggregation 

points (Sub-LAP) in its Proxy Demand Resource program that allows qualifying 

29 See sections 3.3A.4 and 3.3A.5 (Market Settlements in the Real-Time and DayAhead Energy Markets) of the Appendix to Attachment K of the PJM Tariff. 

30 For example, under ISO-NE’s Real-Time Price Response Program, the 

minimum bid is $100/MWh and a demand response resource is paid the higher of LMP 

or $100/MWh. For the Day-Ahead Load Response Program, the minimum offer level is 

calculated on a monthly basis and is the Forward Reserve Fuel Index ($/MMBtu) 

multiplied by an effective heat rate of 11.37 MMBtu/MWh. The maximum offer level is 

$1,000/MWh. See sections III.E.2.1 and III.E.3.2 of Appendix E of the ISO New 

England Transmission, Markets and Services Tariff. NYISO implements a day-ahead 

demand response program by which resources bid into the market at a minimum of 

$75/MWh and can get paid the LMP. See section 4.2.2.9 (“Day-Ahead Bids from 

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

Market Services Tariff. 

31 Midwest ISO FERC Electric Tariff characterizes Demand Response Resources 

(DRR) as either DRR-Type I or DRR-Type II. DRR-Type I are capable of supplying a 

specific quantity of energy or contingency reserve through physical load interruption. 

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

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

32 See Charges and Payments for Purchases and Sales for Demand Response 

Resources. Midwest ISO FERC Electric Tariff, section 39.3.2C. 
Docket No. RM10-17-000 - 13 - 

resources to provide day-ahead and real-time energy.33 CAISO also provides for demand 

response resources to participate in its Participating Load program, which enables certain 

resources to provide curtailable demand in the CAISO market. CAISO pays nodal realtime LMP for its Participating Load program. The Southwest Power Pool, Inc. (SPP) has 

filed revisions to its tariff to facilitate demand response in the Energy Imbalance Service 

Market.34

III. Procedural History

15. As noted above, the Commission issued the NOPR in this proceeding on 

March 18, 2010.35 The NOPR proposed to require RTOs and ISOs to pay the LMP in all 

hours for demand reductions made in response to price signals. The Commission sought 

 33 See section 11.2.1.1 IFM Payments for Supply of Energy, CAISO FERC 

Electric Tariff. CAISO notes that for a Proxy Demand Resource that is made up of 

aggregated loads, the Resource is paid the weighted average of the LMPs of each pricing 

node where the underlying aggregate loads reside. See CAISO, 132 FERC ¶ 61,045, at 

P 26 n.14 (2010). 

34 The Commission has directed SPP to report on ways it can incorporate demand 

response into its imbalance market. Southwest Power Pool, Inc., 128 FERC ¶ 61,085 

(2009). As of September 1, 2010, SPP has submitted seven informational status reports 

regarding its efforts to address issues related to demand response resources. In orders 

addressing SPP’s compliance with Order No. 719, the Commission also directed SPP to 

make another compliance filing addressing demand response participation in its 

organized markets. Southwest Power Pool, Inc., 129 FERC ¶ 61,163, at P 51 (2009). On 

May 19, 2010, SPP submitted revisions to its Open Access Transmission Tariff in Docket 

Nos. ER09-1050-004 and ER09-748-002 to comply with the Commission’s requirements 

established in Order Nos. 719 and 719-A. These filings are pending before the 

Commission. 

35 NOPR, FERC Stats. & Regs. ¶ 32,656. 
Docket No. RM10-17-000 - 14 - 

 

comments on the compensation proposal and, in particular, on the comparability of 

generation and demand response resources; alternative approaches to compensating 

demand response in organized wholesale energy markets; whether payment of LMP 

should apply in all hours, and, if not, any criteria that should be used for establishing 

hours when LMP should apply; and whether to allow for regional variations concerning 

approaches to demand response compensation.36 

16. After receiving the first round of comments, the Commission issued a 

Supplemental Notice of Proposed Rulemaking and Notice of Technical Conference 

(Supplemental NOPR) in this proceeding on August 2, 2010.37 The Supplemental NOPR 

sought additional comment on: whether the Commission should adopt a net benefits test 

for determining when to compensate demand response providers, and, if so, what, if any, 

requirements should apply to the methods for determining net benefits; and what, if any, 

requirements should apply to how the costs of demand response are allocated. The 

Commission further directed Staff to hold a technical conference focused on these two 

issues, which occurred on September 13, 2010.38

36 See Appendix for a list of commenters. 

37 Supplemental Notice of Proposed Rulemaking and Notice of Technical 

Conference, 75 FR 47499 (Aug. 6, 2010), 132 FERC ¶ 61,094 (2010) (Supplemental 

NOPR). 

38 See Notice of Technical Conference (Aug. 27, 2010). 
Docket No. RM10-17-000 - 15 - 

IV. Discussion

17. Based upon the record in this proceeding, the Commission herein requires greater 

uniformity in compensating demand response resources participating in organized 

wholesale energy markets. This Final Rule also addresses the allocation of costs 

resulting from the commitment of demand response, directing that such costs be allocated 

among those customers who benefit from the lower LMP resulting from the demand 

response. 

A. Compensation Level

1. NOPR Proposal

18. The NOPR proposed to require RTOs and ISOs to pay the LMP in all hours for 

demand reductions made in response to price signals. The NOPR sought to provide 

comparable compensation to generation and demand response providers, based on the 

premise that both resources provide a comparable service to RTOs and ISOs for purposes 

of balancing supply and demand and maintaining a reliable electricity grid.39 Also as 

stated in the NOPR, the proposed compensation level was designed to allow more 

demand response resources to cover their investment costs in demand response-related 

technology (such as advanced metering) and thereby facilitate their ability to participate 

in organized wholesale energy markets.40 The Commission sought comments on the 

 39 NOPR, FERC Stats. & Regs. ¶ 32,656 at P 15. 

40 Id. at P 16. 
Docket No. RM10-17-000 - 16 - 

 

compensation proposal and, in particular, on the comparability of generation and demand 

response resources; alternative approaches to compensating demand response in 

organized wholesale energy markets; whether payment of LMP should apply in all hours, 

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

apply; and whether to allow for regional variations concerning approaches to demand 

response compensation. 

19. In the Supplemental NOPR, the Commission sought additional comments and 

directed staff to hold a technical conference regarding various net benefits tests. In 

particular, the Commission sought comment on: whether the Commission should adopt a 

net benefits test applicable in all or only some hours and what the criteria of any such test 

would be; how to define net benefits; what costs demand response providers and load 

serving entities incur and whether they should be included in a net benefits test; whether 

any net benefits methodology adopted should be the same for all RTOs and ISOs; 

proposed methodologies for implementing a net benefits test and the advantages and 

limitations of any proposed methodologies.41 The September 13, 2010 Technical 

Conference included an eleven-member panel discussion of net benefits tests representing 

41 Supplemental NOPR, 132 FERC ¶ 61,094 at P 8-9. 
Docket No. RM10-17-000 - 17 - 

a wide range of interests and viewpoints.42 The Commission subsequently received 

additional written comments addressing these issues. 

2. Comments 

a) Capability of Demand Response and Generation Resources to 

Balance Energy Markets

20. Various commenters address the comparability of demand response and 

generation resources for purposes of compensation in the organized wholesale energy 

markets. To begin, numerous commenters address the physical or functional 

comparability of demand response and generation, agreeing that an increment of 

generation is comparable to a decrement of load for purposes of balancing supply and 

demand in the day-ahead and real-time energy markets.43 Equating generation and 

demand response resources, Dr. Alfred E. Kahn states:

[Demand response] is in all essential respects economically equivalent to 

supply response . . . [so] economic efficiency requires . . . that it should be 

rewarded with the same LMP that clears the market. Since [demand 

response] is actually—and not merely metaphorically—equivalent to 

supply response, economic efficiency requires that it be regarded and 

rewarded, equivalently, as a resource proffered to system operators, and be 

treated equivalently to generation in competitive power markets. That is, 

 42 See Sept. 13, 2010 Tr. 

43 DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 2); Verso May 13, 

2010 Comments at 3-4; Occidental May 13, 2010 Comments at 11; Viridity June 18, 

2010 Comments at 5. 
Docket No. RM10-17-000 - 18 - 

 

all resources—energy saved equivalently to energy supplied— . . . should 

receive the same market-clearing LMP in remuneration.44

Indeed, some commenters believe that, from a physical standpoint, demand response can 

provide superior services to generation, such as providing a quick response in meeting 

system requirements and service without having to construct major new facilities.45 

Occidental asserts that the fungibility of demand response and generation output creates 

greater operational flexibility that, in turn, offers RTOs and ISOs multiple options to 

solve system issues both in energy and ancillary service markets, and that the fungible 

nature of demand response and generation supports comparable compensation for each as 

proposed in the NOPR.46 

21. Viridity states that attempts to distinguish the physical characteristics of 

generation and demand response ignore bid-based security-constrained economic 

dispatch as the foundation for LMP and are based on the assumption that the value of 

load management on the grid is limited to periods when the system is stressed, i.e., 

traditional “super peak shaving.” Viridity states that, while these arguments might have 

been valid 15 years ago, today competitive markets can offer proactively-managed load 

control and comparable and non-discriminatory treatment of load-based energy resources. 

44 DR Supporters August 30, 2010 Reply Comments (Kahn Affidavit at 2 

(footnote omitted)). 

45 Verso May 13, 2010 Comments at 3-4; Alcoa May 13, 2010 Comments at 9. 

46 Occidental May 13, 2010 Comments at 11. 
Docket No. RM10-17-000 - 19 - 

 

Therefore, Viridity asserts that all resources should be paid LMP if the grid operator 

accepts their bid to achieve grid balance.47 

22. At the same time, other commenters argue that generation and demand response 

are not physically equivalent, pointing out that demand response reduces consumption, 

whereas generators serve consumption.48 They argue that a MW reduction in demand 

does not turn on the lights.49 EPSA adds that a load reduction does not provide electrons 

to any other load and, instead, allows the marginal electron to serve a different 

customer.50 Some commenters assert that a power system can function solely and 

reliably on generating plants and without any reliance on demand response, while the 

system cannot rely exclusively on demand response because demand response by itself 

cannot keep the lights on. Ultimately, some commenters point out, megawatts produced 

by generators need to be placed on the system in order for power to flow.51 Battelle 

additionally argues that a reduction in consumption is not exactly the same as an increase 

47 Viridity June 18, 2010 Comments at 5. 

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

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

Comments at 2. 

50 EPSA May 13, 2010 Comments at 72. 

51 See, e.g., PSEG May 13, 2010 Comments at 8. 
Docket No. RM10-17-000 - 20 - 

 

in production, because elastic demand often comes with attendant future consequences, 

such as rebound, by virtue of substitution in time.52 

23. Some commenters who argue that the physical characteristics of demand response 

are not comparable to generation frame their arguments in terms of the ability of the 

system operator to call on demand response and generation resources to provide 

balancing energy. They argue that generation resources provide superior service to 

demand response providers, positing that demand response is not intended for long 

periods of balancing needs,53 and that, moreover, contracts with demand response 

providers limit the number of hours and times a customer may be called upon to curtail. 

For example, ODEC asserts that the degree of physical comparability depends on the 

extent to which demand response resources can be dispatched similar to a generator.54 

Calpine adds that traditional generators provide system support features that demand 

response cannot, such as ancillary services including governor response or reactive power 

voltage support, which are necessary for reliable operation of the electric system.55 

24. Numerous commenters also address the comparability of demand response and 

generation in economic terms. For example, EEI states that, in finance terms, the demand 

52 Battelle May 13, 2010 Comments at 3. 

53 AEP May 13, 2010 Comments at 7-8. 

54 ODEC May 13, 2010 Comments at 12. 

55 Calpine May 13, 2010 Comments at 4-5. 
Docket No. RM10-17-000 - 21 - 

 

response product is, unlike generation, essentially an unexercised call option on spot 

market energy, and the value of that option is well-established in finance theory as the 

value of the resource (LMP) minus the “strike price,” which EEI contends in this case is 

the retail tariff rate.56 EEI and like-minded commenters support, therefore, alternative 

compensation for demand response to equal LMP minus the generation (or G) component 

of the retail rate.57 They posit that payment of LMP without an offset for some portion of 

the retail rate does not send the proper economic signal to providers of demand response, 

because it fails to take into account the retail rate savings associated with demand 

response, and thereby overcompensates the demand response provider. As described by 

Dr. William W. Hogan on behalf of EPSA, this is sometimes called a double-payment for 

demand reductions, because demand response providers would “receive” both the cost 

56 EEI May 13, 2010 Comments at 4-5. See also Robert L. Borlick May 13, 2010 

Comments at 4. Mr. Borlick argues that the correct price is LMP minus the Marginal 

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

paid to a demand response provider as “its offer price minus the price in its retail tariff at 

which it would have purchased the curtailed energy.” Mr. Borlick asserts that this 

amount accurately represents the forgone opportunity costs that result when a demand 

response provider reduces its load. Id.

57 See May 13, 2010 Comments of: APPPA; AEP; The Brattle Group; Calpine; 

ConEd; Consumers Energy; CPG; Detroit Edison; Direct Energy; Dominion; Duke 

Energy; Edison Mission; EEI; EPSA; Exelon; FTC; GDF; NYISO on behalf of the ISO 

RTO Council; ICC; IPPNY; Indicated New York TOs; IPA; ISO-NE; Midwest TDUs; 

Mirant; Midwest ISO TOs; NEPGA; NYISO; ODEC; OMS; PJM; PJM IMM; P3; 

Potomac Economics; PG&E; Ohio Commission; Robert L. Borlick; Roy Shanker; and 

RRI Energy. 
Docket No. RM10-17-000 - 22 - 

 

savings from not consuming an increment of electricity at a particular price, plus an LMP 

payment for not consuming that same increment of electricity.58 Viewing LMP as a 

double-payment, these commenters argue that paying LMP will result in more demand 

response than is economically efficient.59 For example, Dr. Hogan states that paying 

LMP might motivate a company to shut down even though the benefits of consuming 

electricity outweigh the cost at LMP.60 Indeed, P3 argues that compensation in excess of 

LMP-G is unjust and unreasonable, because such a payment level imposes costs on 

customers that are not commensurate with benefits received.61

25. ISO-NE argues that paying full LMP to demand response providers without taking 

into account the bill savings produced by demand response provides a significant 

financial incentive to dispatch demand response with marginal costs exceeding LMPs. 

By dispatching higher-cost demand response, ISO-NE asserts, lower-cost generation 

58 See Attachment to Answer of EPSA, Providing Incentives for Efficient Demand 

Response, Dr. William W. Hogan, Oct. 29, 2009, submitted in Docket No. EL09-68-000. 

59 EPSA May 13, 2010 Comments at 23. See also May 13, 2010 Comments of 

APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5; 

PJM at 6; PSEG at 5; and Potomac Economics at 6-8. 

60 Attachment to Answer of EPSA, Providing Incentives for Efficient Demand 

Response, Dr. William W. Hogan, Oct. 29, 2009, submitted in Docket No. EL09-68-000. 

In Dr. Hogan’s view, supply should produce when the price of electricity exceeds its cost 

of production and demand should decline to consume when the costs in terms of 

convenience of delaying use are less than the price of electricity. 

61 P3 June 14, 2010 Comments at 2, 7-8. 
Docket No. RM10-17-000 - 23 - 

 

resources are displaced.62 At the same time, ISO-NE argues, generation is not dispatched 

and paid for only when the generation reduces LMP—generation is dispatched and paid 

for when it is cost-effective.63

26. Dr. Hogan further disputes arguments equating a MW of energy supplied to a MW 

of energy saved on economic grounds. Dr. Hogan draws a distinction between reselling 

something that one has purchased, and selling something that one would have purchased 

without actually purchasing it. Dr. Hogan argues that from the perspective of economic 

efficiency and welfare maximization, the aggregate effect of demand response is a wash 

producing no economic net benefit. Dr. Hogan asserts that Commission policy citing the 

benefits of price reduction in support of demand response compensation would amount to 

no less than an application of regulatory authority to enforce a buyers' cartel. He states 

that the Commission has been vigilant and aggressive in preventing buyers and sellers 

from engaging in market manipulation to influence prices, and it would be fundamentally 

inconsistent for the Commission to design demand response compensation policies that 

coordinate and enforce such price manipulation. 

27. Dr. Hogan argues that the ideal and economically efficient solution regarding 

demand response compensation is to implement retail real-time pricing at the LMP, 

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

63 Id. at 28. 
Docket No. RM10-17-000 - 24 - 

 

thereby eliminating the need for demand response programs. Realizing that this is 

unattainable at the present time, Dr. Hogan goes on to propose a next-best solution, 

which he believes is to pay demand response compensation in the amount of LMP-G, or 

some amount that simulates explicit contract demand response (such as “buy-thebaseline” approach discussed below). These options, he argues, more than paying LMP, 

better support notions of comparability between demand response resources and 

generation.64

28. The New York Commission, however, argues that requiring payment of LMP-G 

would result in an administrative burden of tracking retail rates for the multiple utilities, 

ESCOs and power authorities and create undue confusion for retail customers and 

administrative difficulties for state commissions and ISOs and RTOs.65

29. Consistent with Dr. Hogan’s arguments, some commenters assert that demand 

response providers should actually own or pay for electricity prior to, what commenters 

characterize as, an effective reselling of the electricity back to the market in the form of 

demand response. For example, these commenters suggest that the demand response 

provider purchase the power in the day-ahead market and resell it in the real-time 

64 Hogan Affidavit, ISO RTO Council May 13, 2010 Comments at 5. 

65 New York Commission May 13, 2010 Comments at 8. 
Docket No. RM10-17-000 - 25 - 

 

markets.66 EPSA argues that there must be some purchase requirement or representative 

offset to allow a demand response provider to “sell” a commodity that it owns to the ISO 

or RTO.67 EPSA argues that such a requirement would send an efficient price signal, 

reduce incentives for gaming the system, and help address difficulties with measurement 

and verification of a demand reduction. EPSA highlights an ISO-NE IMM 

recommendation that, if the Commission permits LMP payment, it should also adopt a 

“buy-the-baseline” approach requiring demand response resources to purchase an 

expected amount of energy consumption in the day-ahead energy market and 

subsequently sell any demand reduction from that level in the real-time market.68

30. Viridity, on the other hand, argues that forcing customers to buy and then resell 

electricity will lead to too little demand response and that adopting a “buy-the-baseline” 

approach would constitute an inappropriate exercise of Commission authority to 

effectively force parties into contracts. Viridity and DR Supporters state that any 

characterization of demand response as a purchase and then resale of energy is 

erroneous69 and based on the flawed assumption that demand response resources are 

66 See, e.g., ISO-NE IMM May 13, 2010 Comments at 4-5; Midwest ISO TOs 

May 13, 2010 Comments at 14; PJM May 13, 2010 Comments at 5; and Duke Energy 

May 13, 2010 Comments at 2. 

67 EPSA June 30, 2010 Comments at 3. 

68 EPSA June 30, 2010 Comments at 23. 

69 Viridity Energy June 18, 2010 Comments at 25. 
Docket No. RM10-17-000 - 26 - 

reselling energy. They state that the description of demand response as a reselling of 

energy has been correctly rejected by the Commission in EnergyConnect, where the 

Commission stated that it was establishing a policy of treating demand response as a 

service rather than a purchase and sale of electric energy.70

31. DR Supporters further argues that, despite claims to the contrary, paying full LMP 

to demand response providers does not constitute a subsidy for demand response any 

more than the remunerations of generators for the power that they sell. As Dr. Kahn 

states: 

Does this plan involve double compensation, as [Dr.] Hogan asserts, at the 

expense of power generators—of successful bidders promising to induce 

efficient demand curtailment and of consumers induced to practice it? 

Certainly not: the decrease in the revenue of the generators is (and 

consequent savings by consumers are) matched by the savings in their 

(marginal) costs of generating that power; the successful bidders for the 

opportunity to induce that consumer response are compensated for the costs 

of those efforts by the pool, whose (marginal) costs they save by assisting 

consumers to reduce their purchases.71

32. Viridity further disputes Dr. Hogan’s argument that payment of LMP for demand 

response will distort an otherwise optimal market. Viridity posits that such arguments 

ignore dislocations in the wholesale power markets, the existence of market power that 

must be mitigated, imperfect information available to customers, barriers to entry and 

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

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

71 DR Supporters Aug. 30, 2010 Reply Comments, Kahn Affidavit at 10. 
Docket No. RM10-17-000 - 27 - 

 

uneconomic resources dispatched to fulfill must-run requirements.72 Viridity further 

states that Dr. Hogan’s arguments fail to acknowledge the limits of the Commission’s 

jurisdiction and widespread dislocations and distortions in virtually all economic aspects 

of relevant energy markets (including fuels, facilities, pricing, environmental attributes, 

information and participation) and fail to account for any market benefits of demand 

response.73 Finally, Viridity argues that Dr. Hogan’s arguments fail to reflect the many 

complex interactions between price, equipment operational requirements, and customer 

processes, which point to a complex demand response decision.74

33. In addition to physical and economic comparability, some commenters contrast 

the environmental effects of generation and demand response resources. EDF notes that 

current market prices fail to internalize environmental externalities – including toxic air 

pollution, greenhouse gas pollution, and land and water use impacts – and other social 

costs. EDF asserts that the social impact of these environmental externalities is 

especially acute at peak times, positing that generation sources used for marginal supply 

at such times (“peaker plants”) are among the oldest, dirtiest, and most inefficient in the 

72 Viridity June 18, 2010 Comments at 13 (“Importantly, Dr. Hogan (and others) 

in opposing the proposed rulemaking fails to acknowledge the limits of the Commission’s 

jurisdiction, and wide spread dislocations and distortions in virtually all economic aspects 

of relevant energy markets (including fuels, facilities, pricing, environmental attributes, 

information and participation).” (Affidavit of John C. Tysseling, Ph.D.)). 

73 Viridity Reply Comments at 13. 

74 Viridity Reply Comments at 14. 
Docket No. RM10-17-000 - 28 - 

 

fleet.75 The American Clean Skies Foundation contends that fossil-fuel generators are 

typically mispriced because wholesale prices radically understate the full environmental 

and health costs associated with such generators.76 Indeed, some commenters, such as 

Alcoa, argue that because demand response does not result in the external costs 

associated with generation (e.g., greenhouse gas emissions), instead resulting in less 

greenhouse gas emissions than generation, it should be compensated at more than LMP.77 

34. Taking the opposite view concerning environmental externalities, EPSA states that 

paying LMP for demand response will merely encourage load to switch to off-grid power 

(or behind-the-meter generation), while still being compensated, and that such behindthe-meter generation produces more greenhouse gases and other air emissions than 

electricity from the regional energy market.78 

35. Some commenters discuss comparability of generation and demand response in 

terms of the market rules that apply to each resource, arguing that both resources should 

be comparably compensated only if the same rules for participation apply to both 

resources, and both resources are held to the same standards for dispatchability.79 They 

75 EDF Oct. 13, 2010 Comments at 2. 

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

77 Alcoa May 13, 2010 Comments at 9. 

78 EPSA May 13, 2010 Comments at 60. 

79 ODEC May 13, 2010 Comments at 12; Westar May 13, 2010 Comments at 5-6. 
Docket No. RM10-17-000 - 29 - 

 

also argue that similar penalty structures should apply to demand response resources as 

apply to generation, and that demand response participation must be subject to market 

monitoring.80 Calpine adds that to the extent demand response resources are used and 

treated on par with generators for purposes of compensation, they should be subject to the 

same performance testing, penalties, and other similar requirements as generators.81 

36. Some commenters address the comparability of demand response providers and 

generators in terms of maintaining system reliability. PIO argues that reductions in 

consumption provide additional reliability.82 According to the NEMA, North American 

Electric Reliability Corporation (NERC) standards suggest that, from a reliability 

perspective, load reductions are equivalent or even superior to generator increases for 

balancing purposes. For example, while specific to the Western Interconnection, BAL002-WECC-1 lists interruptible load as comparable to generation deployable within 10 

minutes.83 EPSA maintains that demand response resources are not full substitutes based 

on the nature of their participation and the rules applicable to each resource in the energy 

80 Id.

81 Calpine May 13, 2010 Comments at 5. 

82 PIO May 13, 2010 Comments at 8. 

83 NEMA May 13, 2010 Comments at 2. 
Docket No. RM10-17-000 - 30 - 

markets, pointing out, for example, that, unlike generators, demand response providers 

are not subject to regional and NERC mandatory reliability standards.84

37. On the other hand, PSEG argues that a MW of demand response does not make 

the same contribution towards system reliability as a MW of generation, because demand 

response committed as a capacity resource is only required to perform for a limited 

number of times over the peak period. PSEG refers to PJM’s capacity market, for 

example, in which demand response only has to perform 10 times during the entire 

summer peak period, and then only for six hours per response. In contrast, PSEG argues, 

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

small percentage of time for forced and planned outages. PSEG further asserts that 

additional reliability standards - applicable to generating facilities, but not to demand 

response - increase the relative reliability value of generating resources to the system.85

b) Appropriateness of a Net Benefits Test 

38. Some commenters assert that demand response providers should be paid LMP 

only when the benefits of demand response compensation outweigh the energy market 

costs to consumers of paying demand response resources, i.e., when cost-effective, as 

 84 EPSA May 13, 2010 Comments at 7. 

85 PSEG May 13, 2010 Comments at 8. 
Docket No. RM10-17-000 - 31 - 

 

determined by some type of net benefits or cost-effectiveness test.86 They maintain that 

paying LMP for demand response in all hours, including off-peak hours, might not result 

in net benefits to customers, because the payments might be substantially more than the 

savings created by reducing the clearing price at that time.87 According to these 

commenters, net benefits are most likely to be positive and greatest when the supply 

curve is steepest, which typically occurs in highest-cost, peak hours.88 They argue that 

experience to date has shown positive benefits from demand response as a peak system 

resource, and that, during peak periods, the positive economics of demand response are 

generally very clear and a cost-benefit analysis may not be needed.89 Furthermore, some 

commenters suggest that limiting the hours in which demand response resources are paid 

86 See generally May 13, 2010 Comments of NYSCPB; NECA; Capital Power; 

NECPUC; Maryland Commission; New York Commission; NSTAR; National Grid; NE 

Public Systems. 

87 Capital Power May 13, 2010 Comments at 5; P3 May 13, 2010 Comments at 5. 

88 NECPUC May 13, 2010 Comments at 13; see also Sept. 13, 2010 Tr. 13:6-19 

(Mr. Keene); Maryland Commission May 13, 2010 Comments at 4-5. 

89 See, e.g., ACEEE Oct. 13, 2010 Comments 3-4. See also National Grid 

May 13, 2010 Comments at 4-5; NSTAR Electric Company (NSTAR) May 14, 2010 

Comments at 3; Maryland Commission May 13, 2010 Comments, submitting Analysis of 

Load Payments and Expenditures under Different Demand Response Compensation 

Schemes at 10-11 (discussing PJM analysis showing that paying demand response 

providers LMP for all hours after compensating LSEs for lost revenues would not benefit 

customers in general but that positive economic benefits results when demand response 

providers receive LMP during at least the top 100 hours (the highest priced energy 

hours)). 
Docket No. RM10-17-000 - 32 - 

 

LMP could help establish better baselines for measuring whether a demand response 

provider has, in fact, responded.90 

39. Some commenters who oppose paying LMP in all hours for demand response also 

suggest various approaches, including net benefits tests, for determining when LMP 

should apply. The stated purpose of any of these tests would be to determine the point at 

which the incremental payment for demand response equals the incremental benefit of the 

reduction in load; payment of LMP would apply only up to that point.91

40. Opposition to use of a net benefits test comes from several directions. Numerous 

commenters, primarily industrial consumers and some consumer advocates, argue that a 

net benefits test will reduce competition,92 have a “chilling effect” on the development of 

demand response,93 and be costly and complex to implement.94 Some commenters 

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

Comments at 8; ISO-NE May 13, 2010 Comments at 34; ACEEE Oct. 13, 2010 

Comments 4. But see ISO-NE May 13, 2010 Comments at 32-33 (contending that no 

baseline estimation methodology that relies upon historical customer meter data can 

accurately and reliably estimate an individual customer’s normal energy usage pattern if 

that customer responds frequently to price signals). 

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

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

92 Viridity Oct. 13, 2010 Comments at 14. 

93 NAPP Oct. 13, 2010 Comments at 2. 

94 Viridity Oct. 13, 2010 Comments at 14; NAPP Oct. 13, 2010 Comments at 3; 

AMP Oct. 13, 2010 Comments at 4; CAISO Oct. 13, 2010 Comments at 5 and 16. 
Docket No. RM10-17-000 - 33 - 

 

further state that no net benefits test is needed because the merit-order bid stack and 

market clearing function in a wholesale market, by definition, assures that the benefits to 

the system of demand response exceed the costs, and that the resource that clears is the 

lowest cost resource; otherwise, demand response would not dispatch ahead of competing 

alternatives.95

41. Another set of commenters argues that a net benefits test is unnecessary and 

inappropriate for different reasons.96 These commenters assert that a net benefits test 

would be very costly and difficult to implement, that RTOs and ISOs cannot implement a 

net benefits test,97 and that such a test is unnecessary with the economically efficient 

compensation level for demand response resources.98 According to Andy Ott of PJM, 

“[t]he implicit assumption in developing a benefits test for purposes of compensation 

would be that you could actually determine individual customers, whether they benefitted 

95 EDF Oct. 13, 2010 Comments at 2; Viridity Oct. 13, 2010 Comments at 10; 

ELCON Oct. 13, 2010 Comments at 3. 

96 See, e.g., Oct. 13, 2010 Comments of: Midwest TDUs at 4-5; NEPGA at 8, 

NJBPU at 2-3; NAPP at 2-3; P3; SPP at 3-4; SDG&E, SoCal Edison, and PG&E at 4-6; 

Viridity Energy at 2; ELCON at 2; AMP at 2; CDWR at 1, 4-5; CAISO at 4, 15; Detroit 

Edison at 2; Smart Grid Coalition at 2; Duke Energy at 2; EDF at 2; FTC at 1; EPSA at 4; 

Indicated New York TOs at 3; Midwest ISO at 9; Steel Manufacturers Ass’n at 3. 

97 P3 Oct. 13, 2010 Comments at 5. 

98 Sept. 13, 2010 Tr. 155:21-24 (Mr. Robinson); Sept. 13, 2010 Tr. 141-42 

(Mr. Centolella); Dr. Hogan Sept. 13, 2010 Comments at 5; Sept. 13, 2010 Tr. 60 

(Dr. Shanker); Sept. 13, 2010 Tr. 27 (Mr. Newton); SDG&E May 13, 2010 Comments at 

4. 
Docket No. RM10-17-000 - 34 - 

or not. That type of analysis would be very costly to implement.”99 Midwest ISO TOs 

further assert that it would be difficult to prescribe by regulation the hours in which 

demand response provides net benefits because system conditions and load patterns 

change across seasons and over time.100 NEPGA argues that compensating demand 

response resources at LMP whenever a reduction in consumption suppresses energy 

prices enough to provide net benefits to load is neither just and reasonable, nor in the 

public interest.101 NEPGA states that the Commission recognized in Amaranth 

Advisors102 that, if prices are suppressed below competitive, market levels, society as a 

whole is worse off. According to NEPGA, the goal is to get the right price—the 

economically efficient price produced by competitive markets. 

42. NYISO posits that a rule mandating payment of LMP-G avoids the need to 

develop a net benefits test. NYISO further states, however, that if the Commission 

decides to move forward with LMP for demand response, it should craft a net benefits 

test that minimizes any opportunities for distorting market prices or exploiting market 

inefficiencies. Citing support for Dr. Hogan’s arguments, NYISO states that “a net 

benefits test should ensure that the demand response program does not have negative net 

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

100 Midwest ISO TOs May 13, 2010 Comments at 16. 

101 NEPGA June 21, 2010 Comments at 1-2. 

102 120 FERC ¶ 61,085 (2007). 
Docket No. RM10-17-000 - 35 - 

benefits compared to no program at all. The criterion to apply would focus on the bidcost savings of generation and load, with the load bids adjusted for the effects of 

avoidance of the retail rate.”103

c) Standardization or Regional Variations in Compensation

43. With regard to potential regional variations for compensation mechanisms across 

RTO and ISO markets, many commenters, mostly those in support of the NOPR’s 

proposed compensation level, endorse standardization.104 Some parties, primarily 

industrial customers and some customer advocates, argue that, regardless of location, 

both demand response providers and generators provide a comparable service in terms of 

balancing supply and demand, as discussed above, and therefore should be comparably 

compensated at the LMP.105 They argue that fair, non-discriminatory markets must adapt 

and eliminate barriers to entry to the use and incorporation of traditional and non-

 103 NYISO Oct. 13, 2010 Comments at 3-4. 

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

AFPA; CDWR; Mayor Bloomberg; Consert; CDRI; CPower; DR Supporters; Derstine’s; 

Durgin; Electricity Committee; ELCON; Electrodynamics; ECS; EnerNOC; ICUB; 

IECA; IECPA; Irving Forest; Joint Consumers; Limington; Madison Paper; 

Massachusetts AG; NEMA; National Energy; National League of Cities; NJBPU; NAPP; 

Occidental; Okemo; Partners; Pennsylvania Department of Environment; Pennsylvania 

Commission; Rep. Chris Ross; Precision; PRLC; Raritan ; SDEG, SoCal; PG&E; 

Schneider; Governor O’Malley; Steel Manufacturers Ass’n; Verso; Viridity; Virginia 

Committee; Wal-Mart; Waterville. 

105 See, e.g., Steel Manufacturers Ass’n May 13, 2010 Comments at 12; NEMA 

May 13, 2010 Comments at 5. 
Docket No. RM10-17-000 - 36 - 

 

traditional resources—where non-traditional resources include actively-managed 

demand—in the dispatch and management of the electric system.106 They further posit 

that the lack of a unified policy itself represents a regulatory barrier to demand 

response,107 and that a consistent set of rules reduces the costs and complexities of 

demand response participation and facilitates training and transfer of personnel across 

regions.108 To that end, many commenters argue that adopting a unified approach to 

demand response compensation at the LMP, as opposed to allowing regional variation 

including payment of something less than LMP, is necessary to overcome the barriers to 

entry of demand response providers.109 Reciting the many benefits of demand reductions 

in energy use, these commenters support a compensation level that will provide a catalyst 

for private sector engagement in improved energy management practices. Viridity argues 

that the near absence of demand response participating in energy markets is powerful 

empirical proof that current, varying levels of compensation are inadequate—especially 

106 Steel Manufacturers Ass’n May 13, 2010 Comments at 12. 

107 PIO May 13, 2010 Comments at 9; DR Supporters Aug. 30, 2010 Comments at 

6-7. 

108 See, e.g., Alcoa May 13, 2010 Comments at 13. 

109 NECPUC May 13, 2010 Comments at 4; NYISO May 13, 2010 Comments at 

16. 
Docket No. RM10-17-000 - 37 - 

in markets that start with a market-based level of compensation and then reduce it by the 

generation portion of a customer’s retail rate (LMP – G).110 

44. Other commenters caution against standardizing the compensation level for 

demand response, pointing to regional differences in market structure, state regulatory 

environment, and resource mix.111

3. Commission Determination

45. The Commission acknowledges the diverging opinions of commenters regarding 

the appropriate level of compensation for demand response resources. As discussed 

above, commenters are split on this issue, with some in favor of paying the LMP for 

demand reductions in the day-ahead and real-time energy markets in all hours, others 

arguing that paying the LMP for demand reductions under any conditions will result in 

over-compensation or distortions in incentives to reduce consumption, and still others 

arguing that paying the LMP for demand reductions is only appropriate when it is 

reasonably certain to be cost-effective. 

 110 Viridity Energy May 13, 2010 Comments at 4. 

111 See, e.g., May 13, 2010 Comments of: ConEd at 3-4; Consumers Energy at 2; 

California Commission at 9; CMEEC at 2-3, 14-15; Detroit Edison at 3-5; Dominion at 8; 

Duke Energy at 4; EPSA at 6; Hess at 4; Indicated New York TOs at 3; Maryland 

Commission at 5; Midwest TDUs at 2, 6; Midwest ISO TOs at 16; National Grid at 5-6; 

11-12; New York Commission at 4, 11; NCPA at 3; NYISO at 2-3; ODEC at 27; PJM at 

5-6; SPP at 1. 
Docket No. RM10-17-000 - 38 - 

 

46. In the face of these diverging opinions, the Commission observes that, as the 

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

not technical, involve policy judgments that lie at the core of the regulatory mission.’”112 

We also observe that, in making such judgments, the Commission is not limited to 

textbook economic analysis of the markets subject to our jurisdiction, but also may 

account for the practical realities of how those markets operate.113 

47. As discussed further below, the Commission agrees with commenters who support 

payment of LMP under conditions when it is cost-effective to do so, as determined by the 

net benefits test described herein.114 We have previously accepted a variety of ISO and 

RTO proposals for compensation for demand response resources participating in 

112 Elec. Consumers Res. Council v. FERC, 407 F.3d 1232, 1236 (D.C. Cir. 2005) 

(quoting Pub. Util. Comm’n of the State of Cal. v. FERC, 254 F.3d 250, 254 (D.C. Cir. 

2001)); see also Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992). 

113 See Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 872 (D.C. Cir. 1993) (“It is 

the FERC’s established policy to consider equitable factors in designing rates, and to 

allow for phasing in of changes where appropriate. . . . It is hardly arbitrary or capricious 

so to temper the dictates of theory by reference to their consequences in practice.”); 

Vermont Dep’t of Pub. Serv. v. FERC, 817 F.2d 127, 135 (D.C. Cir. 1987) (“Indeed, ‘the 

congressional grant of authority to the agency indicates that the agency’s interpretation 

typically will be enhanced by technical knowledge.’” (quoting Nat’l Fuel Gas Supply 

Corp. v. FERC, 811 F.2d 1563, 1570 (D.C. Cir. 1987))); Columbia Gas Transmission 

Corp. v. FERC, 750 F.2d 105, 112 (D.C. Cir. 1984) (“the Commission is vested with 

wide discretion to balance competing equities against the backdrop of the public 

interest”). 

114 See generally May 13, 2010 Comments of NYSCPB; NECA; Capital Power; 

NECPUC; Maryland Commission; New York Commission; NSTAR; National Grid; NE 

Public Systems. 
Docket No. RM10-17-000 - 39 - 

 

organized wholesale energy markets. We find, based on the record here that, when 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. When these conditions are met, we find that payment of LMP 

to these resources will result in just and reasonable rates for ratepayers.115 As stated in 

the NOPR, we believe paying demand response resources the LMP will compensate 

those resources in a manner that reflects the marginal value of the resource to each RTO 

and ISO.116 

48. The Commission emphasizes that these findings reflect a recognition that it is 

appropriate to require compensation at the LMP for the service provided by demand 

response resources participating in the organized wholesale energy markets only when 

two conditions are met: 

 The first condition is that the demand response resource has the capability to 

provide the service , i.e., the demand response resource must be able to displace a 

115 The Commission’s findings in this Final Rule do not preclude the Commission 

from determining that other approaches to compensation would be acceptable when these 

conditions are not met. 

116 NOPR at P 12. 
Docket No. RM10-17-000 - 40 - 

 

generation resource in a manner that serves the RTO or ISO in balancing supply 

and demand. 

 The second condition is that the payment of LMP for the provision of the service 

by the demand response resource must be cost-effective, as determined by the net 

benefits test described herein. 

49. With respect to the first, capability-related condition, we note that a power system 

must be operated so that there is real-time balance of generation and load, supply and 

demand. An RTO or ISO dispatches just the amount of generation needed to match 

expected load at any given moment in time. The system can also be balanced through the 

reduction of demand.117 Both can have the same effect of balancing supply and demand 

at the margin either by increasing supply or by decreasing demand. 

50. With respect to the second cost-effectiveness condition, the record leads us to alter 

the proposal set forth in the NOPR in this proceeding. As various commenters explain, 

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

117 Andrew L. Ott Sept. 13, 2010 Statement at 1. 

Economic and Capacity-based demand response clearly provides benefits to 

regional grid operation and the wholesale market operation. . . . These 

demand resources provide benefits by providing valuable alternatives to 

PJM in maintaining operational reliability and in promoting efficient 

market operations. 

Id. at 1; see also CDRI May 13, 2010 Comments at 10; CDWR May 13, 2010 

Comments at 5; NJPBU May 13, 2010 Comments at 2. 
Docket No. RM10-17-000 - 41 - 

 

associated with the decreased amount of load paying the bill, depending on the change in 

LMP relative to the size of the energy market. As stated above, this is the billing unit 

effect of dispatching demand response resources.118 However, when reductions in LMP 

from implementing demand 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. 119 In comparison, when wholesale energy market customers pay a reduced 

price attributable to demand response that does not reduce total costs to customers more 

than the costs of paying LMP to the demand response dispatched, customers suffer a net 

loss. Implementation of the net benefits test described herein will allow each RTO or 

ISO to distinguish between these situations. 

51. This billing unit effect and the net benefits test through which it is addressed 

herein, warrant more detailed discussion. In the organized wholesale energy markets, the 

economic dispatch organizes offers from lowest to highest bid in order to balance supply 

118 As stated above, dispatching generation resources does not produce this billing 

unit effect because it does not result in a decrease of load. 

119 As a simple example, assume a market of 100 MW, with a current LMP of 

$50/MWh without demand response, and an LMP of $40/MWh if 5 MW of demand 

response were dispatched. Total payments to generators and load would be $4,000 with 

demand response compared to the previous $5,000. Even though, the reduced LMP is 

now being paid by less load, only 95 MW compared to 100 MW, the price paid by each 

remaining customer would decrease from $50/MWh to $42.11/MWh ($4,000/95). 

Therefore, the payment of LMP to demand resources is cost-effective. 
Docket No. RM10-17-000 - 42 - 

and demand, taking into account other parameters such as requirements for a generator to 

operate at a minimum level of output or minimum amount of time, reserve requirements 

and so forth. With dispatch of a demand response resource, the load also goes down, that 

is, the level of remaining load falls. However, the “supply” of resources deployed—

which includes both generation and demand response—does not fall. The total costs to 

the system for these resources must then be allocated among the reduced quantity of 

remaining load. 

52. In the absence of the net benefits test described herein, 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 next unit of generation is not sufficiently 

more expensive than the demand response resource, the decrease in LMP multiplied by 

the remaining load would not be greater than the costs of dispatching the demand 

response resource. In this situation, dispatching the demand response resource would 

result in a higher price to remaining customers than the dispatch of the next unit of 

generation in the bid stack. While the demand response resource appears cost 

competitive in the dispatch order, selection of the demand response resource increases the 

total cost per unit to remaining load, and it would not be cost-effective to dispatch the 

demand response resource. 
Docket No. RM10-17-000 - 43 - 

 

53. For this reason, the billing unit effect associated with dispatch of a demand 

response resource in an energy market must be taken into account in the economic 

comparison of the energy bids of generation resources and demand response resources. 

Therefore, rather than requiring compensation at LMP in all hours, the Commission 

requires the use of the net benefits test described herein to ensure that the overall benefit 

of the reduced LMP that results from dispatching demand response resources exceeds the 

cost of dispatching those resources. When the above-noted conditions of capability and 

of cost-effectiveness are met, it follows that demand response resources that clear in the 

day-ahead and real-time energy markets should receive the LMP for services provided, as 

do generation resources. LMP represents the marginal value of an increase in supply or a 

reduction in consumption at each node within an ISO or RTO, i.e., LMP reflects the 

marginal value of the last unit of resources necessary to balance supply and demand. 

Indeed, LMP has been the primary mechanism for compensating generation resources 

clearing in the organized wholesale energy markets since their formation. 120 

54. The Commission finds that demand response resources that clear in the day-ahead 

and real-time energy markets should receive the same market-clearing LMP as 

compensation in the organized wholesale energy markets when those resources meet the 

conditions established here as a cost-effective alternative to the next highest-bid 

120 See DR Supporters Aug. 30, 2010 Reply Comments (Kahn Affidavit at 2 

(footnote omitted)). 
Docket No. RM10-17-000 - 44 - 

 

generation resources for purposes of balancing the energy market. We discuss below the 

comments filed on these issues. 

55. Some commenters dispute that the foregone consumption of energy by demand 

response resources performs the service of balancing supply and demand in the energy 

market as would energy supplied by generators in the day-ahead and real-time energy 

markets, arguing that it is inappropriate to pay electric consumers to not consume.121 The 

Commission disagrees. Generation and load must be balanced by the RTOs and ISOs 

when clearing the day-ahead and real-time energy markets, and such balancing can be 

accomplished by changes in either supply or demand. The Commission finds that in the 

organized wholesale energy markets demand response can balance supply and demand as 

can generation. 

56. Commenters that oppose this finding do not adequately recognize a distinctive and 

perhaps unique characteristic of the electric industry. The electric industry requires 

instantaneous balancing of supply and demand at all times to maintain reliability. It is in 

this context that the Commission finds that demand response can balance supply and 

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

121 See, e.g., ISO-NE May 13, 2010 Comments at 3; APPA May 13, 2010 

Comments at 12; Capital Power May 13, 2010 Comments at 2; EPSA May 13, 2010 

Comments at 72. 
Docket No. RM10-17-000 - 45 - 

 

57. Due to a variety of factors, demand responsiveness to price changes is relatively 

inelastic in the electric industry and does not play as significant a role in setting the 

wholesale energy market price as in other industries. The Commission has recognized 

that barriers remain to demand response participation in organized wholesale energy 

markets. For example, in Order No. 719, the Commission stated: 

[D]espite previous Commission and RTO and ISO efforts to facilitate 

demand response, regulatory and technological barriers to demand response 

participation persist, thereby limiting the benefits that would otherwise 

result. A market functions effectively only when both supply and demand 

can meaningfully participate, and barriers to demand response limit the 

meaningful participation of demand in electricity markets.122 

Barriers to demand response participation at the wholesale level identified by 

commenters include the lack of a direct connection between wholesale and retail 

prices,123 lack of dynamic retail prices (retail prices that vary with changes in marginal 

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

incentives to invest in enabling technologies that would allow electric customers and 

122 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 83 (citing Federal Energy 

Regulatory Commission Staff, A National Assessment of Demand Response Potential 

(June 2009), found at http://www.ferc.gov/legal/staff-refports/06-09-demandresponse.pdf; Barriers to Demand Side Response in PJM (2009)). In compliance filings 

submitted by RTOs and ISOs and their market monitors pursuant to Order No. 719, as 

well as in responsive pleadings, parties have mentioned additional barriers, such as the 

inability of demand response resources to set LMP, minimum size requirements, and 

others. 

123 See, e.g., Monitoring Analytics May 13, 2010 Comments at 4-6. 
Docket No. RM10-17-000 - 46 - 

aggregators of retail customers to see and respond to changes in marginal costs of 

providing electric service as those costs change. For example, Dr. Kahn states: 

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.124 

Furthermore, EnerNOC states: 

On a more fundamental level, the inadequate compensation mechanisms in 

place today in wholesale energy markets fail to induce sufficient investment 

in demand response resource infrastructure and expertise that could lead to 

adequate levels of demand response procurement. Without sufficient 

investment in the development of demand response, demand response 

resources simply cannot be procured because they do not yet exist as 

resources. Such investment will not occur so long as compensation 

undervalues demand response resources.125 

58. The Commission concludes that paying LMP can address the identified barriers to 

potential demand response providers. 

59. Removing barriers to demand response will lead to increased levels of investment 

in and thereby participation of demand response resources (and help limit potential 

 124 DR Supporters Sept. 16, 2009 Comments filed in Docket No. EL-09-68-000 

(Kahn Affidavit at 6). See also id. at 4 (Customers offering to reduce consumption 

should be induced “to behave as they would if market mechanisms alone were capable of 

rewarding them directly for efficient economizing.”). 

125 EnerNOC May 13, 2010 Comments at 4; see also Alcoa May 13, 2010 

Comments at 4; Viridity May 13, 2010 Comments at 5-6. 
Docket No. RM10-17-000 - 47 - 

 

generator market power), moving prices closer to the levels that would result if all 

demand could respond to the marginal cost of energy. To that end, the Commission 

emphasizes that removing barriers to demand response participation is not the same as 

giving preferential treatment to demand response providers; rather, it facilitates greater 

competition, with the markets themselves determining the appropriate mix of resources, 

which may include both generation and demand response, needed by the RTO and ISO to 

balance supply and demand based on relative bids in the energy markets. In other words, 

while the level of compensation provided to each resource affects its willingness and 

ability to participate in the energy market, ultimately the markets themselves will 

determine the level of generation and demand response resources needed for purposes of 

balancing the electricity grid.126 

60. Another issue raised by a number of commenters, largely representing generators, 

is whether a lower payment based on LMP-G is the economically-efficient price that 

sends the proper price signal to a potential demand response provider. These commenters 

argue that, by not consuming energy, demand response providers already effectively 

receive “G,” the retail rate that they do not need to pay. They therefore contend that 

demand response providers will be overcompensated unless “G” is deducted from 

126 Generation and demand response resources have the potential to earn other 

revenues through bilateral arrangements, capacity markets where they exist, and ancillary 

services. 
Docket No. RM10-17-000 - 48 - 

 

payments made by the RTO or ISO for service in the wholesale energy market, resulting 

in a payment of LMP-G. These commenters suggest that payment of LMP-G will result 

in a price signal to demand response providers equivalent to the LMP (i.e., (LMP - G) + 

G). Similarly, some commenters argue that paying demand response resources the LMP 

will lead to a wholesale electricity price that is not economically efficient.127

61. The Commission disagrees with commenters who contend that demand response 

resources should be paid LMP-G in all hours. First, as discussed above, demand 

response resources participating in the organized wholesale energy markets can be costeffective, as determined by the net benefits test described herein, for balancing supply 

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

should also receive compensation at LMP. Second, such comments largely rely on 

arguments about economic efficiency, analogizing to incentives for individual generators 

to bid their marginal cost. These arguments fail to acknowledge the market imperfections 

caused by the existing barriers to demand response, also discussed above. 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.”128 

127 See NEPGA June 21, 2010 Comments at 1-2. 

128 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154. 
Docket No. RM10-17-000 - 49 - 

Furthermore, Dr. Kahn argues that 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 cost—both at 

competitively-determined levels.”129

62. Several other considerations also support this Commission conclusion. In the 

absence of market power concerns, the Commission does not inquire into the costs or 

benefits of production for the individual resources participating as supply resources in the 

organized wholesale electricity markets and will not here, as requested by some 

commenters, single out demand response resources for adjustments to compensation. 

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,”130 notwithstanding the particular costs of 

production of individual resources. Commenters have not justified why it would be 

appropriate for the Commission to continue to apply this approach to generation 

resources yet depart from this approach for demand response resources.

 129 DR Supporters Aug. 30, 2010 Reply Comments (Kahn Affidavit at 9-10). 

130 See New England Power Pool, 101 FERC ¶ 61,344, at P 35 (2002). 
Docket No. RM10-17-000 - 50 - 

63. In addition, we agree with the New York Commission that given the differences in 

retail rate structures across RTO footprints and even within individual states, requiring 

ISOs and RTOs to incorporate such disparate retail rates into wholesale payments to 

wholesale demand response providers would, even though perhaps feasible, create 

practical difficulties for a number of parties, including state commissions and ISOs and 

RTOs. Moreover, incorporating such rates could result in customer uncertainty as to the 

prevailing wholesale rate. 

64. Some arguments advocating paying LMP-G rather than LMP are based on an 

assumption that demand response resources need to purchase the energy in day-ahead 

markets or by other means and then “resell” the energy to the market in the form of 

demand response. However, as the Commission previously stated in EnergyConnect, the 

Commission does not view demand response as a resale of energy back into the energy 

market. 131 Instead, as the Commission also explained in EnergyConnect and in Order 

No. 719-A, the Commission asserts jurisdiction with respect to demand response in 

organized wholesale energy markets because of the effect of demand response and related 

RTO and ISO market rules on Commission-jurisdictional rates.132 

 131 See EnergyConnect, 130 FERC ¶ 61,031 at P 32. 

132 Id.; see also Order No. 719-A, FERC Stats. & Regs. ¶ 31,292, at P 47. 
Docket No. RM10-17-000 - 51 - 

65. With regard to the “buyers’ cartel” argument, the Commission disagrees that 

market rules establishing circumstances in which particular resources can participate and 

receive the LMP represents cooperative price setting. RTOs and ISOs evaluate the bids 

from generation and demand response resources to establish the order of dispatch which 

secures the most economical supplies needed, consistent with the reliability constraints 

imposed on the system. Imposing a cost-effectiveness condition does not convert this 

unit commitment process by the RTO or ISO into collusion among bidders, whether 

generation or demand response. Furthermore, the market rules administering such a 

program would be approved by this Commission and demand response resources would 

be subject to Commission-approved rules, just like any other participants in the organized 

wholesale energy markets. In addition, arguments that the subject of this proceeding is 

equivalent to the types of market manipulation investigated in Amaranth and ETP are 

groundless and without merit. In Amaranth, the trader was accused of engaging in a 

fraudulent scheme with scienter in connection with a jurisdictional transaction. Here, 

there is no such allegation, merely speculation that the Commission is somehow 

facilitating coordination of demand- side bidders in order to lower prices. 

66. Some commenters argue that demand response providers and generators should 

both be compensated at the market clearing price only if both are subject to the same 

market participation rules, penalty structures, testing requirements, and market 

monitoring provisions. The ISOs and RTOs already consider how to ensure 
Docket No. RM10-17-000 - 52 - 

 

comparability between demand response and generation in terms of market rules.133 The 

Commission agrees that as a general matter demand response providers and generators 

should be subject to comparable rules that reflect the characteristics of the resource, and 

expect ISOs and RTOs to continue their evaluation of their existing rules in light of this 

Final Rule and make appropriate filings with the Commission. 

67. Some commenters argue that the Commission should not impose a single pricing 

rule due to differences in market structure, state regulatory environment, and resource 

mix among the ISOs and RTOs. While such differences may exist, the commenters have 

not shown why such differences warrant a different compensation level among the ISOs 

and RTOs. As discussed above, regardless of the resource mix or the state regulatory 

environment, demand response, which satisfies the net benefits test described herein and 

can balance the system, is a cost-effective alternative to generation in the organized 

wholesale energy markets, and payment of LMP represents the marginal value of a 

decrease in demand. 

133 See PJM Interconnection, L.L.C., 129 FERC ¶ 61,081 (2009). 
Docket No. RM10-17-000 - 53 - 

B. Implementation of a Net Benefits Test

1. Comments

68. In response to questions that the Commission posed in the Supplemental NOPR, 

some commenters advocate a net benefits trigger based on a particular price threshold.134 

The NYISO currently has a static bid threshold of $75/MWh in its day-ahead demand 

response program.135 

69. However, other commenters assert that using a static threshold based on historical 

data misses the changes that occur within electricity markets across seasons and years, 

and that it is erroneous to assume that all demand response occurring above a certain 

threshold price (for instance, at the very highest loads or highest priced hours) will result 

in lower costs to wholesale customers and that demand response is not cost-effective at 

 134 For example, National Grid states that the threshold could be triggered by a 

particular price on the supply offer curve at which the additional cost of paying LMP to 

demand response resources is most likely to be outweighed by LMP reductions in the 

wholesale energy market as a result of the demand reductions produced by these 

resources. National Grid May 13, 2010 Comments at 6. Those in favor of a price 

threshold include National Grid (but allow the ISO or RTO to identify threshold based on 

analysis); NE Public Systems; NECPUC; ISO-NE (minimum offer price based on fixed 

heat rate, times a fuel price index); New York Commission (supports ISO-NE’s heat rate 

indexed price threshold). 

135 NYISO implements a day-ahead demand response program by which resources 

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

4.2.2.9 (“Day-Ahead Bids from Demand Reduction Providers to Supply Energy from 

Demand Reductions”) of NYISO’s Market Services Tariff. 
Docket No. RM10-17-000 - 54 - 

 

prices below the static threshold price.136 They argue that a static threshold offer price 

cannot easily adjust with changing energy market prices which may result in inefficient 

dispatch of demand resources, excluding demand response participation in hours when 

demand response can provide beneficial savings and including demand response 

participation in hours when there are no beneficial savings.137 The New York 

Commission supports a dynamic, rather than a static bid threshold, arguing that, while a 

static bid threshold helps prevent demand response providers from gaming the system by 

seeking compensation for reducing electricity consumption for reasons other than market 

prices, it can also limit participation in a demand response program because prices might 

not exceed the threshold on a consistent basis.138 

70. In a similar vein, some commenters suggest utilizing a dynamic bid threshold for 

determining when LMP payment would apply.139 For example, NECPUC favors use of a 

dynamic mechanism such as a price threshold based on a preset heat rate of marginal 

136 Sept. 13, 2010 Tr. 52-53 (Mr. Peterson); Massachusetts AG Oct. 13, 2010 

Comments at 23. 

137 Massachusetts AG Oct. 13, 2010 Comments (attachment, Demand Response 

Potential in ISO New England’s Day-Ahead Energy Market, Synapse Energy Economics, 

Inc. Oct. 11, 2010 at 9). See generally, NECPUC May 13, 2010 Comments at 18. 

138 Id.

139 National Grid May 13, 2010 Comments at 6; New York Commission May 13, 

2010 Comments at 10; Viridity May 13, 2010 Comments at 24. See generally NECPUC, 

New York Commission; ISO-NE; NSTAR; ACEEE; and NYSCPB Oct. 13, 2010 

Comments. 
Docket No. RM10-17-000 - 55 - 

 

generation and fuel price, like that currently used in New England’s Day-Ahead Load 

Response Program (DALRP),140 for the ISO-NE control area.141 National Grid suggests 

a trigger, determined by each ISO or RTO, using a particular price on the supply offer

curve at which the additional cost of paying LMP to demand resources is most likely to 

be outweighed by LMP reductions in the wholesale energy market as a result of the 

demand reductions.142

71. Still other commenters urge compensating demand response during an ISO- or 

RTO-defined period of critical high-cost hours in which it is cost-effective to pay LMP. 

These commenters argue that the effect of demand response on the market clearing price 

is greatest during a limited number of hours during the year.143 Therefore, identifying the 

hours in which to pay LMP to demand response resources could be used as a costeffective net benefits test with potential savings for ratepayers. According to PJM, 

140 The DALRP establishes a minimum offer price by approximating the variable 

cost component, in the form of a fuel cost, of a hypothetical peaking unit sufficiently high 

enough in the supply stack to ensure net benefits. On a monthly basis, this minimum 

offer price is reset to reflect the product of an appropriate fuel price index and a proxy 

heat rate. See NECPUC Oct. 13, 2010 Comments at 15. 

141 NECPUC Oct. 13, 2010 Comments at 14-16; NECPUC May 13, 2010 

Comments at 17. 

142 Id. at 5-6. 

143 Maryland Commission May 13, 2010 Comments at 4-5; see generally NSTAR, 

ACEEE and NYSCPB Oct. 13, 2010 Comments. 
Docket No. RM10-17-000 - 56 - 

 

further analysis is needed to ascertain the critical high-cost hours in which it will be costeffective to pay full LMP for demand response.144 

72. The Consumer Demand Response Initiative (CDRI) proposes a mechanism for 

determining what demand response resources are cost-effective in any hour.145 This 

dispatch algorithm tests whether the money necessary to compensate demand response is 

less than the cost savings due to the decreased market-clearing price resulting from 

implementing demand response. In a sense, it is a dynamic cost/benefit analysis built 

into the dispatch algorithm. This cost/benefit analysis accounts for the billing unit effect. 

The billing unit effect occurs when demand response resources are dispatched to balance 

the system; the associated reduction in load results in fewer MWh of realized load 

(demand) paying for the sum of generator and demand response resource MWh, so load 

pays an effective rate which is greater than the LMP set to procure resources. Some 

commenters assert that if the Commission finds that a net benefits test is needed, it should 

144 Maryland Commission May 13, 2010 Comments at 4 n.9. 

145 The approach submitted by CDRI was developed for implementation in the 

ISO-NE day-ahead energy market. The discussion here is generalized to be applicable to 

any energy market that uses security-constrained economic dispatch to select the leastcost resources and establish a market-clearing price. 
Docket No. RM10-17-000 - 57 - 

 

require organized wholesale energy market operators to implement a proposal similar to 

that submitted by CDRI.146

73. Under the proposal submitted by CDRI, the demand response bids are part of the 

supply stack to which a security-constrained economic dispatch process is applied. All 

demand response bids that result in a lower price to customers, including consideration of 

the reduced number of billing units, are selected while those bids that raise the price, as 

compared to selecting the next generation bid in the supply stack, are not. This dispatch 

algorithm, as proposed, would be used by the ISO or RTO to determine a revised LMP 

that would be charged to load. The revised LMP creates a surplus (or over-collection) of 

revenue for the ISO or RTO that is then distributed to the LSEs through a settlement 

algorithm with the goal of holding LSEs harmless.147

74. During the September 2010 Technical Conference, Dr. Ethier of ISO-NE stated 

that a dynamic net benefits test done on an hourly basis that examines the effect of the 

demand response resource on LMPs, similar to that proposed by CDRI, would become 

146 PIO July 27, 2010 Comments at 6; Massachusetts AG Oct. 13, 2010 Comments 

at 11; Viridity Oct. 13, 2010 Comments at 2. See CDRI May 13, 2010 Comments for a 

full description of the algorithms. 

147 CDRI May 13, 2010 Comments Attachment B at 18. CDRI states that the 

dispatch and settlement algorithms “could be employed to evaluate dispatch and assure 

customer benefits, without being employed to perform allocations and settlements.” 

CDRI Oct. 13, 2010 Comments at 4. 
Docket No. RM10-17-000 - 58 - 

 

very complicated to implement and require essentially an iterative process.148 Dr. Ethier 

states that the ISO would have to run the dispatch model to formulate a base LMP with 

no demand response and then re-run it with demand response in the market; however 

those two iterations alone do not “cover the whole waterfront” in terms of the possible 

iterations required. According to Dr. Ethier, the ISO could dispatch too much demand 

response the first time, or if the ISO first rejected dispatching demand response, it may 

need to go back and dispatch smaller amounts of demand response to determine what 

would happen to the LMPs. Dr. Ethier stated that it is unclear where the ISO would stop 

the iteration of testing the impact on LMPs of dispatching demand response.149 Andy Ott 

of PJM also stated during the technical conference that implementing a net benefits test 

would entail an iterative process that would be costly and difficult, if the RTO could even 

do it.150 

75. Other commenters do not support the use of a net benefits test, but state that if one 

is adopted it should be based on general principles that RTOs and ISOs must apply to 

their systems in determining when LMP payments will apply.151 A few commenters 

148 Sept. 13, 2010 Tr. 80-81 (Dr. Ethier). 

149 Id.

150 Sept. 13, 2010 Tr. 82:16-21 (Mr. Ott). 

151 See generally AEP, Midwest ISO, Occidental, NYISO, Constellation Oct. 13, 

2010 Comments. 
Docket No. RM10-17-000 - 59 - 

 

articulated specific criteria to be used in a net benefits test.152 AEP believes that the 

objective of an incentive payment for demand response resources on the basis of broad 

market benefits can be achieved through a review of the costs and benefits of individual 

providers. Constellation states that any net benefits test should be based on the difference 

between the value consumers receive from energy and the cost of energy production.153

76. ISO-NE argues that a net benefits test should be based on economic efficiency, the 

sum of producer and consumer surplus, which suggests that demand response incentives 

ought to be provided to encourage demand reductions when the cost of energy production 

exceeds the value of consumption, and to encourage usage when the cost of energy 

production is less than the value of consumption. ISO-NE further states that a net 

benefits test that focuses solely on consumer savings ignores the value lost by consumers 

when energy consumption levels are reduced in response to incentive payments. ISO-NE 

posits that any variant of a LMP payment should be limited to a very small number of 

152 See, e.g., Midwest ISO October 13, 2010 Comments at 9-14 and Table 1 

(setting forth comprehensive list of benefits and costs of demand response by type of 

market participants); Occidental October 13, 2010 Comments at 4-5 (any net benefits test 

must take into consideration offsetting variables, such as higher LMPs in the subsequent 

periods where demand rebound increases market price, and capacity market price 

effects); AEP October 13, 2010 Comments at 3-4 (AEP does not recommend the use of a 

societal benefits component (i.e., health, environment, or employment efforts)). 

153 Constellation October 13, 2010 Comments at 3-4. 
Docket No. RM10-17-000 - 60 - 

 

high-priced hours to minimize the economic distortions and avoid significant 

administrative complexities.154

77. A few commenters state that policies affecting energy prices will also impact 

capacity prices because generation owners with fixed costs must raise capacity price 

offers to remain financially viable at lower energy prices.155 ISO-NE and Pepco argue, 

therefore, that the Commission should adopt a net benefits test that considers the impact 

of demand response compensation on both energy and capacity markets.156 According to 

ISO-NE, when considering capacity market impacts under full-LMP compensation, longterm increases in capacity prices in response to suppressed LMPs offset consumer 

savings and leaves consumers worse off over time.157 Robert Weishaar of the DR 

Supporters argues that properly compensating demand response should flatten the load 

profile and decrease the forecast of load projections, which would reduce capacity 

clearing prices.158 Donald Sipe of CDRI adds that to the extent that scarcity revenues are 

154 ISO-NE Oct. 13, 2010 Comments at 4-5 and 21. 

155 See, e.g., Sept. 13, 2010 Tr. 94:13-22 (Dr. Shanker); Sept. 13, 2010 Tr. 98:4-24 

(Mr. Peterson); Sept. 13, 2010 Tr. 99:2-7 (Mr. Sunderhauf); ISO-NE Oct. 13, 2010 

Comments at 5. 

156 Sept. 13, 2010 Tr. 99:1-24 (Mr. Sunderhauf); ISO-NE Oct. 13, 2010 Comments 

at 5. 

157 ISO-NE Oct. 13, 2010 Comments at 6. 

158 Sept. 13, 2010 Tr. 103-104 (Mr. Weishaar). 
Docket No. RM10-17-000 - 61 - 

not sufficient, capacity markets are designed to ensure that a generator’s capital costs are 

recovered; in a forward market that looks ahead as load adjusts, one can see whether a 

resource is performing or not. For purposes of long-run reliability, he argues, as long as 

compensation is in the amount that is necessary to induce new investment and reflects 

market value, the argument that demand response in the bid stack will push out 

generators is only true if generators are higher priced than the consumer resources that 

are brought by demand response.159 

2. Commission Determination

78. For the reasons discussed previously, the Commission is requiring each RTO and 

ISO to implement the net benefits test described herein to determine whether a demand 

response resource is cost-effective. More specifically, the Commission is adopting two 

distinct requirements with respect to the net benefits test. While we find that the 

integration of the billing unit effect into the RTO/ISO dispatch processes has the potential 

to more precisely identify when demand response resources are cost-effective, we also 

recognize and understand the position of several of the RTOs and ISOs that modification 

of their dispatch algorithms may be difficult in the near term. Given these technical 

difficulties, we will require to RTOs and ISO to perform (1) the net benefits test 

described below to determine on a monthly basis under which conditions it is cost-

 159 Sept. 13, 2010 Tr. 106:16-24 (Mr. Sipe). 
Docket No. RM10-17-000 - 62 - 

 

effective to pay full LMP to demand resources; 160 and (2) a study of the feasibility of 

developing a mechanism for determining the cost-effective dispatch of demand resources.

79. First we direct each RTO and ISO to undertake an analysis on a monthly basis, 

based on historical data and the RTO’s or ISO’s previous year’s supply curve, to identify 

a price threshold to estimate where customer net benefits, as defined herein, would occur. 

The RTO or ISO should determine the threshold price corresponding to the point along 

the supply stack for each month beyond 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, and update the calculation monthly. The ISOs and 

RTOs are to determine monthly threshold prices based on historical data. The threshold 

prices would be updated monthly as new data becomes available and posted on the RTO 

web site. For example, the RTO should conduct an analysis of supply curves for January 

through December 2010 to be used as a starting point to establish threshold prices for 

2011. Those numbers would be updated monthly during 2011 for significant changes in 

resource availability and fuel prices, with the process repeated monthly to reflect that 

160 There will be inherent differences in the supply curves determined by each 

RTO and ISO under the net benefits test required herein due to decisions the RTOs and 

ISOs must make based on supply data for their regions, the mathematical methods each 

RTO and ISO chooses to use for smoothing the supply curves, the certainty of changes in 

supply due to outages in each region, local generation heat rates, and the choice of 

relevant fuel price indices. 
Docket No. RM10-17-000 - 63 - 

 

month’s data from the previous year.161 The supply curve analysis should be updated 

monthly, by the 15th day of the preceeding month in advance of the effective date, to 

allow demand response providers as well as other market participants to plan, while still 

reflecting current supply conditions.162

80. Based on historical evidence and analysis submitted in this proceeding, the 

threshold point along the supply stack for each month will fall in the area where the 

supply curve becomes inelastic, rather than the extreme steep portion at the peak or in the 

flat portion of the supply curve.163 In other words, LMP will be paid to demand response 

resources during periods when the nature of the supply curve is such that small decreases 

161 The ISOs and RTOs are to select a representative supply curve for the study 

month, smooth the supply curve using numerical methods, and find the price/quantity 

pair above which a one megawatt reduction in quantity that is paid LMP would result in a 

larger percentage decrease in price than the corresponding percentage decrease in 

quantity (billing units). Beyond that point, a reduction in quantity everywhere along an 

upward sloping supply curve would be cost-effective. 

162 Thus, the test is to determine where: (Delta LMP x MWh consumed) > 

(LMPNEW x DR); where LMPNEW is the market clearing price after demand response 

(DR) is dispatched and Delta LMP is the price before DR is dispatched minus the market 

clearing price after DR is dispatched. 

163 Supply elasticity is defined as the percentage change in quantity supplied 

divided by the percentage change in price. When the elasticity is less than or equal to 

one, supply is considered inelastic. So, for example, in the inelastic portion of the supply 

curve, a reduction in quantity supplied by one percent will result in more than a one 

percent decrease in price. Using the terms related to demand response compensation, the 

billing unit effect (percentage change in quantity supplied) will be more than offset by 

lower LMP (percentage change in price), thus resulting in lower prices for wholesale 

load. 
Docket No. RM10-17-000 - 64 - 

 

in generation being called to serve load will result in price decreases sufficient to offset 

the billing unit effect. The Massachusetts AG noted that the actual supply stack has 

locally flat and steep sections at all bid prices. We recognize that the threshold price 

approach we adopt here may result in instances both when demand response is not paid 

the LMP but would be cost-effective and when demand response is paid the LMP but is 

not cost-effective. We accept this result given the apparent computational difficulty of 

adopting a dynamic approach that incorporates the billing unit effect in the dispatch 

algorithms at this time.164

81. We direct each RTO and ISO to file its analysis as supporting documentation to 

the accompanying tariff revisions with the Commission on or before July 22, 2011, along 

with proposed tariff revisions necessary to comply with this Final Rule. The filing 

should include the data, analytical methods and the actual supply curves used to 

determine the monthly threshold prices for the last 12 months to show how the RTO or 

ISO would calculate the curves.165 The Commission-approved net benefits test 

methodology must be posted on the RTO or ISO’s website, with supporting 

documentation. The RTO or ISO must also post the price threshold levels that would 

have been in effect in the previous 12 months. In addition, when the net benefits test 

164 See supra note 114. 

165 See supra P 6. 
Docket No. RM10-17-000 - 65 - 

becomes effective, the supply curve analysis for the historic month that corresponds to 

the effective month should be updated for current fuel prices, unit availabilities, and any 

other significant changes to historic supply curve and posted on the RTO website (for 

example, the supply curve analysis for the March price threshold would be posted in midFebruary). Finally, the supply curve analyses for all months should be updated and 

posted on the RTO website if a significant change to the composition or slope of the 

historic monthly curves occurs, such as extended outages or retirements not previously 

reflected.

82. Some commenters argue that that there would be no need for a net benefits test if 

demand response resources were paid LMP-G, while others argue that use of a net 

benefits test otherwise undermines our decision to compensate demand response 

resources at the LMP. As stated above, the Commission finds that when a demand 

response resource participating in an organized wholesale energy market is capable of 

balancing supply and demand in the energy market and is cost-effective, as determined 

by the net benefits test described herein, that demand response resource should receive 

the same compensation, the LMP, as a generation resource when dispatched. We see no 

reason to reduce that compensation simply to avoid the use of the net benefits test that 

will ensure benefits to load.

83. Nearly every participant in the net benefits panel at the September 13, 2010 

Technical Conference agreed that it would be counterproductive to defer to the RTO or 
Docket No. RM10-17-000 - 66 - 

 

ISO stakeholder process to determine when demand response provides net benefits 

without explicit guidance from the Commission.166 We believe that this result, and the 

guidance provided in this Final Rule will provide for timely improvements to RTO and 

ISO market pricing for demand response resources participating in organized wholesale 

energy markets. 

84. In addition to requiring each RTO and ISO to construct the net benefits test 

described herein, the Commission also imposes a second requirement for each RTO and 

ISO to undertake a study, examining the requirements for and impacts of implementing a 

dynamic approach to determine when paying demand response resources LMP results in 

net benefits to customers. We believe that integration of the billing unit effect into RTO 

and ISO dispatch algorithms holds promise for more accurately integrating demand 

resources on a dynamic basis into the dispatch of the RTOs and ISOs. In theory, this 

could help ensure that the cost-effective level of demand response resources is dispatched 

or scheduled into the organized wholesale energy markets. Given the potential of 

software enhancements to determine the amount of cost-effective demand response 

resources purchased in the day-ahead and real- time energy markets, we believe that it 

166 “[G]etting this decision resolved is an impediment to all the other stuff we want 

to do with price response to demand, and DR generally in our market . . . so until we get 

through this, we’re not going to make much progress . . . the implication of that is if you 

send something back that leaves a lot of room for debate, it’s going to be a while on all 

those other things.” Testimony of Robert Ethier, Vice President, Market Design, ISO-NE, 

Sept. 13, 2010 Tr. at 136. 
Docket No. RM10-17-000 - 67 - 

 

would be useful for the Commission to know more about the feasibility of and 

requirements for implementing improvements to the existing dispatch algorithms. 

Therefore, we will require each RTO and ISO to undertake a study, either individually or 

collectively, examining the requirements for, costs of, and impacts of implementing a 

dynamic net benefits approach to the dispatch of demand resources that takes into 

account the billing unit effect in the economic dispatch in both the day-ahead and realtime energy markets, and to file the results of their study with the Commission on or 

before September 21, 2012.

85. ISO-NE and Pepco suggest that the net benefits test also consider the impact of 

demand response compensation on both energy and capacity markets. However, this 

Final Rule is focused only on organized wholesale energy markets, not capacity 

markets.167 Given the differences in capacity markets among the ISOs and RTOs, the 

record in this proceeding provides neither a reasonable basis for including capacity 

market effects in net benefits calculations in the energy markets, nor have ISO-NE and 

Pepco provided a methodology for taking such effects into account. Indeed, in some 

167 Additionally, the arguments presented for focusing on the effect of demand 

response compensation in wholesale energy markets on capacity markets were not 

convincing – that decreases in energy market revenues by generators will be recouped in 

the form of increased capacity prices. First, they fail to consider how the increased 

participation by demand resources could actually increase potential suppliers in the 

capacity markets by reducing barriers to demand resources, which would tend to drive 

capacity prices down. Second, they did not examine the way in which capacity markets 

already may take into account energy revenues. 
Docket No. RM10-17-000 - 68 - 

cases, the capacity markets already reflect energy and ancillary service revenue in 

determining capacity prices.

C. Measurement and Verification

1. NOPR Proposal

86. In the NOPR, the Commission explained that demand response curtailment is a 

reduction in actual load as compared to the demand response provider’s expected level of 

electricity consumption.168 The NOPR did not address measurement and verification of 

demand response. 

87. Each RTO and ISO with a demand response program has procedures for the 

measurement and verification of demand response. These procedures include techniques 

to establish a customer baseline for each demand response participant. This customer 

baseline then becomes the basis for measuring the quantity of demand response delivered 

to the wholesale market. Customer baselines are often based on historic load 

information, such as an average of five of the last ten comparable days’ hourly load 

profile. Techniques vary among RTOs and ISOs and most have several techniques that 

may be allowed, depending on the demand response provider’s characteristics.169

 168 Demand Response Compensation in Organized Wholesale Energy Markets, 

FERC Stats. & Regs. ¶ 32,656, at P 1 (2010). 

169 See, e.g., ISO/RTO Council, North American Wholesale Electricity Demand 

Response 2010 Comparison, under the tab for “Performance Evaluation Methods” 

(continued...) 
Docket No. RM10-17-000 - 69 - 

2. Comments

88. Commenters assert that the integrity of a demand response program is heavily 

dependent on measurement and verification.170 Some commenters raise the issue that 

paying LMP in all hours presents a significant challenge to the accurate measurement and 

verification of demand response.171 ISO-NE argues that when a market participant 

schedules demand reductions for many consecutive days, baselines may become stale—

no longer reflecting a customer’s “normal” electricity usage.172 ISO-NE goes on to argue 

that “it is necessary to limit the number of hours or days that a demand resource could 

clear in the energy market so that the customer’s ‘normal’ load can be estimated” to 

avoid the potential for manipulation.173 In the context of the Commission’s proposal to 

pay demand response the LMP in all hours, ISO-NE goes on to advocate requiring 

 

(http://www.isorto.org/atf/cf/%7B5b4e85c6-7eac-40a0-8dc3-

003829518ebd%7D/IRC%20DR%20M&V%20STANDARDS%20IMPLEMENTATION

%20COMPARISON%20(20100524).XLS). 

170 Illinois CUB May 14, 2010 Comments at 16-17; Joint Consumers May 13, 

2010 Comments at 12; P3 May 12, 2010 Comments at 38; Westar May 13, 2010 

Comments at 3. 

171 See, e.g., ISO-NE May 13, 2010 Comments at 32. 

172 Id.

173 ISO-NE May 13, 2010 Comments at 34. ISO-NE identifies several practices 

that, in its view, might be deployed by a demand responder to receive payment when it 

has not, in fact, responded to price. ISO-NE states that observations of such behavior in 

the Fall of 2007 led it to limit the hours demand response offers could clear the market. 

Citing ISO New England Inc., Docket No. ER08-538-000 (February 5, 2008 filing). 

ISO-NE May 13, 2010 Comments at 32-34. 
Docket No. RM10-17-000 - 70 - 

rt this 

 

demand response to establish baselines by purchasing energy in the day-ahead market as 

a way to overcome its concerns with statistical baseline methods.174 ISO-NE IMM 

makes similar arguments and recommendations.175 Westar also appears to suppo

approach.176 

89. Similarly, CPower notes that with some baseline methods, paying LMP in all 

hours could reward demand responders for any shift in demand from the baseline, not just 

shifting load from high LMP hours to low LMP hours, or could simply shift load from 

day-to-day in different hours to affect the calculation of actual curtailment, which it 

labels “checkerboarding.” However, CPower believes that the capability of consumption 

management to shed or shift load for many hours is well into the future, and perhaps not a 

current concern. CPower also believes that baseline standards along with market 

monitoring will develop to meet these concerns.177 

90. ISO-NE IMM asserts that “[if] the Commission adopts any proposal that permits 

the use of an administrative baseline it should explicitly state that any demand reductions 

offered into Commission-jurisdictional markets that are not genuine, even if they are the 

174 Id.

175 ISO-NE IMM May 13, 2010 Comments at 9-13 and Attachment A. 

176 Westar May 13, 2010 Comments at 3. 

177 CPower May 13, 2010 Comments at 4-5. 
Docket No. RM10-17-000 - 71 - 

result of ‘normal’ activity . . . may be violations of the Commission’s anti-manipulation 

rules and subject to penalties thereunder.”178

91. Noting the ongoing efforts by the industry and the North American Energy 

Standards Board (NAESB) on measurement and verification, EnerNOC takes the view 

that resolution of customer baseline issues should not delay the issuance of this Final 

Rule.179 

92. Finally, some commenters assert that measurement and verification methods 

should not be standardized, but left to the RTOs and ISOs to reflect the unique features of 

their individual energy, ancillary services, and capacity markets.180

3. Commission Determination

93. The Commission agrees with commenters who assert that measurement and 

verification are critical to the integrity and success of demand response programs. 

Without a determination of a demand response provider’s expected use of power, the 

ISOs and RTOs cannot determine whether that provider has in fact reduced its energy 

 178 ISO-NE IMM May 13, 2010 Comments at 14 (footnotes omitted) (ISO-NE 

MMU also notes that “[i]n assessing whether demand reductions are genuine, allowance 

should be made for non-performance analogous to a generator’s forced outage.”). 

179 EnerNOC, Inc. May 13, 2010 Comments at 4. 

180 ECS May 13, 2010 Comments at 3; Indicated New York TOs May 13, 2010 

Comments at 2-3; Midwest ISO May 13, 2010 Comments at 17, 21; National Grid 

May 13, 2010 Comments at 11-12; NSTAR May 14, 2010 Comments at 9; PPL May 13, 

2010 Comments at 4. 
Docket No. RM10-17-000 - 72 - 

 

usage when paid to do so. Towards that end, all the RTOs and ISOs already have 

measurement and verification protocols for their demand response programs.181 In 

addition, we have adopted Phase I standards for measurement and verification published 

by the North American Energy Standards Board, 182 and have recognized the potential 

benefits of the continuing NAESB effort to craft Phase II standards with more substantive 

and consistent wholesale standards for measurement and verification.183

94. A number of commenters maintain that compensating demand response resources 

at the LMP during all hours could make determining baselines for demand response 

providers exceedingly difficult. However, the impact of our adopting the net benefits test 

described herein is that the LMP will not be paid to demand response resources in all 

hours. Accordingly, implementation of this Final Rule would not appear to prevent the 

determination of appropriate baselines. Nonetheless, we direct ISOs and RTOs to review 

their current 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. 

Specifically, we direct each RTO and ISO to include as part of the compliance filing 

181 See, e.g., PJM Interconnection, L.L.C., 123 FERC ¶ 61,257 (2008). 

182Standards for Business Practices and Communication Protocols for Public 

Utilities, Final Rule, 131 FERC ¶ 61,022 (2010). 

183 Id., at P 32-34. 
Docket No. RM10-17-000 - 73 - 

required herein, 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 as necessary to ensure the performance 

of each demand response resource. If necessary, each RTO and ISO should propose any 

changes needed to ensure that measurement and verification of demand response will 

adequately capture the performance (or non-performance) of each participating demand 

response market participant to be consistent with the requirements of this Final Rule. 

95. Finally, we agree with ISO-NE IMM that demand reductions that are not genuine 

may be violations of the Commission’s anti-manipulation rules.184 Allegations of such 

behavior will continue to be investigated, and when appropriate, sanctions will be 

brought to bear. 

D. Cost Allocation

1. NOPR Proposal

96. In response to the NOPR and September 13, 2010 Technical Conference, many 

commenters argue that, in order to determine the justness and reasonableness of the 

proposed compensation level, the corresponding cost allocation must be considered.185 

 184 18 CFR 1.c (2010). 

185 ISO-NE May 13, 2010 Comments at at 39-40; see also May 13, 2010 

Comments of: AEP at 6-10; CAISO at 6; ConEd at 2; Hess at 3; ICC at 12; PJM at 8; 

Potomac Economics at 3; Massachusetts AG at 11; Midwest ISO TOs at 5-6; Midwest 

TDUs at 13; EEI at 5; NECPUC at 12, 22; NECA at 11; RRI at 6; SDG&G at 3-4. 
Docket No. RM10-17-000 - 74 - 

More specifically, these commenters raise concerns regarding how the costs associated 

with payment of LMP for demand response will be allocated, or assigned, within an ISO 

or RTO. Several commenters assert that the issues of cost allocation and net benefits are 

inherently linked, so that the Commission must address both issues together.186 

2. Comments

97. Comments reveal five specific methods for cost allocation: (1) assignment of 

costs to the load serving entity (LSE) associated with the demand response provider, 

(2) assignment of costs broadly to all purchasing customers, (3) bifurcated assignment of 

costs with some directly assigned to a LSE and others assigned broadly, (4) directly 

assign the cost for demand response compensation to the retail customers that bid the 

demand response into the wholesale market, and (5) the settlement method proposed by 

CDRI, which incorporates the cost of demand response into the dispatch algorithm. 

Some commenters argue not for a specific method, but for each regional entity to select 

and employ a method of its own,187 and a few other commenters assert that the 

Commission need not address cost allocation in this proceeding.188 

 186 As further addressed below, several commenters assert that the costs of demand 

response compensation should be borne by only those market participants determined to 

have benefitted from the subject load reduction, as determined by some type of net 

benefits test. See, e.g., May 13, 2010 Comments of: ISO-NE at 5-6; NECPUC at 22; 

PJM at 12-14; P3 at 37-38. 

187 EPSA May 12, 2010 Comments at 67; Midwest TDUs May 13, 2010 

Comments at 1; ODEC May 14, 2010 Comments at 5; Potomac Economics May 14, 2010 

(continued...) 
Docket No. RM10-17-000 - 75 - 

 

98. Some commenters argue that costs should be assigned to the LSE associated with 

the demand response provider because it is this entity that receives the full benefit of 

demand response.189 Others argue that costs should be assigned broadly to all purchasing 

customers because of the concept of cost causation.190 Cost causation dictates that the 

costs of demand response should be allocated directly to those entities that benefit from 

the demand response service provided.191 Another method presented involves a 

bifurcated assignment of costs, with some directly assigned to a LSE and others assigned 

broadly.192 The fourth method suggested is to directly assign the costs of demand 

Comments at 9-10; RRI May 13, 2010 Comments at 4; SoCal Edison May 13, 2010 

Comments at 4 (advocating that the local regulatory authority is the proper entity to 

regulate cost allocation); Viridity May 13, 2010 Comments at 24; EnerNOC Sept. 13, 

2010 Comments at 1; Midwest TDUs Sept. 13, 2010 Comments at 2. 

188 Massachusetts AG May 13, 2010 Comments at 9-10. 

189 PJM May 13, 2010 Comments at 15; Midwest ISO May 13, 2010 Comments at 

6; CAISO May 13, 2010 Comments at 6; Detroit Edison May 13, 2010 Comments at 3-4; 

EEI May 13, 2010 Comments at 5; NUSCO May 13, 2010 Comments at 2; National Grid 

Sept. 13, 2010 Comments at 2-3; Midwest ISO Oct. 13, 2010 Comments at 4. 

190 NECPUC May 13, 2010 Comments at 22; DC OPC May 13, 2010 Comments 

at 4; PCA Sept. 10, 2010 Comments at 4; Steel Manufactures Ass’n Sept. 13, 2010 

Comments at 5; Ohio Commission Sept. 13, 2010 Comments at 4; Wal-Mart Sept. 14, 

2010 Comments at 3. 

191 PJM May 13, 2010 Comments at 9; NECPUC May 13, 2010 Comments at 22; 

PCA Sept. 10, 2010 Comments at 4. 

192 PJM May 13, 2010 Comments at 12; ISO-NE May 13, 2010 Comments at 5. 
Docket No. RM10-17-000 - 76 - 

response to the retail customer that bid the demand response into the wholesale market.193 

Lastly, the settlement algorithm proposed by CDRI adjusts upward the day-ahead price 

paid by the customers that participate in the day-ahead energy market to account for these 

costs.194 

3. Commission Determination

99. When a demand response provider curtails, the RTO experiences a reduction in 

load with a corresponding reduction in billing units through which the RTO derives 

revenue. When the two conditions discussed above 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 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, a method is 

needed to ensure that RTOs and ISOs recover the costs of obtaining demand response. 

100. 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. 

 193 DC OPC May 13, 2010 Comments at 4. It concedes that this could be a 

complex undertaking and would result in billing a retail customer for energy that did not 

consume. Id.

194 CDRI, Integration of Demand Response Into Day Ahead Markets (Attachment 

B), May 13, 2010 Comments at 16. 
Docket No. RM10-17-000 - 77 - 

 

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. Allocating 

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 will reasonably allocate the costs of demand 

response to those who benefit from the lower prices produced by dispatching demand 

response.195

101. We reject the various other methods of cost allocation suggested by commenters. 

Assignment of all costs to the LSE associated with the demand response provider, as 

suggested by some commenters, would not include others who benefit from the demand 

response. Bifurcated assignment of costs to the LSE and to others appears to represent an 

arbitrary division of cost responsibility without regard to the degree to which each 

receives benefits. 

195 This approach is consistent with long-standing judicially-endorsed cost 

allocation principles. See, e.g., Midwest ISO Transmission Owners v. FERC, 373 F.3d 

1361, 1368, 1370-71 (D.C. Cir. 2004); see also Illinois Commerce Comm’n v. FERC, 

576 F.3d 470, 476 (7th Cir. 2009). 
Docket No. RM10-17-000 - 78 - 

102. We therefore find just and reasonable the requirement 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 reduces the market price for energy at the time when the demand response 

resource is committed or dispatched. Accordingly, each RTO and ISO is required to 

make a compliance filing on or before July 21, 2011 that either demonstrates that its 

current cost allocation methodology appropriately allocates costs to those that benefit 

from the demand reduction or proposes revised tariff provisions that conform to this 

requirement.

E. Commission Jurisdiction

1. Comments

103. Some commenters, including several state commissions and LSEs, express 

concern about whether and how standardizing demand response compensation in the 

wholesale market will affect treatment of demand response at the retail level. They assert 

that the issue of demand response compensation is fundamentally intertwined with retail 

rates, ratepayer issues, and state jurisdictional concerns.196 Some commenters note 

general concerns about the need for federal and state level coordination. They assert that 

 196 See, e.g., CAISO May 13, 2010 Comments at 12; PJM May 13, 2010 

Comments at 8 (appropriate and efficient demand response compensation may require 

coordination between the Commission, retail regulatory authorities, competitive retail 

suppliers, and other RTOs). 
Docket No. RM10-17-000 - 79 - 

 

many states have taken significant steps to install advanced meters and implement 

programs to encourage efficient use of energy and that the success of state-level efforts 

should be a factor in deciding whether and how to implement demand response programs 

in the wholesale market.197 According to these commenters, a Commission-mandated 

compensation level could have the unintended consequence of retarding the expansion of 

price-responsive demand at the retail level.198 

104. Other commenters flatly question the Commission’s jurisdiction to set the 

compensation for demand response in wholesale energy markets. They argue that it is 

within the purview of retail regulatory authorities to take into account local policies and 

concerns, and the types of demand response being offered, when determining the 

appropriate compensation level.199 Indeed, the California Commission seeks clarification 

197 See ISO-NE IMM May 13, 2010 Comments at 6. 

198 Illinois Commission May 13, 2010 Comments at 8; PJM May 13, 2010 

Comments at 23; EEI May 13, 2010 Comments at 4; Capital Power May 13, 2010 

Comments at 5; ODEC May 13, 2010 Comments at 60; Steel Producers May 13, 2010 

Comments at 2. 

199 See Illinois Commission May 13, 2010 Comments at 13; CAISO May 13, 2010 

Comments at 12-13; PJM IMM May 13, 2010 Comments at 5 (“The assertion that 

demand side participants should be paid full LMP, regardless of their retail tariff rate, 

because the current approach of paying LMP minus G represents an intervention into 

retail rate design, cannot be correct. The entire demand side program exists only because 

of the disconnect between wholesale and retail rates. The assertion that the program 

design should not account for the details of retail rate design leads to the conclusion that 

there should be no demand side program at all.”); NECPUC May 13, 2010 Comments at 

25 (“As energy market customers benefit most from both a well-functioning wholesale 

(continued...) 
Docket No. RM10-17-000 - 80 - 

 

that this Commission does not seek to regulate retail customer rates or seeks LSE 

oversight authority traditionally exercised by states. The California Commission asserts 

that this Commission’s actions concerning CAISO’s Proxy Demand Resource tariff 

filing200 illustrates that demand response settlement mechanisms are within the authority 

of the California Commission.201 

105. Other commenters foresee retail regulatory authorities effectively taking an endrun around any Commission-mandated compensation level by adjusting retail rate design 

market and robust participation in retail programs, a balance between these two segments 

is essential. Compensation that increases demand response resource participation in the 

wholesale market should not be so generous, from the perspective of the customer, that it 

makes participation in retail programs pale in comparison.”); SDG&E, SoCal Edison, and 

PG&E May 13, 2010 Comments at 4 (“[M]andating that ISOs take on settlement 

responsibility or precluding any retail settlement between retail customers, LSEs or DRPs 

would intrude on retail jurisdictional authority and contravenes the premise of separation 

outlined in Order 719.”); Consumers Energy May 13, 2010 Comments at 3; Detroit 

Edison May 13, 2010 Comments at 4. 

200 See California Independent System Operator Corp., 132 FERC ¶ 61,045 

(2010).

201 California Commission May 13, 2010 Comments at 9-10. 1. See also SDG&E, 

SCE, PG&E May 13, 2010 Comments at 2 (“[T]he Commission should clarify that its 

order does not preclude LRAs from administering retail revenue settlements between 

retail customers, Load Serving Entities (LSEs) and Demand Response Providers (DRPs) 

associated with DR participation in wholesale markets.”). 
Docket No. RM10-17-000 - 81 - 

 

or prohibiting jurisdictional end-use customers from participating in wholesale market 

opportunities available to demand response resources.202 The Illinois Commission 

argues: 

[W]hen load serving entities are vertically integrated with generation 

regulated under state authority . . . any non-zero payment to a demand 

response resource reduces the revenues to generators under the state 

regulatory authority. The result is a leakage of money to an entity outside 

of the state’s regulatory authority. Therefore, retail rates to all customers 

may need to be increased in order to recover the costs to generators that 

would have otherwise been recovered through the purchase of electricity, 

but instead went to the payment of a demand response resource. Therefore, 

compensating demand response resources may increase the likelihood that 

state commissions will prohibit the participation of demand response 

resources in the jurisdictions.203

106. Similarly, PJM states that the prohibition devised by retail regulatory authorities 

with jurisdiction over smaller distributors that deliver 4 million MWh or fewer per annum 

202 See PJM May 13, 2010 Comments at 24; PJM May 13, 2010 Comments at 18 

(It is reasonable to assume that each retail regulatory authority in PJM will re-examine 

the impact of load reduction based on wholesale compensation equal to the LMP, 

including cost allocation, on the LSEs subject to its jurisdiction, and potentially re-align 

retail market rules affecting economic load response participation.); Delaware 

Commission and NECPUC May 13, 2010 Comment at 25; OMS May 13, 2010 

Comments at 7 (state commissions and LSEs have significant concerns that the potential 

costs for non-participating customers may exceed the benefits that ARCs can provide to 

their states and to participating customers, so state commissions will have a significant 

disincentive to support the participation of ARCs in RTO energy markets and in their 

states if LMP compensation is adopted). 

203 Illinois Commission May 13, 2010 Comments at 15. 
Docket No. RM10-17-000 - 82 - 

 

may entail the revocation of previously provided permission to participate in some or all 

of the wholesale market opportunities for demand resources.204 

107. Some commenters further posit that, even where retail regulatory authorities do 

not prohibit or limit demand response participation, they may make adjustments to the 

retail rate, which affect the ultimate compensation that the retail customer will be paid for 

its demand reductions.205 For example, the OMS asserts, 

If the Commission were to adopt the proposed rule, state commissions and 

LSEs could correct this distorted price signal by revising retail tariffs for 

customers that do business with [aggregators of retail customers] in order to 

charge the retail rate to participating customers for energy which was not 

consumed or metered as a result of load reductions.206 

108. Another set of commenters, especially generators, assert that due to the disconnect 

between wholesale and retail issues related to demand response, Commission-mandated 

payments for demand response will fail to address true barriers to demand response, 

which exist, they assert, at the retail level. These commenters argue that the 

Commission’s actions in this proceeding ignore the fact that the primary barrier to 

demand response is the disconnect between retail and wholesale prices and, according to 

these commenters, the remedy resides at the retail -- not wholesale -- level where there is 

204 PJM May 13, 2010 Comments at 20-21. 

205 CAISO May 13, 2010 Comments at 4. 

206 OMS May 13, 2010 Comments at 3. See also EEI May 13, 2010 Comments at 

4. 
Docket No. RM10-17-000 - 83 - 

 

a lack of dynamic pricing.207 For example, some commenters recognize that the lack of 

retail real-time pricing is a barrier to demand response participation but further assert that 

whatever changes the Commission makes to wholesale demand response (where there is 

real-time pricing) will not address that fundamental problem.208 

109. On the other hand, some commenters, such as commercial customers, wholly 

reject challenges to the Commission’s authority to set the compensation level for demand 

response occurring in organized wholesale energy markets.209 They assert that the FPA 

gives the Commission broad authority to correct market flaws, including compensation 

for demand response.210 

207 Calpine May 13, 2010 Comments at 3. 

208 See EPSA May 13, 2010 Comments at 7 (“The NOPR incorrectly attempts to 

resolve retail market barriers to DR participation (i.e., lack of dynamic pricing) through a 

wholesale pricing fix.”); RRI Energy May 13, 2010 Comments at 5 (“The NOPR is 

essentially trying to use an inefficient wholesale solution to remedy a retail problem. The 

NOPR does not attempt to address (nor should it attempt to address) the various retail 

rate structures that demand response providers in various regions of the country face.”); 

The Brattle Group May 13, 2010 Comments at 8 (“[T]he appropriate avoidable retail 

generation rate is best done through agreements between the LSE and the curtailment 

service provider under the oversight of the relevant retail regulating authority. This 

approach . . . avoids requiring the RTO to sort through potentially complicated retail rate 

structures.”); Steel Manufacturers Ass’n May 13, 2010 Comments at 9 (“[T]here is no 

rational basis for the Commission, or RTOs, to adopting varying demand response 

participation or compensation rules based on the retail pricing method of otherwise 

qualified participating loads.”). 

209 DR Supporters Aug. 30, 2010 Reply Comments at 4. 

210 Id.
Docket No. RM10-17-000 - 84 - 

 

110. Some commenters further argue that any disconnect between wholesale and retail 

issues relevant to demand response should not negate the Commission’s efforts in this 

proceeding. They argue that dynamic retail pricing, retail shopping opportunities and the 

potential for retail energy efficiency measures are no substitute for adequate wholesale 

demand response compensation and the deployment of demand response measures akin 

to a generator.211

111. Moreover, some commenters assert that, while the Commission has authority to 

establish the compensation level for demand response in the wholesale market, the 

Commission cannot require subtraction of retail rate components from the LMP rate, 

reasoning that retail rates reflect a myriad of local concerns beyond the Commission’s 

jurisdiction. These commenters assert that LMP reflects the wholesale value of the 

demand response service provided and that proponents of the LMP-G formulation 

(subtracting a portion of the retail rate) seek to draw the Commission into a review of 

retail rate matters beyond its purview.212 Additionally, these commenters point to the 

difficulty of isolating the generation component of the retail rate from other components, 

such as transmission, distribution, and overhead. They argue that different retail rate 

contracts reflect different costs of generation, depending on local circumstances existing 

211 Wal-Mart May 13, 2010 Comments at 11. 

212 Viridity June 18, 2010 Comments at 13. 
Docket No. RM10-17-000 - 85 - 

at the time the contract was executed, and that retail rate structures reflect a wide range of 

competing considerations, such as cost causation, the impact of rate design on 

employment, and the state of the local economy, all of which are appropriately left to 

state commissions. These commenters posit that, instead of tailoring the wholesale rate, 

i.e., LMP, to retail rate conditions, it is better to get the wholesale rate right in the first 

instance and then allow retail rate structures adjust as needed to wholesale market 

conditions.213 According to Dr. Kahn, accounting for the retail rate in this Final Rule 

would “ignore the proper scope of the Commission’s regulatory responsibilities, the fact 

that the great majority of retail rate designs are economically inefficient and that it is 

retail rates that should not be permitted to undermine efficient wholesale rates rather than 

the reverse.”214

2. Commission Determination

112. We begin by rejecting challenges to the Commission’s authority to set the 

compensation level for demand response in organized wholesale energy markets. Section 

205 of the FPA tasks the Commission with ensuring that all rates and charges for or “in 

connection with” the transmission or sale for resale of electric energy in interstate 

commerce, and all rules and regulations “affecting or pertaining to” such rates or charges 

 213 Viridity June 18, 2010 Comments at 14. 

214 DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 4). 
Docket No. RM10-17-000 - 86 - 

 

are just and reasonable.215 The Commission has previously explained that it has 

jurisdiction over demand response in organized wholesale energy markets, because it 

directly affects wholesale rates. 216 

113. For this reason, the Commission has jurisdiction to regulate the market rules under 

which an ISO or RTO accepts a demand response bid into a wholesale market.217 

Furthermore, as discussed above, the Commission’s actions in this proceeding are 

consistent with Congressional policy requiring federal level facilitation of demand 

response, because this Final Rule is designed to remove barriers to demand response 

participation in the organized wholesale energy markets.

114. Nevertheless, we recognize that jurisdiction over demand response is a complex 

matter that lies at the confluence of state and federal jurisdiction. By issuing this Final 

Rule, the Commission is not requiring actions that would violate state laws or 

regulations. The Commission also is not regulating retail rates or usurping or impeding 

state regulatory efforts concerning demand response.

115. We acknowledge that many barriers to demand response participation exist and 

that our ability to address such barriers is limited to the confines of our statutory 

authority. At the same time, the FPA requires the Commission to ensure that the rates 

215 16 U.S.C. 824d (2006). 

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

217 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 52. 
Docket No. RM10-17-000 - 87 - 

charged for energy in wholesale energy markets are just, reasonable, and not unduly 

discriminatory or preferential. The Commission has the authority, indeed the 

responsibility, to assure that wholesale rates are just and reasonable. Therefore, we 

disagree with commenters who would have the Commission refrain from acting on 

demand response compensation in the organized wholesale energy markets because of 

the potential actions that state retail regulatory authorities may or may not take. As we 

note above, this Final Rule is not intended to usurp state authority or impede states from 

taking any actions within their authority. Rather, the Commission is taking action here to 

fulfill its statutory mandate to ensure just, reasonable, and not unduly discriminatory or 

preferential wholesale rates. 

V. Information Collection Statement

116. The Office of Management and Budget (OMB) requires that OMB approve certain 

information collection and data retention requirements imposed by agency rules.218 

Therefore, the Commission is submitting the proposed modifications to its information 

collections to OMB for review and approval in accordance with section 3507(d) of the 

Paperwork Reduction Act of 1995.219

117. OMB’s regulations require approval of certain information collection 

requirements imposed by agency rules. Upon approval of a collection(s) of information, 

 218 5 CFR § 1320.11(b) (2010). 

219 44 U.S.C. § 3507(d) (2006). 
Docket No. RM10-17-000 - 88 - 

OMB will assign an OMB control number and an expiration date. Respondents subject 

to the filing requirements of a rule will not be penalized for failing to respond to these 

collections of information unless the collections of information display a valid OMB 

control number. 

118. The Commission is submitting these reporting requirements to OMB for its review 

and approval under section 3507(d) of the Paperwork Reduction Act. Comments are 

solicited on the Commission’s need for this information, whether the information will 

have practical utility, the accuracy of provided burden estimates, ways to enhance the 

quality, utility, and clarity of the information to be collected, and any suggested methods 

for minimizing the respondent’s burden, including the use of automated information 

techniques. 

Burden Estimate and Information Collection Costs: The estimated Public Reporting 

burden and cost for the requirements contained in the final rule follow. 

FERC-516 

Data 

Collection 

Number of 

Respondents 

(a) 

No. of 

Responses 

Per 

Respondent 

Per Year 

(b) 

Hours Per 

Response 

(c) 

Total 

Annual 

Hours 

(d) [a*b*c] 

Compliance 

filing, 

including tariff 

provisions and 

analysis (onetime filing, due 

7/22/2011) 

 6 (RTOs and 

ISOs) 

1 (one-time 

filing) 300 

1,800 (onetime filing)

Study on 6 (RTOs and 1(one-time 2,000 12,000 (one-
Docket No. RM10-17-000 - 89 - 

dynamic net 

benefits 

approach (onetime filing, due 

9/21/2012) 

ISOs) filing) time filing)

Monthly 

update to price 

threshold and 

web posting 

(due monthly, 

starting after 

the compliance 

filing due 

7/22/2011) 

6 (RTOs and 

ISOs) 12 50 3,600

 In Year 1, the following requirements are imposed220: (1) compliance filing due 

on or before July 22, 2011, and (2) monthly updates (for months 5-12, and starting after 

the compliance filing). The total corresponding burden hours are estimated to be: 1,800 

hrs. + (8 filings * 6 respondents * 50 hrs./filing), for a total of 4,200 hours. The 

corresponding total cost is estimated to be: 4,200 hours * $220/hour, for a total of 

$924,000. 

 In Year 2, (a) the monthly update to the price threshold, and (b) the study on 

dynamic net benefits approach (due on or before September 21, 2012) are imposed. The 

corresponding total burden is estimated to be 3,600 + 12,000 hours, for a total of 15,600 

 220 The one-time study is due on or before September 21, 2012. For the purpose of 

the burden and cost estimates, we are including all of the burden and cost related to the 

study in Year 2, although filers may perform part of the work in Year 1. 
Docket No. RM10-17-000 - 90 - 

hours. The corresponding total cost estimate is: 15,600 hours * $220/hour, for a total of 

$3,432,000. 

 In Year 3, the monthly update to the price threshold is imposed. The 

corresponding total burden and cost are estimated to be 3,600 hours and $792,000 (3,600 

hours * $220/hour). 

Title: FERC-516, “Electric Rate Schedules and Tariff Filings” 

Action: Proposed Collections. 

OMB Control No: 1902-0096. 

Respondents: Business or other for profit, and/or not for profit institutions. 

Frequency of Responses: One-time filings for (a) the compliance filing, due on or before 

July 22, 2011, and (b) the study on dynamic net benefits approach, due on or before 

September 21, 2012. In addition, monthly updates to the price threshold and web posting 

will be required starting after the compliance filing. 

Necessity of the Information: The information from FERC-516 enables the Commission 

to exercise its statutory obligation under sections 205 and 206 of the FPA. FPA section 

205 specifies that all rates and charges, and related contracts and service conditions for 

wholesale sales and transmission of energy in interstate commerce be filed with the 

Commission and must be “just and reasonable.” In addition, FPA section 206 requires 

the Commission, upon complaint or its own motion, to modify existing rates or services 

that are found to be unjust, unreasonable, unduly discriminatory or preferential. 
Docket No. RM10-17-000 - 91 - 

119. In Order No. 719, the Commission emphasized the importance of demand 

response as a vehicle for improving the competitiveness of organized wholesale 

electricity markets and ensuring supplies of energy at just, reasonable and not unduly 

discriminatory or preferential rates. This Final Rule addresses the need for organized 

wholesale energy markets to provide compensation to demand response resources on a 

comparable basis to supply-side resources when demand response resources are 

comparable to supply-side resources, so that both supply and demand can meaningfully 

participate. This final rule establishes a specific compensation approach for demand 

response resources participating in organized wholesale energy markets, administered by 

RTOs and ISOs. Each Commission-approved RTO and ISO that has a tariff provision 

providing for participation of demand response resources in its organized wholesale 

energy market must: (a) pay demand response resources the market price (full LMP) for 

energy (when found to be cost-effective as determined by the net benefits test described 

herein), (b) submit a one-time compliance filing, (c) perform monthly updates to the 

Price Threshold, and (d) submit a one-time Study on Dynamic Net Benefits Approach. 

120. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street NE, Washington, 

DC 20426 [Attention: Ellen Brown, Information Clearance Officer, Office of the 

Executive Director, e-mail: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202) 

273-0873]. Comments on the requirements of the final rule may also be sent to the 
Docket No. RM10-17-000 - 92 - 

Office of Information and Regulatory Affairs, Office of Management and Budget, 

Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory 

Commission]. For security reasons, comments to OMB should be submitted by e-mail 

to: oira_submission@omb.eop.gov. Comments submitted to OMB should include 

Docket Number RM10-17 and OMB Control Number 1902-0096. 

VI. Environmental Analysis

121. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.221 The Commission concludes that neither an Environmental 

Assessment nor an Environmental Impact Statement is required for this Final Rule under 

section 380.4(a)(15) of the Commission’s regulations, which provides a categorical 

exemption for approval of actions under sections 205 and 206 of the FPA relating to the 

filing of schedules containing all rates and charges for the transmission or sale subject to 

the Commission’s jurisdiction, plus the classification, practices, contracts, and 

regulations that affect rates, charges, classifications, and services.222

 221 Regulations Implementing the National Environmental Policy Act, Order 

No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles 

1986-1990 ¶ 30,783 (1987). 

222 18 CFR § 380.4(a)(15) (2010). 
Docket No. RM10-17-000 - 93 - 

VII. Regulatory Flexibility Act

122. The Regulatory Flexibility Act of 1980 (RFA)223 generally requires a description 

and analysis of final rules that will have significant economic impact on a substantial 

number of small entities. The RFA mandates consideration of regulatory alternatives that 

accomplish the stated objectives of a rule and that minimize 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.224 

The SBA has established a size standard for electric 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 megawatt hours.225 ISOs and RTOs, not small 

entities, are impacted directly by this rule. 

123. California Independent System Operator Corp. (CAISO) is a non-profit 

organization with over 54,000 megawatts of capacity and over 25,000 circuit miles of 

power lines. 

 223 5 U.S.C. § 601-612 (2006). 

224 13 CFR § 121.101 (2010). 

225 13 CFR § 121.201, Sector 22, Utilities. 
Docket No. RM10-17-000 - 94 - 

124. New York Independent System Operator, Inc. (NYISO) is a non-profit 

organization that oversees wholesale electricity markets, dispatches over 500 generators, 

and manages a nearly 11,000-mile network of high-voltage lines. 

125. PJM Interconnection, L.L.C. (PJM) is comprised of more than 600 members 

including power generators, transmission owners, electricity distributors, power 

marketers, and large industrial customers, serving 13 states and the District of Columbia. 

126. Southwest Power Pool, Inc. (SPP) is comprised of 61 members serving over 6.2 

million households in nine states and has almost 50,000 miles of transmission lines. 

127. Midwest Independent Transmission System Operator, Inc. (Midwest ISO) is a 

non-profit organization with over 145,000 megawatts of installed generation. Midwest 

ISO has over 57,000 miles of transmission lines and serves 13 states and one Canadian 

province. 

128. ISO New England, Inc. (ISO-NE) is a regional transmission organization serving 

six states in New England. The system is comprised of more than 8,000 miles of highvoltage transmission lines and over 350 generators. 

129. The Commission believes this rule will not have a significant economic impact on 

a substantial number of small entities, and therefore no regulatory flexibility analysis is 

required. 
Docket No. RM10-17-000 - 95 - 

VIII. Document Availability

130. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A, 

Washington DC 20426. 

131. From the Commission's Home Page on the Internet, this information is available 

on eLibrary. The full text of this document is available on eLibrary in PDF and 

Microsoft Word format for viewing, printing, and/or downloading. To access this 

document in eLibrary, type the docket number excluding the last three digits of this 

document in the docket number field. 

132. User assistance is available for eLibrary and the Commission’s website during 

normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-

208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference Room at 

(202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

IX. Effective Date and Congressional Notification

133. This Final Rule will become effective on [INSERT DATE 30 DAYS AFTER 

DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The Commission has 
Docket No. RM10-17-000 - 96 - 

determined, with the concurrence of the Administrator of the Office of Information and 

Regulatory Affairs, Office of Management and Budget, that this rule is not a “major rule” 

as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of 

1996. 

By the Commission. Commissioner Moeller dissenting with a separate statement 

 attached. 

( S E A L ) 

Kimberly D. Bose, 

Secretary. 
Docket No. RM10-17-000 - 97 - 

 In consideration of the foregoing, the Commission proposes to amend Part 35, 

Chapter I, Title 18, Code of Federal Regulations, as follows. 

PART 35—FILING OF RATE SCHEDULES AND TARIFFS 

1. The authority citation for Part 35 continues to read as follows: 

Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 

7101-7352. 

2. Amend § 35.28 as follows: 

Add a new paragraph (g)(1)(v). 

§ 35.28 Non-discriminatory open access transmission tariff. 

* * * * *

(v) Demand response compensation in energy markets. Each Commissionapproved independent system operator or regional transmission organization that 

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

resource in the energy market by reducing consumption of electric energy from 

their expected levels in response to price signals must: 

(A) pay to those demand response resources the market price for energy for these 

reductions when these demand response resources have the capability to balance 

supply and demand and when payment of the market price for energy to these 

resources is cost-effective as determined by a net benefits test accepted by the 

Commission; 

(B) 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 reduces the market price for energy at the time 

when the demand response resource is committed or dispatched. 

Note: The following appendix will not be published in the Code of Federal Regulations. 
Docket No. RM10-17-000 - 98 - 

APPENDIX 

List of Commenters

Alcan Primary Products Corp. (Alcan) 

Alcoa Inc. (Alcoa) 

Alliance for Clean Energy New York, Inc. (ACENY) 

Alliance to Save Energy (Alliance) 

American Chemistry Council (ACC) 

American Clean Skies Foundation 

American Council for an Energy-Efficient Economy (ACEEE) 

American Electric Power Service Corporation (AEP) 

American Forest & Paper Association (AFPA) 

American Municipal Power, Inc. (AMP) 

American Public Power Association (APPA) 

American Wind Energy Association (AWEA) 

ArcelorMittal USA Inc. (ArcelorMittal) 

Battelle Pacific Northwest Laboratories (Battelle) 

Boston College Law School Administrative Law Class (BC Law) 

California Department of Water Resources State Water Project (CDWR) 

California Independent System Operator Corporation (CAISO) 

California Public Utilities Commission (California Commission) 

Calpine Corp. (Calpine) 

Capital Power Corporation (Capital Power) 

Cities of Anaheim, Azusa, Banning, Colton, Pasadena, and Riverside, California (Six 

Cities) 

Citizens for Pennsylvania’s Future (PennFuture) 

Coalition of Midwest Transmission Customers (CMTC) 

Connecticut Municipal Electric Energy Cooperative (CMEEC) 

Consert Inc. (Consert) 

Conservation Law Foundation (CLF) 

Consolidated Edison Solutions, Inc. (ConEd) 

Constellation Energy Commodities Group, Inc. (Constellation) 

Consumer Demand Response Initiative (CDRI) 

Consumer Power Advocates (CPA) 

Consumers Energy Company (Consumers Energy) 

CPG Advisors, Inc. (CPG) 

CPower, Inc. (CPower) 

Crane & Co., Inc. (Crane) 

Delaware Public Service Commission (Delaware Commission) 
Docket No. RM10-17-000 - 99 - 

Demand Response and Smart Grid Coalition (Smart Grid Coalition) 

Demand Response Supporters (DR Supporters) 

Derstine’s Inc. (Derstine’s) 

Detroit Edison Company (Detroit Edison) 

Direct Energy Services, LLC (Direct Energy) 

Dominion Resources Services, Inc. (Dominion) 

Dr. Alfred E. Kahn (Dr. Kahn) 

Dr. Charles J. Cicchetti (Dr. Cicchetti) 

Dr. Roy J. Shanker (Dr. Shanker) 

Dr. William W. Hogan (Dr. Hogan) 

Duke Energy Corporation (Duke Energy) 

Durgin and Crowell Lumber Co., Inc. (Durgin) 

Edison Electric Institute (EEI) 

Edison Mission Energy (Edison Mission) 

Electric Power Supply Association (EPSA) 

Electricity Committee 

Electricity Consumers Resource Council (ELCON) 

Electrodynamics, Inc. (Electrodynamics) 

Energy Curtailment Specialists, Inc. (ECS) 

EnergyConnect (EnergyConnect) 

Energy Future Coalition (EFC) 

EnerNOC, Inc. (EnerNOC) 

Environmental Defense Fund (EDF) 

Exelon Corporation (Exelon) 

Federal Trade Commission (FTC) 

FirstEnergy Service Company (FirstEnergy) 

GDF SUEZ Energy North America, Inc. (GDF) 

Hess Corporation (Hess) 

Illinois Citizens Utility Board (Illinois CUB) 

Illinois Commerce Commission (ICC) 

Independent Power Producers of New York, Inc. (IPPNY) 

Indicated New York Transmission Owners (Indicated New York TOs) 

Industrial Energy Consumers of America (IECA) 

Industrial Energy Consumers of Pennsylvania (IECPA) 

Intergrys Energy Services, Inc. (Intergrys) 

International Power America, Inc. (IPA) 

Irving Forest Products, Inc. (Irving Forest) 

ISO New England Inc. (ISO-NE) 

ISO-NE Internal Market Monitor (ISO-NE IMM) 

Jiminy Peak Mountain Resort, LLC 
Docket No. RM10-17-000 - 100 - 

Joint Consumer Advocates (Joint Consumers) 

Limington Lumber (Limington) 

Madison Paper Industries (Madison Paper) 

Maryland Governor Martin O’Malley (Governor O’Malley) 

Maryland Public Service Commission (Maryland Commission) 

Massachusetts Attorney General (Massachusetts AG) 

Midwest Independent Transmission System Operator, Inc. (Midwest ISO) 

Midwest ISO Transmission Owners (Midwest ISO TOs) 

Midwest TDUs 

Mirant Corporation (Mirant) 

Monitoring Analytics, LLC (PJM IMM) 

National Electrical Manufactures Association (NEMA) 

National Energy Marketers Association (NEM) 

National Grid USA (National Grid) 

National League of Cities (NLC) 

Natural Gas Supply Association (NGSA) 

New England Conference of Public Utilities Commissioners (NECPUC) 

New England Consumer Advocates (NECA) 

New England Power Generators Association Inc. (NEPGA) 

New England Power Pool Participants Committee (NEPOOL) 

New England Public Systems (NE Public Systems) 

New Jersey Board of Public Utilities (NJBPU) 

New York Independent System Operator, Inc. (NYISO) 

New York Mayor Michael R. Bloomberg (Mayor Bloomberg) 

New York State Consumer Protection Board (NYSCPB) 

New York State Public Service Commission (New York Commission) 

North America Power Partners LLC (NAPP) 

Northeast Utilities Services Company (NUSCO) 

Northern California Power Agency (NCPA) 

NSTAR Electric Company (NSTAR) 

Occidental Chemical Corp. (Occidental) 

Office of the People’s Counsel for the District of Columbia (DC OPC) 

Okemo Mountain Resort (Okemo) 

Old Dominion Electric Cooperative (ODEC) 

Organization of Midwest ISO States (OMS) 

Partners HealthCare (Partners) 

Pennsylvania Department of Environmental Protection (PA Department of Environment) 

Pennsylvania Office of Consumer Advocate (PCA) 

Pennsylvania Public Utility Commission (Pennsylvania Commission) 

Pennsylvania State Representative Chris Ross (Rep. Ross) 
Docket No. RM10-17-000 - 101 - 

Pepco Holdings, Inc. (PHI) 

PJM Interconnection, L.L.C. (PJM) 

PJM Power Providers Group (P3) 

Potomac Economics, Ltd. (Potomac Economics) 

PPL Parties (PPL) 

Praxair, Inc. (Praxair) 

Precision Lumber, Inc. (Precision) 

Price Responsive Load Coalition (PRLC) 

PSEG Companies (PSEG) 

Public Interest Organizations (PIO) 

Public Utilities Commission of Ohio (Ohio Commission) 

Raritan Valley Community College (Raritan) 

Robert J. Borlick (Mr. Borlick) 

RRI Energy, Inc. (RRI) 

San Diego Gas & Electric Company (SDG&E) 

Schneider Electric USA, Inc. (Schneider) 

Southern California Edison Company (SoCal Edison) 

Southwest Power Pool, Inc. (SPP) 

Steel Manufacturers Association (Steel Manufacturers Ass’n) 

Steel Producers (SP) 

Tendrill Networks, Inc. (Tendrill) 

The Brattle Group 

The E Cubed Company, L.L.C. (E3) 

University of California, San Diego (UCSD) 

Utility Economic Engineers (UEE) 

Verso Paper Corp. (Verso) 

Virginia Committee for Fair Utility Rates (Virginia Committee) 

Viridity Energy, Inc. (Viridity) 

Wal-Mart Stores, Inc. (Wal-Mart) 

Waterville Valley Ski Resort Inc. (Waterville) 

Westar Energy, Inc. (Westar) 

Wisconsin Industrial Energy Group (WIEG) 
 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

 

Demand Response Compensation in Docket No. RM10-17-000 

Organized Wholesale Energy Markets 

 (Issued March 15, 2011) 

 

MOELLER, Commissioner, dissenting: 

 While the merits of various methods for compensating demand response were 

discussed at length in the course of this rulemaking, nowhere did I review any comment 

or hear any testimony that questioned the benefit of having demand response resources 

participate in the organized wholesale energy markets. On this point, there is no debate. 

The fact is that demand response plays a very important role in these markets by 

providing significant economic, reliability, and other market-related benefits. 

However, in a misguided attempt to encourage greater demand response 

participation in the organized energy markets, today’s Rule imposes a standardized and 

preferential compensation scheme that conflicts both with the Commission’s efforts to 

promote competitive markets and with its statutory mandate to ensure supplies of electric 

energy at just, reasonable, and not unduly discriminatory or preferential rates.1

 For these 

reasons, I cannot support this Rule. 

Standardizing Demand Response Compensation 

 As an initial matter, RTOs and ISOs currently offer different types of demand 

response products that vary from region to region and in terms of capability and services 

offered in the day-ahead and real-time energy markets. Moreover, the RTOs and ISOs to 

date have been working with their market participants in a stakeholder process to design 

demand response compensation rules that are tailored to suit the needs of their individual 

energy markets. However, this will all change once the Rule takes effect and this 

existing framework is replaced with the requirement that every organized wholesale 

energy market pay demand resources the market price for energy (LMP) when its 

demand reductions are, in theory, found to be cost-effective. 

1

 16 U.S.C. § 824d (2006). 
Docket No. RM10-17-000 - 2 -

 

As I recognized in my initial statement in this proceeding, organized markets 

such as the PJM Interconnection have already demonstrated the ability to develop 

demand response compensation rules. Accordingly, I would have preferred to allow 

these markets to continue to develop their own rules. Different demand response 

products will have different values that reflect their varying capabilities and to require a 

standard payment fails to reflect these meaningful differences.2

 

 However, without ever determining that the existing region-by-region approach to 

compensation is unjust and unreasonable, the Rule implies that the current approach is no 

longer adequate to ensure that rates remain just and reasonable. In turn, the Rule finds 

that “greater uniformity in compensating demand response resources” is required and as 

justification for its action, references the existence of various barriers that limit the 

participation of demand response in the energy markets.3

 The majority ultimately 

concludes that these barriers can be removed by better equipping demand response 

providers with the financial resources to invest in enabling technologies.4

 This is to say 

that the majority believes that paying demand resources more money will help overcome 

these barriers and encourage more participation. The Rule, however, never clearly 

explains how the existence of barriers, in turn, justifies a payment of full LMP to demand 

resources. 

 The Rule (like the NOPR) does not sufficiently discuss the need for standardizing 

compensation across the organized markets or elaborate on how standardization will 

remove genuine barriers that prevent meaningful participation by demand resources in 

the energy markets. 5

 While the Energy Policy Act of 2005 states that the policy of the 

2

 California Commission May 13, 2010 Comments at 6, “[P]romulgating a 

uniform national rule at this time may inadvertently impede the implementation of 

optimal demand response compensation for an individual ISO or RTO which address the 

needs of that particular region.” The California Commission “is concerned that 

mandatory ‘one size fits all’ pricing may stifle national and regional efforts to collect 

valuable data and experience regarding the effects of different demand response program 

designs on consumer participation and conflict with Congressional objectives.” 

3

 Rule at P 17, 57-59. 

4

 Rule at P 57-59. 

5

 Significant barriers do exist which prevent demand response from reaching its 

full potential. Specifically, 24 barriers were identified in our National Assessment of 

Demand Response Potential, FERC Staff Report, (June 2009) at 65-67. 
Docket No. RM10-17-000 - 3 -

 

U.S. Government is to remove unnecessary barriers to demand response, the statute 

never authorized the Commission to stimulate increased demand response participation 

by requiring its compensation to include incentives or preferential treatment.6

 Although, 

the majority is quick to claim “that removing barriers to demand response participation is 

not the same as giving preferential treatment to demand response providers...”, this is 

exactly what is occurring in this Rule.7

 As discussed below, the majority’s determination 

is troubling as the Rule both affords preferential treatment to demand response resources 

and unduly discriminates against them in other respects. 

Demand Response Resources are Comparable . . . Sometimes

 At the outset, the concept of “comparability” is at the core of this rulemaking, i.e., 

whether demand response resources are capable of providing a service comparable to 

generation resources and if so, whether these resources should receive comparable 

compensation for a comparable service. On this point, I believe they should.8

 This is not 

to say that a megawatt produced is the same as a megawatt not consumed; they are not 

perfect equivalents. The characteristics of a megawatt and a “negawatt” are different, 

both in terms of physics and in economic impact. 

Assuming, however, that a demand resource can provide a balancing service that 

is identical to that of a generation resource, it would make sense that a demand resource 

providing a comparable service would receive comparable compensation. But this may 

not occur under the Rule. The majority explains that if a demand resource is capable of 

providing a service comparable to a generation resource, it will only be eligible to receive 

comparable compensation, by definition, if it can also be determined that the resource 

will result in a price-lowering effect to the market by passing a net benefits test.9

 

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

965 (2005). 

7

 Rule at P 59. 

8

 As explained below, I believe that comparable compensation is represented by 

the value realized by the demand resource for providing a comparable service, regardless 

of whether the source of that value is a payment from the market or a savings by the 

resource. 

9

 Rule at P 47-50. 
Docket No. RM10-17-000 - 4 -

 

In no other circumstance is a resource required to show that its participation 

will depress the market price in order to receive comparable compensation for a 

comparable service. 10 Such a definition unduly discriminates against demand resources 

and as such, this requirement is unjust, unreasonable, and unduly discriminatory. 

Overcompensating Demand Resources and the Net Benefits Test 

 At first glance, the Rule’s requirement that RTOs and ISOs pay demand response 

resources the LMP only when it is deemed cost-effective appears to make sense. There is 

near-universal agreement that the LMP reflects the value of the marginal unit, and as 

such, it sends the proper price signal to keep supply and demand in relative balance. 

Accordingly, the Rule explains that if the demand resource is capable of providing a 

comparable service and is also cost-effective (i.e., using a net benefits test to ensure that 

the overall benefit of the reduced LMP that results from dispatching demand recourses 

exceeds the cost of dispatching those resources), then this resource should be paid the 

same as a generation resource. However, the decision to pay demand resources the full 

LMP under such circumstances actually results in overcompensation that is economically 

inefficient, preferential to demand resources, and unduly discriminatory towards other 

market resources. 

An example may help to illustrate a major flaw with this Rule. Assume that both a 

generation resource and a demand resource bid into the energy market and both bids are 

accepted and paid the LMP ($100). Then consider the fact that the demand resource will 

save an amount that it would have otherwise paid by not purchasing generation at the 

retail rate (“G”), which is $25. While the Rule requires that RTOs and ISOs pay the 

demand resource the LMP (which is the identical amount the generation resource 

receives), the Rule effectively ignores the fact that the demand resource will actually 

receive a total compensation of LMP+G ($125) as a result of its decision not to 

consume.11 Meanwhile, the generation resource will only receive the LMP ($100) 

10 Testimony of Audrey Zibelman, President and CEO of Viridity Energy, Inc., 

Sept. 13, 2010 Tr. at 119, "[T]he fact that we're debating this [net benefits test] is 

somewhat absurd. We have not required any other resource to demonstrate a benefit in 

order to enter this market." 

11 The proper economic measure of value realized by the demand resource is one 

where the RTO or ISO makes a reduction from the LMP to account for the retail rate, but 

then recognizes that the savings associated with the avoided retail generation cost should 

be added back into the equation, i.e., (LMP-G)+G. 
Docket No. RM10-17-000 - 5 -

 

payment as a result of its decision to produce. While the Rule’s intent is to ensure 

that a demand resource receives “the same compensation, the LMP, as a generation 

resource”, this is not the actual result.12 In this example, what will happen is that the 

Rule will require that the demand response resource be overcompensated by $25.13 

 The Rule effectively finds 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. 

Professor William W. Hogan refers to this outcome as a “double-payment” because 

demand resources would “receive” both the cost savings from not consuming electricity 

at a particular price, plus an LMP payment for not consuming that same increment of 

electricity.14 Not only is this result not comparable (by valuing a negawatt more than a 

megawatt) and economically inefficient (by distorting the price signal), but this 

preferential compensation will harm the efficiency of the competitive wholesale energy 

markets. 

The use of a net benefits test further reduces competitive efficiency and only 

complicates the issue. As the Rule explains, the net benefits test involves the 

determination of a threshold price point that is plotted along a historical supply curve in 

an attempt to accurately calculate whether the cost of procuring additional demand 

response is outweighed by the value it brings to the market in the form of a lower LMP.15 

12 Rule at P 82. If it were the result, the generation resource would be paid the 

LMP, $100, and the demand resource would be paid $75 and realize an additional $25 in 

retail rate savings. Accordingly, both resources realize equivalent compensation valued 

at $100. 

13 Ohio Commission May 13, 2010 Comments at 6, “[T]he Commission’s 

proposal that RTOs pay demand response resources the full LMP takes the incentives for 

wholesale demand response resources a step too far. It would provide an incentive to the 

supplier of a demand response resource that exceeds the payments available to an 

equivalent supply resource. The Commission should instead focus on removing the 

existing barriers in the wholesale markets....” 

14 See Attachment to Answer of EPSA, Providing Incentives for Efficient Demand 

Response, Dr. William W. Hogan, October 29, 2009 (Docket No. EL09-68). 

15 Testimony of Robert Weishaar, Jr., Attorney for Demand Response Supporters, 

Sept. 13, 2010 Tr. at 46-47, "Administratively constructing an LMP-based break point for 

compensating Demand Response participation would ignore many other qualitative and 

(continued...) 
Docket No. RM10-17-000 - 6 -

 

However, this test, which attempts to justify the LMP payment by promising a “winwin” outcome, is nothing more than a fig leaf that provides little protection against the 

long-term potential for unintended market damage. As recognized by ISO-NE, 

generation is not dispatched and paid for only when such generation reduces LMP, 

instead generation is dispatched and paid for only when it is cost-effective.16 Likewise, 

logic would require that demand resources be treated similar to generation resources and 

be similarly cost-effective. 

During a technical conference convened to discuss the specific question on the 

necessity of a net benefits test, the Commission heard testimony from a panel of experts. 

A clear majority of the witnesses (representing a spectrum of interests that included 

demand response advocates, economists, generators, and the RTOs and ISOs) argued 

against the use of a complicated and admittedly imprecise17 net benefits test.18 Chief 

among their concerns was that a net benefits test is unnecessary since the market clearing 

function in a wholesale market, by definition, serves to guarantee that the resource that 

clears the market is the lowest-cost resource.19 Other experts commented that the net 

benefits test would be complicated, costly to implement, and of little value.20 Notably, 

Dr. Alfred E. Kahn, the majority’s oft-quoted expert in defense of the full LMP payment, 

did not opine on the merit of subjecting the LMP payment to a net benefits test. 

quantitative benefits of Demand Response. Focusing only on the LMP impacts of 

Demand Response is problematic." 

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

17 Rule at P 80. Recognizing that “the threshold price approach we adopt here 

may result in instances both when demand response is not paid the LMP but would be 

cost-effective and when demand response is paid the LMP but is not cost-effective.” 

18 Testimony of Donald Sipe, Attorney for Consumer Demand Response Initiative, 

Sept. 13, 2010 Tr. at 43, "[T]here is probably not a need for a Net Benefits Test. But if 

one is adopted, it should not be an artificial threshold that can be wrong both ways. It 

should not be a mechanism that treats DR differently than generation.” 

19 Viridity Energy, Inc., Oct. 13, 2010 Comments at 10. See also ELCON Oct. 13, 

2010 Comments at 3; and Environmental Defense Fund Comments at 2. 

20 Testimony of Andy Ott, Sr. Vice President, PJM Interconnection, Sept. 13, 2010 

Tr. at 19, "[Y]ou have to use caution to actually take a benefits test and apply that to 

compensation, because you may have unintended consequences." 
Docket No. RM10-17-000 - 7 -

iness purpose.” 

 

Further, as explained by Dr. Roy J. Shanker, if the Commission adopted the 

payment of LMP minus the retail rate (“G”), then there is no need for a net benefits test 

since the customer is paid the difference between the LMP and what they would have 

paid under their retail rate, which is their net benefit. 21 He testified that the “Net 

Benefits criteria is troubling in and of itself, as it explicitly incorporates consideration of 

portfolio effects caused by the reduced demand on all load payments, versus the 

economic decision-making of individual market participants pursuing their own 

legitimate bus 22

I similarly agree that this test is unnecessary and will only distort price signals by 

attracting more demand response than is economically efficient.23 The use of a net 

benefits test also is troubling in that the Commission’s decision can be viewed as 

somehow equating the concept of a just and reasonable rate with a lower price.24 

However, I recognize that to defend its compensation scheme, the majority needed some 

proposal that could arguably demonstrate that the cost of paying full LMP to demand 

resources would be outweighed by the “benefit” of a lower market price.25 The net 

benefits test serves this unenviable role. 

21 Testimony of Roy J. Shanker, Ph.D, PJM Power Providers Group, Sept. 13, 

2010 Tr. at 60, "If the Commission adopts the appropriate non-discriminatory pricing for 

Demand Response, and payment of LMP minus the retail rate in the context of customer 

that face a fixed retail rate, then there is no need for a Net Benefits test." 

22 Id., Tr. at 61. 

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

APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5; 

PJM at 6; PSEG at 5; and Potomac Economics at 6-8. 

24 Courts have stated that to be “just and reasonable,” rates must fall within a 

“zone of reasonableness” where they are neither “less than compensatory” to producers 

nor “excessive” to consumers. Farmers Union Central Exchange v. FERC, 734 F.2d 

1486 (D.C. Cir. 1984), cert denied, 469 U.S. 1034 (1984). See also EPSA May 13, 2010 

Comments at 19; and ISO-NE at 26-28. 

25 Testimony of Ohio Commissioner Paul Centolella, Sept. 13, 2010 Tr. at 

141, “The Net Benefits test reflects a recognition that paying full LMP may overcompensate Demand Response and increase cost to customers.” 
Docket No. RM10-17-000 - 8 -

eate 

 can 

 

Relationship to State Retail Regulation

The Rule recognizes that the demand resource will retain the retail rate (“G”) as 

part of the provider’s total compensation, but declines to account for this savings citing 

“practical difficulties” for state commissions, RTOs and ISOs.26 While the authority 

over retail rates is properly within the jurisdiction of the state commissions, under the 

LMP-G equation, the RTO/ISO merely subtracts the retail rate; it does not interfere with 

the retail rate in any way.27 Although the Rule refers to the New York Commission’s 

position that subtracting the retail rate would be an “administrative burden” or cr

“undue confusion”28, other state commissions disagree and contend that the retail rate

be deducted without any concern about impacting the states’ retail jurisdiction.29

26 Rule at P 63. The RTOs and ISOs uniformly state that compensation which 

ignores the retail rate will yield uneconomic outcomes and overcompensate the demand 

resource. Moreover, none of the RTOs or ISOs claimed it would be difficult to subtract 

the retail rate from the LMP payment. See May 13, 2010 Comments of CAISO at 5-6; 

ISO-NE at 17-26; Midwest ISO at 6-11; NYISO at 12-16; and PJM at 5-16. 

27 Testimony of Joel Newton, New England Power Generators Ass’n, Sept. 13, 

2010 Tr. at 75; “The Commission is getting into a real close area with retail ratemaking 

as we go through this entire process. For the Commission then to say ‘ignore the LSE 

payment’ which is the realm of state commissions, it’s almost as you’re just hoping that 

the state commissions will go out and fix it. The state commissions can do that...[b]ut 

the proper thing to do now is to get the price right at the outset.” See also Testimony of 

Ohio Commissioner Paul Centolella, Sept. 13, 2010 Tr. at 197; “[FERC is] putting the 

state in the position where if we were to try to get back to an efficient level of incentives, 

we would be having to in effect issue a charge for energy that was not consumed. We 

would be doing what would be perceived as a take-back by that customer. And that 

would put us in a very difficult position.” 

28 Rule at P 28. Significantly, the New York Commission “acknowledges the 

overstated price signal inherent in an LMP-based formula for DR compensation....” 

“Although we understand that an LMP demand response compensation formula may 

result in uneconomic demand response decisions in the markets (i.e., a price signal that 

exceeds marginal cost), it also creates an incentive to participate in DR programs....” 

New York Commission May 13, 2010 Comments at 5-6 (emphasis added). 

29 Illinois Commission May 13, 2010 Comments at 13, “[I]f tariffs are well 

designed, controversy over the jurisdictional issue can be avoided. Requiring an ex ante 

approval of the retail rate to be subtracted from the LMP at the time demand response 

resources are utilized ...accomplishes this design.” See also Indiana Commission 

(continued...) 
Docket No. RM10-17-000 - 9 -

 

Moreover, the Rule does not conclude that LMP-G would interfere with the retail 

jurisdiction of the states, but goes as far as to acknowledge the subtraction of G is 

“perhaps feasible.”30 The fact is that this calculation is quite feasible. Markets such as 

the PJM Interconnection currently subtract the retail rate portion from the LMP payment 

and there is no evidence that accounting for the retail rate by making the necessary 

reduction is either burdensome or interferes with the retail jurisdiction of state 

commissions.31

The Unintended Consequences of Paying Too Much 

Today’s determination, unencumbered by “textbook economic analysis of the 

markets subject to our jurisdiction” will undoubtedly have effects, both in the short-term 

and the long-term.32 The intended consequence of providing additional compensation to 

demand resources is that demand response participation will increase in the energy 

markets. In turn, this additional demand response participation will have the effect of 

lowering the market price. However, it is at this point where the unintended effects will 

begin to appear. 

With a reduced LMP, the price signal sent to customers will be that the cost of 

power is cheaper so they may decide to use more power even though the real cost of 

producing that power is now higher. Such a result turns the concept of scarcity pricing 

on its head and results in an economically inefficient outcome. Conversely, customers 

who are demand response providers now stand to receive more than the market price as 

an incentive to curtail their consumption and will begin to make inefficient decisions 

about using power.33 Such inefficiencies will result in customers experiencing a shortSeptember 16, 2009 Comments at 3 (Docket No. EL09-68), “LMP-G is an accepted 

indicator of cost-effectiveness. Therefore, to provide incentive compensation at a level 

that is above the LMP raises the specter of unjust and unreasonable rates.” 

30 Rule at P 63. 

31 See Sections 3.3A.4 and 3.3A.5 (Market Settlements in the Real-Time and DayAhead Energy Markets) of the Appendix to Attachment K of the PJM Tariff. 

32 Rule at P 46. 

33 Federal Trade Commission May 13, 2010 Comments at 6, “If customers have to 

pay the retail price for power they use but pay nothing for power they resell, then they 

will have incentives to resell power in situations in which it would be more beneficial for 

(continued...) 
Docket No. RM10-17-000 - 10 -

 

term benefit by way of a lower LMP, but will also impose long-term costs on the 

energy markets.34

The long-term costs of allowing demand resources to receive preferential 

compensation will manifest themselves in various ways. As noted in my initial statement 

in this proceeding, the lack of dynamic prices at the retail level is the primary barrier to 

demand response participation. This Rule does not remedy this barrier and customers 

who pay fixed retail rates will not benefit from lower wholesale market prices. 

Meanwhile, at the wholesale level, the corrosive effect of overcompensating demand 

resources over time will come at the expense of other resources, particularly generation 

resources that will have less to invest in maintaining existing facilities and financing new 

facilities.35 

The Commission’s recent progress in promoting competitive wholesale energy 

markets has the potential to be undone as a result of this well-meaning, but misguided 

Rule. I believe in the proven value of market solutions and therefore agree with the 

majority’s statement that “while the level of compensation provided to each resource 

affects its willingness and ability to participate in the market, ultimately the markets 

themselves will determine the level of generation and demand response resources needed 

society for them to consume it.” See also EPSA May 13, 2010 Comments at 23; APPA 

at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5; PJM at 

6; PSEG at 5; and Potomac Economics at 6-8. 

34 PJM’s Independent Market Monitor (a/k/a Monitoring Analytics, LLC) Oct. 16, 

2009 Comments at 7-8 (Docket No. EL09-68), “Demand side resources are not 

generation. In a well functioning market, demand-side resources avoid paying the market 

price of energy when they choose not to consume. This allows customers to make 

efficient decisions about using power. It also follows that a customer receiving more 

than the market price as an incentive to curtail will make inefficient decisions about using 

power, and that this inefficiency imposes a cost rather than providing a benefit to 

society.” 

35 NYISO May 13, 2010 Comments at 15, “[P]aying demand response an LMPbased payment because it is thought that demand response participation will reduce 

LMPs for all customers is not a sufficient rationale for justifying an ‘additional payment’ 

for a favored technology. Demand response is not the only resource able to provide such 

benefits. However, [other] technologies may be kept out of the market by demand 

response that would be uneconomic at LMP-G but participates when subsidized at LMP.” 
Docket No. RM10-17-000 - 11 -

 

for purposes of balancing the electricity grid.”36 That’s precisely how markets 

should work. Price signals will attract resources and new investment when prices are 

high, and perhaps not so much when prices are low.37 If the playing field is level, 

resources can compete to the best of their abilities and efficient, cost-effective market 

outcomes will result. 

 As noted earlier, I would have preferred that we allow the regional markets to 

continue to develop their own compensation proposals. However, I also recognize that 

returning to a pre-NOPR era would be difficult now that the Commission has signaled a 

new policy of standardized compensation. Accordingly, if I were to now support any 

standardization of demand response compensation, it would be the LMP-G approach, 

which in my opinion, is the only economically efficient outcome for the markets. 

 Ultimately, the Rule, by requiring demand resources to artificially suppress the 

market price in order to receive incomparable compensation, will negatively impact the 

long-term competitiveness of the organized wholesale energy markets.38 As such, 

lacking sufficient rationale, I cannot support this Rule 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 

36 Rule at P 59. 

37 PJM Interconnection’s experience with paying LMP-G for demand response in 

its energy market provides an example of how market fundamentals properly influence 

demand resource participation. PJM’s Independent Market Monitor recently reported 

that “[p]articipation levels through calendar year 2009 and through the first three months 

of 2010 were generally lower compared to prior years due to a number of factors, 

including lower price levels, lower load levels, and improved measurement and 

verification, but have showed strong growth through the summer period as price levels 

and load levels have increased. Citing Monitoring Analytics, LLC, 2010 State of the 

Market Report for PJM at 30 (March 10, 2011) (emphasis added). 

38 Federal Power Act § 205(a), 16 U.S.C. § 824d (2006), “[A]ll rules and 

regulations affecting or pertaining to such rates or charges shall be just and reasonable, 

and any such rate or charge that is not just and reasonable is hereby declared to be 

unlawful.”