16658 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

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). 

DEPARTMENT OF ENERGY 

Federal Energy Regulatory 

Commission 

18 CFR Part 35 

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

Demand Response Compensation in 

Organized Wholesale Energy Markets 

AGENCY: Federal Energy Regulatory 

Commission, Energy. 

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. 

DATES: Effective Date: This Final Rule 

will become effective on April 25, 2011. 

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: 

Table of Contents 

(Issued March 15, 2011) 

Paragraph 

Nos. 

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 

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 1—List of Commenters 

Appendix 2—Dissenting Statement 

Before Commissioners: Jon 

Wellinghoff, Chairman; Marc Spitzer, 

Philip D. Moeller, John R. Norris, and 

Cheryl A. LaFleur. 

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. 


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Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 16659 

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). 

4The 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). 

5LMP 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. 

6The 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. 

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. 

8 16 U.S.C. 824d (2006). 

9We note that this report is for informational 

purposes only and will neither be noticed nor 

require Commission action. 

10See, 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. DC 205 (DC Cir. 2001). 

2. We conclude that when a demand 

response 2 resource 3 participating in an 

organized wholesale energy market 4

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 costeffective 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 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 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 costeffective. 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

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 costeffectiveness 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 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 


emcdonald on DSK2BSOYB1PROD with RULES2
16660 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

11 16 U.S.C. 824d (2006); Order No. 719, FERC 

Stats. & Regs. ¶ 31,281 at P 1. 

12See Order No. 719, FERC Stats. & Regs. 

¶ 31,281 at P 48. 

13Wholesale Competition in Regions with 

Organized Electric Markets, Order No. 719–A, FERC 

Stats. & Regs. ¶ 31,292, at P 48 (2009). 

14NOPR, FERC Stats. & Regs. ¶ 32,656 at P 4. 

15For 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.’’). 

17See Comments of NYISO’s Independent Market 

Monitor filed in Docket No. ER09–1142–000, May 

15, 2009 (Demand response ‘‘contributes to 

reliability in the short-term, resource adequacy in 

the long-term, reduces price volatility and other 

market costs, and mitigates supplier market 

power.’’). 

18 Id. 

19See 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 * * *.’’). 

20For 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). 

21See Energy Policy Act of 2005, Public Law 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.’’). 

22Preventing 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). 

23Order No. 890–A, FERC Stats. & Regs. ¶ 31,261 

at P 216. 

24Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 47–49. 

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

P 194. 

26Order No. 719, FERC Stats. & Regs. ¶ 31,281 at 

P 247. 

27Other 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 

supplies of electric energy at just, 

reasonable, and not unduly 

discriminatory or preferential rates.11

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 retaillevel 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 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 higherpriced 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 

response has the potential to support 

system reliability and address resource 

adequacy 19 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 allow nongeneration 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

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


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¶ 61,227 (2002); California Independent System 

Operator Corp., 132 FERC ¶ 61,045 (2010). 

28See 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. 

29See sections 3.3A.4 and 3.3A.5 (Market 

Settlements in the Real-Time and Day-Ahead 

Energy Markets) of the Appendix to Attachment K 

of the PJM Tariff. 

30For 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. 

31Midwest ISO FERC Electric Tariff characterizes 

Demand Response Resources (DRR) as either DRRType 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. 

32See Charges and Payments for Purchases and 

Sales for Demand Response Resources. Midwest 

ISO FERC Electric Tariff, section 39.3.2C. 

33See 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). 

34The 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. 

35NOPR, FERC Stats. & Regs. ¶ 32,656. 

36See Appendix for a list of commenters. 

37Supplemental Notice of Proposed Rulemaking 

and Notice of Technical Conference, 75 FR 47499 

(Aug. 6, 2010), 132 FERC ¶ 61,094 (2010) 

(Supplemental NOPR). 

38See Notice of Technical Conference (Aug. 27, 

2010). 

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

40 Id. at P 16. 

14. To date, the Commission has 

allowed each RTO and ISO to develop 

its own compensation methodologies for 

demand response resources 

participating in its day-ahead and realtime 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 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 programs 31 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 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 real-time 

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 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

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 responserelated technology (such as advanced 

metering) and thereby facilitate their 

ability to participate in organized 

wholesale energy markets.40 The 

Commission sought 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. 

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: 


emcdonald on DSK2BSOYB1PROD with RULES2
16662 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

41Supplemental NOPR, 132 FERC ¶ 61,094 at 

P 8–9. 

42See 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. 

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. 

46Occidental May 13, 2010 Comments at 11. 

47 Viridity June 18, 2010 Comments at 5. 

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

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

Capital Power May 13, 2010 Comments at 2. 

50EPSA May 13, 2010 Comments at 72. 

51See, e.g., PSEG May 13, 2010 Comments at 8. 

52Battelle May 13, 2010 Comments at 3. 

53AEP May 13, 2010 Comments at 7–8. 

54ODEC May 13, 2010 Comments at 12. 

55Calpine May 13, 2010 Comments at 4–5. 

56EEI 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. 

57See 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 

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 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, 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. 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 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 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 


emcdonald on DSK2BSOYB1PROD with RULES2
Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 16663 

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. 

58See 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. 

59EPSA 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. 

60Attachment 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. 

61P3 June 14, 2010 Comments at 2, 7–8. 

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

63 Id. at 28. 

64Hogan Affidavit, ISO RTO Council May 13, 

2010 Comments at 5. 

65New York Commission May 13, 2010 

Comments at 8. 

66See, 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. 

67EPSA June 30, 2010 Comments at 3. 

68EPSA June 30, 2010 Comments at 23. 

69 Viridity Energy June 18, 2010 Comments at 25. 

70 DR Supporters Aug. 30, 2010 Reply Comments 

at 10 (citing EnergyConnect, Inc., 130 FERC 

¶ 61,031 at P 30–31 (2010)). 

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 doublepayment for demand reductions, 

because demand response providers 

would ‘‘receive’’ both the cost savings 

from not consuming an increment of 

electricity at a particular price, plus an 

LMP payment for not consuming that 

same increment of electricity.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 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, 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-the-baseline’’ 

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 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 

erroneous 69 and based on the flawed 

assumption that demand response 

resources are 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 


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16664 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

71 DR Supporters Aug. 30, 2010 Reply Comments, 

Kahn Affidavit at 10. 

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, PhD)). 

73 Viridity Reply Comments at 13. 

74 Viridity Reply Comments at 14. 

75EDF Oct. 13, 2010 Comments at 2. 

76American Clean Skies Foundation May 13, 

2010 Comments at 4. 

77Alcoa May 13, 2010 Comments at 9. 

78EPSA May 13, 2010 Comments at 60. 

79ODEC May 13, 2010 Comments at 12; Westar 

May 13, 2010 Comments at 5–6. 

80 Id. 

81Calpine May 13, 2010 Comments at 5. 

82PIO May 13, 2010 Comments at 8. 

83NEMA May 13, 2010 Comments at 2. 

84EPSA May 13, 2010 Comments at 7. 

85PSEG May 13, 2010 Comments at 8. 

86See generally May 13, 2010 Comments of 

NYSCPB; NECA; Capital Power; NECPUC; 

Maryland Commission; New York Commission; 

NSTAR; National Grid; NE Public Systems. 

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

May 13, 2010 Comments at 5. 

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 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 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 

behind-the-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 

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, 

BAL–002–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 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 

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 


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Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 16665 

88NECPUC 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. 

89See, 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)). 

90See, 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). 

91NECAA 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. 

93NAPP 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. 

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

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

Comments at 3. 

96See, 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. 

97P3 Oct. 13, 2010 Comments at 5. 

98Sept. 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. 

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

100Midwest ISO TOs May 13, 2010 Comments at 

16. 

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

102 120 FERC ¶ 61,085 (2007). 

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

104See 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. 

105See, e.g., Steel Manufacturers Ass’n May 13, 

2010 Comments at 12; NEMA May 13, 2010 

Comments at 5. 

106Steel Manufacturers Ass’n May 13, 2010 

Comments at 12. 

107PIO May 13, 2010 Comments at 9; DR 

Supporters Aug. 30, 2010 Comments at 6–7. 

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 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 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 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 

Advisors 102 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 benefits compared 

to no program at all. The criterion to 

apply would focus on the bid-cost 

savings of generation and load, with the 

load bids adjusted for the effects of 

avoidance of the retail rate.’’ 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, nondiscriminatory markets must adapt and 

eliminate barriers to entry to the use and 

incorporation of traditional and nontraditional resources—where nontraditional resources include activelymanaged 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 


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

109NECPUC May 13, 2010 Comments at 4; NYISO 

May 13, 2010 Comments at 16. 

110 Viridity Energy May 13, 2010 Comments at 4. 

111See, 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. 

112Elec. Consumers Res. Council v. FERC, 407 

F.3d 1232, 1236 (DC Cir. 2005) (quoting Pub. Util. 

Comm’n of the State of Cal. v. FERC, 254 F.3d 250, 

254 (DC Cir. 2001)); see also Town of Norwood v. 

FERC, 962 F.2d 20, 22 (DC Cir. 1992). 113See Elizabethtown Gas Co. v. FERC, 10 F.3d 

866, 872 (DC 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 (DC 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 (DC Cir. 1987))); Columbia Gas 

Transmission Corp. v. FERC, 750 F.2d 105, 112 (DC 

Cir. 1984) (‘‘the Commission is vested with wide 

discretion to balance competing equities against the 

backdrop of the public interest’’). 

114See generally May 13, 2010 Comments of 

NYSCPB; NECA; Capital Power; NECPUC; 

Maryland Commission; New York Commission; 

NSTAR; National Grid; NE Public Systems. 

115The 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. 

116NOPR at P 12. 

117Andrew 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. 

118As stated above, dispatching generation 

resources does not produce this billing unit effect 

because it does not result in a decrease of load. 

119As a simple example, assume a market of 100 

MW, with a current LMP of $50/MWh without 

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 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 overcompensation 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. 

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 

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 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 costeffectiveness 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 

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 


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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. 

120See DR Supporters Aug. 30, 2010 Reply 

Comments (Kahn Affidavit at 2 (footnote omitted)). 

121See, 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. 

122Order 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- 

demand-response.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. 

123See, e.g., Monitoring Analytics May 13, 2010 

Comments at 4–6. 

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 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. 

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 costeffective alternative to the next highestbid 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. 

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 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-bymoment, 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 


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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.’’). 

125EnerNOC May 13, 2010 Comments at 4; see 

also Alcoa May 13, 2010 Comments at 4; Viridity 

May 13, 2010 Comments at 5–6. 

126 Generation and demand response resources 

have the potential to earn other revenues through 

bilateral arrangements, capacity markets where they 

exist, and ancillary services. 

127See NEPGA June 21, 2010 Comments at 1–2. 

128Order No. 719, FERC Stats. & Regs. ¶ 31,281 

at P 154. 

129 DR Supporters Aug. 30, 2010 Reply Comments 

(Kahn Affidavit at 9–10). 

130See New England Power Pool, 101 FERC 

¶ 61,344, at P 35 (2002). 131See EnergyConnect, 130 FERC ¶ 61,031 at P 

32. 132 Id.; see also Order No. 719–A, FERC Stats. & 

Regs. ¶ 31,292, at P 47. 

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 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 economicallyefficient 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 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 cost-effective, 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 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 dayahead 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. 

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 Commissionjurisdictional rates.132

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 


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133See PJM Interconnection, L.L.C., 129 FERC 

¶ 61,081 (2009). 

134For 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). 

135NYISO 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. 

136Sept. 13, 2010 Tr. 52–53 (Mr. Peterson); 

Massachusetts AG Oct. 13, 2010 Comments at 23. 

137Massachusetts 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. 

139National 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. 

140The 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. 

141NECPUC Oct. 13, 2010 Comments at 14–16; 

NECPUC May 13, 2010 Comments at 17. 

142 Id. at 5–6. 

143Maryland Commission May 13, 2010 

Comments at 4–5; see generally NSTAR, ACEEE 

and NYSCPB Oct. 13, 2010 Comments. 

144Maryland Commission May 13, 2010 

Comments at 4 n.9. 

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 costeffectiveness 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 

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. 

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 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 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, further analysis is needed to 

ascertain the critical high-cost hours in 

which it will be cost-effective 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 


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145The approach submitted by CDRI was 

developed for implementation in the ISO–NE dayahead energy market. The discussion here is 

generalized to be applicable to any energy market 

that uses security-constrained economic dispatch to 

select the least-cost resources and establish a 

market-clearing price. 

146PIO 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. 

147CDRI 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. 

148Sept. 13, 2010 Tr. 80–81 (Dr. Ethier). 

149 Id. 

150Sept. 13, 2010 Tr. 82:16–21 (Mr. Ott). 

151See generally AEP, Midwest ISO, Occidental, 

NYISO, Constellation Oct. 13, 2010 Comments. 

152See, 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)). 

153Constellation October 13, 2010 Comments at 

3–4. 

154 ISO–NE Oct. 13, 2010 Comments at 4–5 and 

21. 

155See, 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. 

156Sept. 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. 

158Sept. 13, 2010 Tr. 103–104 (Mr. Weishaar). 

159Sept. 13, 2010 Tr. 106:16–24 (Mr. Sipe). 

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 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 overcollection) 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 

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 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 highpriced 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, 

long-term 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 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


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160There 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. 

161The 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. 

162Thus, the test is to determine where: (Delta 

LMP × MWh consumed) > (LMP new × DR); where 

LMP new 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. 

163Supply 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. 

164See supra note 114. 

165See supra P 6. 

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 

Continued 

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-effective to pay full LMP to 

demand resources; 160 and (2) a study of 

the feasibility of developing a 

mechanism for determining the costeffective 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 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 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 costeffective 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 Web site, 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 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 Web site (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 Web 

site 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 ISO stakeholder process to 

determine when demand response 

provides net benefits without explicit 

guidance from the Commission.166 We 


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16672 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

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. 

167Additionally, 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. 

168 Demand Response Compensation in 

Organized Wholesale Energy Markets, FERC Stats. 

& Regs. ¶ 32,656, at P 1 (2010). 

169See, e.g., ISO/RTO Council, North American 

Wholesale Electricity Demand Response 2010 

Comparison, under the tab for ‘‘Performance 

Evaluation Methods’’ (http://www.isorto.org/atf/cf/ 

%7B5b4e85c6-7eac-40a0-8dc3-003829518ebd%7D/ 

IRC%20DR%20M&V%20STANDARDS%20

IMPLEMENTATION%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. 

171See, 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. 

174 Id. 

175 ISO–NE IMM May 13, 2010 Comments at 

9–13 and Attachment A. 

176Westar May 13, 2010 Comments at 3. 

177CPower May 13, 2010 Comments at 4–5. 

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 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 

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

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 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 support this 

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 

result of ‘normal’ activity * * * may be 

violations of the Commission’s antiVerDate Mar<15>2010 16:24 Mar 23, 2011 Jkt 223001 PO 00000 Frm 00016 Fmt 4701 Sfmt 4700 E:\FR\FM\24MRR2.SGM 24MRR2

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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 nonperformance analogous to a generator’s forced 

outage.’’). 

179EnerNOC, Inc. May 13, 2010 Comments at 4. 

180ECS 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. 

181See, 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. 

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. 

186As 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. 

187EPSA 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 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. 

188Massachusetts AG May 13, 2010 Comments at 

9–10. 

189PJM 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. 

190NECPUC 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. 

191PJM May 13, 2010 Comments at 9; NECPUC 

May 13, 2010 Comments at 22; PCA Sept. 10, 2010 

Comments at 4. 

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 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 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

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

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 


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16674 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

192PJM May 13, 2010 Comments at 12; ISO–NE 

May 13, 2010 Comments at 5. 

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. 

194CDRI, Integration of Demand Response Into 

Day Ahead Markets (Attachment B), May 13, 2010 

Comments at 16. 

195This 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 (DC Cir. 2004); see 

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

470, 476 (7th Cir. 2009). 

196See, 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). 

197See 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. 

199See 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 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. 200See California Independent System Operator 

Corp., 132 FERC ¶ 61,045 (2010). 

201California 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 

LSE and others assigned broadly.192 The 

fourth method suggested is to directly 

assign the costs of demand 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. 

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. 

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 22, 

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 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 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 

filing 200 illustrates that demand 

response settlement mechanisms are 

within the authority of the California 

Commission.201


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(LSEs) and Demand Response Providers (DRPs) 

associated with DR participation in wholesale 

markets.’’). 

202See 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 nonparticipating 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. 

204PJM May 13, 2010 Comments at 20–21. 

205CAISO May 13, 2010 Comments at 4. 

206OMS May 13, 2010 Comments at 3. See also 

EEI May 13, 2010 Comments at 4. 

207Calpine May 13, 2010 Comments at 3. 

208See 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. 

211Wal-Mart May 13, 2010 Comments at 11. 

212 Viridity June 18, 2010 Comments at 13. 

213 Viridity June 18, 2010 Comments at 14. 

105. Other commenters foresee retail 

regulatory authorities effectively taking 

an end-run around any Commissionmandated compensation level by 

adjusting retail rate design 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 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 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

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 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 


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16676 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

214 DR Supporters Aug. 30, 2010 Comments (Kahn 

Affidavit at 4). 

215 16 U.S.C. 824d (2006). 

216Order No. 719–A, FERC Stats. & Regs. ¶ 31,292 

at P 47. 

217Order No. 719–A, FERC Stats. & Regs. ¶ 31,292 

at P 52. 

218 5 CFR 1320.11(b) (2010). 

219 44 U.S.C. 3507(d) (2006). 

220The 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. 

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 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 

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, 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 

Number of 

responses 

per respondent per year 

Hours per 

response 

Total annual 

hours 

(a) (b) (c) (d) [a*b*c] 

Compliance filing, including tariff provisions and analysis (one-time filing, due 

7/22/2011).

6 (RTOs and 

ISOs).

1 (one-time 

filing).

300 1,800 (onetime filing). 

Study on dynamic net benefits approach (one-time filing, due 9/21/2012) ......... 6 (RTOs and 

ISOs).

1 (one-time 

filing).

2,000 12,000 (onetime 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 imposed 220: (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 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 


emcdonald on DSK2BSOYB1PROD with RULES2
Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 16677 

221Regulations 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). 

223 5 U.S.C. 601–612 (2006). 

224 13 CFR 121.101 (2010). 

225 13 CFR 121.201, Sector 22, Utilities. 

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. 

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 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

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. 

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 high-voltage 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. 

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 


emcdonald on DSK2BSOYB1PROD with RULES2
16678 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

business hours (8:30 a.m. to 5 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 Web site 

during normal business hours from 

FERC Online Support at 202–502–6652 

(toll free at 1–866–208–3676) or e-mail 

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 April 25, 2011. The 

Commission has 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. 

Kimberly D. Bose, 

Secretary. 

In consideration of the foregoing, the 

Commission amends 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 by adding a new 

paragraph (g)(1)(v) to read as follows: 

§ 35.28 Non-discriminatory open access 

transmission tariff. 

* * * * * 

(g) * * * 

(1) * * * 

(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 costeffective 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 appendices will not be 

published in the Code of Federal Regulations. 

Appendix 1—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) 

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 

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) 


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Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 16679 

1 16 U.S.C. § 824d (2006). 

2California 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.’’ 

3Rule at P 17, 57–59. 

4Rule at P 57–59. 

5Significant 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. 

6See Energy Policy Act of 2005, Pub. L. No. 109– 

58, § 1252(f), 119 Stat. 594, 965 (2005). 

7Rule at P 59. 

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) 

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) 

Appendix 2—Dissenting Statement 

UNITED STATES OF AMERICA FEDERAL 

ENERGY REGULATORY COMMISSION 

Demand Response Compensation in 

Organized Wholesale Energy Markets 

Docket No. RM10–17–000 

(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 marketrelated 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. 

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 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 


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16680 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

8As 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. 

9Rule at P 47–50. 

10Testimony 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.’’ 

11The 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. 

12Rule 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. 

13Ohio 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 * * *.’’ 

14See Attachment to Answer of EPSA, Providing 

Incentives for Efficient Demand Response, Dr. 

William W. Hogan, October 29, 2009 (Docket No. 

EL09–68). 

15Testimony of Robert Weishaar, Jr., Attorney for 

Demand Response Supporters, Sept. 13, 2010 Tr. at 

46–47, ‘‘Administratively constructing an LMPbased break point for compensating Demand 

Response participation would ignore many other 

qualitative and 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. 

17Rule 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 costeffective.’’ 

18Testimony 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. 

20Testimony 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.’’ 

21Testimony of Roy J. Shanker, Ph.D, PJM Power 

Providers Group, Sept. 13, 2010 Tr. at 60, ‘‘If the 

Commission adopts the appropriate nondiscriminatory 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.’’ 

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

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) 

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

However, this test, which attempts to justify 

the LMP payment by promising a ‘‘win-win’’ 

outcome, is nothing more than a fig leaf that 

provides little protection against the longterm 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 

imprecise 17 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. 

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 


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Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 16681 

22 Id., Tr. at 61. 

23EPSA 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. 

24Courts 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. 

25Testimony of Ohio Commissioner Paul 

Centolella, Sept. 13, 2010 Tr. at 141, ‘‘The Net 

Benefits test reflects a recognition that paying full 

LMP may over-compensate Demand Response and 

increase cost to customers.’’ 

26Rule 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. 

27Testimony 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.’’ 

28Rule 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 

September 16, 2009 Comments at 3 (Docket No. 

EL09–68), ‘‘LMP–G is an accepted indicator of costeffectiveness. Therefore, to provide incentive 

compensation at a level that is above the LMP raises 

the specter of unjust and unreasonable rates.’’ 

30Rule at P 63. 

31See Sections 3.3A.4 and 3.3A.5 (Market 

Settlements in the Real-Time and Day-Ahead 

Energy Markets) of the Appendix to Attachment K 

of the PJM Tariff. 

32Rule at P 46. 

33Federal 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 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. 

34PJM’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.’’ 

35NYISO May 13, 2010 Comments at 15, 

‘‘[P]aying demand response an LMP-based 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.’’ 

36Rule at P 59. 

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 business purpose.’’ 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. 

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 create ‘‘undue 

confusion’’ 28, other State commissions 

disagree and contend that the retail rate can 

be deducted without any concern about 

impacting the States’ retail jurisdiction.29

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 short-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 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 


emcdonald on DSK2BSOYB1PROD with RULES2
16682 Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations 

37PJM 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). 

38Federal 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.’’ 

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. 

lllllllllllllllllllll

Philip D. Moeller 

Commissioner 

[FR Doc. 2011–6490 Filed 3–23–11; 8:45 am] 

BILLING CODE 6717–01–P 


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