[Federal Register Volume 76, Number 57 (Thursday, March 24, 2011)]
[Rules and Regulations]
[Pages 16658-16682]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2011-6490]



[[Page 16657]]

Vol. 76

Thursday,

No. 57

March 24, 2011

Part II





Department of Energy





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Federal Energy Regulatory Commission



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18 CFR Part 35



Demand Response Compensation in Organized Wholesale Energy Markets; 
Final Rule

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

[[Page 16658]]


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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.

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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, <a href="/cdn-cgi/l/email-protection#bdd9dccbd4d993d5c8d3dad8cffddbd8cfde93dad2cb"><span class="__cf_email__" data-cfemail="c6a2a7b0afa2e8aeb3a8a1a3b486a0a3b4a5e8a1a9b0">[email protected]</span></a>;
Dennis Hough (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8631, <a href="/cdn-cgi/l/email-protection#4327262d2d2a306d2b2c36242b03252631206d242c35"><span class="__cf_email__" data-cfemail="6c08090202051f420403190b042c0a091e0f420b031a">[email protected]</span></a>.

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                     20
             Generation Resources to Balance Energy Markets
            (b) Appropriateness of a Net Benefits Test.....           38
            (c) Standardization or Regional Variations in             43
             Compensation..................................
        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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    \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).

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[[Page 16659]]

    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 cost-effective as determined by the net benefits 
test described herein, that demand response resource must be 
compensated for the service it provides to the energy market at the 
market price for energy, referred to as the locational marginal price 
(LMP).\5\ The Commission finds that this approach to compensation for 
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\
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    \2\ Demand response means a reduction in the consumption of 
electric energy by customers from their expected consumption in 
response to an increase in the price of electric energy or to 
incentive payments designed to induce lower consumption of electric 
energy. 18 CFR 35.28(b)(4) (2010).
    \3\ Demand response resource means a resource capable of 
providing demand response. 18 CFR 35.28(b)(5).
    \4\ The requirements of this final rule apply only to a demand 
response resource participating in a day-ahead or real-time energy 
market administered by an RTO or ISO. Thus, this Final Rule does not 
apply to compensation for demand response under programs that RTOs 
and ISOs administer for reliability or emergency conditions, such 
as, for instance, Midwest ISO's Emergency Demand Response, NYISO's 
Emergency Demand Response Program, and PJM's Emergency Load Response 
Program. This Final Rule also does not apply to compensation in 
ancillary services markets, which the Commission has addressed 
elsewhere. See, e.g., Wholesale Competition in Regions with 
Organized Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28, 
2008), FERC Stats. & Regs. ] 31,281 (2008) (Order No. 719).
    \5\ LMP refers to the price calculated by the ISO or RTO at 
particular locations or electrical nodes or zones within the ISO or 
RTO footprint and is used as the market price to compensate 
generators. There are variations in the way that RTOs and ISOs 
calculate LMP; however, each method establishes the marginal value 
of resources in that market. Nothing in this Final Rule is intended 
to change RTO and ISO methods for calculating LMP.
    \6\ The Commission's findings in this Final Rule do not preclude 
the Commission from determining that other approaches to 
compensation would be acceptable when these conditions are not met.
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    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 cost-effective. The RTO or ISO should determine, 
based on historical data as a starting point and updated for changes in 
relevant supply conditions such as changes in fuel prices and generator 
unit availability, the monthly threshold price corresponding to the 
point along the supply stack beyond which the overall benefit from the 
reduced LMP resulting from dispatching demand response resources 
exceeds the cost of dispatching and paying LMP to those resources. This 
price level is to be updated monthly, by each ISO or RTO, as the 
historic data and relevant supply conditions change.\7\
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    \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.
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    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.
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    \8\ 16 U.S.C. 824d (2006).
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    7. In addition, we believe that integrating a determination of the 
cost-effectiveness of demand response resources into the dispatch of 
the ISOs and RTOs may be more precise than the monthly price threshold 
and, therefore, provide the greatest opportunity for load to benefit 
from participation of demand response in the organized wholesale energy 
market administered by an RTO or ISO. However, we acknowledge the 
position of several of the RTOs and ISOs that modification of their 
dispatch algorithms to incorporate the costs related to demand response 
may be difficult in the near term. In 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\
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    \9\ We note that this report is for informational purposes only 
and will neither be noticed nor require Commission action.
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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

[[Page 16660]]

supplies of electric energy at just, reasonable, and not unduly 
discriminatory or preferential rates.\11\
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    \10\ See, e.g., Wholesale Competition in Regions with Organized 
Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC 
Stats. & Regs. ] 31,281, at P 1 (2008) (Order No. 719); see also 
Regional Transmission Organizations, Order No. 2000, FERC Stats. & 
Regs. ] 31,089, at P 1 (1999), order on reh'g, Order No. 2000-A, 
FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist. 
No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607, 348 
U.S. App. DC 205 (DC Cir. 2001).
    \11\ 16 U.S.C. 824d (2006); Order No. 719, FERC Stats. & Regs. ] 
31,281 at P 1.
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    9. As the Commission recognized in Order No. 719, active 
participation by customers in the form of demand response in organized 
wholesale energy markets helps to increase competition in those 
markets.\12\ Demand response, whereby customers reduce electricity 
consumption from normal usage levels in response to price signals, can 
generally occur in two ways: (1) Customers reduce demand by responding 
to retail rates that are based on wholesale prices (sometimes called 
``price-responsive demand''); and (2) customers provide demand response 
that acts as a resource in organized wholesale energy markets to 
balance supply and demand. While a number of States and utilities are 
pursuing retail-level price-responsive demand initiatives based on 
dynamic and time-differentiated 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.
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    \12\ See Order No. 719, FERC Stats. & Regs. ] 31,281 at P 48.
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    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 higher-priced resources to satisfy load.\16\ Second, demand 
response can mitigate generator market power.\17\ This is because the 
more demand response that sees and responds to higher market prices, 
the greater the competition, and the more downward pressure it places 
on generator bidding strategies by increasing the risk to a supplier 
that it will not be dispatched if it bids a price that is too high.\18\ 
Third, demand 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\
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    \13\ Wholesale Competition in Regions with Organized Electric 
Markets, Order No. 719-A, FERC Stats. & Regs. ] 31,292, at P 48 
(2009).
    \14\ NOPR, FERC Stats. & Regs. ] 32,656 at P 4.
    \15\ For example, a study conducted by PJM, which simulated the 
effect of demand response on prices, demonstrated that a modest 
three percent load reduction in the 100 highest peak hours 
corresponds to a price decline of six to 12 percent. ISO-RTO Council 
Report, Harnessing the Power of Demand How RTOs and ISOs Are 
Integrating Demand Response into Wholesale Electricity Markets, 
found at http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/IRC_DR_Report_101607.pdf.
    \16\ Id. (``Demand response tends to flatten an area's load 
profile, which in turn may reduce the need to construct and use more 
costly resources during periods of high demand; the overall effect 
is to lower the average cost of producing energy.'').
    \17\ See Comments of NYISO's Independent Market Monitor filed in 
Docket No. ER09-1142-000, May 15, 2009 (Demand response 
``contributes to reliability in the short-term, resource adequacy in 
the long-term, reduces price volatility and other market costs, and 
mitigates supplier market power.'').
    \18\ Id.
    \19\ See ISO-RTO Council Report, Harnessing the Power of Demand 
How RTOs and ISOs Are Integrating Demand Response into Wholesale 
Electricity Markets at 4, found at http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/IRC_DR_Report_101607.pdf (``Demand response contributes to maintaining system 
reliability. Lower electric load when supply is especially tight 
reduces the likelihood of load shedding. Improvements in reliability 
mean that many circumstances that otherwise result in forced outages 
and rolling blackouts are averted, resulting in substantial 
financial savings * * *.'').
    \20\ For instance, in ERCOT, on February 26, 2008, through a 
combination of a sudden loss of thermal generation, drop in power 
supplied by wind generators, and a quicker-than-expected ramping up 
of demand, ERCOT found itself short of reserves. The system operator 
called on all demand response resources, and 1200 MW of Load acting 
as Resource (LaaRs) responded quickly, bringing ERCOT back into 
balance. Oak Ridge Nat'l Lab., Nat'l Renewable Energy Lab., Tech. 
Rep. NREL/TP-500-43373, ERCOT Event on Feb. 26, 2008: Lessons 
Learned (Jul. 2008).
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    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 non-generation resources, including demand response 
resources, to be used in the provision of certain ancillary services 
where appropriate on a comparable basis to service provided by 
generation resources.\22\ Order No. 890-A further required transmission 
providers to develop transmission planning processes that treat all 
resources, including demand response, on a comparable basis.\23\
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    \21\ See Energy Policy Act of 2005, Public Law 109-58, Sec.  
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.'').
    \22\ Preventing Undue Discrimination and Preference in 
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241, 
at P 887-88 (2007), order on reh'g, Order No. 890-A, FERC Stats. & 
Regs. ] 31,261 (2007), order on reh'g and clarification, Order No. 
890-B, 123 FERC ] 61,299 (2008), order on reh'g, Order No. 890-C, 
126 FERC ] 61,228 (2009), order on clarification, Order No. 890-D, 
129 FERC ] 61,126 (2009).
    \23\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 216.
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    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\
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    \24\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 47-49.
    \25\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 194.
    \26\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 247.
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    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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    \27\ Other demand response programs allow demand response to be 
used as a capacity resource and as a resource during system 
emergencies or permit the use of demand response for synchronized 
reserves and regulation service. See, e.g., PJM Interconnection, 
L.L.C., 117 FERC ] 61,331 (2006); Devon Power LLC, 115 FERC ] 
61,340, order on reh'g, 117 FERC ] 61,133 (2006), appeal pending sub 
nom. Maine Pub. Utils. Comm'n v. FERC, No. 06-1403 (D.C. Cir. 2007); 
New York Indep. Sys. Operator, Inc., 95 FERC ] 61,136 (2001); NSTAR 
Services Co. v. New England Power Pool, 95 FERC ] 61,250 (2001); New 
England Power Pool and ISO New England, Inc., 100 FERC ] 61,287, 
order on reh'g, 101 FERC ] 61,344 (2002), order on reh'g, 103 FERC ] 
61,304, order on reh'g, 105 FERC ] 61,211 (2003); PJM 
Interconnection, L.L.C., 99 FERC ] 61,227 (2002); California 
Independent System Operator Corp., 132 FERC ] 61,045 (2010).

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[[Page 16661]]

    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 real-time energy markets. As a 
result, the levels of compensation for demand response vary 
significantly among RTOs and ISOs.\28\ For example, PJM 
Interconnection, L.L.C. (PJM) pays the LMP minus the generation and 
transmission portions of the retail 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\
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    \28\ See New England, Inc., Docket No. ER09-1051-000; ISO New 
England, Inc., Docket No. ER08-830-000; Midwest Indep. Transmission 
Sys. Operator, Inc., Docket No. ER09-1049-000.
    \29\ See 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.
    \30\ For example, under ISO-NE's Real-Time Price Response 
Program, the minimum bid is $100/MWh and a demand response resource 
is paid the higher of LMP or $100/MWh. For the Day-Ahead Load 
Response Program, the minimum offer level is calculated on a monthly 
basis and is the Forward Reserve Fuel Index ($/MMBtu) multiplied by 
an effective heat rate of 11.37 MMBtu/MWh. The maximum offer level 
is $1,000/MWh. See sections III.E.2.1 and III.E.3.2 of Appendix E of 
the ISO New England Transmission, Markets and Services Tariff. NYISO 
implements a day-ahead demand response program by which resources 
bid into the market at a minimum of $75/MWh and can get paid the 
LMP. See section 4.2.2.9 (``Day-Ahead Bids from Demand Reduction 
Providers to Supply Energy from Demand Reductions'') of NYISO's 
Market Services Tariff.
    \31\ Midwest ISO FERC Electric Tariff characterizes Demand 
Response Resources (DRR) as either DRR-Type I or DRR-Type II. DRR-
Type I are capable of supplying a specific quantity of energy or 
contingency reserve through physical load interruption. DRR-Type II 
are capable of supplying energy and/or operating reserves over a 
dispatchable range. See sections 39.2.5A and 40.2.5 of the Tariff.
    \32\ See Charges and Payments for Purchases and Sales for Demand 
Response Resources. Midwest ISO FERC Electric Tariff, section 
39.3.2C.
    \33\ See section 11.2.1.1 IFM Payments for Supply of Energy, 
CAISO FERC Electric Tariff. CAISO notes that for a Proxy Demand 
Resource that is made up of aggregated loads, the Resource is paid 
the weighted average of the LMPs of each pricing node where the 
underlying aggregate loads reside. See CAISO, 132 FERC ] 61,045, at 
P 26 n.14 (2010).
    \34\ The Commission has directed SPP to report on ways it can 
incorporate demand response into its imbalance market. Southwest 
Power Pool, Inc., 128 FERC ] 61,085 (2009). As of September 1, 2010, 
SPP has submitted seven informational status reports regarding its 
efforts to address issues related to demand response resources. In 
orders addressing SPP's compliance with Order No. 719, the 
Commission also directed SPP to make another compliance filing 
addressing demand response participation in its organized markets. 
Southwest Power Pool, Inc., 129 FERC ] 61,163, at P 51 (2009). On 
May 19, 2010, SPP submitted revisions to its Open Access 
Transmission Tariff in Docket Nos. ER09-1050-004 and ER09-748-002 to 
comply with the Commission's requirements established in Order Nos. 
719 and 719-A. These filings are pending before the Commission.
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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\
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    \35\ NOPR, FERC Stats. & Regs. ] 32,656.
    \36\ See Appendix for a list of commenters.
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    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\
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    \37\ Supplemental Notice of Proposed Rulemaking and Notice of 
Technical Conference, 75 FR 47499 (Aug. 6, 2010), 132 FERC ] 61,094 
(2010) (Supplemental NOPR).
    \38\ See Notice of Technical Conference (Aug. 27, 2010).
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IV. Discussion

    17. Based upon the record in this proceeding, the Commission herein 
requires greater uniformity in compensating demand response resources 
participating in organized wholesale energy markets. This Final Rule 
also addresses the allocation of costs resulting from the commitment of 
demand response, directing that such costs be allocated among those 
customers who benefit from the lower LMP resulting from the demand 
response.

A. Compensation Level

1. NOPR Proposal
    18. The NOPR proposed to require RTOs and ISOs to pay the LMP in 
all hours for demand reductions made in response to price signals. The 
NOPR sought to provide comparable compensation to generation and demand 
response providers, based on the premise that both resources provide a 
comparable service to RTOs and ISOs for purposes of balancing supply 
and demand and maintaining a reliable electricity grid.\39\ Also as 
stated in the NOPR, the proposed compensation level was designed to 
allow more demand response resources to cover their investment costs in 
demand response-related technology (such as advanced metering) and 
thereby facilitate their ability to participate in organized wholesale 
energy markets.\40\ The Commission sought comments on the 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.
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    \39\ NOPR, FERC Stats. & Regs. ] 32,656 at P 15.
    \40\ Id. at P 16.
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    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:

[[Page 16662]]

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.
---------------------------------------------------------------------------

    \41\ Supplemental NOPR, 132 FERC ] 61,094 at P 8-9.
    \42\ See Sept. 13, 2010 Tr.
---------------------------------------------------------------------------

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:
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    [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\
---------------------------------------------------------------------------

    \44\ DR Supporters August 30, 2010 Reply Comments (Kahn 
Affidavit at 2 (footnote omitted)).

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\
---------------------------------------------------------------------------

    \45\ Verso May 13, 2010 Comments at 3-4; Alcoa May 13, 2010 
Comments at 9.
    \46\ Occidental May 13, 2010 Comments at 11.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \47\ Viridity June 18, 2010 Comments at 5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \48\ ISO-NE May 13, 2010 Comments at 3.
    \49\ See, e.g., APPA May 13, 2010 Comments at 12; Capital Power 
May 13, 2010 Comments at 2.
    \50\ EPSA May 13, 2010 Comments at 72.
    \51\ See, e.g., PSEG May 13, 2010 Comments at 8.
    \52\ Battelle May 13, 2010 Comments at 3.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \53\ AEP May 13, 2010 Comments at 7-8.
    \54\ ODEC May 13, 2010 Comments at 12.
    \55\ Calpine May 13, 2010 Comments at 4-5.
---------------------------------------------------------------------------

    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

[[Page 16663]]

LMP without an offset for some portion of the retail rate does not send 
the proper economic signal to providers of demand response, because it 
fails to take into account the retail rate savings associated with 
demand response, and thereby overcompensates the demand response 
provider. As described by Dr. William W. Hogan on behalf of EPSA, this 
is sometimes called a double-payment for demand reductions, because 
demand response providers would ``receive'' both the cost 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\
---------------------------------------------------------------------------

    \56\ EEI May 13, 2010 Comments at 4-5. See also Robert L. 
Borlick May 13, 2010 Comments at 4. Mr. Borlick argues that the 
correct price is LMP minus the Marginal Foregone Retail Rate (MFRR), 
describing the economically efficient price that should be paid to a 
demand response provider as ``its offer price minus the price in its 
retail tariff at which it would have purchased the curtailed 
energy.'' Mr. Borlick asserts that this amount accurately represents 
the forgone opportunity costs that result when a demand response 
provider reduces its load. Id.
    \57\ See May 13, 2010 Comments of: APPPA; AEP; The Brattle 
Group; Calpine; ConEd; Consumers Energy; CPG; Detroit Edison; Direct 
Energy; Dominion; Duke Energy; Edison Mission; EEI; EPSA; Exelon; 
FTC; GDF; NYISO on behalf of the ISO RTO Council; ICC; IPPNY; 
Indicated New York TOs; IPA; ISO-NE; Midwest TDUs; Mirant; Midwest 
ISO TOs; NEPGA; NYISO; ODEC; OMS; PJM; PJM IMM; P3; Potomac 
Economics; PG&E; Ohio Commission; Robert L. Borlick; Roy Shanker; 
and RRI Energy.
    \58\ See Attachment to Answer of EPSA, Providing Incentives for 
Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009, 
submitted in Docket No. EL09-68-000.
    \59\ EPSA May 13, 2010 Comments at 23. See also May 13, 2010 
Comments of APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; 
New York Commission at 5; PJM at 6; PSEG at 5; and Potomac Economics 
at 6-8.
    \60\ Attachment to Answer of EPSA, Providing Incentives for 
Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009, 
submitted in Docket No. EL09-68-000. In Dr. Hogan's view, supply 
should produce when the price of electricity exceeds its cost of 
production and demand should decline to consume when the costs in 
terms of convenience of delaying use are less than the price of 
electricity.
    \61\ P3 June 14, 2010 Comments at 2, 7-8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \62\ ISO-NE May 13, 2010 Comments at 3-4.
    \63\ Id. at 28.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \65\ New York Commission May 13, 2010 Comments at 8.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \66\ See, e.g., ISO-NE IMM May 13, 2010 Comments at 4-5; Midwest 
ISO TOs May 13, 2010 Comments at 14; PJM May 13, 2010 Comments at 5; 
and Duke Energy May 13, 2010 Comments at 2.
    \67\ EPSA June 30, 2010 Comments at 3.
    \68\ EPSA June 30, 2010 Comments at 23.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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)).
---------------------------------------------------------------------------

    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

[[Page 16664]]

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\

    \71\ DR Supporters Aug. 30, 2010 Reply Comments, Kahn Affidavit 
at 10.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \75\ EDF Oct. 13, 2010 Comments at 2.
    \76\ American Clean Skies Foundation May 13, 2010 Comments at 4.
    \77\ Alcoa May 13, 2010 Comments at 9.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \78\ EPSA May 13, 2010 Comments at 60.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \79\ ODEC May 13, 2010 Comments at 12; Westar May 13, 2010 
Comments at 5-6.
    \80\ Id.
    \81\ Calpine May 13, 2010 Comments at 5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \82\ PIO May 13, 2010 Comments at 8.
    \83\ NEMA May 13, 2010 Comments at 2.
    \84\ EPSA May 13, 2010 Comments at 7.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \85\ PSEG May 13, 2010 Comments at 8.
---------------------------------------------------------------------------

(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

[[Page 16665]]

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\
---------------------------------------------------------------------------

    \86\ See generally May 13, 2010 Comments of NYSCPB; NECA; 
Capital Power; NECPUC; Maryland Commission; New York Commission; 
NSTAR; National Grid; NE Public Systems.
    \87\ Capital Power May 13, 2010 Comments at 5; P3 May 13, 2010 
Comments at 5.
    \88\ NECPUC May 13, 2010 Comments at 13; see also Sept. 13, 2010 
Tr. 13:6-19 (Mr. Keene); Maryland Commission May 13, 2010 Comments 
at 4-5.
    \89\ See, e.g., ACEEE Oct. 13, 2010 Comments 3-4. See also 
National Grid May 13, 2010 Comments at 4-5; NSTAR Electric Company 
(NSTAR) May 14, 2010 Comments at 3; Maryland Commission May 13, 2010 
Comments, submitting Analysis of Load Payments and Expenditures 
under Different Demand Response Compensation Schemes at 10-11 
(discussing PJM analysis showing that paying demand response 
providers LMP for all hours after compensating LSEs for lost 
revenues would not benefit customers in general but that positive 
economic benefits results when demand response providers receive LMP 
during at least the top 100 hours (the highest priced energy 
hours)).
    \90\ See, e.g., CDWR May 13, 2010 Comments at 11; National Grid 
May 13, 2010 Comments at 8; ISO-NE May 13, 2010 Comments at 34; 
ACEEE Oct. 13, 2010 Comments 4. But see ISO-NE May 13, 2010 Comments 
at 32-33 (contending that no baseline estimation methodology that 
relies upon historical customer meter data can accurately and 
reliably estimate an individual customer's normal energy usage 
pattern if that customer responds frequently to price signals).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \91\ NECAA May 13, 2010 Comments at 11; NYSCPB May 13, 2010 
Comments at 5; National Grid May 13, 2010 Comments at 4-5.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \92\ Viridity Oct. 13, 2010 Comments at 14.
    \93\ NAPP Oct. 13, 2010 Comments at 2.
    \94\ Viridity Oct. 13, 2010 Comments at 14; NAPP Oct. 13, 2010 
Comments at 3; AMP Oct. 13, 2010 Comments at 4; CAISO Oct. 13, 2010 
Comments at 5 and 16.
    \95\ EDF Oct. 13, 2010 Comments at 2; Viridity Oct. 13, 2010 
Comments at 10; ELCON Oct. 13, 2010 Comments at 3.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \96\ See, e.g., Oct. 13, 2010 Comments of: Midwest TDUs at 4-5; 
NEPGA at 8, NJBPU at 2-3; NAPP at 2-3; P3; SPP at 3-4; SDG&E, SoCal 
Edison, and PG&E at 4-6; Viridity Energy at 2; ELCON at 2; AMP at 2; 
CDWR at 1, 4-5; CAISO at 4, 15; Detroit Edison at 2; Smart Grid 
Coalition at 2; Duke Energy at 2; EDF at 2; FTC at 1; EPSA at 4; 
Indicated New York TOs at 3; Midwest ISO at 9; Steel Manufacturers 
Ass'n at 3.
    \97\ P3 Oct. 13, 2010 Comments at 5.
    \98\ Sept. 13, 2010 Tr. 155:21-24 (Mr. Robinson); Sept. 13, 2010 
Tr. 141-42 (Mr. Centolella); Dr. Hogan Sept. 13, 2010 Comments at 5; 
Sept. 13, 2010 Tr. 60 (Dr. Shanker); Sept. 13, 2010 Tr. 27 (Mr. 
Newton); SDG&E May 13, 2010 Comments at 4.
    \99\ Sept. 13, 2010 Tr. 19 (Mr. Ott).
    \100\ Midwest ISO TOs May 13, 2010 Comments at 16.
    \101\ NEPGA June 21, 2010 Comments at 1-2.
    \102\ 120 FERC ] 61,085 (2007).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

(c) Standardization or Regional Variations in Compensation
    43. With regard to potential regional variations for compensation 
mechanisms across RTO and ISO markets, many commenters, mostly those in 
support of the NOPR's proposed compensation level, endorse 
standardization.\104\ Some parties, primarily industrial customers and 
some customer advocates, argue that, regardless of location, both 
demand response providers and generators provide a comparable service 
in terms of balancing supply and demand, as discussed above, and 
therefore should be comparably compensated at the LMP.\105\ They argue 
that fair, non-discriminatory markets must adapt and eliminate barriers 
to entry to the use and incorporation of traditional and non-
traditional resources--where non-traditional resources include 
actively-managed demand--in the dispatch and management of the electric 
system.\106\ They further posit that the lack of a unified policy 
itself represents a regulatory barrier to demand response,\107\ and 
that a consistent set of

[[Page 16666]]

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\
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    \104\ See May 13, 2010 Comments of: ArcelorMittal; Alcoa; ACENY; 
ACC; AFPA; CDWR; Mayor Bloomberg; Consert; CDRI; CPower; DR 
Supporters; Derstine's; Durgin; Electricity Committee; ELCON; 
Electrodynamics; ECS; EnerNOC; ICUB; IECA; IECPA; Irving Forest; 
Joint Consumers; Limington; Madison Paper; Massachusetts AG; NEMA; 
National Energy; National League of Cities; NJBPU; NAPP; Occidental; 
Okemo; Partners; Pennsylvania Department of Environment; 
Pennsylvania Commission; Rep. Chris Ross; Precision; PRLC; Raritan; 
SDEG, SoCal; PG&E; Schneider; Governor O'Malley; Steel Manufacturers 
Ass'n; Verso; Viridity; Virginia Committee; Wal-Mart; Waterville.
    \105\ See, e.g., Steel Manufacturers Ass'n May 13, 2010 Comments 
at 12; NEMA May 13, 2010 Comments at 5.
    \106\ Steel Manufacturers Ass'n May 13, 2010 Comments at 12.
    \107\ PIO May 13, 2010 Comments at 9; DR Supporters Aug. 30, 
2010 Comments at 6-7.
    \108\ See, e.g., Alcoa May 13, 2010 Comments at 13.
    \109\ NECPUC May 13, 2010 Comments at 4; NYISO May 13, 2010 
Comments at 16.
    \110\ Viridity Energy May 13, 2010 Comments at 4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \111\ See, e.g., May 13, 2010 Comments of: ConEd at 3-4; 
Consumers Energy at 2; California Commission at 9; CMEEC at 2-3, 14-
15; Detroit Edison at 3-5; Dominion at 8; Duke Energy at 4; EPSA at 
6; Hess at 4; Indicated New York TOs at 3; Maryland Commission at 5; 
Midwest TDUs at 2, 6; Midwest ISO TOs at 16; National Grid at 5-6; 
11-12; New York Commission at 4, 11; NCPA at 3; NYISO at 2-3; ODEC 
at 27; PJM at 5-6; SPP at 1.
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3. Commission Determination
    45. The Commission acknowledges the diverging opinions of 
commenters regarding the appropriate level of compensation for demand 
response resources. As discussed above, commenters are split on this 
issue, with some in favor of paying the LMP for demand reductions in 
the day-ahead and real-time energy markets in all hours, others arguing 
that paying the LMP for demand reductions under any conditions will 
result in over-compensation or distortions in incentives to reduce 
consumption, and still others arguing that paying the LMP for demand 
reductions is only appropriate when it is reasonably certain to be 
cost-effective.
    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\
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    \112\ Elec. 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).
    \113\ See 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'').
---------------------------------------------------------------------------

    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\
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    \114\ See generally May 13, 2010 Comments of NYSCPB; NECA; 
Capital Power; NECPUC; Maryland Commission; New York Commission; 
NSTAR; National Grid; NE Public Systems.
    \115\ The Commission's findings in this Final Rule do not 
preclude the Commission from determining that other approaches to 
compensation would be acceptable when these conditions are not met.
    \116\ NOPR at P 12.
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    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:
    <bullet> 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.
    <bullet> 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.
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    \117\ Andrew L. Ott Sept. 13, 2010 Statement at 1.
    Economic and Capacity-based demand response clearly provides 
benefits to regional grid operation and the wholesale market 
operation. * * * These demand resources provide benefits by 
providing valuable alternatives to PJM in maintaining operational 
reliability and in promoting efficient market operations.
    Id. at 1; see also CDRI May 13, 2010 Comments at 10; CDWR May 
13, 2010 Comments at 5; NJPBU May 13, 2010 Comments at 2.
---------------------------------------------------------------------------

    50. With respect to the second cost-effectiveness condition, the 
record leads us to alter the proposal set forth in the NOPR in this 
proceeding. As various commenters explain, dispatching demand response 
resources may result in an increased cost per unit to load 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

[[Page 16667]]

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.
---------------------------------------------------------------------------

    \118\ As stated above, dispatching generation resources does not 
produce this billing unit effect because it does not result in a 
decrease of load.
    \119\ As a simple example, assume a market of 100 MW, with a 
current LMP of $50/MWh without demand response, and an LMP of $40/
MWh if 5 MW of demand response were dispatched. Total payments to 
generators and load would be $4,000 with demand response compared to 
the previous $5,000. Even though, the reduced LMP is now being paid 
by less load, only 95 MW compared to 100 MW, the price paid by each 
remaining customer would decrease from $50/MWh to $42.11/MWh 
($4,000/95). Therefore, the payment of LMP to demand resources is 
cost-effective.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \120\ See DR Supporters Aug. 30, 2010 Reply Comments (Kahn 
Affidavit at 2 (footnote omitted)).
---------------------------------------------------------------------------

    54. The Commission finds that demand response resources that clear 
in the day-ahead and real-time energy markets should receive the same 
market-clearing LMP as compensation in the organized wholesale energy 
markets when those resources meet the conditions established here as a 
cost-effective alternative to the next highest-bid 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.
---------------------------------------------------------------------------

    \121\ See, e.g., ISO-NE May 13, 2010 Comments at 3; APPA May 13, 
2010 Comments at 12; Capital Power May 13, 2010 Comments at 2; EPSA 
May 13, 2010 Comments at 72.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \122\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 83 
(citing Federal Energy Regulatory Commission Staff, A National 
Assessment of Demand Response Potential (June 2009), found at http://www.ferc.gov/legal/staff-refports/06-09-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.
---------------------------------------------------------------------------

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:
---------------------------------------------------------------------------

    \123\ See, e.g., Monitoring Analytics May 13, 2010 Comments at 
4-6.

    These circumstances--specifically, the fact that pass-through of 
the LMP is costly and (perhaps) politically infeasible, the possibly 
prohibitive cost of the metering necessary to charge each ultimate 
user, moment-by-moment, the often dramatic changes in true marginal 
costs for each--can justify direct payment at full LMP to 
distributors and ultimate customers who promise to guarantee

[[Page 16668]]

their immediate response to such increases in true marginal costs of 
supplying them.\124\
---------------------------------------------------------------------------

    \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.'').

---------------------------------------------------------------------------
    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\
---------------------------------------------------------------------------

    \125\ EnerNOC May 13, 2010 Comments at 4; see also Alcoa May 13, 
2010 Comments at 4; Viridity May 13, 2010 Comments at 5-6.

    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\
---------------------------------------------------------------------------

    \126\ Generation and demand response resources have the 
potential to earn other revenues through bilateral arrangements, 
capacity markets where they exist, and ancillary services.
---------------------------------------------------------------------------

    60. Another issue raised by a number of commenters, largely 
representing generators, is whether a lower payment based on LMP-G is 
the economically-efficient price that sends the proper price signal to 
a potential demand response provider. These commenters argue that, by 
not consuming energy, demand response providers already effectively 
receive ``G,'' the retail rate that they do not need to pay. They 
therefore contend that demand response providers will be 
overcompensated unless ``G'' is deducted from 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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \128\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 154.
    \129\ DR Supporters Aug. 30, 2010 Reply Comments (Kahn Affidavit 
at 9-10).
---------------------------------------------------------------------------

    62. Several other considerations also support this Commission 
conclusion. In the absence of market power concerns, the Commission 
does not inquire into the costs or benefits of production for the 
individual resources participating as supply resources in the organized 
wholesale electricity markets and will not here, as requested by some 
commenters, single out demand response resources for adjustments to 
compensation. The Commission has long held that payment of LMP to 
supply resources clearing in the day-ahead and real-time energy markets 
encourages ``more efficient supply and demand decisions in both the 
short run and long run,'' \130\ notwithstanding the particular costs of 
production of individual resources. Commenters have not justified why 
it would be appropriate for the Commission to continue to apply this 
approach to generation resources yet depart from this approach for 
demand response resources.
---------------------------------------------------------------------------

    \130\ See New England Power Pool, 101 FERC ] 61,344, at P 35 
(2002).
---------------------------------------------------------------------------

    63. In addition, we agree with the New York Commission that given 
the differences in retail rate structures across RTO footprints and 
even within individual States, requiring ISOs and RTOs to incorporate 
such disparate retail rates into wholesale payments to wholesale demand 
response providers would, even though perhaps feasible, create 
practical difficulties for a number of parties, including State 
commissions and ISOs and RTOs. Moreover, incorporating such rates could 
result in customer uncertainty as to the prevailing wholesale rate.
    64. Some arguments advocating paying LMP-G rather than LMP are 
based on an assumption that demand response resources need to purchase 
the energy in day-ahead markets or by other means and then ``resell'' 
the energy to the market in the form of demand response. However, as 
the Commission previously stated in EnergyConnect, the Commission does 
not view demand response as a resale of energy back into the energy 
market.\131\ Instead, as the Commission also explained in EnergyConnect 
and in Order No. 719-A, the Commission asserts jurisdiction with 
respect to demand response in organized wholesale energy markets 
because of the effect of demand response and related RTO and ISO market 
rules on Commission-jurisdictional rates.\132\
---------------------------------------------------------------------------

    \131\ See EnergyConnect, 130 FERC ] 61,031 at P 32.
    \132\ Id.; see also Order No. 719-A, FERC Stats. & Regs. ] 
31,292, at P 47.
---------------------------------------------------------------------------

    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

[[Page 16669]]

from generation and demand response resources to establish the order of 
dispatch which secures the most economical supplies needed, consistent 
with the reliability constraints imposed on the system. Imposing a 
cost-effectiveness condition does not convert this unit commitment 
process by the RTO or ISO into collusion among bidders, whether 
generation or demand response. Furthermore, the market rules 
administering such a program would be approved by this Commission and 
demand response resources would be subject to Commission-approved 
rules, just like any other participants in the organized wholesale 
energy markets. In addition, arguments that the subject of this 
proceeding is equivalent to the types of market manipulation 
investigated in Amaranth and ETP are groundless and without merit. In 
Amaranth, the trader was accused of engaging in a fraudulent scheme 
with scienter in connection with a jurisdictional transaction. Here, 
there is no such allegation, merely speculation that the Commission is 
somehow facilitating coordination of demand-side bidders in order to 
lower prices.
    66. Some commenters argue that demand response providers and 
generators should both be compensated at the market clearing price only 
if both are subject to the same market participation rules, penalty 
structures, testing requirements, and market monitoring provisions. The 
ISOs and RTOs already consider how to ensure 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.
---------------------------------------------------------------------------

    \133\ See PJM Interconnection, L.L.C., 129 FERC ] 61,081 (2009).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \134\ For example, National Grid states that the threshold could 
be triggered by a particular price on the supply offer curve at 
which the additional cost of paying LMP to demand response resources 
is most likely to be outweighed by LMP reductions in the wholesale 
energy market as a result of the demand reductions produced by these 
resources. National Grid May 13, 2010 Comments at 6. Those in favor 
of a price threshold include National Grid (but allow the ISO or RTO 
to identify threshold based on analysis); NE Public Systems; NECPUC; 
ISO-NE (minimum offer price based on fixed heat rate, times a fuel 
price index); New York Commission (supports ISO-NE's heat rate 
indexed price threshold).
    \135\ NYISO implements a day-ahead demand response program by 
which resources bid into the market at a minimum of $75/MWh and can 
get paid the LMP. See section 4.2.2.9 (``Day-Ahead Bids from Demand 
Reduction Providers to Supply Energy from Demand Reductions'') of 
NYISO's Market Services Tariff.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \136\ Sept. 13, 2010 Tr. 52-53 (Mr. Peterson); Massachusetts AG 
Oct. 13, 2010 Comments at 23.
    \137\ Massachusetts AG Oct. 13, 2010 Comments (attachment, 
Demand Response Potential in ISO New England's Day-Ahead Energy 
Market, Synapse Energy Economics, Inc. Oct. 11, 2010 at 9). See 
generally, NECPUC May 13, 2010 Comments at 18.
    \138\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \139\ National Grid May 13, 2010 Comments at 6; New York 
Commission May 13, 2010 Comments at 10; Viridity May 13, 2010 
Comments at 24. See generally NECPUC, New York Commission; ISO-NE; 
NSTAR; ACEEE; and NYSCPB Oct. 13, 2010 Comments.
    \140\ The DALRP establishes a minimum offer price by 
approximating the variable cost component, in the form of a fuel 
cost, of a hypothetical peaking unit sufficiently high enough in the 
supply stack to ensure net benefits. On a monthly basis, this 
minimum offer price is reset to reflect the product of an 
appropriate fuel price index and a proxy heat rate. See NECPUC Oct. 
13, 2010 Comments at 15.
    \141\ NECPUC Oct. 13, 2010 Comments at 14-16; NECPUC May 13, 
2010 Comments at 17.
    \142\ Id. at 5-6.
---------------------------------------------------------------------------

    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 cost-effective 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\
---------------------------------------------------------------------------

    \143\ Maryland Commission May 13, 2010 Comments at 4-5; see 
generally NSTAR, ACEEE and NYSCPB Oct. 13, 2010 Comments.
    \144\ Maryland Commission May 13, 2010 Comments at 4 n.9.
---------------------------------------------------------------------------

    72. The Consumer Demand Response Initiative (CDRI) proposes a 
mechanism for determining what demand response resources are cost-
effective in any

[[Page 16670]]

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\
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    \145\ The approach submitted by CDRI was developed for 
implementation in the ISO-NE day-ahead energy market. The discussion 
here is generalized to be applicable to any energy market that uses 
security-constrained economic dispatch to select the least-cost 
resources and establish a market-clearing price.
    \146\ PIO July 27, 2010 Comments at 6; Massachusetts AG Oct. 13, 
2010 Comments at 11; Viridity Oct. 13, 2010 Comments at 2. See CDRI 
May 13, 2010 Comments for a full description of the algorithms.
---------------------------------------------------------------------------

    73. Under the proposal submitted by CDRI, the demand response bids 
are part of the supply stack to which a security-constrained economic 
dispatch process is applied. All demand response bids that result in a 
lower price to customers, including consideration of the reduced number 
of billing units, are selected while those bids that raise the price, 
as compared to selecting the next generation bid in the supply stack, 
are not. This dispatch algorithm, as proposed, would be used by the ISO 
or RTO to determine a revised LMP that would be charged to load. The 
revised LMP creates a surplus (or over-collection) of revenue for the 
ISO or RTO that is then distributed to the LSEs through a settlement 
algorithm with the goal of holding LSEs harmless.\147\
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    \147\ CDRI May 13, 2010 Comments Attachment B at 18. CDRI states 
that the dispatch and settlement algorithms ``could be employed to 
evaluate dispatch and assure customer benefits, without being 
employed to perform allocations and settlements.'' CDRI Oct. 13, 
2010 Comments at 4.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \148\ Sept. 13, 2010 Tr. 80-81 (Dr. Ethier).
    \149\ Id.
    \150\ Sept. 13, 2010 Tr. 82:16-21 (Mr. Ott).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \151\ See generally AEP, Midwest ISO, Occidental, NYISO, 
Constellation Oct. 13, 2010 Comments.
    \152\ See, e.g., Midwest ISO October 13, 2010 Comments at 9-14 
and Table 1 (setting forth comprehensive list of benefits and costs 
of demand response by type of market participants); Occidental 
October 13, 2010 Comments at 4-5 (any net benefits test must take 
into consideration offsetting variables, such as higher LMPs in the 
subsequent periods where demand rebound increases market price, and 
capacity market price effects); AEP October 13, 2010 Comments at 3-4 
(AEP does not recommend the use of a societal benefits component 
(i.e., health, environment, or employment efforts)).
    \153\ Constellation October 13, 2010 Comments at 3-4.
---------------------------------------------------------------------------

    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 
high-priced hours to minimize the economic distortions and avoid 
significant administrative complexities.\154\
---------------------------------------------------------------------------

    \154\ ISO-NE Oct. 13, 2010 Comments at 4-5 and 21.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \155\ See, e.g., Sept. 13, 2010 Tr. 94:13-22 (Dr. Shanker); 
Sept. 13, 2010 Tr. 98:4-24 (Mr. Peterson); Sept. 13, 2010 Tr. 99:2-7 
(Mr. Sunderhauf); ISO-NE Oct. 13, 2010 Comments at 5.
    \156\ Sept. 13, 2010 Tr. 99:1-24 (Mr. Sunderhauf); ISO-NE Oct. 
13, 2010 Comments at 5.
    \157\ ISO-NE Oct. 13, 2010 Comments at 6.
    \158\ Sept. 13, 2010 Tr. 103-104 (Mr. Weishaar).
    \159\ Sept. 13, 2010 Tr. 106:16-24 (Mr. Sipe).

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[[Page 16671]]

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 cost-effective dispatch of demand 
resources.
---------------------------------------------------------------------------

    \160\ There will be inherent differences in the supply curves 
determined by each RTO and ISO under the net benefits test required 
herein due to decisions the RTOs and ISOs must make based on supply 
data for their regions, the mathematical methods each RTO and ISO 
chooses to use for smoothing the supply curves, the certainty of 
changes in supply due to outages in each region, local generation 
heat rates, and the choice of relevant fuel price indices.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \161\ The ISOs and RTOs are to select a representative supply 
curve for the study month, smooth the supply curve using numerical 
methods, and find the price/quantity pair above which a one megawatt 
reduction in quantity that is paid LMP would result in a larger 
percentage decrease in price than the corresponding percentage 
decrease in quantity (billing units). Beyond that point, a reduction 
in quantity everywhere along an upward sloping supply curve would be 
cost-effective.
    \162\ Thus, the test is to determine where: (Delta LMP x MWh 
consumed) > (LMP new x 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.
---------------------------------------------------------------------------

    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 cost-effective 
and when demand response is paid the LMP but is not cost-effective. We 
accept this result given the apparent computational difficulty of 
adopting a dynamic approach that incorporates the billing unit effect 
in the dispatch algorithms at this time.\164\
---------------------------------------------------------------------------

    \163\ Supply elasticity is defined as the percentage change in 
quantity supplied divided by the percentage change in price. When 
the elasticity is less than or equal to one, supply is considered 
inelastic. So, for example, in the inelastic portion of the supply 
curve, a reduction in quantity supplied by one percent will result 
in more than a one percent decrease in price. Using the terms 
related to demand response compensation, the billing unit effect 
(percentage change in quantity supplied) will be more than offset by 
lower LMP (percentage change in price), thus resulting in lower 
prices for wholesale load.
    \164\ See supra note 114.
---------------------------------------------------------------------------

    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 mid-
February). 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.
---------------------------------------------------------------------------

    \165\ See supra P 6.
---------------------------------------------------------------------------

    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

[[Page 16672]]

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.
---------------------------------------------------------------------------

    \166\ ``[G]etting this decision resolved is an impediment to all 
the other stuff we want to do with price response to demand, and DR 
generally in our market * * * so until we get through this, we're 
not going to make much progress * * * the implication of that is if 
you send something back that leaves a lot of room for debate, it's 
going to be a while on all those other things.'' Testimony of Robert 
Ethier, Vice President, Market Design, ISO-NE, Sept. 13, 2010 Tr. at 
136.
---------------------------------------------------------------------------

    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 real-
time 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.
---------------------------------------------------------------------------

    \167\ Additionally, the arguments presented for focusing on the 
effect of demand response compensation in wholesale energy markets 
on capacity markets were not convincing--that decreases in energy 
market revenues by generators will be recouped in the form of 
increased capacity prices. First, they fail to consider how the 
increased participation by demand resources could actually increase 
potential suppliers in the capacity markets by reducing barriers to 
demand resources, which would tend to drive capacity prices down. 
Second, they did not examine the way in which capacity markets 
already may take into account energy revenues.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \168\ Demand Response Compensation in Organized Wholesale Energy 
Markets, FERC Stats. & Regs. ] 32,656, at P 1 (2010).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \169\ See, 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%20IMPLEMENTATION%20COMPARISON%20(20100524)
.XLS).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \170\ Illinois CUB May 14, 2010 Comments at 16-17; Joint 
Consumers May 13, 2010 Comments at 12; P3 May 12, 2010 Comments at 
38; Westar May 13, 2010 Comments at 3.
    \171\ See, e.g., ISO-NE May 13, 2010 Comments at 32.
    \172\ Id.
    \173\ ISO-NE May 13, 2010 Comments at 34. ISO-NE identifies 
several practices that, in its view, might be deployed by a demand 
responder to receive payment when it has not, in fact, responded to 
price. ISO-NE states that observations of such behavior in the Fall 
of 2007 led it to limit the hours demand response offers could clear 
the market. Citing ISO New England Inc., Docket No. ER08-538-000 
(February 5, 2008 filing). ISO-NE May 13, 2010 Comments at 32-34.
    \174\ Id.
    \175\ ISO-NE IMM May 13, 2010 Comments at 9-13 and Attachment A.
    \176\ Westar May 13, 2010 Comments at 3.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \177\ CPower May 13, 2010 Comments at 4-5.
---------------------------------------------------------------------------

    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 
anti-

[[Page 16673]]

manipulation rules and subject to penalties thereunder.'' \178\
---------------------------------------------------------------------------

    \178\ ISO-NE IMM May 13, 2010 Comments at 14 (footnotes omitted) 
(ISO-NE MMU also notes that ``[i]n assessing whether demand 
reductions are genuine, allowance should be made for non-performance 
analogous to a generator's forced outage.'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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\
---------------------------------------------------------------------------

    \180\ ECS May 13, 2010 Comments at 3; Indicated New York TOs May 
13, 2010 Comments at 2-3; Midwest ISO May 13, 2010 Comments at 17, 
21; National Grid May 13, 2010 Comments at 11-12; NSTAR May 14, 2010 
Comments at 9; PPL May 13, 2010 Comments at 4.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \181\ See, e.g., PJM Interconnection, L.L.C., 123 FERC ] 61,257 
(2008).
    \182\ Standards for Business Practices and Communication 
Protocols for Public Utilities, Final Rule, 131 FERC ] 61,022 
(2010).
    \183\ Id., at P 32-34.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \184\ 18 CFR 1.c (2010).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \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.
    \186\ As further addressed below, several commenters assert that 
the costs of demand response compensation should be borne by only 
those market participants determined to have benefitted from the 
subject load reduction, as determined by some type of net benefits 
test. See, e.g., May 13, 2010 Comments of: ISO-NE at 5-6; NECPUC at 
22; PJM at 12-14; P3 at 37-38.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \187\ EPSA May 12, 2010 Comments at 67; Midwest TDUs May 13, 
2010 Comments at 1; ODEC May 14, 2010 Comments at 5; Potomac 
Economics May 14, 2010 Comments at 9-10; RRI May 13, 2010 Comments 
at 4; SoCal Edison May 13, 2010 Comments at 4 (advocating that the 
local regulatory authority is the proper entity to regulate cost 
allocation); Viridity May 13, 2010 Comments at 24; EnerNOC Sept. 13, 
2010 Comments at 1; Midwest TDUs Sept. 13, 2010 Comments at 2.
    \188\ Massachusetts AG May 13, 2010 Comments at 9-10.
---------------------------------------------------------------------------

    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

[[Page 16674]]

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\
---------------------------------------------------------------------------

    \189\ PJM May 13, 2010 Comments at 15; Midwest ISO May 13, 2010 
Comments at 6; CAISO May 13, 2010 Comments at 6; Detroit Edison May 
13, 2010 Comments at 3-4; EEI May 13, 2010 Comments at 5; NUSCO May 
13, 2010 Comments at 2; National Grid Sept. 13, 2010 Comments at 2-
3; Midwest ISO Oct. 13, 2010 Comments at 4.
    \190\ NECPUC May 13, 2010 Comments at 22; DC OPC May 13, 2010 
Comments at 4; PCA Sept. 10, 2010 Comments at 4; Steel Manufactures 
Ass'n Sept. 13, 2010 Comments at 5; Ohio Commission Sept. 13, 2010 
Comments at 4; Wal-Mart Sept. 14, 2010 Comments at 3.
    \191\ PJM May 13, 2010 Comments at 9; NECPUC May 13, 2010 
Comments at 22; PCA Sept. 10, 2010 Comments at 4.
    \192\ PJM May 13, 2010 Comments at 12; ISO-NE May 13, 2010 
Comments at 5.
    \193\ DC OPC May 13, 2010 Comments at 4. It concedes that this 
could be a complex undertaking and would result in billing a retail 
customer for energy that did not consume. Id.
    \194\ CDRI, Integration of Demand Response Into Day Ahead 
Markets (Attachment B), May 13, 2010 Comments at 16.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \195\ This approach is consistent with long-standing judicially-
endorsed cost allocation principles. See, e.g., Midwest ISO 
Transmission Owners v. FERC, 373 F.3d 1361, 1368, 1370-71 (DC Cir. 
2004); see also Illinois Commerce Comm'n v. FERC, 576 F.3d 470, 476 
(7th Cir. 2009).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \196\ See, e.g., CAISO May 13, 2010 Comments at 12; PJM May 13, 
2010 Comments at 8 (appropriate and efficient demand response 
compensation may require coordination between the Commission, retail 
regulatory authorities, competitive retail suppliers, and other 
RTOs).
    \197\ See ISO-NE IMM May 13, 2010 Comments at 6.
    \198\ Illinois Commission May 13, 2010 Comments at 8; PJM May 
13, 2010 Comments at 23; EEI May 13, 2010 Comments at 4; Capital 
Power May 13, 2010 Comments at 5; ODEC May 13, 2010 Comments at 60; 
Steel Producers May 13, 2010 Comments at 2.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \199\ See Illinois Commission May 13, 2010 Comments at 13; CAISO 
May 13, 2010 Comments at 12-13; PJM IMM May 13, 2010 Comments at 5 
(``The assertion that demand side participants should be paid full 
LMP, regardless of their retail tariff rate, because the current 
approach of paying LMP minus G represents an intervention into 
retail rate design, cannot be correct. The entire demand side 
program exists only because of the disconnect between wholesale and 
retail rates. The assertion that the program design should not 
account for the details of retail rate design leads to the 
conclusion that there should be no demand side program at all.''); 
NECPUC May 13, 2010 Comments at 25 (``As energy market customers 
benefit most from both a well-functioning wholesale market and 
robust participation in retail programs, a balance between these two 
segments is essential. Compensation that increases demand response 
resource participation in the wholesale market should not be so 
generous, from the perspective of the customer, that it makes 
participation in retail programs pale in comparison.''); SDG&E, 
SoCal Edison, and PG&E May 13, 2010 Comments at 4 (``[M]andating 
that ISOs take on settlement responsibility or precluding any retail 
settlement between retail customers, LSEs or DRPs would intrude on 
retail jurisdictional authority and contravenes the premise of 
separation outlined in Order 719.''); Consumers Energy May 13, 2010 
Comments at 3; Detroit Edison May 13, 2010 Comments at 4.
    \200\ See California Independent System Operator Corp., 132 FERC 
] 61,045 (2010).
    \201\ California Commission May 13, 2010 Comments at 9-10. 1. 
See also SDG&E, SCE, PG&E May 13, 2010 Comments at 2 (``[T]he 
Commission should clarify that its order does not preclude LRAs from 
administering retail revenue settlements between retail customers, 
Load Serving Entities (LSEs) and Demand Response Providers (DRPs) 
associated with DR participation in wholesale markets.'').

---------------------------------------------------------------------------

[[Page 16675]]

    105. Other commenters foresee retail regulatory authorities 
effectively taking an end-run around any Commission-mandated 
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:
---------------------------------------------------------------------------

    \202\ See PJM May 13, 2010 Comments at 24; PJM May 13, 2010 
Comments at 18 (It is reasonable to assume that each retail 
regulatory authority in PJM will re-examine the impact of load 
reduction based on wholesale compensation equal to the LMP, 
including cost allocation, on the LSEs subject to its jurisdiction, 
and potentially re-align retail market rules affecting economic load 
response participation.); Delaware Commission and NECPUC May 13, 
2010 Comment at 25; OMS May 13, 2010 Comments at 7 (State 
commissions and LSEs have significant concerns that the potential 
costs for non-participating customers may exceed the benefits that 
ARCs can provide to their States and to participating customers, so 
State commissions will have a significant disincentive to support 
the participation of ARCs in RTO energy markets and in their States 
if LMP compensation is adopted).

    [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\
---------------------------------------------------------------------------

    \203\ Illinois Commission May 13, 2010 Comments at 15.

    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\
---------------------------------------------------------------------------

    \204\ PJM May 13, 2010 Comments at 20-21.
---------------------------------------------------------------------------

    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,
---------------------------------------------------------------------------

    \205\ CAISO May 13, 2010 Comments at 4.

    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\
---------------------------------------------------------------------------

    \206\ OMS May 13, 2010 Comments at 3. See also EEI May 13, 2010 
Comments at 4.

    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\
---------------------------------------------------------------------------

    \207\ Calpine May 13, 2010 Comments at 3.
    \208\ See EPSA May 13, 2010 Comments at 7 (``The NOPR 
incorrectly attempts to resolve retail market barriers to DR 
participation (i.e., lack of dynamic pricing) through a wholesale 
pricing fix.''); RRI Energy May 13, 2010 Comments at 5 (``The NOPR 
is essentially trying to use an inefficient wholesale solution to 
remedy a retail problem. The NOPR does not attempt to address (nor 
should it attempt to address) the various retail rate structures 
that demand response providers in various regions of the country 
face.''); The Brattle Group May 13, 2010 Comments at 8 (``[T]he 
appropriate avoidable retail generation rate is best done through 
agreements between the LSE and the curtailment service provider 
under the oversight of the relevant retail regulating authority. 
This approach . . . avoids requiring the RTO to sort through 
potentially complicated retail rate structures.''); Steel 
Manufacturers Ass'n May 13, 2010 Comments at 9 (``[T]here is no 
rational basis for the Commission, or RTOs, to adopting varying 
demand response participation or compensation rules based on the 
retail pricing method of otherwise qualified participating 
loads.'').
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \209\ DR Supporters Aug. 30, 2010 Reply Comments at 4.
    \210\ Id.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

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

    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

[[Page 16676]]

to undermine efficient wholesale rates rather than the reverse.'' \214\
---------------------------------------------------------------------------

    \212\ Viridity June 18, 2010 Comments at 13.
    \213\ Viridity June 18, 2010 Comments at 14.
    \214\ DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 
4).
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \215\ 16 U.S.C. 824d (2006).
    \216\ Order No. 719-A, FERC Stats. & Regs. ] 31,292 at P 47.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \217\ Order No. 719-A, FERC Stats. & Regs. ] 31,292 at P 52.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \218\ 5 CFR 1320.11(b) (2010).
    \219\ 44 U.S.C. 3507(d) (2006).
---------------------------------------------------------------------------

    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.

----------------------------------------------------------------------------------------------------------------
                                                             Number of
    FERC-516 data collection            Number of          responses per        Hours per     Total annual hours
                                       respondents      respondent per year     response
                                  (a).................  (b)................             (c)  (d) [a*b*c]
----------------------------------------------------------------------------------------------------------------
Compliance filing, including      6 (RTOs and ISOs)...  1 (one-time filing)             300  1,800 (one-time
 tariff provisions and analysis                                                               filing).
 (one-time filing, due 7/22/
 2011).
Study on dynamic net benefits     6 (RTOs and ISOs)...  1 (one-time filing)           2,000  12,000 (one-time
 approach (one-time filing, due                                                               filing).
 9/21/2012).
Monthly update to price           6 (RTOs and ISOs)...  12.................              50  3,600.
 threshold and Web posting (due
 monthly, starting after the
 compliance filing due 7/22/
 2011).
----------------------------------------------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \220\ The one-time study is due on or before September 21, 2012. 
For the purpose of the burden and cost estimates, we are including 
all of the burden and cost related to the study in Year 2, although 
filers may perform part of the work in Year 1.
---------------------------------------------------------------------------

    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

[[Page 16677]]

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: <a href="/cdn-cgi/l/email-protection#f9bd988d98ba959c988b98979a9cb99f9c8b9ad79e968f"><span class="__cf_email__" data-cfemail="c084a1b4a183aca5a1b2a1aea3a580a6a5b2a3eea7afb6">[email protected]</span></a>, 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: <a href="/cdn-cgi/l/email-protection#d9b6b0abb886aaacbbb4b0aaaab0b6b799b6b4bbf7bcb6a9f7beb6af"><span class="__cf_email__" data-cfemail="0867617a69577b7d6a65617b7b6167664867656a266d6778266f677e">[email protected]</span></a>. Comments submitted to OMB should include Docket 
Number RM10-17 and OMB Control Number 1902-0096.

VI. Environmental Analysis

    121. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\221\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact Statement is required for this Final Rule under 
section 380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classifications, and 
services.\222\
---------------------------------------------------------------------------

    \221\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & 
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \222\ 18 CFR 380.4(a)(15) (2010).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \223\ 5 U.S.C. 601-612 (2006).
    \224\ 13 CFR 121.101 (2010).
    \225\ 13 CFR 121.201, Sector 22, Utilities.
---------------------------------------------------------------------------

    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

[[Page 16678]]

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 
<a href="/cdn-cgi/l/email-protection#84e2e1f6e7ebeae8edeae1f7f1f4f4ebf6f0c4e2e1f6e7aae3ebf2"><span class="__cf_email__" data-cfemail="53353621303c3d3f3a3d36202623233c212713353621307d343c25">[email protected]</span></a>, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
<a href="/cdn-cgi/l/email-protection#49393c2b25202a673b2c2f2c3b2c272a2c3b262624092f2c3b2a672e263f"><span class="__cf_email__" data-cfemail="a7d7d2c5cbcec489d5c2c1c2d5c2c9c4c2d5c8c8cae7c1c2d5c489c0c8d1">[email protected]</span></a>.

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

0
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.


0
2. Amend Sec.  35.28 by adding a new paragraph (g)(1)(v) to read as 
follows:


Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (g) * * *
    (1) * * *
    (v) Demand response compensation in energy markets. Each 
Commission-approved independent system operator or regional 
transmission organization that has a tariff provision permitting demand 
response resources to participate as a resource in the energy market by 
reducing consumption of electric energy from their expected levels in 
response to price signals must:
    (A) Pay to those demand response resources the market price for 
energy for these reductions when these demand response resources have 
the capability to balance supply and demand and when payment of the 
market price for energy to these resources is cost-effective as 
determined by a net benefits test accepted by the Commission;
    (B) Allocate the costs associated with demand response compensation 
proportionally to all entities that purchase from the relevant energy 
market in the area(s) where the demand response reduces the market 
price for energy at the time when the demand response resource is 
committed or dispatched.
* * * * *

    Note: The following 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)

[[Page 16679]]

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 market-related benefits.
    However, in a misguided attempt to encourage greater demand 
response participation in the organized energy markets, today's Rule 
imposes a standardized and preferential compensation scheme that 
conflicts both with the Commission's efforts to promote competitive 
markets and with its statutory mandate to ensure supplies of 
electric energy at just, reasonable, and not unduly discriminatory 
or preferential rates.\1\ For these reasons, I cannot support this 
Rule.
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    \1\ 16 U.S.C. Sec.  824d (2006).
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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\
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    \2\ California Commission May 13, 2010 Comments at 6, 
``[P]romulgating a uniform national rule at this time may 
inadvertently impede the implementation of optimal demand response 
compensation for an individual ISO or RTO which address the needs of 
that particular region.'' The California Commission ``is concerned 
that mandatory `one size fits all' pricing may stifle national and 
regional efforts to collect valuable data and experience regarding 
the effects of different demand response program designs on consumer 
participation and conflict with Congressional objectives.''
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    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.
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    \3\ Rule at P 17, 57-59.
    \4\ Rule at P 57-59.
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    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.
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    \5\ Significant barriers do exist which prevent demand response 
from reaching its full potential. Specifically, 24 barriers were 
identified in our National Assessment of Demand Response Potential, 
FERC Staff Report, (June 2009) at 65-67.
    \6\ See Energy Policy Act of 2005, Pub. L. No. 109-58, Sec.  
1252(f), 119 Stat. 594, 965 (2005).
    \7\ Rule at P 59.
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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

[[Page 16680]]

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.
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    \8\ As explained below, I believe that comparable compensation 
is represented by the value realized by the demand resource for 
providing a comparable service, regardless of whether the source of 
that value is a payment from the market or a savings by the 
resource.
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    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\
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    \9\ Rule at P 47-50.
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    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.
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    \10\ Testimony of Audrey Zibelman, President and CEO of Viridity 
Energy, Inc., Sept. 13, 2010 Tr. at 119, ``[T]he fact that we're 
debating this [net benefits test] is somewhat absurd. We have not 
required any other resource to demonstrate a benefit in order to 
enter this market.''
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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\
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    \11\ The proper economic measure of value realized by the demand 
resource is one where the RTO or ISO makes a reduction from the LMP 
to account for the retail rate, but then recognizes that the savings 
associated with the avoided retail generation cost should be added 
back into the equation, i.e., (LMP-G)+G.
    \12\ Rule at P 82. If it were the result, the generation 
resource would be paid the LMP, $100, and the demand resource would 
be paid $75 and realize an additional $25 in retail rate savings. 
Accordingly, both resources realize equivalent compensation valued 
at $100.
    \13\ Ohio Commission May 13, 2010 Comments at 6, ``[T]he 
Commission's proposal that RTOs pay demand response resources the 
full LMP takes the incentives for wholesale demand response 
resources a step too far. It would provide an incentive to the 
supplier of a demand response resource that exceeds the payments 
available to an equivalent supply resource. The Commission should 
instead focus on removing the existing barriers in the wholesale 
markets * * *.''
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    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.
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    \14\ See Attachment to Answer of EPSA, Providing Incentives for 
Efficient Demand Response, Dr. William W. Hogan, October 29, 2009 
(Docket No. EL09-68).
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    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 long-term potential for unintended market damage. As recognized 
by ISO-NE, generation is not dispatched and paid for only when such 
generation reduces LMP, instead generation is dispatched and paid 
for only when it is cost-effective.\16\ Likewise, logic would 
require that demand resources be treated similar to generation 
resources and be similarly cost-effective.
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    \15\ Testimony of Robert Weishaar, Jr., Attorney for Demand 
Response Supporters, Sept. 13, 2010 Tr. at 46-47, ``Administratively 
constructing an LMP-based break point for compensating Demand 
Response participation would ignore many other qualitative and 
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.
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    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.
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    \17\ Rule at P 80. Recognizing that ``the threshold price 
approach we adopt here may result in instances both when demand 
response is not paid the LMP but would be cost-effective and when 
demand response is paid the LMP but is not cost-effective.''
    \18\ Testimony of Donald Sipe, Attorney for Consumer Demand 
Response Initiative, Sept. 13, 2010 Tr. at 43, ``[T]here is probably 
not a need for a Net Benefits Test. But if one is adopted, it should 
not be an artificial threshold that can be wrong both ways. It 
should not be a mechanism that treats DR differently than 
generation.''
    \19\ Viridity Energy, Inc., Oct. 13, 2010 Comments at 10. See 
also ELCON Oct. 13, 2010 Comments at 3; and Environmental Defense 
Fund Comments at 2.
    \20\ Testimony of Andy Ott, Sr. Vice President, PJM 
Interconnection, Sept. 13, 2010 Tr. at 19, ``[Y]ou have to use 
caution to actually take a benefits test and apply that to 
compensation, because you may have unintended consequences.''
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    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

[[Page 16681]]

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\
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    \21\ Testimony of Roy J. Shanker, Ph.D, PJM Power Providers 
Group, Sept. 13, 2010 Tr. at 60, ``If the Commission adopts the 
appropriate non-discriminatory pricing for Demand Response, and 
payment of LMP minus the retail rate in the context of customer that 
face a fixed retail rate, then there is no need for a Net Benefits 
test.''
    \22\ Id., Tr. at 61.
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    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.
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    \23\ EPSA May 13, 2010 Comments at 23. See also May 13, 2010 
Comments of APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; 
New York Commission at 5; PJM at 6; PSEG at 5; and Potomac Economics 
at 6-8.
    \24\ Courts have stated that to be ``just and reasonable,'' 
rates must fall within a ``zone of reasonableness'' where they are 
neither ``less than compensatory'' to producers nor ``excessive'' to 
consumers. Farmers Union Central Exchange v. FERC, 734 F.2d 1486 
(D.C. Cir. 1984), cert denied, 469 U.S. 1034 (1984). See also EPSA 
May 13, 2010 Comments at 19; and ISO-NE at 26-28.
    \25\ Testimony of Ohio Commissioner Paul Centolella, Sept. 13, 
2010 Tr. at 141, ``The Net Benefits test reflects a recognition that 
paying full LMP may over-compensate Demand Response and increase 
cost to customers.''
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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\
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    \26\ Rule at P 63. The RTOs and ISOs uniformly state that 
compensation which ignores the retail rate will yield uneconomic 
outcomes and overcompensate the demand resource. Moreover, none of 
the RTOs or ISOs claimed it would be difficult to subtract the 
retail rate from the LMP payment. See May 13, 2010 Comments of CAISO 
at 5-6; ISO-NE at 17-26; Midwest ISO at 6-11; NYISO at 12-16; and 
PJM at 5-16.
    \27\ Testimony of Joel Newton, New England Power Generators 
Ass'n, Sept. 13, 2010 Tr. at 75; ``The Commission is getting into a 
real close area with retail ratemaking as we go through this entire 
process. For the Commission then to say `ignore the LSE payment' 
which is the realm of State commissions, it's almost as you're just 
hoping that the State commissions will go out and fix it. The State 
commissions can do that * * * [b]ut the proper thing to do now is to 
get the price right at the outset.'' See also Testimony of Ohio 
Commissioner Paul Centolella, Sept. 13, 2010 Tr. at 197; ``[FERC is] 
putting the State in the position where if we were to try to get 
back to an efficient level of incentives, we would be having to in 
effect issue a charge for energy that was not consumed. We would be 
doing what would be perceived as a take-back by that customer. And 
that would put us in a very difficult position.''
    \28\ Rule at P 28. Significantly, the New York Commission 
``acknowledges the overstated price signal inherent in an LMP-based 
formula for DR compensation * * *.'' ``Although we understand that 
an LMP demand response compensation formula may result in uneconomic 
demand response decisions in the markets (i.e., a price signal that 
exceeds marginal cost), it also creates an incentive to participate 
in DR programs * * *.'' New York Commission May 13, 2010 Comments at 
5-6 (emphasis added).
    \29\ Illinois Commission May 13, 2010 Comments at 13, ``[I]f 
tariffs are well designed, controversy over the jurisdictional issue 
can be avoided. Requiring an ex ante approval of the retail rate to 
be subtracted from the LMP at the time demand response resources are 
utilized * * * accomplishes this design.'' See also Indiana 
Commission September 16, 2009 Comments at 3 (Docket No. EL09-68), 
``LMP-G is an accepted indicator of cost-effectiveness. Therefore, 
to provide incentive compensation at a level that is above the LMP 
raises the specter of unjust and unreasonable rates.''
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    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\
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    \30\ Rule at P 63.
    \31\ See 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.
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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.
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    \32\ Rule at P 46.
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    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\
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    \33\ Federal Trade Commission May 13, 2010 Comments at 6, ``If 
customers have to pay the retail price for power they use but pay 
nothing for power they resell, then they will have incentives to 
resell power in situations in which it would be more beneficial for 
society for them to consume it.'' See also EPSA May 13, 2010 
Comments at 23; APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 
2; New York Commission at 5; PJM at 6; PSEG at 5; and Potomac 
Economics at 6-8.
    \34\ PJM's Independent Market Monitor (a/k/a Monitoring 
Analytics, LLC) Oct. 16, 2009 Comments at 7-8 (Docket No. EL09-68), 
``Demand side resources are not generation. In a well functioning 
market, demand-side resources avoid paying the market price of 
energy when they choose not to consume. This allows customers to 
make efficient decisions about using power. It also follows that a 
customer receiving more than the market price as an incentive to 
curtail will make inefficient decisions about using power, and that 
this inefficiency imposes a cost rather than providing a benefit to 
society.''
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    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\
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    \35\ NYISO 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.''
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    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

[[Page 16682]]

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.
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    \36\ Rule at P 59.
    \37\ PJM Interconnection's experience with paying LMP-G for 
demand response in its energy market provides an example of how 
market fundamentals properly influence demand resource 
participation. PJM's Independent Market Monitor recently reported 
that ``[p]articipation levels through calendar year 2009 and through 
the first three months of 2010 were generally lower compared to 
prior years due to a number of factors, including lower price 
levels, lower load levels, and improved measurement and 
verification, but have showed strong growth through the summer 
period as price levels and load levels have increased. Citing 
Monitoring Analytics, LLC, 2010 State of the Market Report for PJM 
at 30 (March 10, 2011) (emphasis added).
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    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.

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    \38\ Federal Power Act Sec.  205(a), 16 U.S.C. Sec.  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.''
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Philip D. Moeller
Commissioner
[FR Doc. 2011-6490 Filed 3-23-11; 8:45 am]
BILLING CODE 6717-01-P


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