Demand Response Compensation In Organized Wholesale Energy Markets RM10 17 000 745 20110315105757
User Manual: 745
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- I. Introduction
- II. Background
- III. Procedural History
- IV. Discussion
- A. Compensation Level
- B. Implementation of a Net Benefits Test
- C. Measurement and Verification
- D. Cost Allocation
- E. Commission Jurisdiction
- V. Information Collection Statement
- VI. Environmental Analysis
- VII. Regulatory Flexibility Act
- VIII. Document Availability
- IX. Effective Date and Congressional Notification
- List of Commenters
134 FERC ¶ 61,187
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
18 CFR Part 35
[Docket No. RM10-17-000; Order No. 745]
Demand Response Compensation in Organized Wholesale Energy Markets
(Issued March 15, 2011)
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final Rule.
SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission
(Commission) amends its regulations under the Federal Power Act to ensure that when a
demand response resource participating in an organized wholesale energy market
administered by a Regional Transmission Organization (RTO) or Independent System
Operator (ISO) has the capability to balance supply and demand as an alternative to a
generation resource and when dispatch of that demand response resource is cost-effective
as determined by the net benefits test described in this rule, that demand response
resource must be compensated for the service it provides to the energy market at the
market price for energy, referred to as the locational marginal price (LMP). This
approach for compensating demand response resources helps to ensure the
competitiveness of organized wholesale energy markets and remove barriers to the
participation of demand response resources, thus ensuring just and reasonable wholesale
Docket No. RM10-17-000 - 2 -
EFFECTIVE DATE: This Final Rule will become effective on [INSERT DATE 30
DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER]. Dates for
compliance and other required filings are provided in the Final Rule.
FOR FURTHER INFORMATION CONTACT:
David Hunger (Technical Information)
Office of Energy Policy and Innovation
Federal Energy Regulatory Commission
888 First Street, NE, Washington, DC 20426
Dennis Hough (Legal Information)
Office of the General Counsel
Federal Energy Regulatory Commission
888 First Street, NE, Washington, DC 20426
134 FERC ¶ 61,187
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Demand Response Compensation in Organized
Wholesale Energy Markets Docket No. RM10-17-000
ORDER NO. 745
TABLE OF CONTENTS
(Issued March 15, 2011)
III. Procedural History...............................................................................................................15.
IV. Discussion ...........................................................................................................................17.
A. Compensation Level.........................................................................................................18.
1. NOPR Proposal.............................................................................................................18.
2. Comments ....................................................................................................................20.
a) Capability of Demand Response and Generation Resources to Balance Energy
b) Appropriateness of a Net Benefits Test ..................................................................38.
c) Standardization or Regional Variations in Compensation.......................................43.
3. Commission Determination..........................................................................................45.
B. Implementation of a Net Benefits Test.............................................................................68.
2. Commission Determination..........................................................................................78.
C. Measurement and Verification .........................................................................................86.
1. NOPR Proposal.............................................................................................................86.
3. Commission Determination..........................................................................................93.
D. Cost Allocation.................................................................................................................96.
1. NOPR Proposal.............................................................................................................96.
3. Commission Determination..........................................................................................99.
E. Commission Jurisdiction ..................................................................................................103.
Docket No. RM10-17-000 ii
2. Commission Determination..........................................................................................112.
V. Information Collection Statement ........................................................................................116.
VI. Environmental Analysis ......................................................................................................121.
VII. Regulatory Flexibility Act .................................................................................................122.
VIII. Document Availability .....................................................................................................130.
IX. Effective Date and Congressional Notification...................................................................133.
APPENDIX: List of Commenters
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: Jon Wellinghoff, Chairman;
Marc Spitzer, Philip D. Moeller,
John R. Norris, and Cheryl A. LaFleur.
Demand Response Compensation in Organized
Wholesale Energy Markets Docket No. RM10-17-000
ORDER NO. 745
(Issued March 15, 2011)
1. This Final Rule addresses compensation for demand response in Regional
Transmission Organization (RTO) and Independent System Operator (ISO) organized
wholesale energy markets, i.e., the day-ahead and real-time energy markets. As the
Commission has previously recognized, a market functions effectively only when both
supply and demand can meaningfully participate. The Commission, in the Notice of
Proposed Rulemaking (NOPR) issued in this proceeding on March 18, 2010, proposed a
remedy to concerns that current compensation levels inhibited meaningful demand-side
participation.1 After nearly 3,800 pages of comments, a subsequent technical conference,
and the opportunity for additional comment, we now take final action.
1 Demand Response Compensation in Organized Wholesale Energy Markets,
Notice of Proposed Rulemaking, 75 FR 15362 (Mar. 29, 2010), FERC Stats. & Regs.
¶ 32,656 (2010) (NOPR).
Docket No. RM10-17-000 - 2 -
2. We conclude that when a demand response2 resource3 participating in an
organized wholesale energy market4 administered by an RTO or ISO has the capability to
balance supply and demand as an alternative to a generation resource and when dispatch
of that demand response resource is cost-effective as determined by the net benefits test
described herein, that demand response resource must be compensated for the service it
provides to the energy market at the market price for energy, referred to as the locational
marginal price (LMP).5 The Commission finds that this approach to compensation for
2 Demand response means a reduction in the consumption of electric energy by
customers from their expected consumption in response to an increase in the price of
electric energy or to incentive payments designed to induce lower consumption of electric
energy. 18 CFR 35.28(b)(4) (2010).
3 Demand response resource means a resource capable of providing demand
response. 18 CFR 35.28(b)(5).
4The requirements of this final rule apply only to a demand response resource
participating in a day-ahead or real-time energy market administered by an RTO or ISO.
Thus, this Final Rule does not apply to compensation for demand response under
programs that RTOs and ISOs administer for reliability or emergency conditions, such as,
for instance, Midwest ISO’s Emergency Demand Response, NYISO’s Emergency
Demand Response Program, and PJM’s Emergency Load Response Program. This Final
Rule also does not apply to compensation in ancillary services markets, which the
Commission has addressed elsewhere. See, e.g., Wholesale Competition in Regions
with Organized Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC
Stats. & Regs. ¶ 31,281 (2008) (Order No. 719).
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
Docket No. RM10-17-000 - 3 -
demand response resources is necessary to ensure that rates are just and reasonable in the
organized wholesale energy markets. Consistent with this finding, this Final Rule adds
section 35.28(g)(1)(v) to the Commission’s regulations to establish a specific
compensation approach for demand response resources participating in the organized
wholesale energy markets administered by RTOs and ISOs. The Commission is not
requiring the use of this compensation approach when demand response resources do not
satisfy the capability and cost-effectiveness conditions noted above.6
3. This cost-effectiveness condition, as determined by the net benefits test described
herein, recognizes that, depending on the change in LMP relative to the size of the energy
market, dispatching demand response resources may result in an increased cost per unit
($/MWh) to the remaining wholesale load associated with the decreased amount of load
paying the bill. This is the case because customers are billed for energy based on the
units, MWh, of electricity consumed. We refer to this potential result as the billing unit
effect of dispatching demand response. By contrast, dispatching generation resources
does not produce this billing unit effect because it does not result in a decrease of load.
To address this billing unit effect, the Commission in this Final Rule requires the use of
the net benefits test described herein to ensure that the overall benefit of the reduced
6 The Commission’s findings in this Final Rule do not preclude the Commission
from determining that other approaches to compensation would be acceptable when these
conditions are not met.
Docket No. RM10-17-000 - 4 -
LMP that results from dispatching demand response resources exceeds the cost of
dispatching and paying LMP to those resources. When the net benefits test described
herein is satisfied and the demand response resource clears in the RTO’s or ISO’s
economic dispatch, the demand response resource is a cost-effective alternative to
generation resources for balancing supply and demand.
4. To implement the net benefits test described herein, we direct each RTO and ISO
to develop a mechanism as an approximation to determine a price level at which the
dispatch of demand response resources will be cost-effective. The RTO or ISO should
determine, based on historical data as a starting point and updated for changes in relevant
supply conditions such as changes in fuel prices and generator unit availability, the
monthly threshold price corresponding to the point along the supply stack beyond which
the overall benefit from the reduced LMP resulting from dispatching demand response
resources exceeds the cost of dispatching and paying LMP to those resources. This price
level is to be updated monthly, by each ISO or RTO, as the historic data and relevant
supply conditions change.7
7 In its compliance filing an RTO or ISO may attempt to show, in whole or in part,
how its proposed or existing practices are consistent with or superior to the requirements
of this Final Rule.
Docket No. RM10-17-000 - 5 -
5. This Final Rule also sets forth a method for allocating the costs of demand
response payments among all customers who benefit from the lower LMP resulting from
the demand response.
6. The tariff changes needed to implement the compensation approach required in
this Final Rule, including the net benefits test, measurement and verification explanation
and proposed changes, and the cost allocation mechanism must be made on or before
July 22, 2011. All tariff changes directed herein should be submitted as compliance
filings pursuant to this Final Rule, not pursuant to section 205 of the Federal Power Act
(FPA).8 Accordingly, each RTO’s or ISO’s compliance filing to this Final Rule will
become effective prospectively from the date of the Commission order addressing that
filing, and not within 60 days of submission.
7. In addition, we believe that integrating a determination of the cost-effectiveness of
demand response resources into the dispatch of the ISOs and RTOs may be more precise
than the monthly price threshold and, therefore, provide the greatest opportunity for load
to benefit from participation of demand response in the organized wholesale energy
market administered by an RTO or ISO. However, we acknowledge the position of
several of the RTOs and ISOs that modification of their dispatch algorithms to
incorporate the costs related to demand response may be difficult in the near term. In
8 16 U.S.C. 824d (2006).
Docket No. RM10-17-000 - 6 -
light of those concerns, we require each RTO and ISO to undertake a study examining the
requirements for and impacts of implementing a dynamic approach which incorporates
the billing unit effect in the dispatch algorithm to determine when paying demand
response resources the LMP results in net benefits to customers in both the day-ahead and
real-time energy markets. The Commission directs each RTO and ISO to file the results
of this study with the Commission on or before September 21, 2012.9
8. Effective wholesale competition protects customers by, among other things,
providing more supply options, encouraging new entry and innovation, and spurring
deployment of new technologies.10 Improving the competitiveness of organized
wholesale energy markets is therefore integral to the Commission fulfilling its statutory
mandate under the FPA to ensure supplies of electric energy at just, reasonable, and not
unduly discriminatory or preferential rates.11
9 We note that this report is for informational purposes only and will neither be
noticed nor require Commission action.
10 See, e.g., Wholesale Competition in Regions with Organized Electric Markets,
Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC Stats. & Regs. ¶ 31,281, at P 1
(2008) (Order No. 719); see also Regional Transmission Organizations, Order No. 2000,
FERC Stats. & Regs. ¶ 31,089, at P 1 (1999), order on reh'g, Order No. 2000-A, FERC
Stats. & Regs. ¶ 31,092 (2000), aff'd sub nom. Pub. Util. Dist. No. 1 of Snohomish
County, Washington v. FERC, 272 F.3d 607, 348 U.S. App. D.C. 205 (D.C. Cir. 2001).
11 16 U.S.C. 824d (2006); Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 1.
Docket No. RM10-17-000 - 7 -
9. As the Commission recognized in Order No. 719, active participation by
customers in the form of demand response in organized wholesale energy markets helps
to increase competition in those markets.12 Demand response, whereby customers reduce
electricity consumption from normal usage levels in response to price signals, can
generally occur in two ways: (1) customers reduce demand by responding to retail rates
that are based on wholesale prices (sometimes called “price-responsive demand”); and
(2) customers provide demand response that acts as a resource in organized wholesale
energy markets to balance supply and demand. While a number of states and utilities are
pursuing retail-level price-responsive demand initiatives based on dynamic and 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
10. As the Commission stated in Order No. 719,13 and emphasized in the NOPR,14
there are several ways in which demand response in organized wholesale energy markets
12 See Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 48.
13 Wholesale Competition in Regions with Organized Electric Markets, Order
No. 719-A, FERC Stats. & Regs. ¶ 31,292, at P 48 (2009).
14 NOPR, FERC Stats. & Regs. ¶ 32,656 at P 4.
Docket No. RM10-17-000 - 8 -
can help improve the functioning and competitiveness of those markets. First, when bid
directly into the wholesale market, demand response can facilitate RTOs and ISOs in
balancing supply and demand, and thereby, help produce just and reasonable energy
prices.15 This is because customers who choose to respond will signal to the RTO or ISO
and energy market their willingness to reduce demand on the grid which may result in
reduced dispatch of higher-priced resources to satisfy load.16 Second, demand response
can mitigate generator market power.17 This is because the more demand response that
sees and responds to higher market prices, the greater the competition, and the more
downward pressure it places on generator bidding strategies by increasing the risk to a
supplier that it will not be dispatched if it bids a price that is too high.18 Third, demand
15 For example, a study conducted by PJM, which simulated the effect of demand
response on prices, demonstrated that a modest three percent load reduction in the 100
highest peak hours corresponds to a price decline of six to 12 percent. ISO-RTO Council
Report, Harnessing the Power of Demand How RTOs and ISOs Are Integrating Demand
Response into Wholesale Electricity Markets, found at
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.”).
Docket No. RM10-17-000 - 9 -
response has the potential to support system reliability and address resource adequacy19
and resource management challenges surrounding the unexpected loss of generation.
This is because demand response resources can provide quick balancing of the electricity
11. Congress has recognized the importance of demand response by enacting national
policy requiring its facilitation.21 Consistent with that policy, the Commission has
undertaken several reforms to support competitive wholesale energy markets by
removing barriers to participation of demand response resources. For example, in Order
No. 890, the Commission modified the pro forma Open Access Transmission Tariff to
19 See ISO-RTO Council Report, Harnessing the Power of Demand How RTOs
and ISOs Are Integrating Demand Response into Wholesale Electricity Markets at 4,
found at http://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-
003829518EBD%7D/IRC_DR_Report_101607.pdf (“Demand response contributes to
maintaining system reliability. Lower electric load when supply is especially tight
reduces the likelihood of load shedding. Improvements in reliability mean that many
circumstances that otherwise result in forced outages and rolling blackouts are averted,
resulting in substantial financial savings . . . .”).
20 For instance, in ERCOT, on February 26, 2008, through a combination of a
sudden loss of thermal generation, drop in power supplied by wind generators, and a
quicker-than-expected ramping up of demand, ERCOT found itself short of reserves.
The system operator called on all demand response resources, and 1200 MW of Load
acting as Resource (LaaRs) responded quickly, bringing ERCOT back into balance. OAK
RIDGE NAT’L LAB., NAT’L RENEWABLE ENERGY LAB., TECH. REP. NREL/TP-500-43373,
ERCOT EVENT ON FEB. 26, 2008: LESSONS LEARNED (JUL. 2008).
21 See Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(f), 119 Stat. 594,
965 (2005) (“It is the policy of the United States that . . . unnecessary barriers to demand
response participation in energy, capacity, and ancillary service markets shall be
Docket No. RM10-17-000 - 10 -
allow non-generation resources, including demand response resources, to be used in the
provision of certain ancillary services where appropriate on a comparable basis to service
provided by generation resources.22 Order No. 890-A further required transmission
providers to develop transmission planning processes that treat all resources, including
demand response, on a comparable basis.23
12. In Order No. 719, the Commission required RTOs and ISOs to, among other
things, accept bids from demand response resources in their markets for certain ancillary
services on a basis comparable to other resources.24 The Commission also required each
RTO and ISO “to reform or demonstrate the adequacy of its existing market rules to
ensure that the market price for energy reflects the value of energy during an operating
reserve shortage,”25 for purposes of encouraging existing generation and demand
resources to continue to be relied upon during an operating reserve shortage, and
encouraging entry of new generation and demand resources.26
22 Preventing Undue Discrimination and Preference in Transmission Service,
Order No. 890, FERC Stats. & Regs. ¶ 31,241, at P 887-88 (2007), order on reh’g, Order
No. 890-A, FERC Stats. & Regs. ¶ 31,261 (2007), order on reh'g and clarification, Order
No. 890-B, 123 FERC ¶ 61,299 (2008), order on reh'g, Order No. 890-C, 126 FERC
¶ 61,228 (2009), order on clarification, Order No. 890-D, 129 FERC ¶ 61,126 (2009).
23 Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 216.
24 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 47-49.
25 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 194.
26 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 247.
Docket No. RM10-17-000 - 11 -
13. Additionally, in recent years several RTOs and ISOs have instituted various types
of demand response programs. While some of these programs are administered for
reliability and emergency conditions, other programs allow wholesale customers,
qualifying large retail customers, and aggregators of retail customers to participate
directly in the day-ahead and real-time energy markets, certain ancillary service markets
and capacity markets.27
14. To date, the Commission has allowed each RTO and ISO to develop its own
compensation methodologies for demand response resources participating in its 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
27 Other demand response programs allow demand response to be used as a
capacity resource and as a resource during system emergencies or permit the use of
demand response for synchronized reserves and regulation service. See, e.g., PJM
Interconnection, L.L.C., 117 FERC ¶ 61,331 (2006); Devon Power LLC, 115 FERC
¶ 61,340, order on reh’g, 117 FERC ¶ 61,133 (2006), appeal pending sub nom. Maine
Pub. Utils. Comm’n v. FERC, No. 06-1403 (D.C. Cir. 2007); New York Indep. Sys.
Operator, Inc., 95 FERC ¶ 61,136 (2001); NSTAR Services Co. v. New England Power
Pool, 95 FERC ¶ 61,250 (2001); New England Power Pool and ISO New England, Inc.,
100 FERC ¶ 61,287, order on reh’g, 101 FERC ¶ 61,344 (2002), order on reh’g,
103 FERC ¶ 61,304, order on reh’g, 105 FERC ¶ 61,211 (2003); PJM Interconnection,
L.L.C., 99 FERC ¶ 61,227 (2002); California Independent System Operator Corp.,
132 FERC ¶ 61,045 (2010).
28 See New England, Inc., Docket No. ER09-1051-000; ISO New England, Inc.,
Docket No. ER08-830-000; Midwest Indep. Transmission Sys. Operator, Inc., Docket
Docket No. RM10-17-000 - 12 -
rate.29 ISO New England Inc. (ISO-NE) and New York Independent System Operator,
Inc. (NYISO) pay LMP when prices exceed a threshold level, with the levels differing
between the RTOs.30 The Midwest Independent Transmission System Operator, Inc.’s
(Midwest ISO) demand response programs31 pay LMP for demand response resources in
the day-ahead and real-time energy markets.32 The California Independent System
Operator Corporation (CAISO) pays LMP at pricing nodes, or sub-load aggregation
points (Sub-LAP) in its Proxy Demand Resource program that allows qualifying
29 See sections 3.3A.4 and 3.3A.5 (Market Settlements in the Real-Time and 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 184.108.40.206 (“Day-Ahead Bids from
Demand Reduction Providers to Supply Energy from Demand Reductions”) of NYISO’s
Market Services Tariff.
31 Midwest ISO FERC Electric Tariff characterizes Demand Response Resources
(DRR) as either DRR-Type I or DRR-Type II. DRR-Type I are capable of supplying a
specific quantity of energy or contingency reserve through physical load interruption.
DRR-Type II are capable of supplying energy and/or operating reserves over a
dispatchable range. See sections 39.2.5A and 40.2.5 of the Tariff.
32 See Charges and Payments for Purchases and Sales for Demand Response
Resources. Midwest ISO FERC Electric Tariff, section 39.3.2C.
Docket No. RM10-17-000 - 13 -
resources to provide day-ahead and real-time energy.33 CAISO also provides for demand
response resources to participate in its Participating Load program, which enables certain
resources to provide curtailable demand in the CAISO market. CAISO pays nodal 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
III. Procedural History
15. As noted above, the Commission issued the NOPR in this proceeding on
March 18, 2010.35 The NOPR proposed to require RTOs and ISOs to pay the LMP in all
hours for demand reductions made in response to price signals. The Commission sought
33 See section 220.127.116.11 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
35 NOPR, FERC Stats. & Regs. ¶ 32,656.
Docket No. RM10-17-000 - 14 -
comments on the compensation proposal and, in particular, on the comparability of
generation and demand response resources; alternative approaches to compensating
demand response in organized wholesale energy markets; whether payment of LMP
should apply in all hours, and, if not, any criteria that should be used for establishing
hours when LMP should apply; and whether to allow for regional variations concerning
approaches to demand response compensation.36
16. After receiving the first round of comments, the Commission issued a
Supplemental Notice of Proposed Rulemaking and Notice of Technical Conference
(Supplemental NOPR) in this proceeding on August 2, 2010.37 The Supplemental NOPR
sought additional comment on: whether the Commission should adopt a net benefits test
for determining when to compensate demand response providers, and, if so, what, if any,
requirements should apply to the methods for determining net benefits; and what, if any,
requirements should apply to how the costs of demand response are allocated. The
Commission further directed Staff to hold a technical conference focused on these two
issues, which occurred on September 13, 2010.38
36 See Appendix for a list of commenters.
37 Supplemental Notice of Proposed Rulemaking and Notice of Technical
Conference, 75 FR 47499 (Aug. 6, 2010), 132 FERC ¶ 61,094 (2010) (Supplemental
38 See Notice of Technical Conference (Aug. 27, 2010).
Docket No. RM10-17-000 - 15 -
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
A. Compensation Level
1. NOPR Proposal
18. The NOPR proposed to require RTOs and ISOs to pay the LMP in all hours for
demand reductions made in response to price signals. The NOPR sought to provide
comparable compensation to generation and demand response providers, based on the
premise that both resources provide a comparable service to RTOs and ISOs for purposes
of balancing supply and demand and maintaining a reliable electricity grid.39 Also as
stated in the NOPR, the proposed compensation level was designed to allow more
demand response resources to cover their investment costs in demand response-related
technology (such as advanced metering) and thereby facilitate their ability to participate
in organized wholesale energy markets.40 The Commission sought comments on the
39 NOPR, FERC Stats. & Regs. ¶ 32,656 at P 15.
40 Id. at P 16.
Docket No. RM10-17-000 - 16 -
compensation proposal and, in particular, on the comparability of generation and demand
response resources; alternative approaches to compensating demand response in
organized wholesale energy markets; whether payment of LMP should apply in all hours,
and, if not, any criteria that should be used for establishing hours when LMP should
apply; and whether to allow for regional variations concerning approaches to demand
19. In the Supplemental NOPR, the Commission sought additional comments and
directed staff to hold a technical conference regarding various net benefits tests. In
particular, the Commission sought comment on: whether the Commission should adopt a
net benefits test applicable in all or only some hours and what the criteria of any such test
would be; how to define net benefits; what costs demand response providers and load
serving entities incur and whether they should be included in a net benefits test; whether
any net benefits methodology adopted should be the same for all RTOs and ISOs;
proposed methodologies for implementing a net benefits test and the advantages and
limitations of any proposed methodologies.41 The September 13, 2010 Technical
Conference included an eleven-member panel discussion of net benefits tests representing
41 Supplemental NOPR, 132 FERC ¶ 61,094 at P 8-9.
Docket No. RM10-17-000 - 17 -
a wide range of interests and viewpoints.42 The Commission subsequently received
additional written comments addressing these issues.
a) Capability of Demand Response and Generation Resources to
Balance Energy Markets
20. Various commenters address the comparability of demand response and
generation resources for purposes of compensation in the organized wholesale energy
markets. To begin, numerous commenters address the physical or functional
comparability of demand response and generation, agreeing that an increment of
generation is comparable to a decrement of load for purposes of balancing supply and
demand in the day-ahead and real-time energy markets.43 Equating generation and
demand response resources, Dr. Alfred E. Kahn states:
[Demand response] is in all essential respects economically equivalent to
supply response . . . [so] economic efficiency requires . . . that it should be
rewarded with the same LMP that clears the market. Since [demand
response] is actually—and not merely metaphorically—equivalent to
supply response, economic efficiency requires that it be regarded and
rewarded, equivalently, as a resource proffered to system operators, and be
treated equivalently to generation in competitive power markets. That is,
42 See Sept. 13, 2010 Tr.
43 DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 2); Verso May 13,
2010 Comments at 3-4; Occidental May 13, 2010 Comments at 11; Viridity June 18,
2010 Comments at 5.
Docket No. RM10-17-000 - 18 -
all resources—energy saved equivalently to energy supplied— . . . should
receive the same market-clearing LMP in remuneration.44
Indeed, some commenters believe that, from a physical standpoint, demand response can
provide superior services to generation, such as providing a quick response in meeting
system requirements and service without having to construct major new facilities.45
Occidental asserts that the fungibility of demand response and generation output creates
greater operational flexibility that, in turn, offers RTOs and ISOs multiple options to
solve system issues both in energy and ancillary service markets, and that the fungible
nature of demand response and generation supports comparable compensation for each as
proposed in the NOPR.46
21. Viridity states that attempts to distinguish the physical characteristics of
generation and demand response ignore bid-based security-constrained economic
dispatch as the foundation for LMP and are based on the assumption that the value of
load management on the grid is limited to periods when the system is stressed, i.e.,
traditional “super peak shaving.” Viridity states that, while these arguments might have
been valid 15 years ago, today competitive markets can offer proactively-managed load
control and comparable and non-discriminatory treatment of load-based energy resources.
44 DR Supporters August 30, 2010 Reply Comments (Kahn Affidavit at 2
45 Verso May 13, 2010 Comments at 3-4; Alcoa May 13, 2010 Comments at 9.
46 Occidental May 13, 2010 Comments at 11.
Docket No. RM10-17-000 - 19 -
Therefore, Viridity asserts that all resources should be paid LMP if the grid operator
accepts their bid to achieve grid balance.47
22. At the same time, other commenters argue that generation and demand response
are not physically equivalent, pointing out that demand response reduces consumption,
whereas generators serve consumption.48 They argue that a MW reduction in demand
does not turn on the lights.49 EPSA adds that a load reduction does not provide electrons
to any other load and, instead, allows the marginal electron to serve a different
customer.50 Some commenters assert that a power system can function solely and
reliably on generating plants and without any reliance on demand response, while the
system cannot rely exclusively on demand response because demand response by itself
cannot keep the lights on. Ultimately, some commenters point out, megawatts produced
by generators need to be placed on the system in order for power to flow.51 Battelle
additionally argues that a reduction in consumption is not exactly the same as an increase
47 Viridity June 18, 2010 Comments at 5.
48 ISO-NE May 13, 2010 Comments at 3.
49 See, e.g., APPA May 13, 2010 Comments at 12; Capital Power May 13, 2010
Comments at 2.
50 EPSA May 13, 2010 Comments at 72.
51 See, e.g., PSEG May 13, 2010 Comments at 8.
Docket No. RM10-17-000 - 20 -
in production, because elastic demand often comes with attendant future consequences,
such as rebound, by virtue of substitution in time.52
23. Some commenters who argue that the physical characteristics of demand response
are not comparable to generation frame their arguments in terms of the ability of the
system operator to call on demand response and generation resources to provide
balancing energy. They argue that generation resources provide superior service to
demand response providers, positing that demand response is not intended for long
periods of balancing needs,53 and that, moreover, contracts with demand response
providers limit the number of hours and times a customer may be called upon to curtail.
For example, ODEC asserts that the degree of physical comparability depends on the
extent to which demand response resources can be dispatched similar to a generator.54
Calpine adds that traditional generators provide system support features that demand
response cannot, such as ancillary services including governor response or reactive power
voltage support, which are necessary for reliable operation of the electric system.55
24. Numerous commenters also address the comparability of demand response and
generation in economic terms. For example, EEI states that, in finance terms, the demand
52 Battelle May 13, 2010 Comments at 3.
53 AEP May 13, 2010 Comments at 7-8.
54 ODEC May 13, 2010 Comments at 12.
55 Calpine May 13, 2010 Comments at 4-5.
Docket No. RM10-17-000 - 21 -
response product is, unlike generation, essentially an unexercised call option on spot
market energy, and the value of that option is well-established in finance theory as the
value of the resource (LMP) minus the “strike price,” which EEI contends in this case is
the retail tariff rate.56 EEI and like-minded commenters support, therefore, alternative
compensation for demand response to equal LMP minus the generation (or G) component
of the retail rate.57 They posit that payment of LMP without an offset for some portion of
the retail rate does not send the proper economic signal to providers of demand response,
because it fails to take into account the retail rate savings associated with demand
response, and thereby overcompensates the demand response provider. As described by
Dr. William W. Hogan on behalf of EPSA, this is sometimes called a double-payment for
demand reductions, because demand response providers would “receive” both the cost
56 EEI May 13, 2010 Comments at 4-5. See also Robert L. Borlick May 13, 2010
Comments at 4. Mr. Borlick argues that the correct price is LMP minus the Marginal
Foregone Retail Rate (MFRR), describing the economically efficient price that should be
paid to a demand response provider as “its offer price minus the price in its retail tariff at
which it would have purchased the curtailed energy.” Mr. Borlick asserts that this
amount accurately represents the forgone opportunity costs that result when a demand
response provider reduces its load. Id.
57 See May 13, 2010 Comments of: APPPA; AEP; The Brattle Group; Calpine;
ConEd; Consumers Energy; CPG; Detroit Edison; Direct Energy; Dominion; Duke
Energy; Edison Mission; EEI; EPSA; Exelon; FTC; GDF; NYISO on behalf of the ISO
RTO Council; ICC; IPPNY; Indicated New York TOs; IPA; ISO-NE; Midwest TDUs;
Mirant; Midwest ISO TOs; NEPGA; NYISO; ODEC; OMS; PJM; PJM IMM; P3;
Potomac Economics; PG&E; Ohio Commission; Robert L. Borlick; Roy Shanker; and
Docket No. RM10-17-000 - 22 -
savings from not consuming an increment of electricity at a particular price, plus an LMP
payment for not consuming that same increment of electricity.58 Viewing LMP as a
double-payment, these commenters argue that paying LMP will result in more demand
response than is economically efficient.59 For example, Dr. Hogan states that paying
LMP might motivate a company to shut down even though the benefits of consuming
electricity outweigh the cost at LMP.60 Indeed, P3 argues that compensation in excess of
LMP-G is unjust and unreasonable, because such a payment level imposes costs on
customers that are not commensurate with benefits received.61
25. ISO-NE argues that paying full LMP to demand response providers without taking
into account the bill savings produced by demand response provides a significant
financial incentive to dispatch demand response with marginal costs exceeding LMPs.
By dispatching higher-cost demand response, ISO-NE asserts, lower-cost generation
58 See Attachment to Answer of EPSA, Providing Incentives for Efficient Demand
Response, Dr. William W. Hogan, Oct. 29, 2009, submitted in Docket No. EL09-68-000.
59 EPSA May 13, 2010 Comments at 23. See also May 13, 2010 Comments of
APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5;
PJM at 6; PSEG at 5; and Potomac Economics at 6-8.
60 Attachment to Answer of EPSA, Providing Incentives for Efficient Demand
Response, Dr. William W. Hogan, Oct. 29, 2009, submitted in Docket No. EL09-68-000.
In Dr. Hogan’s view, supply should produce when the price of electricity exceeds its cost
of production and demand should decline to consume when the costs in terms of
convenience of delaying use are less than the price of electricity.
61 P3 June 14, 2010 Comments at 2, 7-8.
Docket No. RM10-17-000 - 23 -
resources are displaced.62 At the same time, ISO-NE argues, generation is not dispatched
and paid for only when the generation reduces LMP—generation is dispatched and paid
for when it is cost-effective.63
26. Dr. Hogan further disputes arguments equating a MW of energy supplied to a MW
of energy saved on economic grounds. Dr. Hogan draws a distinction between reselling
something that one has purchased, and selling something that one would have purchased
without actually purchasing it. Dr. Hogan argues that from the perspective of economic
efficiency and welfare maximization, the aggregate effect of demand response is a wash
producing no economic net benefit. Dr. Hogan asserts that Commission policy citing the
benefits of price reduction in support of demand response compensation would amount to
no less than an application of regulatory authority to enforce a buyers' cartel. He states
that the Commission has been vigilant and aggressive in preventing buyers and sellers
from engaging in market manipulation to influence prices, and it would be fundamentally
inconsistent for the Commission to design demand response compensation policies that
coordinate and enforce such price manipulation.
27. Dr. Hogan argues that the ideal and economically efficient solution regarding
demand response compensation is to implement retail real-time pricing at the LMP,
62 ISO-NE May 13, 2010 Comments at 3-4.
63 Id. at 28.
Docket No. RM10-17-000 - 24 -
thereby eliminating the need for demand response programs. Realizing that this is
unattainable at the present time, Dr. Hogan goes on to propose a next-best solution,
which he believes is to pay demand response compensation in the amount of LMP-G, or
some amount that simulates explicit contract demand response (such as “buy-the-
baseline” approach discussed below). These options, he argues, more than paying LMP,
better support notions of comparability between demand response resources and
28. The New York Commission, however, argues that requiring payment of LMP-G
would result in an administrative burden of tracking retail rates for the multiple utilities,
ESCOs and power authorities and create undue confusion for retail customers and
administrative difficulties for state commissions and ISOs and RTOs.65
29. Consistent with Dr. Hogan’s arguments, some commenters assert that demand
response providers should actually own or pay for electricity prior to, what commenters
characterize as, an effective reselling of the electricity back to the market in the form of
demand response. For example, these commenters suggest that the demand response
provider purchase the power in the day-ahead market and resell it in the real-time
64 Hogan Affidavit, ISO RTO Council May 13, 2010 Comments at 5.
65 New York Commission May 13, 2010 Comments at 8.
Docket No. RM10-17-000 - 25 -
markets.66 EPSA argues that there must be some purchase requirement or representative
offset to allow a demand response provider to “sell” a commodity that it owns to the ISO
or RTO.67 EPSA argues that such a requirement would send an efficient price signal,
reduce incentives for gaming the system, and help address difficulties with measurement
and verification of a demand reduction. EPSA highlights an ISO-NE IMM
recommendation that, if the Commission permits LMP payment, it should also adopt a
“buy-the-baseline” approach requiring demand response resources to purchase an
expected amount of energy consumption in the day-ahead energy market and
subsequently sell any demand reduction from that level in the real-time market.68
30. Viridity, on the other hand, argues that forcing customers to buy and then resell
electricity will lead to too little demand response and that adopting a “buy-the-baseline”
approach would constitute an inappropriate exercise of Commission authority to
effectively force parties into contracts. Viridity and DR Supporters state that any
characterization of demand response as a purchase and then resale of energy is
erroneous69 and based on the flawed assumption that demand response resources are
66 See, e.g., ISO-NE IMM May 13, 2010 Comments at 4-5; Midwest ISO TOs
May 13, 2010 Comments at 14; PJM May 13, 2010 Comments at 5; and Duke Energy
May 13, 2010 Comments at 2.
67 EPSA June 30, 2010 Comments at 3.
68 EPSA June 30, 2010 Comments at 23.
69 Viridity Energy June 18, 2010 Comments at 25.
Docket No. RM10-17-000 - 26 -
reselling energy. They state that the description of demand response as a reselling of
energy has been correctly rejected by the Commission in EnergyConnect, where the
Commission stated that it was establishing a policy of treating demand response as a
service rather than a purchase and sale of electric energy.70
31. DR Supporters further argues that, despite claims to the contrary, paying full LMP
to demand response providers does not constitute a subsidy for demand response any
more than the remunerations of generators for the power that they sell. As Dr. Kahn
Does this plan involve double compensation, as [Dr.] Hogan asserts, at the
expense of power generators—of successful bidders promising to induce
efficient demand curtailment and of consumers induced to practice it?
Certainly not: the decrease in the revenue of the generators is (and
consequent savings by consumers are) matched by the savings in their
(marginal) costs of generating that power; the successful bidders for the
opportunity to induce that consumer response are compensated for the costs
of those efforts by the pool, whose (marginal) costs they save by assisting
consumers to reduce their purchases.71
32. Viridity further disputes Dr. Hogan’s argument that payment of LMP for demand
response will distort an otherwise optimal market. Viridity posits that such arguments
ignore dislocations in the wholesale power markets, the existence of market power that
must be mitigated, imperfect information available to customers, barriers to entry and
70 DR Supporters Aug. 30, 2010 Reply Comments at 10 (citing EnergyConnect,
Inc., 130 FERC ¶ 61,031 at P 30-31 (2010)).
71 DR Supporters Aug. 30, 2010 Reply Comments, Kahn Affidavit at 10.
Docket No. RM10-17-000 - 27 -
uneconomic resources dispatched to fulfill must-run requirements.72 Viridity further
states that Dr. Hogan’s arguments fail to acknowledge the limits of the Commission’s
jurisdiction and widespread dislocations and distortions in virtually all economic aspects
of relevant energy markets (including fuels, facilities, pricing, environmental attributes,
information and participation) and fail to account for any market benefits of demand
response.73 Finally, Viridity argues that Dr. Hogan’s arguments fail to reflect the many
complex interactions between price, equipment operational requirements, and customer
processes, which point to a complex demand response decision.74
33. In addition to physical and economic comparability, some commenters contrast
the environmental effects of generation and demand response resources. EDF notes that
current market prices fail to internalize environmental externalities – including toxic air
pollution, greenhouse gas pollution, and land and water use impacts – and other social
costs. EDF asserts that the social impact of these environmental externalities is
especially acute at peak times, positing that generation sources used for marginal supply
at such times (“peaker plants”) are among the oldest, dirtiest, and most inefficient in the
72 Viridity June 18, 2010 Comments at 13 (“Importantly, Dr. Hogan (and others)
in opposing the proposed rulemaking fails to acknowledge the limits of the Commission’s
jurisdiction, and wide spread dislocations and distortions in virtually all economic aspects
of relevant energy markets (including fuels, facilities, pricing, environmental attributes,
information and participation).” (Affidavit of John C. Tysseling, Ph.D.)).
73 Viridity Reply Comments at 13.
74 Viridity Reply Comments at 14.
Docket No. RM10-17-000 - 28 -
fleet.75 The American Clean Skies Foundation contends that fossil-fuel generators are
typically mispriced because wholesale prices radically understate the full environmental
and health costs associated with such generators.76 Indeed, some commenters, such as
Alcoa, argue that because demand response does not result in the external costs
associated with generation (e.g., greenhouse gas emissions), instead resulting in less
greenhouse gas emissions than generation, it should be compensated at more than LMP.77
34. Taking the opposite view concerning environmental externalities, EPSA states that
paying LMP for demand response will merely encourage load to switch to off-grid power
(or behind-the-meter generation), while still being compensated, and that such behind-
the-meter generation produces more greenhouse gases and other air emissions than
electricity from the regional energy market.78
35. Some commenters discuss comparability of generation and demand response in
terms of the market rules that apply to each resource, arguing that both resources should
be comparably compensated only if the same rules for participation apply to both
resources, and both resources are held to the same standards for dispatchability.79 They
75 EDF Oct. 13, 2010 Comments at 2.
76 American Clean Skies Foundation May 13, 2010 Comments at 4.
77 Alcoa May 13, 2010 Comments at 9.
78 EPSA May 13, 2010 Comments at 60.
79 ODEC May 13, 2010 Comments at 12; Westar May 13, 2010 Comments at 5-6.
Docket No. RM10-17-000 - 29 -
also argue that similar penalty structures should apply to demand response resources as
apply to generation, and that demand response participation must be subject to market
monitoring.80 Calpine adds that to the extent demand response resources are used and
treated on par with generators for purposes of compensation, they should be subject to the
same performance testing, penalties, and other similar requirements as generators.81
36. Some commenters address the comparability of demand response providers and
generators in terms of maintaining system reliability. PIO argues that reductions in
consumption provide additional reliability.82 According to the NEMA, North American
Electric Reliability Corporation (NERC) standards suggest that, from a reliability
perspective, load reductions are equivalent or even superior to generator increases for
balancing purposes. For example, while specific to the Western Interconnection, 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
81 Calpine May 13, 2010 Comments at 5.
82 PIO May 13, 2010 Comments at 8.
83 NEMA May 13, 2010 Comments at 2.
Docket No. RM10-17-000 - 30 -
markets, pointing out, for example, that, unlike generators, demand response providers
are not subject to regional and NERC mandatory reliability standards.84
37. On the other hand, PSEG argues that a MW of demand response does not make
the same contribution towards system reliability as a MW of generation, because demand
response committed as a capacity resource is only required to perform for a limited
number of times over the peak period. PSEG refers to PJM’s capacity market, for
example, in which demand response only has to perform 10 times during the entire
summer peak period, and then only for six hours per response. In contrast, PSEG argues,
generators are available for dispatch, 24 hours a day, 365 days per year, except for a
small percentage of time for forced and planned outages. PSEG further asserts that
additional reliability standards - applicable to generating facilities, but not to demand
response - increase the relative reliability value of generating resources to the system.85
b) Appropriateness of a Net Benefits Test
38. Some commenters assert that demand response providers should be paid LMP
only when the benefits of demand response compensation outweigh the energy market
costs to consumers of paying demand response resources, i.e., when cost-effective, as
84 EPSA May 13, 2010 Comments at 7.
85 PSEG May 13, 2010 Comments at 8.
Docket No. RM10-17-000 - 31 -
determined by some type of net benefits or cost-effectiveness test.86 They maintain that
paying LMP for demand response in all hours, including off-peak hours, might not result
in net benefits to customers, because the payments might be substantially more than the
savings created by reducing the clearing price at that time.87 According to these
commenters, net benefits are most likely to be positive and greatest when the supply
curve is steepest, which typically occurs in highest-cost, peak hours.88 They argue that
experience to date has shown positive benefits from demand response as a peak system
resource, and that, during peak periods, the positive economics of demand response are
generally very clear and a cost-benefit analysis may not be needed.89 Furthermore, some
commenters suggest that limiting the hours in which demand response resources are paid
86 See generally May 13, 2010 Comments of NYSCPB; NECA; Capital Power;
NECPUC; Maryland Commission; New York Commission; NSTAR; National Grid; NE
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
Docket No. RM10-17-000 - 32 -
LMP could help establish better baselines for measuring whether a demand response
provider has, in fact, responded.90
39. Some commenters who oppose paying LMP in all hours for demand response also
suggest various approaches, including net benefits tests, for determining when LMP
should apply. The stated purpose of any of these tests would be to determine the point at
which the incremental payment for demand response equals the incremental benefit of the
reduction in load; payment of LMP would apply only up to that point.91
40. Opposition to use of a net benefits test comes from several directions. Numerous
commenters, primarily industrial consumers and some consumer advocates, argue that a
net benefits test will reduce competition,92 have a “chilling effect” on the development of
demand response,93 and be costly and complex to implement.94 Some commenters
90 See, e.g., CDWR May 13, 2010 Comments at 11; National Grid May 13, 2010
Comments at 8; ISO-NE May 13, 2010 Comments at 34; ACEEE Oct. 13, 2010
Comments 4. But see ISO-NE May 13, 2010 Comments at 32-33 (contending that no
baseline estimation methodology that relies upon historical customer meter data can
accurately and reliably estimate an individual customer’s normal energy usage pattern if
that customer responds frequently to price signals).
91 NECAA May 13, 2010 Comments at 11; NYSCPB May 13, 2010 Comments at
5; National Grid May 13, 2010 Comments at 4-5.
92 Viridity Oct. 13, 2010 Comments at 14.
93 NAPP Oct. 13, 2010 Comments at 2.
94 Viridity Oct. 13, 2010 Comments at 14; NAPP Oct. 13, 2010 Comments at 3;
AMP Oct. 13, 2010 Comments at 4; CAISO Oct. 13, 2010 Comments at 5 and 16.
Docket No. RM10-17-000 - 33 -
further state that no net benefits test is needed because the merit-order bid stack and
market clearing function in a wholesale market, by definition, assures that the benefits to
the system of demand response exceed the costs, and that the resource that clears is the
lowest cost resource; otherwise, demand response would not dispatch ahead of competing
41. Another set of commenters argues that a net benefits test is unnecessary and
inappropriate for different reasons.96 These commenters assert that a net benefits test
would be very costly and difficult to implement, that RTOs and ISOs cannot implement a
net benefits test,97 and that such a test is unnecessary with the economically efficient
compensation level for demand response resources.98 According to Andy Ott of PJM,
“[t]he implicit assumption in developing a benefits test for purposes of compensation
would be that you could actually determine individual customers, whether they benefitted
95 EDF Oct. 13, 2010 Comments at 2; Viridity Oct. 13, 2010 Comments at 10;
ELCON Oct. 13, 2010 Comments at 3.
96 See, e.g., Oct. 13, 2010 Comments of: Midwest TDUs at 4-5; NEPGA at 8,
NJBPU at 2-3; NAPP at 2-3; P3; SPP at 3-4; SDG&E, SoCal Edison, and PG&E at 4-6;
Viridity Energy at 2; ELCON at 2; AMP at 2; CDWR at 1, 4-5; CAISO at 4, 15; Detroit
Edison at 2; Smart Grid Coalition at 2; Duke Energy at 2; EDF at 2; FTC at 1; EPSA at 4;
Indicated New York TOs at 3; Midwest ISO at 9; Steel Manufacturers Ass’n at 3.
97 P3 Oct. 13, 2010 Comments at 5.
98 Sept. 13, 2010 Tr. 155:21-24 (Mr. Robinson); Sept. 13, 2010 Tr. 141-42
(Mr. Centolella); Dr. Hogan Sept. 13, 2010 Comments at 5; Sept. 13, 2010 Tr. 60
(Dr. Shanker); Sept. 13, 2010 Tr. 27 (Mr. Newton); SDG&E May 13, 2010 Comments at
Docket No. RM10-17-000 - 34 -
or not. That type of analysis would be very costly to implement.”99 Midwest ISO TOs
further assert that it would be difficult to prescribe by regulation the hours in which
demand response provides net benefits because system conditions and load patterns
change across seasons and over time.100 NEPGA argues that compensating demand
response resources at LMP whenever a reduction in consumption suppresses energy
prices enough to provide net benefits to load is neither just and reasonable, nor in the
public interest.101 NEPGA states that the Commission recognized in Amaranth
Advisors102 that, if prices are suppressed below competitive, market levels, society as a
whole is worse off. According to NEPGA, the goal is to get the right price—the
economically efficient price produced by competitive markets.
42. NYISO posits that a rule mandating payment of LMP-G avoids the need to
develop a net benefits test. NYISO further states, however, that if the Commission
decides to move forward with LMP for demand response, it should craft a net benefits
test that minimizes any opportunities for distorting market prices or exploiting market
inefficiencies. Citing support for Dr. Hogan’s arguments, NYISO states that “a net
benefits test should ensure that the demand response program does not have negative net
99 Sept. 13, 2010 Tr. 19 (Mr. Ott).
100 Midwest ISO TOs May 13, 2010 Comments at 16.
101 NEPGA June 21, 2010 Comments at 1-2.
102 120 FERC ¶ 61,085 (2007).
Docket No. RM10-17-000 - 35 -
benefits compared to no program at all. The criterion to apply would focus on the bid-
cost savings of generation and load, with the load bids adjusted for the effects of
avoidance of the retail rate.”103
c) Standardization or Regional Variations in Compensation
43. With regard to potential regional variations for compensation mechanisms across
RTO and ISO markets, many commenters, mostly those in support of the NOPR’s
proposed compensation level, endorse standardization.104 Some parties, primarily
industrial customers and some customer advocates, argue that, regardless of location,
both demand response providers and generators provide a comparable service in terms of
balancing supply and demand, as discussed above, and therefore should be comparably
compensated at the LMP.105 They argue that fair, non-discriminatory markets must adapt
and eliminate barriers to entry to the use and incorporation of traditional and non-
103 NYISO Oct. 13, 2010 Comments at 3-4.
104 See May 13, 2010 Comments of: ArcelorMittal; Alcoa; ACENY; ACC;
AFPA; CDWR; Mayor Bloomberg; Consert; CDRI; CPower; DR Supporters; Derstine’s;
Durgin; Electricity Committee; ELCON; Electrodynamics; ECS; EnerNOC; ICUB;
IECA; IECPA; Irving Forest; Joint Consumers; Limington; Madison Paper;
Massachusetts AG; NEMA; National Energy; National League of Cities; NJBPU; NAPP;
Occidental; Okemo; Partners; Pennsylvania Department of Environment; Pennsylvania
Commission; Rep. Chris Ross; Precision; PRLC; Raritan ; SDEG, SoCal; PG&E;
Schneider; Governor O’Malley; Steel Manufacturers Ass’n; Verso; Viridity; Virginia
Committee; Wal-Mart; Waterville.
105 See, e.g., Steel Manufacturers Ass’n May 13, 2010 Comments at 12; NEMA
May 13, 2010 Comments at 5.
Docket No. RM10-17-000 - 36 -
traditional resources—where non-traditional resources include actively-managed
demand—in the dispatch and management of the electric system.106 They further posit
that the lack of a unified policy itself represents a regulatory barrier to demand
response,107 and that a consistent set of rules reduces the costs and complexities of
demand response participation and facilitates training and transfer of personnel across
regions.108 To that end, many commenters argue that adopting a unified approach to
demand response compensation at the LMP, as opposed to allowing regional variation
including payment of something less than LMP, is necessary to overcome the barriers to
entry of demand response providers.109 Reciting the many benefits of demand reductions
in energy use, these commenters support a compensation level that will provide a catalyst
for private sector engagement in improved energy management practices. Viridity argues
that the near absence of demand response participating in energy markets is powerful
empirical proof that current, varying levels of compensation are inadequate—especially
106 Steel Manufacturers Ass’n May 13, 2010 Comments at 12.
107 PIO May 13, 2010 Comments at 9; DR Supporters Aug. 30, 2010 Comments at
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
Docket No. RM10-17-000 - 37 -
in markets that start with a market-based level of compensation and then reduce it by the
generation portion of a customer’s retail rate (LMP – G).110
44. Other commenters caution against standardizing the compensation level for
demand response, pointing to regional differences in market structure, state regulatory
environment, and resource mix.111
3. Commission Determination
45. The Commission acknowledges the diverging opinions of commenters regarding
the appropriate level of compensation for demand response resources. As discussed
above, commenters are split on this issue, with some in favor of paying the LMP for
demand reductions in the day-ahead and real-time energy markets in all hours, others
arguing that paying the LMP for demand reductions under any conditions will result in
over-compensation or distortions in incentives to reduce consumption, and still others
arguing that paying the LMP for demand reductions is only appropriate when it is
reasonably certain to be cost-effective.
110 Viridity Energy May 13, 2010 Comments at 4.
111 See, e.g., May 13, 2010 Comments of: ConEd at 3-4; Consumers Energy at 2;
California Commission at 9; CMEEC at 2-3, 14-15; Detroit Edison at 3-5; Dominion at 8;
Duke Energy at 4; EPSA at 6; Hess at 4; Indicated New York TOs at 3; Maryland
Commission at 5; Midwest TDUs at 2, 6; Midwest ISO TOs at 16; National Grid at 5-6;
11-12; New York Commission at 4, 11; NCPA at 3; NYISO at 2-3; ODEC at 27; PJM at
5-6; SPP at 1.
Docket No. RM10-17-000 - 38 -
46. In the face of these diverging opinions, the Commission observes that, as the
courts have recognized, “‘issues of rate design are fairly technical and, insofar as they are
not technical, involve policy judgments that lie at the core of the regulatory mission.’”112
We also observe that, in making such judgments, the Commission is not limited to
textbook economic analysis of the markets subject to our jurisdiction, but also may
account for the practical realities of how those markets operate.113
47. As discussed further below, the Commission agrees with commenters who support
payment of LMP under conditions when it is cost-effective to do so, as determined by the
net benefits test described herein.114 We have previously accepted a variety of ISO and
RTO proposals for compensation for demand response resources participating in
112 Elec. Consumers Res. Council v. FERC, 407 F.3d 1232, 1236 (D.C. Cir. 2005)
(quoting Pub. Util. Comm’n of the State of Cal. v. FERC, 254 F.3d 250, 254 (D.C. Cir.
2001)); see also Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992).
113 See Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 872 (D.C. Cir. 1993) (“It is
the FERC’s established policy to consider equitable factors in designing rates, and to
allow for phasing in of changes where appropriate. . . . It is hardly arbitrary or capricious
so to temper the dictates of theory by reference to their consequences in practice.”);
Vermont Dep’t of Pub. Serv. v. FERC, 817 F.2d 127, 135 (D.C. Cir. 1987) (“Indeed, ‘the
congressional grant of authority to the agency indicates that the agency’s interpretation
typically will be enhanced by technical knowledge.’” (quoting Nat’l Fuel Gas Supply
Corp. v. FERC, 811 F.2d 1563, 1570 (D.C. Cir. 1987))); Columbia Gas Transmission
Corp. v. FERC, 750 F.2d 105, 112 (D.C. Cir. 1984) (“the Commission is vested with
wide discretion to balance competing equities against the backdrop of the public
114 See generally May 13, 2010 Comments of NYSCPB; NECA; Capital Power;
NECPUC; Maryland Commission; New York Commission; NSTAR; National Grid; NE
Docket No. RM10-17-000 - 39 -
organized wholesale energy markets. We find, based on the record here that, when a
demand response resource has the capability to balance supply and demand as an
alternative to a generation resource, and when dispatching and paying LMP to that
demand response resource is shown to be cost-effective as determined by the net benefits
test described herein, payment by an RTO or ISO of compensation other than the LMP is
unjust and unreasonable. When these conditions are met, we find that payment of LMP
to these resources will result in just and reasonable rates for ratepayers.115 As stated in
the NOPR, we believe paying demand response resources the LMP will compensate
those resources in a manner that reflects the marginal value of the resource to each RTO
48. The Commission emphasizes that these findings reflect a recognition that it is
appropriate to require compensation at the LMP for the service provided by demand
response resources participating in the organized wholesale energy markets only when
two conditions are met:
The first condition is that the demand response resource has the capability to
provide the service , i.e., the demand response resource must be able to displace a
115 The Commission’s findings in this Final Rule do not preclude the Commission
from determining that other approaches to compensation would be acceptable when these
conditions are not met.
116 NOPR at P 12.
Docket No. RM10-17-000 - 40 -
generation resource in a manner that serves the RTO or ISO in balancing supply
The second condition is that the payment of LMP for the provision of the service
by the demand response resource must be cost-effective, as determined by the net
benefits test described herein.
49. With respect to the first, capability-related condition, we note that a power system
must be operated so that there is real-time balance of generation and load, supply and
demand. An RTO or ISO dispatches just the amount of generation needed to match
expected load at any given moment in time. The system can also be balanced through the
reduction of demand.117 Both can have the same effect of balancing supply and demand
at the margin either by increasing supply or by decreasing demand.
50. With respect to the second cost-effectiveness condition, the record leads us to alter
the proposal set forth in the NOPR in this proceeding. As various commenters explain,
dispatching demand response resources may result in an increased cost per unit to load
117 Andrew L. Ott Sept. 13, 2010 Statement at 1.
Economic and Capacity-based demand response clearly provides benefits to
regional grid operation and the wholesale market operation. . . . These
demand resources provide benefits by providing valuable alternatives to
PJM in maintaining operational reliability and in promoting efficient
Id. at 1; see also CDRI May 13, 2010 Comments at 10; CDWR May 13, 2010
Comments at 5; NJPBU May 13, 2010 Comments at 2.
Docket No. RM10-17-000 - 41 -
associated with the decreased amount of load paying the bill, depending on the change in
LMP relative to the size of the energy market. As stated above, this is the billing unit
effect of dispatching demand response resources.118 However, when reductions in LMP
from implementing demand response results in a reduction in the total amount consumers
pay for resources that is greater than the money spent acquiring those demand response
resources at LMP, such a payment is a cost-effective purchase from the customers’
standpoint. 119 In comparison, when wholesale energy market customers pay a reduced
price attributable to demand response that does not reduce total costs to customers more
than the costs of paying LMP to the demand response dispatched, customers suffer a net
loss. Implementation of the net benefits test described herein will allow each RTO or
ISO to distinguish between these situations.
51. This billing unit effect and the net benefits test through which it is addressed
herein, warrant more detailed discussion. In the organized wholesale energy markets, the
economic dispatch organizes offers from lowest to highest bid in order to balance supply
118 As stated above, dispatching generation resources does not produce this billing
unit effect because it does not result in a decrease of load.
119 As a simple example, assume a market of 100 MW, with a current LMP of
$50/MWh without demand response, and an LMP of $40/MWh if 5 MW of demand
response were dispatched. Total payments to generators and load would be $4,000 with
demand response compared to the previous $5,000. Even though, the reduced LMP is
now being paid by less load, only 95 MW compared to 100 MW, the price paid by each
remaining customer would decrease from $50/MWh to $42.11/MWh ($4,000/95).
Therefore, the payment of LMP to demand resources is cost-effective.
Docket No. RM10-17-000 - 42 -
and demand, taking into account other parameters such as requirements for a generator to
operate at a minimum level of output or minimum amount of time, reserve requirements
and so forth. With dispatch of a demand response resource, the load also goes down, that
is, the level of remaining load falls. However, the “supply” of resources deployed—
which includes both generation and demand response—does not fall. The total costs to
the system for these resources must then be allocated among the reduced quantity of
52. In the absence of the net benefits test described herein, the RTO’s or ISO’s
economic dispatch ordinarily would select demand response when it is the incremental
resource with the lowest bid. However, if the next unit of generation is not sufficiently
more expensive than the demand response resource, the decrease in LMP multiplied by
the remaining load would not be greater than the costs of dispatching the demand
response resource. In this situation, dispatching the demand response resource would
result in a higher price to remaining customers than the dispatch of the next unit of
generation in the bid stack. While the demand response resource appears cost
competitive in the dispatch order, selection of the demand response resource increases the
total cost per unit to remaining load, and it would not be cost-effective to dispatch the
demand response resource.
Docket No. RM10-17-000 - 43 -
53. For this reason, the billing unit effect associated with dispatch of a demand
response resource in an energy market must be taken into account in the economic
comparison of the energy bids of generation resources and demand response resources.
Therefore, rather than requiring compensation at LMP in all hours, the Commission
requires the use of the net benefits test described herein to ensure that the overall benefit
of the reduced LMP that results from dispatching demand response resources exceeds the
cost of dispatching those resources. When the above-noted conditions of capability and
of cost-effectiveness are met, it follows that demand response resources that clear in the
day-ahead and real-time energy markets should receive the LMP for services provided, as
do generation resources. LMP represents the marginal value of an increase in supply or a
reduction in consumption at each node within an ISO or RTO, i.e., LMP reflects the
marginal value of the last unit of resources necessary to balance supply and demand.
Indeed, LMP has been the primary mechanism for compensating generation resources
clearing in the organized wholesale energy markets since their formation. 120
54. The Commission finds that demand response resources that clear in the day-ahead
and real-time energy markets should receive the same market-clearing LMP as
compensation in the organized wholesale energy markets when those resources meet the
conditions established here as a cost-effective alternative to the next highest-bid
120 See DR Supporters Aug. 30, 2010 Reply Comments (Kahn Affidavit at 2
Docket No. RM10-17-000 - 44 -
generation resources for purposes of balancing the energy market. We discuss below the
comments filed on these issues.
55. Some commenters dispute that the foregone consumption of energy by demand
response resources performs the service of balancing supply and demand in the energy
market as would energy supplied by generators in the day-ahead and real-time energy
markets, arguing that it is inappropriate to pay electric consumers to not consume.121 The
Commission disagrees. Generation and load must be balanced by the RTOs and ISOs
when clearing the day-ahead and real-time energy markets, and such balancing can be
accomplished by changes in either supply or demand. The Commission finds that in the
organized wholesale energy markets demand response can balance supply and demand as
56. Commenters that oppose this finding do not adequately recognize a distinctive and
perhaps unique characteristic of the electric industry. The electric industry requires
instantaneous balancing of supply and demand at all times to maintain reliability. It is in
this context that the Commission finds that demand response can balance supply and
demand as can generation when dispatched, in the organized wholesale energy markets.
121 See, e.g., ISO-NE May 13, 2010 Comments at 3; APPA May 13, 2010
Comments at 12; Capital Power May 13, 2010 Comments at 2; EPSA May 13, 2010
Comments at 72.
Docket No. RM10-17-000 - 45 -
57. Due to a variety of factors, demand responsiveness to price changes is relatively
inelastic in the electric industry and does not play as significant a role in setting the
wholesale energy market price as in other industries. The Commission has recognized
that barriers remain to demand response participation in organized wholesale energy
markets. For example, in Order No. 719, the Commission stated:
[D]espite previous Commission and RTO and ISO efforts to facilitate
demand response, regulatory and technological barriers to demand response
participation persist, thereby limiting the benefits that would otherwise
result. A market functions effectively only when both supply and demand
can meaningfully participate, and barriers to demand response limit the
meaningful participation of demand in electricity markets.122
Barriers to demand response participation at the wholesale level identified by
commenters include the lack of a direct connection between wholesale and retail
prices,123 lack of dynamic retail prices (retail prices that vary with changes in marginal
wholesale costs), the lack of real-time information sharing, and the lack of market
incentives to invest in enabling technologies that would allow electric customers and
122 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 83 (citing Federal Energy
Regulatory Commission Staff, A National Assessment of Demand Response Potential
(June 2009), found at http://www.ferc.gov/legal/staff-refports/06-09-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
123 See, e.g., Monitoring Analytics May 13, 2010 Comments at 4-6.
Docket No. RM10-17-000 - 46 -
aggregators of retail customers to see and respond to changes in marginal costs of
providing electric service as those costs change. For example, Dr. Kahn states:
These circumstances—specifically, the fact that pass-through of the LMP is
costly and (perhaps) politically infeasible, the possibly prohibitive cost of
the metering necessary to charge each ultimate user, moment-by-moment,
the often dramatic changes in true marginal costs for each—can justify
direct payment at full LMP to distributors and ultimate customers who
promise to guarantee their immediate response to such increases in true
marginal costs of supplying them.124
Furthermore, EnerNOC states:
On a more fundamental level, the inadequate compensation mechanisms in
place today in wholesale energy markets fail to induce sufficient investment
in demand response resource infrastructure and expertise that could lead to
adequate levels of demand response procurement. Without sufficient
investment in the development of demand response, demand response
resources simply cannot be procured because they do not yet exist as
resources. Such investment will not occur so long as compensation
undervalues demand response resources.125
58. The Commission concludes that paying LMP can address the identified barriers to
potential demand response providers.
59. Removing barriers to demand response will lead to increased levels of investment
in and thereby participation of demand response resources (and help limit potential
124 DR Supporters Sept. 16, 2009 Comments filed in Docket No. EL-09-68-000
(Kahn Affidavit at 6). See also id. at 4 (Customers offering to reduce consumption
should be induced “to behave as they would if market mechanisms alone were capable of
rewarding them directly for efficient economizing.”).
125 EnerNOC May 13, 2010 Comments at 4; see also Alcoa May 13, 2010
Comments at 4; Viridity May 13, 2010 Comments at 5-6.
Docket No. RM10-17-000 - 47 -
generator market power), moving prices closer to the levels that would result if all
demand could respond to the marginal cost of energy. To that end, the Commission
emphasizes that removing barriers to demand response participation is not the same as
giving preferential treatment to demand response providers; rather, it facilitates greater
competition, with the markets themselves determining the appropriate mix of resources,
which may include both generation and demand response, needed by the RTO and ISO to
balance supply and demand based on relative bids in the energy markets. In other words,
while the level of compensation provided to each resource affects its willingness and
ability to participate in the energy market, ultimately the markets themselves will
determine the level of generation and demand response resources needed for purposes of
balancing the electricity grid.126
60. Another issue raised by a number of commenters, largely representing generators,
is whether a lower payment based on LMP-G is the economically-efficient price that
sends the proper price signal to a potential demand response provider. These commenters
argue that, by not consuming energy, demand response providers already effectively
receive “G,” the retail rate that they do not need to pay. They therefore contend that
demand response providers will be overcompensated unless “G” is deducted from
126 Generation and demand response resources have the potential to earn other
revenues through bilateral arrangements, capacity markets where they exist, and ancillary
Docket No. RM10-17-000 - 48 -
payments made by the RTO or ISO for service in the wholesale energy market, resulting
in a payment of LMP-G. These commenters suggest that payment of LMP-G will result
in a price signal to demand response providers equivalent to the LMP (i.e., (LMP - G) +
G). Similarly, some commenters argue that paying demand response resources the LMP
will lead to a wholesale electricity price that is not economically efficient.127
61. The Commission disagrees with commenters who contend that demand response
resources should be paid LMP-G in all hours. First, as discussed above, demand
response resources participating in the organized wholesale energy markets can be 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
127 See NEPGA June 21, 2010 Comments at 1-2.
128 Order No. 719, FERC Stats. & Regs. ¶ 31,281 at P 154.
Docket No. RM10-17-000 - 49 -
Furthermore, Dr. Kahn argues that paying demand response LMP sets “up an
arrangement that treats proffered reductions in demand on a competitive par with positive
supplies; but the one is no more a [case of overcompensation] than the other: the one
delivers electric power to users at marginal costs—the other—reductions in cost—both at
62. Several other considerations also support this Commission conclusion. In the
absence of market power concerns, the Commission does not inquire into the costs or
benefits of production for the individual resources participating as supply resources in the
organized wholesale electricity markets and will not here, as requested by some
commenters, single out demand response resources for adjustments to compensation.
The Commission has long held that payment of LMP to supply resources clearing in the
day-ahead and real-time energy markets encourages “more efficient supply and demand
decisions in both the short run and long run,”130 notwithstanding the particular costs of
production of individual resources. Commenters have not justified why it would be
appropriate for the Commission to continue to apply this approach to generation
resources yet depart from this approach for demand response resources.
129 DR Supporters Aug. 30, 2010 Reply Comments (Kahn Affidavit at 9-10).
130 See New England Power Pool, 101 FERC ¶ 61,344, at P 35 (2002).
Docket No. RM10-17-000 - 50 -
63. In addition, we agree with the New York Commission that given the differences in
retail rate structures across RTO footprints and even within individual states, requiring
ISOs and RTOs to incorporate such disparate retail rates into wholesale payments to
wholesale demand response providers would, even though perhaps feasible, create
practical difficulties for a number of parties, including state commissions and ISOs and
RTOs. Moreover, incorporating such rates could result in customer uncertainty as to the
prevailing wholesale rate.
64. Some arguments advocating paying LMP-G rather than LMP are based on an
assumption that demand response resources need to purchase the energy in day-ahead
markets or by other means and then “resell” the energy to the market in the form of
demand response. However, as the Commission previously stated in EnergyConnect, the
Commission does not view demand response as a resale of energy back into the energy
market. 131 Instead, as the Commission also explained in EnergyConnect and in Order
No. 719-A, the Commission asserts jurisdiction with respect to demand response in
organized wholesale energy markets because of the effect of demand response and related
RTO and ISO market rules on Commission-jurisdictional rates.132
131 See EnergyConnect, 130 FERC ¶ 61,031 at P 32.
132 Id.; see also Order No. 719-A, FERC Stats. & Regs. ¶ 31,292, at P 47.
Docket No. RM10-17-000 - 51 -
65. With regard to the “buyers’ cartel” argument, the Commission disagrees that
market rules establishing circumstances in which particular resources can participate and
receive the LMP represents cooperative price setting. RTOs and ISOs evaluate the bids
from generation and demand response resources to establish the order of dispatch which
secures the most economical supplies needed, consistent with the reliability constraints
imposed on the system. Imposing a cost-effectiveness condition does not convert this
unit commitment process by the RTO or ISO into collusion among bidders, whether
generation or demand response. Furthermore, the market rules administering such a
program would be approved by this Commission and demand response resources would
be subject to Commission-approved rules, just like any other participants in the organized
wholesale energy markets. In addition, arguments that the subject of this proceeding is
equivalent to the types of market manipulation investigated in Amaranth and ETP are
groundless and without merit. In Amaranth, the trader was accused of engaging in a
fraudulent scheme with scienter in connection with a jurisdictional transaction. Here,
there is no such allegation, merely speculation that the Commission is somehow
facilitating coordination of demand- side bidders in order to lower prices.
66. Some commenters argue that demand response providers and generators should
both be compensated at the market clearing price only if both are subject to the same
market participation rules, penalty structures, testing requirements, and market
monitoring provisions. The ISOs and RTOs already consider how to ensure
Docket No. RM10-17-000 - 52 -
comparability between demand response and generation in terms of market rules.133 The
Commission agrees that as a general matter demand response providers and generators
should be subject to comparable rules that reflect the characteristics of the resource, and
expect ISOs and RTOs to continue their evaluation of their existing rules in light of this
Final Rule and make appropriate filings with the Commission.
67. Some commenters argue that the Commission should not impose a single pricing
rule due to differences in market structure, state regulatory environment, and resource
mix among the ISOs and RTOs. While such differences may exist, the commenters have
not shown why such differences warrant a different compensation level among the ISOs
and RTOs. As discussed above, regardless of the resource mix or the state regulatory
environment, demand response, which satisfies the net benefits test described herein and
can balance the system, is a cost-effective alternative to generation in the organized
wholesale energy markets, and payment of LMP represents the marginal value of a
decrease in demand.
133 See PJM Interconnection, L.L.C., 129 FERC ¶ 61,081 (2009).
Docket No. RM10-17-000 - 53 -
B. Implementation of a Net Benefits Test
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
69. However, other commenters assert that using a static threshold based on historical
data misses the changes that occur within electricity markets across seasons and years,
and that it is erroneous to assume that all demand response occurring above a certain
threshold price (for instance, at the very highest loads or highest priced hours) will result
in lower costs to wholesale customers and that demand response is not cost-effective at
134 For example, National Grid states that the threshold could be triggered by a
particular price on the supply offer curve at which the additional cost of paying LMP to
demand response resources is most likely to be outweighed by LMP reductions in the
wholesale energy market as a result of the demand reductions produced by these
resources. National Grid May 13, 2010 Comments at 6. Those in favor of a price
threshold include National Grid (but allow the ISO or RTO to identify threshold based on
analysis); NE Public Systems; NECPUC; ISO-NE (minimum offer price based on fixed
heat rate, times a fuel price index); New York Commission (supports ISO-NE’s heat rate
indexed price threshold).
135 NYISO implements a day-ahead demand response program by which resources
bid into the market at a minimum of $75/MWh and can get paid the LMP. See section
18.104.22.168 (“Day-Ahead Bids from Demand Reduction Providers to Supply Energy from
Demand Reductions”) of NYISO’s Market Services Tariff.
Docket No. RM10-17-000 - 54 -
prices below the static threshold price.136 They argue that a static threshold offer price
cannot easily adjust with changing energy market prices which may result in inefficient
dispatch of demand resources, excluding demand response participation in hours when
demand response can provide beneficial savings and including demand response
participation in hours when there are no beneficial savings.137 The New York
Commission supports a dynamic, rather than a static bid threshold, arguing that, while a
static bid threshold helps prevent demand response providers from gaming the system by
seeking compensation for reducing electricity consumption for reasons other than market
prices, it can also limit participation in a demand response program because prices might
not exceed the threshold on a consistent basis.138
70. In a similar vein, some commenters suggest utilizing a dynamic bid threshold for
determining when LMP payment would apply.139 For example, NECPUC favors use of a
dynamic mechanism such as a price threshold based on a preset heat rate of marginal
136 Sept. 13, 2010 Tr. 52-53 (Mr. Peterson); Massachusetts AG Oct. 13, 2010
Comments at 23.
137 Massachusetts AG Oct. 13, 2010 Comments (attachment, Demand Response
Potential in ISO New England’s Day-Ahead Energy Market, Synapse Energy Economics,
Inc. Oct. 11, 2010 at 9). See generally, NECPUC May 13, 2010 Comments at 18.
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
Docket No. RM10-17-000 - 55 -
generation and fuel price, like that currently used in New England’s Day-Ahead Load
Response Program (DALRP),140 for the ISO-NE control area.141 National Grid suggests
a trigger, determined by each ISO or RTO, using a particular price on the supply offer
curve at which the additional cost of paying LMP to demand resources is most likely to
be outweighed by LMP reductions in the wholesale energy market as a result of the
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,
140 The DALRP establishes a minimum offer price by approximating the variable
cost component, in the form of a fuel cost, of a hypothetical peaking unit sufficiently high
enough in the supply stack to ensure net benefits. On a monthly basis, this minimum
offer price is reset to reflect the product of an appropriate fuel price index and a proxy
heat rate. See NECPUC Oct. 13, 2010 Comments at 15.
141 NECPUC Oct. 13, 2010 Comments at 14-16; NECPUC May 13, 2010
Comments at 17.
142 Id. at 5-6.
143 Maryland Commission May 13, 2010 Comments at 4-5; see generally NSTAR,
ACEEE and NYSCPB Oct. 13, 2010 Comments.
Docket No. RM10-17-000 - 56 -
further analysis is needed to ascertain the critical high-cost hours in which it will be cost-
effective to pay full LMP for demand response.144
72. The Consumer Demand Response Initiative (CDRI) proposes a mechanism for
determining what demand response resources are cost-effective in any hour.145 This
dispatch algorithm tests whether the money necessary to compensate demand response is
less than the cost savings due to the decreased market-clearing price resulting from
implementing demand response. In a sense, it is a dynamic cost/benefit analysis built
into the dispatch algorithm. This cost/benefit analysis accounts for the billing unit effect.
The billing unit effect occurs when demand response resources are dispatched to balance
the system; the associated reduction in load results in fewer MWh of realized load
(demand) paying for the sum of generator and demand response resource MWh, so load
pays an effective rate which is greater than the LMP set to procure resources. Some
commenters assert that if the Commission finds that a net benefits test is needed, it should
144 Maryland Commission May 13, 2010 Comments at 4 n.9.
145 The approach submitted by CDRI was developed for implementation in the
ISO-NE day-ahead energy market. The discussion here is generalized to be applicable to
any energy market that uses security-constrained economic dispatch to select the least-
cost resources and establish a market-clearing price.
Docket No. RM10-17-000 - 57 -
require organized wholesale energy market operators to implement a proposal similar to
that submitted by CDRI.146
73. Under the proposal submitted by CDRI, the demand response bids are part of the
supply stack to which a security-constrained economic dispatch process is applied. All
demand response bids that result in a lower price to customers, including consideration of
the reduced number of billing units, are selected while those bids that raise the price, as
compared to selecting the next generation bid in the supply stack, are not. This dispatch
algorithm, as proposed, would be used by the ISO or RTO to determine a revised LMP
that would be charged to load. The revised LMP creates a surplus (or over-collection) of
revenue for the ISO or RTO that is then distributed to the LSEs through a settlement
algorithm with the goal of holding LSEs harmless.147
74. During the September 2010 Technical Conference, Dr. Ethier of ISO-NE stated
that a dynamic net benefits test done on an hourly basis that examines the effect of the
demand response resource on LMPs, similar to that proposed by CDRI, would become
146 PIO July 27, 2010 Comments at 6; Massachusetts AG Oct. 13, 2010 Comments
at 11; Viridity Oct. 13, 2010 Comments at 2. See CDRI May 13, 2010 Comments for a
full description of the algorithms.
147 CDRI May 13, 2010 Comments Attachment B at 18. CDRI states that the
dispatch and settlement algorithms “could be employed to evaluate dispatch and assure
customer benefits, without being employed to perform allocations and settlements.”
CDRI Oct. 13, 2010 Comments at 4.
Docket No. RM10-17-000 - 58 -
very complicated to implement and require essentially an iterative process.148 Dr. Ethier
states that the ISO would have to run the dispatch model to formulate a base LMP with
no demand response and then re-run it with demand response in the market; however
those two iterations alone do not “cover the whole waterfront” in terms of the possible
iterations required. According to Dr. Ethier, the ISO could dispatch too much demand
response the first time, or if the ISO first rejected dispatching demand response, it may
need to go back and dispatch smaller amounts of demand response to determine what
would happen to the LMPs. Dr. Ethier stated that it is unclear where the ISO would stop
the iteration of testing the impact on LMPs of dispatching demand response.149 Andy Ott
of PJM also stated during the technical conference that implementing a net benefits test
would entail an iterative process that would be costly and difficult, if the RTO could even
75. Other commenters do not support the use of a net benefits test, but state that if one
is adopted it should be based on general principles that RTOs and ISOs must apply to
their systems in determining when LMP payments will apply.151 A few commenters
148 Sept. 13, 2010 Tr. 80-81 (Dr. Ethier).
150 Sept. 13, 2010 Tr. 82:16-21 (Mr. Ott).
151 See generally AEP, Midwest ISO, Occidental, NYISO, Constellation Oct. 13,
Docket No. RM10-17-000 - 59 -
articulated specific criteria to be used in a net benefits test.152 AEP believes that the
objective of an incentive payment for demand response resources on the basis of broad
market benefits can be achieved through a review of the costs and benefits of individual
providers. Constellation states that any net benefits test should be based on the difference
between the value consumers receive from energy and the cost of energy production.153
76. ISO-NE argues that a net benefits test should be based on economic efficiency, the
sum of producer and consumer surplus, which suggests that demand response incentives
ought to be provided to encourage demand reductions when the cost of energy production
exceeds the value of consumption, and to encourage usage when the cost of energy
production is less than the value of consumption. ISO-NE further states that a net
benefits test that focuses solely on consumer savings ignores the value lost by consumers
when energy consumption levels are reduced in response to incentive payments. ISO-NE
posits that any variant of a LMP payment should be limited to a very small number of
152 See, e.g., Midwest ISO October 13, 2010 Comments at 9-14 and Table 1
(setting forth comprehensive list of benefits and costs of demand response by type of
market participants); Occidental October 13, 2010 Comments at 4-5 (any net benefits test
must take into consideration offsetting variables, such as higher LMPs in the subsequent
periods where demand rebound increases market price, and capacity market price
effects); AEP October 13, 2010 Comments at 3-4 (AEP does not recommend the use of a
societal benefits component (i.e., health, environment, or employment efforts)).
153 Constellation October 13, 2010 Comments at 3-4.
Docket No. RM10-17-000 - 60 -
high-priced hours to minimize the economic distortions and avoid significant
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
154 ISO-NE Oct. 13, 2010 Comments at 4-5 and 21.
155 See, e.g., Sept. 13, 2010 Tr. 94:13-22 (Dr. Shanker); Sept. 13, 2010 Tr. 98:4-24
(Mr. Peterson); Sept. 13, 2010 Tr. 99:2-7 (Mr. Sunderhauf); ISO-NE Oct. 13, 2010
Comments at 5.
156 Sept. 13, 2010 Tr. 99:1-24 (Mr. Sunderhauf); ISO-NE Oct. 13, 2010 Comments
157 ISO-NE Oct. 13, 2010 Comments at 6.
158 Sept. 13, 2010 Tr. 103-104 (Mr. Weishaar).
Docket No. RM10-17-000 - 61 -
not sufficient, capacity markets are designed to ensure that a generator’s capital costs are
recovered; in a forward market that looks ahead as load adjusts, one can see whether a
resource is performing or not. For purposes of long-run reliability, he argues, as long as
compensation is in the amount that is necessary to induce new investment and reflects
market value, the argument that demand response in the bid stack will push out
generators is only true if generators are higher priced than the consumer resources that
are brought by demand response.159
2. Commission Determination
78. For the reasons discussed previously, the Commission is requiring each RTO and
ISO to implement the net benefits test described herein to determine whether a demand
response resource is cost-effective. More specifically, the Commission is adopting two
distinct requirements with respect to the net benefits test. While we find that the
integration of the billing unit effect into the RTO/ISO dispatch processes has the potential
to more precisely identify when demand response resources are cost-effective, we also
recognize and understand the position of several of the RTOs and ISOs that modification
of their dispatch algorithms may be difficult in the near term. Given these technical
difficulties, we will require to RTOs and ISO to perform (1) the net benefits test
described below to determine on a monthly basis under which conditions it is cost-
159 Sept. 13, 2010 Tr. 106:16-24 (Mr. Sipe).
Docket No. RM10-17-000 - 62 -
effective to pay full LMP to demand resources; 160 and (2) a study of the feasibility of
developing a mechanism for determining the cost-effective dispatch of demand resources.
79. First we direct each RTO and ISO to undertake an analysis on a monthly basis,
based on historical data and the RTO’s or ISO’s previous year’s supply curve, to identify
a price threshold to estimate where customer net benefits, as defined herein, would occur.
The RTO or ISO should determine the threshold price corresponding to the point along
the supply stack for each month beyond which the benefit to load from the reduced LMP
resulting from dispatching demand response resources exceeds the increased cost to load
associated with the billing unit effect, and update the calculation monthly. The ISOs and
RTOs are to determine monthly threshold prices based on historical data. The threshold
prices would be updated monthly as new data becomes available and posted on the RTO
web site. For example, the RTO should conduct an analysis of supply curves for January
through December 2010 to be used as a starting point to establish threshold prices for
2011. Those numbers would be updated monthly during 2011 for significant changes in
resource availability and fuel prices, with the process repeated monthly to reflect that
160 There will be inherent differences in the supply curves determined by each
RTO and ISO under the net benefits test required herein due to decisions the RTOs and
ISOs must make based on supply data for their regions, the mathematical methods each
RTO and ISO chooses to use for smoothing the supply curves, the certainty of changes in
supply due to outages in each region, local generation heat rates, and the choice of
relevant fuel price indices.
Docket No. RM10-17-000 - 63 -
month’s data from the previous year.161 The supply curve analysis should be updated
monthly, by the 15th day of the preceeding month in advance of the effective date, to
allow demand response providers as well as other market participants to plan, while still
reflecting current supply conditions.162
80. Based on historical evidence and analysis submitted in this proceeding, the
threshold point along the supply stack for each month will fall in the area where the
supply curve becomes inelastic, rather than the extreme steep portion at the peak or in the
flat portion of the supply curve.163 In other words, LMP will be paid to demand response
resources during periods when the nature of the supply curve is such that small decreases
161 The ISOs and RTOs are to select a representative supply curve for the study
month, smooth the supply curve using numerical methods, and find the price/quantity
pair above which a one megawatt reduction in quantity that is paid LMP would result in a
larger percentage decrease in price than the corresponding percentage decrease in
quantity (billing units). Beyond that point, a reduction in quantity everywhere along an
upward sloping supply curve would be cost-effective.
162 Thus, the test is to determine where: (Delta LMP x MWh consumed) >
(LMPNEW x DR); where LMPNEW is the market clearing price after demand response
(DR) is dispatched and Delta LMP is the price before DR is dispatched minus the market
clearing price after DR is dispatched.
163 Supply elasticity is defined as the percentage change in quantity supplied
divided by the percentage change in price. When the elasticity is less than or equal to
one, supply is considered inelastic. So, for example, in the inelastic portion of the supply
curve, a reduction in quantity supplied by one percent will result in more than a one
percent decrease in price. Using the terms related to demand response compensation, the
billing unit effect (percentage change in quantity supplied) will be more than offset by
lower LMP (percentage change in price), thus resulting in lower prices for wholesale
Docket No. RM10-17-000 - 64 -
in generation being called to serve load will result in price decreases sufficient to offset
the billing unit effect. The Massachusetts AG noted that the actual supply stack has
locally flat and steep sections at all bid prices. We recognize that the threshold price
approach we adopt here may result in instances both when demand response is not paid
the LMP but would be cost-effective and when demand response is paid the LMP but is
not cost-effective. We accept this result given the apparent computational difficulty of
adopting a dynamic approach that incorporates the billing unit effect in the dispatch
algorithms at this time.164
81. We direct each RTO and ISO to file its analysis as supporting documentation to
the accompanying tariff revisions with the Commission on or before July 22, 2011, along
with proposed tariff revisions necessary to comply with this Final Rule. The filing
should include the data, analytical methods and the actual supply curves used to
determine the monthly threshold prices for the last 12 months to show how the RTO or
ISO would calculate the curves.165 The Commission-approved net benefits test
methodology must be posted on the RTO or ISO’s website, with supporting
documentation. The RTO or ISO must also post the price threshold levels that would
have been in effect in the previous 12 months. In addition, when the net benefits test
164 See supra note 114.
165 See supra P 6.
Docket No. RM10-17-000 - 65 -
becomes effective, the supply curve analysis for the historic month that corresponds to
the effective month should be updated for current fuel prices, unit availabilities, and any
other significant changes to historic supply curve and posted on the RTO website (for
example, the supply curve analysis for the March price threshold would be posted in mid-
February). Finally, the supply curve analyses for all months should be updated and
posted on the RTO website if a significant change to the composition or slope of the
historic monthly curves occurs, such as extended outages or retirements not previously
82. Some commenters argue that that there would be no need for a net benefits test if
demand response resources were paid LMP-G, while others argue that use of a net
benefits test otherwise undermines our decision to compensate demand response
resources at the LMP. As stated above, the Commission finds that when a demand
response resource participating in an organized wholesale energy market is capable of
balancing supply and demand in the energy market and is cost-effective, as determined
by the net benefits test described herein, that demand response resource should receive
the same compensation, the LMP, as a generation resource when dispatched. We see no
reason to reduce that compensation simply to avoid the use of the net benefits test that
will ensure benefits to load.
83. Nearly every participant in the net benefits panel at the September 13, 2010
Technical Conference agreed that it would be counterproductive to defer to the RTO or
Docket No. RM10-17-000 - 66 -
ISO stakeholder process to determine when demand response provides net benefits
without explicit guidance from the Commission.166 We believe that this result, and the
guidance provided in this Final Rule will provide for timely improvements to RTO and
ISO market pricing for demand response resources participating in organized wholesale
84. In addition to requiring each RTO and ISO to construct the net benefits test
described herein, the Commission also imposes a second requirement for each RTO and
ISO to undertake a study, examining the requirements for and impacts of implementing a
dynamic approach to determine when paying demand response resources LMP results in
net benefits to customers. We believe that integration of the billing unit effect into RTO
and ISO dispatch algorithms holds promise for more accurately integrating demand
resources on a dynamic basis into the dispatch of the RTOs and ISOs. In theory, this
could help ensure that the cost-effective level of demand response resources is dispatched
or scheduled into the organized wholesale energy markets. Given the potential of
software enhancements to determine the amount of cost-effective demand response
resources purchased in the day-ahead and real- time energy markets, we believe that it
166 “[G]etting this decision resolved is an impediment to all the other stuff we want
to do with price response to demand, and DR generally in our market . . . so until we get
through this, we’re not going to make much progress . . . the implication of that is if you
send something back that leaves a lot of room for debate, it’s going to be a while on all
those other things.” Testimony of Robert Ethier, Vice President, Market Design, ISO-NE,
Sept. 13, 2010 Tr. at 136.
Docket No. RM10-17-000 - 67 -
would be useful for the Commission to know more about the feasibility of and
requirements for implementing improvements to the existing dispatch algorithms.
Therefore, we will require each RTO and ISO to undertake a study, either individually or
collectively, examining the requirements for, costs of, and impacts of implementing a
dynamic net benefits approach to the dispatch of demand resources that takes into
account the billing unit effect in the economic dispatch in both the day-ahead and 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
167 Additionally, the arguments presented for focusing on the effect of demand
response compensation in wholesale energy markets on capacity markets were not
convincing – that decreases in energy market revenues by generators will be recouped in
the form of increased capacity prices. First, they fail to consider how the increased
participation by demand resources could actually increase potential suppliers in the
capacity markets by reducing barriers to demand resources, which would tend to drive
capacity prices down. Second, they did not examine the way in which capacity markets
already may take into account energy revenues.
Docket No. RM10-17-000 - 68 -
cases, the capacity markets already reflect energy and ancillary service revenue in
determining capacity prices.
C. Measurement and Verification
1. NOPR Proposal
86. In the NOPR, the Commission explained that demand response curtailment is a
reduction in actual load as compared to the demand response provider’s expected level of
electricity consumption.168 The NOPR did not address measurement and verification of
87. Each RTO and ISO with a demand response program has procedures for the
measurement and verification of demand response. These procedures include techniques
to establish a customer baseline for each demand response participant. This customer
baseline then becomes the basis for measuring the quantity of demand response delivered
to the wholesale market. Customer baselines are often based on historic load
information, such as an average of five of the last ten comparable days’ hourly load
profile. Techniques vary among RTOs and ISOs and most have several techniques that
may be allowed, depending on the demand response provider’s characteristics.169
168 Demand Response Compensation in Organized Wholesale Energy Markets,
FERC Stats. & Regs. ¶ 32,656, at P 1 (2010).
169 See, e.g., ISO/RTO Council, North American Wholesale Electricity Demand
Response 2010 Comparison, under the tab for “Performance Evaluation Methods”
Docket No. RM10-17-000 - 69 -
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
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.
173 ISO-NE May 13, 2010 Comments at 34. ISO-NE identifies several practices
that, in its view, might be deployed by a demand responder to receive payment when it
has not, in fact, responded to price. ISO-NE states that observations of such behavior in
the Fall of 2007 led it to limit the hours demand response offers could clear the market.
Citing ISO New England Inc., Docket No. ER08-538-000 (February 5, 2008 filing).
ISO-NE May 13, 2010 Comments at 32-34.
Docket No. RM10-17-000 - 70 -
demand response to establish baselines by purchasing energy in the day-ahead market as
a way to overcome its concerns with statistical baseline methods.174 ISO-NE IMM
makes similar arguments and recommendations.175 Westar also appears to suppo
89. Similarly, CPower notes that with some baseline methods, paying LMP in all
hours could reward demand responders for any shift in demand from the baseline, not just
shifting load from high LMP hours to low LMP hours, or could simply shift load from
day-to-day in different hours to affect the calculation of actual curtailment, which it
labels “checkerboarding.” However, CPower believes that the capability of consumption
management to shed or shift load for many hours is well into the future, and perhaps not a
current concern. CPower also believes that baseline standards along with market
monitoring will develop to meet these concerns.177
90. ISO-NE IMM asserts that “[if] the Commission adopts any proposal that permits
the use of an administrative baseline it should explicitly state that any demand reductions
offered into Commission-jurisdictional markets that are not genuine, even if they are the
175 ISO-NE IMM May 13, 2010 Comments at 9-13 and Attachment A.
176 Westar May 13, 2010 Comments at 3.
177 CPower May 13, 2010 Comments at 4-5.
Docket No. RM10-17-000 - 71 -
result of ‘normal’ activity . . . may be violations of the Commission’s anti-manipulation
rules and subject to penalties thereunder.”178
91. Noting the ongoing efforts by the industry and the North American Energy
Standards Board (NAESB) on measurement and verification, EnerNOC takes the view
that resolution of customer baseline issues should not delay the issuance of this Final
92. Finally, some commenters assert that measurement and verification methods
should not be standardized, but left to the RTOs and ISOs to reflect the unique features of
their individual energy, ancillary services, and capacity markets.180
3. Commission Determination
93. The Commission agrees with commenters who assert that measurement and
verification are critical to the integrity and success of demand response programs.
Without a determination of a demand response provider’s expected use of power, the
ISOs and RTOs cannot determine whether that provider has in fact reduced its energy
178 ISO-NE IMM May 13, 2010 Comments at 14 (footnotes omitted) (ISO-NE
MMU also notes that “[i]n assessing whether demand reductions are genuine, allowance
should be made for non-performance analogous to a generator’s forced outage.”).
179 EnerNOC, Inc. May 13, 2010 Comments at 4.
180 ECS May 13, 2010 Comments at 3; Indicated New York TOs May 13, 2010
Comments at 2-3; Midwest ISO May 13, 2010 Comments at 17, 21; National Grid
May 13, 2010 Comments at 11-12; NSTAR May 14, 2010 Comments at 9; PPL May 13,
2010 Comments at 4.
Docket No. RM10-17-000 - 72 -
usage when paid to do so. Towards that end, all the RTOs and ISOs already have
measurement and verification protocols for their demand response programs.181 In
addition, we have adopted Phase I standards for measurement and verification published
by the North American Energy Standards Board, 182 and have recognized the potential
benefits of the continuing NAESB effort to craft Phase II standards with more substantive
and consistent wholesale standards for measurement and verification.183
94. A number of commenters maintain that compensating demand response resources
at the LMP during all hours could make determining baselines for demand response
providers exceedingly difficult. However, the impact of our adopting the net benefits test
described herein is that the LMP will not be paid to demand response resources in all
hours. Accordingly, implementation of this Final Rule would not appear to prevent the
determination of appropriate baselines. Nonetheless, we direct ISOs and RTOs to review
their current requirements in light of the changes in this Final Rule and develop
appropriate revisions and modifications, if necessary, to ensure that their baselines
remain accurate and that they can verify that demand response resources have performed.
Specifically, we direct each RTO and ISO to include as part of the compliance filing
181 See, e.g., PJM Interconnection, L.L.C., 123 FERC ¶ 61,257 (2008).
182Standards for Business Practices and Communication Protocols for Public
Utilities, Final Rule, 131 FERC ¶ 61,022 (2010).
183 Id., at P 32-34.
Docket No. RM10-17-000 - 73 -
required herein, an explanation of how its measurement and verification protocols will
continue to ensure that appropriate baselines are set, and that demand response will
continue to be adequately measured and verified as necessary to ensure the performance
of each demand response resource. If necessary, each RTO and ISO should propose any
changes needed to ensure that measurement and verification of demand response will
adequately capture the performance (or non-performance) of each participating demand
response market participant to be consistent with the requirements of this Final Rule.
95. Finally, we agree with ISO-NE IMM that demand reductions that are not genuine
may be violations of the Commission’s anti-manipulation rules.184 Allegations of such
behavior will continue to be investigated, and when appropriate, sanctions will be
brought to bear.
D. Cost Allocation
1. NOPR Proposal
96. In response to the NOPR and September 13, 2010 Technical Conference, many
commenters argue that, in order to determine the justness and reasonableness of the
proposed compensation level, the corresponding cost allocation must be considered.185
184 18 CFR 1.c (2010).
185 ISO-NE May 13, 2010 Comments at at 39-40; see also May 13, 2010
Comments of: AEP at 6-10; CAISO at 6; ConEd at 2; Hess at 3; ICC at 12; PJM at 8;
Potomac Economics at 3; Massachusetts AG at 11; Midwest ISO TOs at 5-6; Midwest
TDUs at 13; EEI at 5; NECPUC at 12, 22; NECA at 11; RRI at 6; SDG&G at 3-4.
Docket No. RM10-17-000 - 74 -
More specifically, these commenters raise concerns regarding how the costs associated
with payment of LMP for demand response will be allocated, or assigned, within an ISO
or RTO. Several commenters assert that the issues of cost allocation and net benefits are
inherently linked, so that the Commission must address both issues together.186
97. Comments reveal five specific methods for cost allocation: (1) assignment of
costs to the load serving entity (LSE) associated with the demand response provider,
(2) assignment of costs broadly to all purchasing customers, (3) bifurcated assignment of
costs with some directly assigned to a LSE and others assigned broadly, (4) directly
assign the cost for demand response compensation to the retail customers that bid the
demand response into the wholesale market, and (5) the settlement method proposed by
CDRI, which incorporates the cost of demand response into the dispatch algorithm.
Some commenters argue not for a specific method, but for each regional entity to select
and employ a method of its own,187 and a few other commenters assert that the
Commission need not address cost allocation in this proceeding.188
186 As further addressed below, several commenters assert that the costs of demand
response compensation should be borne by only those market participants determined to
have benefitted from the subject load reduction, as determined by some type of net
benefits test. See, e.g., May 13, 2010 Comments of: ISO-NE at 5-6; NECPUC at 22;
PJM at 12-14; P3 at 37-38.
187 EPSA May 12, 2010 Comments at 67; Midwest TDUs May 13, 2010
Comments at 1; ODEC May 14, 2010 Comments at 5; Potomac Economics May 14, 2010
Docket No. RM10-17-000 - 75 -
98. Some commenters argue that costs should be assigned to the LSE associated with
the demand response provider because it is this entity that receives the full benefit of
demand response.189 Others argue that costs should be assigned broadly to all purchasing
customers because of the concept of cost causation.190 Cost causation dictates that the
costs of demand response should be allocated directly to those entities that benefit from
the demand response service provided.191 Another method presented involves a
bifurcated assignment of costs, with some directly assigned to a LSE and others assigned
broadly.192 The fourth method suggested is to directly assign the costs of demand
Comments at 9-10; RRI May 13, 2010 Comments at 4; SoCal Edison May 13, 2010
Comments at 4 (advocating that the local regulatory authority is the proper entity to
regulate cost allocation); Viridity May 13, 2010 Comments at 24; EnerNOC Sept. 13,
2010 Comments at 1; Midwest TDUs Sept. 13, 2010 Comments at 2.
188 Massachusetts AG May 13, 2010 Comments at 9-10.
189 PJM May 13, 2010 Comments at 15; Midwest ISO May 13, 2010 Comments at
6; CAISO May 13, 2010 Comments at 6; Detroit Edison May 13, 2010 Comments at 3-4;
EEI May 13, 2010 Comments at 5; NUSCO May 13, 2010 Comments at 2; National Grid
Sept. 13, 2010 Comments at 2-3; Midwest ISO Oct. 13, 2010 Comments at 4.
190 NECPUC May 13, 2010 Comments at 22; DC OPC May 13, 2010 Comments
at 4; PCA Sept. 10, 2010 Comments at 4; Steel Manufactures Ass’n Sept. 13, 2010
Comments at 5; Ohio Commission Sept. 13, 2010 Comments at 4; Wal-Mart Sept. 14,
2010 Comments at 3.
191 PJM May 13, 2010 Comments at 9; NECPUC May 13, 2010 Comments at 22;
PCA Sept. 10, 2010 Comments at 4.
192 PJM May 13, 2010 Comments at 12; ISO-NE May 13, 2010 Comments at 5.
Docket No. RM10-17-000 - 76 -
response to the retail customer that bid the demand response into the wholesale market.193
Lastly, the settlement algorithm proposed by CDRI adjusts upward the day-ahead price
paid by the customers that participate in the day-ahead energy market to account for these
3. Commission Determination
99. When a demand response provider curtails, the RTO experiences a reduction in
load with a corresponding reduction in billing units through which the RTO derives
revenue. When the two conditions discussed above are met, however, the RTO must pay
LMP to both generators and demand response providers for the resources that clear the
energy market. The difference between the amount owed by the RTO to resources,
including demand response providers, and the revenue it derives from load results in a
negative balance that must be addressed through cost allocation. Therefore, a method is
needed to ensure that RTOs and ISOs recover the costs of obtaining demand response.
100. Since the dispatch of demand response resources affects the LMP charged, and
will result in a lower LMP, the customers benefitting from that lower LMP depends upon
transmission constraints, and the price separation such constraints cause within the RTO.
193 DC OPC May 13, 2010 Comments at 4. It concedes that this could be a
complex undertaking and would result in billing a retail customer for energy that did not
194 CDRI, Integration of Demand Response Into Day Ahead Markets (Attachment
B), May 13, 2010 Comments at 16.
Docket No. RM10-17-000 - 77 -
In some hours in which transmission constraints do not exist, RTOs establish a single
LMP for their entire system (a single pricing area) in which case the demand response
would result in a benefit to all customers on the system. When transmission constraints
are present, however, LMPs often vary by zone, or other geographic areas. Allocating
the costs associated with demand response compensation proportionally to all entities that
purchase from the relevant energy market in the area(s) where the demand response
resource reduces the market price for energy at the time when the demand response
resource is committed or dispatched will reasonably allocate the costs of demand
response to those who benefit from the lower prices produced by dispatching demand
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
195 This approach is consistent with long-standing judicially-endorsed cost
allocation principles. See, e.g., Midwest ISO Transmission Owners v. FERC, 373 F.3d
1361, 1368, 1370-71 (D.C. Cir. 2004); see also Illinois Commerce Comm’n v. FERC,
576 F.3d 470, 476 (7th Cir. 2009).
Docket No. RM10-17-000 - 78 -
102. We therefore find just and reasonable the requirement that each RTO and ISO
allocate the costs associated with demand response compensation proportionally to all
entities that purchase from the relevant energy market in the area(s) where the demand
response reduces the market price for energy at the time when the demand response
resource is committed or dispatched. Accordingly, each RTO and ISO is required to
make a compliance filing on or before July 21, 2011 that either demonstrates that its
current cost allocation methodology appropriately allocates costs to those that benefit
from the demand reduction or proposes revised tariff provisions that conform to this
E. Commission Jurisdiction
103. Some commenters, including several state commissions and LSEs, express
concern about whether and how standardizing demand response compensation in the
wholesale market will affect treatment of demand response at the retail level. They assert
that the issue of demand response compensation is fundamentally intertwined with retail
rates, ratepayer issues, and state jurisdictional concerns.196 Some commenters note
general concerns about the need for federal and state level coordination. They assert that
196 See, e.g., CAISO May 13, 2010 Comments at 12; PJM May 13, 2010
Comments at 8 (appropriate and efficient demand response compensation may require
coordination between the Commission, retail regulatory authorities, competitive retail
suppliers, and other RTOs).
Docket No. RM10-17-000 - 79 -
many states have taken significant steps to install advanced meters and implement
programs to encourage efficient use of energy and that the success of state-level efforts
should be a factor in deciding whether and how to implement demand response programs
in the wholesale market.197 According to these commenters, a Commission-mandated
compensation level could have the unintended consequence of retarding the expansion of
price-responsive demand at the retail level.198
104. Other commenters flatly question the Commission’s jurisdiction to set the
compensation for demand response in wholesale energy markets. They argue that it is
within the purview of retail regulatory authorities to take into account local policies and
concerns, and the types of demand response being offered, when determining the
appropriate compensation level.199 Indeed, the California Commission seeks clarification
197 See ISO-NE IMM May 13, 2010 Comments at 6.
198 Illinois Commission May 13, 2010 Comments at 8; PJM May 13, 2010
Comments at 23; EEI May 13, 2010 Comments at 4; Capital Power May 13, 2010
Comments at 5; ODEC May 13, 2010 Comments at 60; Steel Producers May 13, 2010
Comments at 2.
199 See Illinois Commission May 13, 2010 Comments at 13; CAISO May 13, 2010
Comments at 12-13; PJM IMM May 13, 2010 Comments at 5 (“The assertion that
demand side participants should be paid full LMP, regardless of their retail tariff rate,
because the current approach of paying LMP minus G represents an intervention into
retail rate design, cannot be correct. The entire demand side program exists only because
of the disconnect between wholesale and retail rates. The assertion that the program
design should not account for the details of retail rate design leads to the conclusion that
there should be no demand side program at all.”); NECPUC May 13, 2010 Comments at
25 (“As energy market customers benefit most from both a well-functioning wholesale
Docket No. RM10-17-000 - 80 -
that this Commission does not seek to regulate retail customer rates or seeks LSE
oversight authority traditionally exercised by states. The California Commission asserts
that this Commission’s actions concerning CAISO’s Proxy Demand Resource tariff
filing200 illustrates that demand response settlement mechanisms are within the authority
of the California Commission.201
105. Other commenters foresee retail regulatory authorities effectively taking an end-
run around any Commission-mandated compensation level by adjusting retail rate design
market and robust participation in retail programs, a balance between these two segments
is essential. Compensation that increases demand response resource participation in the
wholesale market should not be so generous, from the perspective of the customer, that it
makes participation in retail programs pale in comparison.”); SDG&E, SoCal Edison, and
PG&E May 13, 2010 Comments at 4 (“[M]andating that ISOs take on settlement
responsibility or precluding any retail settlement between retail customers, LSEs or DRPs
would intrude on retail jurisdictional authority and contravenes the premise of separation
outlined in Order 719.”); Consumers Energy May 13, 2010 Comments at 3; Detroit
Edison May 13, 2010 Comments at 4.
200 See California Independent System Operator Corp., 132 FERC ¶ 61,045
201 California Commission May 13, 2010 Comments at 9-10. 1. See also SDG&E,
SCE, PG&E May 13, 2010 Comments at 2 (“[T]he Commission should clarify that its
order does not preclude LRAs from administering retail revenue settlements between
retail customers, Load Serving Entities (LSEs) and Demand Response Providers (DRPs)
associated with DR participation in wholesale markets.”).
Docket No. RM10-17-000 - 81 -
or prohibiting jurisdictional end-use customers from participating in wholesale market
opportunities available to demand response resources.202 The Illinois Commission
[W]hen load serving entities are vertically integrated with generation
regulated under state authority . . . any non-zero payment to a demand
response resource reduces the revenues to generators under the state
regulatory authority. The result is a leakage of money to an entity outside
of the state’s regulatory authority. Therefore, retail rates to all customers
may need to be increased in order to recover the costs to generators that
would have otherwise been recovered through the purchase of electricity,
but instead went to the payment of a demand response resource. Therefore,
compensating demand response resources may increase the likelihood that
state commissions will prohibit the participation of demand response
resources in the jurisdictions.203
106. Similarly, PJM states that the prohibition devised by retail regulatory authorities
with jurisdiction over smaller distributors that deliver 4 million MWh or fewer per annum
202 See PJM May 13, 2010 Comments at 24; PJM May 13, 2010 Comments at 18
(It is reasonable to assume that each retail regulatory authority in PJM will re-examine
the impact of load reduction based on wholesale compensation equal to the LMP,
including cost allocation, on the LSEs subject to its jurisdiction, and potentially re-align
retail market rules affecting economic load response participation.); Delaware
Commission and NECPUC May 13, 2010 Comment at 25; OMS May 13, 2010
Comments at 7 (state commissions and LSEs have significant concerns that the potential
costs for non-participating customers may exceed the benefits that ARCs can provide to
their states and to participating customers, so state commissions will have a significant
disincentive to support the participation of ARCs in RTO energy markets and in their
states if LMP compensation is adopted).
203 Illinois Commission May 13, 2010 Comments at 15.
Docket No. RM10-17-000 - 82 -
may entail the revocation of previously provided permission to participate in some or all
of the wholesale market opportunities for demand resources.204
107. Some commenters further posit that, even where retail regulatory authorities do
not prohibit or limit demand response participation, they may make adjustments to the
retail rate, which affect the ultimate compensation that the retail customer will be paid for
its demand reductions.205 For example, the OMS asserts,
If the Commission were to adopt the proposed rule, state commissions and
LSEs could correct this distorted price signal by revising retail tariffs for
customers that do business with [aggregators of retail customers] in order to
charge the retail rate to participating customers for energy which was not
consumed or metered as a result of load reductions.206
108. Another set of commenters, especially generators, assert that due to the disconnect
between wholesale and retail issues related to demand response, Commission-mandated
payments for demand response will fail to address true barriers to demand response,
which exist, they assert, at the retail level. These commenters argue that the
Commission’s actions in this proceeding ignore the fact that the primary barrier to
demand response is the disconnect between retail and wholesale prices and, according to
these commenters, the remedy resides at the retail -- not wholesale -- level where there is
204 PJM May 13, 2010 Comments at 20-21.
205 CAISO May 13, 2010 Comments at 4.
206 OMS May 13, 2010 Comments at 3. See also EEI May 13, 2010 Comments at
Docket No. RM10-17-000 - 83 -
a lack of dynamic pricing.207 For example, some commenters recognize that the lack of
retail real-time pricing is a barrier to demand response participation but further assert that
whatever changes the Commission makes to wholesale demand response (where there is
real-time pricing) will not address that fundamental problem.208
109. On the other hand, some commenters, such as commercial customers, wholly
reject challenges to the Commission’s authority to set the compensation level for demand
response occurring in organized wholesale energy markets.209 They assert that the FPA
gives the Commission broad authority to correct market flaws, including compensation
for demand response.210
207 Calpine May 13, 2010 Comments at 3.
208 See EPSA May 13, 2010 Comments at 7 (“The NOPR incorrectly attempts to
resolve retail market barriers to DR participation (i.e., lack of dynamic pricing) through a
wholesale pricing fix.”); RRI Energy May 13, 2010 Comments at 5 (“The NOPR is
essentially trying to use an inefficient wholesale solution to remedy a retail problem. The
NOPR does not attempt to address (nor should it attempt to address) the various retail
rate structures that demand response providers in various regions of the country face.”);
The Brattle Group May 13, 2010 Comments at 8 (“[T]he appropriate avoidable retail
generation rate is best done through agreements between the LSE and the curtailment
service provider under the oversight of the relevant retail regulating authority. This
approach . . . avoids requiring the RTO to sort through potentially complicated retail rate
structures.”); Steel Manufacturers Ass’n May 13, 2010 Comments at 9 (“[T]here is no
rational basis for the Commission, or RTOs, to adopting varying demand response
participation or compensation rules based on the retail pricing method of otherwise
qualified participating loads.”).
209 DR Supporters Aug. 30, 2010 Reply Comments at 4.
Docket No. RM10-17-000 - 84 -
110. Some commenters further argue that any disconnect between wholesale and retail
issues relevant to demand response should not negate the Commission’s efforts in this
proceeding. They argue that dynamic retail pricing, retail shopping opportunities and the
potential for retail energy efficiency measures are no substitute for adequate wholesale
demand response compensation and the deployment of demand response measures akin
to a generator.211
111. Moreover, some commenters assert that, while the Commission has authority to
establish the compensation level for demand response in the wholesale market, the
Commission cannot require subtraction of retail rate components from the LMP rate,
reasoning that retail rates reflect a myriad of local concerns beyond the Commission’s
jurisdiction. These commenters assert that LMP reflects the wholesale value of the
demand response service provided and that proponents of the LMP-G formulation
(subtracting a portion of the retail rate) seek to draw the Commission into a review of
retail rate matters beyond its purview.212 Additionally, these commenters point to the
difficulty of isolating the generation component of the retail rate from other components,
such as transmission, distribution, and overhead. They argue that different retail rate
contracts reflect different costs of generation, depending on local circumstances existing
211 Wal-Mart May 13, 2010 Comments at 11.
212 Viridity June 18, 2010 Comments at 13.
Docket No. RM10-17-000 - 85 -
at the time the contract was executed, and that retail rate structures reflect a wide range of
competing considerations, such as cost causation, the impact of rate design on
employment, and the state of the local economy, all of which are appropriately left to
state commissions. These commenters posit that, instead of tailoring the wholesale rate,
i.e., LMP, to retail rate conditions, it is better to get the wholesale rate right in the first
instance and then allow retail rate structures adjust as needed to wholesale market
conditions.213 According to Dr. Kahn, accounting for the retail rate in this Final Rule
would “ignore the proper scope of the Commission’s regulatory responsibilities, the fact
that the great majority of retail rate designs are economically inefficient and that it is
retail rates that should not be permitted to undermine efficient wholesale rates rather than
2. Commission Determination
112. We begin by rejecting challenges to the Commission’s authority to set the
compensation level for demand response in organized wholesale energy markets. Section
205 of the FPA tasks the Commission with ensuring that all rates and charges for or “in
connection with” the transmission or sale for resale of electric energy in interstate
commerce, and all rules and regulations “affecting or pertaining to” such rates or charges
213 Viridity June 18, 2010 Comments at 14.
214 DR Supporters Aug. 30, 2010 Comments (Kahn Affidavit at 4).
Docket No. RM10-17-000 - 86 -
are just and reasonable.215 The Commission has previously explained that it has
jurisdiction over demand response in organized wholesale energy markets, because it
directly affects wholesale rates. 216
113. For this reason, the Commission has jurisdiction to regulate the market rules under
which an ISO or RTO accepts a demand response bid into a wholesale market.217
Furthermore, as discussed above, the Commission’s actions in this proceeding are
consistent with Congressional policy requiring federal level facilitation of demand
response, because this Final Rule is designed to remove barriers to demand response
participation in the organized wholesale energy markets.
114. Nevertheless, we recognize that jurisdiction over demand response is a complex
matter that lies at the confluence of state and federal jurisdiction. By issuing this Final
Rule, the Commission is not requiring actions that would violate state laws or
regulations. The Commission also is not regulating retail rates or usurping or impeding
state regulatory efforts concerning demand response.
115. We acknowledge that many barriers to demand response participation exist and
that our ability to address such barriers is limited to the confines of our statutory
authority. At the same time, the FPA requires the Commission to ensure that the rates
215 16 U.S.C. 824d (2006).
216 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 47.
217 Order No. 719-A, FERC Stats. & Regs. ¶ 31,292 at P 52.
Docket No. RM10-17-000 - 87 -
charged for energy in wholesale energy markets are just, reasonable, and not unduly
discriminatory or preferential. The Commission has the authority, indeed the
responsibility, to assure that wholesale rates are just and reasonable. Therefore, we
disagree with commenters who would have the Commission refrain from acting on
demand response compensation in the organized wholesale energy markets because of
the potential actions that state retail regulatory authorities may or may not take. As we
note above, this Final Rule is not intended to usurp state authority or impede states from
taking any actions within their authority. Rather, the Commission is taking action here to
fulfill its statutory mandate to ensure just, reasonable, and not unduly discriminatory or
preferential wholesale rates.
V. Information Collection Statement
116. The Office of Management and Budget (OMB) requires that OMB approve certain
information collection and data retention requirements imposed by agency rules.218
Therefore, the Commission is submitting the proposed modifications to its information
collections to OMB for review and approval in accordance with section 3507(d) of the
Paperwork Reduction Act of 1995.219
117. OMB’s regulations require approval of certain information collection
requirements imposed by agency rules. Upon approval of a collection(s) of information,
218 5 CFR § 1320.11(b) (2010).
219 44 U.S.C. § 3507(d) (2006).
Docket No. RM10-17-000 - 88 -
OMB will assign an OMB control number and an expiration date. Respondents subject
to the filing requirements of a rule will not be penalized for failing to respond to these
collections of information unless the collections of information display a valid OMB
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
Burden Estimate and Information Collection Costs: The estimated Public Reporting
burden and cost for the requirements contained in the final rule follow.
time filing, due
7/22/2011) 6 (RTOs and
ISOs) 1 (one-time
filing) 300 1,800 (one-
Study on 6 (RTOs and 1(one-time 2,000 12,000 (one-
Docket No. RM10-17-000 - 89 -
time filing, due
ISOs) filing) time filing)
update to price
7/22/2011) 6 (RTOs and
ISOs) 12 50 3,600
In Year 1, the following requirements are imposed220: (1) compliance filing due
on or before July 22, 2011, and (2) monthly updates (for months 5-12, and starting after
the compliance filing). The total corresponding burden hours are estimated to be: 1,800
hrs. + (8 filings * 6 respondents * 50 hrs./filing), for a total of 4,200 hours. The
corresponding total cost is estimated to be: 4,200 hours * $220/hour, for a total of
In Year 2, (a) the monthly update to the price threshold, and (b) the study on
dynamic net benefits approach (due on or before September 21, 2012) are imposed. The
corresponding total burden is estimated to be 3,600 + 12,000 hours, for a total of 15,600
220 The one-time study is due on or before September 21, 2012. For the purpose of
the burden and cost estimates, we are including all of the burden and cost related to the
study in Year 2, although filers may perform part of the work in Year 1.
Docket No. RM10-17-000 - 90 -
hours. The corresponding total cost estimate is: 15,600 hours * $220/hour, for a total of
In Year 3, the monthly update to the price threshold is imposed. The
corresponding total burden and cost are estimated to be 3,600 hours and $792,000 (3,600
hours * $220/hour).
Title: FERC-516, “Electric Rate Schedules and Tariff Filings”
Action: Proposed Collections.
OMB Control No: 1902-0096.
Respondents: Business or other for profit, and/or not for profit institutions.
Frequency of Responses: One-time filings for (a) the compliance filing, due on or before
July 22, 2011, and (b) the study on dynamic net benefits approach, due on or before
September 21, 2012. In addition, monthly updates to the price threshold and web posting
will be required starting after the compliance filing.
Necessity of the Information: The information from FERC-516 enables the Commission
to exercise its statutory obligation under sections 205 and 206 of the FPA. FPA section
205 specifies that all rates and charges, and related contracts and service conditions for
wholesale sales and transmission of energy in interstate commerce be filed with the
Commission and must be “just and reasonable.” In addition, FPA section 206 requires
the Commission, upon complaint or its own motion, to modify existing rates or services
that are found to be unjust, unreasonable, unduly discriminatory or preferential.
Docket No. RM10-17-000 - 91 -
119. In Order No. 719, the Commission emphasized the importance of demand
response as a vehicle for improving the competitiveness of organized wholesale
electricity markets and ensuring supplies of energy at just, reasonable and not unduly
discriminatory or preferential rates. This Final Rule addresses the need for organized
wholesale energy markets to provide compensation to demand response resources on a
comparable basis to supply-side resources when demand response resources are
comparable to supply-side resources, so that both supply and demand can meaningfully
participate. This final rule establishes a specific compensation approach for demand
response resources participating in organized wholesale energy markets, administered by
RTOs and ISOs. Each Commission-approved RTO and ISO that has a tariff provision
providing for participation of demand response resources in its organized wholesale
energy market must: (a) pay demand response resources the market price (full LMP) for
energy (when found to be cost-effective as determined by the net benefits test described
herein), (b) submit a one-time compliance filing, (c) perform monthly updates to the
Price Threshold, and (d) submit a one-time Study on Dynamic Net Benefits Approach.
120. Interested persons may obtain information on the reporting requirements by
contacting: Federal Energy Regulatory Commission, 888 First Street NE, Washington,
DC 20426 [Attention: Ellen Brown, Information Clearance Officer, Office of the
Executive Director, e-mail: DataClearance@ferc.gov, phone: (202) 502-8663, fax: (202)
273-0873]. Comments on the requirements of the final rule may also be sent to the
Docket No. RM10-17-000 - 92 -
Office of Information and Regulatory Affairs, Office of Management and Budget,
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy Regulatory
Commission]. For security reasons, comments to OMB should be submitted by e-mail
to: firstname.lastname@example.org. Comments submitted to OMB should include
Docket Number RM10-17 and OMB Control Number 1902-0096.
VI. Environmental Analysis
121. The Commission is required to prepare an Environmental Assessment or an
Environmental Impact Statement for any action that may have a significant adverse effect
on the human environment.221 The Commission concludes that neither an Environmental
Assessment nor an Environmental Impact Statement is required for this Final Rule under
section 380.4(a)(15) of the Commission’s regulations, which provides a categorical
exemption for approval of actions under sections 205 and 206 of the FPA relating to the
filing of schedules containing all rates and charges for the transmission or sale subject to
the Commission’s jurisdiction, plus the classification, practices, contracts, and
regulations that affect rates, charges, classifications, and services.222
221 Regulations Implementing the National Environmental Policy Act, Order
No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles
1986-1990 ¶ 30,783 (1987).
222 18 CFR § 380.4(a)(15) (2010).
Docket No. RM10-17-000 - 93 -
VII. Regulatory Flexibility Act
122. The Regulatory Flexibility Act of 1980 (RFA)223 generally requires a description
and analysis of final rules that will have significant economic impact on a substantial
number of small entities. The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a rule and that minimize any significant economic
impact on a substantial number of small entities. The Small Business Administration’s
(SBA) Office of Size Standards develops the numerical definition of a small business.224
The SBA has established a size standard for electric utilities, stating that a firm is small
if, including its affiliates, it is primarily engaged in the transmission, generation and/or
distribution of electric energy for sale and its total electric output for the preceding twelve
months did not exceed four million megawatt hours.225 ISOs and RTOs, not small
entities, are impacted directly by this rule.
123. California Independent System Operator Corp. (CAISO) is a non-profit
organization with over 54,000 megawatts of capacity and over 25,000 circuit miles of
223 5 U.S.C. § 601-612 (2006).
224 13 CFR § 121.101 (2010).
225 13 CFR § 121.201, Sector 22, Utilities.
Docket No. RM10-17-000 - 94 -
124. New York Independent System Operator, Inc. (NYISO) is a non-profit
organization that oversees wholesale electricity markets, dispatches over 500 generators,
and manages a nearly 11,000-mile network of high-voltage lines.
125. PJM Interconnection, L.L.C. (PJM) is comprised of more than 600 members
including power generators, transmission owners, electricity distributors, power
marketers, and large industrial customers, serving 13 states and the District of Columbia.
126. Southwest Power Pool, Inc. (SPP) is comprised of 61 members serving over 6.2
million households in nine states and has almost 50,000 miles of transmission lines.
127. Midwest Independent Transmission System Operator, Inc. (Midwest ISO) is a
non-profit organization with over 145,000 megawatts of installed generation. Midwest
ISO has over 57,000 miles of transmission lines and serves 13 states and one Canadian
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
Docket No. RM10-17-000 - 95 -
VIII. Document Availability
130. In addition to publishing the full text of this document in the Federal Register, the
Commission provides all interested persons an opportunity to view and/or print the
contents of this document via the Internet through the Commission’s Home Page
(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal
business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A,
Washington DC 20426.
131. From the Commission's Home Page on the Internet, this information is available
on eLibrary. The full text of this document is available on eLibrary in PDF and
Microsoft Word format for viewing, printing, and/or downloading. To access this
document in eLibrary, type the docket number excluding the last three digits of this
document in the docket number field.
132. User assistance is available for eLibrary and the Commission’s website during
normal business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-
208-3676) or email at email@example.com, or the Public Reference Room at
(202) 502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at
IX. Effective Date and Congressional Notification
133. This Final Rule will become effective on [INSERT DATE 30 DAYS AFTER
DATE OF PUBLICATION IN THE FEDERAL REGISTER]. The Commission has
Docket No. RM10-17-000 - 96 -
determined, with the concurrence of the Administrator of the Office of Information and
Regulatory Affairs, Office of Management and Budget, that this rule is not a “major rule”
as defined in section 351 of the Small Business Regulatory Enforcement Fairness Act of
By the Commission. Commissioner Moeller dissenting with a separate statement
( S E A L )
Kimberly D. Bose,
Docket No. RM10-17-000 - 97 -
In consideration of the foregoing, the Commission proposes to amend Part 35,
Chapter I, Title 18, Code of Federal Regulations, as follows.
PART 35—FILING OF RATE SCHEDULES AND TARIFFS
1. The authority citation for Part 35 continues to read as follows:
Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C.
2. Amend § 35.28 as follows:
Add a new paragraph (g)(1)(v).
§ 35.28 Non-discriminatory open access transmission tariff.
* * * * *
(v) Demand response compensation in energy markets. Each 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
(B) allocate the costs associated with demand response compensation
proportionally to all entities that purchase from the relevant energy market in the
area(s) where the demand response reduces the market price for energy at the time
when the demand response resource is committed or dispatched.
Note: The following appendix will not be published in the Code of Federal Regulations.
Docket No. RM10-17-000 - 98 -
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
Citizens for Pennsylvania’s Future (PennFuture)
Coalition of Midwest Transmission Customers (CMTC)
Connecticut Municipal Electric Energy Cooperative (CMEEC)
Consert Inc. (Consert)
Conservation Law Foundation (CLF)
Consolidated Edison Solutions, Inc. (ConEd)
Constellation Energy Commodities Group, Inc. (Constellation)
Consumer Demand Response Initiative (CDRI)
Consumer Power Advocates (CPA)
Consumers Energy Company (Consumers Energy)
CPG Advisors, Inc. (CPG)
CPower, Inc. (CPower)
Crane & Co., Inc. (Crane)
Delaware Public Service Commission (Delaware Commission)
Docket No. RM10-17-000 - 99 -
Demand Response and Smart Grid Coalition (Smart Grid Coalition)
Demand Response Supporters (DR Supporters)
Derstine’s Inc. (Derstine’s)
Detroit Edison Company (Detroit Edison)
Direct Energy Services, LLC (Direct Energy)
Dominion Resources Services, Inc. (Dominion)
Dr. Alfred E. Kahn (Dr. Kahn)
Dr. Charles J. Cicchetti (Dr. Cicchetti)
Dr. Roy J. Shanker (Dr. Shanker)
Dr. William W. Hogan (Dr. Hogan)
Duke Energy Corporation (Duke Energy)
Durgin and Crowell Lumber Co., Inc. (Durgin)
Edison Electric Institute (EEI)
Edison Mission Energy (Edison Mission)
Electric Power Supply Association (EPSA)
Electricity Consumers Resource Council (ELCON)
Electrodynamics, Inc. (Electrodynamics)
Energy Curtailment Specialists, Inc. (ECS)
Energy Future Coalition (EFC)
EnerNOC, Inc. (EnerNOC)
Environmental Defense Fund (EDF)
Exelon Corporation (Exelon)
Federal Trade Commission (FTC)
FirstEnergy Service Company (FirstEnergy)
GDF SUEZ Energy North America, Inc. (GDF)
Hess Corporation (Hess)
Illinois Citizens Utility Board (Illinois CUB)
Illinois Commerce Commission (ICC)
Independent Power Producers of New York, Inc. (IPPNY)
Indicated New York Transmission Owners (Indicated New York TOs)
Industrial Energy Consumers of America (IECA)
Industrial Energy Consumers of Pennsylvania (IECPA)
Intergrys Energy Services, Inc. (Intergrys)
International Power America, Inc. (IPA)
Irving Forest Products, Inc. (Irving Forest)
ISO New England Inc. (ISO-NE)
ISO-NE Internal Market Monitor (ISO-NE IMM)
Jiminy Peak Mountain Resort, LLC
Docket No. RM10-17-000 - 100 -
Joint Consumer Advocates (Joint Consumers)
Limington Lumber (Limington)
Madison Paper Industries (Madison Paper)
Maryland Governor Martin O’Malley (Governor O’Malley)
Maryland Public Service Commission (Maryland Commission)
Massachusetts Attorney General (Massachusetts AG)
Midwest Independent Transmission System Operator, Inc. (Midwest ISO)
Midwest ISO Transmission Owners (Midwest ISO TOs)
Mirant Corporation (Mirant)
Monitoring Analytics, LLC (PJM IMM)
National Electrical Manufactures Association (NEMA)
National Energy Marketers Association (NEM)
National Grid USA (National Grid)
National League of Cities (NLC)
Natural Gas Supply Association (NGSA)
New England Conference of Public Utilities Commissioners (NECPUC)
New England Consumer Advocates (NECA)
New England Power Generators Association Inc. (NEPGA)
New England Power Pool Participants Committee (NEPOOL)
New England Public Systems (NE Public Systems)
New Jersey Board of Public Utilities (NJBPU)
New York Independent System Operator, Inc. (NYISO)
New York Mayor Michael R. Bloomberg (Mayor Bloomberg)
New York State Consumer Protection Board (NYSCPB)
New York State Public Service Commission (New York Commission)
North America Power Partners LLC (NAPP)
Northeast Utilities Services Company (NUSCO)
Northern California Power Agency (NCPA)
NSTAR Electric Company (NSTAR)
Occidental Chemical Corp. (Occidental)
Office of the People’s Counsel for the District of Columbia (DC OPC)
Okemo Mountain Resort (Okemo)
Old Dominion Electric Cooperative (ODEC)
Organization of Midwest ISO States (OMS)
Partners HealthCare (Partners)
Pennsylvania Department of Environmental Protection (PA Department of Environment)
Pennsylvania Office of Consumer Advocate (PCA)
Pennsylvania Public Utility Commission (Pennsylvania Commission)
Pennsylvania State Representative Chris Ross (Rep. Ross)
Docket No. RM10-17-000 - 101 -
Pepco Holdings, Inc. (PHI)
PJM Interconnection, L.L.C. (PJM)
PJM Power Providers Group (P3)
Potomac Economics, Ltd. (Potomac Economics)
PPL Parties (PPL)
Praxair, Inc. (Praxair)
Precision Lumber, Inc. (Precision)
Price Responsive Load Coalition (PRLC)
PSEG Companies (PSEG)
Public Interest Organizations (PIO)
Public Utilities Commission of Ohio (Ohio Commission)
Raritan Valley Community College (Raritan)
Robert J. Borlick (Mr. Borlick)
RRI Energy, Inc. (RRI)
San Diego Gas & Electric Company (SDG&E)
Schneider Electric USA, Inc. (Schneider)
Southern California Edison Company (SoCal Edison)
Southwest Power Pool, Inc. (SPP)
Steel Manufacturers Association (Steel Manufacturers Ass’n)
Steel Producers (SP)
Tendrill Networks, Inc. (Tendrill)
The Brattle Group
The E Cubed Company, L.L.C. (E3)
University of California, San Diego (UCSD)
Utility Economic Engineers (UEE)
Verso Paper Corp. (Verso)
Virginia Committee for Fair Utility Rates (Virginia Committee)
Viridity Energy, Inc. (Viridity)
Wal-Mart Stores, Inc. (Wal-Mart)
Waterville Valley Ski Resort Inc. (Waterville)
Westar Energy, Inc. (Westar)
Wisconsin Industrial Energy Group (WIEG)
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Demand Response Compensation in Docket No. RM10-17-000
Organized Wholesale Energy Markets
(Issued March 15, 2011)
MOELLER, Commissioner, dissenting:
While the merits of various methods for compensating demand response were
discussed at length in the course of this rulemaking, nowhere did I review any comment
or hear any testimony that questioned the benefit of having demand response resources
participate in the organized wholesale energy markets. On this point, there is no debate.
The fact is that demand response plays a very important role in these markets by
providing significant economic, reliability, and other market-related benefits.
However, in a misguided attempt to encourage greater demand response
participation in the organized energy markets, today’s Rule imposes a standardized and
preferential compensation scheme that conflicts both with the Commission’s efforts to
promote competitive markets and with its statutory mandate to ensure supplies of electric
energy at just, reasonable, and not unduly discriminatory or preferential rates.1 For these
reasons, I cannot support this Rule.
Standardizing Demand Response Compensation
As an initial matter, RTOs and ISOs currently offer different types of demand
response products that vary from region to region and in terms of capability and services
offered in the day-ahead and real-time energy markets. Moreover, the RTOs and ISOs to
date have been working with their market participants in a stakeholder process to design
demand response compensation rules that are tailored to suit the needs of their individual
energy markets. However, this will all change once the Rule takes effect and this
existing framework is replaced with the requirement that every organized wholesale
energy market pay demand resources the market price for energy (LMP) when its
demand reductions are, in theory, found to be cost-effective.
1 16 U.S.C. § 824d (2006).
Docket No. RM10-17-000 - 2 -
As I recognized in my initial statement in this proceeding, organized markets
such as the PJM Interconnection have already demonstrated the ability to develop
demand response compensation rules. Accordingly, I would have preferred to allow
these markets to continue to develop their own rules. Different demand response
products will have different values that reflect their varying capabilities and to require a
standard payment fails to reflect these meaningful differences.2
However, without ever determining that the existing region-by-region approach to
compensation is unjust and unreasonable, the Rule implies that the current approach is no
longer adequate to ensure that rates remain just and reasonable. In turn, the Rule finds
that “greater uniformity in compensating demand response resources” is required and as
justification for its action, references the existence of various barriers that limit the
participation of demand response in the energy markets.3 The majority ultimately
concludes that these barriers can be removed by better equipping demand response
providers with the financial resources to invest in enabling technologies.4 This is to say
that the majority believes that paying demand resources more money will help overcome
these barriers and encourage more participation. The Rule, however, never clearly
explains how the existence of barriers, in turn, justifies a payment of full LMP to demand
The Rule (like the NOPR) does not sufficiently discuss the need for standardizing
compensation across the organized markets or elaborate on how standardization will
remove genuine barriers that prevent meaningful participation by demand resources in
the energy markets. 5 While the Energy Policy Act of 2005 states that the policy of the
2 California Commission May 13, 2010 Comments at 6, “[P]romulgating a
uniform national rule at this time may inadvertently impede the implementation of
optimal demand response compensation for an individual ISO or RTO which address the
needs of that particular region.” The California Commission “is concerned that
mandatory ‘one size fits all’ pricing may stifle national and regional efforts to collect
valuable data and experience regarding the effects of different demand response program
designs on consumer participation and conflict with Congressional objectives.”
3 Rule at P 17, 57-59.
4 Rule at P 57-59.
5 Significant barriers do exist which prevent demand response from reaching its
full potential. Specifically, 24 barriers were identified in our National Assessment of
Demand Response Potential, FERC Staff Report, (June 2009) at 65-67.
Docket No. RM10-17-000 - 3 -
U.S. Government is to remove unnecessary barriers to demand response, the statute
never authorized the Commission to stimulate increased demand response participation
by requiring its compensation to include incentives or preferential treatment.6 Although,
the majority is quick to claim “that removing barriers to demand response participation is
not the same as giving preferential treatment to demand response providers…”, this is
exactly what is occurring in this Rule.7 As discussed below, the majority’s determination
is troubling as the Rule both affords preferential treatment to demand response resources
and unduly discriminates against them in other respects.
Demand Response Resources are Comparable . . . Sometimes
At the outset, the concept of “comparability” is at the core of this rulemaking, i.e.,
whether demand response resources are capable of providing a service comparable to
generation resources and if so, whether these resources should receive comparable
compensation for a comparable service. On this point, I believe they should.8 This is not
to say that a megawatt produced is the same as a megawatt not consumed; they are not
perfect equivalents. The characteristics of a megawatt and a “negawatt” are different,
both in terms of physics and in economic impact.
Assuming, however, that a demand resource can provide a balancing service that
is identical to that of a generation resource, it would make sense that a demand resource
providing a comparable service would receive comparable compensation. But this may
not occur under the Rule. The majority explains that if a demand resource is capable of
providing a service comparable to a generation resource, it will only be eligible to receive
comparable compensation, by definition, if it can also be determined that the resource
will result in a price-lowering effect to the market by passing a net benefits test.9
6 See Energy Policy Act of 2005, Pub. L. No. 109-58, § 1252(f), 119 Stat. 594,
7 Rule at P 59.
8 As explained below, I believe that comparable compensation is represented by
the value realized by the demand resource for providing a comparable service, regardless
of whether the source of that value is a payment from the market or a savings by the
9 Rule at P 47-50.
Docket No. RM10-17-000 - 4 -
In no other circumstance is a resource required to show that its participation
will depress the market price in order to receive comparable compensation for a
comparable service. 10 Such a definition unduly discriminates against demand resources
and as such, this requirement is unjust, unreasonable, and unduly discriminatory.
Overcompensating Demand Resources and the Net Benefits Test
At first glance, the Rule’s requirement that RTOs and ISOs pay demand response
resources the LMP only when it is deemed cost-effective appears to make sense. There is
near-universal agreement that the LMP reflects the value of the marginal unit, and as
such, it sends the proper price signal to keep supply and demand in relative balance.
Accordingly, the Rule explains that if the demand resource is capable of providing a
comparable service and is also cost-effective (i.e., using a net benefits test to ensure that
the overall benefit of the reduced LMP that results from dispatching demand recourses
exceeds the cost of dispatching those resources), then this resource should be paid the
same as a generation resource. However, the decision to pay demand resources the full
LMP under such circumstances actually results in overcompensation that is economically
inefficient, preferential to demand resources, and unduly discriminatory towards other
An example may help to illustrate a major flaw with this Rule. Assume that both a
generation resource and a demand resource bid into the energy market and both bids are
accepted and paid the LMP ($100). Then consider the fact that the demand resource will
save an amount that it would have otherwise paid by not purchasing generation at the
retail rate (“G”), which is $25. While the Rule requires that RTOs and ISOs pay the
demand resource the LMP (which is the identical amount the generation resource
receives), the Rule effectively ignores the fact that the demand resource will actually
receive a total compensation of LMP+G ($125) as a result of its decision not to
consume.11 Meanwhile, the generation resource will only receive the LMP ($100)
10 Testimony of Audrey Zibelman, President and CEO of Viridity Energy, Inc.,
Sept. 13, 2010 Tr. at 119, "[T]he fact that we're debating this [net benefits test] is
somewhat absurd. We have not required any other resource to demonstrate a benefit in
order to enter this market."
11 The proper economic measure of value realized by the demand resource is one
where the RTO or ISO makes a reduction from the LMP to account for the retail rate, but
then recognizes that the savings associated with the avoided retail generation cost should
be added back into the equation, i.e., (LMP-G)+G.
Docket No. RM10-17-000 - 5 -
payment as a result of its decision to produce. While the Rule’s intent is to ensure
that a demand resource receives “the same compensation, the LMP, as a generation
resource”, this is not the actual result.12 In this example, what will happen is that the
Rule will require that the demand response resource be overcompensated by $25.13
The Rule effectively finds that demand resources being compensated at the value
of full LMP is not enough, so instead requires that demand resource be paid the full LMP
plus be allowed to retain the savings associated with its avoided retail generation cost.
Professor William W. Hogan refers to this outcome as a “double-payment” because
demand resources would “receive” both the cost savings from not consuming electricity
at a particular price, plus an LMP payment for not consuming that same increment of
electricity.14 Not only is this result not comparable (by valuing a negawatt more than a
megawatt) and economically inefficient (by distorting the price signal), but this
preferential compensation will harm the efficiency of the competitive wholesale energy
The use of a net benefits test further reduces competitive efficiency and only
complicates the issue. As the Rule explains, the net benefits test involves the
determination of a threshold price point that is plotted along a historical supply curve in
an attempt to accurately calculate whether the cost of procuring additional demand
response is outweighed by the value it brings to the market in the form of a lower LMP.15
12 Rule at P 82. If it were the result, the generation resource would be paid the
LMP, $100, and the demand resource would be paid $75 and realize an additional $25 in
retail rate savings. Accordingly, both resources realize equivalent compensation valued
13 Ohio Commission May 13, 2010 Comments at 6, “[T]he Commission’s
proposal that RTOs pay demand response resources the full LMP takes the incentives for
wholesale demand response resources a step too far. It would provide an incentive to the
supplier of a demand response resource that exceeds the payments available to an
equivalent supply resource. The Commission should instead focus on removing the
existing barriers in the wholesale markets….”
14 See Attachment to Answer of EPSA, Providing Incentives for Efficient Demand
Response, Dr. William W. Hogan, October 29, 2009 (Docket No. EL09-68).
15 Testimony of Robert Weishaar, Jr., Attorney for Demand Response Supporters,
Sept. 13, 2010 Tr. at 46-47, "Administratively constructing an LMP-based break point for
compensating Demand Response participation would ignore many other qualitative and
Docket No. RM10-17-000 - 6 -
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.
During a technical conference convened to discuss the specific question on the
necessity of a net benefits test, the Commission heard testimony from a panel of experts.
A clear majority of the witnesses (representing a spectrum of interests that included
demand response advocates, economists, generators, and the RTOs and ISOs) argued
against the use of a complicated and admittedly imprecise17 net benefits test.18 Chief
among their concerns was that a net benefits test is unnecessary since the market clearing
function in a wholesale market, by definition, serves to guarantee that the resource that
clears the market is the lowest-cost resource.19 Other experts commented that the net
benefits test would be complicated, costly to implement, and of little value.20 Notably,
Dr. Alfred E. Kahn, the majority’s oft-quoted expert in defense of the full LMP payment,
did not opine on the merit of subjecting the LMP payment to a net benefits test.
quantitative benefits of Demand Response. Focusing only on the LMP impacts of
Demand Response is problematic."
16 ISO-NE May 13, 2010 Comments at 3-4.
17 Rule at P 80. Recognizing that “the threshold price approach we adopt here
may result in instances both when demand response is not paid the LMP but would be
cost-effective and when demand response is paid the LMP but is not cost-effective.”
18 Testimony of Donald Sipe, Attorney for Consumer Demand Response Initiative,
Sept. 13, 2010 Tr. at 43, "[T]here is probably not a need for a Net Benefits Test. But if
one is adopted, it should not be an artificial threshold that can be wrong both ways. It
should not be a mechanism that treats DR differently than generation.”
19 Viridity Energy, Inc., Oct. 13, 2010 Comments at 10. See also ELCON Oct. 13,
2010 Comments at 3; and Environmental Defense Fund Comments at 2.
20 Testimony of Andy Ott, Sr. Vice President, PJM Interconnection, Sept. 13, 2010
Tr. at 19, "[Y]ou have to use caution to actually take a benefits test and apply that to
compensation, because you may have unintended consequences."
Docket No. RM10-17-000 - 7 -
Further, as explained by Dr. Roy J. Shanker, if the Commission adopted the
payment of LMP minus the retail rate (“G”), then there is no need for a net benefits test
since the customer is paid the difference between the LMP and what they would have
paid under their retail rate, which is their net benefit. 21 He testified that the “Net
Benefits criteria is troubling in and of itself, as it explicitly incorporates consideration of
portfolio effects caused by the reduced demand on all load payments, versus the
economic decision-making of individual market participants pursuing their own
legitimate bus 22
I similarly agree that this test is unnecessary and will only distort price signals by
attracting more demand response than is economically efficient.23 The use of a net
benefits test also is troubling in that the Commission’s decision can be viewed as
somehow equating the concept of a just and reasonable rate with a lower price.24
However, I recognize that to defend its compensation scheme, the majority needed some
proposal that could arguably demonstrate that the cost of paying full LMP to demand
resources would be outweighed by the “benefit” of a lower market price.25 The net
benefits test serves this unenviable role.
21 Testimony of Roy J. Shanker, Ph.D, PJM Power Providers Group, Sept. 13,
2010 Tr. at 60, "If the Commission adopts the appropriate non-discriminatory pricing for
Demand Response, and payment of LMP minus the retail rate in the context of customer
that face a fixed retail rate, then there is no need for a Net Benefits test."
22 Id., Tr. at 61.
23 EPSA May 13, 2010 Comments at 23. See also May 13, 2010 Comments of
APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5;
PJM at 6; PSEG at 5; and Potomac Economics at 6-8.
24 Courts have stated that to be “just and reasonable,” rates must fall within a
“zone of reasonableness” where they are neither “less than compensatory” to producers
nor “excessive” to consumers. Farmers Union Central Exchange v. FERC, 734 F.2d
1486 (D.C. Cir. 1984), cert denied, 469 U.S. 1034 (1984). See also EPSA May 13, 2010
Comments at 19; and ISO-NE at 26-28.
25 Testimony of Ohio Commissioner Paul Centolella, Sept. 13, 2010 Tr. at
141, “The Net Benefits test reflects a recognition that paying full LMP may over-
compensate Demand Response and increase cost to customers.”
Docket No. RM10-17-000 - 8 -
Relationship to State Retail Regulation
The Rule recognizes that the demand resource will retain the retail rate (“G”) as
part of the provider’s total compensation, but declines to account for this savings citing
“practical difficulties” for state commissions, RTOs and ISOs.26 While the authority
over retail rates is properly within the jurisdiction of the state commissions, under the
LMP-G equation, the RTO/ISO merely subtracts the retail rate; it does not interfere with
the retail rate in any way.27 Although the Rule refers to the New York Commission’s
position that subtracting the retail rate would be an “administrative burden” or cr
“undue confusion”28, other state commissions disagree and contend that the retail rate
be deducted without any concern about impacting the states’ retail jurisdiction.29
26 Rule at P 63. The RTOs and ISOs uniformly state that compensation which
ignores the retail rate will yield uneconomic outcomes and overcompensate the demand
resource. Moreover, none of the RTOs or ISOs claimed it would be difficult to subtract
the retail rate from the LMP payment. See May 13, 2010 Comments of CAISO at 5-6;
ISO-NE at 17-26; Midwest ISO at 6-11; NYISO at 12-16; and PJM at 5-16.
27 Testimony of Joel Newton, New England Power Generators Ass’n, Sept. 13,
2010 Tr. at 75; “The Commission is getting into a real close area with retail ratemaking
as we go through this entire process. For the Commission then to say ‘ignore the LSE
payment’ which is the realm of state commissions, it’s almost as you’re just hoping that
the state commissions will go out and fix it. The state commissions can do that…[b]ut
the proper thing to do now is to get the price right at the outset.” See also Testimony of
Ohio Commissioner Paul Centolella, Sept. 13, 2010 Tr. at 197; “[FERC is] putting the
state in the position where if we were to try to get back to an efficient level of incentives,
we would be having to in effect issue a charge for energy that was not consumed. We
would be doing what would be perceived as a take-back by that customer. And that
would put us in a very difficult position.”
28 Rule at P 28. Significantly, the New York Commission “acknowledges the
overstated price signal inherent in an LMP-based formula for DR compensation….”
“Although we understand that an LMP demand response compensation formula may
result in uneconomic demand response decisions in the markets (i.e., a price signal that
exceeds marginal cost), it also creates an incentive to participate in DR programs….”
New York Commission May 13, 2010 Comments at 5-6 (emphasis added).
29 Illinois Commission May 13, 2010 Comments at 13, “[I]f tariffs are well
designed, controversy over the jurisdictional issue can be avoided. Requiring an ex ante
approval of the retail rate to be subtracted from the LMP at the time demand response
resources are utilized …accomplishes this design.” See also Indiana Commission
Docket No. RM10-17-000 - 9 -
Moreover, the Rule does not conclude that LMP-G would interfere with the retail
jurisdiction of the states, but goes as far as to acknowledge the subtraction of G is
“perhaps feasible.”30 The fact is that this calculation is quite feasible. Markets such as
the PJM Interconnection currently subtract the retail rate portion from the LMP payment
and there is no evidence that accounting for the retail rate by making the necessary
reduction is either burdensome or interferes with the retail jurisdiction of state
The Unintended Consequences of Paying Too Much
Today’s determination, unencumbered by “textbook economic analysis of the
markets subject to our jurisdiction” will undoubtedly have effects, both in the short-term
and the long-term.32 The intended consequence of providing additional compensation to
demand resources is that demand response participation will increase in the energy
markets. In turn, this additional demand response participation will have the effect of
lowering the market price. However, it is at this point where the unintended effects will
begin to appear.
With a reduced LMP, the price signal sent to customers will be that the cost of
power is cheaper so they may decide to use more power even though the real cost of
producing that power is now higher. Such a result turns the concept of scarcity pricing
on its head and results in an economically inefficient outcome. Conversely, customers
who are demand response providers now stand to receive more than the market price as
an incentive to curtail their consumption and will begin to make inefficient decisions
about using power.33 Such inefficiencies will result in customers experiencing a short-
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.”
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.
32 Rule at P 46.
33 Federal Trade Commission May 13, 2010 Comments at 6, “If customers have to
pay the retail price for power they use but pay nothing for power they resell, then they
will have incentives to resell power in situations in which it would be more beneficial for
Docket No. RM10-17-000 - 10 -
term benefit by way of a lower LMP, but will also impose long-term costs on the
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
The Commission’s recent progress in promoting competitive wholesale energy
markets has the potential to be undone as a result of this well-meaning, but misguided
Rule. I believe in the proven value of market solutions and therefore agree with the
majority’s statement that “while the level of compensation provided to each resource
affects its willingness and ability to participate in the market, ultimately the markets
themselves will determine the level of generation and demand response resources needed
society for them to consume it.” See also EPSA May 13, 2010 Comments at 23; APPA
at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New York Commission at 5; PJM at
6; PSEG at 5; and Potomac Economics at 6-8.
34 PJM’s Independent Market Monitor (a/k/a Monitoring Analytics, LLC) Oct. 16,
2009 Comments at 7-8 (Docket No. EL09-68), “Demand side resources are not
generation. In a well functioning market, demand-side resources avoid paying the market
price of energy when they choose not to consume. This allows customers to make
efficient decisions about using power. It also follows that a customer receiving more
than the market price as an incentive to curtail will make inefficient decisions about using
power, and that this inefficiency imposes a cost rather than providing a benefit to
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.”
Docket No. RM10-17-000 - 11 -
for purposes of balancing the electricity grid.”36 That’s precisely how markets
should work. Price signals will attract resources and new investment when prices are
high, and perhaps not so much when prices are low.37 If the playing field is level,
resources can compete to the best of their abilities and efficient, cost-effective market
outcomes will result.
As noted earlier, I would have preferred that we allow the regional markets to
continue to develop their own compensation proposals. However, I also recognize that
returning to a pre-NOPR era would be difficult now that the Commission has signaled a
new policy of standardized compensation. Accordingly, if I were to now support any
standardization of demand response compensation, it would be the LMP-G approach,
which in my opinion, is the only economically efficient outcome for the markets.
Ultimately, the Rule, by requiring demand resources to artificially suppress the
market price in order to receive incomparable compensation, will negatively impact the
long-term competitiveness of the organized wholesale energy markets.38 As such,
lacking sufficient rationale, I cannot support this Rule as it violates the Commission’s
statutory mandate to ensure supplies of electric energy at just, reasonable, and not unduly
discriminatory or preferential rates.
Philip D. Moeller
36 Rule at P 59.
37 PJM Interconnection’s experience with paying LMP-G for demand response in
its energy market provides an example of how market fundamentals properly influence
demand resource participation. PJM’s Independent Market Monitor recently reported
that “[p]articipation levels through calendar year 2009 and through the first three months
of 2010 were generally lower compared to prior years due to a number of factors,
including lower price levels, lower load levels, and improved measurement and
verification, but have showed strong growth through the summer period as price levels
and load levels have increased. Citing Monitoring Analytics, LLC, 2010 State of the
Market Report for PJM at 30 (March 10, 2011) (emphasis added).
38 Federal Power Act § 205(a), 16 U.S.C. § 824d (2006), “[A]ll rules and
regulations affecting or pertaining to such rates or charges shall be just and reasonable,
and any such rate or charge that is not just and reasonable is hereby declared to be