Demand Response Compensation in Organized Wholesale Energy Markets, 16658-16682 [2011-6490]
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Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations
DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM10–17–000; Order No. 745]
Demand Response Compensation in
Organized Wholesale Energy Markets
Federal Energy Regulatory
Commission, Energy.
ACTION: Final rule.
AGENCY:
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
SUMMARY:
Regional Transmission Organization
(RTO) or Independent System Operator
(ISO) has the capability to balance
supply and demand as an alternative to
a generation resource and when
dispatch of that demand response
resource is cost-effective as determined
by the net benefits test described in this
rule, that demand response resource
must be compensated for the service it
provides to the energy market at the
market price for energy, referred to as
the locational marginal price (LMP).
This approach for compensating
demand response resources helps to
ensure the competitiveness of organized
wholesale energy markets and remove
barriers to the participation of demand
response resources, thus ensuring just
and reasonable wholesale rates.
Effective Date: This Final Rule
will become effective on April 25, 2011.
Dates for compliance and other required
filings are provided in the Final Rule.
FOR FURTHER INFORMATION CONTACT:
David Hunger (Technical Information),
Office of Energy Policy and
Innovation, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
8148, david.hunger@ferc.gov;
Dennis Hough (Legal Information),
Office of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–8631,
dennis.hough@ferc.gov.
DATES:
SUPPLEMENTARY INFORMATION:
Table of Contents
(Issued March 15, 2011)
Paragraph
Nos.
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I. Introduction .........................................................................................................................................................................................
II. Background .........................................................................................................................................................................................
III. Procedural History ............................................................................................................................................................................
IV. Discussion .........................................................................................................................................................................................
A. Compensation Level ...................................................................................................................................................................
1. NOPR Proposal .....................................................................................................................................................................
2. Comments .............................................................................................................................................................................
(a) Capability of Demand Response and Generation Resources to Balance Energy Markets .......................................
(b) Appropriateness of a Net Benefits Test .....................................................................................................................
(c) Standardization or Regional Variations in Compensation ........................................................................................
3. Commission Determination .................................................................................................................................................
B. Implementation of a Net Benefits Test ......................................................................................................................................
1. Comments .............................................................................................................................................................................
2. Commission Determination .................................................................................................................................................
C. Measurement and Verification ...................................................................................................................................................
1. NOPR Proposal .....................................................................................................................................................................
2. Comments .............................................................................................................................................................................
3. Commission Determination .................................................................................................................................................
D. Cost Allocation ...........................................................................................................................................................................
1. NOPR Proposal .....................................................................................................................................................................
2. Comments .............................................................................................................................................................................
3. Commission Determination .................................................................................................................................................
E. Commission Jurisdiction ............................................................................................................................................................
1. Comments .............................................................................................................................................................................
2. Commission Determination .................................................................................................................................................
V. Information Collection Statement .....................................................................................................................................................
VI. Environmental Analysis ...................................................................................................................................................................
VII. Regulatory Flexibility Act ...............................................................................................................................................................
VIII. Document Availability ...................................................................................................................................................................
IX. Effective Date and Congressional Notification ...............................................................................................................................
Regulatory Text
Appendix 1—List of Commenters
Appendix 2—Dissenting Statement
Before Commissioners: Jon
Wellinghoff, Chairman; Marc Spitzer,
Philip D. Moeller, John R. Norris, and
Cheryl A. LaFleur.
I. Introduction
1. This Final Rule addresses
compensation for demand response in
Regional Transmission Organization
(RTO) and Independent System
Operator (ISO) organized wholesale
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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
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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).
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2. We conclude that when a demand
response 2 resource 3 participating in an
organized wholesale energy market 4
administered by an RTO or ISO has the
capability to balance supply and
demand as an alternative to a generation
resource and when dispatch of that
demand response resource is costeffective as determined by the net
benefits test described herein, that
demand response resource must be
compensated for the service it provides
to the energy market at the market price
for energy, referred to as the locational
marginal price (LMP).5 The Commission
finds that this approach to
compensation for demand response
resources is necessary to ensure that
rates are just and reasonable in the
organized wholesale energy markets.
Consistent with this finding, this Final
Rule adds section 35.28(g)(1)(v) to the
Commission’s regulations to establish a
specific compensation approach for
demand response resources
participating in the organized wholesale
energy markets administered by RTOs
and ISOs. The Commission is not
requiring the use of this compensation
approach when demand response
resources do not satisfy the capability
and cost-effectiveness conditions noted
above.6
3. This cost-effectiveness condition,
as determined by the net benefits test
2 Demand response means a reduction in the
consumption of electric energy by customers from
their expected consumption in response to an
increase in the price of electric energy or to
incentive payments designed to induce lower
consumption of electric energy. 18 CFR 35.28(b)(4)
(2010).
3 Demand response resource means a resource
capable of providing demand response. 18 CFR
35.28(b)(5).
4 The requirements of this final rule apply only
to a demand response resource participating in a
day-ahead or real-time energy market administered
by an RTO or ISO. Thus, this Final Rule does not
apply to compensation for demand response under
programs that RTOs and ISOs administer for
reliability or emergency conditions, such as, for
instance, Midwest ISO’s Emergency Demand
Response, NYISO’s Emergency Demand Response
Program, and PJM’s Emergency Load Response
Program. This Final Rule also does not apply to
compensation in ancillary services markets, which
the Commission has addressed elsewhere. See, e.g.,
Wholesale Competition in Regions with Organized
Electric Markets, Order No. 719, 73 FR 64100 (Oct.
28, 2008), FERC Stats. & Regs. ¶ 31,281 (2008)
(Order No. 719).
5 LMP refers to the price calculated by the ISO or
RTO at particular locations or electrical nodes or
zones within the ISO or RTO footprint and is used
as the market price to compensate generators. There
are variations in the way that RTOs and ISOs
calculate LMP; however, each method establishes
the marginal value of resources in that market.
Nothing in this Final Rule is intended to change
RTO and ISO methods for calculating LMP.
6 The Commission’s findings in this Final Rule do
not preclude the Commission from determining that
other approaches to compensation would be
acceptable when these conditions are not met.
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described herein, recognizes that,
depending on the change in LMP
relative to the size of the energy market,
dispatching demand response resources
may result in an increased cost per unit
($/MWh) to the remaining wholesale
load associated with the decreased
amount of load paying the bill. This is
the case because customers are billed for
energy based on the units, MWh, of
electricity consumed. We refer to this
potential result as the billing unit effect
of dispatching demand response. By
contrast, dispatching generation
resources does not produce this billing
unit effect because it does not result in
a decrease of load. To address this
billing unit effect, the Commission in
this Final Rule requires the use of the
net benefits test described herein to
ensure that the overall benefit of the
reduced LMP that results from
dispatching demand response resources
exceeds the cost of dispatching and
paying LMP to those resources. When
the net benefits test described herein is
satisfied and the demand response
resource clears in the RTO’s or ISO’s
economic dispatch, the demand
response resource is a cost-effective
alternative to generation resources for
balancing supply and demand.
4. To implement the net benefits test
described herein, we direct each RTO
and ISO to develop a mechanism as an
approximation to determine a price
level at which the dispatch of demand
response resources will be costeffective. The RTO or ISO should
determine, based on historical data as a
starting point and updated for changes
in relevant supply conditions such as
changes in fuel prices and generator
unit availability, the monthly threshold
price corresponding to the point along
the supply stack beyond which the
overall benefit from the reduced LMP
resulting from dispatching demand
response resources exceeds the cost of
dispatching and paying LMP to those
resources. This price level is to be
updated monthly, by each ISO or RTO,
as the historic data and relevant supply
conditions change.7
5. This Final Rule also sets forth a
method for allocating the costs of
demand response payments among all
customers who benefit from the lower
LMP resulting from the demand
response.
6. The tariff changes needed to
implement the compensation approach
required in this Final Rule, including
the net benefits test, measurement and
7 In its compliance filing an RTO or ISO may
attempt to show, in whole or in part, how its
proposed or existing practices are consistent with
or superior to the requirements of this Final Rule.
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verification explanation and proposed
changes, and the cost allocation
mechanism must be made on or before
July 22, 2011. All tariff changes directed
herein should be submitted as
compliance filings pursuant to this
Final Rule, not pursuant to section 205
of the Federal Power Act (FPA).8
Accordingly, each RTO’s or ISO’s
compliance filing to this Final Rule will
become effective prospectively from the
date of the Commission order
addressing that filing, and not within 60
days of submission.
7. In addition, we believe that
integrating a determination of the costeffectiveness of demand response
resources into the dispatch of the ISOs
and RTOs may be more precise than the
monthly price threshold and, therefore,
provide the greatest opportunity for load
to benefit from participation of demand
response in the organized wholesale
energy market administered by an RTO
or ISO. However, we acknowledge the
position of several of the RTOs and ISOs
that modification of their dispatch
algorithms to incorporate the costs
related to demand response may be
difficult in the near term. In light of
those concerns, we require each RTO
and ISO to undertake a study examining
the requirements for and impacts of
implementing a dynamic approach
which incorporates the billing unit
effect in the dispatch algorithm to
determine when paying demand
response resources the LMP results in
net benefits to customers in both the
day-ahead and real-time energy markets.
The Commission directs each RTO and
ISO to file the results of this study with
the Commission on or before September
21, 2012.9
II. Background
8. Effective wholesale competition
protects customers by, among other
things, providing more supply options,
encouraging new entry and innovation,
and spurring deployment of new
technologies.10 Improving the
competitiveness of organized wholesale
energy markets is therefore integral to
the Commission fulfilling its statutory
mandate under the FPA to ensure
8 16
U.S.C. 824d (2006).
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. DC 205 (DC Cir. 2001).
9 We
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supplies of electric energy at just,
reasonable, and not unduly
discriminatory or preferential rates.11
9. As the Commission recognized in
Order No. 719, active participation by
customers in the form of demand
response in organized wholesale energy
markets helps to increase competition in
those markets.12 Demand response,
whereby customers reduce electricity
consumption from normal usage levels
in response to price signals, can
generally occur in two ways:
(1) Customers reduce demand by
responding to retail rates that are based
on wholesale prices (sometimes called
‘‘price-responsive demand’’); and
(2) customers provide demand response
that acts as a resource in organized
wholesale energy markets to balance
supply and demand. While a number of
States and utilities are pursuing retaillevel price-responsive demand
initiatives based on dynamic and timedifferentiated retail prices and utility
investments in demand response
enabling technologies, these are State
efforts, and, thus, are not the subject of
this proceeding. Our focus here is on
customers or aggregators of retail
customers providing, through bids or
self-schedules, demand response that
acts as a resource in organized
wholesale energy markets.
10. As the Commission stated in
Order No. 719,13 and emphasized in the
NOPR,14 there are several ways in
which demand response in organized
wholesale energy markets can help
improve the functioning and
competitiveness of those markets. First,
when bid directly into the wholesale
market, demand response can facilitate
RTOs and ISOs in balancing supply and
demand, and thereby, help produce just
and reasonable energy prices.15 This is
because customers who choose to
respond will signal to the RTO or ISO
and energy market their willingness to
reduce demand on the grid which may
result in reduced dispatch of higher11 16 U.S.C. 824d (2006); Order No. 719, FERC
Stats. & Regs. ¶ 31,281 at P 1.
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.
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 https://www.isorto.org/atf/cf/
%7B5B4E85C6-7EAC-40A0-8DC3003829518EBD%7D/IRC_DR_Report_101607.pdf.
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priced resources to satisfy load.16
Second, demand response can mitigate
generator market power.17 This is
because the more demand response that
sees and responds to higher market
prices, the greater the competition, and
the more downward pressure it places
on generator bidding strategies by
increasing the risk to a supplier that it
will not be dispatched if it bids a price
that is too high.18 Third, demand
response has the potential to support
system reliability and address resource
adequacy 19 and resource management
challenges surrounding the unexpected
loss of generation. This is because
demand response resources can provide
quick balancing of the electricity grid.20
11. Congress has recognized the
importance of demand response by
enacting national policy requiring its
facilitation.21 Consistent with that
policy, the Commission has undertaken
several reforms to support competitive
wholesale energy markets by removing
barriers to participation of demand
response resources. For example, in
Order No. 890, the Commission
modified the pro forma Open Access
Transmission Tariff to allow nongeneration resources, including demand
16 Id. (‘‘Demand response tends to flatten an area’s
load profile, which in turn may reduce the need to
construct and use more costly resources during
periods of high demand; the overall effect is to
lower the average cost of producing energy.’’).
17 See Comments of NYISO’s Independent Market
Monitor filed in Docket No. ER09–1142–000, May
15, 2009 (Demand response ‘‘contributes to
reliability in the short-term, resource adequacy in
the long-term, reduces price volatility and other
market costs, and mitigates supplier market
power.’’).
18 Id.
19 See ISO–RTO Council Report, Harnessing the
Power of Demand How RTOs and ISOs Are
Integrating Demand Response into Wholesale
Electricity Markets at 4, found at https://
www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A08DC3-003829518EBD%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, Public Law 109–
58, § 1252(f), 119 Stat. 594, 965 (2005) (‘‘It is the
policy of the United States that * * * unnecessary
barriers to demand response participation in
energy, capacity, and ancillary service markets shall
be eliminated.’’).
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response resources, to be used in the
provision of certain ancillary services
where appropriate on a comparable
basis to service provided by generation
resources.22 Order No. 890–A further
required transmission providers to
develop transmission planning
processes that treat all resources,
including demand response, on a
comparable basis.23
12. In Order No. 719, the Commission
required RTOs and ISOs to, among other
things, accept bids from demand
response resources in their markets for
certain ancillary services on a basis
comparable to other resources.24 The
Commission also required each RTO
and ISO ‘‘to reform or demonstrate the
adequacy of its existing market rules to
ensure that the market price for energy
reflects the value of energy during an
operating reserve shortage,’’ 25 for
purposes of encouraging existing
generation and demand resources to
continue to be relied upon during an
operating reserve shortage, and
encouraging entry of new generation
and demand resources.26
13. Additionally, in recent years
several RTOs and ISOs have instituted
various types of demand response
programs. While some of these programs
are administered for reliability and
emergency conditions, other programs
allow wholesale customers, qualifying
large retail customers, and aggregators of
retail customers to participate directly
in the day-ahead and real-time energy
markets, certain ancillary service
markets and capacity markets.27
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.
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
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14. To date, the Commission has
allowed each RTO and ISO to develop
its own compensation methodologies for
demand response resources
participating in its day-ahead and realtime energy markets. As a result, the
levels of compensation for demand
response vary significantly among RTOs
and ISOs.28 For example, PJM
Interconnection, L.L.C. (PJM) pays the
LMP minus the generation and
transmission portions of the retail rate.29
ISO New England Inc. (ISO–NE) and
New York Independent System
Operator, Inc. (NYISO) pay LMP when
prices exceed a threshold level, with the
levels differing between the RTOs.30
The Midwest Independent Transmission
System Operator, Inc.’s (Midwest ISO)
demand response programs 31 pay LMP
for demand response resources in the
day-ahead and real-time energy
markets.32 The California Independent
System Operator Corporation (CAISO)
pays LMP at pricing nodes, or sub-load
aggregation points (Sub-LAP) in its
Proxy Demand Resource program that
allows qualifying resources to provide
day-ahead and real-time energy.33
¶ 61,227 (2002); California Independent System
Operator Corp., 132 FERC ¶ 61,045 (2010).
28 See New England, Inc., Docket No. ER09–1051–
000; ISO New England, Inc., Docket No. ER08–830–
000; Midwest Indep. Transmission Sys. Operator,
Inc., Docket No. ER09–1049–000.
29 See sections 3.3A.4 and 3.3A.5 (Market
Settlements in the Real-Time and Day-Ahead
Energy Markets) of the Appendix to Attachment K
of the PJM Tariff.
30 For example, under ISO–NE’s Real-Time Price
Response Program, the minimum bid is $100/MWh
and a demand response resource is paid the higher
of LMP or $100/MWh. For the Day-Ahead Load
Response Program, the minimum offer level is
calculated on a monthly basis and is the Forward
Reserve Fuel Index ($/MMBtu) multiplied by an
effective heat rate of 11.37 MMBtu/MWh. The
maximum offer level is $1,000/MWh. See sections
III.E.2.1 and III.E.3.2 of Appendix E of the ISO New
England Transmission, Markets and Services Tariff.
NYISO implements a day-ahead demand response
program by which resources bid into the market at
a minimum of $75/MWh and can get paid the LMP.
See section 4.2.2.9 (‘‘Day-Ahead Bids from Demand
Reduction Providers to Supply Energy from
Demand Reductions’’) of NYISO’s Market Services
Tariff.
31 Midwest ISO FERC Electric Tariff characterizes
Demand Response Resources (DRR) as either DRRType I or DRR-Type II. DRR-Type I are capable of
supplying a specific quantity of energy or
contingency reserve through physical load
interruption. DRR-Type II are capable of supplying
energy and/or operating reserves over a
dispatchable range. See sections 39.2.5A and 40.2.5
of the Tariff.
32 See Charges and Payments for Purchases and
Sales for Demand Response Resources. Midwest
ISO FERC Electric Tariff, section 39.3.2C.
33 See section 11.2.1.1 IFM Payments for Supply
of Energy, CAISO FERC Electric Tariff. CAISO notes
that for a Proxy Demand Resource that is made up
of aggregated loads, the Resource is paid the
weighted average of the LMPs of each pricing node
where the underlying aggregate loads reside. See
CAISO, 132 FERC ¶ 61,045, at P 26 n.14 (2010).
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CAISO also provides for demand
response resources to participate in its
Participating Load program, which
enables certain resources to provide
curtailable demand in the CAISO
market. CAISO pays nodal real-time
LMP for its Participating Load program.
The Southwest Power Pool, Inc. (SPP)
has filed revisions to its tariff to
facilitate demand response in the
Energy Imbalance Service Market.34
III. Procedural History
15. As noted above, the Commission
issued the NOPR in this proceeding on
March 18, 2010.35 The NOPR proposed
to require RTOs and ISOs to pay the
LMP in all hours for demand reductions
made in response to price signals. The
Commission sought comments on the
compensation proposal and, in
particular, on the comparability of
generation and demand response
resources; alternative approaches to
compensating demand response in
organized wholesale energy markets;
whether payment of LMP should apply
in all hours, and, if not, any criteria that
should be used for establishing hours
when LMP should apply; and whether
to allow for regional variations
concerning approaches to demand
response compensation.36
16. After receiving the first round of
comments, the Commission issued a
Supplemental Notice of Proposed
Rulemaking and Notice of Technical
Conference (Supplemental NOPR) in
this proceeding on August 2, 2010.37
The Supplemental NOPR sought
additional comment on: Whether the
Commission should adopt a net benefits
test for determining when to
compensate demand response
providers, and, if so, what, if any,
requirements should apply to the
methods for determining net benefits;
and what, if any, requirements should
34 The Commission has directed SPP to report on
ways it can incorporate demand response into its
imbalance market. Southwest Power Pool, Inc., 128
FERC ¶ 61,085 (2009). As of September 1, 2010,
SPP has submitted seven informational status
reports regarding its efforts to address issues related
to demand response resources. In orders addressing
SPP’s compliance with Order No. 719, the
Commission also directed SPP to make another
compliance filing addressing demand response
participation in its organized markets. Southwest
Power Pool, Inc., 129 FERC ¶ 61,163, at P 51 (2009).
On May 19, 2010, SPP submitted revisions to its
Open Access Transmission Tariff in Docket Nos.
ER09–1050–004 and ER09–748–002 to comply with
the Commission’s requirements established in
Order Nos. 719 and 719–A. These filings are
pending before the Commission.
35 NOPR, FERC Stats. & Regs. ¶ 32,656.
36 See Appendix for a list of commenters.
37 Supplemental Notice of Proposed Rulemaking
and Notice of Technical Conference, 75 FR 47499
(Aug. 6, 2010), 132 FERC ¶ 61,094 (2010)
(Supplemental NOPR).
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apply to how the costs of demand
response are allocated. The Commission
further directed Staff to hold a technical
conference focused on these two issues,
which occurred on September 13,
2010.38
IV. Discussion
17. Based upon the record in this
proceeding, the Commission herein
requires greater uniformity in
compensating demand response
resources participating in organized
wholesale energy markets. This Final
Rule also addresses the allocation of
costs resulting from the commitment of
demand response, directing that such
costs be allocated among those
customers who benefit from the lower
LMP resulting from the demand
response.
A. Compensation Level
1. NOPR Proposal
18. The NOPR proposed to require
RTOs and ISOs to pay the LMP in all
hours for demand reductions made in
response to price signals. The NOPR
sought to provide comparable
compensation to generation and
demand response providers, based on
the premise that both resources provide
a comparable service to RTOs and ISOs
for purposes of balancing supply and
demand and maintaining a reliable
electricity grid.39 Also as stated in the
NOPR, the proposed compensation level
was designed to allow more demand
response resources to cover their
investment costs in demand responserelated technology (such as advanced
metering) and thereby facilitate their
ability to participate in organized
wholesale energy markets.40 The
Commission sought comments on the
compensation proposal and, in
particular, on the comparability of
generation and demand response
resources; alternative approaches to
compensating demand response in
organized wholesale energy markets;
whether payment of LMP should apply
in all hours, and, if not, any criteria that
should be used for establishing hours
when LMP should apply; and whether
to allow for regional variations
concerning approaches to demand
response compensation.
19. In the Supplemental NOPR, the
Commission sought additional
comments and directed staff to hold a
technical conference regarding various
net benefits tests. In particular, the
Commission sought comment on:
38 See Notice of Technical Conference (Aug. 27,
2010).
39 NOPR, FERC Stats. & Regs. ¶ 32,656 at P 15.
40 Id. at P 16.
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whether the Commission should adopt
a net benefits test applicable in all or
only some hours and what the criteria
of any such test would be; how to define
net benefits; what costs demand
response providers and load serving
entities incur and whether they should
be included in a net benefits test;
whether any net benefits methodology
adopted should be the same for all RTOs
and ISOs; proposed methodologies for
implementing a net benefits test and the
advantages and limitations of any
proposed methodologies.41 The
September 13, 2010 Technical
Conference included an eleven-member
panel discussion of net benefits tests
representing a wide range of interests
and viewpoints.42 The Commission
subsequently received additional
written comments addressing these
issues.
Indeed, some commenters believe that,
from a physical standpoint, demand
response can provide superior services
to generation, such as providing a quick
response in meeting system
requirements and service without
having to construct major new
facilities.45 Occidental asserts that the
fungibility of demand response and
generation output creates greater
operational flexibility that, in turn,
offers RTOs and ISOs multiple options
to solve system issues both in energy
and ancillary service markets, and that
the fungible nature of demand response
and generation supports comparable
compensation for each as proposed in
the NOPR.46
21. Viridity states that attempts to
distinguish the physical characteristics
of generation and demand response
ignore bid-based security-constrained
economic dispatch as the foundation for
LMP and are based on the assumption
that the value of load management on
the grid is limited to periods when the
system is stressed, i.e., traditional
‘‘super peak shaving.’’ Viridity states
that, while these arguments might have
been valid 15 years ago, today
competitive markets can offer
proactively-managed load control and
comparable and non-discriminatory
treatment of load-based energy
resources. Therefore, Viridity asserts
that all resources should be paid LMP
if the grid operator accepts their bid to
achieve grid balance.47
22. At the same time, other
commenters argue that generation and
demand response are not physically
equivalent, pointing out that demand
response reduces consumption, whereas
generators serve consumption.48 They
argue that a MW reduction in demand
does not turn on the lights.49 EPSA adds
that a load reduction does not provide
electrons to any other load and, instead,
allows the marginal electron to serve a
different customer.50 Some commenters
assert that a power system can function
solely and reliably on generating plants
and without any reliance on demand
response, while the system cannot rely
exclusively on demand response
because demand response by itself
cannot keep the lights on. Ultimately,
some commenters point out, megawatts
produced by generators need to be
placed on the system in order for power
to flow.51 Battelle additionally argues
that a reduction in consumption is not
exactly the same as an increase in
41 Supplemental NOPR, 132 FERC ¶ 61,094 at
P 8–9.
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.
44 DR Supporters August 30, 2010 Reply
Comments (Kahn Affidavit at 2 (footnote omitted)).
45 Verso May 13, 2010 Comments at 3–4; Alcoa
May 13, 2010 Comments at 9.
46 Occidental May 13, 2010 Comments at 11.
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.
2. Comments
(a) Capability of Demand Response and
Generation Resources To Balance
Energy Markets
20. Various commenters address the
comparability of demand response and
generation resources for purposes of
compensation in the organized
wholesale energy markets. To begin,
numerous commenters address the
physical or functional comparability of
demand response and generation,
agreeing that an increment of generation
is comparable to a decrement of load for
purposes of balancing supply and
demand in the day-ahead and real-time
energy markets.43 Equating generation
and demand response resources, Dr.
Alfred E. Kahn states:
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[Demand response] is in all essential
respects economically equivalent to supply
response * * * [so] economic efficiency
requires * * * that it should be rewarded
with the same LMP that clears the market.
Since [demand response] is actually—and
not merely metaphorically—equivalent to
supply response, economic efficiency
requires that it be regarded and rewarded,
equivalently, as a resource proffered to
system operators, and be treated equivalently
to generation in competitive power markets.
That is, all resources—energy saved
equivalently to energy supplied—* * *
should receive the same market-clearing LMP
in remuneration.44
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production, because elastic demand
often comes with attendant future
consequences, such as rebound, by
virtue of substitution in time.52
23. Some commenters who argue that
the physical characteristics of demand
response are not comparable to
generation frame their arguments in
terms of the ability of the system
operator to call on demand response
and generation resources to provide
balancing energy. They argue that
generation resources provide superior
service to demand response providers,
positing that demand response is not
intended for long periods of balancing
needs,53 and that, moreover, contracts
with demand response providers limit
the number of hours and times a
customer may be called upon to curtail.
For example, ODEC asserts that the
degree of physical comparability
depends on the extent to which demand
response resources can be dispatched
similar to a generator.54 Calpine adds
that traditional generators provide
system support features that demand
response cannot, such as ancillary
services including governor response or
reactive power voltage support, which
are necessary for reliable operation of
the electric system.55
24. Numerous commenters also
address the comparability of demand
response and generation in economic
terms. For example, EEI states that, in
finance terms, the demand response
product is, unlike generation,
essentially an unexercised call option
on spot market energy, and the value of
that option is well-established in
finance theory as the value of the
resource (LMP) minus the ‘‘strike price,’’
which EEI contends in this case is the
retail tariff rate.56 EEI and like-minded
commenters support, therefore,
alternative compensation for demand
response to equal LMP minus the
generation (or G) component of the
retail rate.57 They posit that payment of
52 Battelle
May 13, 2010 Comments at 3.
May 13, 2010 Comments at 7–8.
54 ODEC May 13, 2010 Comments at 12.
55 Calpine May 13, 2010 Comments at 4–5.
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
53 AEP
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LMP without an offset for some portion
of the retail rate does not send the
proper economic signal to providers of
demand response, because it fails to
take into account the retail rate savings
associated with demand response, and
thereby overcompensates the demand
response provider. As described by Dr.
William W. Hogan on behalf of EPSA,
this is sometimes called a doublepayment for demand reductions,
because demand response providers
would ‘‘receive’’ both the cost savings
from not consuming an increment of
electricity at a particular price, plus an
LMP payment for not consuming that
same increment of electricity.58 Viewing
LMP as a double-payment, these
commenters argue that paying LMP will
result in more demand response than is
economically efficient.59 For example,
Dr. Hogan states that paying LMP might
motivate a company to shut down even
though the benefits of consuming
electricity outweigh the cost at LMP.60
Indeed, P3 argues that compensation in
excess of LMP–G is unjust and
unreasonable, because such a payment
level imposes costs on customers that
are not commensurate with benefits
received.61
25. ISO–NE argues that paying full
LMP to demand response providers
without taking into account the bill
savings produced by demand response
provides a significant financial
incentive to dispatch demand response
with marginal costs exceeding LMPs. By
dispatching higher-cost demand
response, ISO–NE asserts, lower-cost
generation resources are displaced.62 At
the same time, ISO–NE argues,
generation is not dispatched and paid
for only when the generation reduces
ISO RTO Council; ICC; IPPNY; Indicated New York
TOs; IPA; ISO–NE; Midwest TDUs; Mirant;
Midwest ISO TOs; NEPGA; NYISO; ODEC; OMS;
PJM; PJM IMM; P3; Potomac Economics; PG&E;
Ohio Commission; Robert L. Borlick; Roy Shanker;
and RRI Energy.
58 See Attachment to Answer of EPSA, Providing
Incentives for Efficient Demand Response, Dr.
William W. Hogan, Oct. 29, 2009, submitted in
Docket No. EL09–68–000.
59 EPSA May 13, 2010 Comments at 23. See also
May 13, 2010 Comments of APPA at 13; FTC at 9;
Midwest TDUs at 14; Mirant at 2; New York
Commission at 5; PJM at 6; PSEG at 5; and Potomac
Economics at 6–8.
60 Attachment to Answer of EPSA, Providing
Incentives for Efficient Demand Response, Dr.
William W. Hogan, Oct. 29, 2009, submitted in
Docket No. EL09–68–000. In Dr. Hogan’s view,
supply should produce when the price of electricity
exceeds its cost of production and demand should
decline to consume when the costs in terms of
convenience of delaying use are less than the price
of electricity.
61 P3 June 14, 2010 Comments at 2, 7–8.
62 ISO–NE May 13, 2010 Comments at 3–4.
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LMP—generation is dispatched and
paid for when it is cost-effective.63
26. Dr. Hogan further disputes
arguments equating a MW of energy
supplied to a MW of energy saved on
economic grounds. Dr. Hogan draws a
distinction between reselling something
that one has purchased, and selling
something that one would have
purchased without actually purchasing
it. Dr. Hogan argues that from the
perspective of economic efficiency and
welfare maximization, the aggregate
effect of demand response is a wash
producing no economic net benefit. Dr.
Hogan asserts that Commission policy
citing the benefits of price reduction in
support of demand response
compensation would amount to no less
than an application of regulatory
authority to enforce a buyers’ cartel. He
states that the Commission has been
vigilant and aggressive in preventing
buyers and sellers from engaging in
market manipulation to influence
prices, and it would be fundamentally
inconsistent for the Commission to
design demand response compensation
policies that coordinate and enforce
such price manipulation.
27. Dr. Hogan argues that the ideal
and economically efficient solution
regarding demand response
compensation is to implement retail
real-time pricing at the LMP, thereby
eliminating the need for demand
response programs. Realizing that this is
unattainable at the present time, Dr.
Hogan goes on to propose a next-best
solution, which he believes is to pay
demand response compensation in the
amount of LMP–G, or some amount that
simulates explicit contract demand
response (such as ‘‘buy-the-baseline’’
approach discussed below). These
options, he argues, more than paying
LMP, better support notions of
comparability between demand
response resources and generation.64
28. The New York Commission,
however, argues that requiring payment
of LMP–G would result in an
administrative burden of tracking retail
rates for the multiple utilities, ESCOs
and power authorities and create undue
confusion for retail customers and
administrative difficulties for State
commissions and ISOs and RTOs.65
29. Consistent with Dr. Hogan’s
arguments, some commenters assert that
demand response providers should
actually own or pay for electricity prior
to, what commenters characterize as, an
63 Id.
at 28.
Affidavit, ISO RTO Council May 13,
2010 Comments at 5.
65 New York Commission May 13, 2010
Comments at 8.
64 Hogan
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effective reselling of the electricity back
to the market in the form of demand
response. For example, these
commenters suggest that the demand
response provider purchase the power
in the day-ahead market and resell it in
the real-time markets.66 EPSA argues
that there must be some purchase
requirement or representative offset to
allow a demand response provider to
‘‘sell’’ a commodity that it owns to the
ISO or RTO.67 EPSA argues that such a
requirement would send an efficient
price signal, reduce incentives for
gaming the system, and help address
difficulties with measurement and
verification of a demand reduction.
EPSA highlights an ISO–NE IMM
recommendation that, if the
Commission permits LMP payment, it
should also adopt a ‘‘buy-the-baseline’’
approach requiring demand response
resources to purchase an expected
amount of energy consumption in the
day-ahead energy market and
subsequently sell any demand reduction
from that level in the real-time market.68
30. Viridity, on the other hand, argues
that forcing customers to buy and then
resell electricity will lead to too little
demand response and that adopting a
‘‘buy-the-baseline’’ approach would
constitute an inappropriate exercise of
Commission authority to effectively
force parties into contracts. Viridity and
DR Supporters state that any
characterization of demand response as
a purchase and then resale of energy is
erroneous 69 and based on the flawed
assumption that demand response
resources are reselling energy. They
state that the description of demand
response as a reselling of energy has
been correctly rejected by the
Commission in EnergyConnect, where
the Commission stated that it was
establishing a policy of treating demand
response as a service rather than a
purchase and sale of electric energy.70
31. DR Supporters further argues that,
despite claims to the contrary, paying
full LMP to demand response providers
does not constitute a subsidy for
demand response any more than the
remunerations of generators for the
power that they sell. As Dr. Kahn states:
Does this plan involve double
compensation, as [Dr.] Hogan asserts, at the
expense of power generators—of successful
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.
70 DR Supporters Aug. 30, 2010 Reply Comments
at 10 (citing EnergyConnect, Inc., 130 FERC
¶ 61,031 at P 30–31 (2010)).
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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
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32. Viridity further disputes Dr.
Hogan’s argument that payment of LMP
for demand response will distort an
otherwise optimal market. Viridity
posits that such arguments ignore
dislocations in the wholesale power
markets, the existence of market power
that must be mitigated, imperfect
information available to customers,
barriers to entry and uneconomic
resources dispatched to fulfill must-run
requirements.72 Viridity further states
that Dr. Hogan’s arguments fail to
acknowledge the limits of the
Commission’s jurisdiction and
widespread dislocations and distortions
in virtually all economic aspects of
relevant energy markets (including
fuels, facilities, pricing, environmental
attributes, information and
participation) and fail to account for any
market benefits of demand response.73
Finally, Viridity argues that Dr. Hogan’s
arguments fail to reflect the many
complex interactions between price,
equipment operational requirements,
and customer processes, which point to
a complex demand response decision.74
33. In addition to physical and
economic comparability, some
commenters contrast the environmental
effects of generation and demand
response resources. EDF notes that
current market prices fail to internalize
environmental externalities—including
toxic air pollution, greenhouse gas
pollution, and land and water use
impacts—and other social costs. EDF
asserts that the social impact of these
environmental externalities is especially
acute at peak times, positing that
generation sources used for marginal
supply at such times (‘‘peaker plants’’)
are among the oldest, dirtiest, and most
inefficient in the fleet.75 The American
71 DR Supporters Aug. 30, 2010 Reply Comments,
Kahn Affidavit at 10.
72 Viridity June 18, 2010 Comments at 13
(‘‘Importantly, Dr. Hogan (and others) in opposing
the proposed rulemaking fails to acknowledge the
limits of the Commission’s jurisdiction, and wide
spread dislocations and distortions in virtually all
economic aspects of relevant energy markets
(including fuels, facilities, pricing, environmental
attributes, information and participation).’’
(Affidavit of John C. Tysseling, PhD)).
73 Viridity Reply Comments at 13.
74 Viridity Reply Comments at 14.
75 EDF Oct. 13, 2010 Comments at 2.
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Clean Skies Foundation contends that
fossil-fuel generators are typically
mispriced because wholesale prices
radically understate the full
environmental and health costs
associated with such generators.76
Indeed, some commenters, such as
Alcoa, argue that because demand
response does not result in the external
costs associated with generation (e.g.,
greenhouse gas emissions), instead
resulting in less greenhouse gas
emissions than generation, it should be
compensated at more than LMP.77
34. Taking the opposite view
concerning environmental externalities,
EPSA states that paying LMP for
demand response will merely encourage
load to switch to off-grid power (or
behind-the-meter generation), while still
being compensated, and that such
behind-the-meter generation produces
more greenhouse gases and other air
emissions than electricity from the
regional energy market.78
35. Some commenters discuss
comparability of generation and demand
response in terms of the market rules
that apply to each resource, arguing that
both resources should be comparably
compensated only if the same rules for
participation apply to both resources,
and both resources are held to the same
standards for dispatchability.79 They
also argue that similar penalty
structures should apply to demand
response resources as apply to
generation, and that demand response
participation must be subject to market
monitoring.80 Calpine adds that to the
extent demand response resources are
used and treated on par with generators
for purposes of compensation, they
should be subject to the same
performance testing, penalties, and
other similar requirements as
generators.81
36. Some commenters address the
comparability of demand response
providers and generators in terms of
maintaining system reliability. PIO
argues that reductions in consumption
provide additional reliability.82
According to the NEMA, North
American Electric Reliability
Corporation (NERC) standards suggest
that, from a reliability perspective, load
reductions are equivalent or even
superior to generator increases for
balancing purposes. For example, while
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.
80 Id.
81 Calpine May 13, 2010 Comments at 5.
82 PIO May 13, 2010 Comments at 8.
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specific to the Western Interconnection,
BAL–002–WECC–1 lists interruptible
load as comparable to generation
deployable within 10 minutes.83 EPSA
maintains that demand response
resources are not full substitutes based
on the nature of their participation and
the rules applicable to each resource in
the energy markets, pointing out, for
example, that, unlike generators,
demand response providers are not
subject to regional and NERC mandatory
reliability standards.84
37. On the other hand, PSEG argues
that a MW of demand response does not
make the same contribution towards
system reliability as a MW of
generation, because demand response
committed as a capacity resource is only
required to perform for a limited
number of times over the peak period.
PSEG refers to PJM’s capacity market,
for example, in which demand response
only has to perform 10 times during the
entire summer peak period, and then
only for six hours per response. In
contrast, PSEG argues, generators are
available for dispatch, 24 hours a day,
365 days per year, except for a small
percentage of time for forced and
planned outages. PSEG further asserts
that additional reliability standards—
applicable to generating facilities, but
not to demand response—increase the
relative reliability value of generating
resources to the system.85
(b) Appropriateness of a Net Benefits
Test
38. Some commenters assert that
demand response providers should be
paid LMP only when the benefits of
demand response compensation
outweigh the energy market costs to
consumers of paying demand response
resources, i.e., when cost-effective, as
determined by some type of net benefits
or cost-effectiveness test.86 They
maintain that paying LMP for demand
response in all hours, including off-peak
hours, might not result in net benefits to
customers, because the payments might
be substantially more than the savings
created by reducing the clearing price at
that time.87 According to these
commenters, net benefits are most likely
to be positive and greatest when the
supply curve is steepest, which
typically occurs in highest-cost, peak
83 NEMA
May 13, 2010 Comments at 2.
May 13, 2010 Comments at 7.
85 PSEG May 13, 2010 Comments at 8.
86 See generally May 13, 2010 Comments of
NYSCPB; NECA; Capital Power; NECPUC;
Maryland Commission; New York Commission;
NSTAR; National Grid; NE Public Systems.
87 Capital Power May 13, 2010 Comments at 5; P3
May 13, 2010 Comments at 5.
84 EPSA
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hours.88 They argue that experience to
date has shown positive benefits from
demand response as a peak system
resource, and that, during peak periods,
the positive economics of demand
response are generally very clear and a
cost-benefit analysis may not be
needed.89 Furthermore, some
commenters suggest that limiting the
hours in which demand response
resources are paid LMP could help
establish better baselines for measuring
whether a demand response provider
has, in fact, responded.90
39. Some commenters who oppose
paying LMP in all hours for demand
response also suggest various
approaches, including net benefits tests,
for determining when LMP should
apply. The stated purpose of any of
these tests would be to determine the
point at which the incremental payment
for demand response equals the
incremental benefit of the reduction in
load; payment of LMP would apply only
up to that point.91
40. Opposition to use of a net benefits
test comes from several directions.
Numerous commenters, primarily
industrial consumers and some
consumer advocates, argue that a net
benefits test will reduce competition,92
have a ‘‘chilling effect’’ on the
development of demand response,93 and
be costly and complex to implement.94
Some commenters further state that no
net benefits test is needed because the
88 NECPUC May 13, 2010 Comments at 13; see
also Sept. 13, 2010 Tr. 13:6–19 (Mr. Keene);
Maryland Commission May 13, 2010 Comments at
4–5.
89 See, e.g., ACEEE Oct. 13, 2010 Comments 3–4.
See also National Grid May 13, 2010 Comments at
4–5; NSTAR Electric Company (NSTAR) May 14,
2010 Comments at 3; Maryland Commission May
13, 2010 Comments, submitting Analysis of Load
Payments and Expenditures under Different
Demand Response Compensation Schemes at 10–11
(discussing PJM analysis showing that paying
demand response providers LMP for all hours after
compensating LSEs for lost revenues would not
benefit customers in general but that positive
economic benefits results when demand response
providers receive LMP during at least the top 100
hours (the highest priced energy hours)).
90 See, e.g., CDWR May 13, 2010 Comments at 11;
National Grid May 13, 2010 Comments at 8;
ISO–NE May 13, 2010 Comments at 34; ACEEE Oct.
13, 2010 Comments 4. But see ISO–NE May 13,
2010 Comments at 32–33 (contending that no
baseline estimation methodology that relies upon
historical customer meter data can accurately and
reliably estimate an individual customer’s normal
energy usage pattern if that customer responds
frequently to price signals).
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.
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merit-order bid stack and market
clearing function in a wholesale market,
by definition, assures that the benefits to
the system of demand response exceed
the costs, and that the resource that
clears is the lowest cost resource;
otherwise, demand response would not
dispatch ahead of competing
alternatives.95
41. Another set of commenters argues
that a net benefits test is unnecessary
and inappropriate for different
reasons.96 These commenters assert that
a net benefits test would be very costly
and difficult to implement, that RTOs
and ISOs cannot implement a net
benefits test,97 and that such a test is
unnecessary with the economically
efficient compensation level for demand
response resources.98 According to
Andy Ott of PJM, ‘‘[t]he implicit
assumption in developing a benefits test
for purposes of compensation would be
that you could actually determine
individual customers, whether they
benefitted or not. That type of analysis
would be very costly to implement.’’ 99
Midwest ISO TOs further assert that it
would be difficult to prescribe by
regulation the hours in which demand
response provides net benefits because
system conditions and load patterns
change across seasons and over time.100
NEPGA argues that compensating
demand response resources at LMP
whenever a reduction in consumption
suppresses energy prices enough to
provide net benefits to load is neither
just and reasonable, nor in the public
interest.101 NEPGA states that the
Commission recognized in Amaranth
Advisors 102 that, if prices are
suppressed below competitive, market
levels, society as a whole is worse off.
According to NEPGA, the goal is to get
the right price—the economically
efficient price produced by competitive
markets.
95 EDF Oct. 13, 2010 Comments at 2; Viridity Oct.
13, 2010 Comments at 10; ELCON Oct. 13, 2010
Comments at 3.
96 See, e.g., Oct. 13, 2010 Comments of: Midwest
TDUs at 4–5; NEPGA at 8, NJBPU at 2–3; NAPP at
2–3; P3; SPP at 3–4; SDG&E, SoCal Edison, and
PG&E at 4–6; Viridity Energy at 2; ELCON at 2; AMP
at 2; CDWR at 1, 4–5; CAISO at 4, 15; Detroit Edison
at 2; Smart Grid Coalition at 2; Duke Energy at 2;
EDF at 2; FTC at 1; EPSA at 4; Indicated New York
TOs at 3; Midwest ISO at 9; Steel Manufacturers
Ass’n at 3.
97 P3 Oct. 13, 2010 Comments at 5.
98 Sept. 13, 2010 Tr. 155:21–24 (Mr. Robinson);
Sept. 13, 2010 Tr. 141–42 (Mr. Centolella); Dr.
Hogan Sept. 13, 2010 Comments at 5; Sept. 13, 2010
Tr. 60 (Dr. Shanker); Sept. 13, 2010 Tr. 27 (Mr.
Newton); SDG&E May 13, 2010 Comments at 4.
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).
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42. NYISO posits that a rule
mandating payment of LMP–G avoids
the need to develop a net benefits test.
NYISO further states, however, that if
the Commission decides to move
forward with LMP for demand response,
it should craft a net benefits test that
minimizes any opportunities for
distorting market prices or exploiting
market inefficiencies. Citing support for
Dr. Hogan’s arguments, NYISO states
that ‘‘a net benefits test should ensure
that the demand response program does
not have negative net benefits compared
to no program at all. The criterion to
apply would focus on the bid-cost
savings of generation and load, with the
load bids adjusted for the effects of
avoidance of the retail rate.’’ 103
(c) Standardization or Regional
Variations in Compensation
43. With regard to potential regional
variations for compensation
mechanisms across RTO and ISO
markets, many commenters, mostly
those in support of the NOPR’s
proposed compensation level, endorse
standardization.104 Some parties,
primarily industrial customers and
some customer advocates, argue that,
regardless of location, both demand
response providers and generators
provide a comparable service in terms of
balancing supply and demand, as
discussed above, and therefore should
be comparably compensated at the
LMP.105 They argue that fair, nondiscriminatory markets must adapt and
eliminate barriers to entry to the use and
incorporation of traditional and nontraditional resources—where nontraditional resources include activelymanaged demand—in the dispatch and
management of the electric system.106
They further posit that the lack of a
unified policy itself represents a
regulatory barrier to demand
response,107 and that a consistent set of
103 NYISO
Oct. 13, 2010 Comments at 3–4.
May 13, 2010 Comments of: ArcelorMittal;
Alcoa; ACENY; ACC; AFPA; CDWR; Mayor
Bloomberg; Consert; CDRI; CPower; DR Supporters;
Derstine’s; Durgin; Electricity Committee; ELCON;
Electrodynamics; ECS; EnerNOC; ICUB; IECA;
IECPA; Irving Forest; Joint Consumers; Limington;
Madison Paper; Massachusetts AG; NEMA; National
Energy; National League of Cities; NJBPU; NAPP;
Occidental; Okemo; Partners; Pennsylvania
Department of Environment; Pennsylvania
Commission; Rep. Chris Ross; Precision; PRLC;
Raritan; SDEG, SoCal; PG&E; Schneider; Governor
O’Malley; Steel Manufacturers Ass’n; Verso;
Viridity; Virginia Committee; Wal-Mart; Waterville.
105 See, e.g., Steel Manufacturers Ass’n May 13,
2010 Comments at 12; NEMA May 13, 2010
Comments at 5.
106 Steel Manufacturers Ass’n May 13, 2010
Comments at 12.
107 PIO May 13, 2010 Comments at 9; DR
Supporters Aug. 30, 2010 Comments at 6–7.
104 See
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rules reduces the costs and complexities
of demand response participation and
facilitates training and transfer of
personnel across regions.108 To that end,
many commenters argue that adopting a
unified approach to demand response
compensation at the LMP, as opposed to
allowing regional variation including
payment of something less than LMP, is
necessary to overcome the barriers to
entry of demand response providers.109
Reciting the many benefits of demand
reductions in energy use, these
commenters support a compensation
level that will provide a catalyst for
private sector engagement in improved
energy management practices. Viridity
argues that the near absence of demand
response participating in energy markets
is powerful empirical proof that current,
varying levels of compensation are
inadequate—especially in markets that
start with a market-based level of
compensation and then reduce it by the
generation portion of a customer’s retail
rate (LMP–G).110
44. Other commenters caution against
standardizing the compensation level
for demand response, pointing to
regional differences in market structure,
State regulatory environment, and
resource mix.111
3. Commission Determination
45. The Commission acknowledges
the diverging opinions of commenters
regarding the appropriate level of
compensation for demand response
resources. As discussed above,
commenters are split on this issue, with
some in favor of paying the LMP for
demand reductions in the day-ahead
and real-time energy markets in all
hours, others arguing that paying the
LMP for demand reductions under any
conditions will result in overcompensation or distortions in
incentives to reduce consumption, and
still others arguing that paying the LMP
for demand reductions is only
appropriate when it is reasonably
certain to be cost-effective.
46. In the face of these diverging
opinions, the Commission observes that,
as the courts have recognized, ‘‘ ‘issues
of rate design are fairly technical and,
insofar as they are not technical, involve
108 See,
e.g., Alcoa May 13, 2010 Comments at 13.
May 13, 2010 Comments at 4; NYISO
May 13, 2010 Comments at 16.
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.
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109 NECPUC
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policy judgments that lie at the core of
the regulatory mission.’ ’’ 112 We also
observe that, in making such judgments,
the Commission is not limited to
textbook economic analysis of the
markets subject to our jurisdiction, but
also may account for the practical
realities of how those markets
operate.113
47. As discussed further below, the
Commission agrees with commenters
who support payment of LMP under
conditions when it is cost-effective to do
so, as determined by the net benefits test
described herein.114 We have previously
accepted a variety of ISO and RTO
proposals for compensation for demand
response resources participating in
organized wholesale energy markets. We
find, based on the record here that,
when a demand response resource has
the capability to balance supply and
demand as an alternative to a generation
resource, and when dispatching and
paying LMP to that demand response
resource is shown to be cost-effective as
determined by the net benefits test
described herein, payment by an RTO or
ISO of compensation other than the
LMP is unjust and unreasonable. When
these conditions are met, we find that
payment of LMP to these resources will
result in just and reasonable rates for
ratepayers.115 As stated in the NOPR,
we believe paying demand response
resources the LMP will compensate
those resources in a manner that reflects
the marginal value of the resource to
each RTO and ISO.116
48. The Commission emphasizes that
these findings reflect a recognition that
it is appropriate to require
112 Elec. Consumers Res. Council v. FERC, 407
F.3d 1232, 1236 (DC Cir. 2005) (quoting Pub. Util.
Comm’n of the State of Cal. v. FERC, 254 F.3d 250,
254 (DC Cir. 2001)); see also Town of Norwood v.
FERC, 962 F.2d 20, 22 (DC Cir. 1992).
113 See Elizabethtown Gas Co. v. FERC, 10 F.3d
866, 872 (DC Cir. 1993) (‘‘It is the FERC’s
established policy to consider equitable factors in
designing rates, and to allow for phasing in of
changes where appropriate. * * * It is hardly
arbitrary or capricious so to temper the dictates of
theory by reference to their consequences in
practice.’’); Vermont Dep’t of Pub. Serv. v. FERC,
817 F.2d 127, 135 (DC Cir. 1987) (‘‘Indeed, ‘the
congressional grant of authority to the agency
indicates that the agency’s interpretation typically
will be enhanced by technical knowledge.’ ’’
(quoting Nat’l Fuel Gas Supply Corp. v. FERC, 811
F.2d 1563, 1570 (DC Cir. 1987))); Columbia Gas
Transmission Corp. v. FERC, 750 F.2d 105, 112 (DC
Cir. 1984) (‘‘the Commission is vested with wide
discretion to balance competing equities against the
backdrop of the public interest’’).
114 See generally May 13, 2010 Comments of
NYSCPB; NECA; Capital Power; NECPUC;
Maryland Commission; New York Commission;
NSTAR; National Grid; NE Public Systems.
115 The Commission’s findings in this Final Rule
do not preclude the Commission from determining
that other approaches to compensation would be
acceptable when these conditions are not met.
116 NOPR at P 12.
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compensation at the LMP for the service
provided by demand response resources
participating in the organized wholesale
energy markets only when two
conditions are met:
• The first condition is that the
demand response resource has the
capability to provide the service, i.e.,
the demand response resource must be
able to displace a generation resource in
a manner that serves the RTO or ISO in
balancing supply and demand.
• The second condition is that the
payment of LMP for the provision of the
service by the demand response
resource must be cost-effective, as
determined by the net benefits test
described herein.
49. With respect to the first,
capability-related condition, we note
that a power system must be operated so
that there is real-time balance of
generation and load, supply and
demand. An RTO or ISO dispatches just
the amount of generation needed to
match expected load at any given
moment in time. The system can also be
balanced through the reduction of
demand.117 Both can have the same
effect of balancing supply and demand
at the margin either by increasing
supply or by decreasing demand.
50. With respect to the second costeffectiveness condition, the record leads
us to alter the proposal set forth in the
NOPR in this proceeding. As various
commenters explain, dispatching
demand response resources may result
in an increased cost per unit to load
associated with the decreased amount of
load paying the bill, depending on the
change in LMP relative to the size of the
energy market. As stated above, this is
the billing unit effect of dispatching
demand response resources.118
However, when reductions in LMP from
implementing demand response results
in a reduction in the total amount
consumers pay for resources that is
greater than the money spent acquiring
those demand response resources at
LMP, such a payment is a cost-effective
purchase from the customers’
standpoint.119 In comparison, when
117 Andrew
L. Ott Sept. 13, 2010 Statement at 1.
Economic and Capacity-based demand response
clearly provides benefits to regional grid operation
and the wholesale market operation. * * * These
demand resources provide benefits by providing
valuable alternatives to PJM in maintaining
operational reliability and in promoting efficient
market operations.
Id. at 1; see also CDRI May 13, 2010 Comments
at 10; CDWR May 13, 2010 Comments at 5; NJPBU
May 13, 2010 Comments at 2.
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
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wholesale energy market customers pay
a reduced price attributable to demand
response that does not reduce total costs
to customers more than the costs of
paying LMP to the demand response
dispatched, customers suffer a net loss.
Implementation of the net benefits test
described herein will allow each RTO or
ISO to distinguish between these
situations.
51. This billing unit effect and the net
benefits test through which it is
addressed herein, warrant more detailed
discussion. In the organized wholesale
energy markets, the economic dispatch
organizes offers from lowest to highest
bid in order to balance supply and
demand, taking into account other
parameters such as requirements for a
generator to operate at a minimum level
of output or minimum amount of time,
reserve requirements and so forth. With
dispatch of a demand response resource,
the load also goes down, that is, the
level of remaining load falls. However,
the ‘‘supply’’ of resources deployed—
which includes both generation and
demand response—does not fall. The
total costs to the system for these
resources must then be allocated among
the reduced quantity of remaining load.
52. In the absence of the net benefits
test described herein, the RTO’s or ISO’s
economic dispatch ordinarily would
select demand response when it is the
incremental resource with the lowest
bid. However, if the next unit of
generation is not sufficiently more
expensive than the demand response
resource, the decrease in LMP
multiplied by the remaining load would
not be greater than the costs of
dispatching the demand response
resource. In this situation, dispatching
the demand response resource would
result in a higher price to remaining
customers than the dispatch of the next
unit of generation in the bid stack.
While the demand response resource
appears cost competitive in the dispatch
order, selection of the demand response
resource increases the total cost per unit
to remaining load, and it would not be
cost-effective to dispatch the demand
response resource.
53. For this reason, the billing unit
effect associated with dispatch of a
demand response resource in an energy
market must be taken into account in
the economic comparison of the energy
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.
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bids of generation resources and
demand response resources. Therefore,
rather than requiring compensation at
LMP in all hours, the Commission
requires the use of the net benefits test
described herein to ensure that the
overall benefit of the reduced LMP that
results from dispatching demand
response resources exceeds the cost of
dispatching those resources. When the
above-noted conditions of capability
and of cost-effectiveness are met, it
follows that demand response resources
that clear in the day-ahead and real-time
energy markets should receive the LMP
for services provided, as do generation
resources. LMP represents the marginal
value of an increase in supply or a
reduction in consumption at each node
within an ISO or RTO, i.e., LMP reflects
the marginal value of the last unit of
resources necessary to balance supply
and demand. Indeed, LMP has been the
primary mechanism for compensating
generation resources clearing in the
organized wholesale energy markets
since their formation.120
54. The Commission finds that
demand response resources that clear in
the day-ahead and real-time energy
markets should receive the same
market-clearing LMP as compensation
in the organized wholesale energy
markets when those resources meet the
conditions established here as a costeffective alternative to the next highestbid generation resources for purposes of
balancing the energy market. We discuss
below the comments filed on these
issues.
55. Some commenters dispute that the
foregone consumption of energy by
demand response resources performs
the service of balancing supply and
demand in the energy market as would
energy supplied by generators in the
day-ahead and real-time energy markets,
arguing that it is inappropriate to pay
electric consumers to not consume.121
The Commission disagrees. Generation
and load must be balanced by the RTOs
and ISOs when clearing the day-ahead
and real-time energy markets, and such
balancing can be accomplished by
changes in either supply or demand.
The Commission finds that in the
organized wholesale energy markets
demand response can balance supply
and demand as can generation.
56. Commenters that oppose this
finding do not adequately recognize a
distinctive and perhaps unique
characteristic of the electric industry.
120 See DR Supporters Aug. 30, 2010 Reply
Comments (Kahn Affidavit at 2 (footnote omitted)).
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.
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16667
The electric industry requires
instantaneous balancing of supply and
demand at all times to maintain
reliability. It is in this context that the
Commission finds that demand
response can balance supply and
demand as can generation when
dispatched, in the organized wholesale
energy markets.
57. Due to a variety of factors, demand
responsiveness to price changes is
relatively inelastic in the electric
industry and does not play as significant
a role in setting the wholesale energy
market price as in other industries. The
Commission has recognized that barriers
remain to demand response
participation in organized wholesale
energy markets. For example, in Order
No. 719, the Commission stated:
[D]espite previous Commission and RTO
and ISO efforts to facilitate demand response,
regulatory and technological barriers to
demand response participation persist,
thereby limiting the benefits that would
otherwise result. A market functions
effectively only when both supply and
demand can meaningfully participate, and
barriers to demand response limit the
meaningful participation of demand in
electricity markets.122
Barriers to demand response
participation at the wholesale level
identified by commenters include the
lack of a direct connection between
wholesale and retail prices,123 lack of
dynamic retail prices (retail prices that
vary with changes in marginal
wholesale costs), the lack of real-time
information sharing, and the lack of
market incentives to invest in enabling
technologies that would allow electric
customers and aggregators of retail
customers to see and respond to changes
in marginal costs of providing electric
service as those costs change. For
example, Dr. Kahn states:
These circumstances—specifically, the fact
that pass-through of the LMP is costly and
(perhaps) politically infeasible, the possibly
prohibitive cost of the metering necessary to
charge each ultimate user, moment-bymoment, the often dramatic changes in true
marginal costs for each—can justify direct
payment at full LMP to distributors and
ultimate customers who promise to guarantee
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
https://www.ferc.gov/legal/staff-refports/06-09demand-response.pdf; Barriers to Demand Side
Response in PJM (2009)). In compliance filings
submitted by RTOs and ISOs and their market
monitors pursuant to Order No. 719, as well as in
responsive pleadings, parties have mentioned
additional barriers, such as the inability of demand
response resources to set LMP, minimum size
requirements, and others.
123 See, e.g., Monitoring Analytics May 13, 2010
Comments at 4–6.
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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
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58. The Commission concludes that
paying LMP can address the identified
barriers to potential demand response
providers.
59. Removing barriers to demand
response will lead to increased levels of
investment in and thereby participation
of demand response resources (and help
limit potential generator market power),
moving prices closer to the levels that
would result if all demand could
respond to the marginal cost of energy.
To that end, the Commission
emphasizes that removing barriers to
demand response participation is not
the same as giving preferential treatment
to demand response providers; rather, it
facilitates greater competition, with the
markets themselves determining the
appropriate mix of resources, which
may include both generation and
demand response, needed by the RTO
and ISO to balance supply and demand
based on relative bids in the energy
markets. In other words, while the level
of compensation provided to each
resource affects its willingness and
ability to participate in the energy
market, ultimately the markets
themselves will determine the level of
generation and demand response
resources needed for purposes of
balancing the electricity grid.126
60. Another issue raised by a number
of commenters, largely representing
generators, is whether a lower payment
based on LMP–G is the economicallyefficient price that sends the proper
price signal to a potential demand
response provider. These commenters
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.
126 Generation and demand response resources
have the potential to earn other revenues through
bilateral arrangements, capacity markets where they
exist, and ancillary services.
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argue that, by not consuming energy,
demand response providers already
effectively receive ‘‘G,’’ the retail rate
that they do not need to pay. They
therefore contend that demand response
providers will be overcompensated
unless ‘‘G’’ is deducted from payments
made by the RTO or ISO for service in
the wholesale energy market, resulting
in a payment of LMP–G. These
commenters suggest that payment of
LMP–G will result in a price signal to
demand response providers equivalent
to the LMP (i.e., (LMP¥G) + G).
Similarly, some commenters argue that
paying demand response resources the
LMP will lead to a wholesale electricity
price that is not economically
efficient.127
61. The Commission disagrees with
commenters who contend that demand
response resources should be paid
LMP–G in all hours. First, as discussed
above, demand response resources
participating in the organized wholesale
energy markets can be cost-effective, as
determined by the net benefits test
described herein, for balancing supply
and demand and, in those
circumstances, it follows that the
demand response resource should also
receive compensation at LMP. Second,
such comments largely rely on
arguments about economic efficiency,
analogizing to incentives for individual
generators to bid their marginal cost.
These arguments fail to acknowledge
the market imperfections caused by the
existing barriers to demand response,
also discussed above. In Order No. 719,
the Commission found that allowing
demand response to bid into organized
wholesale energy markets ‘‘expands the
amount of resources available to the
market, increases competition, helps
reduce prices to consumers and
enhances reliability.’’ 128 Furthermore,
Dr. Kahn argues that paying demand
response LMP sets ‘‘up an arrangement
that treats proffered reductions in
demand on a competitive par with
positive supplies; but the one is no more
a [case of overcompensation] than the
other: the one delivers electric power to
users at marginal costs—the other—
reductions in cost—both at
competitively-determined levels.’’ 129
62. Several other considerations also
support this Commission conclusion. In
the absence of market power concerns,
the Commission does not inquire into
the costs or benefits of production for
the individual resources participating as
127 See
NEPGA June 21, 2010 Comments at 1–2.
128 Order No. 719, FERC Stats. & Regs. ¶ 31,281
at P 154.
129 DR Supporters Aug. 30, 2010 Reply Comments
(Kahn Affidavit at 9–10).
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supply resources in the organized
wholesale electricity markets and will
not here, as requested by some
commenters, single out demand
response resources for adjustments to
compensation. The Commission has
long held that payment of LMP to
supply resources clearing in the dayahead and real-time energy markets
encourages ‘‘more efficient supply and
demand decisions in both the short run
and long run,’’ 130 notwithstanding the
particular costs of production of
individual resources. Commenters have
not justified why it would be
appropriate for the Commission to
continue to apply this approach to
generation resources yet depart from
this approach for demand response
resources.
63. In addition, we agree with the
New York Commission that given the
differences in retail rate structures
across RTO footprints and even within
individual States, requiring ISOs and
RTOs to incorporate such disparate
retail rates into wholesale payments to
wholesale demand response providers
would, even though perhaps feasible,
create practical difficulties for a number
of parties, including State commissions
and ISOs and RTOs. Moreover,
incorporating such rates could result in
customer uncertainty as to the
prevailing wholesale rate.
64. Some arguments advocating
paying LMP–G rather than LMP are
based on an assumption that demand
response resources need to purchase the
energy in day-ahead markets or by other
means and then ‘‘resell’’ the energy to
the market in the form of demand
response. However, as the Commission
previously stated in EnergyConnect, the
Commission does not view demand
response as a resale of energy back into
the energy market.131 Instead, as the
Commission also explained in
EnergyConnect and in Order No. 719–A,
the Commission asserts jurisdiction
with respect to demand response in
organized wholesale energy markets
because of the effect of demand
response and related RTO and ISO
market rules on Commissionjurisdictional rates.132
65. With regard to the ‘‘buyers’ cartel’’
argument, the Commission disagrees
that market rules establishing
circumstances in which particular
resources can participate and receive
the LMP represents cooperative price
setting. RTOs and ISOs evaluate the bids
130 See New England Power Pool, 101 FERC
¶ 61,344, at P 35 (2002).
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.
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from generation and demand response
resources to establish the order of
dispatch which secures the most
economical supplies needed, consistent
with the reliability constraints imposed
on the system. Imposing a costeffectiveness condition does not convert
this unit commitment process by the
RTO or ISO into collusion among
bidders, whether generation or demand
response. Furthermore, the market rules
administering such a program would be
approved by this Commission and
demand response resources would be
subject to Commission-approved rules,
just like any other participants in the
organized wholesale energy markets. In
addition, arguments that the subject of
this proceeding is equivalent to the
types of market manipulation
investigated in Amaranth and ETP are
groundless and without merit. In
Amaranth, the trader was accused of
engaging in a fraudulent scheme with
scienter in connection with a
jurisdictional transaction. Here, there is
no such allegation, merely speculation
that the Commission is somehow
facilitating coordination of demand-side
bidders in order to lower prices.
66. Some commenters argue that
demand response providers and
generators should both be compensated
at the market clearing price only if both
are subject to the same market
participation rules, penalty structures,
testing requirements, and market
monitoring provisions. The ISOs and
RTOs already consider how to ensure
comparability between demand
response and generation in terms of
market rules.133 The Commission agrees
that as a general matter demand
response providers and generators
should be subject to comparable rules
that reflect the characteristics of the
resource, and expect ISOs and RTOs to
continue their evaluation of their
existing rules in light of this Final Rule
and make appropriate filings with the
Commission.
67. Some commenters argue that the
Commission should not impose a single
pricing rule due to differences in market
structure, State regulatory environment,
and resource mix among the ISOs and
RTOs. While such differences may exist,
the commenters have not shown why
such differences warrant a different
compensation level among the ISOs and
RTOs. As discussed above, regardless of
the resource mix or the State regulatory
environment, demand response, which
satisfies the net benefits test described
herein and can balance the system, is a
cost-effective alternative to generation
133 See PJM Interconnection, L.L.C., 129 FERC
¶ 61,081 (2009).
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in the organized wholesale energy
markets, and payment of LMP
represents the marginal value of a
decrease in demand.
B. Implementation of a Net Benefits Test
1. Comments
68. In response to questions that the
Commission posed in the Supplemental
NOPR, some commenters advocate a net
benefits trigger based on a particular
price threshold.134 The NYISO currently
has a static bid threshold of $75/MWh
in its day-ahead demand response
program.135
69. However, other commenters assert
that using a static threshold based on
historical data misses the changes that
occur within electricity markets across
seasons and years, and that it is
erroneous to assume that all demand
response occurring above a certain
threshold price (for instance, at the very
highest loads or highest priced hours)
will result in lower costs to wholesale
customers and that demand response is
not cost-effective at prices below the
static threshold price.136 They argue
that a static threshold offer price cannot
easily adjust with changing energy
market prices which may result in
inefficient dispatch of demand
resources, excluding demand response
participation in hours when demand
response can provide beneficial savings
and including demand response
participation in hours when there are no
beneficial savings.137 The New York
Commission supports a dynamic, rather
than a static bid threshold, arguing that,
while a static bid threshold helps
prevent demand response providers
from gaming the system by seeking
compensation for reducing electricity
134 For example, National Grid states that the
threshold could be triggered by a particular price
on the supply offer curve at which the additional
cost of paying LMP to demand response resources
is most likely to be outweighed by LMP reductions
in the wholesale energy market as a result of the
demand reductions produced by these resources.
National Grid May 13, 2010 Comments at 6. Those
in favor of a price threshold include National Grid
(but allow the ISO or RTO to identify threshold
based on analysis); NE Public Systems; NECPUC;
ISO–NE (minimum offer price based on fixed heat
rate, times a fuel price index); New York
Commission (supports ISO–NE’s heat rate indexed
price threshold).
135 NYISO implements a day-ahead demand
response program by which resources bid into the
market at a minimum of $75/MWh and can get paid
the LMP. See section 4.2.2.9 (‘‘Day-Ahead Bids from
Demand Reduction Providers to Supply Energy
from Demand Reductions’’) of NYISO’s Market
Services Tariff.
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.
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16669
consumption for reasons other than
market prices, it can also limit
participation in a demand response
program because prices might not
exceed the threshold on a consistent
basis.138
70. In a similar vein, some
commenters suggest utilizing a dynamic
bid threshold for determining when
LMP payment would apply.139 For
example, NECPUC favors use of a
dynamic mechanism such as a price
threshold based on a preset heat rate of
marginal generation and fuel price, like
that currently used in New England’s
Day-Ahead Load Response Program
(DALRP),140 for the ISO–NE control
area.141 National Grid suggests a trigger,
determined by each ISO or RTO, using
a particular price on the supply offer
curve at which the additional cost of
paying LMP to demand resources is
most likely to be outweighed by LMP
reductions in the wholesale energy
market as a result of the demand
reductions.142
71. Still other commenters urge
compensating demand response during
an ISO- or RTO-defined period of
critical high-cost hours in which it is
cost-effective to pay LMP. These
commenters argue that the effect of
demand response on the market clearing
price is greatest during a limited
number of hours during the year.143
Therefore, identifying the hours in
which to pay LMP to demand response
resources could be used as a costeffective net benefits test with potential
savings for ratepayers. According to
PJM, further analysis is needed to
ascertain the critical high-cost hours in
which it will be cost-effective to pay full
LMP for demand response.144
72. The Consumer Demand Response
Initiative (CDRI) proposes a mechanism
for determining what demand response
resources are cost-effective in any
138 Id.
139 National Grid May 13, 2010 Comments at 6;
New York Commission May 13, 2010 Comments at
10; Viridity May 13, 2010 Comments at 24. See
generally NECPUC, New York Commission; ISO–
NE; NSTAR; ACEEE; and NYSCPB Oct. 13, 2010
Comments.
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.
144 Maryland Commission May 13, 2010
Comments at 4 n.9.
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hour.145 This dispatch algorithm tests
whether the money necessary to
compensate demand response is less
than the cost savings due to the
decreased market-clearing price
resulting from implementing demand
response. In a sense, it is a dynamic
cost/benefit analysis built into the
dispatch algorithm. This cost/benefit
analysis accounts for the billing unit
effect. The billing unit effect occurs
when demand response resources are
dispatched to balance the system; the
associated reduction in load results in
fewer MWh of realized load (demand)
paying for the sum of generator and
demand response resource MWh, so
load pays an effective rate which is
greater than the LMP set to procure
resources. Some commenters assert that
if the Commission finds that a net
benefits test is needed, it should require
organized wholesale energy market
operators to implement a proposal
similar to that submitted by CDRI.146
73. Under the proposal submitted by
CDRI, the demand response bids are
part of the supply stack to which a
security-constrained economic dispatch
process is applied. All demand response
bids that result in a lower price to
customers, including consideration of
the reduced number of billing units, are
selected while those bids that raise the
price, as compared to selecting the next
generation bid in the supply stack, are
not. This dispatch algorithm, as
proposed, would be used by the ISO or
RTO to determine a revised LMP that
would be charged to load. The revised
LMP creates a surplus (or overcollection) of revenue for the ISO or
RTO that is then distributed to the LSEs
through a settlement algorithm with the
goal of holding LSEs harmless.147
74. During the September 2010
Technical Conference, Dr. Ethier of
ISO–NE stated that a dynamic net
benefits test done on an hourly basis
that examines the effect of the demand
response resource on LMPs, similar to
that proposed by CDRI, would become
very complicated to implement and
require essentially an iterative
process.148 Dr. Ethier states that the ISO
would have to run the dispatch model
to formulate a base LMP with no
demand response and then re-run it
with demand response in the market;
however those two iterations alone do
not ‘‘cover the whole waterfront’’ in
terms of the possible iterations required.
According to Dr. Ethier, the ISO could
dispatch too much demand response the
first time, or if the ISO first rejected
dispatching demand response, it may
need to go back and dispatch smaller
amounts of demand response to
determine what would happen to the
LMPs. Dr. Ethier stated that it is unclear
where the ISO would stop the iteration
of testing the impact on LMPs of
dispatching demand response.149 Andy
Ott of PJM also stated during the
technical conference that implementing
a net benefits test would entail an
iterative process that would be costly
and difficult, if the RTO could even do
it.150
75. Other commenters do not support
the use of a net benefits test, but state
that if one is adopted it should be based
on general principles that RTOs and
ISOs must apply to their systems in
determining when LMP payments will
apply.151 A few commenters articulated
specific criteria to be used in a net
benefits test.152 AEP believes that the
objective of an incentive payment for
demand response resources on the basis
of broad market benefits can be
achieved through a review of the costs
and benefits of individual providers.
Constellation states that any net benefits
test should be based on the difference
between the value consumers receive
from energy and the cost of energy
production.153
76. ISO–NE argues that a net benefits
test should be based on economic
efficiency, the sum of producer and
consumer surplus, which suggests that
demand response incentives ought to be
provided to encourage demand
148 Sept.
13, 2010 Tr. 80–81 (Dr. Ethier).
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149 Id.
145 The approach submitted by CDRI was
developed for implementation in the ISO–NE dayahead energy market. The discussion here is
generalized to be applicable to any energy market
that uses security-constrained economic dispatch to
select the least-cost resources and establish a
market-clearing price.
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.
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150 Sept.
13, 2010 Tr. 82:16–21 (Mr. Ott).
generally AEP, Midwest ISO, Occidental,
NYISO, Constellation Oct. 13, 2010 Comments.
152 See, e.g., Midwest ISO October 13, 2010
Comments at 9–14 and Table 1 (setting forth
comprehensive list of benefits and costs of demand
response by type of market participants); Occidental
October 13, 2010 Comments at 4–5 (any net benefits
test must take into consideration offsetting
variables, such as higher LMPs in the subsequent
periods where demand rebound increases market
price, and capacity market price effects); AEP
October 13, 2010 Comments at 3–4 (AEP does not
recommend the use of a societal benefits
component (i.e., health, environment, or
employment efforts)).
153 Constellation October 13, 2010 Comments at
3–4.
151 See
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reductions when the cost of energy
production exceeds the value of
consumption, and to encourage usage
when the cost of energy production is
less than the value of consumption.
ISO–NE further states that a net benefits
test that focuses solely on consumer
savings ignores the value lost by
consumers when energy consumption
levels are reduced in response to
incentive payments. ISO–NE posits that
any variant of a LMP payment should be
limited to a very small number of highpriced hours to minimize the economic
distortions and avoid significant
administrative complexities.154
77. A few commenters state that
policies affecting energy prices will also
impact capacity prices because
generation owners with fixed costs must
raise capacity price offers to remain
financially viable at lower energy
prices.155 ISO–NE and Pepco argue,
therefore, that the Commission should
adopt a net benefits test that considers
the impact of demand response
compensation on both energy and
capacity markets.156 According to ISO–
NE, when considering capacity market
impacts under full-LMP compensation,
long-term increases in capacity prices in
response to suppressed LMPs offset
consumer savings and leaves consumers
worse off over time.157 Robert Weishaar
of the DR Supporters argues that
properly compensating demand
response should flatten the load profile
and decrease the forecast of load
projections, which would reduce
capacity clearing prices.158 Donald Sipe
of CDRI adds that to the extent that
scarcity revenues are not sufficient,
capacity markets are designed to ensure
that a generator’s capital costs are
recovered; in a forward market that
looks ahead as load adjusts, one can see
whether a resource is performing or not.
For purposes of long-run reliability, he
argues, as long as compensation is in the
amount that is necessary to induce new
investment and reflects market value,
the argument that demand response in
the bid stack will push out generators is
only true if generators are higher priced
than the consumer resources that are
brought by demand response.159
154 ISO–NE
Oct. 13, 2010 Comments at 4–5 and
21.
155 See, e.g., Sept. 13, 2010 Tr. 94:13–22 (Dr.
Shanker); Sept. 13, 2010 Tr. 98:4–24 (Mr. Peterson);
Sept. 13, 2010 Tr. 99:2–7 (Mr. Sunderhauf); ISO–
NE Oct. 13, 2010 Comments at 5.
156 Sept. 13, 2010 Tr. 99:1–24 (Mr. Sunderhauf);
ISO–NE Oct. 13, 2010 Comments at 5.
157 ISO–NE Oct. 13, 2010 Comments at 6.
158 Sept. 13, 2010 Tr. 103–104 (Mr. Weishaar).
159 Sept. 13, 2010 Tr. 106:16–24 (Mr. Sipe).
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2. Commission Determination
78. For the reasons discussed
previously, the Commission is requiring
each RTO and ISO to implement the net
benefits test described herein to
determine whether a demand response
resource is cost-effective. More
specifically, the Commission is adopting
two distinct requirements with respect
to the net benefits test. While we find
that the integration of the billing unit
effect into the RTO/ISO dispatch
processes has the potential to more
precisely identify when demand
response resources are cost-effective, we
also recognize and understand the
position of several of the RTOs and ISOs
that modification of their dispatch
algorithms may be difficult in the near
term. Given these technical difficulties,
we will require to RTOs and ISO to
perform (1) the net benefits test
described below to determine on a
monthly basis under which conditions
it is cost-effective to pay full LMP to
demand resources; 160 and (2) a study of
the feasibility of developing a
mechanism for determining the costeffective dispatch of demand resources.
79. First we direct each RTO and ISO
to undertake an analysis on a monthly
basis, based on historical data and the
RTO’s or ISO’s previous year’s supply
curve, to identify a price threshold to
estimate where customer net benefits, as
defined herein, would occur. The RTO
or ISO should determine the threshold
price corresponding to the point along
the supply stack for each month beyond
which the benefit to load from the
reduced LMP resulting from dispatching
demand response resources exceeds the
increased cost to load associated with
the billing unit effect, and update the
calculation monthly. The ISOs and
RTOs are to determine monthly
threshold prices based on historical
data. The threshold prices would be
updated monthly as new data becomes
available and posted on the RTO Web
site. For example, the RTO should
conduct an analysis of supply curves for
January through December 2010 to be
used as a starting point to establish
threshold prices for 2011. Those
numbers would be updated monthly
during 2011 for significant changes in
resource availability and fuel prices,
with the process repeated monthly to
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.
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reflect that month’s data from the
previous year.161 The supply curve
analysis should be updated monthly, by
the 15th day of the preceeding month in
advance of the effective date, to allow
demand response providers as well as
other market participants to plan, while
still reflecting current supply
conditions.162
80. Based on historical evidence and
analysis submitted in this proceeding,
the threshold point along the supply
stack for each month will fall in the area
where the supply curve becomes
inelastic, rather than the extreme steep
portion at the peak or in the flat portion
of the supply curve.163 In other words,
LMP will be paid to demand response
resources during periods when the
nature of the supply curve is such that
small decreases in generation being
called to serve load will result in price
decreases sufficient to offset the billing
unit effect. The Massachusetts AG noted
that the actual supply stack has locally
flat and steep sections at all bid prices.
We recognize that the threshold price
approach we adopt here may result in
instances both when demand response
is not paid the LMP but would be costeffective and when demand response is
paid the LMP but is not cost-effective.
We accept this result given the apparent
computational difficulty of adopting a
dynamic approach that incorporates the
billing unit effect in the dispatch
algorithms at this time.164
81. We direct each RTO and ISO to
file its analysis as supporting
documentation to the accompanying
tariff revisions with the Commission on
or before July 22, 2011, along with
proposed tariff revisions necessary to
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 × MWh consumed) > (LMP new × DR); where
LMP new is the market clearing price after demand
response (DR) is dispatched and Delta LMP is the
price before DR is dispatched minus the market
clearing price after DR is dispatched.
163 Supply elasticity is defined as the percentage
change in quantity supplied divided by the
percentage change in price. When the elasticity is
less than or equal to one, supply is considered
inelastic. So, for example, in the inelastic portion
of the supply curve, a reduction in quantity
supplied by one percent will result in more than a
one percent decrease in price. Using the terms
related to demand response compensation, the
billing unit effect (percentage change in quantity
supplied) will be more than offset by lower LMP
(percentage change in price), thus resulting in lower
prices for wholesale load.
164 See supra note 114.
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16671
comply with this Final Rule. The filing
should include the data, analytical
methods and the actual supply curves
used to determine the monthly
threshold prices for the last 12 months
to show how the RTO or ISO would
calculate the curves.165 The
Commission-approved net benefits test
methodology must be posted on the
RTO or ISO’s Web site, with supporting
documentation. The RTO or ISO must
also post the price threshold levels that
would have been in effect in the
previous 12 months. In addition, when
the net benefits test becomes effective,
the supply curve analysis for the
historic month that corresponds to the
effective month should be updated for
current fuel prices, unit availabilities,
and any other significant changes to
historic supply curve and posted on the
RTO Web site (for example, the supply
curve analysis for the March price
threshold would be posted in midFebruary). Finally, the supply curve
analyses for all months should be
updated and posted on the RTO Web
site if a significant change to the
composition or slope of the historic
monthly curves occurs, such as
extended outages or retirements not
previously reflected.
82. Some commenters argue that that
there would be no need for a net
benefits test if demand response
resources were paid LMP–G, while
others argue that use of a net benefits
test otherwise undermines our decision
to compensate demand response
resources at the LMP. As stated above,
the Commission finds that when a
demand response resource participating
in an organized wholesale energy
market is capable of balancing supply
and demand in the energy market and
is cost-effective, as determined by the
net benefits test described herein, that
demand response resource should
receive the same compensation, the
LMP, as a generation resource when
dispatched. We see no reason to reduce
that compensation simply to avoid the
use of the net benefits test that will
ensure benefits to load.
83. Nearly every participant in the net
benefits panel at the September 13, 2010
Technical Conference agreed that it
would be counterproductive to defer to
the RTO or ISO stakeholder process to
determine when demand response
provides net benefits without explicit
guidance from the Commission.166 We
165 See
supra P 6.
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
166 ‘‘[G]etting
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believe that this result, and the guidance
provided in this Final Rule will provide
for timely improvements to RTO and
ISO market pricing for demand response
resources participating in organized
wholesale energy markets.
84. In addition to requiring each RTO
and ISO to construct the net benefits test
described herein, the Commission also
imposes a second requirement for each
RTO and ISO to undertake a study,
examining the requirements for and
impacts of implementing a dynamic
approach to determine when paying
demand response resources LMP results
in net benefits to customers. We believe
that integration of the billing unit effect
into RTO and ISO dispatch algorithms
holds promise for more accurately
integrating demand resources on a
dynamic basis into the dispatch of the
RTOs and ISOs. In theory, this could
help ensure that the cost-effective level
of demand response resources is
dispatched or scheduled into the
organized wholesale energy markets.
Given the potential of software
enhancements to determine the amount
of cost-effective demand response
resources purchased in the day-ahead
and real-time energy markets, we
believe that it would be useful for the
Commission to know more about the
feasibility of and requirements for
implementing improvements to the
existing dispatch algorithms. Therefore,
we will require each RTO and ISO to
undertake a study, either individually or
collectively, examining the
requirements for, costs of, and impacts
of implementing a dynamic net benefits
approach to the dispatch of demand
resources that takes into account the
billing unit effect in the economic
dispatch in both the day-ahead and realtime energy markets, and to file the
results of their study with the
Commission on or before September 21,
2012.
85. ISO–NE and Pepco suggest that
the net benefits test also consider the
impact of demand response
compensation on both energy and
capacity markets. However, this Final
Rule is focused only on organized
wholesale energy markets, not capacity
markets.167 Given the differences in
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.
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
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capacity markets among the ISOs and
RTOs, the record in this proceeding
provides neither a reasonable basis for
including capacity market effects in net
benefits calculations in the energy
markets, nor have ISO–NE and Pepco
provided a methodology for taking such
effects into account. Indeed, in some
cases, the capacity markets already
reflect energy and ancillary service
revenue in determining capacity prices.
C. Measurement and Verification
1. NOPR Proposal
86. In the NOPR, the Commission
explained that demand response
curtailment is a reduction in actual load
as compared to the demand response
provider’s expected level of electricity
consumption.168 The NOPR did not
address measurement and verification of
demand response.
87. Each RTO and ISO with a demand
response program has procedures for the
measurement and verification of
demand response. These procedures
include techniques to establish a
customer baseline for each demand
response participant. This customer
baseline then becomes the basis for
measuring the quantity of demand
response delivered to the wholesale
market. Customer baselines are often
based on historic load information, such
as an average of five of the last ten
comparable days’ hourly load profile.
Techniques vary among RTOs and ISOs
and most have several techniques that
may be allowed, depending on the
demand response provider’s
characteristics.169
2. Comments
88. Commenters assert that the
integrity of a demand response program
is heavily dependent on measurement
and verification.170 Some commenters
raise the issue that paying LMP in all
hours presents a significant challenge to
the accurate measurement and
increase potential suppliers in the capacity markets
by reducing barriers to demand resources, which
would tend to drive capacity prices down. Second,
they did not examine the way in which capacity
markets already may take into account energy
revenues.
168 Demand Response Compensation in
Organized Wholesale Energy Markets, FERC Stats.
& Regs. ¶ 32,656, at P 1 (2010).
169 See, e.g., ISO/RTO Council, North American
Wholesale Electricity Demand Response 2010
Comparison, under the tab for ‘‘Performance
Evaluation Methods’’ (https://www.isorto.org/atf/cf/
%7B5b4e85c6-7eac-40a0-8dc3-003829518ebd%7D/
IRC%20DR%20M&V%20STANDARDS%20
IMPLEMENTATION%20COMPARISON
%20(20100524).XLS).
170 Illinois CUB May 14, 2010 Comments at 16–
17; Joint Consumers May 13, 2010 Comments at 12;
P3 May 12, 2010 Comments at 38; Westar May 13,
2010 Comments at 3.
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verification of demand response.171
ISO–NE argues that when a market
participant schedules demand
reductions for many consecutive days,
baselines may become stale—no longer
reflecting a customer’s ‘‘normal’’
electricity usage.172 ISO–NE goes on to
argue that ‘‘it is necessary to limit the
number of hours or days that a demand
resource could clear in the energy
market so that the customer’s ‘normal’
load can be estimated’’ to avoid the
potential for manipulation.173 In the
context of the Commission’s proposal to
pay demand response the LMP in all
hours, ISO–NE goes on to advocate
requiring demand response to establish
baselines by purchasing energy in the
day-ahead market as a way to overcome
its concerns with statistical baseline
methods.174 ISO–NE IMM makes similar
arguments and recommendations.175
Westar also appears to support this
approach.176
89. Similarly, CPower notes that with
some baseline methods, paying LMP in
all hours could reward demand
responders for any shift in demand from
the baseline, not just shifting load from
high LMP hours to low LMP hours, or
could simply shift load from day-to-day
in different hours to affect the
calculation of actual curtailment, which
it labels ‘‘checkerboarding.’’ However,
CPower believes that the capability of
consumption management to shed or
shift load for many hours is well into
the future, and perhaps not a current
concern. CPower also believes that
baseline standards along with market
monitoring will develop to meet these
concerns.177
90. ISO–NE IMM asserts that ‘‘[if] the
Commission adopts any proposal that
permits the use of an administrative
baseline it should explicitly state that
any demand reductions offered into
Commission-jurisdictional markets that
are not genuine, even if they are the
result of ‘normal’ activity * * * may be
violations of the Commission’s anti171 See,
e.g., ISO–NE May 13, 2010 Comments at
32.
172 Id.
173 ISO–NE May 13, 2010 Comments at 34. ISO–
NE identifies several practices that, in its view,
might be deployed by a demand responder to
receive payment when it has not, in fact, responded
to price. ISO–NE states that observations of such
behavior in the Fall of 2007 led it to limit the hours
demand response offers could clear the market.
Citing ISO New England Inc., Docket No. ER08–
538–000 (February 5, 2008 filing). ISO–NE May 13,
2010 Comments at 32–34.
174 Id.
175 ISO–NE IMM May 13, 2010 Comments at
9–13 and Attachment A.
176 Westar May 13, 2010 Comments at 3.
177 CPower May 13, 2010 Comments at 4–5.
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manipulation rules and subject to
penalties thereunder.’’ 178
91. Noting the ongoing efforts by the
industry and the North American
Energy Standards Board (NAESB) on
measurement and verification, EnerNOC
takes the view that resolution of
customer baseline issues should not
delay the issuance of this Final Rule.179
92. Finally, some commenters assert
that measurement and verification
methods should not be standardized,
but left to the RTOs and ISOs to reflect
the unique features of their individual
energy, ancillary services, and capacity
markets.180
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3. Commission Determination
93. The Commission agrees with
commenters who assert that
measurement and verification are
critical to the integrity and success of
demand response programs. Without a
determination of a demand response
provider’s expected use of power, the
ISOs and RTOs cannot determine
whether that provider has in fact
reduced its energy usage when paid to
do so. Towards that end, all the RTOs
and ISOs already have measurement
and verification protocols for their
demand response programs.181 In
addition, we have adopted Phase I
standards for measurement and
verification published by the North
American Energy Standards Board,182
and have recognized the potential
benefits of the continuing NAESB effort
to craft Phase II standards with more
substantive and consistent wholesale
standards for measurement and
verification.183
94. A number of commenters
maintain that compensating demand
response resources at the LMP during
all hours could make determining
baselines for demand response
providers exceedingly difficult.
However, the impact of our adopting the
net benefits test described herein is that
the LMP will not be paid to demand
response resources in all hours.
178 ISO–NE IMM May 13, 2010 Comments at 14
(footnotes omitted) (ISO–NE MMU also notes that
‘‘[i]n assessing whether demand reductions are
genuine, allowance should be made for nonperformance analogous to a generator’s forced
outage.’’).
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.
181 See, e.g., PJM Interconnection, L.L.C., 123
FERC ¶ 61,257 (2008).
182 Standards for Business Practices and
Communication Protocols for Public Utilities, Final
Rule, 131 FERC ¶ 61,022 (2010).
183 Id., at P 32–34.
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Accordingly, implementation of this
Final Rule would not appear to prevent
the determination of appropriate
baselines. Nonetheless, we direct ISOs
and RTOs to review their current
requirements in light of the changes in
this Final Rule and develop appropriate
revisions and modifications, if
necessary, to ensure that their baselines
remain accurate and that they can verify
that demand response resources have
performed. Specifically, we direct each
RTO and ISO to include as part of the
compliance filing required herein, an
explanation of how its measurement
and verification protocols will continue
to ensure that appropriate baselines are
set, and that demand response will
continue to be adequately measured and
verified as necessary to ensure the
performance of each demand response
resource. If necessary, each RTO and
ISO should propose any changes needed
to ensure that measurement and
verification of demand response will
adequately capture the performance (or
non-performance) of each participating
demand response market participant to
be consistent with the requirements of
this Final Rule.
95. Finally, we agree with ISO–NE
IMM that demand reductions that are
not genuine may be violations of the
Commission’s anti-manipulation
rules.184 Allegations of such behavior
will continue to be investigated, and
when appropriate, sanctions will be
brought to bear.
D. Cost Allocation
1. NOPR Proposal
96. In response to the NOPR and
September 13, 2010 Technical
Conference, many commenters argue
that, in order to determine the justness
and reasonableness of the proposed
compensation level, the corresponding
cost allocation must be considered.185
More specifically, these commenters
raise concerns regarding how the costs
associated with payment of LMP for
demand response will be allocated, or
assigned, within an ISO or RTO. Several
commenters assert that the issues of cost
allocation and net benefits are
inherently linked, so that the
Commission must address both issues
together.186
184 18
CFR 1.c (2010).
May 13, 2010 Comments at at 39–40;
see also May 13, 2010 Comments of: AEP at 6–10;
CAISO at 6; ConEd at 2; Hess at 3; ICC at 12; PJM
at 8; Potomac Economics at 3; Massachusetts AG at
11; Midwest ISO TOs at 5–6; Midwest TDUs at 13;
EEI at 5; NECPUC at 12, 22; NECA at 11; RRI at 6;
SDG&G at 3–4.
186 As further addressed below, several
commenters assert that the costs of demand
response compensation should be borne by only
185 ISO–NE
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2. Comments
97. Comments reveal five specific
methods for cost allocation: (1)
Assignment of costs to the load serving
entity (LSE) associated with the demand
response provider, (2) assignment of
costs broadly to all purchasing
customers, (3) bifurcated assignment of
costs with some directly assigned to a
LSE and others assigned broadly,
(4) directly assign the cost for demand
response compensation to the retail
customers that bid the demand response
into the wholesale market, and (5) the
settlement method proposed by CDRI,
which incorporates the cost of demand
response into the dispatch algorithm.
Some commenters argue not for a
specific method, but for each regional
entity to select and employ a method of
its own,187 and a few other commenters
assert that the Commission need not
address cost allocation in this
proceeding.188
98. Some commenters argue that costs
should be assigned to the LSE
associated with the demand response
provider because it is this entity that
receives the full benefit of demand
response.189 Others argue that costs
should be assigned broadly to all
purchasing customers because of the
concept of cost causation.190 Cost
causation dictates that the costs of
demand response should be allocated
directly to those entities that benefit
from the demand response service
provided.191 Another method presented
involves a bifurcated assignment of
costs, with some directly assigned to a
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 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.
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LSE and others assigned broadly.192 The
fourth method suggested is to directly
assign the costs of demand response to
the retail customer that bid the demand
response into the wholesale market.193
Lastly, the settlement algorithm
proposed by CDRI adjusts upward the
day-ahead price paid by the customers
that participate in the day-ahead energy
market to account for these costs.194
3. Commission Determination
emcdonald on DSK2BSOYB1PROD with RULES2
99. When a demand response
provider curtails, the RTO experiences a
reduction in load with a corresponding
reduction in billing units through which
the RTO derives revenue. When the two
conditions discussed above are met,
however, the RTO must pay LMP to
both generators and demand response
providers for the resources that clear the
energy market. The difference between
the amount owed by the RTO to
resources, including demand response
providers, and the revenue it derives
from load results in a negative balance
that must be addressed through cost
allocation. Therefore, a method is
needed to ensure that RTOs and ISOs
recover the costs of obtaining demand
response.
100. Since the dispatch of demand
response resources affects the LMP
charged, and will result in a lower LMP,
the customers benefitting from that
lower LMP depends upon transmission
constraints, and the price separation
such constraints cause within the RTO.
In some hours in which transmission
constraints do not exist, RTOs establish
a single LMP for their entire system (a
single pricing area) in which case the
demand response would result in a
benefit to all customers on the system.
When transmission constraints are
present, however, LMPs often vary by
zone, or other geographic areas.
Allocating the costs associated with
demand response compensation
proportionally to all entities that
purchase from the relevant energy
market in the area(s) where the demand
response resource reduces the market
price for energy at the time when the
demand response resource is committed
or dispatched will reasonably allocate
the costs of demand response to those
who benefit from the lower prices
192 PJM May 13, 2010 Comments at 12; ISO–NE
May 13, 2010 Comments at 5.
193 DC OPC May 13, 2010 Comments at 4. It
concedes that this could be a complex undertaking
and would result in billing a retail customer for
energy that did not consume. Id.
194 CDRI, Integration of Demand Response Into
Day Ahead Markets (Attachment B), May 13, 2010
Comments at 16.
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produced by dispatching demand
response.195
101. We reject the various other
methods of cost allocation suggested by
commenters. Assignment of all costs to
the LSE associated with the demand
response provider, as suggested by some
commenters, would not include others
who benefit from the demand response.
Bifurcated assignment of costs to the
LSE and to others appears to represent
an arbitrary division of cost
responsibility without regard to the
degree to which each receives benefits.
102. We therefore find just and
reasonable the requirement that each
RTO and ISO allocate the costs
associated with demand response
compensation proportionally to all
entities that purchase from the relevant
energy market in the area(s) where the
demand response reduces the market
price for energy at the time when the
demand response resource is committed
or dispatched. Accordingly, each RTO
and ISO is required to make a
compliance filing on or before July 22,
2011 that either demonstrates that its
current cost allocation methodology
appropriately allocates costs to those
that benefit from the demand reduction
or proposes revised tariff provisions that
conform to this requirement.
E. Commission Jurisdiction
1. Comments
103. Some commenters, including
several State commissions and LSEs,
express concern about whether and how
standardizing demand response
compensation in the wholesale market
will affect treatment of demand
response at the retail level. They assert
that the issue of demand response
compensation is fundamentally
intertwined with retail rates, ratepayer
issues, and State jurisdictional
concerns.196 Some commenters note
general concerns about the need for
Federal and State level coordination.
They assert that many States have taken
significant steps to install advanced
meters and implement programs to
encourage efficient use of energy and
that the success of State-level efforts
should be a factor in deciding whether
and how to implement demand
195 This approach is consistent with long-standing
judicially-endorsed cost allocation principles. See,
e.g., Midwest ISO Transmission Owners v. FERC,
373 F.3d 1361, 1368, 1370–71 (DC Cir. 2004); see
also Illinois Commerce Comm’n v. FERC, 576 F.3d
470, 476 (7th Cir. 2009).
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).
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response programs in the wholesale
market.197 According to these
commenters, a Commission-mandated
compensation level could have the
unintended consequence of retarding
the expansion of price-responsive
demand at the retail level.198
104. Other commenters flatly question
the Commission’s jurisdiction to set the
compensation for demand response in
wholesale energy markets. They argue
that it is within the purview of retail
regulatory authorities to take into
account local policies and concerns, and
the types of demand response being
offered, when determining the
appropriate compensation level.199
Indeed, the California Commission
seeks clarification that this Commission
does not seek to regulate retail customer
rates or seeks LSE oversight authority
traditionally exercised by States. The
California Commission asserts that this
Commission’s actions concerning
CAISO’s Proxy Demand Resource tariff
filing 200 illustrates that demand
response settlement mechanisms are
within the authority of the California
Commission.201
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 market and
robust participation in retail programs, a balance
between these two segments is essential.
Compensation that increases demand response
resource participation in the wholesale market
should not be so generous, from the perspective of
the customer, that it makes participation in retail
programs pale in comparison.’’); SDG&E, SoCal
Edison, and PG&E May 13, 2010 Comments at 4
(‘‘[M]andating that ISOs take on settlement
responsibility or precluding any retail settlement
between retail customers, LSEs or DRPs would
intrude on retail jurisdictional authority and
contravenes the premise of separation outlined in
Order 719.’’); Consumers Energy May 13, 2010
Comments at 3; Detroit Edison May 13, 2010
Comments at 4.
200 See California Independent System Operator
Corp., 132 FERC ¶ 61,045 (2010).
201 California Commission May 13, 2010
Comments at 9–10. 1. See also SDG&E, SCE, PG&E
May 13, 2010 Comments at 2 (‘‘[T]he Commission
should clarify that its order does not preclude LRAs
from administering retail revenue settlements
between retail customers, Load Serving Entities
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105. Other commenters foresee retail
regulatory authorities effectively taking
an end-run around any Commissionmandated compensation level by
adjusting retail rate design or
prohibiting jurisdictional end-use
customers from participating in
wholesale market opportunities
available to demand response
resources.202 The Illinois Commission
argues:
[W]hen load serving entities are vertically
integrated with generation regulated under
state authority * * * any non-zero payment
to a demand response resource reduces the
revenues to generators under the state
regulatory authority. The result is a leakage
of money to an entity outside of the state’s
regulatory authority. Therefore, retail rates to
all customers may need to be increased in
order to recover the costs to generators that
would have otherwise been recovered
through the purchase of electricity, but
instead went to the payment of a demand
response resource. Therefore, compensating
demand response resources may increase the
likelihood that state commissions will
prohibit the participation of demand
response resources in the jurisdictions.203
emcdonald on DSK2BSOYB1PROD with RULES2
106. Similarly, PJM states that the
prohibition devised by retail regulatory
authorities with jurisdiction over
smaller distributors that deliver
4 million MWh or fewer per annum may
entail the revocation of previously
provided permission to participate in
some or all of the wholesale market
opportunities for demand resources.204
107. Some commenters further posit
that, even where retail regulatory
authorities do not prohibit or limit
demand response participation, they
may make adjustments to the retail rate,
which affect the ultimate compensation
that the retail customer will be paid for
its demand reductions.205 For example,
the OMS asserts,
(LSEs) and Demand Response Providers (DRPs)
associated with DR participation in wholesale
markets.’’).
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 nonparticipating customers may exceed the benefits
that ARCs can provide to their States and to
participating customers, so State commissions will
have a significant disincentive to support the
participation of ARCs in RTO energy markets and
in their States if LMP compensation is adopted).
203 Illinois Commission May 13, 2010 Comments
at 15.
204 PJM May 13, 2010 Comments at 20–21.
205 CAISO May 13, 2010 Comments at 4.
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If the Commission were to adopt the
proposed rule, state commissions and LSEs
could correct this distorted price signal by
revising retail tariffs for customers that do
business with [aggregators of retail
customers] in order to charge the retail rate
to participating customers for energy which
was not consumed or metered as a result of
load reductions.206
108. Another set of commenters,
especially generators, assert that due to
the disconnect between wholesale and
retail issues related to demand response,
Commission-mandated payments for
demand response will fail to address
true barriers to demand response, which
exist, they assert, at the retail level.
These commenters argue that the
Commission’s actions in this proceeding
ignore the fact that the primary barrier
to demand response is the disconnect
between retail and wholesale prices
and, according to these commenters, the
remedy resides at the retail—not
wholesale—level where there is a lack
of dynamic pricing.207 For example,
some commenters recognize that the
lack of retail real-time pricing is a
barrier to demand response
participation but further assert that
whatever changes the Commission
makes to wholesale demand response
(where there is real-time pricing) will
not address that fundamental
problem.208
109. On the other hand, some
commenters, such as commercial
customers, wholly reject challenges to
the Commission’s authority to set the
compensation level for demand
response occurring in organized
wholesale energy markets.209 They
assert that the FPA gives the
Commission broad authority to correct
206 OMS May 13, 2010 Comments at 3. See also
EEI May 13, 2010 Comments at 4.
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.
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16675
market flaws, including compensation
for demand response.210
110. Some commenters further argue
that any disconnect between wholesale
and retail issues relevant to demand
response should not negate the
Commission’s efforts in this proceeding.
They argue that dynamic retail pricing,
retail shopping opportunities and the
potential for retail energy efficiency
measures are no substitute for adequate
wholesale demand response
compensation and the deployment of
demand response measures akin to a
generator.211
111. Moreover, some commenters
assert that, while the Commission has
authority to establish the compensation
level for demand response in the
wholesale market, the Commission
cannot require subtraction of retail rate
components from the LMP rate,
reasoning that retail rates reflect a
myriad of local concerns beyond the
Commission’s jurisdiction. These
commenters assert that LMP reflects the
wholesale value of the demand response
service provided and that proponents of
the LMP–G formulation (subtracting a
portion of the retail rate) seek to draw
the Commission into a review of retail
rate matters beyond its purview.212
Additionally, these commenters point to
the difficulty of isolating the generation
component of the retail rate from other
components, such as transmission,
distribution, and overhead. They argue
that different retail rate contracts reflect
different costs of generation, depending
on local circumstances existing at the
time the contract was executed, and that
retail rate structures reflect a wide range
of competing considerations, such as
cost causation, the impact of rate design
on employment, and the state of the
local economy, all of which are
appropriately left to State commissions.
These commenters posit that, instead of
tailoring the wholesale rate, i.e., LMP, to
retail rate conditions, it is better to get
the wholesale rate right in the first
instance and then allow retail rate
structures adjust as needed to wholesale
market conditions.213 According to Dr.
Kahn, accounting for the retail rate in
this Final Rule would ‘‘ignore the proper
scope of the Commission’s regulatory
responsibilities, the fact that the great
majority of retail rate designs are
economically inefficient and that it is
retail rates that should not be permitted
210 Id.
211 Wal-Mart
May 13, 2010 Comments at 11.
June 18, 2010 Comments at 13.
213 Viridity June 18, 2010 Comments at 14.
212 Viridity
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to undermine efficient wholesale rates
rather than the reverse.’’ 214
2. Commission Determination
112. We begin by rejecting challenges
to the Commission’s authority to set the
compensation level for demand
response in organized wholesale energy
markets. Section 205 of the FPA tasks
the Commission with ensuring that all
rates and charges for or ‘‘in connection
with’’ the transmission or sale for resale
of electric energy in interstate
commerce, and all rules and regulations
‘‘affecting or pertaining to’’ such rates or
charges are just and reasonable.215 The
Commission has previously explained
that it has jurisdiction over demand
response in organized wholesale energy
markets, because it directly affects
wholesale rates.216
113. For this reason, the Commission
has jurisdiction to regulate the market
rules under which an ISO or RTO
accepts a demand response bid into a
wholesale market.217 Furthermore, as
discussed above, the Commission’s
actions in this proceeding are consistent
with Congressional policy requiring
Federal level facilitation of demand
response, because this Final Rule is
designed to remove barriers to demand
response participation in the organized
wholesale energy markets.
114. Nevertheless, we recognize that
jurisdiction over demand response is a
complex matter that lies at the
confluence of State and Federal
jurisdiction. By issuing this Final Rule,
the Commission is not requiring actions
that would violate State laws or
regulations. The Commission also is not
regulating retail rates or usurping or
impeding State regulatory efforts
concerning demand response.
115. We acknowledge that many
barriers to demand response
participation exist and that our ability to
address such barriers is limited to the
confines of our statutory authority. At
the same time, the FPA requires the
Commission to ensure that the rates
charged for energy in wholesale energy
markets are just, reasonable, and not
unduly discriminatory or preferential.
The Commission has the authority,
indeed the responsibility, to assure that
wholesale rates are just and reasonable.
Therefore, we disagree with commenters
who would have the Commission
refrain from acting on demand response
compensation in the organized
wholesale energy markets because of the
potential actions that State retail
regulatory authorities may or may not
take. As we note above, this Final Rule
is not intended to usurp State authority
or impede States from taking any
actions within their authority. Rather,
the Commission is taking action here to
fulfill its statutory mandate to ensure
just, reasonable, and not unduly
discriminatory or preferential wholesale
rates.
V. Information Collection Statement
116. The Office of Management and
Budget (OMB) requires that OMB
approve certain information collection
and data retention requirements
imposed by agency rules.218 Therefore,
the Commission is submitting the
proposed modifications to its
information collections to OMB for
review and approval in accordance with
section 3507(d) of the Paperwork
Reduction Act of 1995.219
117. OMB’s regulations require
approval of certain information
collection requirements imposed by
agency rules. Upon approval of a
collection(s) of information, OMB will
assign an OMB control number and an
expiration date. Respondents subject to
the filing requirements of a rule will not
be penalized for failing to respond to
these collections of information unless
the collections of information display a
valid OMB control number.
118. The Commission is submitting
these reporting requirements to OMB for
its review and approval under section
3507(d) of the Paperwork Reduction
Act. Comments are solicited on the
Commission’s need for this information,
whether the information will have
practical utility, the accuracy of
provided burden estimates, ways to
enhance the quality, utility, and clarity
of the information to be collected, and
any suggested methods for minimizing
the respondent’s burden, including the
use of automated information
techniques.
Burden Estimate and Information
Collection Costs: The estimated Public
Reporting burden and cost for the
requirements contained in the final rule
follow.
Number of
respondents
Compliance filing, including tariff provisions and analysis (one-time filing, due
7/22/2011).
Study on dynamic net benefits approach (one-time filing, due 9/21/2012) .........
emcdonald on DSK2BSOYB1PROD with RULES2
Monthly update to price threshold and Web posting (due monthly, starting after
the compliance filing due 7/22/2011).
Number of
responses
per respondent per year
Hours per
response
Total annual
hours
(a)
FERC–516 data collection
(b)
(c)
(d) [a*b*c]
6 (RTOs and
ISOs).
6 (RTOs and
ISOs).
6 (RTOs and
ISOs).
1 (one-time
filing).
1 (one-time
filing).
12 .................
300
2,000
50
1,800 (onetime filing).
12,000 (onetime filing).
3,600.
In Year 1, the following requirements
are imposed 220: (1) Compliance filing
due on or before July 22, 2011, and (2)
monthly updates (for months 5–12, and
starting after the compliance filing). The
total corresponding burden hours are
estimated to be: 1,800 hrs. + (8 filings
* 6 respondents * 50 hrs./filing), for a
total of 4,200 hours. The corresponding
total cost is estimated to be: 4,200 hours
* $220/hour, for a total of $924,000.
In Year 2, (a) the monthly update to
the price threshold, and (b) the study on
dynamic net benefits approach (due on
or before September 21, 2012) are
imposed. The corresponding total
burden is estimated to be 3,600 + 12,000
hours, for a total of 15,600 hours. The
corresponding total cost estimate is:
15,600 hours * $220/hour, for a total of
$3,432,000.
In Year 3, the monthly update to the
price threshold is imposed. The
corresponding total burden and cost are
214 DR Supporters Aug. 30, 2010 Comments (Kahn
Affidavit at 4).
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.
218 5 CFR 1320.11(b) (2010).
219 44 U.S.C. 3507(d) (2006).
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.
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Federal Register / Vol. 76, No. 57 / Thursday, March 24, 2011 / Rules and Regulations
estimated to be 3,600 hours and
$792,000 (3,600 hours * $220/hour).
Title: FERC–516, ‘‘Electric Rate
Schedules and Tariff Filings’’.
Action: Proposed Collections.
OMB Control No: 1902–0096.
Respondents: Business or other for
profit, and/or not for profit institutions.
Frequency of Responses: One-time
filings for (a) the compliance filing, due
on or before July 22, 2011, and (b) the
study on dynamic net benefits
approach, due on or before September
21, 2012. In addition, monthly updates
to the price threshold and Web posting
will be required starting after the
compliance filing.
Necessity of the Information: The
information from FERC–516 enables the
Commission to exercise its statutory
obligation under sections 205 and 206 of
the FPA. FPA section 205 specifies that
all rates and charges, and related
contracts and service conditions for
wholesale sales and transmission of
energy in interstate commerce be filed
with the Commission and must be ‘‘just
and reasonable.’’ In addition, FPA
section 206 requires the Commission,
upon complaint or its own motion, to
modify existing rates or services that are
found to be unjust, unreasonable,
unduly discriminatory or preferential.
119. In Order No. 719, the
Commission emphasized the
importance of demand response as a
vehicle for improving the
competitiveness of organized wholesale
electricity markets and ensuring
supplies of energy at just, reasonable
and not unduly discriminatory or
preferential rates. This Final Rule
addresses the need for organized
wholesale energy markets to provide
compensation to demand response
resources on a comparable basis to
supply-side resources when demand
response resources are comparable to
supply-side resources, so that both
supply and demand can meaningfully
participate. This final rule establishes a
specific compensation approach for
demand response resources
participating in organized wholesale
energy markets, administered by RTOs
and ISOs. Each Commission-approved
RTO and ISO that has a tariff provision
providing for participation of demand
response resources in its organized
wholesale energy market must: (a) Pay
demand response resources the market
price (full LMP) for energy (when found
to be cost-effective as determined by the
net benefits test described herein), (b)
submit a one-time compliance filing, (c)
perform monthly updates to the Price
Threshold, and (d) submit a one-time
Study on Dynamic Net Benefits
Approach.
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120. Interested persons may obtain
information on the reporting
requirements by contacting: Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC 20426
[Attention: Ellen Brown, Information
Clearance Officer, Office of the
Executive Director, e-mail:
DataClearance@ferc.gov, phone: (202)
502–8663, fax: (202) 273–0873].
Comments on the requirements of the
final rule may also be sent to the Office
of Information and Regulatory Affairs,
Office of Management and Budget,
Washington, DC 20503 [Attention: Desk
Officer for the Federal Energy
Regulatory Commission]. For security
reasons, comments to OMB should be
submitted by e-mail to:
oira_submission@omb.eop.gov.
Comments submitted to OMB should
include Docket Number RM10–17 and
OMB Control Number 1902–0096.
VI. Environmental Analysis
121. The Commission is required to
prepare an Environmental Assessment
or an Environmental Impact Statement
for any action that may have a
significant adverse effect on the human
environment.221 The Commission
concludes that neither an
Environmental Assessment nor an
Environmental Impact Statement is
required for this Final Rule under
section 380.4(a)(15) of the Commission’s
regulations, which provides a
categorical exemption for approval of
actions under sections 205 and 206 of
the FPA relating to the filing of
schedules containing all rates and
charges for the transmission or sale
subject to the Commission’s
jurisdiction, plus the classification,
practices, contracts, and regulations that
affect rates, charges, classifications, and
services.222
VII. Regulatory Flexibility Act
122. The Regulatory Flexibility Act of
1980 (RFA) 223 generally requires a
description and analysis of final rules
that will have significant economic
impact on a substantial number of small
entities. The RFA mandates
consideration of regulatory alternatives
that accomplish the stated objectives of
a rule and that minimize any significant
economic impact on a substantial
number of small entities. The Small
Business Administration’s (SBA) Office
of Size Standards develops the
numerical definition of a small
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).
223 5 U.S.C. 601–612 (2006).
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16677
business.224 The SBA has established a
size standard for electric utilities,
stating that a firm is small if, including
its affiliates, it is primarily engaged in
the transmission, generation and/or
distribution of electric energy for sale
and its total electric output for the
preceding twelve months did not exceed
four million megawatt hours.225 ISOs
and RTOs, not small entities, are
impacted directly by this rule.
123. California Independent System
Operator Corp. (CAISO) is a non-profit
organization with over 54,000
megawatts of capacity and over 25,000
circuit miles of power lines.
124. New York Independent System
Operator, Inc. (NYISO) is a non-profit
organization that oversees wholesale
electricity markets, dispatches over 500
generators, and manages a nearly
11,000-mile network of high-voltage
lines.
125. PJM Interconnection, L.L.C.
(PJM) is comprised of more than 600
members including power generators,
transmission owners, electricity
distributors, power marketers, and large
industrial customers, serving 13 States
and the District of Columbia.
126. Southwest Power Pool, Inc. (SPP)
is comprised of 61 members serving
over 6.2 million households in nine
States and has almost 50,000 miles of
transmission lines.
127. Midwest Independent
Transmission System Operator, Inc.
(Midwest ISO) is a non-profit
organization with over 145,000
megawatts of installed generation.
Midwest ISO has over 57,000 miles of
transmission lines and serves 13 States
and one Canadian province.
128. ISO New England, Inc. (ISO–NE)
is a regional transmission organization
serving six States in New England. The
system is comprised of more than 8,000
miles of high-voltage transmission lines
and over 350 generators.
129. The Commission believes this
rule will not have a significant
economic impact on a substantial
number of small entities, and therefore
no regulatory flexibility analysis is
required.
VIII. Document Availability
130. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to
view and/or print the contents of this
document via the Internet through the
Commission’s Home Page (https://
www.ferc.gov) and in the Commission’s
Public Reference Room during normal
224 13
225 13
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CFR 121.201, Sector 22, Utilities.
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business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE.,
Room 2A, Washington DC 20426.
131. From the Commission’s Home
Page on the Internet, this information is
available on eLibrary. The full text of
this document is available on eLibrary
in PDF and Microsoft Word format for
viewing, printing, and/or downloading.
To access this document in eLibrary,
type the docket number excluding the
last three digits of this document in the
docket number field.
132. User assistance is available for
eLibrary and the Commission’s Web site
during normal business hours from
FERC Online Support at 202–502–6652
(toll free at 1–866–208–3676) or e-mail
at ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. E-mail the
Public Reference Room at
public.referenceroom@ferc.gov.
IX. Effective Date and Congressional
Notification
133. This Final Rule will become
effective on April 25, 2011. The
Commission has determined, with the
concurrence of the Administrator of the
Office of Information and Regulatory
Affairs, Office of Management and
Budget, that this rule is not a ‘‘major
rule’’ as defined in section 351 of the
Small Business Regulatory Enforcement
Fairness Act of 1996.
By the Commission. Commissioner Moeller
dissenting with a separate statement
attached.
Kimberly D. Bose,
Secretary.
In consideration of the foregoing, the
Commission amends part 35, chapter I,
title 18, Code of Federal Regulations, as
follows.
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for Part 35
continues to read as follows:
■
Authority: 16 U.S.C. 791a–825r, 2601–
2645; 31 U.S.C. 9701; 42 U.S.C. 7101–7352.
2. Amend § 35.28 by adding a new
paragraph (g)(1)(v) to read as follows:
■
§ 35.28 Non-discriminatory open access
transmission tariff.
emcdonald on DSK2BSOYB1PROD with RULES2
*
*
*
*
*
(g) * * *
(1) * * *
(v) Demand response compensation in
energy markets. Each Commissionapproved independent system operator
or regional transmission organization
that has a tariff provision permitting
demand response resources to
participate as a resource in the energy
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market by reducing consumption of
electric energy from their expected
levels in response to price signals must:
(A) Pay to those demand response
resources the market price for energy for
these reductions when these demand
response resources have the capability
to balance supply and demand and
when payment of the market price for
energy to these resources is costeffective as determined by a net benefits
test accepted by the Commission;
(B) Allocate the costs associated with
demand response compensation
proportionally to all entities that
purchase from the relevant energy
market in the area(s) where the demand
response reduces the market price for
energy at the time when the demand
response resource is committed or
dispatched.
*
*
*
*
*
Note: The following appendices will not be
published in the Code of Federal Regulations.
Appendix 1—List of Commenters
Alcan Primary Products Corp. (Alcan)
Alcoa Inc. (Alcoa)
Alliance for Clean Energy New York, Inc.
(ACENY)
Alliance to Save Energy (Alliance)
American Chemistry Council (ACC)
American Clean Skies Foundation
American Council for an Energy-Efficient
Economy (ACEEE)
American Electric Power Service Corporation
(AEP)
American Forest & Paper Association (AFPA)
American Municipal Power, Inc. (AMP)
American Public Power Association (APPA)
American Wind Energy Association (AWEA)
ArcelorMittal USA Inc. (ArcelorMittal)
Battelle Pacific Northwest Laboratories
(Battelle)
Boston College Law School Administrative
Law Class (BC Law)
California Department of Water Resources
State Water Project (CDWR)
California Independent System Operator
Corporation (CAISO)
California Public Utilities Commission
(California Commission)
Calpine Corp. (Calpine)
Capital Power Corporation (Capital Power)
Cities of Anaheim, Azusa, Banning, Colton,
Pasadena, and Riverside, California (Six
Cities)
Citizens for Pennsylvania’s Future
(PennFuture)
Coalition of Midwest Transmission
Customers (CMTC)
Connecticut Municipal Electric Energy
Cooperative (CMEEC)
Consert Inc. (Consert)
Conservation Law Foundation (CLF)
Consolidated Edison Solutions, Inc. (ConEd)
Constellation Energy Commodities Group,
Inc. (Constellation)
Consumer Demand Response Initiative
(CDRI)
Consumer Power Advocates (CPA)
Consumers Energy Company (Consumers
Energy)
PO 00000
Frm 00022
Fmt 4701
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CPG Advisors, Inc. (CPG)
CPower, Inc. (CPower)
Crane & Co., Inc. (Crane)
Delaware Public Service Commission
(Delaware Commission)
Demand Response and Smart Grid Coalition
(Smart Grid Coalition)
Demand Response Supporters (DR
Supporters)
Derstine’s Inc. (Derstine’s)
Detroit Edison Company (Detroit Edison)
Direct Energy Services, LLC (Direct Energy)
Dominion Resources Services, Inc.
(Dominion)
Dr. Alfred E. Kahn (Dr. Kahn)
Dr. Charles J. Cicchetti (Dr. Cicchetti)
Dr. Roy J. Shanker (Dr. Shanker)
Dr. William W. Hogan (Dr. Hogan)
Duke Energy Corporation (Duke Energy)
Durgin and Crowell Lumber Co., Inc.
(Durgin)
Edison Electric Institute (EEI)
Edison Mission Energy (Edison Mission)
Electric Power Supply Association (EPSA)
Electricity Committee
Electricity Consumers Resource Council
(ELCON)
Electrodynamics, Inc. (Electrodynamics)
Energy Curtailment Specialists, Inc. (ECS)
EnergyConnect (EnergyConnect)
Energy Future Coalition (EFC)
EnerNOC, Inc. (EnerNOC)
Environmental Defense Fund (EDF)
Exelon Corporation (Exelon)
Federal Trade Commission (FTC)
FirstEnergy Service Company (FirstEnergy)
GDF SUEZ Energy North America, Inc. (GDF)
Hess Corporation (Hess)
Illinois Citizens Utility Board (Illinois CUB)
Illinois Commerce Commission (ICC)
Independent Power Producers of New York,
Inc. (IPPNY)
Indicated New York Transmission Owners
(Indicated New York TOs)
Industrial Energy Consumers of America
(IECA)
Industrial Energy Consumers of Pennsylvania
(IECPA)
Intergrys Energy Services, Inc. (Intergrys)
International Power America, Inc. (IPA)
Irving Forest Products, Inc. (Irving Forest)
ISO New England Inc. (ISO–NE)
ISO–NE Internal Market Monitor (ISO–NE
IMM)
Jiminy Peak Mountain Resort, LLC
Joint Consumer Advocates (Joint Consumers)
Limington Lumber (Limington)
Madison Paper Industries (Madison Paper)
Maryland Governor Martin O’Malley
(Governor O’Malley)
Maryland Public Service Commission
(Maryland Commission)
Massachusetts Attorney General
(Massachusetts AG)
Midwest Independent Transmission System
Operator, Inc. (Midwest ISO)
Midwest ISO Transmission Owners (Midwest
ISO TOs)
Midwest TDUs
Mirant Corporation (Mirant)
Monitoring Analytics, LLC (PJM IMM)
National Electrical Manufactures Association
(NEMA)
National Energy Marketers Association
(NEM)
National Grid USA (National Grid)
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National League of Cities (NLC)
Natural Gas Supply Association (NGSA)
New England Conference of Public Utilities
Commissioners (NECPUC)
New England Consumer Advocates (NECA)
New England Power Generators Association
Inc. (NEPGA)
New England Power Pool Participants
Committee (NEPOOL)
New England Public Systems (NE Public
Systems)
New Jersey Board of Public Utilities (NJBPU)
New York Independent System Operator, Inc.
(NYISO)
New York Mayor Michael R. Bloomberg
(Mayor Bloomberg)
New York State Consumer Protection Board
(NYSCPB)
New York State Public Service Commission
(New York Commission)
North America Power Partners LLC (NAPP)
Northeast Utilities Services Company
(NUSCO)
Northern California Power Agency (NCPA)
NSTAR Electric Company (NSTAR)
Occidental Chemical Corp. (Occidental)
Office of the People’s Counsel for the District
of Columbia (DC OPC)
Okemo Mountain Resort (Okemo)
Old Dominion Electric Cooperative (ODEC)
Organization of Midwest ISO States (OMS)
Partners HealthCare (Partners)
Pennsylvania Department of Environmental
Protection (PA Department of
Environment)
Pennsylvania Office of Consumer Advocate
(PCA)
Pennsylvania Public Utility Commission
(Pennsylvania Commission)
Pennsylvania State Representative Chris Ross
(Rep. Ross)
Pepco Holdings, Inc. (PHI)
PJM Interconnection, L.L.C. (PJM)
PJM Power Providers Group (P3)
Potomac Economics, Ltd. (Potomac
Economics)
PPL Parties (PPL)
Praxair, Inc. (Praxair)
Precision Lumber, Inc. (Precision)
Price Responsive Load Coalition (PRLC)
PSEG Companies (PSEG)
Public Interest Organizations (PIO)
Public Utilities Commission of Ohio (Ohio
Commission)
Raritan Valley Community College (Raritan)
Robert J. Borlick (Mr. Borlick)
RRI Energy, Inc. (RRI)
San Diego Gas & Electric Company (SDG&E)
Schneider Electric USA, Inc. (Schneider)
Southern California Edison Company (SoCal
Edison)
Southwest Power Pool, Inc. (SPP)
Steel Manufacturers Association (Steel
Manufacturers Ass’n)
Steel Producers (SP)
Tendrill Networks, Inc. (Tendrill)
The Brattle Group
The E Cubed Company, L.L.C. (E3)
University of California, San Diego (UCSD)
Utility Economic Engineers (UEE)
Verso Paper Corp. (Verso)
Virginia Committee for Fair Utility Rates
(Virginia Committee)
Viridity Energy, Inc. (Viridity)
Wal-Mart Stores, Inc. (Wal-Mart)
Waterville Valley Ski Resort Inc. (Waterville)
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Westar Energy, Inc. (Westar)
Wisconsin Industrial Energy Group (WIEG)
Appendix 2—Dissenting Statement
UNITED STATES OF AMERICA FEDERAL
ENERGY REGULATORY COMMISSION
Demand Response Compensation in
Organized Wholesale Energy Markets
Docket No. RM10–17–000
(Issued March 15, 2011)
MOELLER, Commissioner, dissenting:
While the merits of various methods for
compensating demand response were
discussed at length in the course of this
rulemaking, nowhere did I review any
comment or hear any testimony that
questioned the benefit of having demand
response resources participate in the
organized wholesale energy markets. On this
point, there is no debate. The fact is that
demand response plays a very important role
in these markets by providing significant
economic, reliability, and other marketrelated benefits.
However, in a misguided attempt to
encourage greater demand response
participation in the organized energy
markets, today’s Rule imposes a standardized
and preferential compensation scheme that
conflicts both with the Commission’s efforts
to promote competitive markets and with its
statutory mandate to ensure supplies of
electric energy at just, reasonable, and not
unduly discriminatory or preferential rates.1
For these reasons, I cannot support this Rule.
Standardizing Demand Response
Compensation
As an initial matter, RTOs and ISOs
currently offer different types of demand
response products that vary from region to
region and in terms of capability and services
offered in the day-ahead and real-time energy
markets. Moreover, the RTOs and ISOs to
date have been working with their market
participants in a stakeholder process to
design demand response compensation rules
that are tailored to suit the needs of their
individual energy markets. However, this
will all change once the Rule takes effect and
this existing framework is replaced with the
requirement that every organized wholesale
energy market pay demand resources the
market price for energy (LMP) when its
demand reductions are, in theory, found to
be cost-effective.
As I recognized in my initial statement in
this proceeding, organized markets such as
the PJM Interconnection have already
demonstrated the ability to develop demand
response compensation rules. Accordingly, I
would have preferred to allow these markets
to continue to develop their own rules.
Different demand response products will
have different values that reflect their varying
capabilities and to require a standard
payment fails to reflect these meaningful
differences.2
1 16
U.S.C. § 824d (2006).
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
2 California
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16679
However, without ever determining that
the existing region-by-region approach to
compensation is unjust and unreasonable,
the Rule implies that the current approach is
no longer adequate to ensure that rates
remain just and reasonable. In turn, the Rule
finds that ‘‘greater uniformity in
compensating demand response resources’’ is
required and as justification for its action,
references the existence of various barriers
that limit the participation of demand
response in the energy markets.3 The
majority ultimately concludes that these
barriers can be removed by better equipping
demand response providers with the
financial resources to invest in enabling
technologies.4 This is to say that the majority
believes that paying demand resources more
money will help overcome these barriers and
encourage more participation. The Rule,
however, never clearly explains how the
existence of barriers, in turn, justifies a
payment of full LMP to demand resources.
The Rule (like the NOPR) does not
sufficiently discuss the need for
standardizing compensation across the
organized markets or elaborate on how
standardization will remove genuine barriers
that prevent meaningful participation by
demand resources in the energy markets.5
While the Energy Policy Act of 2005 states
that the policy of the U.S. Government is to
remove unnecessary barriers to demand
response, the statute never authorized the
Commission to stimulate increased demand
response participation by requiring its
compensation to include incentives or
preferential treatment.6 Although, the
majority is quick to claim ‘‘that removing
barriers to demand response participation is
not the same as giving preferential treatment
to demand response providers * * *’’, this is
exactly what is occurring in this Rule.7 As
discussed below, the majority’s
determination is troubling as the Rule both
affords preferential treatment to demand
response resources and unduly discriminates
against them in other respects.
Demand Response Resources are Comparable
* * * Sometimes
At the outset, the concept of
‘‘comparability’’ is at the core of this
rulemaking, i.e., whether demand response
resources are capable of providing a service
comparable to generation resources and if so,
whether these resources should receive
comparable compensation for a comparable
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.
6 See Energy Policy Act of 2005, Pub. L. No. 109–
58, § 1252(f), 119 Stat. 594, 965 (2005).
7 Rule at P 59.
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service. On this point, I believe they should.8
This is not to say that a megawatt produced
is the same as a megawatt not consumed;
they are not perfect equivalents. The
characteristics of a megawatt and a
‘‘negawatt’’ are different, both in terms of
physics and in economic impact.
Assuming, however, that a demand
resource can provide a balancing service that
is identical to that of a generation resource,
it would make sense that a demand resource
providing a comparable service would
receive comparable compensation. But this
may not occur under the Rule. The majority
explains that if a demand resource is capable
of providing a service comparable to a
generation resource, it will only be eligible to
receive comparable compensation, by
definition, if it can also be determined that
the resource will result in a price-lowering
effect to the market by passing a net benefits
test.9
In no other circumstance is a resource
required to show that its participation will
depress the market price in order to receive
comparable compensation for a comparable
service.10 Such a definition unduly
discriminates against demand resources and
as such, this requirement is unjust,
unreasonable, and unduly discriminatory.
emcdonald on DSK2BSOYB1PROD with RULES2
Overcompensating Demand Resources and
the Net Benefits Test
At first glance, the Rule’s requirement that
RTOs and ISOs pay demand response
resources the LMP only when it is deemed
cost-effective appears to make sense. There is
near-universal agreement that the LMP
reflects the value of the marginal unit, and
as such, it sends the proper price signal to
keep supply and demand in relative balance.
Accordingly, the Rule explains that if the
demand resource is capable of providing a
comparable service and is also cost-effective
(i.e., using a net benefits test to ensure that
the overall benefit of the reduced LMP that
results from dispatching demand recourses
exceeds the cost of dispatching those
resources), then this resource should be paid
the same as a generation resource. However,
the decision to pay demand resources the full
LMP under such circumstances actually
results in overcompensation that is
economically inefficient, preferential to
demand resources, and unduly
discriminatory towards other market
resources.
An example may help to illustrate a major
flaw with this Rule. Assume that both a
generation resource and a demand resource
bid into the energy market and both bids are
accepted and paid the LMP ($100). Then
consider the fact that the demand resource
8 As explained below, I believe that comparable
compensation is represented by the value realized
by the demand resource for providing a comparable
service, regardless of whether the source of that
value is a payment from the market or a savings by
the resource.
9 Rule at P 47–50.
10 Testimony of Audrey Zibelman, President and
CEO of Viridity Energy, Inc., Sept. 13, 2010 Tr. at
119, ‘‘[T]he fact that we’re debating this [net benefits
test] is somewhat absurd. We have not required any
other resource to demonstrate a benefit in order to
enter this market.’’
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will save an amount that it would have
otherwise paid by not purchasing generation
at the retail rate (‘‘G’’), which is $25. While
the Rule requires that RTOs and ISOs pay the
demand resource the LMP (which is the
identical amount the generation resource
receives), the Rule effectively ignores the fact
that the demand resource will actually
receive a total compensation of LMP+G
($125) as a result of its decision not to
consume.11 Meanwhile, the generation
resource will only receive the LMP ($100)
payment as a result of its decision to
produce. While the Rule’s intent is to ensure
that a demand resource receives ‘‘the same
compensation, the LMP, as a generation
resource’’, this is not the actual result.12 In
this example, what will happen is that the
Rule will require that the demand response
resource be overcompensated by $25.13
The Rule effectively finds that demand
resources being compensated at the value of
full LMP is not enough, so instead requires
that demand resource be paid the full LMP
plus be allowed to retain the savings
associated with its avoided retail generation
cost. Professor William W. Hogan refers to
this outcome as a ‘‘double-payment’’ because
demand resources would ‘‘receive’’ both the
cost savings from not consuming electricity
at a particular price, plus an LMP payment
for not consuming that same increment of
electricity.14 Not only is this result not
comparable (by valuing a negawatt more than
a megawatt) and economically inefficient (by
distorting the price signal), but this
preferential compensation will harm the
efficiency of the competitive wholesale
energy markets.
The use of a net benefits test further
reduces competitive efficiency and only
complicates the issue. As the Rule explains,
the net benefits test involves the
determination of a threshold price point that
is plotted along a historical supply curve in
an attempt to accurately calculate whether
the cost of procuring additional demand
response is outweighed by the value it brings
to the market in the form of a lower LMP.15
11 The proper economic measure of value realized
by the demand resource is one where the RTO or
ISO makes a reduction from the LMP to account for
the retail rate, but then recognizes that the savings
associated with the avoided retail generation cost
should be added back into the equation, i.e., (LMP–
G)+G.
12 Rule at P 82. If it were the result, the generation
resource would be paid the LMP, $100, and the
demand resource would be paid $75 and realize an
additional $25 in retail rate savings. Accordingly,
both resources realize equivalent compensation
valued at $100.
13 Ohio Commission May 13, 2010 Comments at
6, ‘‘[T]he Commission’s proposal that RTOs pay
demand response resources the full LMP takes the
incentives for wholesale demand response
resources a step too far. It would provide an
incentive to the supplier of a demand response
resource that exceeds the payments available to an
equivalent supply resource. The Commission
should instead focus on removing the existing
barriers in the wholesale markets * * *.’’
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
PO 00000
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However, this test, which attempts to justify
the LMP payment by promising a ‘‘win-win’’
outcome, is nothing more than a fig leaf that
provides little protection against the longterm potential for unintended market
damage. As recognized by ISO–NE,
generation is not dispatched and paid for
only when such generation reduces LMP,
instead generation is dispatched and paid for
only when it is cost-effective.16 Likewise,
logic would require that demand resources be
treated similar to generation resources and be
similarly cost-effective.
During a technical conference convened to
discuss the specific question on the necessity
of a net benefits test, the Commission heard
testimony from a panel of experts. A clear
majority of the witnesses (representing a
spectrum of interests that included demand
response advocates, economists, generators,
and the RTOs and ISOs) argued against the
use of a complicated and admittedly
imprecise 17 net benefits test.18 Chief among
their concerns was that a net benefits test is
unnecessary since the market clearing
function in a wholesale market, by definition,
serves to guarantee that the resource that
clears the market is the lowest-cost
resource.19 Other experts commented that the
net benefits test would be complicated, costly
to implement, and of little value.20 Notably,
Dr. Alfred E. Kahn, the majority’s oft-quoted
expert in defense of the full LMP payment,
did not opine on the merit of subjecting the
LMP payment to a net benefits test.
Further, as explained by Dr. Roy J.
Shanker, if the Commission adopted the
payment of LMP minus the retail rate (‘‘G’’),
then there is no need for a net benefits test
since the customer is paid the difference
between the LMP and what they would have
paid under their retail rate, which is their net
benefit.21 He testified that the ‘‘Net Benefits
46–47, ‘‘Administratively constructing an LMPbased break point for compensating Demand
Response participation would ignore many other
qualitative and quantitative benefits of Demand
Response. Focusing only on the LMP impacts of
Demand Response is problematic.’’
16 ISO–NE May 13, 2010 Comments at 3–4.
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 costeffective.’’
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.’’
21 Testimony of Roy J. Shanker, Ph.D, PJM Power
Providers Group, Sept. 13, 2010 Tr. at 60, ‘‘If the
Commission adopts the appropriate nondiscriminatory pricing for Demand Response, and
payment of LMP minus the retail rate in the context
of customer that face a fixed retail rate, then there
is no need for a Net Benefits test.’’
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criteria is troubling in and of itself, as it
explicitly incorporates consideration of
portfolio effects caused by the reduced
demand on all load payments, versus the
economic decision-making of individual
market participants pursuing their own
legitimate business purpose.’’ 22
I similarly agree that this test is
unnecessary and will only distort price
signals by attracting more demand response
than is economically efficient.23 The use of
a net benefits test also is troubling in that the
Commission’s decision can be viewed as
somehow equating the concept of a just and
reasonable rate with a lower price.24
However, I recognize that to defend its
compensation scheme, the majority needed
some proposal that could arguably
demonstrate that the cost of paying full LMP
to demand resources would be outweighed
by the ‘‘benefit’’ of a lower market price.25
The net benefits test serves this unenviable
role.
Relationship to State Retail Regulation
The Rule recognizes that the demand
resource will retain the retail rate (‘‘G’’) as
part of the provider’s total compensation, but
declines to account for this savings citing
‘‘practical difficulties’’ for State commissions,
RTOs and ISOs.26 While the authority over
retail rates is properly within the jurisdiction
of the State commissions, under the LMP–G
equation, the RTO/ISO merely subtracts the
retail rate; it does not interfere with the retail
rate in any way.27 Although the Rule refers
22 Id.,
Tr. at 61.
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.’’
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
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23 EPSA
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to the New York Commission’s position that
subtracting the retail rate would be an
‘‘administrative burden’’ or create ‘‘undue
confusion’’ 28, other State commissions
disagree and contend that the retail rate can
be deducted without any concern about
impacting the States’ retail jurisdiction.29
Moreover, the Rule does not conclude that
LMP–G would interfere with the retail
jurisdiction of the States, but goes as far as
to acknowledge the subtraction of G is
‘‘perhaps feasible.’’ 30 The fact is that this
calculation is quite feasible. Markets such as
the PJM Interconnection currently subtract
the retail rate portion from the LMP payment
and there is no evidence that accounting for
the retail rate by making the necessary
reduction is either burdensome or interferes
with the retail jurisdiction of State
commissions.31
The Unintended Consequences of Paying Too
Much
Today’s determination, unencumbered by
‘‘textbook economic analysis of the markets
subject to our jurisdiction’’ will undoubtedly
have effects, both in the short-term and the
long-term.32 The intended consequence of
providing additional compensation to
demand resources is that demand response
participation will increase in the energy
markets. In turn, this additional demand
response participation will have the effect of
lowering the market price. However, it is at
this point where the unintended effects will
begin to appear.
With a reduced LMP, the price signal sent
to customers will be that the cost of power
is cheaper so they may decide to use more
power even though the real cost of producing
that power is now higher. Such a result turns
the concept of scarcity pricing on its head
and results in an economically inefficient
outcome. Conversely, customers who are
demand response providers now stand to
issue a charge for energy that was not consumed.
We would be doing what would be perceived as a
take-back by that customer. And that would put us
in a very difficult position.’’
28 Rule at P 28. Significantly, the New York
Commission ‘‘acknowledges the overstated price
signal inherent in an LMP-based formula for DR
compensation * * *.’’ ‘‘Although we understand
that an LMP demand response compensation
formula may result in uneconomic demand
response decisions in the markets (i.e., a price
signal that exceeds marginal cost), it also creates an
incentive to participate in DR programs * * *.’’
New York Commission May 13, 2010 Comments at
5–6 (emphasis added).
29 Illinois Commission May 13, 2010 Comments
at 13, ‘‘[I]f tariffs are well designed, controversy over
the jurisdictional issue can be avoided. Requiring
an ex ante approval of the retail rate to be
subtracted from the LMP at the time demand
response resources are utilized * * * accomplishes
this design.’’ See also Indiana Commission
September 16, 2009 Comments at 3 (Docket No.
EL09–68), ‘‘LMP–G is an accepted indicator of costeffectiveness. 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.
PO 00000
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Fmt 4701
Sfmt 4700
16681
receive more than the market price as an
incentive to curtail their consumption and
will begin to make inefficient decisions about
using power.33 Such inefficiencies will result
in customers experiencing a short-term
benefit by way of a lower LMP, but will also
impose long-term costs on the energy
markets.34
The long-term costs of allowing demand
resources to receive preferential
compensation will manifest themselves in
various ways. As noted in my initial
statement in this proceeding, the lack of
dynamic prices at the retail level is the
primary barrier to demand response
participation. This Rule does not remedy this
barrier and customers who pay fixed retail
rates will not benefit from lower wholesale
market prices. Meanwhile, at the wholesale
level, the corrosive effect of
overcompensating demand resources over
time will come at the expense of other
resources, particularly generation resources
that will have less to invest in maintaining
existing facilities and financing new
facilities.35
The Commission’s recent progress in
promoting competitive wholesale energy
markets has the potential to be undone as a
result of this well-meaning, but misguided
Rule. I believe in the proven value of market
solutions and therefore agree with the
majority’s statement that ‘‘while the level of
compensation provided to each resource
affects its willingness and ability to
participate in the market, ultimately the
markets themselves will determine the level
of generation and demand response resources
needed for purposes of balancing the
electricity grid.’’ 36 That’s precisely how
markets should work. Price signals will
attract resources and new investment when
prices are high, and perhaps not so much
33 Federal Trade Commission May 13, 2010
Comments at 6, ‘‘If customers have to pay the retail
price for power they use but pay nothing for power
they resell, then they will have incentives to resell
power in situations in which it would be more
beneficial for society for them to consume it.’’ See
also EPSA May 13, 2010 Comments at 23; APPA at
13; FTC at 9; Midwest TDUs at 14; Mirant at 2; New
York Commission at 5; PJM at 6; PSEG at 5; and
Potomac Economics at 6–8.
34 PJM’s Independent Market Monitor (a/k/a
Monitoring Analytics, LLC) Oct. 16, 2009
Comments at 7–8 (Docket No. EL09–68), ‘‘Demand
side resources are not generation. In a well
functioning market, demand-side resources avoid
paying the market price of energy when they choose
not to consume. This allows customers to make
efficient decisions about using power. It also
follows that a customer receiving more than the
market price as an incentive to curtail will make
inefficient decisions about using power, and that
this inefficiency imposes a cost rather than
providing a benefit to society.’’
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.’’
36 Rule at P 59.
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when prices are low.37 If the playing field is
level, resources can compete to the best of
their abilities and efficient, cost-effective
market outcomes will result.
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37 PJM Interconnection’s experience with paying
LMP–G for demand response in its energy market
provides an example of how market fundamentals
properly influence demand resource participation.
PJM’s Independent Market Monitor recently
reported that ‘‘[p]articipation levels through
calendar year 2009 and through the first three
months of 2010 were generally lower compared to
prior years due to a number of factors, including
lower price levels, lower load levels, and improved
measurement and verification, but have showed
strong growth through the summer period as price
levels and load levels have increased. Citing
Monitoring Analytics, LLC, 2010 State of the
Market Report for PJM at 30 (March 10, 2011)
(emphasis added).
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As noted earlier, I would have preferred
that we allow the regional markets to
continue to develop their own compensation
proposals. However, I also recognize that
returning to a pre-NOPR era would be
difficult now that the Commission has
signaled a new policy of standardized
compensation. Accordingly, if I were to now
support any standardization of demand
response compensation, it would be the
LMP–G approach, which in my opinion, is
the only economically efficient outcome for
the markets.
Ultimately, the Rule, by requiring demand
resources to artificially suppress the market
price in order to receive incomparable
compensation, will negatively impact the
long-term competitiveness of the organized
PO 00000
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Fmt 4701
Sfmt 9990
wholesale energy markets.38 As such, lacking
sufficient rationale, I cannot support this
Rule as it violates the Commission’s statutory
mandate to ensure supplies of electric energy
at just, reasonable, and not unduly
discriminatory or preferential rates.
lllllllllllllllllllll
Philip D. Moeller
Commissioner
[FR Doc. 2011–6490 Filed 3–23–11; 8:45 am]
BILLING CODE 6717–01–P
38 Federal Power Act § 205(a), 16 U.S.C. § 824d
(2006), ‘‘[A]ll rules and regulations affecting or
pertaining to such rates or charges shall be just and
reasonable, and any such rate or charge that is not
just and reasonable is hereby declared to be
unlawful.’’
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]]>Agencies
[Federal Register Volume 76, Number 57 (Thursday, March 24, 2011)]
[Rules and Regulations]
[Pages 16658-16682]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-6490]
[[Page 16657]]
Vol. 76
Thursday,
No. 57
March 24, 2011
Part II
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Demand Response Compensation in Organized Wholesale Energy Markets;
Final Rule
Federal Register / Vol. 76 , No. 57 / Thursday, March 24, 2011 /
Rules and Regulations
[[Page 16658]]
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket No. RM10-17-000; Order No. 745]
Demand Response Compensation in Organized Wholesale Energy
Markets
AGENCY: Federal Energy Regulatory Commission, Energy.
ACTION: Final rule.
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SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission
(Commission) amends its regulations under the Federal Power Act to
ensure that when a demand response resource participating in an
organized wholesale energy market administered by a Regional
Transmission Organization (RTO) or Independent System Operator (ISO)
has the capability to balance supply and demand as an alternative to a
generation resource and when dispatch of that demand response resource
is cost-effective as determined by the net benefits test described in
this rule, that demand response resource must be compensated for the
service it provides to the energy market at the market price for
energy, referred to as the locational marginal price (LMP). This
approach for compensating demand response resources helps to ensure the
competitiveness of organized wholesale energy markets and remove
barriers to the participation of demand response resources, thus
ensuring just and reasonable wholesale rates.
DATES: Effective Date: This Final Rule will become effective on April
25, 2011. Dates for compliance and other required filings are provided
in the Final Rule.
FOR FURTHER INFORMATION CONTACT:
David Hunger (Technical Information), Office of Energy Policy and
Innovation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, (202) 502-8148, david.hunger@ferc.gov;
Dennis Hough (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502-8631, dennis.hough@ferc.gov.
SUPPLEMENTARY INFORMATION:
Table of Contents
(Issued March 15, 2011)
Paragraph
Nos.
I. Introduction............................................ 1
II. Background............................................. 8
III. Procedural History.................................... 15
IV. Discussion............................................. 17
A. Compensation Level.................................. 18
1. NOPR Proposal................................... 18
2. Comments........................................ 20
(a) Capability of Demand Response and 20
Generation Resources to Balance Energy Markets
(b) Appropriateness of a Net Benefits Test..... 38
(c) Standardization or Regional Variations in 43
Compensation..................................
3. Commission Determination........................ 45
B. Implementation of a Net Benefits Test............... 68
1. Comments........................................ 68
2. Commission Determination........................ 78
C. Measurement and Verification........................ 86
1. NOPR Proposal................................... 86
2. Comments........................................ 88
3. Commission Determination........................ 93
D. Cost Allocation..................................... 96
1. NOPR Proposal................................... 96
2. Comments........................................ 97
3. Commission Determination........................ 99
E. Commission Jurisdiction............................. 103
1. Comments........................................ 103
2. Commission Determination........................ 112
V. Information Collection Statement........................ 116
VI. Environmental Analysis................................. 121
VII. Regulatory Flexibility Act............................ 122
VIII. Document Availability................................ 130
IX. Effective Date and Congressional Notification.......... 133
Regulatory Text
Appendix 1--List of Commenters
Appendix 2--Dissenting Statement
Before Commissioners: Jon Wellinghoff, Chairman; Marc Spitzer,
Philip D. Moeller, John R. Norris, and Cheryl A. LaFleur.
I. Introduction
1. This Final Rule addresses compensation for demand response in
Regional Transmission Organization (RTO) and Independent System
Operator (ISO) organized wholesale energy markets, i.e., the day-ahead
and real-time energy markets. As the Commission has previously
recognized, a market functions effectively only when both supply and
demand can meaningfully participate. The Commission, in the Notice of
Proposed Rulemaking (NOPR) issued in this proceeding on March 18, 2010,
proposed a remedy to concerns that current compensation levels
inhibited meaningful demand-side participation.\1\ After nearly 3,800
pages of comments, a subsequent technical conference, and the
opportunity for additional comment, we now take final action.
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\1\ Demand Response Compensation in Organized Wholesale Energy
Markets, Notice of Proposed Rulemaking, 75 FR 15362 (Mar. 29, 2010),
FERC Stats. & Regs. ] 32,656 (2010) (NOPR).
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[[Page 16659]]
2. We conclude that when a demand response \2\ resource \3\
participating in an organized wholesale energy market \4\ administered
by an RTO or ISO has the capability to balance supply and demand as an
alternative to a generation resource and when dispatch of that demand
response resource is cost-effective as determined by the net benefits
test described herein, that demand response resource must be
compensated for the service it provides to the energy market at the
market price for energy, referred to as the locational marginal price
(LMP).\5\ The Commission finds that this approach to compensation for
demand response resources is necessary to ensure that rates are just
and reasonable in the organized wholesale energy markets. Consistent
with this finding, this Final Rule adds section 35.28(g)(1)(v) to the
Commission's regulations to establish a specific compensation approach
for demand response resources participating in the organized wholesale
energy markets administered by RTOs and ISOs. The Commission is not
requiring the use of this compensation approach when demand response
resources do not satisfy the capability and cost-effectiveness
conditions noted above.\6\
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\2\ Demand response means a reduction in the consumption of
electric energy by customers from their expected consumption in
response to an increase in the price of electric energy or to
incentive payments designed to induce lower consumption of electric
energy. 18 CFR 35.28(b)(4) (2010).
\3\ Demand response resource means a resource capable of
providing demand response. 18 CFR 35.28(b)(5).
\4\ The requirements of this final rule apply only to a demand
response resource participating in a day-ahead or real-time energy
market administered by an RTO or ISO. Thus, this Final Rule does not
apply to compensation for demand response under programs that RTOs
and ISOs administer for reliability or emergency conditions, such
as, for instance, Midwest ISO's Emergency Demand Response, NYISO's
Emergency Demand Response Program, and PJM's Emergency Load Response
Program. This Final Rule also does not apply to compensation in
ancillary services markets, which the Commission has addressed
elsewhere. See, e.g., Wholesale Competition in Regions with
Organized Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28,
2008), FERC Stats. & Regs. ] 31,281 (2008) (Order No. 719).
\5\ LMP refers to the price calculated by the ISO or RTO at
particular locations or electrical nodes or zones within the ISO or
RTO footprint and is used as the market price to compensate
generators. There are variations in the way that RTOs and ISOs
calculate LMP; however, each method establishes the marginal value
of resources in that market. Nothing in this Final Rule is intended
to change RTO and ISO methods for calculating LMP.
\6\ The Commission's findings in this Final Rule do not preclude
the Commission from determining that other approaches to
compensation would be acceptable when these conditions are not met.
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3. This cost-effectiveness condition, as determined by the net
benefits test described herein, recognizes that, depending on the
change in LMP relative to the size of the energy market, dispatching
demand response resources may result in an increased cost per unit ($/
MWh) to the remaining wholesale load associated with the decreased
amount of load paying the bill. This is the case because customers are
billed for energy based on the units, MWh, of electricity consumed. We
refer to this potential result as the billing unit effect of
dispatching demand response. By contrast, dispatching generation
resources does not produce this billing unit effect because it does not
result in a decrease of load. To address this billing unit effect, the
Commission in this Final Rule requires the use of the net benefits test
described herein to ensure that the overall benefit of the reduced LMP
that results from dispatching demand response resources exceeds the
cost of dispatching and paying LMP to those resources. When the net
benefits test described herein is satisfied and the demand response
resource clears in the RTO's or ISO's economic dispatch, the demand
response resource is a cost-effective alternative to generation
resources for balancing supply and demand.
4. To implement the net benefits test described herein, we direct
each RTO and ISO to develop a mechanism as an approximation to
determine a price level at which the dispatch of demand response
resources will be cost-effective. The RTO or ISO should determine,
based on historical data as a starting point and updated for changes in
relevant supply conditions such as changes in fuel prices and generator
unit availability, the monthly threshold price corresponding to the
point along the supply stack beyond which the overall benefit from the
reduced LMP resulting from dispatching demand response resources
exceeds the cost of dispatching and paying LMP to those resources. This
price level is to be updated monthly, by each ISO or RTO, as the
historic data and relevant supply conditions change.\7\
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\7\ In its compliance filing an RTO or ISO may attempt to show,
in whole or in part, how its proposed or existing practices are
consistent with or superior to the requirements of this Final Rule.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\8\ 16 U.S.C. 824d (2006).
---------------------------------------------------------------------------
7. In addition, we believe that integrating a determination of the
cost-effectiveness of demand response resources into the dispatch of
the ISOs and RTOs may be more precise than the monthly price threshold
and, therefore, provide the greatest opportunity for load to benefit
from participation of demand response in the organized wholesale energy
market administered by an RTO or ISO. However, we acknowledge the
position of several of the RTOs and ISOs that modification of their
dispatch algorithms to incorporate the costs related to demand response
may be difficult in the near term. In light of those concerns, we
require each RTO and ISO to undertake a study examining the
requirements for and impacts of implementing a dynamic approach which
incorporates the billing unit effect in the dispatch algorithm to
determine when paying demand response resources the LMP results in net
benefits to customers in both the day-ahead and real-time energy
markets. The Commission directs each RTO and ISO to file the results of
this study with the Commission on or before September 21, 2012.\9\
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\9\ We note that this report is for informational purposes only
and will neither be noticed nor require Commission action.
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II. Background
8. Effective wholesale competition protects customers by, among
other things, providing more supply options, encouraging new entry and
innovation, and spurring deployment of new technologies.\10\ Improving
the competitiveness of organized wholesale energy markets is therefore
integral to the Commission fulfilling its statutory mandate under the
FPA to ensure
[[Page 16660]]
supplies of electric energy at just, reasonable, and not unduly
discriminatory or preferential rates.\11\
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\10\ See, e.g., Wholesale Competition in Regions with Organized
Electric Markets, Order No. 719, 73 FR 64100 (Oct. 28, 2008), FERC
Stats. & Regs. ] 31,281, at P 1 (2008) (Order No. 719); see also
Regional Transmission Organizations, Order No. 2000, FERC Stats. &
Regs. ] 31,089, at P 1 (1999), order on reh'g, Order No. 2000-A,
FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist.
No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607, 348
U.S. App. DC 205 (DC Cir. 2001).
\11\ 16 U.S.C. 824d (2006); Order No. 719, FERC Stats. & Regs. ]
31,281 at P 1.
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9. As the Commission recognized in Order No. 719, active
participation by customers in the form of demand response in organized
wholesale energy markets helps to increase competition in those
markets.\12\ Demand response, whereby customers reduce electricity
consumption from normal usage levels in response to price signals, can
generally occur in two ways: (1) Customers reduce demand by responding
to retail rates that are based on wholesale prices (sometimes called
``price-responsive demand''); and (2) customers provide demand response
that acts as a resource in organized wholesale energy markets to
balance supply and demand. While a number of States and utilities are
pursuing retail-level price-responsive demand initiatives based on
dynamic and time-differentiated retail prices and utility investments
in demand response enabling technologies, these are State efforts, and,
thus, are not the subject of this proceeding. Our focus here is on
customers or aggregators of retail customers providing, through bids or
self-schedules, demand response that acts as a resource in organized
wholesale energy markets.
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\12\ See Order No. 719, FERC Stats. & Regs. ] 31,281 at P 48.
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10. As the Commission stated in Order No. 719,\13\ and emphasized
in the NOPR,\14\ there are several ways in which demand response in
organized wholesale energy markets can help improve the functioning and
competitiveness of those markets. First, when bid directly into the
wholesale market, demand response can facilitate RTOs and ISOs in
balancing supply and demand, and thereby, help produce just and
reasonable energy prices.\15\ This is because customers who choose to
respond will signal to the RTO or ISO and energy market their
willingness to reduce demand on the grid which may result in reduced
dispatch of higher-priced resources to satisfy load.\16\ Second, demand
response can mitigate generator market power.\17\ This is because the
more demand response that sees and responds to higher market prices,
the greater the competition, and the more downward pressure it places
on generator bidding strategies by increasing the risk to a supplier
that it will not be dispatched if it bids a price that is too high.\18\
Third, demand response has the potential to support system reliability
and address resource adequacy \19\ and resource management challenges
surrounding the unexpected loss of generation. This is because demand
response resources can provide quick balancing of the electricity
grid.\20\
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\13\ Wholesale Competition in Regions with Organized Electric
Markets, Order No. 719-A, FERC Stats. & Regs. ] 31,292, at P 48
(2009).
\14\ NOPR, FERC Stats. & Regs. ] 32,656 at P 4.
\15\ For example, a study conducted by PJM, which simulated the
effect of demand response on prices, demonstrated that a modest
three percent load reduction in the 100 highest peak hours
corresponds to a price decline of six to 12 percent. ISO-RTO Council
Report, Harnessing the Power of Demand How RTOs and ISOs Are
Integrating Demand Response into Wholesale Electricity Markets,
found at https://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/IRC_DR_Report_101607.pdf.
\16\ Id. (``Demand response tends to flatten an area's load
profile, which in turn may reduce the need to construct and use more
costly resources during periods of high demand; the overall effect
is to lower the average cost of producing energy.'').
\17\ See Comments of NYISO's Independent Market Monitor filed in
Docket No. ER09-1142-000, May 15, 2009 (Demand response
``contributes to reliability in the short-term, resource adequacy in
the long-term, reduces price volatility and other market costs, and
mitigates supplier market power.'').
\18\ Id.
\19\ See ISO-RTO Council Report, Harnessing the Power of Demand
How RTOs and ISOs Are Integrating Demand Response into Wholesale
Electricity Markets at 4, found at https://www.isorto.org/atf/cf/%7B5B4E85C6-7EAC-40A0-8DC3-003829518EBD%7D/IRC_DR_Report_101607.pdf (``Demand response contributes to maintaining system
reliability. Lower electric load when supply is especially tight
reduces the likelihood of load shedding. Improvements in reliability
mean that many circumstances that otherwise result in forced outages
and rolling blackouts are averted, resulting in substantial
financial savings * * *.'').
\20\ For instance, in ERCOT, on February 26, 2008, through a
combination of a sudden loss of thermal generation, drop in power
supplied by wind generators, and a quicker-than-expected ramping up
of demand, ERCOT found itself short of reserves. The system operator
called on all demand response resources, and 1200 MW of Load acting
as Resource (LaaRs) responded quickly, bringing ERCOT back into
balance. Oak Ridge Nat'l Lab., Nat'l Renewable Energy Lab., Tech.
Rep. NREL/TP-500-43373, ERCOT Event on Feb. 26, 2008: Lessons
Learned (Jul. 2008).
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11. Congress has recognized the importance of demand response by
enacting national policy requiring its facilitation.\21\ Consistent
with that policy, the Commission has undertaken several reforms to
support competitive wholesale energy markets by removing barriers to
participation of demand response resources. For example, in Order No.
890, the Commission modified the pro forma Open Access Transmission
Tariff to allow non-generation resources, including demand response
resources, to be used in the provision of certain ancillary services
where appropriate on a comparable basis to service provided by
generation resources.\22\ Order No. 890-A further required transmission
providers to develop transmission planning processes that treat all
resources, including demand response, on a comparable basis.\23\
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\21\ See Energy Policy Act of 2005, Public Law 109-58, Sec.
1252(f), 119 Stat. 594, 965 (2005) (``It is the policy of the United
States that * * * unnecessary barriers to demand response
participation in energy, capacity, and ancillary service markets
shall be eliminated.'').
\22\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241,
at P 887-88 (2007), order on reh'g, Order No. 890-A, FERC Stats. &
Regs. ] 31,261 (2007), order on reh'g and clarification, Order No.
890-B, 123 FERC ] 61,299 (2008), order on reh'g, Order No. 890-C,
126 FERC ] 61,228 (2009), order on clarification, Order No. 890-D,
129 FERC ] 61,126 (2009).
\23\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 216.
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12. In Order No. 719, the Commission required RTOs and ISOs to,
among other things, accept bids from demand response resources in their
markets for certain ancillary services on a basis comparable to other
resources.\24\ The Commission also required each RTO and ISO ``to
reform or demonstrate the adequacy of its existing market rules to
ensure that the market price for energy reflects the value of energy
during an operating reserve shortage,'' \25\ for purposes of
encouraging existing generation and demand resources to continue to be
relied upon during an operating reserve shortage, and encouraging entry
of new generation and demand resources.\26\
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\24\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 47-49.
\25\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 194.
\26\ Order No. 719, FERC Stats. & Regs. ] 31,281 at P 247.
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13. Additionally, in recent years several RTOs and ISOs have
instituted various types of demand response programs. While some of
these programs are administered for reliability and emergency
conditions, other programs allow wholesale customers, qualifying large
retail customers, and aggregators of retail customers to participate
directly in the day-ahead and real-time energy markets, certain
ancillary service markets and capacity markets.\27\
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\27\ Other demand response programs allow demand response to be
used as a capacity resource and as a resource during system
emergencies or permit the use of demand response for synchronized
reserves and regulation service. See, e.g., PJM Interconnection,
L.L.C., 117 FERC ] 61,331 (2006); Devon Power LLC, 115 FERC ]
61,340, order on reh'g, 117 FERC ] 61,133 (2006), appeal pending sub
nom. Maine Pub. Utils. Comm'n v. FERC, No. 06-1403 (D.C. Cir. 2007);
New York Indep. Sys. Operator, Inc., 95 FERC ] 61,136 (2001); NSTAR
Services Co. v. New England Power Pool, 95 FERC ] 61,250 (2001); New
England Power Pool and ISO New England, Inc., 100 FERC ] 61,287,
order on reh'g, 101 FERC ] 61,344 (2002), order on reh'g, 103 FERC ]
61,304, order on reh'g, 105 FERC ] 61,211 (2003); PJM
Interconnection, L.L.C., 99 FERC ] 61,227 (2002); California
Independent System Operator Corp., 132 FERC ] 61,045 (2010).
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[[Page 16661]]
14. To date, the Commission has allowed each RTO and ISO to develop
its own compensation methodologies for demand response resources
participating in its day-ahead and real-time energy markets. As a
result, the levels of compensation for demand response vary
significantly among RTOs and ISOs.\28\ For example, PJM
Interconnection, L.L.C. (PJM) pays the LMP minus the generation and
transmission portions of the retail rate.\29\ ISO New England Inc.
(ISO-NE) and New York Independent System Operator, Inc. (NYISO) pay LMP
when prices exceed a threshold level, with the levels differing between
the RTOs.\30\ The Midwest Independent Transmission System Operator,
Inc.'s (Midwest ISO) demand response programs \31\ pay LMP for demand
response resources in the day-ahead and real-time energy markets.\32\
The California Independent System Operator Corporation (CAISO) pays LMP
at pricing nodes, or sub-load aggregation points (Sub-LAP) in its Proxy
Demand Resource program that allows qualifying resources to provide
day-ahead and real-time energy.\33\ CAISO also provides for demand
response resources to participate in its Participating Load program,
which enables certain resources to provide curtailable demand in the
CAISO market. CAISO pays nodal real-time LMP for its Participating Load
program. The Southwest Power Pool, Inc. (SPP) has filed revisions to
its tariff to facilitate demand response in the Energy Imbalance
Service Market.\34\
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\28\ See New England, Inc., Docket No. ER09-1051-000; ISO New
England, Inc., Docket No. ER08-830-000; Midwest Indep. Transmission
Sys. Operator, Inc., Docket No. ER09-1049-000.
\29\ See sections 3.3A.4 and 3.3A.5 (Market Settlements in the
Real-Time and Day-Ahead Energy Markets) of the Appendix to
Attachment K of the PJM Tariff.
\30\ For example, under ISO-NE's Real-Time Price Response
Program, the minimum bid is $100/MWh and a demand response resource
is paid the higher of LMP or $100/MWh. For the Day-Ahead Load
Response Program, the minimum offer level is calculated on a monthly
basis and is the Forward Reserve Fuel Index ($/MMBtu) multiplied by
an effective heat rate of 11.37 MMBtu/MWh. The maximum offer level
is $1,000/MWh. See sections III.E.2.1 and III.E.3.2 of Appendix E of
the ISO New England Transmission, Markets and Services Tariff. NYISO
implements a day-ahead demand response program by which resources
bid into the market at a minimum of $75/MWh and can get paid the
LMP. See section 4.2.2.9 (``Day-Ahead Bids from Demand Reduction
Providers to Supply Energy from Demand Reductions'') of NYISO's
Market Services Tariff.
\31\ Midwest ISO FERC Electric Tariff characterizes Demand
Response Resources (DRR) as either DRR-Type I or DRR-Type II. DRR-
Type I are capable of supplying a specific quantity of energy or
contingency reserve through physical load interruption. DRR-Type II
are capable of supplying energy and/or operating reserves over a
dispatchable range. See sections 39.2.5A and 40.2.5 of the Tariff.
\32\ See Charges and Payments for Purchases and Sales for Demand
Response Resources. Midwest ISO FERC Electric Tariff, section
39.3.2C.
\33\ See section 11.2.1.1 IFM Payments for Supply of Energy,
CAISO FERC Electric Tariff. CAISO notes that for a Proxy Demand
Resource that is made up of aggregated loads, the Resource is paid
the weighted average of the LMPs of each pricing node where the
underlying aggregate loads reside. See CAISO, 132 FERC ] 61,045, at
P 26 n.14 (2010).
\34\ The Commission has directed SPP to report on ways it can
incorporate demand response into its imbalance market. Southwest
Power Pool, Inc., 128 FERC ] 61,085 (2009). As of September 1, 2010,
SPP has submitted seven informational status reports regarding its
efforts to address issues related to demand response resources. In
orders addressing SPP's compliance with Order No. 719, the
Commission also directed SPP to make another compliance filing
addressing demand response participation in its organized markets.
Southwest Power Pool, Inc., 129 FERC ] 61,163, at P 51 (2009). On
May 19, 2010, SPP submitted revisions to its Open Access
Transmission Tariff in Docket Nos. ER09-1050-004 and ER09-748-002 to
comply with the Commission's requirements established in Order Nos.
719 and 719-A. These filings are pending before the Commission.
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III. Procedural History
15. As noted above, the Commission issued the NOPR in this
proceeding on March 18, 2010.\35\ The NOPR proposed to require RTOs and
ISOs to pay the LMP in all hours for demand reductions made in response
to price signals. The Commission sought comments on the compensation
proposal and, in particular, on the comparability of generation and
demand response resources; alternative approaches to compensating
demand response in organized wholesale energy markets; whether payment
of LMP should apply in all hours, and, if not, any criteria that should
be used for establishing hours when LMP should apply; and whether to
allow for regional variations concerning approaches to demand response
compensation.\36\
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\35\ NOPR, FERC Stats. & Regs. ] 32,656.
\36\ See Appendix for a list of commenters.
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16. After receiving the first round of comments, the Commission
issued a Supplemental Notice of Proposed Rulemaking and Notice of
Technical Conference (Supplemental NOPR) in this proceeding on August
2, 2010.\37\ The Supplemental NOPR sought additional comment on:
Whether the Commission should adopt a net benefits test for determining
when to compensate demand response providers, and, if so, what, if any,
requirements should apply to the methods for determining net benefits;
and what, if any, requirements should apply to how the costs of demand
response are allocated. The Commission further directed Staff to hold a
technical conference focused on these two issues, which occurred on
September 13, 2010.\38\
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\37\ Supplemental Notice of Proposed Rulemaking and Notice of
Technical Conference, 75 FR 47499 (Aug. 6, 2010), 132 FERC ] 61,094
(2010) (Supplemental NOPR).
\38\ See Notice of Technical Conference (Aug. 27, 2010).
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IV. Discussion
17. Based upon the record in this proceeding, the Commission herein
requires greater uniformity in compensating demand response resources
participating in organized wholesale energy markets. This Final Rule
also addresses the allocation of costs resulting from the commitment of
demand response, directing that such costs be allocated among those
customers who benefit from the lower LMP resulting from the demand
response.
A. Compensation Level
1. NOPR Proposal
18. The NOPR proposed to require RTOs and ISOs to pay the LMP in
all hours for demand reductions made in response to price signals. The
NOPR sought to provide comparable compensation to generation and demand
response providers, based on the premise that both resources provide a
comparable service to RTOs and ISOs for purposes of balancing supply
and demand and maintaining a reliable electricity grid.\39\ Also as
stated in the NOPR, the proposed compensation level was designed to
allow more demand response resources to cover their investment costs in
demand response-related technology (such as advanced metering) and
thereby facilitate their ability to participate in organized wholesale
energy markets.\40\ The Commission sought comments on the compensation
proposal and, in particular, on the comparability of generation and
demand response resources; alternative approaches to compensating
demand response in organized wholesale energy markets; whether payment
of LMP should apply in all hours, and, if not, any criteria that should
be used for establishing hours when LMP should apply; and whether to
allow for regional variations concerning approaches to demand response
compensation.
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\39\ NOPR, FERC Stats. & Regs. ] 32,656 at P 15.
\40\ Id. at P 16.
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19. In the Supplemental NOPR, the Commission sought additional
comments and directed staff to hold a technical conference regarding
various net benefits tests. In particular, the Commission sought
comment on:
[[Page 16662]]
whether the Commission should adopt a net benefits test applicable in
all or only some hours and what the criteria of any such test would be;
how to define net benefits; what costs demand response providers and
load serving entities incur and whether they should be included in a
net benefits test; whether any net benefits methodology adopted should
be the same for all RTOs and ISOs; proposed methodologies for
implementing a net benefits test and the advantages and limitations of
any proposed methodologies.\41\ The September 13, 2010 Technical
Conference included an eleven-member panel discussion of net benefits
tests representing a wide range of interests and viewpoints.\42\ The
Commission subsequently received additional written comments addressing
these issues.
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\41\ Supplemental NOPR, 132 FERC ] 61,094 at P 8-9.
\42\ See Sept. 13, 2010 Tr.
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2. Comments
(a) Capability of Demand Response and Generation Resources To Balance
Energy Markets
20. Various commenters address the comparability of demand response
and generation resources for purposes of compensation in the organized
wholesale energy markets. To begin, numerous commenters address the
physical or functional comparability of demand response and generation,
agreeing that an increment of generation is comparable to a decrement
of load for purposes of balancing supply and demand in the day-ahead
and real-time energy markets.\43\ Equating generation and demand
response resources, Dr. Alfred E. Kahn states:
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\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.
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[Demand response] is in all essential respects economically
equivalent to supply response * * * [so] economic efficiency
requires * * * that it should be rewarded with the same LMP that
clears the market. Since [demand response] is actually--and not
merely metaphorically--equivalent to supply response, economic
efficiency requires that it be regarded and rewarded, equivalently,
as a resource proffered to system operators, and be treated
equivalently to generation in competitive power markets. That is,
all resources--energy saved equivalently to energy supplied--* * *
should receive the same market-clearing LMP in remuneration.\44\
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\44\ DR Supporters August 30, 2010 Reply Comments (Kahn
Affidavit at 2 (footnote omitted)).
Indeed, some commenters believe that, from a physical standpoint,
demand response can provide superior services to generation, such as
providing a quick response in meeting system requirements and service
without having to construct major new facilities.\45\ Occidental
asserts that the fungibility of demand response and generation output
creates greater operational flexibility that, in turn, offers RTOs and
ISOs multiple options to solve system issues both in energy and
ancillary service markets, and that the fungible nature of demand
response and generation supports comparable compensation for each as
proposed in the NOPR.\46\
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\45\ Verso May 13, 2010 Comments at 3-4; Alcoa May 13, 2010
Comments at 9.
\46\ Occidental May 13, 2010 Comments at 11.
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21. Viridity states that attempts to distinguish the physical
characteristics of generation and demand response ignore bid-based
security-constrained economic dispatch as the foundation for LMP and
are based on the assumption that the value of load management on the
grid is limited to periods when the system is stressed, i.e.,
traditional ``super peak shaving.'' Viridity states that, while these
arguments might have been valid 15 years ago, today competitive markets
can offer proactively-managed load control and comparable and non-
discriminatory treatment of load-based energy resources. Therefore,
Viridity asserts that all resources should be paid LMP if the grid
operator accepts their bid to achieve grid balance.\47\
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\47\ Viridity June 18, 2010 Comments at 5.
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22. At the same time, other commenters argue that generation and
demand response are not physically equivalent, pointing out that demand
response reduces consumption, whereas generators serve consumption.\48\
They argue that a MW reduction in demand does not turn on the
lights.\49\ EPSA adds that a load reduction does not provide electrons
to any other load and, instead, allows the marginal electron to serve a
different customer.\50\ Some commenters assert that a power system can
function solely and reliably on generating plants and without any
reliance on demand response, while the system cannot rely exclusively
on demand response because demand response by itself cannot keep the
lights on. Ultimately, some commenters point out, megawatts produced by
generators need to be placed on the system in order for power to
flow.\51\ Battelle additionally argues that a reduction in consumption
is not exactly the same as an increase in production, because elastic
demand often comes with attendant future consequences, such as rebound,
by virtue of substitution in time.\52\
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\48\ ISO-NE May 13, 2010 Comments at 3.
\49\ See, e.g., APPA May 13, 2010 Comments at 12; Capital Power
May 13, 2010 Comments at 2.
\50\ EPSA May 13, 2010 Comments at 72.
\51\ See, e.g., PSEG May 13, 2010 Comments at 8.
\52\ Battelle May 13, 2010 Comments at 3.
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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\
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\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.
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24. Numerous commenters also address the comparability of demand
response and generation in economic terms. For example, EEI states
that, in finance terms, the demand response product is, unlike
generation, essentially an unexercised call option on spot market
energy, and the value of that option is well-established in finance
theory as the value of the resource (LMP) minus the ``strike price,''
which EEI contends in this case is the retail tariff rate.\56\ EEI and
like-minded commenters support, therefore, alternative compensation for
demand response to equal LMP minus the generation (or G) component of
the retail rate.\57\ They posit that payment of
[[Page 16663]]
LMP without an offset for some portion of the retail rate does not send
the proper economic signal to providers of demand response, because it
fails to take into account the retail rate savings associated with
demand response, and thereby overcompensates the demand response
provider. As described by Dr. William W. Hogan on behalf of EPSA, this
is sometimes called a double-payment for demand reductions, because
demand response providers would ``receive'' both the cost savings from
not consuming an increment of electricity at a particular price, plus
an LMP payment for not consuming that same increment of
electricity.\58\ Viewing LMP as a double-payment, these commenters
argue that paying LMP will result in more demand response than is
economically efficient.\59\ For example, Dr. Hogan states that paying
LMP might motivate a company to shut down even though the benefits of
consuming electricity outweigh the cost at LMP.\60\ Indeed, P3 argues
that compensation in excess of LMP-G is unjust and unreasonable,
because such a payment level imposes costs on customers that are not
commensurate with benefits received.\61\
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\56\ EEI May 13, 2010 Comments at 4-5. See also Robert L.
Borlick May 13, 2010 Comments at 4. Mr. Borlick argues that the
correct price is LMP minus the Marginal Foregone Retail Rate (MFRR),
describing the economically efficient price that should be paid to a
demand response provider as ``its offer price minus the price in its
retail tariff at which it would have purchased the curtailed
energy.'' Mr. Borlick asserts that this amount accurately represents
the forgone opportunity costs that result when a demand response
provider reduces its load. Id.
\57\ See May 13, 2010 Comments of: APPPA; AEP; The Brattle
Group; Calpine; ConEd; Consumers Energy; CPG; Detroit Edison; Direct
Energy; Dominion; Duke Energy; Edison Mission; EEI; EPSA; Exelon;
FTC; GDF; NYISO on behalf of the ISO RTO Council; ICC; IPPNY;
Indicated New York TOs; IPA; ISO-NE; Midwest TDUs; Mirant; Midwest
ISO TOs; NEPGA; NYISO; ODEC; OMS; PJM; PJM IMM; P3; Potomac
Economics; PG&E; Ohio Commission; Robert L. Borlick; Roy Shanker;
and RRI Energy.
\58\ See Attachment to Answer of EPSA, Providing Incentives for
Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009,
submitted in Docket No. EL09-68-000.
\59\ EPSA May 13, 2010 Comments at 23. See also May 13, 2010
Comments of APPA at 13; FTC at 9; Midwest TDUs at 14; Mirant at 2;
New York Commission at 5; PJM at 6; PSEG at 5; and Potomac Economics
at 6-8.
\60\ Attachment to Answer of EPSA, Providing Incentives for
Efficient Demand Response, Dr. William W. Hogan, Oct. 29, 2009,
submitted in Docket No. EL09-68-000. In Dr. Hogan's view, supply
should produce when the price of electricity exceeds its cost of
production and demand should decline to consume when the costs in
terms of convenience of delaying use are less than the price of
electricity.
\61\ P3 June 14, 2010 Comments at 2, 7-8.
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25. ISO-NE argues that paying full LMP to demand response providers
without taking into account the bill savings produced by demand
response provides a significant financial incentive to dispatch demand
response with marginal costs exceeding LMPs. By dispatching higher-cost
demand response, ISO-NE asserts, lower-cost generation resources are
displaced.\62\ At the same time, ISO-NE argues, generation is not
dispatched and paid for only when the generation reduces LMP--
generation is dispatched and paid for when it is cost-effective.\63\
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\62\ ISO-NE May 13, 2010 Comments at 3-4.
\63\ Id. at 28.
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26. Dr. Hogan further disputes arguments equating a MW of energy
supplied to a MW of energy saved on economic grounds. Dr. Hogan draws a
distinction between reselling something that one has purchased, and
selling something that one would have purchased without actually
purchasing it. Dr. Hogan argues that from the perspective of economic
efficiency and welfare maximization, the aggregate effect of demand
response is a wash producing no economic net benefit. Dr. Hogan asserts
that Commission policy citing the benefits of price reduction in
support of demand response compensation would amount to no less than an
application of regulatory authority to enforce a buyers' cartel. He
states that the Commission has been vigilant and aggressive in
preventing buyers and sellers from engaging in market manipulation to
influence prices, and it would be fundamentally inconsistent for the
Commission to design demand response compensation policies that
coordinate and enforce such price manipulation.
27. Dr. Hogan argues that the ideal and economically efficient
solution regarding demand response compensation is to implement retail
real-time pricing at the LMP, thereby eliminating the need for demand
response programs. Realizing that this is unattainable at the present
time, Dr. Hogan goes on to propose a next-best solution, which he
believes is to pay demand response compensation in the amount of LMP-G,
or some amount that simulates explicit contract demand response (such
as ``buy-the-baseline'' approach discussed below). These options, he
argues, more than paying LMP, better support notions of comparability
between demand response resources and generation.\64\
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\64\ Hogan Affidavit, ISO RTO Council May 13, 2010 Comments at
5.
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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\
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\65\ New York Commission May 13, 2010 Comments at 8.
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29. Consistent with Dr. Hogan's arguments, some commenters assert
that demand response providers should actually own or pay for
electricity prior to, what commenters characterize as, an effective
reselling of the electricity back to the market in the form of demand
response. For example, these commenters suggest that the demand
response provider purchase the power in the day-ahead market and resell
it in the real-time markets.\66\ EPSA argues that there must be some
purchase requirement or representative offset to allow a demand
response provider to ``sell'' a commodity that it owns to the ISO or
RTO.\67\ EPSA argues that such a requirement would send an efficient
price signal, reduce incentives for gaming the system, and help address
difficulties with measurement and verification of a demand reduction.
EPSA highlights an ISO-NE IMM recommendation that, if the Commission
permits LMP payment, it should also adopt a ``buy-the-baseline''
approach requiring demand response resources to purchase an expected
amount of energy consumption in the day-ahead energy market and
subsequently sell any demand reduction from that level in the real-time
market.\68\
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\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.
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30. Viridity, on the other hand, argues that forcing customers to
buy and then resell electricity will lead to too little demand response
and that adopting a ``buy-the-baseline'' approach would constitute an
inappropriate exercise of Commission authority to effectively force
parties into contracts. Viridity and DR Supporters state that any
characterization of demand response as a purchase and then resale of
energy is erroneous \69\ and based on the flawed assumption that demand
response resources are reselling energy. They state that the
description of demand response as a reselling of energy has been
correctly rejected by the Commission in EnergyConnect, where the
Commission stated that it was establishing a policy of treating demand
response as a service rather than a purchase and sale of electric
energy.\70\
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\69\ Viridity Energy June 18, 2010 Comments at 25.
\70\ DR Supporters Aug. 30, 2010 Reply Comments at 10 (citing
EnergyConnect, Inc., 130 FERC ] 61,031 at P 30-31 (2010)).
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31. DR Supporters further argues that, despite claims to the
contrary, paying full LMP to demand response providers does not
constitute a subsidy for demand response any more than the
remunerations of generators for the power that they sell. As Dr. Kahn
states:
Does this plan involve double compensation, as [Dr.] Hogan
asserts, at the expense of power generators--of successful
[[Page 16664]]
bidders promising to induce efficient demand curtailment and of
consumers induced to practice it? Certainly not: The decrease in the
revenue of the generators is (and consequent savings by consumers
are) matched by the savings in their (marginal) costs of generating
that power; the successful bidders for the opportunity to induce
that consumer response are compensated for the costs of those
efforts by the pool, whose (marginal) costs they save by assisting
consumers to reduce their purchases.\71\
\71\ DR Supporters Aug. 30, 2010 Reply Comments, Kahn Affidavit
at 10.
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32. Viridity further disputes Dr. Hogan's argument that payment of
LMP for demand response will distort an otherwise optimal market.
Viridity posits that such arguments ignore dislocations in the
wholesale power markets, the existence of market power that must be
mitigated, imperfect information available to customers, barriers to
entry and uneconomic resources dispatched to fulfill must-run
requirements.\72\ Viridity further states that Dr. Hogan's arguments
fail to acknowledge the limits of the Commission's jurisdiction and
widespread dislocations and distortions in virtually all economic
aspects of relevant energy markets (including fuels, facilities,
pricing, environmental attributes, information and participation) and
fail to account for any market benefits of demand response.\73\
Finally, Viridity argues that Dr. Hogan's arguments fail to reflect the
many complex interactions between price, equipment operational
requirements, and customer processes, which point to a complex demand
response decision.\74\
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\72\ Viridity June 18, 2010 Comments at 13 (``Importantly, Dr.
Hogan (and others) in opposing the proposed rulemaking fails to
acknowledge the limits of the Commission's jurisdiction, and wide
spread dislocations and distortions in virtually all economic
aspects of relevant energy markets (including fuels, facilities,
pricing, environmental attributes, information and participation).''
(Affidavit of John C. Tysseling, PhD)).
\73\ Viridity Reply Comments at 13.
\74\ Viridity Reply Comments at 14.
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33. In addition to physical and economic comparability, some
commenters contrast the environmental effects of generation and demand
response resources. EDF notes that current market prices fail to
internalize environmental externalities--including toxic air pollution,
greenhouse gas pollution, and land and water use impacts--and other
social costs. EDF asserts that the social impact of these environmental
externalities is especially acute at peak times, positing that
generation sources used for marginal supply at such times (``peaker
plants'') are among the oldest, dirtiest, and most inefficient in the
fleet.\75\ The American Clean Skies Foundation contends that fossil-
fuel generators are typically mispriced because wholesale prices
radically understate the full environmental and health costs associated
with such generators.\76\ Indeed, some commenters, such as Alcoa, argue
that because demand response does not result in the external costs
associated with generation (e.g., greenhouse gas emissions), instead
resulting in less greenhouse gas emissions than generation, it should
be compensated at more than LMP.\77\
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\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.
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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\
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\78\ EPSA May 13, 2010 Comments at 60.
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35. Some commenters discuss comparability of generation and demand
response in terms of the market rules that apply to each resource,
arguing that both resources should be comparably compensated only if
the same rules for participation apply to both resources, and both
resources are held to the same standards for dispatchability.\79\ They
also argue that similar penalty structures should apply to demand
response resources as apply to generation, and that demand response
participation must be subject to market monitoring.\80\ Calpine adds
that to the extent demand response resources are used and treated on
par with generators for purposes of compensation, they should be
subject to the same performance testing, penalties, and other similar
requirements as generators.\81\
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\79\ ODEC May 13, 2010 Comments at 12; Westar May 13, 2010
Comments at 5-6.
\80\ Id.
\81\ Calpine May 13, 2010 Comments at 5.
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36. Some commenters address the comparability of demand response
providers and generators in terms of maintaining system reliability.
PIO argues that reductions in consumption provide additional
reliability.\82\ According to the NEMA, North American Electric
Reliability Corporation (NERC) standards suggest that, from a
reliability perspective, load reductions are equivalent or even
superior to generator increases for balancing purposes. For example,
while specific to the Western Interconnection, BAL-002-WECC-1 lists
interruptible load as comparable to generation deployable within 10
minutes.\83\ EPSA maintains that demand response resources are not full
substitutes based on the nature of their participation and the rules
applicable to each resource in the energy markets, pointing out, for
example, that, unlike generators, demand response providers are not
subject to regional and NERC mandatory reliability standards.\84\
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\82\ PIO May 13, 2010 Comments at 8.
\83\ NEMA May 13, 2010 Comments at 2.
\84\ EPSA May 13, 2010 Comments at 7.
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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\
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\85\ PSEG May 13, 2010 Comments at 8.
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(b) Appropriateness of a Net Benefits Test
38. Some commenters assert that demand response providers should be
paid LMP only when the benefits of demand response compensation
outweigh the energy market costs to consumers of paying demand response
resources, i.e., when cost-effective, as determined by some type of net
benefits or cost-effectiveness test.\86\ They maintain that paying LMP
for demand response in all hours, including off-peak hours, might not
result in net benefits to customers, because the payments might be
substantially more than the savings created by reducing the clearing
price at that time.\87\ According to these commenters, net benefits are
most likely to be positive and greatest when the supply curve is
steepest, which typically occurs in highest-cost, peak
[[Page 16665]]
hours.\88\ They argue that experience to date has shown positive
benefits from demand response as a peak system resource, and that,
during peak periods, the positive economics of demand response are
generally very clear and a cost-benefit analysis may not be needed.\89\
Furthermore, some commenters suggest that limiting the hours in which
demand response resources are paid LMP could help establish better
baselines for measuring whether a demand response provider has, in
fact, responded.\90\
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\86\ See generally May 13, 2010 Comments of NYSCPB; NECA;
Capital Power; NECPUC; Maryland Commission; New York Commission;
NSTAR; National Grid; NE Public Systems.
\87\ Capital Power May 13, 2010 Comments at 5; P3 May 13, 2010
Comments at 5.
\88\ NECPUC May 13, 2010 Comments at 13; see also Sept. 13, 2010
Tr. 13:6-19 (Mr. Keene); Maryland Commission May 13, 2010 Comments
at 4-5.
\89\ See, e.g., ACEEE Oct. 13, 2010 Comments 3-4. See also
National Grid May 13, 2010 Comments at 4-5; NSTAR Electric Company
(NSTAR) May 14, 2010 Comments at 3; Maryland Commission May 13, 2010
Comments, submitting Analysis of Load Payments and Expenditures
under Different Demand Response Compensation Schemes at 10-11
(discussing PJM analysis showing that paying demand response
providers LMP for all hours after compensating LSEs for lost
revenues would not benefit customers in general but that positive
economic benefits results when demand response providers receive LMP
during at least the top 100 hours (the highest priced energy
hours)).
\90\ See, e.g., CDWR May 13, 2010 Comments at 11; National Grid
May 13, 2010 Comments at 8; ISO-NE May 13, 2010 Comments at 34;
ACEEE Oct. 13, 2010 Comments 4. But see ISO-NE May 13, 2010 Comments
at 32-33 (contending that no baseline estimation methodology that
relies upon historical customer meter data can accurately and
reliably estimate an individual customer's normal energy usage
pattern if that customer responds frequently to price signals).
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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\
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\91\ NECAA May 13, 2010 Comments at 11; NYSCPB May 13, 2010
Comments at 5; National Grid May 13, 2010 Comments at 4-5.
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40. Opposition to use of a net benefits test comes from several
directions. Numerous commenters, primarily industrial consumers and
some consumer advocates, argue that a net benefits test will reduce
competition,\92\ have a ``chilling effect'' on the development of
demand response,\93\ and be costly and complex to implement.\94\ Some
commenters further state that no net benefits test is needed because
the merit-order bid stack and market clearing function in a wholesale
market, by definition, assures that the benefits to the system of
demand response exceed the costs, and that the resource that clears is
the lowest cost resource; otherwise, demand response would not dispatch
ahead of competing alternatives.\95\
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\92\ Viridity Oct. 13, 2010 Comments at 14.
\93\ NAPP Oct. 13, 2010 Comments at 2.
\94\ Viridity Oct. 13, 2010 Comments at 14; NAPP Oct. 13, 2010
Comments at 3; AMP Oct. 13, 2010 Comments at 4; CAISO Oct. 13, 2010
Comments at 5 and 16.
\95\ EDF Oct. 13, 2010 Comments at 2; Viridity Oct. 13, 2010
Comments at 10; ELCON Oct. 13, 2010 Comments at 3.
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41. Another set of commenters argues that a net benefits test is
unnecessary and inappr
