b. Virtual Purchasers
    122. In the NOPR, the Commission asked for comments on whether it
should require RTOs and ISOs to modify their tariffs to eliminate
deviation charges for virtual purchases during system emergencies.\163\
The Commission noted that virtual purchasers may not cause significant
additional costs during an emergency. Instead, virtual purchases may
enhance reliability by increasing the amount of generation resources
available in real time during a system emergency. Therefore, the
Commission noted that assessing a deviation charge on virtual
purchasers during an emergency may be unfair and may discourage helpful
virtual purchases when system resources are expected to be tight.\164\
---------------------------------------------------------------------------

    \163\ A virtual purchase (or sale) is a purchase (or sale) in
the RTO or ISO day-ahead market that does not go to physical
delivery. For example, an entity that does not serve load may make a
purchase in the day-ahead market, which it must pay for, and then
take no power in real time. This lack of consumption is treated as a
sale of the purchased power into the real-time spot market. By
making virtual energy purchases and sales in the day-ahead market
and settling these positions in the real-time market, a market
participant can arbitrage price differences between the two markets.
    \164\ NOPR, FERC Stats. & Regs. ] 32,628 at P 78.
---------------------------------------------------------------------------

i. Comments
    123. Several commenters state that virtual purchasers should be
treated in the same manner as other ``physical'' purchasers by
exempting their day-ahead market bids from deviation charges during
system emergencies.\165\ MADRI States and BP Energy assert that there
is no need to assess deviation charges to virtual purchasers because
such purchasers enhance reliability by increasing the amount of
generation resources available in real-time during an emergency.\166\
Mr. Borlick asserts that virtual bids in the day-ahead market do not
impose any costs on the system; he states this is because an RTO and
ISO is able to differentiate between virtual and physical bids and it
can ignore the virtual bids when determining unit commitment for the
next day's real-time operations.\167\ Further, DC Energy claims that
all buyers of energy (physical and virtual buyers) in the real-time
market should be treated equally.\168\
---------------------------------------------------------------------------

    \165\ E.g., Mr. Borlick at 2-3; BP Energy at 15; Exelon; MADRI
States; and DC Energy at 5-6.
    \166\ MADRI States at 6-7; BP Energy at 15.
    \167\ Mr. Borlick at 3.
    \168\ BP Energy at 5.
---------------------------------------------------------------------------

    124. Exelon agrees with the elimination of charges for virtual
purchasers during system emergencies, but suggests that the Commission
allow each RTO or ISO to implement such a rule after exploring the
consequences of such action through its stakeholder process.\169\
---------------------------------------------------------------------------

    \169\ Exelon at 6-8.
---------------------------------------------------------------------------

    125. Other commenters oppose this option and state that virtual
purchasers should be subject to deviation charges.\170\ For instance,
First Energy and TAPS state that virtual purchasers provide no load
reduction benefit and, therefore should not be exempt from paying the
deviation charge. TAPS also states that the NOPR record contains no
evidence that the hypothetical benefits of eliminating the deviation
charge for virtual bidders would outweigh the harm that would result
from removing deviation charges, as they act to discourage bidding
behavior that imposes significant costs on consumers.\171\ Several
commenters believe that exempting virtual purchasers from deviation
charges (1) may encourage speculation; (2) result in over commitment of
generation when it is not needed; and (3) result in cost shifts to
other market participants, thereby distorting markets.\172\ APPA
asserts that virtual bidders may be able to game the system and receive
a payment when no benefit is provided to the region.
---------------------------------------------------------------------------

    \170\ E.g., Ameren at 24; APPA at 3; ISO New England at 9; ISO/
RTO Council at 8; Old Dominion at 10; and TAPS at 10.
    \171\ First Energy at 8; TAPS at 9-11.
    \172\ ISO New England at 8-9; RTO/ISO Council at 6-8; and NYISO
at 7-8.
---------------------------------------------------------------------------

    126. NEPOOL Participants believes that it is important to more
fully evaluate the issues around virtual bidding and whether it is
necessary to include virtual bidding in any discussion regarding the
removal of deviation charges.\173\
---------------------------------------------------------------------------

    \173\ NEPOOL Participants at 13.
---------------------------------------------------------------------------

ii. Commission Determination
    127. The Commission agrees with the comments that virtual purchases
can enhance reliability by increasing the amount of generation
resources available in real-time during an emergency. Further,
assessing a deviation charge on virtual purchasers during an emergency
may be unfair and may discourage such virtual purchasing when it may be
most beneficial to other customers. Our preferred policy is to
eliminate deviation charges for virtual purchasers as well as physical
purchasers during a real-time market period for which the RTO or ISO
declares an operating reserve shortage or makes a generic request to
reduce load in order to avoid an operating reserve

shortage. However, we are concerned an RTO's or ISO's particular market
design may not readily accommodate this policy, and we acknowledge
commenters' concerns about the possibility of market manipulation under
a particular market design if deviation charges are removed for virtual
purchasers. Therefore, we direct RTOs and ISOs to modify their tariffs
to eliminate deviation charges for virtual purchasers, during the same
period as they are eliminated for physical purchasers as set out above,
unless the RTO or ISO upon compliance makes a showing that it would be
appropriate to assess such deviation charges for virtual purchasers
during this period. This approach establishes a reasoned generic policy
and still provides an opportunity for each RTO or ISO, on a case-by-
case basis, to present a factual record that the generic policy does
not fit its overall market design.
4. Aggregation of Retail Customers
a. Commission Proposal
    128. In the NOPR, the Commission proposed to require RTOs and ISOs
to amend their market rules as necessary to permit an ARC to bid demand
response on behalf of retail customers directly into the RTO's or ISO's
organized markets, unless the laws or regulations of the relevant
electric retail regulatory authority do not permit a retail customer to
participate.\174\
---------------------------------------------------------------------------

    \174\ NOPR, FERC Stats. & Regs. ] 32,628 at P 86.
---------------------------------------------------------------------------

    129. The Commission recognized that each region's market design is
different and that it is important for ARC provisions to respect these
market design differences. For this reason, the Commission proposed not
to mandate generic market rule amendments; rather, it proposed to
require RTOs and ISOs to amend their tariffs and market rules as
necessary to allow an ARC to bid demand response directly into the
RTO's or ISO's organized market, provided that the ARC's demand
response bid must meet the same requirements as a demand response bid
from any other entity such as an LSE. The NOPR proposed the following
flexibilities in RTO and ISO market designs:
     The RTO or ISO may require the ARC to be an RTO member if
membership is a requirement for other bidders.
     RTOs and ISOs may require that an aggregated bid must
consist of individual demand response bids from a single area,
reasonably defined.
     An RTO or ISO may place appropriate restrictions on any
customer's participation in an ARC-aggregated demand response bid to
avoid counting the same demand response resource more than once.
     The market rules do not have to allow bids from an ARC if
this is not permitted under the laws or regulations of the relevant
electric retail regulatory authority. The RTO or ISO must receive
explicit notification from the relevant retail regulatory authority in
order to disqualify a bid from an ARC that includes the demand response
of that authority's retail customers.
    130. The Commission requested comment about whether: (1) These
features of the proposal are appropriate and whether there are
additional appropriate criteria or features for allowing an ARC to bid
demand response; and (2) there is any reason not to subject an ARC to
the same requirements as any other bidder in the energy market.\175\
---------------------------------------------------------------------------

    \175\ Id. P 88, 91.
---------------------------------------------------------------------------

    131. The Commission proposed that an RTO or ISO must either propose
amendments to its tariff to comply with the requirement or demonstrate
in a filing that its existing tariff and market design already satisfy
the requirement to permit an ARC to bid demand response on behalf of
retail customers.\176\ It also proposed that this filing be submitted
within six months of the date the Final Rule is published in the
Federal Register. The Commission proposed that it would assess whether
each filing satisfies the proposed requirement and would issue
additional orders as necessary.
---------------------------------------------------------------------------

    \176\ Id. P 92.
---------------------------------------------------------------------------

b. Comments
i. Comments regarding ARC proposal
    132. Many commenters support the NOPR proposal to allow ARCs to bid
demand response directly into organized markets, unless it is not
permitted by the relevant regulatory authority.\177\ For instance, EEI
asserts that the Commission should adopt this proposal in the Final
Rule because it is appropriate for RTOs and ISOs to treat ARCs
comparably to wholesale market participants under RTO and ISO rules as
long as: (1) State commissions permit aggregation of retail demand
response; (2) such treatment is aligned with state requirements; and
(3) no preferential treatment is accorded to ARCs, including being
subject to monitoring and verification requirements.\178\ Some
commenters note that experiences in organized markets have demonstrated
that allowing ARCs to participate directly in wholesale energy markets
has increased market efficiency and led to greater diversity of demand
response options.\179\ In particular, Comverge and EnerNOC note that
allowing ARCs to enter wholesale energy markets has been successful in
PJM, ISO New England, and NYISO.\180\
---------------------------------------------------------------------------

    \177\ E.g., American Forest; BlueStar Energy; BP Energy;
California PUC; Comverge; DC Energy; Dominion Resources; DRAM; EEI;
EnergyConnect; Energy Curtailment; EnerNOC; Exelon; FirstEnergy;
IMEA; Industrial Coalitions; Industrial Consumers; Integrys Energy;
ISO/RTO Council; LPPC; MADRI States; Midwest ISO; NYISO; Ohio PUC;
OMS; OPSI; Pennsylvania PUC; PG&E Public Interest Organizations;
Reliant; Retail Energy; Steel Producers; Wal-Mart; and Xcel.
    \178\ EEI at 16.
    \179\ E.g., DRAM at 20; EnerNOC at 12.
    \180\ Comverge at 18; EnerNOC at 12-13.
---------------------------------------------------------------------------

    133. Industrial Coalitions note that this proposal would expand the
pool of potential demand response providers, thereby increasing demand
elasticity. American Forest states that the proposal could encourage
development of state-level retail programs that may not otherwise be
considered. The potential for such participation may encourage the
development of state law or retail structures to accommodate
participation where none now exists as retail customers seek to avail
themselves of the opportunities larger markets offer.\181\
---------------------------------------------------------------------------

    \181\ American Forest at 5-6.
---------------------------------------------------------------------------

    134. Ameren states, however, that unless RTOs and ISOs develop and
properly implement clear tariff provisions and market rules that
explain how the aggregation of retail customers for demand response
reductions will work, LSEs and providers of last resort could be harmed
by ARCs' demand bids. Ameren asserts that ARCs' unanticipated demand
reductions can expose LSEs and providers of last resort to the
difference between day-ahead and real-time locational marginal prices,
as well as to deviation charges due to this difference. Ameren urges
the Commission to require RTOs and ISOs to adopt tariff provisions and
market rules that protect LSEs and providers of last resort from such
harm if an ARC reduces load. Similarly, NCPA urges the Commission to
require coordination among the LSE, the ARC, and the RTO or ISO. NCPA
asserts that such coordination is necessary to preserve the value of
the demand response and to prevent imprudent resource planning or
operating decisions.\182\
---------------------------------------------------------------------------

    \182\ NCPA at 3-4.
---------------------------------------------------------------------------

    135. BP Energy is concerned that ARCs' participation in wholesale
markets during non-emergency periods can lead to gaming. Therefore, it
recommends that the Commission consider restricting or eliminating
during any non-emergency period any

incentive, subsidy or capacity-type payment for RTO and ISO demand
response programs related to energy markets.\183\ Similarly, LPPC
states that each RTO or ISO should adopt mechanisms to prevent gaming
of the program.\184\
---------------------------------------------------------------------------

    \183\ BP Energy at 16.
    \184\ LPPC at 8.
---------------------------------------------------------------------------

    136. TAPS believes that the Commission's proposal regarding ARCs
may require existing LSE demand response programs to change to
accommodate the ARC demand response programs, which would increase
rather than decrease barriers to effective demand response programs. It
requests clarification that the Commission's proposal would not require
any change to an existing aggregation program that already functions
well.
    137. Several regional entities maintain that they are already
working to allow ARC participation in their markets. CAISO states that
it is working with its stakeholders and California PUC to address
regulatory policy and state law concerning aggregation. ISO New England
states that its current market rules allow ARCs to aggregate retail
customers for the purpose of participating in demand response programs
and the forward capacity market. Midwest ISO notes that, in accordance
with the Commission's ASM Order,\185\ it will continue to work with
stakeholders to develop tariff provisions to allow ARCs to operate
within its footprint. Finally, NYISO states that it is making efforts
to identify common issues and best practices related to demand resource
bidding programs.\186\
---------------------------------------------------------------------------

    \185\ See infra note 60.
    \186\ NYISO at 10.
---------------------------------------------------------------------------

    138. SPP states that there are no states within its footprint that
currently provide retail access. However, to the extent there would be
an ARC within its footprint, it notes that it would be up to the
relevant retail regulatory authority to determine whether retail load
would be permitted to participate in the wholesale market demand
response program.\187\
---------------------------------------------------------------------------

    \187\ SPP at 5-6.
---------------------------------------------------------------------------

ii. Comments on regulatory approval of ARCs
    139. Most regulatory authorities, including NARUC, as well as other
commenters, such as NRECA, APPA, and TAPS, ask the Commission to modify
its proposal to clarify that an ARC or any retail customer may not bid
load-reduction response into an RTO or ISO market without the relevant
retail regulatory authority's express permission.\188\ They assert that
the Commission's proposal would allow ARCs to bid retail demand
response into organized energy markets without express permission from
the relevant retail regulatory authority and thereby place a burden on
the local authority to take affirmative action to disallow such
participation. Some assert that such a burden displaces state authority
and would impose an undue burden on municipalities, resulting in
unintended consequences.\189\ They state that an ARC's participation
should be subject to the rules and laws of the relevant retail
regulatory authority and argue that an ARC or any retail customer
should not bid load-reduction response into an RTO or ISO market
without the relevant retail regulatory authority's express permission.
They contend that the burden should be on the ARC or the regional
entity to obtain state regulators' permission for the demand response
program, and not on the retail electric regulatory authority to
prohibit it.
---------------------------------------------------------------------------

    \188\ E.g., APPA at 43; California PUC at 17; IMEA at 2; Kansas
CC at 2; Maine PUC at 4; NARUC at 8; NCPA at 3; North Carolina
Electric Membership at 5; NRECA at 12; Ohio PUC at 8; Pennsylvania
PUC at 12; NIPSCO at 13; PG&E at 9; and Old Dominion at 13.
    \189\ E.g., NRECA at 10-14; NARUC at 7; TAPS at 13; and IMEA at
2. APPA notes that only a small fraction of the 1,315 public systems
providing retail electric services in states served by RTOs and ISOs
have laws or rules that address end-use aggregation. Therefore, it
argues that requiring relevant electric retail regulatory authority
to take affirmative actions to consider retail aggregation by ARCs
can be a substantive undertaking. APPA at 44.
---------------------------------------------------------------------------

    140. The Final Rule, they contend, should specify that an RTO or
ISO can accept ARC bids only if the relevant electric retail regulatory
authority affirmatively informs the RTO or ISO that it permits ARC
activities for its retail load; without such explicit notification, the
RTO should presume that an ARC could not lawfully aggregate the retail
load. For instance NARUC states that the last criterion proposed by the
Commission should be revised to state that:

    The market rules shall not allow bids from an ARC unless this is
expressly permitted under the laws or regulations of the relevant
electric retail regulatory authority. The RTO or ISO must receive
explicit notification from the relevant retail regulatory authority
in order to qualify a bid from an ARC that includes the demand
response of that authority's retail customers.\190\
---------------------------------------------------------------------------

    \190\ NARUC at 9. PG&E and NRECA offer similar revisions. PG&E
at 10; NRECA at 11.

    141. NRECA argues that if the Commission does not require explicit
permission from the relevant authority, ARCs would effectively be
allowed to cherry-pick the best load response resources out of existing
LSE demand response programs. NRECA contends that this would deprive
those LSEs of important resources used to keep rates down for all
consumers.\191\ APPA, like NRECA, asks that the Commission require RTOs
and ISOs to assume that in the case of public power systems,
aggregation is not permitted unless the state's retail regulatory
authority has notified the RTO or ISO otherwise. However, if the
Commission maintains the NOPR proposal over APPA's objections, APPA
suggests an alternative approach to this issue, making it clear that
this is not its preferred approach. It suggests that the Commission
implement its proposal for power systems with 4 million MWh or more in
total annual output, but exempt systems of smaller size.\192\ That is,
for power systems above 4 million MWh of total annual output the
presumption would be as proposed by the Commission: that an ARC or
individual retail consumer may bid demand response into an organized
wholesale power market unless the relevant electric retail regulatory
authority notifies the RTO or ISO that this is not permitted. For
smaller systems, the presumption would be that retail load may not be
bid into the organized market, unless the relevant electric retail
regulatory authority expressly indicates that participation by retail
customers is permitted. APPA states that this option would preserve the
Commission's intention to remove barriers to the participation of
demand response resources in organized wholesale electricity markets
while not imposing an undue burden on small systems that may not be
prepared to address this issue.
---------------------------------------------------------------------------

    \191\ NRECA at 14.
    \192\ APPA at 47. APPA states that the United States Small
Business Administration defines an entity whose total annual output
is under 4 million MWh as a small utility. APPA at 45 & n.21.
---------------------------------------------------------------------------

    142. E.ON U.S. opposes the proposal on the grounds that it violates
the separation of federal and state jurisdiction and places at risk a
utility's obligation to serve its retail load.\193\ It notes that state
regulatory commission approval is required before retail customers may
band together to offer a bid into the wholesale market and such an
approval will be difficult if the program benefits large customers to
the detriment of many small customers. Also, while Mr. Borlick does not
oppose the proposal, he states that ARCs are not the best means for
promoting demand response resources.\194\
---------------------------------------------------------------------------

    \193\ E.ON U.S. at 11.
    \194\ Mr. Borlick at 3.
---------------------------------------------------------------------------

    143. PG&E asserts that explicit approval of the regulatory
authority is

needed to assure that opportunities for unreasonable and unfair
allocations of cost are eliminated and that critical enabling elements
have been established. According to PG&E, this includes: (1) Assuring
that a customer properly informs a load-serving entity of its demand
response participation; (2) assurance that costs are not
inappropriately transferred from one group of customers to another
through demand response aggregation; (3) that appropriate RTO or ISO
metering protocols exist to eliminate double counting concerns; and (4)
resource adequacy value is fairly allocated.\195\
---------------------------------------------------------------------------

    \195\ PG&E at 9.
---------------------------------------------------------------------------

    144. Wal-Mart, however, states that the Commission has the
authority to promote aggregation of retail load reduction bids,
including bids from individual retail customers, and should not require
RTOs or ISOs to reject bids unless permitted by the relevant retail
regulatory authority.\196\ Similarly, some commenters assert that the
Commission should exercise its jurisdiction over demand response
programs to direct RTOs and ISOs to allow any retail customer either on
its own or through an aggregator to participate in RTO or ISO demand
response programs as long as the customer can meet the operational
requirements of the RTO or ISO tariff, without consulting with a state
commission.\197\ They contend that such unrestricted access to demand
response programs is the best way to maximize program participation and
thereby bring benefits to organized markets. In the alternative,
however, they state that they support the NOPR proposal.\198\
---------------------------------------------------------------------------

    \196\ Wal-Mart at 6-7.
    \197\ Integrys Energy at 4-5; Retail Energy at 2.
    \198\ Integrys Energy at 5; Retail Energy at 2
---------------------------------------------------------------------------

    145. Xcel supports the proposed rule on aggregation by ARCs, but
asks the Commission to clarify how the RTO or ISO would receive
explicit notification from the relevant regulatory authority to
disqualify an offer from an ARC. Xcel suggests that the Commission
follow the procedure used for compliance with NERC mandatory electric
reliability standards and require each ARC to register with the RTO or
ISO, which could then require the ARC to certify that it has received
the appropriate regulatory approval.\199\
---------------------------------------------------------------------------

    \199\ Xcel at 9-10.
---------------------------------------------------------------------------

iii. Comments on proposed criteria and regional flexibility
    146. Many commenters state that they support the Commission's
proposed criteria and regional flexibility for RTOs and ISOs listed in
the NOPR for allowing an ARC to bid retail load-response into an RTO or
ISO market.\200\ For example, LPPC believes that the proposed criteria
are useful in evaluating RTO and ISO implementation of the proposal. It
also suggests two additional criteria: (1) the RTO or ISO must
demonstrate that its procedure for administering ARC bids effectively
coordinates activities of the ARCs and LSEs; and (2) the Commission
should ensure that there is a demonstration of net benefits to
consumers and that a system is in place for verifying that demonstrated
load reduction is achieved.\201\
---------------------------------------------------------------------------

    \200\ E.g., Exelon at 9; Industrial Consumers at 16; LPPC at 8;
MADRI States at 5;NYISO at 9; Reliant at 6; and Wal-Mart at 7.
    \201\ LPPC at 8.
---------------------------------------------------------------------------

    147. Reliant agrees with the Commission's proposed criteria, but it
believes that the most effective approach for demand response
development is through the direct relationship between the retail
customer and its LSE.\202\
---------------------------------------------------------------------------

    \202\ Reliant at 6.
---------------------------------------------------------------------------

    148. Many commenters support the NOPR proposal to allow each market
to develop its own rules to implement retail aggregation by ARCs.\203\
For example, Dominion Resources agrees with the Commission that it is
important for RTOs and ISOs to have flexibility in developing ARC
provisions to account for regional differences.\204\ EEI stresses that
RTOs and ISOs should have flexibility to adopt pricing methods and
other provisions that reflect regional differences.\205\ NEPOOL
Participants states that the current arrangements in ISO New England
already allow ARCs to participate in its markets, and any changes to
the existing program to accommodate Commission directives should be
handled through the stakeholder process. SoCal Edison-SDG&E believe
that CAISO should have the flexibility to pursue development of demand
response programs without being constrained by overly broad nationwide
restrictions and requirements. California Munis urges the Commission to
consider regional and jurisdictional distinctions that may affect ARCs'
effectiveness, noting that some states and local jurisdictions within
RTO or ISO may not have adopted a retail choice model.
---------------------------------------------------------------------------

    \203\ E.g., APPA; California Munis; Dominion Resources; EEI;
Exelon; ISO/RTO Council; Old Dominion; NEPOOL Participants; and
SoCal Edison-SDG&E.
    \204\ Dominion Resources at 5.
    \205\ EEI at 17.
---------------------------------------------------------------------------

    149. Public Interest Organizations, however, recommend that the
Commission adopt a more detailed generic (pro forma) set of market
rules on ARCs, which RTOs and ISOs may modify based on regional
differences if the modifications are comparable or superior to the
Commission's rules. According to Public Interest Organizations, these
pro forma rules could be developed through a technical conference.
iv. Comments on Specific ARC Requirements and Clarifications
    150. Many commenters assert that it is important that ARCs be
required to comply with necessary technical requirements.\206\ For
instance, several commenters state that certain technical matters
should be standardized, including (1) the method for determining
baseline compensation, (2) tools to establish uniform baselines and
verification, (3) interface tools for demand response to use a common
portal and protocol in organized markets, and (4) telemetry and
metering requirements.\207\ DC Energy states that ARCs should provide
verification of measurement equal to others in the same market and
notes that all participants should have similar requirements for the
ability to bid into wholesale markets. DRAM and Converge state that
double payment should be avoided and FirstEnergy asserts that each RTO
or ISO should adopt appropriate restrictions to avoid double counting.
---------------------------------------------------------------------------

    \206\ E.g., NYISO at 5; LPPC at 7; Comverge at 18; EEI at 2; and
Industrial Consumersat 14.
    \207\ E.g., DRAM at 21; Comverge at 18; and NEPOOL Participants
at 9.
---------------------------------------------------------------------------

    151. EnergyConnect notes that past efforts to aggregate small
retail loads have not been successful primarily due to the requirement
that every small resource in an aggregated group meet the same
registration, measurement and verification standards as large
generators or other resources. EnergyConnect recommends the use of
sampling or other techniques to address this issue.
    152. Several commenters seek clarification of various aspects of
the proposal. For instance, EEI stresses that the Final Rule should
clarify that RTOs and ISOs may specify certain requirements of ARCs,
such as registration and creditworthiness requirements, and that RTOs
and ISOs should have the flexibility to adopt pricing methods and other
provisions that reflect regional differences.\208\ Industrial
Coalitions also ask the Commission to clarify that ARCs, like LSEs and
industrial customers, should be held accountable for responding

when called upon by their respective RTO or ISO. LPPC requests that the
Commission clarify that its rules would not permit ARC bids to be
submitted on behalf of load served by LSEs that are not RTO or ISO
members. Similarly, SMUD requests clarification that the Commission did
not intend that loads located outside the control area of an RTO or ISO
would participate in demand response programs, whether through a retail
aggregator or directly with the RTO or ISO.
---------------------------------------------------------------------------

    \208\ EEI at 17.
---------------------------------------------------------------------------

    153. NYISO states that the Commission should not accept proposals
that would provide preferential treatment to ARCs or that would not be
comparable to the rules for other demand resources or generators.\209\
NYISO suggests that the Commission amend its proposed regulatory text
in section 35.28(g)(iii) to clarify that ARCs must meet ``applicable
reliability requirements'' before they can bid into regional markets,
and clarify that the reference to ``organized market'' has the same
meaning as proposed under subsection (g)(i).\210\ Similarly, it states
that the Commission should conform subsection (g)(iii) to (g)(i) so
that (g)(iii) will specifically require ARCs to comply with ``necessary
technical requirements under the RTO or ISO tariff.'' NYISO notes that
such a change will ensure that RTOs and ISOs may adopt reasonable
metering, verification, communications, minimum size, and other
technical rules for both individual demand resources and ARCs.\211\
---------------------------------------------------------------------------

    \209\ NYISO at 9-10.
    \210\ Section 35.28 (g)(i) establishes that ``organized
markets'' includes any RTO or ISO-administered market based on
competitive bidding.
    \211\ NYISO at 10.
---------------------------------------------------------------------------

c. Commission Determination
    154. The Commission adopts in this Final Rule the proposed rule to
require RTOs and ISOs to amend their market rules as necessary to
permit an ARC to bid demand response on behalf of retail customers
directly into the RTO's or ISO's organized markets, unless the laws or
regulations of the relevant electric retail regulatory authority do not
permit a retail customer to participate. We find that allowing an ARC
to act as an intermediary for many small retail loads that cannot
individually participate in the organized market would reduce a barrier
to demand response. Aggregating small retail customers into larger
pools of resources expands the amount of resources available to the
market, increases competition, helps reduce prices to consumers and
enhances reliability. We also agree with commenters that this proposal
could encourage development of demand response programs and thereby
provide retail customers more opportunities available through larger
markets. Additionally, as some commenters note, experiences with
existing aggregation programs in PJM, NYISO, and ISO New England have
shown that these programs have increased demand responsiveness in these
regions.
    155. We are mindful of the comments that allowing ARCs to bid into
the wholesale energy market without the relevant electric retail
regulatory authority's express permission may have unintended
consequences, such as placing an undue burden on the relevant electric
retail regulatory authority. In the NOPR, the Commission sought to
address the concerns of state and local retail regulatory entities by
proposing to require that an ARC may bid retail load reduction into an
RTO or ISO regional market unless the laws or regulations of the
relevant electric retail regulatory authority do not permit a retail
customer to participate in this activity. The Commission's intent was
not to interfere with the operation of successful demand response
programs, place an undue burden on state and local retail regulatory
entities, or to raise new concerns regarding federal and state
jurisdiction, as some commenters argue. As described above, we clarify
that we will not require a retail electric regulatory authority to make
any showing or take any action in compliance with this rule. Rather,
this rule requires an RTO or ISO to accept a bid from an ARC, unless
the laws or regulations of the relevant electric retail regulatory
authority do not permit the customers aggregated in the bid to
participate.
    156. In response to E.ON U.S., we do not agree that the approach we
adopt here violates the separation of federal and state jurisdiction.
Rather, we find that this action properly balances the Commission's
goal of removing barriers to development of demand response resources
in the organized markets that we regulate with the interests and
concerns of state and local regulatory authorities.
    157. With regard to LPPC's request that ARCs not bid on behalf of
load served by LSEs that are not RTO or ISO members, SMUD's request for
clarification that loads outside of an RTO's or ISO's control area
would not participate in demand response programs, and TAPS's comment
that the proposal should not require a change to an existing retail
load reduction program, the continuing role of the relevant retail
electric regulatory authority adequately addresses these concerns.
    158. Further, we agree with the comments that, because each
region's market design is different, it is important to permit each RTO
or ISO to design ARC provisions that account for these differences.
Therefore, instead of developing pro forma language or requiring RTOs
and ISOs to make detailed generic market rule amendments, we direct
RTOs and ISOs to amend their tariffs and market rules as necessary to
allow an ARC to bid demand response directly into the RTO's or ISO's
organized market in accordance with the following criteria and
flexibilities that remain largely unchanged from those advanced in the
NOPR:
    a. The ARC's demand response bid must meet the same requirements as
a demand response bid from any other entity, such as an LSE. For
example:
    i. Its aggregate demand response must be as verifiable as that of
an eligible LSE or large industrial customer's demand response that is
bid directly into the market;
    ii. The requirements for measurement and verification of aggregated
demand response should be comparable to the requirements for other
providers of demand response resources, regarding such matters as
transparency, ability to be documented, and ensuring compliance;
    iii. Demand response bids from an ARC must not be treated
differently than the demand response bids of an LSE or large industrial
customer.
    b. The bidder has only an opportunity to bid demand response in the
organized market and does not have a guarantee that its bid will be
selected.
    c. The term ``relevant electric retail regulatory authority'' means
the entity that establishes the retail electric prices and any retail
competition policies for customers, such as the city council for a
municipal utility, the governing board of a cooperative utility, or the
state public utility commission.
    d. An ARC can bid demand response either on behalf of only one
retail customer or multiple retail customers.
    e. Except for circumstances where the laws and regulations of the
relevant retail regulatory authority do not permit a retail customer to
participate, there is no prohibition on who may be an ARC.
    f. An individual customer may serve as an ARC on behalf of itself
and others.
    g. The RTO or ISO may specify certain requirements, such as
registration with the RTO or ISO, creditworthiness requirements, and
certification that participation is not precluded by the

relevant electric retail regulatory authority.\212\
---------------------------------------------------------------------------

    \212\ The RTO or ISO should not be in the position of
interpreting the laws or regulations of a relevant electric retail
regulatory authority.
---------------------------------------------------------------------------

    h. The RTO or ISO may require the ARC to be an RTO or ISO member if
its membership is a requirement for other bidders.
    i. Single aggregated bids consisting of individual demand response
from a single area, reasonably defined, may be required by RTOs and
ISOs.
    j. An RTO or ISO may place appropriate restrictions on any
customer's participation in an ARC-aggregated demand response bid to
avoid counting the same demand response resource more than once.
    k. The market rules shall allow bids from an ARC unless this is not
permitted under the laws or regulations of relevant electric retail
regulatory authority.
    159. The above criteria in combination with regional flexibility
will provide the foundation for each RTO and ISO to work with its
stakeholders, including state and local regulatory entities, to develop
market rules that will enable more small entities to provide demand
response to the regional markets. Such a process would provide the
forum necessary to discuss and resolve concerns raised by the
commenters in this proceeding, including: (1) Developing standardized
terms and conditions, (2) the requirement that ARC's demand response
bid must meet the same requirements as other demand response bids,\213\
(3) verification and measurement, (4) penalties for non-compliance, (5)
registration and creditworthiness requirements, and (6) mechanisms to
prevent gaming. Further, in response to those who ask us to require in
this rule (1) that each RTO or ISO should be required to demonstrate
net benefits of its program, (2) that bids should be aggregated on a
local basis, and (3) that so called ``double payment'' should be either
required or prohibited, we decline to do so here. Such issues are more
appropriately addressed by each region in its compliance filing if it
chooses to do so.
---------------------------------------------------------------------------

    \213\ We note that ``same requirement'' does not necessarily
mean identical to other demand response bids. An ARC's demand
response bid must meet similar or comparable requirements as other
demand response bids.
---------------------------------------------------------------------------

    160. Given this regional approach, we do not find that standardized
technical issues or a pro forma set of market rules, as raised by some
commenters, is necessary at this time. The comments do not persuade us
to add additional criteria to the criteria adopted herein. As noted
above, we encourage RTOs and ISOs to coordinate their efforts with
customers, state and local regulatory entities, and other stakeholders.
The Commission will consider such regional proposals in the compliance
filings. Further, we agree with commenters on the need for coordination
of the activities of the ARCs and LSEs to ensure efficient operation of
the markets.
    161. In accordance with NYISO's recommendation, the Commission will
clarify that its regulatory reference in Sec.  35.28 (g)(ii) to
``organized market'' has the same meaning as proposed under (g)(i) and
that ARCs are to comply with any necessary technical requirements under
the RTO's or ISO's tariff.
    162. Regarding NYISO's recommendation that the Commission clarify
that ARCs must meet ``applicable reliability requirements,'' the
Commission does not see a need to change its proposed language in this
rulemaking because reliability issues are addressed by each RTO or ISO
in accordance with Commission established reliability requirements.
    163. Each RTO and ISO is required to submit, within six months of
the date that this Final Rule is published in the Federal Register, a
compliance filing with the Commission, proposing amendments to its
tariffs or otherwise demonstrating how its existing tariff and market
design is in compliance with the requirements of this Final Rule.
    164. We appreciate comments of CAISO, ISO New England, Midwest ISO,
and NYISO that they are already working with stakeholders to allow ARCs
to operate within their footprint or to address compliance issues. With
regard to SPP's comment that there is no retail access state within
SPP, the Commission notes that its ARC requirements are not limited to
aggregation of retail customers who have retail choice. We will not
prejudge here whether any nascent ARC program will satisfy our
requirements. Nor will we decide whether a regulator of a traditional,
vertically-integrated monopoly utility may give permission for an ARC
to aggregate retail customers' demand responses for bidding into SPP's
markets. SPP may explain in its compliance filing its situation
regarding retail choice but should also explain how it would
accommodate a bid from an ARC consistent with the criteria listed
above.
5. Market Rules Governing Price Formation During Periods of Operating
Reserve Shortage
    165. In the NOPR, the Commission observed that existing RTO and ISO
market rules continue to appear to be unjust, unreasonable, and unduly
discriminatory or preferential during periods of operating reserve
shortages. In particular, the Commission noted that these rules may not
produce prices that accurately reflect the true value of energy in such
an emergency and, by failing to do so, may harm reliability, inhibit
demand response, deter new entry of demand response and generation
resources, and thwart innovation.\214\
---------------------------------------------------------------------------

    \214\ NOPR, FERC Stats. & Regs. ] 62,628 at P 107.
---------------------------------------------------------------------------

    166. Therefore, the Commission proposed to reform market rules
governing price formation in RTO and ISO energy markets during
operating reserve shortages. Specifically, the Commission proposed to
require each RTO or ISO with an organized energy market to make a
compliance filing, within six months of the date that the Final Rule is
published in the Federal Register, proposing any necessary reforms to
ensure that the market price for energy accurately reflects the value
of such energy during shortage periods (i.e., an operating reserve
shortage). The Commission stated that each RTO or ISO may propose one
of four suggested approaches to pricing reform during an operating
reserve shortage or to develop its own alternative approach to achieve
the same objectives. These approaches are discussed in section (b) of
this chapter. Alternatively, an RTO or ISO may demonstrate that its
existing market rules already reflect the value of energy during
periods of shortage and, therefore, do not need to be reformed. The
Commission proposed to require RTOs and ISOs proposing reforms or
demonstrating the adequacy of existing market rules to provide an
adequate factual record for the Commission to evaluate their proposals;
and proposed six criteria by which the Commission would evaluate the
RTO's or ISO's compliance filing. The Commission asked for comments on
these criteria. The Commission noted that any change in market rules to
implement the proposed reforms must consider the issue of market power
abuse, recognize regional differences in market rules, and be based on
a sound factual record.
    167. Further, the Commission stated that it would require any RTO
or ISO proposing reform in this area to address the adequacy of any
market power mitigation measures that would be in place during periods
of operating reserve shortage. In addition, to ensure an adequate
record on the issue of market power mitigation, the Commission proposed
to solicit the views of the Independent Market

Monitor for each RTO or ISO region on any proposed reforms in this
area.
    168. Section (a) of this Chapter presents a discussion of the
Commission's proposed rule to reform pricing for RTOs and ISOs to more
accurately reflect the value of energy during periods of operating
reserve shortage. Section (b) addresses comments on the four approaches
provided by the Commission that RTOs and ISOs must consider in
addressing this issue. Section (c) addresses the six criteria that the
Commission proposed to ensure that any reforms implemented by an RTO or
ISO achieve the desired results; and section (d) addresses the option
for each RTO or ISO to phase-in its reform proposal over a number of
years.
a. Price Formation During Periods of Operating Reserve Shortage
i. Comments
    169. A number of commenters state that they support the proposed
rule on price formation during periods of operating reserve
shortage.\215\ Some of these commenters assert that prices must be
allowed to reflect the true value of energy during an operating reserve
shortage in order for wholesale energy markets to operate
efficiently.\216\ Other commenters state that a transparent price
signal can: (1) Enhance system reliability and protect customers; \217\
(2) encourage a vibrant demand response market because both demand
response and other sources of energy supply will participate in the
market to a greater degree; \218\ and (3) encourage those with advanced
metering technology to follow energy prices more closely, and those
without such technology to acquire it.\219\
---------------------------------------------------------------------------

    \215\ E.g., Mr. Borlick; BP Energy; CAISO; California PUC;
Comverge; Constellation; DC Energy; Dominion Resources; DRAM; Duke
Energy; EEI; EPSA; Exelon; FirstEnergy; Integrys Energy; Ohio PUC;
OMS; Potomac Economics; PJM Power Providers; PPL Parties; and
Reliant.
    \216\ E.g., BP Energy at 22; Mr. Borlick at 5; Comverge at 20,
22; Dominion Resources at 7; Exelon at 11; OMS at 6; PPL Parties at
5; and PJM Power Providers at 3.
    \217\ Comverge at 20, 23; PPL Parties at 5. PPL Parties notes
that ``customers will be protected because the price signal will
encourage more robust bilateral contracting, self-supplied
generation, the improved use of hedging and financial instruments,
and increased amounts of demand responsive load.'' PPL Parties at 6.
    \218\ PPL Parties at 5.
    \219\ OMS at 6.
---------------------------------------------------------------------------

    170. EEI maintains that RTOs and ISOs should modify their market
rules to allow the market-clearing price to accurately reflect the
value of energy during periods of operating reserve shortages. It also
agrees that any change in market rules must consider the issue of
market power, recognize regional differences in market rules, and be
based on a sound factual record.\220\
---------------------------------------------------------------------------

    \220\ EEI at 19.
---------------------------------------------------------------------------

    171. PJM Power Providers asserts that accurate price signals are
the cornerstone of a successful wholesale market design. It notes that
many of the problems in wholesale electric markets stem from market
design features that suppress prices during shortage conditions to
levels below the value of lost load.\221\ It adds that shortage pricing
can provide short-term signals to generation to ensure production and
long-term signals to allow for fixed cost recovery supporting
maintenance of existing facilities and new entry. Therefore, PJM Power
Providers asserts that a shortage pricing mechanism must be integrated
with the overall market design.
---------------------------------------------------------------------------

    \221\ PJM Power Providers at 3. See also PPL Parties at 5
(``implementing appropriate [shortage] pricing will require
permitting energy prices to rise when warranted to reflect the
average value of lost load'').
---------------------------------------------------------------------------

    172. Reliant states that for all RTOs and ISOs--with or without
capacity markets, prices in real-time should properly signal needed
responses from both supply-side and demand-side resources. To the
extent that price caps or bid mitigation suppress the appropriate price
signals in the energy market, reforms should be made. These price
signals are needed to encourage the necessary short-term response to
the market and also to provide critical pricing information to the
market.\222\ Reliant argues that the current market design in several
RTOs and ISOs does not support the investment needed to maintain system
reliability.\223\ It asserts that transparent price signals in the
market will encourage the most efficient and effective implementation
of new generation and demand-side technology and investment. Therefore,
to the extent that RTO and ISO market design fails to provide such
transparent price signals, Reliant asserts that the Commission should
direct necessary pricing reforms.\224\
---------------------------------------------------------------------------

    \222\ Reliant at 8.
    \223\ For example, in Midwest ISO and CAISO, Reliant notes that
market revenues were not sufficient to support new generation
investment. Id. at 9.
    \224\ Id. 9-10.
---------------------------------------------------------------------------

    173. Several commenters note that they support the proposed
shortage pricing proposal and also note that generation and demand
resources should be treated comparably during shortage pricing.\225\
For instance, OMS states that both generation and demand resources are
equally valuable so they should be treated comparably. In that respect,
it notes that, similar to generators, demand resources, if offered and
accepted into the market during shortage periods, should be assessed
penalties if the RTO calls on them and they do not comply.\226\
---------------------------------------------------------------------------

    \225\ PPL Parties at 5; First Energy at 11; and OMS at 6.
    \226\ OMS at 6.
---------------------------------------------------------------------------

    174. Several commenters support the Commission's proposal to
recognize regional differences by adopting a flexible regional
approach, rather than a general mandate.\227\ These commenters state
that given the market design and rule variations among organized
markets, a one-size-fits-all approach may not be appropriate. They
believe that it is reasonable for the Commission to establish
fundamental principles and necessary elements for promoting demand
responsiveness, while leaving the specifics of implementation to each
RTO or ISO market. Therefore, they support the Commission's proposal to
allow each region to choose its own shortage pricing approach from the
four offered or to choose another developed through the stakeholder
process.
---------------------------------------------------------------------------

    \227\ E.g., CAISO; EEI; EPSA; ISO/RTO Council; Midwest ISO; PJM
Power Providers; Old Dominion; Wal-Mart; ISO New England; NYISO; NY
TOs; Detroit Edison; Dominion Resources; and SPP.
---------------------------------------------------------------------------

    175. EEI also strongly supports the Commission's regional approach;
stating that, given the regional differences in market design, each
region should have the flexibility to propose its own approach or
demonstrate that its existing market rules satisfy this
requirement.\228\ Similarly, California PUC states that implementation
of this rule should be done through collaborative efforts between the
state commission and its respective RTO or ISO (e.g., how the shortage
price is set, at what level it is set, and under what circumstances the
shortage price is triggered).\229\
---------------------------------------------------------------------------

    \228\ EEI at 19.
    \229\ California PUC at 19. CAISO also states that it supports
the Commission's proposal to require RTOs and ISOs to study shortage
pricing market reforms and report back to the Commission.
---------------------------------------------------------------------------

    176. Several regional entities assert that they are in compliance
or will be in compliance with the proposed rule. For instance, CAISO
states that it will be in compliance with the proposed plans to
incorporate a demand curve for reserves within 12 months of the roll-
out of MRTU, as directed by the Commission.\230\ Midwest ISO states
that it is in compliance with the proposed rule because its recently-
approved ancillary services market incorporates a demand curve for
operating reserves.\231\ NYISO maintains that it intends to demonstrate
in its compliance filing that

its rules fully satisfy the NOPR's requirements.\232\ ISO New England
also states that it has a demand curve for operating reserves and thus
is in compliance with the proposal.\233\
---------------------------------------------------------------------------

    \230\ CAISO at 3.
    \231\ Midwest ISO at 16.
    \232\ NYISO at 4.
    \233\ ISO New England at 12; see also NEPOOL Participants at 16;
NSTAR at 3; and Maine PUC at 4-5.
---------------------------------------------------------------------------

    177. Many commenters object to the Commission's proposed rule on
pricing reform during periods of operating reserve shortages, and they
proffer various reasons.\234\ Some of these commenters oppose the
proposed rule on grounds that it will result in exercise of market
power because the organized markets are not competitive,\235\ leading
to unjust and unreasonable rates. APPA argues that the prices produced
by RTO or ISO markets do not reflect the actual economic costs of
providing service because the rates are not the product of competitive
markets.\236\ According to APPA, the only restraint on generation
suppliers' ability to extract the maximum amount of profits from
regional markets is the RTO's and ISO's market mitigation rules. It
states that exposing retail consumers directly to unmitigated price
signals would result in unjust and unreasonable rates. Therefore, APPA
urges the Commission to first address market deficiencies, including
market competitiveness and proper demand response infrastructure, in
order to enable consumers to respond to higher prices.\237\ NRECA
argues that the Commission would violate its duty under FPA if it were
to subject customers to unjust and unreasonable rates, even if those
excessive rates were limited to emergency situations.\238\
---------------------------------------------------------------------------

    \234\ E.g., Alcoa; APPA; California Munis; Industrial
Coalitions; Industrial Consumers; LPPC; North Carolina Electric
Membership; NRECA; OLD Dominion; TAPS; Steel Manufacturers; SMUD;
Public Interest Organizations; New Jersey BPU; and National Grid.
    \235\ E.g., Alcoa; APPA; NRECA; TAPS; North Carolina Electric
Membership; Pennsylvania PUC; LPPC; and Steel Manufacturers.
    \236\ APPA at 53.
    \237\ Id. at 30-31. The California Munis adopt the comments of
APPA on these issues and incorporate them by reference into their
comments. California Munis at 17.
    \238\ NRECA at 16.
---------------------------------------------------------------------------

    178. LPPC is opposed to proposals that would permit generation
prices to rise above rate cap levels during scarcity situations.\239\
According to LPPC, the proposed rule would undermine the Commission's
core mission to ensure just and reasonable rates and would result in an
unjust and unreasonable transfer of wealth from customers to
generators. It notes that the Commission has long approved the use of
price caps in RTO and ISO markets in order to mitigate market power and
to protect customers from unreasonable prices during periods of
capacity deficiency or emergency.\240\ It asserts that removing these
price caps would be inconsistent with Commission precedent that market-
based rates may be relied on only where the Commission has determined
that the market is sufficiently competitive.\241\ It further argues
that the Commission is abdicating market mitigation by abandoning price
caps when it has previously determined that price caps are needed to
restrain prices in times of scarcity.\242\ Therefore, instead of
removing bid caps, LPPC believes that the Commission should promote
demand response through payments for demand reduction.
---------------------------------------------------------------------------

    \239\ LPPC at 3.
    \240\ Id. at 9-10.
    \241\ Id. at 12 (citing California ex re. Lockyer v. FERC, 383
F.3d 1006 (9th Cir. 2004, cert denied, Coral Power, LLC v. Cal. ex
rel. Brown, 127 S. Ct. 2972, 168 L. Ed. 2d 719 (2007); Interstate
Natural Gas Ass'n v. FERC, 285 F.3d 18, 30-31 (DC Cir. 2002);
Elizabethtown Gas Co. v. FERC, 10 F.3d 866 (DC Cir. 1993); Louisiana
Energy & Power Auth. v. FERC, 10 F.3d 866 (DC Cir. 1998)).
    \242\ LPPC 12-13.
---------------------------------------------------------------------------

    179. Several commenters dispute the Commission's premise that
customers will be able to respond to higher prices.\243\ For instance,
Steel Manufacturers asserts that the vast majority of end users do not
see hourly price signals because they are retail customers regulated by
state commissions.\244\ According to Steel Manufacturers, only a small
percentage of loads, typically large manufacturing loads, who take
electric service through advanced meters will be able to respond to
price signals during periods of scarcity. Therefore, they argue that
there is no rational justification for imposing all market risks only
on such a small pool of retail loads.\245\ Further, New Jersey BPU
states that demand-side resources that pay a fixed seasonal or annual
retail price for electricity will have no reason to respond to any
dramatic increase in hourly prices.\246\
---------------------------------------------------------------------------

    \243\ E.g., North Carolina Electric Membership; New Jersey BPU;
Old Dominion; Steel Manufacturers; and Pennsylvania PUC.
    \244\ Steel Manufacturers at 12-13.
    \245\ Id.
    \246\ New Jersey BPU notes that virtually all New Jersey
residential customers and commercial and industrial customers below
100 kW pay fixed retail prices. Therefore, a major increase in
wholesale electricity prices during peak hours cannot be expected to
attract new demand resources from the large majority of New Jersey
customers. New Jersey BPU at 3.
---------------------------------------------------------------------------

    180. Similarly, TAPS argues that the proposed rule is not supported
by sufficient evidence that lifting such bid caps will attract demand
response sufficient to protect consumers from market power.\247\ It
asserts that when the Commission is relying on demand response to
provide the competitive response necessary to keep rates just and
reasonable, there must be sufficient empirical proof that actual prices
will be just and reasonable.\248\ TAPS contends that the Commission has
not provided such evidence, and is prepared to ``unleash market forces
without making factual findings that the demand response necessary to
restrain prices is ready, willing and able to be called upon.'' \249\
TAPS also disputes the Commission's statement that artificial bid caps
inhibit price signals needed to attract entry by both generation and
demand response resources. It asserts that high spot market prices do
not correlate with entry in RTO and ISO markets.\250\
---------------------------------------------------------------------------

    \247\ TAPS at 24.
    \248\ Id. at 24-25.
    \249\ Id. at 26. TAPS asserts that the Commission must protect
customers from excessive rates and charges, and if it acts without
the requisite empirical proof, the Commission will fail to protect
consumers. TAPS at 29 (citing, Atl. Ref. Co. v. Pub. Serv. Comm'n of
N. Y., 360 U.S. 378, 388 (1959)).
    \250\ TAPS at 26-27.
---------------------------------------------------------------------------

    181. Pennsylvania PUC states that demand response must be fully
integrated into existing markets before price caps can be removed in
RTOs and ISOs. It asserts that the Commission wrongly concludes that
price caps are inhibiting an otherwise competitive market. It also
argues that without infrastructure improvements that permit load to see
shortages being priced, removing bid caps would promote the exercise of
market power.\251\
---------------------------------------------------------------------------

    \251\ Pennsylvania PUC at 14-15.
---------------------------------------------------------------------------

    182. Similarly, Industrial Coalitions argue that necessary
technology and demand response capability must be in place before any
changes to mitigation rules can be contemplated. They also state that
there are barriers to demand response such as inadequate federal-state
coordination, utilities' ability to preclude and frustrate customer
participation, and complex participation requirements. Industrial
Coalitions ask that the Commission demonstrate how any change in
shortage pricing rules will result in lower prices to consumers.\252\
SMUD also states that while the elimination of every barrier to demand
response is not a prerequisite to easing bid caps for demand response,
the problem is that there are still significant barriers to demand
response participation that must be addressed first.\253\ SMUD reports
that there were deficiencies in technology that led the Commission not
to allow bid caps to be

lifted previously, and these technologies are still insufficiently
developed today.
---------------------------------------------------------------------------

    \252\ Industrial Consumers at 19.
    \253\ SMUD at 3 (citing NOPR, FERC Stats. & Regs. ] 32,628 at P
109).
---------------------------------------------------------------------------

    183. Old Dominion also opposes removing price caps and asserts that
efforts to increase demand response should not come at the expense of a
customer base that cannot respond to price signals.\254\ It states that
the Commission should adopt a presumption that such pricing incentives
are not necessary and require the RTOs and ISOs that believe otherwise
to make a factual demonstration that they are. This would include
demonstrating that non-price barriers to demand response have been
removed and that current market power mitigation rules will suffice to
deal with any gaming behavior.
---------------------------------------------------------------------------

    \254\ Old Dominion at 14.
---------------------------------------------------------------------------

    184. North Carolina Electric Membership states that there is no
evidence that generators require higher scarcity payments if the region
already has a capacity market.\255\ National Grid states that the
Commission's proposal to shift revenue from capacity markets to energy
markets should not be implemented because it conflicts with the market
designs approved by the Commission and implemented in NYISO and ISO New
England.\256\ New Jersey BPU does not share the Commission's belief
that such shortage pricing reforms will automatically lead to lower
prices in capacity markets.\257\ PG&E states that any proposed shortage
pricing rules must be coordinated with other mechanisms that provide
similar reliability benefits to electrical systems, including resource
adequacy requirements and DR programs.\258\ This must include capacity
pricing mechanisms. An explanation of such coordination should be a
requirement of the filing that RTOs and ISOs make as part of their
proposal. PG&E is particularly concerned about the CAISO's
implementation of reserve shortage pricing, along with its relaxation
of price caps, before meaningful demand response products are
available.
---------------------------------------------------------------------------

    \255\ North Carolina Electric Membership at 9.
    \256\ National Grid at 23.
    \257\ New Jersey BPU at 5.
    \258\ PG&E at 11.
---------------------------------------------------------------------------

    185. Comverge and DRAM state that they support the Commission's
proposal to reflect the value of energy during times of scarcity.
However, they note that they are concerned about how the proposal would
impact existing capacity markets, particularly in the longer term.\259\
Comverge states that where capacity markets are, or will be, in place
each of the four approaches may reduce capacity market prices because
revenues from energy and ancillary services would be subtracted from
capacity payments. This may discourage participation by some demand
response resources in capacity markets.\260\ According to DRAM, demand
response resources need the ``stable revenue stream'' from the capacity
market, and any energy payment received during reliability events is of
secondary importance.\261\ DRAM states that shortage pricing should not
be pursued in a way that requires demand response providers to
participate in the energy market because not all customers are suited
to, or interested in, energy market participation. Instead, it notes
that these customers may participate in a reliability-based demand
response program that helps preserve reliability, allowing them to be
paid to be a reliability resource. EnerNOC asks the Commission to
fashion a policy on shortage pricing that encourages demand response
resources to interact in both energy and capacity markets, or in either
one, in a manner that is most appropriate for the demand response
resource.\262\
---------------------------------------------------------------------------

    \259\ DRAM at 23.
    \260\ Comverge at 21-23.
    \261\ DRAM at 24.
    \262\ EnerNOC at 14.
---------------------------------------------------------------------------

    186. The FTC encourages the Commission to require that proposals
from RTOs and ISOs to lift wholesale bid caps during periods of
operating reserve shortages be accompanied by an analysis of how the
proposed change in the wholesale bid caps will change the totality of
regulatory restrictions on wholesale prices during these periods.\263\
Industrial Consumers also state that capacity markets should be
suspended prior to any shortage pricing changes to prevent the gaming
of multiple markets. They add that shortage pricing without competition
is ``monopoly pricing in disguise'' and assert that conditions of true
competition must be demonstrated before shortage price is used.\264\
---------------------------------------------------------------------------

    \263\ FTC at 29.
    \264\ Industrial Consumers at 19.
---------------------------------------------------------------------------

    187. PJM Power Providers agrees with the Commission that existing
market rules do not accurately reflect the value of energy during
periods of shortage and, therefore may deter new entry of demand
response and generation resources.\265\ They also agree that many of
the problems in wholesale electric markets stem from mitigation
policies and market design features that suppress prices during
shortage conditions below the value of lost load (VOLL). PJM Power
Providers notes that in addressing these issues, a balance must be
struck to encourage supplies to enter the market while minimizing
market power concerns.
---------------------------------------------------------------------------

    \265\ PJM Power Providers at 3.
---------------------------------------------------------------------------

    188. In this regard, PJM Power Providers notes that scarcity
pricing mechanisms need to be integrated into the overall market design
in order to be effective, so that prices reflect actual system
operation.\266\ It states that in the PJM market, pricing does not
always match operating procedures. For example, they note that due to
startup limitations the system operator may keep a peaking unit
operating during non-peak hours so that the unit may be used again
later in the day to meet increasing load. While operators should have
the flexibility to make these types of decisions, it is critical that
prices accurately reflect these operating procedures. Thus, PJM Power
Providers states that if the system operator compensates the generator
for the cost of keeping a peaking unit operating during non-shortage
periods through an uplift charge rather than through the market-
clearing price, as is currently the practice in PJM, this practice
``must be fixed.'' It states that the shortage pricing mechanism should
be coupled with a new ``reserve product'' so that the scarcity price
reflects the opportunity cost of held reserves (the cost of operating
the peaking unit during no-scarcity periods) in a manner that is
consistent with the overall shortage pricing rules. Finally, PJM Power
Providers states that to achieve the intended results, the Commission
must provide that when a contingency or constraint related to
operations and reserves is seen in either the day-ahead or real-time
market, shortage pricing should be reflected in the energy market as
well.
---------------------------------------------------------------------------

    \266\ Id. at 4.
---------------------------------------------------------------------------

    189. Finally, TAPS makes two recommendations. The first is that the
Commission should maintain some type of ``safety net cap'' that will
protect consumers against ``stratospheric'' prices.\267\ The second is
that if the Commission does approve some shortage pricing rules, it
must also revisit its approval of RTO and ISO capacity markets that
were justified on the basis that such caps prevented generators from
earning revenues needed to recover investment costs.\268\ It argues
that if spot market prices can rise to the levels claimed to be needed
to recover generator investment costs, a

principal justification for organized capacity markets is eliminated,
and consumers will be subjected to the high energy prices that the
capacity market was intended to replace.
---------------------------------------------------------------------------

    \267\ TAPS at 43.
    \268\ For example, TAPS notes that a primary justification of
ISO New England's locational installed capacity market proposal was
that caps take away revenues needed for cost recovery. Id. 43-44.
---------------------------------------------------------------------------

    190. Several commenters address the Commission's requirement that
RTOs and ISOs proposing shortage pricing reforms address the adequacy
of any market power mitigation measures and that the Commission will
solicit the views of the Independent Market Monitor for each RTO and
ISO on any proposed reforms. EEI states that the Commission is correct
to address concerns regarding the exercise of market power by requiring
that any proposed reforms be supported by an adequate record
demonstrating that provisions exist for mitigating market power and
deterring gaming behavior.\269\ EEI agrees that the Commission should
solicit input from the Independent Market Monitor on any proposed rule
changes in this area. Old Dominion states that the Commission should
adopt a presumption that such pricing incentives are not necessary and
require the RTOs and ISOs that believe otherwise to make a factual
demonstration that they are.\270\ This would include demonstrating that
non-price barriers to demand response have been removed and that
current market power mitigation rules will suffice to deal with any
gaming behavior. Public Interest Organizations urge that before current
market mitigation rules are relaxed, resource adequacy requirement must
be in place and that an independent market monitor must be able to
monitor shortage pricing behavior very closely.\271\ TAPS states that
the Commission needs to strengthen the factual showing that RTOs and
ISOs must make with respect to shortage pricing reforms \272\ to
include at least six analyses: (1) Address market power under scarcity
conditions; (2) measure whether demand response successfully mitigates
market power, including empirical evidence, such as critical loss
analyses; (3) examine the incentive and ability of demand response
resources to engage in withholding of their demand response resources;
(4) demonstrate that market power mitigation methods are effective
during shortage periods for any resource, demand or generation, that
can affect prices; (5) determine if there is enough demand response
available to respond under scarcity conditions; and (6) prepare
statistics on past and expected frequency of scarcity events as an
indication of the effectiveness of policies to ensure resource
adequacy.
---------------------------------------------------------------------------

    \269\ EEI at 19.
    \270\ Old Dominion at 15.
    \271\ Public Interest Organizations at 9.
    \272\ TAPS at 29.
---------------------------------------------------------------------------

    191. Comverge and DRAM express concerns about ``price averaging''
and its possible adverse impact on demand response resource
participation in organized markets. DRAM recommends time-differentiated
capacity payments based on loss-of-load probability or loss-of-load
expectation as an alternative to raising price caps during a period of
operating reserve shortage as a means of removing a barrier to demand
response resources.\273\
---------------------------------------------------------------------------

    \273\ Comverge at 10; DRAM at 10.
---------------------------------------------------------------------------

ii. Commission Determination
    192. In this Final Rule, the Commission adopts the proposed rule on
price formation during times of operating reserve shortage. The
Commission continues to find that existing rules that do not allow for
prices to rise sufficiently during an operating reserve shortage to
allow supply to meet demand are unjust, unreasonable, and may be unduly
discriminatory. In particular, they may not produce prices that
accurately reflect the value of energy and, by failing to do so, may
harm reliability, inhibit demand response, deter entry of demand
response and generation resources, and thwart innovation.
    193. When bid caps are in place, it is not possible to elicit the
optimal level of demand or generator response, thereby forgoing the
additional resources that are needed to maintain reliability and
mitigate market power. This, in turn, increases the likelihood of
involuntary curtailments and contributes to price volatility and market
uncertainty. Further, by artificially capping prices, price signals
needed to attract new market entry by both supply- and demand-side
resources are muted and long-term resource adequacy may be harmed.
Without accurate prices that reflect the true value of energy, we
cannot expect the optimal integration of demand response into organized
markets.
    194. Therefore, we are taking action to remove such barriers to
demand response by requiring price formation during periods of
operating shortage to more accurately reflect the value of such energy
during such shortage periods. Each RTO or ISO is required 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. The RTO or ISO is required to provide, as
part of its compliance filing, a factual record that includes
historical evidence for its region regarding the interaction of supply
and demand during periods of scarcity and the resulting effects on
market prices, an explanation of the degree to which demand resources
are integrated into the various markets, the ability of demand
resources to mitigate market power,\274\ and how market power will be
monitored and mitigated, among other factors.
---------------------------------------------------------------------------

    \274\ As discussed further below, demand resources are the set
of demand response resources and energy efficiency resources and
programs that can be used to reduce demand or reduce electricity
demand growth.
---------------------------------------------------------------------------

    195. Some commenters oppose price reforms during periods of
shortages on grounds that such reforms may lead to the exercise of
market power and will result in unjust and unreasonable rates. They
argue that the Commission is abdicating market mitigation by allowing
price caps to be removed during a power shortage. We disagree. To the
contrary, the Commission is not taking any action to remove market
mitigation in regional markets. Each of the Commission's proposed
reforms includes some form of mitigation, either bid caps,
administratively-determined prices, or prices tied to payments made in
emergency demand response programs administered by RTOs or ISOs (and
thus approved by the Commission). RTOs and ISOs are free to propose
other pricing reforms and associated mitigation that meet the criteria
herein. Moreover, these reforms to enhance demand responsiveness
further mitigate seller market power by allowing demand to choose to
not consume power when the price is higher than they wish to pay.
Allowing buyers to respond to prices reduces incentives for a seller to
manipulate market prices.\275\
---------------------------------------------------------------------------

    \275\ See B.F. Neenan et al., Neenan Associates, 2004 NYISO
Demand Response Program Evaluation, at E-5, (Feb. 2005); David B.
Patton, Potomac Economics, 2006 State of the Market Report--The
Midwest ISO, at 44 (May 2007 ).
---------------------------------------------------------------------------

    196. To guard the consumer against exploitation by sellers, we
adopt the proposal to require RTOs and ISOs to adequately address
market power issues in the compliance filings directed herein. We
require an adequate factual record demonstrating that provisions exist
for mitigating market power and deterring gaming behavior to be part of
a compliance filing for price reform during periods of operating
reserve shortage. This could include, but is not limited to, the use of
demand resources to discipline bidding behavior to competitive levels
during an operating reserve shortage. We also intend to closely monitor
market behavior during periods of operating reserve shortage to

ensure that market participants are following market rules and to guard
against the exercise of market power.
    197. For purposes of providing the Commission with an adequate
factual record regarding its shortage pricing proposal, the RTO or ISO
must address the six criteria that we adopt below,\276\ several of
which refer to demand resources. For these purposes, ``demand
resources'' refers to the set of demand response resources and energy
efficiency \277\ resources and programs that can be used to reduce
demand or reduce electricity demand growth. Although the Final Rule
requires provisions related to RTO or ISO ancillary services markets,
aggregation by ARCs and deviation penalties to be implemented for
demand response resources, we believe it is appropriate to allow the
RTO or ISO to support its shortage pricing proposal with reference to
the broader set of demand resources.
---------------------------------------------------------------------------

    \276\ See discussion infra P 247.
    \277\ The Commission's Staff has defined energy efficiency to
refer to using less energy to provide the same or improved level of
service to energy consumers in an economically efficient way. Energy
efficiency uses less energy by employing products, technologies, and
systems to use less energy to do the same or better job than by
conventional means. Energy efficiency saves kilowatt-hours on a
persistent basis, rather than being dispatchable for peak hours, as
are some demand-response programs. Energy efficiency can include
switching to energy-saving appliances (such as Energy Star(r)
certified products) and advanced lighting (compact fluorescent or
LED lighting); improving building design and construction (better
insulation and windows, tighter ductwork, use of high-efficiency
heating, ventilation, and air conditioning); and redesigning
manufacturing processes (advanced electric motor drives, heat
recovery systems) to use less energy, thus reducing use of
electricity and natural gas. Federal Energy Regulatory Commission,
Assessment of Demand Response & Advance Metering: Staff Report at A-
4 (September 2007).
---------------------------------------------------------------------------

    198. We note that this Final Rule does not eliminate or otherwise
revise the market power mitigation measures that remain in place during
times when operating reserves are insufficient. For example, conduct
and impact tests are applied in ISO New England, NYISO, and Midwest
ISO. A pivotal supplier test is used in PJM. Further, PJM and CAISO
mitigate bids by generators that are chosen out-of-merit order.
    199. Existing rules should combine effectively with the more
vigilant monitoring required in this rule to dissuade the exercise of
market power. Further, as noted in the NOPR, the pricing reform
established in this Final Rule is only one part of the continuing
effort by the Commission and RTOs and ISOs to improve the functioning
of organized markets.
    200. TAPS recommends a ``safety net cap'' to protect against very
high prices and for a review of the need for capacity markets if there
is shortage pricing. As stated earlier, none of the four approaches
suggested by the Commission precludes a limit on prices. For example,
the first approach does not propose necessarily to eliminate bid caps;
instead, ``bid caps would be allowed to rise above existing caps'' (as
stated in the NOPR) during an operating reserve shortage. No explicit
amount of increase is stated or required under the first suggested
approach. Under the second approach, a demand curve for operating
reserves is commonly capped at some multitude of the expected cost of
new entry (for instance, one and a half times the cost of new entry).
The market-clearing price under the fourth approach--allowing the
payment made to emergency demand response providers to set the market-
clearing price--depends on that payment. As such, the approaches
already account for a ``safety net'' cap.
    201. TAPS and others also recommend examining the need for capacity
markets under shortage pricing and whether customers would be charged
twice. Under all existing capacity market rules, the revenues earned
from the sale of energy and ancillary services are accounted for in the
calculation of capacity payments so that customers will not be double
charged. Comverge and DRAM suggest addressing price averaging in
capacity markets as an alternative to raising price caps during periods
of operating reserve shortages. The Commission has noted previously
that this rulemaking is not designed to address capacity market issues
and, therefore, finds their comments to be outside the scope of this
proceeding.
    202. Some commenters argue that end users are not able to see
hourly prices and, therefore, will not respond to a shortage price
signal. Similarly, several commenters argue that demand response
capability must be in place before changes to mitigation rules are
considered. Demand response programs that currently allow a fraction of
the load to respond can have a positive effect on system reliability
and market demand and help reduce prices for all. Full deployment of
advanced meters and complete participation by all load is not needed to
help cope with operating reserve shortages.\278\ In addition, the
Commission establishes six criteria, as discussed below, to evaluate an
RTO's or ISO's proposal--criteria designed to ensure that the shortage
pricing proposal achieves the objectives of this requirement while
protecting customers from market power.\279\
---------------------------------------------------------------------------

    \278\ See Federal Energy Regulatory Commission, Assessment of
Demand Response and Advanced Metering: Staff Report, Docket No.
AD06-2-000, at 7. As little as five percent of load responding to a
high price can avert a system emergency and may help to lower the
market price.
    \279\ See discussion infra at P 247.
---------------------------------------------------------------------------

    203. Further, with better price signals, more buyers would find it
worthwhile to invest in technologies that allow them to respond to
prices. Also, while some customers may not be able to respond to hourly
prices, they will see monthly bills and have an incentive to reduce use
of power in general by, for example, setting air conditioning
thermostats higher during peak periods or simply when the weather
forecast calls for high temperatures, or engaging in energy efficiency,
which can lead to an overall reduction in market demand, reduced need
for marginal resources, and fewer periods of shortage. Further, we
reiterate that such price signals would encourage entry by generators,
investment in new technology, and more participation in demand response
programs.
    204. Several commenters are concerned that some demand response
resources would be negatively affected by the shift of revenues from
capacity markets to energy markets. In general, giving resource
suppliers and customers more choices for how they participate in
markets is beneficial. Shortage pricing in an emergency and capacity
markets for long-term resource adequacy assurance serve largely
distinct purposes, but we agree that they should not work at cross
purposes. Adding any new element to a market design can have effects on
the other elements. We require that each RTO and ISO address in its
compliance filing how its selected method of shortage pricing interacts
with its existing market design.
    205. We disagree with LPPC's claim that higher prices during
shortage periods will destabilize long-term arrangements. Allowing
prices to rise during emergencies should instead provide an incentive
for customers to increase their hedging through long-term contracting.
Further, as noted above, it should also encourage investment in demand
response technology and provide an incentive to market participants to
participate in load response programs, thereby mitigating the expected
higher prices.
    206. Our requirement that RTOs and ISOs provide a factual record to
demonstrate the adequacy of market power mitigation measures, coupled
with the Commission's solicitation of the views of each RTO's and ISO's
Market Monitoring Unit on proposed shortage pricing reforms, as
supported by EEI, should address the concerns of

Old Dominion, Public Interest Organizations, and TAPS regarding the
ability of market participants to exercise market power during periods
of operating reserve shortages.
    207. Finally, we address PJM Power Providers' concerns that
shortage pricing mechanisms be integrated into the overall market
design of the RTO, perhaps with a new ``reserve product,'' and the need
for contingencies or constraints related to reserves that is seen in
the day-ahead or real-time market to be reflected in the energy market.
We share PJM Power Providers' concern about out-of-merit order
generation, such as the example they cite, and it being reimbursed
through up-lift charges. A market works more efficiently when all
decisions of the system operator that affect costs, e.g., running
peaking units, are reflected in market prices rather than in uplift
charges. We encourage all RTOs and ISOs to consider this when
evaluating their existing shortage pricing rules or developing new
ones. This might include, as PJM Power Providers describes it, the
development of ``new reserve products.'' As to their second concern, we
also agree that the better integrated markets are with one another, the
more efficiently they will operate. However, the aim of this
rulemaking, maintaining reliability through entry of new generation and
demand response resources, need not be achieved through one particular
market rule structure.
b. Four Approaches
    208. In the NOPR, the Commission proposed to require each RTO or
ISO to make a compliance filing proposing any necessary reforms to
ensure that the market price for energy accurately reflects the value
of such energy during an operating reserve shortage. Given regional
differences in market design, the Commission did not propose to require
one particular approach to achieving this reform. Rather, the
Commission stated that each RTO or ISO may propose one of four
suggested approaches or another approach that achieves the same
objectives. The four approaches are: (1) RTOs and ISOs would increase
the energy supply and demand bid caps above the current levels only
during an emergency; (2) RTOs and ISOs would increase bid caps above
the current level during an emergency only for demand bids while
keeping generation bid caps in place; (3) RTOs and ISOs would establish
a demand curve for operating reserves, which has the effect of raising
prices in a previously agreed-upon way as operating reserves grow
short; and (4) RTOs and ISOs would set the market-clearing price during
an emergency for all supply and demand response resources dispatched
equal to the payment made to participants in an emergency demand
response program.
i. Comments
    209. Many commenters spoke for or against all four approaches
collectively. Those in support state that each of the four approaches
is an appropriate means for achieving the goals of the NOPR's proposal
on shortage pricing. Supporters of all four approaches typically did
not address each approach individually, and their comments are included
above among those who spoke in support of the overall proposal.
Similarly, many of the commenters that oppose the overall proposal and
all four approaches are also summarized above, but a few of these make
more detailed collective comments on the NOPR's four suggested
approaches, which are presented next. For example, NRECA and APPA state
that they are firmly opposed to the Commission's four approaches to
change pricing rules during shortage situations and base their
opposition on the fundamental disagreement that current prices during
shortage periods are unjust and unreasonable.\280\ NRECA states that
the approaches put forward by the Commission would result in rates that
are unjust and unreasonable, and would, at a minimum, grant windfall
profits to those suppliers that have been found by the RTOs' and ISOs'
market monitors to possess market power. APPA also states that it does
not support any of the four proposed shortage pricing approaches.\281\
Public Interest Organizations state that it cannot support any of the
Commission's proposed approaches at this time because demand response
participation is not at a level that will assure customers that prices
will be just and reasonable.\282\ Public Interest Organizations urge
that before current market mitigation rules are relaxed, a resource
adequacy requirement must be in place and market access and effective
demand response resource participation must be demonstrated. It also
states that an independent market monitor must be able to monitor
shortage pricing behaviors very closely.
---------------------------------------------------------------------------

    \280\ NRECA at 23.
    \281\ APPA at 29.
    \282\ Public Interest Organizations at 17.
---------------------------------------------------------------------------

    210. Numerous commenters spoke for or against some of the four
approaches, and their comments on each approach are discussed next.
    211. Among those who favored one or more of the four approaches,
the demand curve for operating reserves (the third approach) received
the most and strongest support.
    212. Under the first approach, RTOs and ISOs would increase energy
bid caps (for each bidder) and the price cap (for the market-clearing
price) above the current level, but only during an operating reserve
shortage.\283\ PJM Power Providers supports this approach and notes
that to avoid market power concerns, bids may be assessed for the
potential of economic withholding by considering the value of lost load
multiplied by the increased probability of outages. FirstEnergy
supports lifting bid caps during a shortage if the shortage is genuine,
wholesale prices are reflected in retail rates, and energy and demand
response are treated on a comparable basis.\284\ Ohio PUC states that
it would recommend this approach only where there are a sufficient
number of suppliers or enough demand response to check the exercise of
market power.\285\ In commenting on the four approaches, Mr. Borlick
notes that the Commission has correctly concluded that energy prices
during periods of supply shortage fail to accurately reflect the value
of load reduction.\286\ Mr. Borlick states that approach 1 would
produce energy prices high enough to accurately reflect the marginal
value of consumption but would also encourage generators to exercise
market power both through economic and physical withholding. Of the
four approaches proposed in the NOPR, Mr. Borlick states that this is
the least desirable. He states that approach 2 is superior to approach
1 because it would allow the demand side to set economically efficient
clearing prices while controlling economic withholding by generators,
although generators could still physically withhold capacity. Its
drawback is that it does not provide a vehicle for efficiently trading
off operating reserves for energy production.
---------------------------------------------------------------------------

    \283\ For example, PJM may choose to increase its current
market-wide price cap. Another RTO or ISO could lift individual
generator bid caps while keeping its market-wide price cap at its
existing level. What exactly will be changed under this proposal
depends on existing rules and what the RTO or ISO stakeholders
consider for that region's market design and on what the RTO or ISO
then proposes in its compliance filing.
    \284\ FirstEnergy at 11.
    \285\ Ohio PUC at 10-11.
    \286\ Mr. Borlick at 5.
---------------------------------------------------------------------------

    213. NRECA opposes the first approach because it would remove price
caps that have been established to mitigate market power, exposing
consumers to the price bid by the marginal resource. NRECA asserts that
the market-clearing price during a

system emergency could potentially exceed the cost of the marginal
resource dispatched and the cost of new entry.\287\ Similarly, TAPS
opposes the first approach because it offers consumers no protection
against the exercise of market power and thus would only produce unjust
and unreasonable rates.\288\ TAPS notes that if demand response is
insufficient to restrain prices, the Commission would have to rely on
generators, who have neither the ability nor the incentive to set a
price that is just and reasonable under shortage conditions.\289\
---------------------------------------------------------------------------

    \287\ NRECA at 20.
    \288\ TAPS at 40.
    \289\ Id.
---------------------------------------------------------------------------

    214. Other commenters present a variety of reasons for not
supporting the first approach. NEPOOL Participants argues that imposing
either of the first two approaches in ISO New England could have
unintended effects on New England markets because many market
participants agreed to the forward capacity market with the
understanding that the $1000/MWh cap on ``energy offers and bids''
would not be removed.\290\ Maine PUC claims that in New England, it is
particularly unreasonable to impose a requirement to remove bid caps
from the energy market or take other steps that remove consumer
protections prior to a showing that consumers can change their behavior
to avoid being harmed.\291\
---------------------------------------------------------------------------

    \290\ NEPOOL Participants at 17.
    \291\ Maine PUC at 5.
---------------------------------------------------------------------------

    215. Comverge asserts that the first approach may invite gaming:
generators could withhold capacity so that emergency conditions occur
and then take advantage of the ensuing higher prices. However, it
states that if a much more dispatchable demand response and voluntary
price-response were in place the potential for gaming would be
substantially reduced.\292\ Duke Energy states that it is unrealistic
to expect resources to accurately predict emergency conditions and
tailor their bids appropriately. Thus, it states that this approach
would provide generation owners with an incentive to bid above cost,
putting upward pressure on prices.\293\
---------------------------------------------------------------------------

    \292\ Comverge at 21.
    \293\ Duke Energy at 9.
---------------------------------------------------------------------------

    216. Potomac Economics recommends that the Commission not encourage
this approach because it believes that the theory implicit in this
approach is flawed. It states that when the system is in a shortage,
relying on supply offers is not the action generally taken by system
operators. Also, if suppliers do not have market power, they will not
have an incentive to raise the price of their offers. Therefore, it
concludes that pursuing an approach that relies on suppliers to raise
their offers to achieve efficient price signals during shortage
conditions would not be reliable.\294\
---------------------------------------------------------------------------

    \294\ Potomac Economics at 4-5.
---------------------------------------------------------------------------

    217. NRECA states that, in presenting the first and second
approaches, the NOPR uses the terms bid caps, offer caps, and price
caps interchangeably and asks the Commission to specifically define
these terms. North Carolina Electric Membership also notes that the
NOPR does not clearly distinguish between a generation offer cap in
place as a result of mitigation procedures and the $1,000/MWh umbrella
energy offer cap ceiling in place in most RTOs and ISOs.\295\
---------------------------------------------------------------------------

    \295\ Id.
---------------------------------------------------------------------------

    218. Under the second approach, RTOs and ISOs would raise bid caps
above the current levels only for demand bids, that is, for bids by
customers expressing their willingness to pay more than the market
price cap to continue to receive power during an emergency and hence
perhaps avoid being curtailed. Ohio PUC states that lifting the caps
for only demand bids during system emergencies is a reasonable approach
for creating transparent price signals in shortage situations.\296\
---------------------------------------------------------------------------

    \296\ Ohio PUC at 12.
---------------------------------------------------------------------------

    219. NRECA opposes this approach because these demand bids would
set the market-clearing price paid to all resources, including
generators. This would result in customers paying rates to generators
that exceed the costs of the most expensive generator available on the
system, even if those generators do nothing unusual to alleviate the
emergency condition.\297\ TAPS states that this approach could also
raise market power concerns if the market participant submitting a
demand bid also had generation that could benefit from a price
increase.\298\
---------------------------------------------------------------------------

    \297\ NRECA at 20.
    \298\ TAPS at 41-42.
---------------------------------------------------------------------------

    220. Duke Energy and FirstEnergy do not support this approach
because generation resources would be treated differently from load,
which is inconsistent with the comparability principle the Commission
proposes for demand resources.\299\
---------------------------------------------------------------------------

    \299\ Duke Energy at 9; First Energy at 11.
---------------------------------------------------------------------------

    221. Under the third approach, RTOs and ISOs would establish a
demand curve for operating reserves, which establishes a predetermined
schedule of prices according to the level of operating reserves. As
operating reserves become shorter, the price increases. Many commenters
support this approach and state that it should be implemented.\300\
Several commenters assert that this approach: (1) Is the most efficient
means of moving prices toward the value of lost load during emergency
situations; \301\ (2) would promote reliability by providing greater
and timely incentives for market participants to provide capacity;
\302\ (3) can allow RTOs and ISOs to set prices that more accurately
reflect the costs of meeting demand and reserve requirements during
power shortages; \303\ and (4) avoids various concerns regarding the
exercise of market power. PPL Parties note that the Commission has
already approved this approach for the ISO New England, NYISO, and
Midwest ISO markets.\304\ Dominion Resources also emphasizes that the
demand curve for operating reserves has proved to be a workable method
in ISO New England.\305\ Of the four approaches, Mr. Borlick states
that approach 3 is the most appealing based on economic theory;
however, it poses implementation problems because of the computational
burden involved in developing a demand curve that would accurately
reflect the value of consumption.\306\
---------------------------------------------------------------------------

    \300\ E.g., Ameren; Mr. Borlick; Constellation; Duke Energy;
Exelon; FirstEnergy; Potomac Economics; PJM Power Providers; and PPL
Parties.
    \301\ Duke Energy at 10. Duke Energy explains that the use of
predetermined demand curves provides a structure under which the
price of energy rises to the level of the value of lost load when
firm loads are interrupted. As the probability of falling below
target reserve levels rises, the price of energy and reserves also
rises. Any load that wishes to respond to higher prices would take
appropriate action to curtail demand. Duke Energy believes that the
use of such shortage pricing is essential to elicit broader demand
response. Id. (citing Robert Stoddard Affidavit, Duke Energy ANOPR
Comments).
    \302\ PJM Power Providers at 6.
    \303\ Ameren at 28.
    \304\ PPL Parties at 6.
    \305\ Dominion Resources at 7.
    \306\ Mr. Borlick at 8.
---------------------------------------------------------------------------

    222. Potomac Economics states that implementing a demand curve for
operating reserve is critical for achieving efficient shortage pricing
and should be a required element for RTO or ISO markets.\307\ It states
that such demand curves are most effectively implemented in the context
of jointly-optimized energy and ancillary services markets. It believes
that effective shortage pricing requires jointly-optimized markets with
operating reserve demand curves set at levels that reflect the value of
reliability that the operating reserves provide to consumers.\308\
However, Potomac

Economics states that the third approach alone is not sufficient and
that the fourth approach, allowing payments to emergency demand
response resources to set the market-clearing price is a valuable
complement.\309\ It notes that RTOs and ISOs can call on emergency
demand response or interruptible retail load to maintain reliability.
These forms of demand response are not integrated into the market, and
therefore some form of the fourth approach is needed to set efficient
shortage prices when the demand response of emergency demand response
providers is called on in an emergency.\310\
---------------------------------------------------------------------------

    \307\ Potomac Economics at 5.
    \308\ Id. at 6.
    \309\ Id. at 7.
    \310\ Id.
---------------------------------------------------------------------------

    223. PJM Power Providers proposes that PJM should use a downward-
sloping operating reserve demand curve simultaneously for both energy
and operating reserves, instead of having a fixed operating reserve
requirement. It notes that this would (1) remove certain anomalies that
occur with the current fixed requirement, (2) provide an adequate
incentive for ``increased energy demand bidding,'' and (3) improve
reliability by providing greater and timely incentives for market
participants to provide capacity.\311\ Constellation supports the
approach of using a demand curve for operating reserves. While
acknowledging this approach presents practical problems associated with
developing the demand curve, Constellation states that these can be
addressed and the benefits of this solution justify efforts to deal
with these challenges.\312\ Exelon states that the demand curve for
operating reserves, the Commission's third approach, would be the most
effective of the four approaches (although it recommends an alternative
approach, reported below) because it would help induce additional
demand response during periods of peak demand. FirstEnergy states that
an administratively set demand curve is an acceptable way to set the
operating reserve price in times of shortage because the demand side of
the market is underdeveloped and cannot respond to market forces on the
same scale as supply-side resources. It states that a demand curve can
effectively mitigate market power where one market participant becomes
the last available supplier in a shortage.\313\
---------------------------------------------------------------------------

    \311\ PJM Power Providers at 7.
    \312\ Constellation at 13.
    \313\ FirstEnergy at 11-12.
---------------------------------------------------------------------------

    224. NRECA opposes the demand curve for reserves approach because
it is designed to raise the price above the current maximum level
allowed. TAPS states that the third approach risks mandating a
particular type of reform, an RTO-run ancillary services market, rather
than a reform that originates with stakeholders.\314\
---------------------------------------------------------------------------

    \314\ TAPS at 42.
---------------------------------------------------------------------------

    225. Ohio PUC does not support the third approach because a demand
curve for operating reserves may not ensure that any new generation
will be built.\315\ Comverge states that the third approach is
difficult to implement because it requires an administrative
determination of the demand curve's characteristics.\316\
---------------------------------------------------------------------------

    \315\ Ohio PUC at 11.
    \316\ Comverge at 22.
---------------------------------------------------------------------------

    226. Under the fourth approach, RTOs or ISOs would set the market-
clearing price during an operating reserve shortage at the payment made
to participants in an emergency demand response program. PJM Power
Providers states that this fourth approach is reasonable, but notes
that when operating reserves and locational reserve requirements
decline below target levels despite use of the fourth approach, the
question of how to set and adjust the price must then be
addressed.\317\
---------------------------------------------------------------------------

    \317\ PJM Power Providers at 8.
---------------------------------------------------------------------------

    227. TAPS states that the fourth approach appears to allow market-
clearing prices to be set by the RTO or ISO at whatever payment an RTO
or ISO makes to a demand response resource that reduces consumption
during emergencies in return for a contractually established payment
that, perhaps, was determined by a regulatory body other than the
Commission and, therefore, would be outside of the Commission-approved
market-clearing mechanism and on that basis rejects it.\318\ Comverge
believes that the fourth approach presents two issues: (1) Participants
are likely to ignore the market value of demand response before an
emergency is declared; and (2) the emergency value of demand response
would be substituted for the market value of power, which may reinforce
the use of demand resource as an emergency-only resource.\319\
Similarly, Duke Energy states that this proposal is questionable
because it would be difficult to determine exactly what price would be
paid to non-demand response market participants, and the program price
paid to participating demand response resources may not actually
reflect these participants' or other parties' economic assessment of
the hourly value of power. Emergency demand response resources do not
submit bids, but just receive a payment, against which they must judge
the cost of forgoing energy. Because there is no solicitation of value
from resources, it would be difficult and unreliable to determine a
single price that would be suitable both for the interrupted emergency
demand response providers and for payment to other resource
providers.\320\ Mr. Borlick gives approach four the most favorable
review on the basis that it creates an incentive of demand response to
bid its true interruptible cost and, therefore is more likely to
produce economically efficient prices.\321\
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    \318\ TAPS at 42.
    \319\ Comverge at 22.
    \320\ Duke Energy at 10 (citing Robert Stoddard Affidavit, Duke
Energy ANOPR Comments at 16).
    \321\ Mr. Borlick at 9.
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    228. Ameren particularly objects to the fourth approach because of
the market distortion and unintended consequences it could cause. It
states that load should receive payments for demand response only if
the load clears in the day-ahead market, and its payment should be
based on the bid that the market participant submitted.\322\ Ohio PUC
does not support the fourth approach, stating that it falls short of
resolving the problem at hand.\323\
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    \322\ Ameren at 28-29.
    \323\ Ohio PUC at 12.
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    229. A few commenters offer new approaches or variations on one of
our four suggested approaches. EPSA points to the 2007 PJM State of the
Market Report to assert that other approaches besides these four should
be considered. Specifically, in that report PJM's market monitor,
Joseph Bowring, recommended that shortage pricing should be defined in
several stages with different pricing in each stage. While EPSA does
not specifically endorse this proposal, it states that such a proposal
should be considered.\324\
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    \324\ EPSA at 10.
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    230. Exelon suggests a variation on the Commission's proposed
shortage pricing approaches. Exelon proposes a price cap in the market
that would ratchet up as shortage conditions worsen.\325\ This price
cap would rise to predetermined levels as a shortage situation
approaches. In essence, this would work like a demand curve, with the
price cap increasing as the amount of available operating reserves
diminished. Under this approach, the administratively set price levels
would function as a moving cap and the market would determine the value
of supply, up to that administratively set price cap.\326\ Exelon
maintains that this approach would elicit demand response to alleviate
the shortage before it becomes a real crisis. It makes the point

that no bids under this cap would be subject to mitigation procedures.
Exelon believes that this approach is superior because it allows the
market to determine the value of supply, within the cap, rather than
requiring the market administrator to impose a value.
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    \325\ Exelon at 11.
    \326\ Id. at 12.>
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    231. NRECA offers what it says is a variation on the second
approach, and APPA and TAPS support this alternative. They propose
allowing only demand response resources to bid higher than the current
caps. Demand response resources would be paid the resulting clearing
price, but generating resources would not. Instead, generators would
receive the highest clearing price among the generating resources.
NRECA explains that this approach would encourage additional demand
response by allowing demand response resources to obtain a higher price
for their response during emergencies. Specifically, it states that
this proposal would: (1) Encourage additional demand response; (2)
contribute to maintaining reliability; (3) help achieve the needed
balance between demand and supply on a real-time basis; and (4) not
shift rents from consumers to those generators whose market power must
be mitigated by supply bid caps in the first place.\327\ TAPS states
that if properly implemented, this proposal should not incent
generators to create emergencies because they would not profit from
them and, although this proposal would add to the uplift consumers must
bear, it would not exact the same degree of extreme hardship on
consumers as elevating the market-clearing price across ``swaths of the
nation.'' \328\ TAPS asserts that this alternative proposal is an
effective way for the Commission to gather data on the willingness of
demand response to come to market and on the relative costs of the
uplift associated with this method versus allowing the demand response
price to be the market-clearing price. In order to guarantee that such
a proposal would be allowable, TAPS suggests changes to the proposed
regulatory language and the definition of ``operating reserve
shortage.'' \329\ Like NRECA, Steel Manufacturers indicates that it
would support the removal of bid caps for demand response resources
during a system emergency if the higher bids do not set the market-
clearing prices.\330\
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    \327\ NRECA at 17.
    \328\ TAPS at 37.
    \329\ Id. at 39.
    \330\ NRECA at 17; Steel Manufacturers at 13.
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    232. Comverge recommends an alternative approach that allows price
caps to be relaxed as the market adds more dispatchable, price-
responsive demand response. It states that this would allow for use of
the best forms of market power mitigation: dispatchable demand response
and customer price response.\331\
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    \331\ Comverge at 22.
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    233. Potomac Economics states that the Commission should add to the
four approaches provisions that would set efficient prices when the
RTOs and ISOs take other emergency actions under shortage conditions,
including emergency transactions, export curtailments, voltage
reductions, and other emergency actions.\332\
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    \332\ Potomac Economics at 7.
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ii. Commission Determination
    234. Although we require RTOs and ISOs to modify, where necessary,
their market rules governing price formation during periods of
operating reserve shortage, we will not mandate any specific approach
to this reform. Rather, because each market design is different, the
changes to market rules should reflect each region's market design. To
that end, each RTO or ISO may propose one of four approaches or another
approach that achieves the same objectives. Each RTO or ISO should work
with its stakeholders to develop a program that is appropriate for its
region. Each of the four suggested approaches can be fashioned in a
reasonable way upon compliance to achieve the objectives of the reform
required here.
    235. We address comments on the four approaches below. We will not
address individually each comment on the four approaches provided by
the Commission because we are not mandating one specific approach that
all RTOs and ISOs must follow, and because each RTO and ISO must
demonstrate that it currently complies with the rule or has a proposal
that will put it in compliance. We cannot make a determination at this
point that any particular approach as offered by an RTO or ISO is
superior to another. Indeed, that is why a menu of options is offered
here. One method of pricing during shortage situations may work better
than another for any one RTO or ISO. All four of the approaches
presented by the Commission have the potential to meet the goals of
this rulemaking: maintaining reliability, eliminating barriers to the
comparable treatment of demand response, and allocating energy during a
shortage to those who value it most. Any filing by an RTO or ISO will
be judged according to the criteria set forth in this Final Rule. We
are also requiring the Independent Market Monitor for each RTO and ISO
to provide us with its view on any proposed reforms. Finally, any
proposal put forth by an RTO or ISO that follows a path different from
the four approaches offered here must meet the same criteria set forth
above. Only when an RTO or ISO submits a compliance filing can and will
the Commission determine if its pricing rules are just and reasonable,
not unduly discriminatory and sufficient to meet the stated goals of
this rulemaking.
    236. NRECA and North Carolina Electric Membership seek
clarification on the terms bid cap, offer cap, and price cap. Bid cap
refers to the maximum price that a seller (generation or demand
response resource) or buyer may bid (i.e., offer to sell or buy)
energy.\333\ The term price cap refers to a limit on the price of
energy in an organized market.\334\ In this rulemaking we have
restricted our usage to bid cap or price cap, as appropriate.
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    \333\ Although bid cap and offer cap have the same meaning in
the NOPR, we use only the term bid cap to avoid confusion.
    \334\ For example, a particular generator may have a bid cap of
$100 and bid $100 but be paid a higher market-clearing price. A
price cap is a limit on the market-clearing price.
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    237. Several commenters offer alternative approaches to modifying
shortage pricing rules. In the NOPR we asked commenters to provide us
with, not just barriers, but potential solutions, and these commenters
have done just that. While we will not adopt any of these proposed
changes explicitly in this rule, we note that RTOs and ISOs and their
stakeholders are free to consider these and other possible solutions
and propose to us their own method of shortage pricing reform that
satisfies the criteria as well as our four approaches.
c. The Commission's Proposed Criteria
    238. The Commission proposed to adopt further requirements to
ensure that any proposed reforms of shortage pricing rules or
demonstrations of the adequacy of existing rules in the area of
shortage pricing have adequate factual support and that RTOs and ISOs
show how the proposed reforms are designed to protect consumers against
the exercise of market power.\335\ First, each RTO or ISO proposing to
reform or demonstrate the adequacy of its existing market rules in this
area must provide an adequate factual record for the Commission to
evaluate its proposal. This factual record will allow the Commission to
discharge its duty to ensure that any reform is just and reasonable,
not unduly discriminatory, and appropriately tailored to the

circumstances in the RTO's or ISO's region. Second, the Commission
proposed that any change in market rules to implement the proposed
reforms must consider the issue of market power and the RTO or ISO
proposing reform must address the adequacy of any market power
mitigation measures that would be in place during an operating reserve
shortage. In addition, to ensure an adequate record on the issue of
market power mitigation, the Commission proposed to solicit the views
of the Independent Market Monitor for each RTO or ISO region on any
proposed reform.
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    \335\ NOPR, FERC Stats. & Regs. ] 32,628 at P 118.
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    239. Further, the Commission stated that it would consider the
factual record compiled by the RTO or ISO to determine whether its
proposal, or its demonstration of the adequacy of its existing market
rules, meet six criteria, namely, that the proposal would:
     Improve reliability by reducing demand and increasing
generation during periods of operating reserve shortage;
     Make it more worthwhile for customers to invest in demand
response technologies;
     Encourage existing generation and demand resources needed
during an operating reserve shortage to remain in business;
     Encourage entry of new generation and demand resources;
     Provide comparable treatment and compensation to demand
resources during periods of operating reserve shortages; and
     Have provisions for mitigating market power and deterring
gaming behavior, including, but not limited to, use of demand resources
to discipline bidding behavior to competitive levels during periods of
operating reserve shortages.
    240. The Commission requested comment on whether these criteria are
appropriate and whether there are additional criteria that we should
consider in evaluating a proposal for pricing during a period of
operating reserve shortage by RTOs and ISOs.
i. Comments
    241. Duke Energy supports the proposed criteria to evaluate RTO's
and ISO's filings on proposed reforms for shortage pricing. Wal-Mart
states that the criteria are a reasonable approach to providing
guidance to RTOs and ISOs in their reform proposals.\336\ EPSA states
that the Commission must be clear in the Final Rule on the principles
and the criteria which underpin its proposal.\337\
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    \336\ Wal-Mart at 8.
    \337\ EPSA at 8.
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    242. Comverge states that it supports each of the six proposed
criteria to demonstrate the merits of new energy market rules and the
Commission's proposed rulemaking approach for each respective RTO or
ISO. However, it recommends that the Commission add the following
criterion: ``where applicable, require a detailed assessment of the
impact of new energy market rules on the respective capacity market
participants.'' \338\
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    \338\ Comverge at 23.
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