[Federal Register: October 28, 2008 (Volume 73, Number 209)]
[Rules and Regulations]
[Page 64099-64173]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr28oc08-14]
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Part IV
Department of Energy
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Federal Energy Regulatory Commission
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18 CFR Part 35
Wholesale Competition in Regions With Organized Electric Markets; Final
Rule
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DEPARTMENT OF ENERGY
Federal Energy Regulatory Commission
18 CFR Part 35
[Docket Nos. RM07-19-000 and AD07-7-000]
Wholesale Competition in Regions With Organized Electric Markets
Issued October 17, 2008.
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final Rule.
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SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission
(Commission) is amending its regulations under the Federal Power Act to
improve the operation of organized wholesale electric markets in the
areas of: Demand response and market pricing during periods of
operating reserve shortage; long-term power contracting; market-
monitoring policies; and the responsiveness of regional transmission
organizations (RTOs) and independent system operators (ISOs) to their
customers and other stakeholders, and ultimately to the consumers who
benefit from and pay for electricity services. Each RTO and ISO will be
required to make certain filings that propose amendments to its tariff
to comply with the requirements in each area, or that demonstrate that
its existing tariff and market design already satisfy the requirements.
DATES: Effective Date: This Final Rule will become effective December
29, 2008.
FOR FURTHER INFORMATION CONTACT:
Russell Profozich (Technical Information), Office of Energy Market
Regulation, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426, Russell.Profozich@ferc.gov, (202) 502-6478.
Tina Ham (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426, Tina.Ham@ferc.gov, (202) 502-6224.
SUPPLEMENTARY INFORMATION:
Table of Contents
Paragraph
Numbers
I. Introduction........................................... 1
II. Background............................................ 10
III. Discussion........................................... 15
A. Demand Response and Pricing During Periods of 15
Operating Reserve Shortages in Organized Markets......
1. Background..................................... 16
2. Ancillary Services Provided by Demand Response 20
Resources.........................................
a. Ancillary Services Market.................. 21
b. New Bidding Parameters..................... 64
c. Small Demand Response Resource Assessment.. 90
3. Eliminating Deviation Charges During System 100
Emergencies.......................................
a. Deviation Charges.......................... 100
b. Virtual Purchasers......................... 122
4. Aggregation of Retail Customers................ 128
a. Commission Proposal........................ 128
b. Comments................................... 132
c. Commission Determination................... 154
5. Market Rules Governing Price Formation During 165
Periods of Operating Reserve Shortage.............
a. Price Formation During Periods of Operating 169
Reserve Shortage..............................
b. Four Approaches............................ 208
c. The Commission's Proposed Criteria......... 238
d. Phase-In of New Rules...................... 254
6. Reporting on Remaining Barriers to Comparable 259
Treatment of Demand Response Resources............
a. Comments................................... 263
b. Commission Determination................... 274
B. Long-Term Power Contracting in Organized Markets... 277
1. Background..................................... 278
2. Commission Proposal............................ 283
3. Comments....................................... 286
4. Commission Determination....................... 301
C. Market-Monitoring Policies......................... 310
1. Background..................................... 314
2. Independence and Function...................... 317
a. Structure and Tools........................ 318
b. Oversight.................................. 333
c. Functions.................................. 345
d. Mitigation and Operations.................. 361
e. Ethics..................................... 380
f. Tariff Provisions.......................... 388
3. Information Sharing............................ 395
a. Enhanced Information Dissemination......... 395
b. Tailored Requests for Information.......... 425
c. Commission Referrals....................... 460
4. Pro Forma Tariff............................... 470
a. Commission Proposal........................ 470
b. Comments................................... 471
c. Commission Determination................... 473
D. Responsiveness of RTOs and ISOs to Customers and 477
Other Stakeholders....................................
1. Background..................................... 479
2. Commission Proposal............................ 481
a. Responsiveness Obligation and Proposed 481
Criteria......................................
[[Page 64101]]
3. Comments....................................... 484
4. Commission Determination....................... 501
5. Board Advisory Committee and Hybrid Board...... 516
a. Comments................................... 517
b. Commission Determination................... 534
6. Supermajority Requirement...................... 538
a. Comments................................... 539
b. Commission Determination................... 546
7. Posting Mission Statement or Organizational 547
Charter on Web site...............................
a. Comments................................... 548
b. Commission Determination................... 556
8. Executive Compensation......................... 558
a. Comments................................... 559
b. Commission Determination................... 561
9. Compliance Filing Requirement.................. 562
a. Comments................................... 563
b. Commission Determination................... 565
E. Other Comments..................................... 568
1. Comments....................................... 568
2. Commission Determination....................... 573
IV. Applicability of the Final Rule and Compliance 574
Procedures................................................
A. NOPR Proposal...................................... 574
B. Comments........................................... 575
C. Commission Determination........................... 578
V. Information Collection Statement....................... 584
VI. Environmental Analysis................................ 587
VII. Regulatory Flexibility Act Certification............. 588
A. NOPR Proposal...................................... 593
1. Comments....................................... 596
2. Commission Determination....................... 602
VIII. Document Availability............................... 606
IX. Effective Date and Congressional Notification......... 609
Regulatory Text
APPENDIX: Abbreviated Names of Commenters
I. Introduction
1. This Final Rule addresses reforms to improve the operation of
organized wholesale electric power markets.\1\ Improving the
competitiveness of organized wholesale markets is integral to the
Commission fulfilling its statutory mandate to ensure supplies of
electric energy at just, reasonable and not unduly discriminatory or
preferential rates. Effective wholesale competition protects consumers
by providing more supply options, encouraging new entry and innovation,
spurring deployment of new technologies, promoting demand response and
energy efficiency, improving operating performance, exerting downward
pressure on costs, and shifting risk away from consumers. National
policy has been, and continues to be, to foster competition in
wholesale electric power markets. This policy was embraced in the
Energy Policy Act of 2005 (EPAct 2005),\2\ and is reflected in
Commission policy and practice. The Commission balances the mix of
regulation and competition based on changing circumstances, taking into
account such factors as the opportunities for competition to control
market power, advances in technology, changes in economies of scale,
and new state and federal laws that affect the energy industry.
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\1\ Organized market regions are areas of the country in which a
regional transmission organization (RTO) or independent system
operator (ISO) operates day-ahead and/or real-time energy markets.
The following RTOs and ISOs have organized markets:
PJMInterconnection, LLC (PJM), New York Independent System Operator,
Inc. (NYISO), Midwest Independent Transmission System Operator, Inc.
(Midwest ISO), ISO New England, Inc. (ISO New England), California
Independent Service Operator Corp. (CAISO), and Southwest Power
Pool, Inc. (SPP).
\2\ Pub. L. 109-58, 119 Stat. 594 (2005).
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2. The Commission has a duty to improve the operation of wholesale
power markets. To that end, in this Final Rule, the Commission is
making reforms to improve the operation of organized wholesale electric
markets in the areas of demand response, long-term power contracting,
market monitoring policies, and RTO and ISO responsiveness. By making
these reforms, the Commission is not seeking to fundamentally redesign
organized markets; rather, these reforms are intended to be incremental
improvements to the operation of organized markets without undoing or
upsetting the significant efforts that have already been made in
providing demonstrable benefits to wholesale customers.
3. In the areas of demand response and the use of market prices to
elicit demand response, the Commission is requiring RTOs and ISOs to:
(1) Accept bids from demand response resources in RTOs' and ISOs'
markets for certain ancillary services on a basis comparable to other
resources; (2) eliminate, during a system emergency, a charge to a
buyer that takes less electric energy in the real-time market than it
purchased in the day-ahead market; (3) in certain circumstances, permit
an aggregator of retail customers (ARC) \3\ to bid demand response on
behalf of retail customers directly into the organized energy market;
(4) modify their market rules, as necessary, to allow the market-
clearing price, during periods of operating reserve shortage, to reach
a level that rebalances supply and demand so as to maintain reliability
while providing sufficient provisions for mitigating market power; and
(5) study whether further reforms are necessary to
[[Page 64102]]
eliminate barriers to demand response in organized markets.
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\3\ We will use the phrase ``aggregator of retail customers,''
or ARC, to refer to an entity that aggregates demand response bids
(which are mostly from retail loads).
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4. With regard to long-term power contracting, the Commission is
requiring RTOs and ISOs to dedicate a portion of their Web sites for
market participants to post offers to buy or sell power on a long-term
basis. This requirement will promote greater use of long-term contracts
by improving transparency among market participants.
5. To improve market monitoring, the Commission is requiring that
RTOs and ISOs provide their Market Monitoring Units (MMU) with access
to market data, resources and personnel sufficient to carry out their
duties, and that the MMU (or the external MMU in a hybrid structure)
report directly to the RTO or ISO board of directors.\4\ In addition,
the Commission is requiring that the MMU's functions include: (1)
Identifying ineffective market rules and recommending proposed rules
and tariff changes; (2) reviewing and reporting on the performance of
the wholesale markets to the RTO or ISO, the Commission, and other
interested entities; and (3) notifying appropriate Commission staff of
instances in which a market participant's behavior may require
investigation. The Commission is also expanding the list of recipients
of MMU recommendations regarding rule and tariff changes, and
broadening the scope of behavior to be reported to the Commission.
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\4\ Our use of the phrase ``board of directors'' also includes
the board of managers, board of governors, and similar entities.
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6. The Commission is also modifying MMU participation in tariff
administration and market mitigation, requiring each RTO and ISO to
include ethics standards for MMU employees in its tariff, and requiring
each RTO and ISO to consolidate all its MMU provisions in one section
of its tariff. The Commission is expanding the dissemination of MMU
market information to a broader constituency, with reports made on a
more frequent basis than they are now, and reducing the time period
before energy market bid and offer data are released to the public.
7. Finally, the Commission establishes an obligation for each RTO
and ISO to make reforms, as necessary, to increase its responsiveness
to customers and other stakeholders and will assess each RTO's or ISO's
compliance using four responsiveness criteria: (1) Inclusiveness; (2)
fairness in balancing diverse interests; (3) representation of minority
positions; and (4) ongoing responsiveness.
8. In each of these four areas, the Commission is requiring each
RTO or ISO to consult with its stakeholders and make a compliance
filing that explains how its existing practices comply with the Final
Rule in this proceeding, or its plans to attain compliance.
9. Significant differences exist between regions, including
differences in industry structure, mix of ownership, sources of
electric generation, population densities, and weather patterns. Some
regions have organized spot markets administered by an RTO or ISO, and
others rely solely on bilateral contracting between wholesale sellers
and buyers. We recognize and respect these differences across various
regions. At the same time, wholesale competition can serve customers
well in all regions. The focus of this Final Rule is to further improve
the operation of wholesale competitive markets in organized market
regions.
II. Background
10. The Commission has acted over the last few decades to implement
Congressional policy to expand the wholesale electric power markets to
facilitate entry of new generators and to support competitive markets.
Absent a single national power market, the development of regional
markets is the best method of facilitating competition within the power
industry, and the Commission has made sustained efforts to recognize
and foster such markets.
11. In 2007, the Commission held several public conferences to
gather information and address issues on competition at the wholesale
level and other related issues.\5\ At these conferences, the Commission
examined issues affecting competition in the RTO and ISO regions,
including the levels of wholesale prices, the need for long-term power
contracts, the effectiveness of market monitoring, and the lack of
adequate demand response. The Commission also addressed concerns
related to the RTO and ISO board of directors' responsiveness to their
customers and other stakeholders.
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\5\ Three technical conferences were held on February 27, 2007,
April 5, 2007, and May 8, 2007.
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12. On June 22, 2007, the Commission issued an Advance Notice of
Proposed Rulemaking (ANOPR),\6\ identifying four specific issues in
organized market regions that were not being adequately addressed or
were not under consideration in other proceedings. These areas were:
(1) The role of demand response in organized markets and greater use of
market prices to elicit demand response during periods of operating
reserve shortage; (2) increasing opportunities for long-term power
contracting; (3) strengthening market monitoring; and (4) enhancing the
responsiveness of RTOs and ISOs to customers and other stakeholders,
and ultimately to the consumers who benefit from and pay for
electricity services. The Commission presented preliminary views on
proposed reforms for these areas and sought comment on them.
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\6\ Wholesale Competition in Regions with Organized Electric
Markets, Advance Notice of Proposed Rulemaking, FERC Stats. & Regs.
] 32,617 (2007).
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13. After receiving and considering over a hundred comments on the
ANOPR, on February 22, 2008, the Commission issued a Notice of Proposed
Rulemaking (NOPR).\7\ In the NOPR, pursuant to the Commission's
responsibility under sections 205 and 206 of the Federal Power Act
(FPA),\8\ the Commission proposed reforms in the four specific areas
identified above that were designed to ensure just and reasonable
rates, to remedy undue discrimination and preference, and to improve
wholesale competition in regions with organized markets. As noted in
the NOPR, these proposed reforms are intended to improve the operation
of wholesale competition in organized markets.\9\
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\7\ Wholesale Competition in Regions with Organized Electric
Markets, Notice of Proposed Rulemaking, 73 FR 12,576 (March 7,
2008), FERC Stats. & Regs. ] 32,628 (2008).
\8\ 16 U.S.C. 824d--824e.
\9\ NOPR, FERC Stats. & Regs. ] 32,628 at P 11.
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14. In the NOPR, the Commission also noted that the reforms
proposed in this proceeding do not represent its final effort to
improve the functioning of competitive organized markets for the
benefit of consumers; rather, the Commission will continue to evaluate
specific proposals that may strengthen organized markets.\10\ To that
end, for example, the Commission proposed to require each RTO or ISO to
study whether further reforms are necessary to eliminate barriers to
demand response in organized markets. Any reforms must ensure that
demand response resources are treated on a basis comparable to other
resources. The Commission also ordered two staff technical conferences:
(1) One to investigate proposals by American Forest and the Portland
Cement Association, et al. to modify the design of organized markets;
\11\ and (2) a separate conference to consider several issues related
to demand response participation in wholesale
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markets.\12\ Further, the Commission directed each RTO or ISO to
provide a forum for affected consumers to voice specific concerns (and
to propose regional solutions) on how to improve the efficient
operation of competitive markets.\13\
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\10\ Id. P 1.
\11\ The technical conference was held on May 7, 2008. See
Supplemental Notice of Technical Conference, Capacity Markets in
Regions with Organized Electric Markets, Docket No. AD08-4-000
(April 25, 2008).
\12\ The technical conference was held on May 21, 2008. See
Supplemental Notice of Technical Conference, Demand Response in
Organized Electric Markets, Docket No. AD08-8-000 (May 13, 2008).
\13\ NOPR, FERC Stats. & Regs. ] 32,628 at P 11.
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III. Discussion
A. Demand Response and Pricing During Periods of Operating Reserve
Shortages in Organized Markets
15. This section of the Final Rule makes several reforms to further
eliminate barriers to demand response participation in organized energy
markets. These reforms are to ensure that demand response is treated
comparably to other resources. To that end, the Commission will require
RTOs and ISOs to: (1) Accept bids from demand response resources in
their markets for certain ancillary services, on a basis comparable to
other resources; (2) eliminate, during a system emergency, certain
charges to buyers in the energy market for voluntarily reducing demand;
(3) permit ARCs to bid demand response on behalf of retail customers
directly into the RTO's or ISO's organized markets; and (4) modify
their rules governing price formation during periods of operating
reserve shortage to allow the market-clearing price during periods of
operating reserve shortage to more accurately reflect the true value of
energy.
1. Background
16. Commission policy does not favor granting preference for demand
response; rather, our goal is to eliminate barriers to the
participation of demand response in the organized power markets by
ensuring comparable treatment of resources. This policy reflects the
Commission's view that the cost of producing electricity and the value
to customers of electric power varies over time and from place to
place.\14\ Demand response can provide competitive pressure to reduce
wholesale power prices; increases awareness of energy usage; provides
for more efficient operation of markets; mitigates market power;
enhances reliability; and in combination with certain new technologies,
can support the use of renewable energy resources, distributed
generation, and advanced metering. Thus, enabling demand-side
resources, as well as supply-side resources, improves the economic
operation of electric power markets by aligning prices more closely
with the value customers place on electric power. A well-functioning
competitive wholesale electric energy market should reflect current
supply and demand conditions.
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\14\ That is, for two customers at the same time and place, one
customer may prefer to reduce consumption if the price is high, and
the other may be willing to pay a high price to avoid curtailment in
an emergency.
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17. The Commission's policy also reflects its responsibility under
sections 205 and 206 of the FPA to remedy any undue discrimination and
preference in organized markets. To that end, the Commission explicitly
addressed demand response in its Open Access Transmission Tariff (OATT)
Reform (Order No. 890) \15\ and reliability standards (Order No.
693).\16\
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\15\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241
(2007), order on reh'g, Order No. 890-A, 73 FR 2,984 (Jan. 16,
2008), FERC Stats. & Regs. ] 31,261 (2007), order on reh'g, Order
No. 890-B, 73 FR 39,092 (July 8, 2008), 123 FERC ] 61,299 (2008).
\16\ See Mandatory Reliability Standards for the Bulk-Power
System, Order No. 693, FERC Stats. & Regs. ] 31,242, order on reh'g,
Order No. 693-A, 120 FERC ] 61,053 (2007).
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18. Additionally, on numerous occasions, the Commission has
expressed the view that the wholesale electric power market works best
when demand can respond to the wholesale price.\17\ Also, the
Commission has issued numerous orders over the last several years on
various aspects of electric demand response in organized markets, with
the goal of removing unnecessary obstacles to demand response
participating in the wholesale power markets of RTOs and ISOs.\18\ To
that end, some of these orders approved various types of demand
response programs, including programs to allow demand response to be
used as a capacity resource \19\ and as a resource during system
emergencies,\20\ to allow wholesale buyers and qualifying large retail
buyers to bid demand response directly into the day-ahead and real-time
energy markets and certain ancillary service markets, particularly as a
provider of operating reserves, as well as programs to accept bids from
ARCs.\21\ The Commission also has approved special demand response
applications such as use of demand response for synchronized reserves
and regulation service.\22\ The theme underlying the Commission's
approval of these programs has been to allow demand response resources
to participate in these markets on a basis that is comparable to other
resources.
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\17\ See, e.g., New England Power Pool and ISO New England,
Inc., 101 FERC ] 61,344, at P 44-49 (2002), order on reh'g, 103 FERC
] 61,304, order on reh'g, 105 FERC ] 61,211 (2003); PJM
Interconnection, LLC, 95 FERC ] 61,306 (2001); PJM Interconnection,
LLC, 99 FERC ] 61,227 (2002); Southwest Power Pool, Inc., 116 FERC ]
61,289 (2006).
\18\ See, e.g., New York Indep. Sys. Operator, Inc., 92 FERC ]
61,073, order on clarification, 92 FERC ] 61,181 (2000), order on
reh'g, 97 FERC ] 61,154 (2001); New England Power Pool and ISO New
England, Inc., 100 FERC ] 61,287, order on reh'g, 101 FERC ] 61,344
(2002), order on reh'g, 103 FERC ] 61,304, order on reh'g, 105 FERC
] 61,211 (2003); PJM Interconnection, LLC, 95 FERC ] 61,306 (2001);
PJM Interconnection, LLC, 99 FERC ] 61,139 (2002); PJM
Interconnection, LLC, 99 FERC ] 61,227 (2002).
\19\ See, e.g., PJM Interconnection, LLC, 117 FERC ] 61,331
(2006); Devon Power LLC, 115 FERC ] 61,340, order on reh'g, 117 FERC
] 61,133 (2006), appeal pending sub nom. Maine Pub. Utils. Comm'n v.
FERC, No. 06-1403 (DC Cir. 2007).
\20\ See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ]
61,136 (2001); NSTAR Services Co. v. New England Power Pool, 95 FERC
] 61,250 (2001); New England Power Pool and ISO New England, Inc.,
100 FERC ] 61,287, order on reh'g, 101 FERC ] 61,344 (2002), order
on reh'g, 103 FERC ] 61,304, order on reh'g, 105 FERC ] 61,211
(2003); PJM Interconnection, LLC, 99 FERC ] 61,139 (2002).
\21\ See, e.g., New York Indep. Sys. Operator, Inc., 95 FERC ]
61,223 (2001); New England Power Pool and ISO New England, Inc., 100
FERC ] 61,287, order on reh'g, 101 FERC ] 61,344 (2002), order on
reh'g, 103 FERC ] 61,304, order on reh'g, 105 FERC ] 61,211 (2003);
PJM Interconnection, LLC, 99 FERC ] 61,227 (2002).
\22\ See, e.g., PJM Interconnection, LLC, 114 FERC ] 61,201
(2006).
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19. While the Commission and the various RTOs and ISOs have done
much to eliminate barriers to demand response in organized power
markets, more needs to be done to ensure comparable treatment of all
resources. Therefore, as discussed below, the Commission is taking
action in this Final Rule to further eliminate barriers to demand
response in organized power markets.
2. Ancillary Services Provided by Demand Response Resources
20. The Commission included several components in the NOPR
obligating RTOs and ISOs to accept bids from demand response resources
for ancillary services. First, demand response resources were required
to meet necessary technical requirements established by the RTO or ISO
in order to participate in these markets. Second, the Commission
proposed that demand response resources be allowed to specify the
frequency and duration of their service through the use of additional
bidding parameters. Finally, the Commission proposed that RTOs and ISOs
perform a small demand response resource assessment to evaluate the
technical feasibility and value to the market of such smaller
resources. Comments in response to these issues are addressed below.
[[Page 64104]]
a. Ancillary Services Market
21. In the NOPR, the Commission proposed to obligate each RTO or
ISO to accept bids from demand response resources, on a basis
comparable to any other resources, for ancillary services that are
acquired in a competitive bidding process, if the demand response
resources: (1) are technically capable of providing the ancillary
service and meet the necessary technical requirements; and (2) submit a
bid under the generally-applicable bidding rules at or below the
market-clearing price, unless the laws or regulations of the relevant
electric retail regulatory authority do not permit a retail customer to
participate.\23\ The Commission stated that this proposal would apply
to competitively-bid markets, if any, for energy imbalance, spinning
reserves, supplemental reserves, reactive supply and voltage control,
and regulation and frequency response as defined in the pro forma OATT,
or to the markets for their functional equivalents in an RTO or ISO
tariff.\24\
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\23\ NOPR, FERC Stats. & Regs. ] 32,628 at P 56.
\24\ Id.
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22. The Commission proposed that, on compliance, an RTO or ISO must
either propose amendments to its tariff to comply with the proposed
requirement or demonstrate that its existing tariff and market design
already satisfy the requirement. This filing would be submitted within
six months of the date the Final Rule is published in the Federal
Register. The Commission proposed to assess whether each filing
satisfies the proposed requirement and issue additional orders as
necessary.\25\
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\25\ Id. P 63.
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i. Comments
23. Many commenters support the Commission's proposal and agree
that allowing demand response resources to participate in ancillary
services markets would increase competition, enhance system
reliability, and lower the overall price for ancillary services.\26\
For instance, Public Interest Organizations assert that the presence of
demand response in these markets will mitigate the exercise of market
power and allow large amounts of variable resources (e.g., wind and
solar) to be integrated into the grid.\27\ DRAM states that allowing
demand response to participate in ancillary services markets and other
types of wholesale markets would lead to a more viable and sustainable
demand response industry, and to the availability of a larger overall
demand response resource.\28\ Comverge maintains that the Commission's
proposal is particularly appropriate because it enables market
participants to simultaneously participate in capacity markets (or
resource adequacy) and operating reserve markets.\29\ DRAM and APPA,
while in support of the Commission's proposal, state that demand
response resources must be able to meet the appropriate technical
requirements.\30\
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\26\ E.g., American Forest at 5; BlueStar Energy at 1-2;
California PUC at 9; Cogeneration Parties at 2-3; Dominion at 4;
Duke Energy at 3; Integrys Energy at 9; ISO/RTO Council at 3-4;
Industrial Coalitions at 9; Midwest Energy at 2-3; North Carolina
Electric Membership at 3-4; NYISO at 5; Public Interest
Organizations at 5-6; Reliant at 3; and Wal-Mart at 5.
\27\ Public Interest Organizations at 4-5.
\28\ DRAM at 5-6.
\29\ Comverge at 11.
\30\ DRAM at 4-5; APPA at 31-32.
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24. Several commenters state that they support the Commission's
clarification in the NOPR that the proposal would not require the
adoption of competitive bidding processes in areas where they were not
previously used.\31\ APPA states that it opposes the development of new
RTO or ISO markets for ancillary services just so demand response
resources could participate in them.\32\ Similarly, EEI asserts that
this proposal should be limited to competitively-bid markets only, as
defined in the proposal.\33\ Comverge also agrees with the Commission's
proposed requirement that this provision apply only to competitively-
bid markets, but asks the Commission to include two other services
within its proposal: Out-of-Market \34\ and Scarcity Pricing.\35\
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\31\ NOPR, FERC Stats. & Regs. ] 32,628 at P 58.
\32\ APPA at 34-35.
\33\ EEI at 11.
\34\ It is not entirely clear what service Comverge is referring
to here. It is possible that Comverge is referring to Out-Of-Market
Dispatch, i.e., RTO or ISO dispatch actions that are not reflected
in the ISO's real-time market prices. In CAISO, for example,
dispatchers procure energy to make up for imbalances by contacting
selected resources or control area operators that chose not to
submit any bids into the ISO's or RTO's markets. This practice
results in bilateral trades negotiated by the RTO or ISO.
\35\ Comverge at 13-14. Similarly, it is not clear to the
Commission what service Comverge is referring to, as Scarcity
Pricing is not an ancillary service.
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25. Xcel requests that the Commission clarify that the proposed
rule does not require a demand response provider to offer its potential
demand response into the market.\36\ Xcel argues that a demand response
provider should be free to evaluate its willingness to bid its offering
into the market.
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\36\ Xcel at 7.
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26. In its reply comments, Allied Public Interests Groups note that
providing for comparable treatment of demand-side resources in
wholesale markets is critical to making those markets competitive,
efficient, reliable and sustainable. Therefore, they ask the Commission
to clarify the meaning and implication of the term ``comparable
treatment.'' \37\
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\37\ Allied Public Interest Groups at 1.
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27. NARUC argues that the state-law exemption within the NOPR
should be modified to avoid displacing state authority and state policy
decisions on demand response.\38\ NARUC explains that this exemption
places the burden on state regulators to show that the demand response
proposal conflicts with state laws or regulations. NARUC would like to
see this reversed, and the burden placed on the RTO or ISO to obtain
the state regulator's permission to allow the demand response proposal.
Similarly, Pennsylvania PUC states that the state exemption highlights
a jurisdictional issue and recommends that the Commission continue to
work with state authorities to eliminate these types of barriers to
demand response.\39\
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\38\ NARUC at 7. The proposal for ancillary services market
states: ``The Commission proposed to obligate each RTO or ISO to
accept bids from demand response resources, on a basis comparable to
any other resources, for ancillary services that are acquired in a
competitive bidding process, if the demand response resources (1)
are technically capable of providing the ancillary service and meet
the necessary technical requirements, and (2) submit a bid under the
generally-applicable bidding rules at or below the market-clearing
price, unless the laws or regulations of the relevant electric
retail regulatory authority do not permit a retail customer to
participate.'' NOPR, FERC Stats. & Regs. ] 32,628 at P 56 (emphasis
added).
\39\ Pennsylvania PUC at 11.
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28. Some commenters recommend that each RTO and ISO should
determine new rules for ancillary services.\40\ Dominion states that
each RTO and ISO should have flexibility to develop the necessary rules
to modify existing ancillary services markets within its stakeholder
processes.\41\ Comverge suggests that these rules be determined by each
RTO and ISO, but initially framed in a Commission technical conference,
consistent with the Commission's substantive recommendations to amend
RTO and ISO bidding rules.\42\ SoCal Edison-SDG&E argue that an overly
prescriptive national approach may be counterproductive.\43\
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\40\ See, e.g., Comverge at 17; Dominion at 4; and SoCal Edison-
SDG&E at 3.
\41\ Dominion at 4.
\42\ Comverge at 17.
\43\ SoCal Edison-SDG&E at 3.
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29. While Midwest Energy supports the proposal, it is concerned
that the quest for comparability may evolve into a program that treats
demand response preferentially with respect to competitive resource
providers. It states
[[Page 64105]]
that any such preferential treatment could lead to overall increases in
costs to customers through the subsidization of demand response.\44\
Therefore, Midwest Energy asks that the Commission require that: (1)
each RTO or ISO demand response program be subject to a net-benefits
test and (2) all demand-side resources be subject to a performance
evaluation.\45\
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\44\ Midwest Energy at 3.
\45\ Id.
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30. Reliant comments that demand response resources should be
subject to penalties for non-performance comparable to those that
supply resources face. Reliant also states that demand response
resources that supply ancillary services should participate in RTO and
ISO ancillary services markets primarily via the entity that schedules
and financially settles the load for their meters.\46\ Allied Public
Interest Groups agrees that demand response resources should face
comparable penalties for non-performance, but notes in reply comments
that ``comparable'' penalties does not mean ``the same'' penalties.\47\
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\46\ Reliant at 4.
\47\ Allied Public Interest Groups at 4.
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31. Public Interest Organizations urge the Commission to expand the
demand response provisions to include energy efficiency resources,
environmentally benign behind-the-meter distributed generation, and all
other demand-side resources that are capable of providing the
service.\48\ Public Interest Organizations explain in their comments
that ``energy efficient resources produce load reductions for the
length of their measured lives, relieving congestion, reducing market
costs, and increasing system reliability.'' They state that ``a bundle
of energy efficient resources that reduces energy use on a large
scale--an `efficiency power plant' or EPP--can achieve energy savings
that are just as predictable and substantial as the energy output of a
conventional power plant. The consistent savings from these energy
efficiency programs and investments can be thought of as a virtual
power plant.'' \49\ Allied Public Interest Groups assert that the
comparable treatment proposed for demand response in the NOPR should be
expanded to cover all reliable and efficient demand response resources
that are technically capable of providing the service needed. Allied
Public Interest Groups notes that limiting participation in ancillary
services markets to ``traditional'' demand response resources may
unintentionally exclude innovative new technologies that can help
achieve goals of system reliability and efficiency.\50\
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\48\ Public Interest Organizations at 4.
\49\ Id. at 13-14.
\50\ Allied Public Interest Groups at 7.
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32. TAPS asserts that behind-the-meter generation can perform as a
demand resource in ancillary services markets. TAPS states that the
regulatory language should be modified to include this type of
resources as well as reliability-based demand response. They note that
reliability-based demand response, or demand response that is not in
reaction to an increase in the price of electric energy or to incentive
payments, is currently not included in the regulatory definition of
Demand Response contained within this proceeding.\51\
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\51\ TAPS at 9.
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33. Some supporters state that the Commission should address in the
Final Rule compensation for demand response resources. For instance,
Industrial Consumers suggest that the payment structure for demand
response resources should be comparable to the payment of a
generator.\52\ They also note that to promote the development of demand
response resources and fairly compensate these resources for their
ancillary services, a methodology for calculating and accurately
representing customer baselines must be developed on a consistent
basis.\53\ EnerNOC agrees and asks the Commission to require RTOs and
ISOs to demonstrate in future compliance filings that customer baseline
methodologies appropriately address concerns of accuracy, integrity,
and comparable treatment of demand response resources.\54\
---------------------------------------------------------------------------
\52\ Industrial Consumers at 13.
\53\ Id. at 14.
\54\ EnerNOC at 11.
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34. E.ON U.S. does not support the Commission's proposal. E.ON U.S.
believes that the Commission's proposal mandates the purchase of demand
response products regardless of price, and that such a practice will
distort the market and create additional costs for end-use
customers.\55\ E.ON U.S. argues that the Commission should only require
comparable treatment of demand response resources and not place any
extra emphasis or incentive on their use.
---------------------------------------------------------------------------
\55\ E.ON U.S. at 14.
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35. Several commenters request that the Commission develop a pro
forma tariff regarding demand response participation in ancillary
services markets. Industrial Consumers argue that the Commission should
prescribe specific pro forma tariff language for RTOs and ISOs to adopt
within 30 days of the Final Rule's effective date. Otherwise, they
assert that piecemeal implementation by RTOs and ISOs may result in
delay, inefficiency, and inconsistency.\56\ Similarly, Industrial
Coalitions state that the Commission should incorporate into a pro
forma demand response tariff appropriate minimum standards to enable
demand response resources to provide, and be comparably compensated
for, ancillary services. Industrial Coalitions and Steel Manufacturers
contend that the Commission should obligate RTOs and ISOs to
demonstrate that their own tariffs are consistent with or superior to
the pro forma provisions and any deviations from the pro forma tariff
should only be permitted if they can provide a clear justification for
doing so.\57\
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\56\ Industrial Consumers at 7-8. Industrial Consumers note that
the Commission's practice extending back to Order No. 888 has been
to standardize rules and procedures for generators and other
transmission users with the pro forma OATT as necessary to promote
consistency and to avoid undue discrimination. Id.
\57\ Industrial Coalitions at 11; Steel Manufacturers at 10.
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36. A few commenters express concern about the Western Electricity
Coordinating Council's (WECC) regional reliability standard addressing
operating reserve requirements because WECC currently allows demand
response to supply only non-spinning reserves.\58\ For example, CAISO
points out that WECC's standard is inconsistent with the Commission's
directive in Order No. 890 that a transmission provider must permit
non-generation resources to provide ancillary services to the extent
they are capable of doing so. It argues that WECC is non-compliant with
Order No. 693, which includes a requirement explicitly providing that
demand-side management may be used as a resource for contingency
reserves. Therefore, CAISO comments that the Commission should direct
the Electric Reliability Organization (ERO) to effect a change in WECC
requirements.\59\
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\58\ California DWR at 8; CAISO at 5; California PUC at 9-10;
and PG&E at 6 -7.
\59\ CAISO at 5; see also California PUC at 10.
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37. Several entities ask that the Final Rule not disturb or replace
ongoing proceedings in individual regions. Midwest ISO states that the
Commission recently approved its integration of demand response
resources to participate in Midwest ISO ancillary services markets, on
a basis comparable to other resources (ASM Proposal).\60\ Given this,
Midwest ISO requests that the Commission find that its ASM Proposal
satisfies the NOPR's
[[Page 64106]]
requirement that each RTO and ISO submit for Commission approval
standards by which demand response resources are able to participate
and bid in the ancillary service markets on comparable terms as other
resources.\61\ CAISO states that it will comply with the NOPR
requirement in the Release 1A enhancements to its Markets Redesign &
Technology Upgrade (MRTU).\62\ It asks the Commission to clarify that
it does not intend to replace the specific schedule that it has
accepted for the CAISO's implementation of MRTU with the generic
compliance schedule proposed in the NOPR.\63\
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\60\ Midwest Independent Transmission System Operator, Inc., 112
FERC ] 61,283 (2005), order on reh'g, 123 FERC ] 61,297 (2008) (ASM
Order).
\61\ Midwest ISO at 9.
\62\ Cal. Indep. Sys. Operator Corp., 116 FERC ] 61,274 (2006),
order on reh'g, 119 FERC ] 61,076 (2007).
\63\ CAISO at 2-4.
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38. In addition, while Maine PUC agrees that demand response is
important to the efficient functioning of wholesale electric markets,
it states that the Commission should allow ISO New England to work with
state regulators and NEPOOL Participants to make existing programs more
robust and to eliminate barriers to demand response participation.\64\
Maine PUC notes that demand response programs in New England are
achieving price savings and reducing the need for additional generation
and transmission, demonstrated by the significant participation of
demand response resources in the forward capacity market. Therefore,
Maine PUC states that the Commission should not impose the NOPR's
specific requirements for demand response on ISO New England.
---------------------------------------------------------------------------
\64\ Maine PUC at 3-4.
---------------------------------------------------------------------------
39. SPP states that it does not currently have an ancillary
services market; however, it reports that consideration and
incorporation of demand response in future market development is
currently being undertaken by SPP's Working Groups and Task Forces.\65\
---------------------------------------------------------------------------
\65\ SPP at 5.
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40. Alcoa maintains that the Commission's proposal is well-
intended, but falls short of what is needed to ensure non-
discriminatory treatment of demand response bids by industrial
customers. Alcoa asserts that the Commission's proposal is incomplete
because it relies too heavily on vague concepts such as comparability
of resources and reasonable requirements to increase access to
ancillary services. Alcoa argues that there should be no restriction on
the amount of participation by demand response resources in organized
wholesale markets, and suggests that, at a minimum, regional operators
should be required to justify such restrictions to the Commission and
demonstrate that they are necessary for technical reasons.\66\
---------------------------------------------------------------------------
\66\ Alcoa at 2-3.
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41. Several commenters support the Commission's conclusion that it
is not appropriate for the Commission to develop a standardized set of
technical requirements.\67\ California PUC stresses the importance of
allowing RTOs and ISOs the flexibility to modify requirements in the
future, as experience is gained with demand response programs. EEI
believes that standardization of these requirements could result in
unnecessary expense and delay in implementation by requiring
incompatible infrastructure across different RTOs and ISOs. EnerNOC
believes that the Commission struck the appropriate balance by
requiring coordination among the RTOs and ISOs without mandating
standardization.
---------------------------------------------------------------------------
\67\ E.g., California PUC at 9; EEI at 12; EnerNOC at 9; NYISO
at 6; and North Carolina Electric Membership at 4.
---------------------------------------------------------------------------
42. North Carolina Electric Membership states that the Commission
should require RTOs and ISOs to develop technical requirements in
conjunction with stakeholders to ensure that all interests are properly
considered. Old Dominion also states that any standards developed in
response to the Commission's requirement should be comprehensive and
result from a stakeholder process.
43. LPPC supports the Commission's recognition that demand response
resources must be technically capable of providing ancillary services.
In addition, LPPC agrees with the Commission's statement that RTOs and
ISOs need to impose requirements on telemetry and metering to allow
demand response resources to fully participate in ancillary services
markets. LPPC adds that an important element of any RTO-or ISO-led
ancillary services program must be performance monitoring to ensure
that demand response resources truly respond when called upon.\68\
Also, Old Dominion argues that the ability to accurately measure and
verify demand response is necessary to guarantee that these resources
are providing real benefits to the market.\69\
---------------------------------------------------------------------------
\68\ LPPC at 6-7.
\69\ Old Dominion at 7.
---------------------------------------------------------------------------
44. APPA supports the Commission's overall proposal, but states
that the Commission should recognize that metering, telemetry and
performance requirements that may have to be imposed on demand-side
resources to ensure their reliable performance will be more stringent
than the requirements most retail customers are used to accommodating.
APPA questions whether end-use customers will offer ancillary services
that may require them to reduce consumption substantially on very short
notice. APPA asserts that program participants may drop out when called
upon too frequently. APPA states that it may prove difficult to
reconcile the rigorous technical requirements for end users
necessitated by the instantaneous nature of certain ancillary services
with the desire of many larger loads for reliability, flexibility and
convenience.\70\
---------------------------------------------------------------------------
\70\ APPA at 33-34.
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45. NYISO recommends that the Final Rule clarify the NOPR's
proposed regulatory language to specify that demand response resources
must also meet applicable reliability requirements before they are
permitted to bid into markets.\71\ NYISO states that this language
would clearly articulate the Commission's support for the integration
of demand resources into ancillary services markets without overriding
requirements adopted by NERC or the New York State Reliability Council.
Further, it notes that this approach would be consistent with Order
890-A, which allows RTOs and ISOs to adopt reasonable reliability
related limitations on demand resource participation.\72\
---------------------------------------------------------------------------
\71\ NYISO at 5-6.
\72\ Id. at 6 (citing Order No. 890-A, 73 FR 2984 (Jan. 16,
2008), FERC Stats. & Regs. ] 31,261 at P 499).
---------------------------------------------------------------------------
46. Comverge requests that the Commission ensure that any
requirements imposed on demand response resources are not overly
technical and burdensome.\73\ California PUC states that telemetry, for
example, is necessary for resources offering ancillary services, but a
telemetry requirement for every participant (such as small commercial
and residential customers) may be excessive and could erect a barrier
to entry for these smaller customers, particularly when not every
demand response supplier has the money to install real-time telemetry
and metering.\74\ EnerNOC also mentions this concern, and asks that the
Commission clarify that its ``reasonableness'' requirement is aimed at
ensuring that reasonable technical requirements not be unduly
restrictive on demand response resources, such as those that may add
unwarranted and unnecessary costs to participation. EnerNOC states that
technical standards should focus on the reliability parameters of the
[[Page 64107]]
particular ancillary service and allowing demand response resources to
utilize alternative methods to meet these standards.\75\
---------------------------------------------------------------------------
\73\ Comverge at 13.
\74\ California PUC at 11.
\75\ EnerNOC at 10-11.
---------------------------------------------------------------------------
ii. Commission Determination
47. In this Final Rule, the Commission adopts the NOPR proposal to
require each RTO or ISO to accept bids from demand response resources,
on a basis comparable to any other resources, for ancillary services
that are acquired in a competitive bidding process, if the demand
response resources: (1) are technically capable of providing the
ancillary service and meet the necessary technical requirements; and
(2) submit a bid under the generally-applicable bidding rules at or
below the market-clearing price, unless the laws or regulations of the
relevant electric retail regulatory authority do not permit a retail
customer to participate. All accepted bids would receive the market-
clearing price.
48. The Commission's policy has been, and continues to be, to
identify and eliminate barriers to participation of demand response
resources in organized power markets. Development of demand response
resources provides benefits to consumers by providing competitive
pressure to reduce wholesale power prices, providing for the more
efficient operation of organized markets, helping to mitigate market
power and enhance system reliability, and encouraging development and
implementation of new technologies, including renewable energy and
energy efficiency resources, distributed generation and advanced
metering. The reforms implemented in this Final Rule will benefit
energy consumers by removing several barriers to the development and
use of demand response resources in organized wholesale electric power
markets.
49. As noted in the NOPR, this requirement would apply to
competitively-bid markets, if any, for energy imbalance, spinning
reserves, supplemental reserves, reactive supply and voltage control,
and regulation and frequency response as defined in the pro forma OATT,
or to the markets of their functional equivalents in an RTO or ISO
tariff.\76\ The Commission requires that demand response resources that
are technically capable of providing the ancillary service within the
response time requirements,\77\ and that meet reasonable requirements
adopted by the RTO or ISO as to size, telemetry, metering and bidding,
be eligible to bid to supply energy imbalance, spinning reserves,
supplemental reserves, reactive and voltage control, and regulation and
frequency response.\78\
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\76\ NOPR, FERC Stats. & Regs. ] 32,628 at P 56.
\77\ Some technologies may be capable of responding to an RTO's
or ISO's control signal and providing certain ancillary services,
such as regulation and frequency response service, more quickly than
under existing response time requirements.
\78\ 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. The RTO or ISO should not be
in the position of interpreting the laws or regulations of a
relevant electric retail regulatory authority.
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50. In response to Allied Public Interest Groups, we decline to
define ``comparable treatment.'' Each RTO and ISO is unique, and the
Commission hesitates to impose a uniform definition. Each RTO and ISO
therefore should establish policies and procedures in cooperation with
its customers and other stakeholders that ensure that demand response
resources are treated comparably to supply-side resources. The
Commission will have ample opportunity to evaluate concerns that may
arise when it reviews the compliance filings required by this Final
Rule.
51. In light of APPA's comments, we clarify that this requirement
applies only to competitively-bid markets for those ancillary services
specified, as well as to the markets of their functional equivalents in
an RTO or ISO tariff. This requirement does not obligate RTOs or ISOs
to create new competitively-bid ancillary services markets.
52. In response to Xcel and E.ON U.S., we note that the Commission
proposed in the NOPR to obligate RTOs and ISOs to accept bids from
demand response resources on a comparable basis to supply resources for
ancillary services. For Xcel, we clarify that demand response providers
are not required to offer potential demand response into the ancillary
services markets. Demand response resources may evaluate market prices
and other factors before making a determination to bid or not.
Regarding E.ON U.S.'s comments, the Commission did not propose (and
does not require) that RTOs or ISOs must purchase ancillary services
from demand response resources without regard to whether these
resources are lower-bid alternatives to supply resources.
53. In response to NARUC and others who comment that the
Commission's proposal would place the burden on retail regulatory
authorities to show that a demand response proposal conflicts with
state or local laws or regulations, we clarify that we will not require
a retail regulatory authority to make any showing or take any action in
compliance with this rule.\79\ Rather, this rule merely requires an RTO
or ISO to accept bids for ancillary services from demand response
resources, unless the laws or regulations of the relevant electric
retail regulatory authority do not permit a retail customer to
participate.
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\79\ In reply to the Pennsylvania PUC's recommendation that the
Commission continue to work with state authorities to eliminate
barriers to demand response, we note that NARUC and the Commission,
through their Demand Response Collaborative, are working to outline
options to coordinate retail and wholesale regulatory policies in
order to stimulate participation in demand response by reducing or
eliminating jurisdictional barriers.
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54. We disagree with commenters who argue that requiring RTOs and
ISOs to allow demand response resources to participate in ancillary
services markets may be counterproductive or unnecessary.\80\ This
requirement removes a barrier to participation of demand response
resources in organized wholesale markets and allows these resources to
provide ancillary services on a basis comparable to generation sources.
This requirement would potentially expand the resource pool in these
organized markets, thereby lowering the overall market price for
ancillary services, as well as potentially mitigating the exercise of
market power. The competitiveness within ancillary services markets, as
well as the system reliability, would be enhanced through increased
participation.
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\80\ The Commission has approved actions by some RTOs and ISOs
to incorporate demand response into their ancillary services
markets. See, e.g., California Indep. Sys. Operator, 116 FERC ]
61,274 (2006); PJM Interconnection, LLC, 114 FERC ] 61,201 (2006).
---------------------------------------------------------------------------
55. Contrary to Midwest Energy's comments, we do not find that this
requirement will lead to any preferential treatment for demand response
resources or supply-side resources. Both sets of resources would be
treated and penalized comparably in instances of non-performance.
56. In response to Public Interest Organizations, the Commission
has not excluded from eligibility any type of resource that is
technically capable of providing the ancillary service, including a
load serving entity's (LSE) or eligible retail customer's behind-the-
meter generation or any other demand response resource. Further, the
Commission appreciates the value of energy efficiency, and is aware of
RTO and ISO efforts to integrate energy efficiency into organized
markets. Nothing in this rule precludes an RTO or ISO from
appropriately including energy efficiency into any of its markets. The
Commission did not propose to include energy efficiency as a provider
[[Page 64108]]
of competitively procured ancillary services, and does not have an
adequate record to address this issue here.
57. With regard to Industrial Consumers' and EnerNOC's comments
requesting the resolution of customer baseline issues, the Commission
agrees that customer baselines are an important factor in the
appropriate compensation for demand response resources. Customer
baselines are designed to depict, as accurately as possible, a
customer's normal load on a given day. Establishing this baseline helps
system operators to measure and verify load reductions, thus giving
RTOs and ISOs the ability to not only determine if demand response
resources showed up, but also what the proper value of the demand
reduction should be. Many RTOs and ISOs currently establish such bidder
baselines as part of their demand response programs, or they are
working with their stakeholders to modify such methodologies.
Accordingly, RTOs and ISOs should describe in their compliance filings
their efforts to develop adequate customer baselines.
58. Regarding comments related to WECC's provisions for demand
response resources in its reliability standards, we note that this rule
requires comparable treatment for demand response resource
participation in ancillary services markets. This is a general
rulemaking and is not the proper venue for adjudicating the alleged
issue regarding WECC's regional reliability standards.\81\
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\81\ Concerns regarding WECC's regional reliability standards
can be addressed by filing a complaint under section 206 of the FPA,
16 U.S.C. 824e, or by filing a notice under section 215 of the FPA,
16. U.S.C. 824o. Under section 215, ``[i]f a user, owner or operator
of the transmission facilities of a Transmission Organization
determines that a [r]eliablity [s]tandard may conflict with a
function, rule, order, tariff, rate schedule, or agreement accepted,
approved, or ordered by the Commission * * *. the Transmission
Organization shall expeditiously notify the Commission * * *.'' 18
CFR 39.6.
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59. In response to comments, the Commission again finds that it is
not appropriate in this rulemaking to develop a standardized set of
technical requirements for demand response resources participating in
ancillary services markets. Instead, the Commission will allow each RTO
and ISO, in conjunction with its stakeholders, to develop its own
minimum requirements. However, as proposed in the NOPR, the Commission
will require RTOs and ISOs to coordinate with each other in the
development of such technical requirements, and provide the Commission
with a technical and factual basis for any necessary regional
variations.\82\ In addition, having RTOs and ISOs work in conjunction
with stakeholders as well as with each other should ensure that any
developed requirement is not so full of technical detail or so
burdensome that it discourages demand response resource participation.
---------------------------------------------------------------------------
\82\ NOPR, FERC Stats. & Regs. ] 32,628 at P 64.
---------------------------------------------------------------------------
60. With respect to NYISO's request that the Commission clarify its
proposed regulatory language to specify that demand response resources
must also meet ``applicable reliability requirements,'' the Commission
does not see a need to include this provision in this Final Rule. To do
so would merely duplicate existing regulations that require reliability
standards, and that set out certain reliability requirements. This
duplication would serve no useful purpose.
61. As part of the compliance filing to be submitted within six
months of the Final Rule, each RTO or ISO is required to file a
proposal to adopt reasonable standards necessary for system operators
to call on demand response resources, and mechanisms to measure,
verify, and ensure compliance with any such standards. These standards
would be subject to Commission approval.
62. The Commission is mindful of the progress being made in
California with MRTU and in the Midwest ISO with its ASM Order. Our
requirement is that, where there are markets for acquiring ancillary
services, these markets must be open to qualified demand response
bidders. This requirement allows each RTO or ISO to work with
stakeholders to develop the appropriate implementation rules for its
own market design. This approach allows for regional variation and
should alleviate the concerns of Midwest ISO, CAISO, and Maine PUC.
63. The Commission will not now rule on CAISO's request that the
Commission not interfere with its current timeline to implement MRTU,
or Midwest ISO's request that the Commission find Midwest ISO already
satisfies the proposed requirements through its ASM Proposal. CAISO and
Midwest ISO must submit, within their respective compliance filings, a
description of how their current activities comply with the
requirements of this Final Rule. Upon review, the Commission will
determine if further action on behalf of either RTO or ISO is
necessary.
b. New Bidding Parameters
64. The Commission proposed to require RTOs and ISOs to allow
demand response resources to specify limits on the frequency and
duration of their service in their bids to provide ancillary services--
or their bids into the joint energy-ancillary services market in the
co-optimized RTO markets.\83\ These limits would include a maximum
duration for dispatch, a maximum number of times per day that demand
response resources could be called, or a maximum amount of energy per
day or week that a resource can produce.
---------------------------------------------------------------------------
\83\ Id. P 62.
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65. The Commission requested comment on this proposed requirement
and whether these new parameters should be available for all bidders,
not just for demand response resources. Further, the Commission
intended that the bidding parameters would be implemented by all RTOs
and ISOs, and proposed to require them to confer with each other and to
provide a technical and factual basis for any necessary regional
variations.
i. Comments
66. Most commenters support the Commission's proposal to require
RTOs and ISOs to incorporate new parameters into their bidding rules to
allow demand response resources to specify in their bids the duration
and frequency of their service.\84\ For instance, several commenters
state that allowing new bidding parameters would increase the number
and type of demand response resources participating in the ancillary
services markets.\85\ Some commenters note that generators face certain
constraints (including start-up costs, ramp rates, and limits on the
number of hours that they may operate efficiently), which are reflected
within their bids. They assert that allowing demand response resources
to specify similar constraints within their bids is consistent with the
Commission's principle of comparability between demand-side and supply-
side resources.\86\ DC Energy states that, similar to generators,
demand response providers should have the choice to
[[Page 64109]]
observe market signals and make an informed decision on whether to bid
into these markets.\87\
---------------------------------------------------------------------------
\84\ E.g., Ameren; American Forest; APPA; BlueStar Energy;
Beacon Power; Mr. Borlick; BP Energy; California DWR; California
PUC; Cogeneration Parties; Comverge; DC Energy; Detroit Edison;
DRAM; Duke Energy; EEI; EnergyConnect; EnerNOC; Exelon; FTC; First
Energy; Industrial Coalitions; Industrial Consumers; ISO New
England; ISO/RTO Council; Midwest ISO; North Carolina Electric
Membership; Ohio PUC; Old Dominion; Organization of Midwest ISO
States; PG&E; Public Interest Organizations; Reliant; Steel
Producers; TAPS; Wal-Mart; and Xcel.
\85\ E.g., American Forest at 5; Exelon at 5.
\86\ American Forest at 5; Cogeneration Parties at 3; DRAM at 6-
7; Duke Energyat 3-4; Exelon at 5-6; FTC at 25-27; FirstEnergy at 7;
Industrial Consumers at 12; ISO/RTO Council at 4; North Carolina
Electric Membership at 4; Old Dominion at 8; and Public Interest
Organizations at 6.
\87\ DC Energy at 4.
---------------------------------------------------------------------------
67. The ISO/RTO Council asserts that the implementation of these
new bidding parameters must be done in a way that assures demand
response resources participating in ancillary services markets meet the
same product requirements as supply-side resources.\88\ Several
commenters express their support for this concept provided that demand
response resources are not afforded an undue advantage over supply-side
resources.\89\
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\88\ ISO/RTO Council at 4.
\89\ E.g., Old Dominion at 8; Reliant at 4; and Wal-Mart at 5.
---------------------------------------------------------------------------
68. Two commenters state that they support the proposal provided
that certain conditions are met. Ameren states there should be no
adverse effect on system reliability and that any market rules that
provide this flexibility should be limited in scope so as to avoid the
potential for gaming.\90\ BP Energy agrees with the Commission's
proposal only to the extent that bidding parameters submitted by demand
response resources can be incorporated into the RTO and ISO software in
a cost effective manner while maintaining the algorithm's ability to
perform timely cost minimizing optimizations.\91\
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\90\ Ameren at 18.
\91\ BP Energy at 14.
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69. ISO New England supports granting individual demand response
resources the opportunity to specify additional bidding parameters, but
notes that such specification may limit the resource's qualification
(under market rules) on an individual basis to bid to supply operating
reserves.\92\ However, ISO New England itself notes that demand
response aggregators should be in a position to formulate bids
combining individual demand resources so as to be able to meet the
reserves market's availability requirements in a manner comparable to
that of generation.
---------------------------------------------------------------------------
\92\ ISO New England at 5.
---------------------------------------------------------------------------
70. Duke Energy notes that the NOPR proposal would allow demand
response resources to manage the risk that they would be called upon
too frequently or for too long a period relative to their individual
constraints. In that respect, Duke Energy asserts that if RTOs and ISOs
are not required to account for such bid flexibility, demand resources
could potentially be eliminated from the ancillary services markets
through voluntary means.\93\ Duke Energy argues that without any
knowledge of how and when they will be used, demand resources may view
the ancillary services markets as too risky and, therefore, not
participate in them. APPA states that large end-use customers' desire
to reduce consumption on short notice decreases the more frequently
they are called upon.\94\
---------------------------------------------------------------------------
\93\ Duke Energy at 3-4.
\94\ APPA at 36-37.
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71. Steel Producers asserts that demand response resources' unique
characteristics need to be taken into account, and recommends that the
Commission require RTOs and ISOs to allow, at a minimum, the following
optional bidding parameters in addition to the three mentioned in the
NOPR: (1) Minimum notice requirement; (2) minimum/maximum shut-down
time; (3) minimum duration for dispatch; (4) targeted demand reduction
level; (5) bids ``down to'' a designated megawatt level; and (6)
guaranteed minimum LMP.\95\
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\95\ Steel Producers at 4-5.
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72. Similarly, California PUC requests that the Commission expand
its proposal to include all demand response resource bids in all
aspects of wholesale markets, and also permit each demand resource
bidder to submit, as part of its bid and a master file, its output
constraints such as minimum load reduction, minimum load, load
reduction initiation time, minimum load reduction time, maximum load
reduction time, minimum base load time, maximum number of daily load
curtailments, minimum and maximum daily energy limits, load pick up
rate, load drop rate, load reduction initiation cost, and minimum load
reduction cost.\96\
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\96\ California PUC at 13-14.
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73. Multiple commenters argue for a regional approach in
implementing the Commission's proposal.\97\ For instance, EEI and
Detroit Edison state that they support the Commission's proposal
provided that RTOs and ISOs can establish lower or minimum limits for
such service.\98\ EEI asks that RTOs and ISOs be allowed to specify the
minimum duration in hours or minimum number of times per day or week
that a resource may be called upon. Duke Energy states that the
specific bid parameters, as well as the methodologies and procedures
that RTOs and ISOs use to implement the Commission's proposal, should
be developed on a regional basis within their stakeholder processes,
rather than through a Commission-imposed uniform requirement in the
Final Rule.\99\ NYISO also contends that a regional approach is
appropriate because specifying bidding parameters in the regulations
may prove problematic in the future as regional market designs continue
to evolve.\100\ Exelon agrees with the Commission that minimum
requirements for bidding parameters should not be prescribed by the
Commission in this rulemaking, but rather should be developed by RTOs
and ISOs. Exelon also supports the Commission's proposed requirement
that RTOs and ISOs provide justification for any necessary regional
variations.\101\ EnerNOC believes the Commission, by requiring
coordination and justification for variations, without mandating
standardization, has articulated the correct compromise.\102\
---------------------------------------------------------------------------
\97\ E.g., EEI; Detroit Edison; Duke Energy; ISO/RTO Council;
North Carolina Electric Membership; NYISO; and Kansas CC.
\98\ EEI at 13; Detroit Edison at 2-3.
\99\ Duke Energy at 4.
\100\ NYISO at 6.
\101\ Exelon at 6.
\102\ EnerNOC at 9.
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74. Midwest ISO and CAISO state that their market designs already
satisfy the NOPR's proposed bidding parameters requirement. Midwest ISO
states that it developed its bidding parameters through the stakeholder
process and that the parameters were approved by the Commission within
its ASM Order.\103\ Therefore, Midwest ISO asks that the Commission
find that its ASM proposal satisfies the NOPR's requirement regarding
bidding parameters. Similarly, CAISO states that it is developing its
ancillary services market and it will comply with the proposed bidding
parameters in the Release 1A enhancements to MRTU.\104\
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\103\ Midwest ISO at 10. Midwest ISO states that its tariff
allows market participants (both generators and demand response
resources) to specify hourly ramp rates, hourly economic minimum and
maximum limits, hourly regulation minimum and maximum limits,
minimum and maximum run times, as well as a maximum start-up limit,
which establishes the maximum number of times the resource can be
called upon within a twenty-four-hour period.
\104\ CAISO at 2.
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75. Further, several commenters support making additional
parameters available for all bidders, to include both demand and supply
resources.\105\ Wal-Mart states that comparable rules could apply to
supply resources as long as neither supply nor demand resources are
provided with an advantage.\106\ Old Dominion states that all resources
bidding into the ancillary services markets should be susceptible to
the same penalties, performance and reliability requirements.\107\
Exelon states that as long as the specification of operational
limitations does not impair
[[Page 64110]]
market efficiency, demand and supply resources should be treated on a
comparable basis because they provide reliable and efficient capacity
to RTOs and ISOs.\108\
---------------------------------------------------------------------------
\105\ E.g., California DWR at 12; Duke Energy at 4; EEI at 14;
EnerNOC at 8; Exelon at 6; Midwest ISO at 10; Reliant at 4; and Wal-
Mart at 5.
\106\ Wal-Mart at 5.
\107\ Old Dominion at 8.
\108\ Exelon at 5-6.
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76. The California DWR supports making new parameters available to
all resources because certain facilities have a specific purpose that
is distinct from sales to, or support of, the electric grid. For
instance, hydroelectric generation sites must satisfy water storage,
water delivery, and related operational requirements. The California
DWR asserts that any RTO or ISO requirements must accommodate this
primary purpose for these resources.\109\
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\109\ California DWR at 12-13.
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77. Several commenters state that new bidding parameters should not
be available to all resources.\110\ For instance, TAPS states that
there is already ample bidding flexibility for generators, and it is
concerned about the possibility of creating unintended consequences
such as new gaming opportunities. APPA states that RTO and ISO
ancillary services markets are already complex and accommodating
additional bid parameters for generators in their software and problem
solving algorithms would make the markets even more complicated.
Although EEI is in agreement with making new bidding parameters
available for all bids, it is concerned that applying the new
parameters to generation resources without evaluating the implications
could result in creating unintended incentives. Therefore, EEI suggests
that RTOs and ISOs should not be required to apply the new parameters
across all generating resources as long as they provide justification
for treating some generating resources differently.
---------------------------------------------------------------------------
\110\ E.g., APPA at 37; Mr. Borlick at 2; and TAPS at 8.
---------------------------------------------------------------------------
78. Finally, among the supporters of this proposal, EEI states that
the addition of new parameters to bidding rules must not result in any
fundamental change to existing market designs or affect the
efficiencies of co-optimized markets.\111\
---------------------------------------------------------------------------
\111\ EEI at 14.
---------------------------------------------------------------------------
79. Several commenters state that demand response providers should
be allowed to sell into the ancillary services markets without being
required to sell into the energy market.\112\ Comverge is in favor of
this, but notes that demand response providers should also be allowed
to sell into the energy market on a voluntary basis. Beacon Power
states that a generator is always capable of supplying energy and,
therefore, does not face the financial risks and barriers that a non-
generator faces if it is forced to bid into the energy market.
---------------------------------------------------------------------------
\112\ E.g., Beacon Power at 9; Comverge at 12; and Wal-Mart at
5.
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80. NEPOOL Participants opposes the Commission's proposal to
implement new bidding parameters for demand response resources. NEPOOL
Participants states that each region needs an opportunity to evaluate
this issue more fully and consider whether bidding limits are the most
appropriate solution and whether such limits or other reforms should be
restricted to just demand response or include other kinds of resources.
It asserts that any change in bidding requirements needs to ensure
comparability with others resources and that system reliability is
maintained.\113\ Maine PUC agrees.\114\
---------------------------------------------------------------------------
\113\ NEPOOL Participants at 11-12.
\114\ Maine PUC at 3-4.
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ii. Commission Determination
81. The Commission determines that each RTO and ISO is required to
allow demand response resources to specify limits on the duration,
frequency and amount of their service in their bids to provide
ancillary services--or their bids into the joint energy-ancillary
services markets in the co-optimized RTO markets. As noted in the NOPR
(and several commenters agree), these limits are comparable to the
limits generators may specify on price, quantity, startup and no-load
costs, and minimum downtime between starts.\115\ All RTOs and ISOs must
incorporate new parameters into their ancillary services bidding rules
that allow demand response resources to specify a maximum duration in
hours that the demand response resource may be dispatched, a maximum
number of times that the demand response resource may be dispatched
during a day, and a maximum amount of electric energy reduction that
the demand response resource may be required to provide either daily or
weekly.
---------------------------------------------------------------------------
\115\ NOPR, FERC Stats. & Regs. ] 32,628 at P 62.
---------------------------------------------------------------------------
82. This requirement eliminates a major barrier to participation of
demand response resources in ancillary services markets by ensuring
that demand response resources are treated comparably to supply-side
resources. In this regard, the Commission agrees with comments from
APPA, Duke Energy, and others that argue that the desire of many end-
use customers to reduce their consumption levels on short notice may
decrease the more frequently they are called upon. This requirement
would allow those customers to limit the frequency with which they are
called upon to reduce demand, and thus make it more economically
beneficial for these resources to participate in ancillary services
markets.
83. The Commission's requirement also enhances competition within
ancillary services markets. With demand response resources able to
specify the duration, frequency and amount of their service, ancillary
services markets will become more attractive for such resources.
Increased participation in the market will result in an expanded pool
of available resources, thereby potentially improving demand elasticity
and system reliability, as well as lessening price volatility.
84. The Commission also finds that this requirement removes
barriers to the comparable treatment of demand-side and supply-side
resources. Generators include operational constraints in their bids,
and permitting demand response resources to do the same results in the
comparable treatment of both supply-side and demand-side resources.
However, in keeping with this effort of greater comparability, the
Commission determines that implementation of its requirement by RTOs
and ISOs should not lead to either demand-side or supply-side resources
being afforded an undue advantage within ancillary services markets.
85. In the NOPR, the Commission requested comment on whether other
bidding parameters should be considered.\116\ The Commission noted that
any proposed parameters must not have the effect of creating an undue
preference for demand response resources. The Commission does not have
a sufficient record here to assess whether the proposed additional
bidding parameters submitted by the California PUC and Steel Producers
may offer demand response resources greater flexibility within their
bids as compared to the bids of generators. For this reason the
Commission will not accept the proposed additional bidding parameters
on a generic basis for all RTOs and ISOs in this rulemaking. Rather,
individual RTOs and ISOs are free to propose additional parameters in
their compliance filings, as long as they do not provide undue
preference to demand response resources vis-a-vis supply-side
resources, and interested persons may raise these additional parameters
with their deliberations with the individual RTOs and ISOs.
---------------------------------------------------------------------------
\116\ Id. P 64.
---------------------------------------------------------------------------
86. In the NOPR, the Commission stated that it was not appropriate
for the Commission to develop in a rulemaking a standardized set of
minimum requirements for minimum size bids, measurement, telemetry and
other
[[Page 64111]]
factors, and instead allowed RTOs and ISOs to develop their own minimum
requirements, including bidding parameters.\117\ The Commission adopts
this position in this Final Rule. RTOs and ISOs must incorporate
bidding parameters that allow demand response resources to specify
limitations on the duration, frequency and amount of their service.
However, the development of specific parameters and the methods used to
implement the Commission's requirement are the responsibility of the
RTOs and ISOs, in consultation with their respective stakeholders. RTOs
and ISOs are also required to confer with each other on such parameters
and methods and to provide a technical and factual basis for any
necessary regional variations. This approach adequately accounts for
regional variation between the RTOs and ISOs and alleviates the
concerns of those commenters requesting regional flexibility in
implementing the Commission's requirement.
---------------------------------------------------------------------------
\117\ Id.
---------------------------------------------------------------------------
87. Midwest ISO asks that the Commission find that it already
complies with the additional bidding parameters requirement of the
Final Rule. Similarly, the California ISO asserts that it will also be
compliant with the requirement upon Release 1A in its MRTU process. The
Commission does not intend to interrupt the progress being made in
either region. However, as indicated above, the Commission will not at
this time determine that either region satisfies the Commission's
requirement obligating RTOs and ISOs to incorporate new bidding
parameters for demand response resources, and instead will wait until
each region submits its necessary compliance filing.
88. In the NOPR, the Commission requested comment on whether these
additional parameters should be available for all bids, or for demand
response bids only. In light of the comments received, the Commission
determines that new requirements for bidding rules allowing demand
response resources to specify the duration, frequency and amount of
their service pertain only to demand response resources. Individual
RTOs and ISOs are free to propose to apply them more broadly. While the
Commission understands that making these new parameters available for
all resources could benefit hydropower resources and other
environmentally restricted, or run-time limited resources, the
Commission agrees with TAPS and others that there is already sufficient
bidding flexibility afforded to generators, and is concerned about the
possibility of creating unintended consequences. For these reasons, at
this time the Commission will not require an RTO or ISO to make these
new bidding parameters available for all resources.
89. With regard to comments that demand response providers should
be allowed to sell into the ancillary services markets without being
required to sell into the energy market, the Commission notes that the
ANOPR proposal permitting such action was removed at the NOPR stage,
and replaced with a proposal to allow demand response resources to
specify limitations on the duration, frequency and amount of their
service.\118\ The Commission had received comments previously that
argued that allowing demand response resources to bid into the
ancillary services markets without also bidding into the energy markets
could upset certain market efficiencies in co-optimized markets.
Therefore, the Commission put forth a compromise proposal, which allows
demand response resources to specify operational limits in their bids
as a way for these resources to minimize the risk that they are called
on too frequently, thereby making participation in ancillary services
markets more feasible. No one has persuaded us otherwise; therefore,
the Commission will adopt this provision from the NOPR.
---------------------------------------------------------------------------
\118\ Id. P 62.
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c. Small Demand Response Resource Assessment
90. The NOPR proposed to direct RTOs and ISOs to assess the value
and technical feasibility of small demand response resources providing
ancillary services one year from the effective date of the Final Rule,
including whether (and how) smaller demand response resources can
reliably and economically provide operating reserves through pilot
projects or other mechanisms.\119\
---------------------------------------------------------------------------
\119\ Id. P 59.
---------------------------------------------------------------------------
i. Comments
91. Several commenters support the NOPR proposal for small demand
response resource assessment.\120\ For example, Reliant states that
accommodating smaller demand response resources may result in an
increase in operating reserves.\121\ EnerNOC believes that the
assessment effort will reveal ways for smaller demand response
resources to provide ancillary services while maintaining reliable
operations and appropriate measurement and verification.\122\ APPA
believes that pilot programs could be particularly valuable in
assessing technical feasibility of accommodating smaller demand-side
resources.\123\ It notes that accurate metering and telemetry would be
significant factors in any efforts associated with this assessment,
primarily because ``communication and operational performance standards
applicable to demand-side resources are more demanding than the current
requirements applicable to retail customers.'' Public Interest
Organizations request that ``RTOs and ISOs be directed to specifically
address the issue of comparable treatment of smaller loads.'' \124\
Allied Public Interest Groups believe that the Commission should
include in its Final Rule a directive to RTOs and ISOs to initiate
pilot programs for small demand response resources similar to the ISO
New England Demand Response Reserves Pilot Program.\125\ In their view,
pilot programs aid grid operators in determining whether a diverse
portfolio of demand response resources that includes small resources
can provide cost-effective and reliable ancillary services.
---------------------------------------------------------------------------
\120\ E.g., APPA, Public Interest Organizations, EnerNOC; DRAM;
Old Dominion; andReliant.
\121\ Reliant at 4.
\122\ EnerNOC at 3.
\123\ APPA at 35.
\124\ Public Interest Organizations at 6.
\125\ Allied Public Interest Groups at 9.
---------------------------------------------------------------------------
92. EnerNOC and DRAM indicate that technical requirements for
demand response participation in ancillary services markets may act as
a barrier if the technical requirements exceed what is necessary to
ensure reliable electric system operations.\126\ For example, they note
that certain telemetry requirements may preclude smaller loads from
participating in ancillary services markets. However, EnerNOC states
that an assessment on how to accommodate these resources could result
in reasonable standards for smaller loads that take into account the
operational characteristics of such loads so as to capture their value
efficiently. DRAM states that the proposed assessment should allow
parties to focus on how best to modify the requirements for small
demand response resource participation without creating a bias against
supply-side resources.\127\ Neither EnerNOC nor DRAM suggests that
smaller demand response resources be allowed to participate in these
markets with less stringent standards than other resources. Further,
EnerNOC asserts that the small demand response resource assessment
requirement should not be used as an excuse to delay currently underway
pilot programs or
[[Page 64112]]
other smaller resource reforms taking place in RTOs and ISOs. In
addition, this requirement should not create an opportunity to avoid
addressing barriers to smaller resource participation in ancillary
services markets.\128\
---------------------------------------------------------------------------
\126\ EnerNOC at 4; DRAM at 16.
\127\ DRAM at 16.
\128\ EnerNOC at 6.
---------------------------------------------------------------------------
93. Old Dominion supports the proposal and agrees that
incorporating smaller demand response resources would be beneficial to
the market, but notes that measurement and verification standards
specific to these smaller resources may be necessary to ensure proper
allocation of costs and to address any reliability concerns.\129\
---------------------------------------------------------------------------
\129\ Old Dominion at 8.
---------------------------------------------------------------------------
94. Two commenters disagree on how smaller demand response
resources should be defined. EnerNOC recommends that the Commission
clarify that ``smaller demand response resources'' should be construed
more broadly than the residential class of customers because a more
diverse portfolio is more valuable to the market. EEI, however,
disagrees and recommends that the Commission not define what
constitutes smaller demand response resources, and instead allow each
RTO or ISO to propose a definition that reflects its particular market
design and characteristics.\130\
---------------------------------------------------------------------------
\130\ EEI at 12.
---------------------------------------------------------------------------
95. The ISO/RTO Council comments that its Markets Committee is
already addressing certain aspects of this issue by developing a
communications protocol for small demand resources, and that these
efforts will be discussed at a technical conference on integrating
small demand resources into organized markets. The ISO/RTO Council
asserts that its report will not supplant the Commission's proposed
assessment, but still urges the Commission to coalesce its proposal
with the work of the ISO/RTO Council Markets Committee.\131\
---------------------------------------------------------------------------
\131\ ISO/RTO Council at 6.
---------------------------------------------------------------------------
96. Finally, ISO New England notes that it currently has a demand
response reserve pilot program in place to assess the ability of
smaller demand resources to provide reserve products to the wholesale
market, and to develop comparable communication, metering, telemetry
and other technical infrastructure solutions that are more suitable and
cost effective for smaller, dispersed demand resources.\132\
---------------------------------------------------------------------------
\132\ ISO New England at 4.
---------------------------------------------------------------------------
ii. Commission Determination
97. The Commission will require RTOs and ISOs, in cooperation with
their customers and other stakeholders, to perform an assessment,
through pilot projects or other mechanisms, of the technical
feasibility and value to the market of smaller demand response
resources providing ancillary services, within one year from the
effective date of the Final Rule, including whether (and how) smaller
demand response resources can reliably and economically provide
operating reserves and report their findings to the Commission. The
choice between either a pilot program or other mechanisms in this
assessment is appropriately left to the discretion of the RTO or ISO
and its customers and other stakeholders. Additional issues raised here
by commenters, such as the need for measurement and verification
standards and a definition of what constitutes a ``small demand
response resource'' should be addressed in the assessments.
98. The Commission finds that, based on the comments, accommodating
smaller demand response resources through adjusted minimum size
thresholds and telemetry requirements could result in an increase in
potential operating reserves. Allowing more resources to participate in
operating reserves and other ancillary services markets may increase
the competitiveness of these markets and could lower the overall price
for such services.
99. The Commission agrees that this assessment should not delay
pilot programs that are currently underway or other smaller load
reforms taking place in RTOs and ISOs, nor should it create an
opportunity to avoid addressing barriers to smaller load participation
in ancillary services markets. In addition, while not part of the
Commission's requirement, the Commission encourages the ISO/RTO Council
to continue developing a communications protocol for small demand
response resources and encourages RTOs and ISOs to consider the ISO/RTO
Council's work in developing their individual assessments.
3. Eliminating Deviation Charges During System Emergencies
a. Deviation Charges
100. The Commission proposed in the NOPR to require that all RTO
and ISO tariffs be modified as necessary to eliminate a charge-referred
to as a deviation charge \133\--to a buyer \134\ in the energy market
for taking less electric energy than it planned to take in the real-
time market, 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 to avoid an operating reserve shortage.\135\
---------------------------------------------------------------------------
\133\ Deviation charges recover certain costs, including
generators' costs (such as start-up costs) that exceed their energy
market revenues when real-time demand is less than forecast. These
``uplift'' costs may include the cost of extra generators committed
after the close of the day-ahead market to serve anticipated load,
if those costs are not recovered from sales of energy at real-time
LMPs.
\134\ Examples of buyers in RTO and ISO energy markets include
an LSE thatpurchases electricity to meet the load requirements of
its retail customers and a retail customer that purchases
electricity directly from the wholesale market.
\135\ NOPR, FERC Stats. & Regs. ] 32,682 at P 72.
---------------------------------------------------------------------------
101. The Commission proposed that an RTO or ISO must either propose
amendments to its tariffs to comply with this requirement or
demonstrate through a compliance filing that its existing tariff and
market design meet this requirement. The Commission proposed that this
filing be submitted within six months of the date that this Final Rule
is published in the Federal Register .
102. The Commission's proposal applies to real-time demand response
that occurs in addition to the demand response of participants in an
RTO's or ISO's wholesale demand response program. Under the proposal,
deviation charges would be eliminated only when the RTO or ISO
announces an emergency situation after the close of the day-ahead
market. The Commission also proposed that since deviation charges cover
real costs to generators and others that are not recovered from the
sale of energy in real time, these costs should be allocated to all
loads of the RTO or ISO.
i. Comments
103. A majority of commenters supports the Commission's proposal
and agree that eliminating deviation charges during periods when the
RTO or ISO declares an operating reserve shortage or makes a generic
request to reduce load to avoid an operating reserve shortage would
eliminate a barrier to demand reduction in wholesale energy
markets.\136\ For instance, Energy Curtailment and PG&E state that
penalizing an LSE for taking less energy in real-time during system
[[Page 64113]]
emergencies would be counterproductive.\137\ Many commenters agree that
this proposal would result in several benefits, including reduced
market prices, mitigation of market power, and improved system
reliability.\138\
---------------------------------------------------------------------------
\136\ Ameren at 23; American Forest at 6; APPA at 3; BlueStar
Energy at 2; Mr. Borlick at 2; BP Energy at 15; California DWR at
15; CASIO at 1; California PUC at 15; Cogeneration Parties at 3;
Comverge at 17; DC Energy at 5; Dominion Resources at 6; DRAM at 18;
Duke Energy at 5; EEI at 14; Energy Curtailment at 4; EnerNOC at 11;
Exelon at 6; FirstEnergy at 8; Industrial Coalitions at 11;
Industrial Consumers at 15; Integrys Energy at 9; ISO New England at
8; ISO/RTO Council at 6; LPPC at 7; MADRI States at 6; Maine PUC at
3; Midwest Energy at 2; Midwest ISO at 11; NCPA at 5; NEPOOL
Participants at 12; NIPSCO at 9; North Carolina Electric Membership
at 4; Ohio PUC at 7; Old Dominion at 9; OMS at 3; OPSI at 4;
Pennsylvania PUC at 11; PG&E at 8; Public Interest Organizations at
6; Reliant at 4; Steel Manufacturers at 11; Steel Producers at 5;
TAPS at 9; Wal-Mart at 5; and Xcel at 8.
\137\ Energy Curtailment at 4-5; PG&E at 8.
\138\ While APPA supports this proposal, it states that if bid
and offer caps are eliminated during system emergencies, it cannot
support uplifting such charges.APPA at 3.
---------------------------------------------------------------------------
104. Several supporters also agree with the Commission's proposal
to allocate to all loads of the RTO and ISO uplift charges to cover
costs associated with the elimination of such deviation charges.\139\
However, NIPSCO and Old Dominion state that uplift charges should be
allocated only within the zones where the emergency occurred.\140\
Dominion Resources and ISO/RTO Council urge the Commission to allow
each region to decide how the costs should be allocated based on market
constraints and input from stakeholders.\141\
---------------------------------------------------------------------------
\139\ E.g., Ohio PUC at 7-8; Public Interest Organizations at 6;
EEI at 14-15; DRAM at 18-19.
\140\ NIPSCO at 9; Old Dominion at 9.
\141\ Dominion Resources at 8-9; ISO/RTO Council at 6-8.
---------------------------------------------------------------------------
105. Several commenters seek clarification of various aspects of
the proposal. For instance, EEI asks the Commission to clarify that
deviation charges would be eliminated only when the RTO or ISO
announces an emergency situation after the close of the day-ahead
market.\142\ TAPS suggests that the Commission clarify that it intends
to encompass all forms of demand response that could be activated to
reduce load during emergencies, including programs that operate behind
the meter of the LSE with a reduction reflected in the wholesale market
participant's demand.\143\ Cogeneration Parties note that it is unclear
whether the costs caused by uninstructed deviations during normal
operations would also be incurred during a system emergency, and
recommend that the Final Rule require RTOs and ISOs to verify their
actual costs incurred during system emergencies before such charges are
imposed on customers.\144\ Similarly, Midwest Energy suggests that the
net benefits for load reductions be verified before costs are imposed
on customers.\145\
---------------------------------------------------------------------------
\142\ EEI at 14-15.
\143\ TAPS at 9-11.
\144\ Cogeneration Parties at 3.
\145\ Midwest Energy at 3.
---------------------------------------------------------------------------
106. A few commenters urge the Commission to clearly define
``deviation charge'' and the circumstances under which deviation
charges would be eliminated. For example, NYISO requests that the
Commission clarify its proposed regulatory text to more specifically
define deviation charges.\146\ Others state that circumstances under
which an RTO or ISO merely seeks to avoid an operating reserve shortage
are significantly different from those in which it has experienced an
actual operating reserve shortage or emergency. Therefore, they suggest
that the Commission define the conditions when elimination of deviation
charges would take place.\147\ NIPSCO states that the Commission should
clarify that deviation charges should also be waived when an RTO or ISO
declares a NERC Energy Emergency Alert.\148\ The Pennsylvania PUC
states that there are two types of emergencies, generation
insufficiency and generation excess, and while generation insufficiency
is of greatest concern to the public, excess generation emergencies are
not uncommon. At such times locational marginal price or LMP may go
negative in an effort to resolve a rapidly dropping load situation. For
such reasons the Pennsylvania PUC asks that the Commission clarify
whether eliminating a deviation charge is appropriate for both kinds of
emergencies.\149\
---------------------------------------------------------------------------
\146\ NYISO at 7-8.
\147\ E.g., DRAM at 18-19; Comverge at 17-18; and NIPSCO at 12-
14.
\148\ NIPSCO at 12-14. The NERC reliability standard provides
procedures that RTOs and ISOs must follow when capacity emergencies
are declared and requires that all resources be used to meet load
before operating reserves are tapped to address an emergency.
\149\ Pennsylvania PUC at 11.
---------------------------------------------------------------------------
107. Additionally, some commenters recommend that the proposal
should be expanded so that deviation charges would be eliminated not
just in emergency situations, but in all situations when demand
deviates from schedule by using less energy.\150\ Duke urges the
Commission to eliminate deviation charges so long as the load remains
within an appropriate demand response ``bandwidth.'' \151\ No deviation
charges would be assessed in emergency or non-emergency situations, so
long as the load behaves consistently with the price-sensitive demand
schedule provided to the RTO or ISO. Other commenters suggest that the
proposal be expanded to include other contractual arrangements,\152\
demand-reduction services,\153\ and programs that compensate market
participants for demand reductions during system emergencies.\154\
---------------------------------------------------------------------------
\150\ E.g., California PUC at 15-16; Industrial Consumers at 15-
16 and Steel Manufacturers at 11-12.
\151\ Duke suggests that a reasonable solution to preventing
inequitable cost shifts is to establish a bandwidth that would
determine whether deviation charges should apply. Duke at 5-7.
\152\ NCPA states that the Commission's proposal to allow RTOs
and ISOs to waive deviation charges should be expanded to include
other contractual arrangements to the degree that ARCs are permitted
to perform aggregations of retail load. NCPA at 5-6.
\153\ OMS recommends that the Commission direct RTOs and ISOs to
explore the development of programs that compensate market
participants for demand reductions during system emergencies. OMS at
3.
\154\ Id. at 3. Similarly, EEI asks the Commission to allow RTOs
and ISOs to propose compensation sufficient to encourage demand
response resources to incur the cost of reducing consumption. EEI at
14-15.
---------------------------------------------------------------------------
108. Several commenters support a regional approach to establishing
methods for dealing with deviation charges. For example, ISO/RTO
Council urges the Commission to allow each RTO or ISO to develop its
own appropriate rules to implement the proposal to account for regional
operating considerations and to establish appropriate details,
including defining what system conditions constitute an emergency.\155\
California Munis urges regional flexibility to ensure that specific
facts pertaining to each RTO or ISO can be fully considered in
assessing whether this proposal will be beneficial to consumers or
merely shifts costs among consumers.\156\ Similarly, SoCal Edison-SDG&E
state that, rather than having the Commission eliminate deviation
charges in a uniform manner for all RTOs and ISOs, a method for dealing
with deviations from the day-ahead energy market purchases must be
considered comprehensively by each RTO or ISO within the framework of
its overall market design.\157\
---------------------------------------------------------------------------
\155\ ISO/RTO Council at 6-8.
\156\ California Munis is not opposed to the Commission's
proposal, but states that there are California-specific issues that
must be considered, which may lead to a policy conclusion that
elimination of deviation charge may not be appropriate for
California. California Munis at 11-12.
\157\ SoCal Edison-SDG&E state that eliminating charges in a
uniform manner to all demand does not recognize the locational
benefits of reducing demand in certain areas or cases where
decreasing demand could hinder efforts to address grid reliability
concerns. SoCal Edison-SDG&E at 3.
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109. NEPOOL Participants states that the Commission should not
impose its proposal on RTOs and ISOs before allowing NEPOOL
Participants to evaluate, through its stakeholder process, issues
around how deviation charges are calculated and assessed, including ISO
New England's ability to separate out the types of deviation charges
that the Commission has proposed.\158\
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\158\ NEPOOL Participants at 14.
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110. Constellation opposes this proposal, stating that eliminating
[[Page 64114]]
deviation charges during system emergencies could create unintended
consequences. Constellation believes that the proposal provides
preferential treatment for energy providers that supply load reductions
over generators that supply a similar product. Constellation argues
that deviation charges are appropriate because such charges provide:
(1) an incentive for LSEs to accurately forecast and bid their load
into the day-ahead market; and (2) a source of funds to compensate out-
of-market generators that are necessary to meet peak load when the
real-time load deviates from its day-ahead load bid.\159\ In addition,
Constellation states that opportunities for the demand side of the
market to respond are lost whenever supply resources are compensated
outside of market-clearing prices through the use of uplift charges. It
believes this problem can be alleviated through proper price
formation.\160\ For these reasons, Constellation recommends that the
Commission leave the deviation charge in place and institute a shortage
pricing regime, and address other issues that socialize out-of-market
costs in order to minimize socialized uplift charges.\161\
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\159\ Constellation at 6.
\160\ Id. at 7.
\161\ Id. at 6-7.
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ii. Commission Determination
111. The Commission adopts the NOPR proposal to require all RTOs
and ISOs to modify their tariffs to eliminate a deviation charge to a
buyer in the energy market for taking less electric energy in the real-
time market than was scheduled in the day-ahead market 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. This requirement does not apply to
RTO or ISO wholesale demand response program participants, but rather
to market buyers who voluntarily provide additional demand response
either during or prior to an RTO- or ISO-directed operating reserve
shortage in an effort to improve system reliability.
112. Removal of the deviation charge during a system emergency will
eliminate a disincentive for participation of demand response in the
real-time market. A buyer may be deterred from reducing demand during
periods of reserve shortage if that buyer is subject to a charge for
reducing its real-time consumption below its day-ahead purchases at the
request of the RTO or ISO market operator. This unintended disincentive
may result in the buyer maintaining a higher level of demand or
discourage an LSE from calling on the demand response resources in its
retail market. Removal of this disincentive will help maintain system
reliability and help reduce prices during system emergencies.
113. Demand response program participants currently are not levied
a deviation charge if they reduce demand as directed by the RTO or ISO,
and the Commission's requirement in this Final Rule does not alter this
practice. In addition, the Commission is not requiring that RTOs and
ISOs remove penalties for day-ahead bidders of demand response that
fail to follow dispatch instructions to reduce demand in real time.
What this requirement does focus on is demand response that is provided
by LSEs and other market buyers that consume less total energy in real
time during system emergencies or at the request of the RTO or ISO than
they had scheduled in the day-ahead market. The intent of the
Commission's requirement is not only to ensure that market buyers who
voluntarily reduce their energy consumption during system emergencies
at the request of the RTO or ISO are not penalized for their deviation,
but also that demand-side and supply-side resources are treated
comparably.
114. As noted above, a majority of commenters support this
requirement and agree that removal of these deviation charges would
remove a disincentive for demand reduction. Elimination of deviation
charges for a buyer's response to RTO and ISO calls for demand
reductions also will further comparable treatment of demand and supply
resources. RTO and ISO tariffs already do not impose deviation charges
on generators that generate more power during system emergencies than
scheduled in the day-ahead market.
115. An RTO or ISO must either propose amendments to its tariff to
comply with this requirement or demonstrate in a compliance filing that
its existing tariff and market design already satisfy this requirement.
This compliance filing must be filed with the Commission within six
months of the date that this Final Rule is published in the Federal
Register . The Commission will assess each filing to determine if it
satisfies the requirements of this section and will issue additional
orders, as needed. This process addresses comments by RTO/ISO Council,
California Munis, SoCalEdison-SDG&E, NEPOOL Participants and others
recommending regional flexibility in addressing this issue.
116. The Commission encourages each RTO and ISO to work with its
customers and other stakeholders in making tariff revisions and other
changes to its market design necessary to comply with this requirement.
The Commission's goal is to remove barriers to the development and use
of demand response resources in wholesale energy markets, and the
Commission expects that barriers can be effectively removed if each RTO
and ISO works effectively and cooperatively with its customers and
stakeholders.
117. Although the majority of commenters express support for this
requirement, as noted above, a significant number ask for clarification
or suggest changes to the NOPR proposal. Customer demand reduction in
response to an emergency appeal benefits all customers, by averting or
reducing the severity of a power shortage, so voluntary reductions
during system emergencies can provide system-wide benefits. They can
help maintain system reliability and reduce overall energy prices,
which benefits all customers. As a result, the Commission finds that
socialization of these costs is justified. However, in response to
comments by NIPSCO and Old Dominion that the deviation charge should be
allocated locally rather than on a system wide basis, this matter is
best addressed in each RTO's or ISO's compliance filing. Any proposal
for local allocation of these costs should be accompanied by an
explanation of when costs would be spread across the entire RTO or ISO
region and when applied locally, how the local area would be
determined, and why local cost recovery is justified. Further, in
response to comments by EEI and NIPSCO, we clarify that deviation
charges would be eliminated only when the RTO or ISO announces an
emergency situation or requests a voluntary load reduction after the
close of the day-ahead market.
118. In response to TAPS's request for clarification on what forms
of demand response this requirement would apply to, we note that this
requirement applies to all buyers in the wholesale energy market,
outside of an RTO's or ISO's demand response program, that may respond
to an RTO or ISO request for voluntary load reduction during a system
emergency. In response to comments by Cogeneration Parties and Midwest
Energy state that the costs and benefits of load reduction must be
verified before costs are imposed on customers, measurement and
verification protocols should be addressed within the RTO's or ISO's
compliance filing, and therefore will not require a net benefits test.
In order to accommodate regional differences, we will also defer
NYISO's request that the
[[Page 64115]]
Commission specify more clearly the definition of ``deviation charge''
to the compliance filing process (which will permit stakeholder input).
119. The Pennsylvania PUC asked for clarification of whether it is
appropriate to eliminate deviation charges during periods of excess
generation, when RTOs and ISO might call upon generators to reduce
supply. The Commission notes that the intent of this Final Rule is to
remove disincentives to demand-side resources so that they can be
treated similarly and comparably in relation to supply-side resources.
While it may be appropriate to remove deviation charges for supply-side
resources during periods of excess generation, issues involving periods
of excess generation are not addressed in this rulemaking.
120. We disagree with comments by the California PUC, Industrial
Consumers and Steel Manufacturers recommending that deviation charges
be eliminated any time demand deviates from schedule by using less
energy. As noted in the NOPR, a reduction in demand during a system
emergency benefits the RTO or ISO and its customers by better matching
demand with available supply.\162\ The Pennsylvania PUC mentions in its
comments that if actual demand deviates from scheduled demand during
non-emergency periods, such load reductions may result in periods of
excess supply and impose costs on the RTO or ISO and its customers.
Similarly, Duke's request that no deviation charges be assessed, so
long as load remains within a specified bandwidth, may lead to greater
disparity between day-ahead and real-time market purchases and could
result in additional costs to consumers without providing consumer
benefits. In particular, eliminating deviation charges for all periods
could result in over-scheduling, which has cost consequences for
generators. Therefore, the Commission does not accept these
recommendations.
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\162\ NOPR, FERC Stats. & Regs. ] 32,628 at P 77.
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121. With regard to Constellation's recommendation that the
Commission leave the deviation charge in place and institute a shortage
pricing regime to better match supply and demand, the Commission is
addressing shortage pricing issues in another part of this Final Rule.
As noted above, we find that elimination of deviation charges for
demand reduction during system emergency periods provides benefits to
consumers distinct from those inherent in a shortage pricing regime and
removes a disincentive to participation of demand-side resources by
treating demand and supply comparably. The Commission therefore
declines to adopt Constellation's recommendation.
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\
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\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.
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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\
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\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.
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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\
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\169\ Exelon at 6-8.
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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.
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\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.
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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\
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\173\ NEPOOL Participants at 13.
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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
[[Page 64116]]
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\
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\174\ NOPR, FERC Stats. & Regs. ] 32,628 at P 86.
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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\
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\175\ Id. P 88, 91.
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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.
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\176\ Id. P 92.
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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\
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\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.
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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\
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\181\ American Forest at 5-6.
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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\
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\182\ NCPA at 3-4.
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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
[[Page 64117]]
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\
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\183\ BP Energy at 16.
\184\ LPPC at 8.
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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\
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\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\
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\187\ SPP at 5-6.
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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.
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\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\
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\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
[[Page 64118]]
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
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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\
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\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\
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\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.
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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\
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\202\ Reliant at 6.
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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.
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\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.
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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.
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\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.
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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
[[Page 64119]]
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.
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\208\ EEI at 17.
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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\
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\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.
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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
[[Page 64120]]
relevant electric retail regulatory authority.\212\
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\212\ The RTO or ISO should not be in the position of
interpreting the laws or regulations of a relevant electric retail
regulatory authority.
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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.
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\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\
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\214\ NOPR, FERC Stats. & Regs. ] 62,628 at P 107.
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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
[[Page 64121]]
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\
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\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.
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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.
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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.
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\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\
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\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.
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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\
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\225\ PPL Parties at 5; First Energy at 11; and OMS at 6.
\226\ OMS at 6.
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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.
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\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.
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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
[[Page 64122]]
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\
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\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.
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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\
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\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.
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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.
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\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.
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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\
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\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.
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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\
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\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.
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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.
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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
[[Page 64123]]
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.
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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\
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\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\
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\263\ FTC at 29.
\264\ Industrial Consumers at 19.
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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.
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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
[[Page 64124]]
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
[[Page 64125]]
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
[[Page 64126]]
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
[[Page 64127]]
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.
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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.
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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.
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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.
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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.
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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
[[Page 64128]]
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.
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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\
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\311\ PJM Power Providers at 7.
\312\ Constellation at 13.
\313\ FirstEnergy at 11-12.
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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.
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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\
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\315\ Ohio PUC at 11.
\316\ Comverge at 22.
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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.
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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\
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\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\
---------------------------------------------------------------------------
\324\ EPSA at 10.
---------------------------------------------------------------------------
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
[[Page 64129]]
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.
---------------------------------------------------------------------------
\325\ Exelon at 11.
\326\ Id. at 12.>
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\327\ NRECA at 17.
\328\ TAPS at 37.
\329\ Id. at 39.
\330\ NRECA at 17; Steel Manufacturers at 13.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\331\ Comverge at 22.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\332\ Potomac Economics at 7.
---------------------------------------------------------------------------
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.
---------------------------------------------------------------------------
\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.
---------------------------------------------------------------------------
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
[[Page 64130]]
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.
---------------------------------------------------------------------------
\335\ NOPR, FERC Stats. & Regs. ] 32,628 at P 118.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\336\ Wal-Mart at 8.
\337\ EPSA at 8.
---------------------------------------------------------------------------
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\
---------------------------------------------------------------------------
\338\ Comverge at 23.
---------------------------------------------------------------------------
243. North Carolina Electric Membership states that if the
Commission adopts the proposed rule on price reform during shortage
periods, the Commission should adopt additional criteria to protect
consumers against the exercise of market power, similar to the minimum
protections included in the PJM shortage pricing settlement.\339\ It
suggests that the Commission should also require RTOs and ISOs to show
that any shortage pricing will: (1) Protect consumers in the most
vulnerable and smallest load pockets where access to available
resources is significantly constrained even in non-shortage conditions;
(2) define explicit triggers for when shortage prices will apply; (3)
ensure that the extra revenues received by generators will be included
in the energy and ancillary service revenue offset to capacity market
clearing prices paid in forward capacity markets; and (4) require that
RTOs and ISOs work with stakeholders to develop a program for setting
prices during a power shortage that is acceptable to all.\340\
---------------------------------------------------------------------------
\339\ North Carolina Electric Membership at 12-13.
\340\ Id. at 12.
---------------------------------------------------------------------------
244. Similarly, PG&E states that the proposed criteria should be
expanded to include the following: (1) A demonstration that any
proposed market rule changes are cost effective, including an
evaluation of the impact on reliability and an estimation of the cost
of the program; (2) an evaluation that the operating reserve shortage
pricing mechanism is adequately coordinated with other key market
mechanisms; and (3) an assessment of the readiness of demand response
programs that will be called upon to reduce the number and severity of
shortage pricing events and help mitigate market power.\341\
---------------------------------------------------------------------------
\341\ PG&E at 13.
---------------------------------------------------------------------------
245. TAPS asserts that the Commission needs to strengthen the
factual showing that RTOs and ISOs must make with respect to shortage
pricing reforms. It states that each RTO's or ISO's compliance filing
should include the following: (1) Market power analysis specifically
addressing scarcity conditions, including pivotal supplier, market
share, and the delivered price test; (2) an analysis of whether demand
response successfully mitigates market power, including empirical
evidence, such as critical loss analyses; (3) market power analyses
addressing the ability of generation owners to withhold demand
response; (4) a demonstration that the RTO has methods for mitigating
market power that are effective during shortage periods, for any
resources, demand or generation, that can affect prices; (5) an
analysis of whether there is enough demand response available to
respond under scarcity conditions, given reliance on demand response
for capacity reserves and ancillary services; and (6) prepared
statistics on past power shortages and expectations of future power
shortages.
ii. Commission Determination
246. In this Final Rule, the Commission adopts the proposal to
require each RTO or ISO to support its proposed reform in shortage
pricing or its demonstration of the adequacy of its existing rules with
adequate factual support. This factual record will allow the Commission
to discharge its duty to ensure that any reform is necessary and
narrowly tailored to address the circumstances in that region, and that
it is designed to protect consumers against the exercise of market
power. The Commission here adopts the six criteria proposed in the
NOPR, as modified below, and will use these six criteria to consider
whether the factual record compiled by the RTO or ISO meets the
requirements adopted in this Final Rule.
247. After further review of the criteria identified in the NOPR,
we revise the criteria. The RTO or ISO must describe how its 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 to
continue to be relied upon during an operating reserve shortage;
Encourage entry of new generation and demand resources;
Ensure that the principle of comparability in treatment of
and compensation to all resources is not discarded during periods of
operating reserve shortage; and
[[Page 64131]]
Ensure market power is mitigated and gaming behavior is
deterred during periods of operating reserve shortages including, but
not limited to, showing how demand resources discipline bidding
behavior to competitive levels.
248. The criteria we adopt are not significantly different from the
criteria proposed in the NOPR. Our intention in revising the criteria
is to further clarify what we expect from an RTO's or ISO's compliance
filing.\342\ Under the revised criteria, we expect an RTO or ISO to
explain how its market rules will reduce or avoid periods of operating
reserve shortages as well as how its market rules will reliably reduce
demand and increase generation during periods of operating reserve
shortage. Nothing in this Final Rule dictates the particular market
rules or mechanisms an RTO or ISO must adopt. For example, we do not
require regions that have not adopted a capacity market to develop such
markets. We are intentionally providing latitude to the RTOs and ISOs
to work with their stakeholders to determine the appropriate mechanisms
for their regions and then explain how those mechanisms meet the
revised criteria.
---------------------------------------------------------------------------
\342\ For example, the third criterion in the NOPR sought an
explanation of how the market rules encourage existing generation
and demand resources needed during an operating reserve shortage to
``remain in business.'' Upon review, the Commission is concerned
that this could have been read to require shortage pricing
provisions that would subsidize or give preferences to resources to
ensure they ``remain in business.'' Instead, our intention is for
the RTO or ISO to explain how its shortage pricing proposal,
together with existing market rules,encourages existing generation
and demand resources to be available in an emergency. Similarly, the
fifth criterion in the NOPR could have been read to limit comparable
treatment and compensation for all resources to periods of operating
reserve shortage. Because neither of these implications was our
intention, we clarify the wording of these criteria.
---------------------------------------------------------------------------
249. Some commenters propose expanding or modifying the criteria.
However, we conclude that the following suggestions are already either
explicitly part of the required filing or are implicitly required. For
example, North Carolina Electric Membership suggests a specific
criterion that the Commission should adopt to protect consumers against
the exercise of market power. Such a requirement, however, is already
implicit in the required analysis of market power mitigation adopted
here. Requiring that energy and ancillary services revenues be
accounted for in the settlement of capacity market payments also is
already an explicit requirement for existing capacity markets. Further,
all RTOs and ISOs have established procedures by which market rule
changes are developed, which generally include consultations with their
stakeholders. We expect that RTOs and ISOs will work with their
stakeholders to develop any new proposed rules and decline to make this
an explicit criterion.
250. Similarly, the changes requested by PG&E are already addressed
in the six criteria, as modified above. We note that an explicit
requirement to evaluate the effect of a rule change on reliability is
not needed. We are firmly of the opinion that the changes mandated in
this Final Rule will increase system reliability by inducing additional
response by demand- and supply-side resources and that RTO and ISO
compliance will not result in a decrease in reliability. Second,
requiring an explicit accounting of the costs of the program will not
be included. We do not see the usefulness of this exercise. While there
will be costs involved, the long-term benefits of maintaining grid
reliability are evident.
251. As to when these pricing rules would go into effect, it is
when the RTO or ISO has an operating reserve shortage. The reliability
standards of the North American Electric Reliability Corporation, which
have been approved by the Commission, or of other authorized
reliability body, specify system operating reserve requirements, and
these standards are well known to system operators such as RTOs and
ISOs, as well as to the many stakeholders who helped develop them. The
level of operating reserves required by the reliability standards
depends on the characteristics of each system and cannot be correctly
reduced to a single number that applies to every system, such as seven
percent of peak load. Further, if we were to repeat the reliability
standard definition here in our regulations, it would be cumbersome for
reliability organizations to improve their definition of operating
reserve requirements over time without also having to seek a change in
our regulations. We find that this is the best definition of when these
price reforms apply; we do not adopt a second, different definition,
here, because having two definitions of operating reserve shortage
would only cause confusion for system operators.
252. We decline to accept all other suggested criteria because they
would represent a level of burden to the RTO or ISO that would exceed
the benefit of doing the analysis.
253. We find that the criteria proposed in the NOPR, as modified
above, are sufficient to show whether a region's proposed changes to
its existing market rules meet the requirements of this rule, while
protecting consumers from market power.
d. Phase-In of New Rules
254. In the NOPR, the Commission stated that each RTO or ISO may
also consider a ``phase-in'' of its specific emergency pricing method
over a period of years, giving three years as an example. This would
serve to introduce customers gradually to pricing increases during an
emergency and allow them to develop ways to reduce demand and avoid
higher prices.\343\
---------------------------------------------------------------------------
\343\ NOPR, FERC Stats. & Regs. ] 32,628 at P 128.
---------------------------------------------------------------------------
i. Comments
255. Duke Energy states that while it prefers that any shortage
pricing program start immediately, if a phase-in is deemed worthwhile,
this phase-in should not be indefinite.\344\ EEI also states that these
rule changes may best be implemented through a phase-in, provided that
it is not protracted.\345\ It also notes that it is appropriate for the
Commission to allow such a phase-in to be linked to key factors such as
the deployment of advanced metering. Old Dominion supports a phase-in
of emergency pricing.
---------------------------------------------------------------------------
\344\ Duke Energy at 11.
\345\ EEI at 20.
---------------------------------------------------------------------------
256. FirstEnergy supports the Commission's proposed phase-in
approach because it can allow the Market Monitor to evaluate the market
reform, mindful of any unintended consequences including the exercise
of market power and gaming.\346\
---------------------------------------------------------------------------
\346\ FirstEnergy at 12.
---------------------------------------------------------------------------
257. Industrial Consumers recommends that the Commission require a
phase-in period of at least three to five years, together with
benchmarks that measure the ability of specific market factors to
protect consumers from the exercise of market power at the time of
shortages. It urges that the shortage price levels only be allowed to
increase in conjunction with and proportional to four benchmarks: (1)
Measured and verified amount of new net incremental demand response
resources entering the market; (2) net incremental reductions in
congestion, whether through enhancement of generation or transmission
resources, in the zones where such shortage pricing is implemented; (3)
sustained increases in the volume of load hedged in long-term forward
markets; and (4) development of credible forward price curves of power
delivered at RTO and ISO hubs published in support of the third
benchmark that are regularly relied upon by market participants.\347\
---------------------------------------------------------------------------
\347\ Industrial Consumers at 19.
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[[Page 64132]]
ii. Commission Determination
258. The Commission will allow an RTO or ISO to phase in any new
pricing rules for a period of a few years, provided that this period is
not protracted. Any phase-in period must be justified as part of the
RTO's or ISO's overall proposal to change its pricing rules. No RTO or
ISO is required to use a phase-in period, and we will not adopt by rule
a requirement that any such phase-in be tied to certain benchmarks as
Industrial Consumers and EEI propose. However, an RTO or ISO in
consultation with its stakeholders, may propose to tie the phase-in
period to certain benchmarks, and we will consider these in the
compliance filing. We caution, however, that it should not choose to
tie implementation to benchmarks that will not be met over a few years.
This would not be consistent with our requirement that the phase-in
period must not be protracted.
6. Reporting on Remaining Barriers to Comparable Treatment of Demand
Response Resources
259. In the NOPR, the Commission recognized that further reforms
may be necessary to eliminate barriers to demand response in the
future. The Commission did not wish to delay the adoption of the
specific reforms proposed in the NOPR while the Commission and the
industry continue to study and consider other advances in this area.
Rather, the proposed reforms were to proceed while the Commission and
stakeholders studied what additional efforts were necessary and
developed a record to support further reform.
260. The Commission directed staff to hold a technical conference
to consider the following issues for demand response participation in
the wholesale markets: (1) Whether there are barriers to comparable
treatment of demand response that have not previously been identified,
and what they are; (2) potential solutions to eliminate any potential
barriers to comparable treatment of demand response; (3) appropriate
compensation for demand response; and (4) the need for and the ability
to standardize terms, practices, rules and procedures associated with
demand response, among other things.\348\
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\348\ NOPR. FERC Stats. & Regs. ] 32,628 at P 95. The technical
conference was held on May 21, 2008. See infra note 12.
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261. In the NOPR, the Commission also proposed to require each RTO
and ISO to assess and report on the barriers to comparable treatment of
demand response resources that are within the Commission's
jurisdiction, including those listed above. The RTOs and ISOs would be
required to submit their findings and any proposed solutions, along
with a timeline for implementation to address barriers, to the
Commission within six months of the Final Rule's publication in the
Federal Register. The Commission also proposed to require the
Independent Market Monitor for each RTO or ISO to provide its views on
this issue to the Commission. To ensure that minority views are
adequately represented, the Commission proposed to require that the RTO
or ISO identify any significant minority views in its filing.
262. The Commission sought comment on the proposed approach to
identify and assess remaining barriers to comparable treatment of
demand response as well as any particular issues or areas that should
be addressed in the RTO and ISO reports.
a. Comments
263. A number of commenters indicate their support for the
Commission's intention to continue to address barriers to demand
response resources, and/or the Commission's proposal to require each
RTO and ISO to report on the barriers they currently perceive.\349\
Some offer suggestions for how the Commission should proceed toward
this goal.
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\349\ E.g., Exelon at 9; Pennsylvania PUC at 12; PG&E at 11;
Public Interest Organizations at 8; Reliant at 6; and Steel
Producers at 6.
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264. For example, APPA cautions the Commission, as it seeks to
remove barriers to demand response resources, not to unintentionally
endanger existing and planned demand response and energy efficiency
programs at the retail level.\350\ EnerNOC is encouraged by the
Commission's objective to continue its oversight, to review and approve
implementation of reforms for demand response programs and to consider
future reforms.\351\ However, it believes the Commission's continued
involvement and active engagement may be necessary to eliminate
barriers to demand response resources.
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\350\ APPA at 51.
\351\ EnerNOC at 22.
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265. EEI agrees that the Commission should not delay the adoption
of specific reforms for demand response while the Commission and
industry stakeholders evaluate additional reforms in this area.
However, EEI suggests that the Commission provide additional
specification of the parameters of these studies, suggesting that the
Commission clarify that such studies should not ignore existing work
and should be conducted in a cost-effective manner. EEI also urges the
Commission to have RTOs and ISOs study whether demand response is cost-
effective and to quantify benefits.\352\
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\352\ EEI at 18.
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266. Regional entities report that they are already engaged in some
of the issues the Commission described. With regard to future demand
response reforms, the ISO/RTO Council says that it is working to
develop standards for incorporating small demand response resources
into organized markets, and that it is actively engaged with NAESB to
standardize measurement and verification protocols.\353\ These efforts,
in combination with the Commission's technical conference, in which the
ISO/RTO Council participated, should benefit future discussions on
barriers, pricing, and standardization. The ISO/RTO Council looks
forward to sharing the results of its standardization initiative.
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\353\ ISO/RTO Council at 8.
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267. Midwest ISO supports the Commission's approach to identifying
additional demand response barriers and solutions, and states that many
issues regarding barriers and solutions to demand response resources
are already being addressed as part of the Midwest ISO's ongoing
emergency demand response and long-term resource adequacy
proceedings.\354\ Through the rest of 2008, the Midwest ISO's Demand
Response Working Group will facilitate many activities to further
identify measures to advance demand response resources.
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\354\ Midwest ISO at 14-15.
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268. NYISO agrees that this Final Rule should not mark the end of
the Commission's efforts in the demand response area and that further
improvements and additional enhancements should be explored. NYISO has
no objection to preparing the post-Final Rule report that the NOPR
proposes.\355\
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\355\ NYISO at 3.
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269. SPP notes that it is currently studying what further reforms
are necessary to eliminate barriers to demand response in its organized
markets. This process is done through its working groups and task
forces as well as participating in groups such as the ISO/RTO
Council.\356\
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\356\ SPP at 6.
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270. The California PUC believes that two important areas that
could be improved are the evaluation of the cost-effectiveness of
demand response and how it impacts load. The California PUC is working
with stakeholders on both of these issues. The California PUC would
[[Page 64133]]
also like to see more effective load-shifting and the technology that
allows for that to be encouraged to a greater degree.\357\
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\357\ California PUC at 20.
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271. Old Dominion supports the Commission's proposal to continue
discussions on demand response through RTO and ISO studies and suggests
that RTOs and ISOs be required to identify all minority views and not
just ``significant minority views'' as currently required by the NOPR.
Old Dominion sees lack of telemetry, high implementation costs,
institutional barriers related to cost recovery, insufficiently
detailed business rules, and demand response gaming as impediments to
demand response that should be discussed further.\358\
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\358\ Old Dominion at 16-19.
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272. Old Dominion also suggests that each RTO and ISO should be
directed to work with its stakeholders to develop by a specific date a
prioritized list of barriers to demand response and a timeline for
developing solutions to the same; that demand response should be
considered in the transmission planning process in accordance with
engineering-based transmission planning principles; and that
implementation of demand response should be evolutionary in accordance
with the sufficiency and certainty of business rules and availability
of necessary measurement and verification infrastructure. Similarly,
California DWR asks the Commission to require RTOs and ISOs to provide
a listing of barriers identified by market participants, state or local
regulators, the RTO or ISO market monitor, and the RTO or ISO itself;
further, the RTOs and ISOs would provide information on their response
to each barrier and let the Commission know if additional action is
needed.\359\
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\359\ California DWR at 37.
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273. Public Interest Organizations recommend that the Commission
schedule a technical conference in each region to address both general
and region-specific barriers.\360\ Public Interest Organizations also
recommend that RTOs and ISOs be required to: (1) Assess the potential
of other demand-side resources in their control areas, including demand
response, energy efficiency, and environmentally benign and efficient
behind-the-meter distributed generation; (2) analyze and quantify all
local and regional benefits as well as costs and risks of demand side
resources available to address grid needs; and (3) assess and report on
the longer-term impacts of demand resource participation on wholesale
price levels and volatility, grid congestion, and system reliability.
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\360\ Public Interest Organizations at 8.
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b. Commission Determination
274. The Commission adopts the requirement that each RTO or ISO
assess and report on any remaining barriers to comparable treatment of
demand response resources that are within the Commission's jurisdiction
and to submit its findings and any proposed solutions, along with a
timeline for implementation, to the Commission within six months of the
Final Rule's publication in the Federal Register. We further adopt the
requirement that each RTO's or ISO's Independent Market Monitor must
submit a report describing its views on these issues to the Commission.
To ensure that minority views are adequately represented, the
Commission requires that the RTO or ISO, in its report, identify any
significant minority views; this does not, however, require reporting
every opinion of every individual stakeholder.
275. The Commission appreciates the many thoughtful comments
received in response to this proposal. RTOs and ISOs have a duty to
remove unreasonable barriers to treating demand response resources
comparably with other resources and the required report will help RTOs,
ISOs, and the Commission to identify and address such barriers. The
report should identify all known barriers, and provide an in-depth
analysis of those that are practical to analyze in the compliance time
frame given and a time frame for analyzing the remainder. As commenters
have noted, this should include (but is not limited to) technical
requirements as well as performance verification limitations. It need
not contain, however, a formal cost-benefit analysis of each barrier
and a proposal to overcome it. Public Interest Organizations suggest
that RTOs and ISOs might hold regional conferences on this topic, and
while we agree this may have merit, we leave to each region the means
of developing its report.
276. Energy efficiency and distributed generation are valuable
resources, as commenters point out; however, the scope of this rule is
limited to removing barriers to comparable treatment of demandresponse
resources in the organized markets. Hence, we will not require RTOs and
ISOs to study these resources in the report we require. Nevertheless,
nothing here precludes RTOs and ISOs from analyzing barriers to energy
efficiency measures and distributed generation in their markets and
proposing revisions to their tariffs that integrate these measures into
their markets.
B. Long-Term Power Contracting in Organized Markets
277. In this section of the Final Rule, the Commission establishes
a requirement that RTOs and ISOs dedicate a portion of their Web sites
for market participants to post offers to buy or sell electric energy
on a long-term basis. This requirement is designed to improve
transparency in the contracting process to encourage long-term
contracting for electric power. The Commission requires each RTO or ISO
to submit a compliance filing describing actions the RTO or ISO has
taken, or plans to take, to comply with the requirement and providing
information on the bulletin board the RTO or ISO has chosen to
implement.
1. Background
278. Long-term power contracts are an important element of a
functioning electric power market. Forward power contracting allows
buyers and sellers to hedge against the risk that prices may fluctuate
in the future. Both buyers and sellers should be able to create
portfolios of short-, intermediate-, and long-term power supplies to
manage risk and meet customer demand. Long-term contracts can also
improve price stability, mitigate the risk of market power abuse, and
provide a platform for investment in new generation and transmission.
279. As the Commission noted in the NOPR, having an organized
market in a region should facilitate long-term contracting by
eliminating pancaked rates for long-distance power sales, eliminating
loop flow problems within its footprint, and ensuring reliable
transmission operation over a large area.\361\ RTO and ISO transmission
services also expand the size of the markets available to buyers and
sellers of long-term power contracts, and provide independent and
unified transmission scheduling and operation services over a large
area.
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\361\ NOPR, FERC Stats. & Regs. ] 32,628 at P 130.
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280. The Commission has already taken action in other areas to
facilitate long-term contracting. In Order No. 681, the Commission
adopted a Final Rule on long-term transmission rights for organized
market regions designed to assure availability of long-term
transmission at a predictable cost.\362\ The Commission then adopted
transmission planning reforms in Order
[[Page 64134]]
No. 890 to provide an open and transparent process for wholesale
entities and transmission providers to plan for the long-term needs of
their customers. Interconnection rules for large, small and wind
generators in Order Nos. 2003, 2006 and 661 have provided a uniform and
transparent interconnection process and provided for interconnection
with network integration service to facilitate long-term reliance on
new generation.\363\ The Commission has also reformed capacity markets
in several regions to shift reliance from short-term purchases to
forward markets held sufficiently in advance of delivery (e.g., three
years) to be more consistent with the time necessary to construct new
generation.\364\
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\362\ Long-Term Firm Transmission Rights in Organized
Electricity Markets, Order No. 681, FERC Stats. & Regs. ] 31,226
(2006), order on reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006).
\363\ Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (DC Cir. 2007); Standardization of
Small Generator Interconnection Agreements and Procedures, Order No.
2006, FERC Stats. & Regs. ] 31,180, order on reh'g, Order No. 2006-
A, FERC Stats. & Regs. ] 31,196 (2005), order granting
clarification, Order No. 2006-B, FERC Stats. & Regs. ] 31,221
(2006), appeal pending sub nom. Consolidated Edison Co. of New York,
Inc., et al. v. FERC Docket No. 06-1018, et al.; Interconnection for
Wind Energy, Order No. 661, FERC Stats. & Regs. ] 31,186, order on
reh'g, Order No. 661-A, FERC Stats. & Regs. ] 31,198 (2005).
\364\ Devon Power, LLC, 115 FERC ] 61,340, order on reh'g, 117
FERC ] 61,133 (2006), aff'd in part and rev'd in part sub nom. Maine
Pub. Utils. Comm'n v. FERC, 520 F.3d 464 (DC 2008); PJM
Interconnection, LLC, 117 FERC ] 61,331 (2006).
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281. The Commission did not find that there is a fundamental
problem with long-term contracting for electric power, either inside or
outside of organized markets. The interest among buyers and sellers in
engaging in long-term contracting fluctuates depending upon the balance
of resources and demand in the market for power. Interest among buyers
for long-term arrangements was low when excess generation was readily
available. Although demand for long-term contracting by buyers has
increased as reserve margins have shrunk, buyers are still able to
enter into long-term contracts. These contracts may be at higher prices
than in the past, but this is a result of market factors, such as
changes in fuel prices and shifting supply and demand. Finding no
fundamental problem preventing parties from contracting on a long-term
basis, the Commission proposed to limit its action in this proceeding
to improving transparency in long-term contracting in organized
markets.
282. In the NOPR, the Commission stated that further transparency
in long-term electric energy markets would facilitate efforts by both
sellers and buyers to include long-term contracts in their energy
portfolios. This is especially true for market participants that may
not be aware of the full range of contract options available to them,
including the full range of potential contract counterparties. While
the market has the most important role to play in disseminating
information, an RTO or ISO can also promote greater transparency and
liquidity in long-term power markets,\365\ and thus help reduce
possible over-reliance on spot markets. In the NOPR, the Commission
proposed that regional organizations play a supporting role in
encouraging voluntary contracting by providing an online forum in which
potential buyers and sellers may exchange information.\366\
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\365\ Transcript of Conference at 117, Conference on Competition
in Wholesale Power Markets, Docket No. AD07-7-000 (May 8, 2007).
\366\ NOPR, FERC Stats. & Regs. ] 32,628 at P 137.
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2. Commission Proposal
283. In the NOPR, the Commission proposed to require that RTOs and
ISOs dedicate a portion of their Web sites for market participants to
post offers to buy or sell electric energy on a long-term basis.\367\
The Commission stated that the proposal for an RTO or ISO Web site
``bulletin board'' for posting long-term offers to sell or buy electric
energy is designed to facilitate the long-term contracting process by
increasing the transparency of the availability of potential sellers
and buyers for market participants. The Commission did not propose to
mandate the specific type of bulletin board that each RTO and ISO must
post, but proposed to require each to work with its stakeholders to
design a solution that works for its market participants.\368\ The
Commission also encouraged RTOs and ISOs to work with stakeholders to
facilitate long-term power contracting.
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\367\ Id. P 155.
\368\ Id. P 156-57.
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284. The Commission proposed to require RTOs and ISOs to make a
compliance filing within six months of the date of publication of the
Final Rule in the Federal Register. This filing should explain the
actions the RTO or ISO has taken or plans to take to comply with the
long-term contracts bulletin board requirement and provide information
on the bulletin board the RTO or ISO has chosen to implement.\369\
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\369\ Id. P 158.
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285. The Commission also sought public comment on a number of
questions related to its proposal, including comment on minimum
necessary features and processes for the Web page and the proposal that
the RTO or ISO should not be responsible for the content of the offers
on its bulletin board. Further, the Commission solicited comment on
provisions for the disclaimer of liability by the RTO or ISO and by
market participants.\370\
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\370\ Id. P 159.
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3. Comments
286. A majority of commenters either support \371\ or do not object
\372\ to the Commission's proposal to require RTOs and ISOs to
implement bulletin boards to facilitate long-term power contracts. Most
commenters note that the Commission should not impose conditions on the
format of the bulletin board, but should instead leave the creation to
RTOs and ISOs in conjunction with their stakeholders.\373\ Some
commenters also state that the Commission should act to ensure that
RTOs or ISOs should not be held liable for postings on their bulletin
boards.\374\ For instance, NYISO states that the Commission should
allow posted disclaimers against liability by the RTOs on their
bulletin board Web sites. Midwest ISO also requests that the Commission
provide assurance that RTOs and ISOs will not be exposed to antitrust
liability for providing a contracting forum. Finally, commenters
generally believe that the cost of a bulletin board will be low for
RTOs and ISOs.\375\
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\371\ See, e.g., APPA at 72; DC Energy at 8; EEI at 4; Exelon at
15; LPPC at 4; Midwest ISO at 18; NEPOOL at 19-20; New York PSC at
4; NIPSCO at 15; NRECA at 47; NSTAR at 5; NYISO at 11; OMS at 7;
Pennsylvania PUC at 16; Steel Producers at 10; and Xcel at 11.
NIPSCO notes that its support is contingent on the bulletin boards
having common elements or generic features across all organized
markets, and the boards not burdening the RTO.
\372\ See, e.g., Ameren at 29-30; EPSA at 12; FirstEnergy at 12;
Indianapolis P&L at 4; Industrial Coalitions at 32-35; Industrial
Customers at 21; North Carolina Electric Membership at 13-15; Ohio
PUC at 16; Old Dominion at 19-20; OMS at 7-8; PJM at 2; and TAPS at
3.
\373\ See, e.g., Ameren at 30; APPA at 72; CAISO at 19; DC
Energy at 9; EEI at 20; EPSA at 12; Exelon at 15; NEPOOL
Participants at 19-20; North Carolina Electric Membership at 13-15;
NYISO at 12; Old Dominion at 19; PJM at 2; and Xcel at 11.
\374\ See, e.g., Ameren at 30; CAISO at 19; Exelon at 15;
Midwest ISO at 18; NRECA at 48; NYISO at 12; Ohio PUC at 16; Reliant
at 11; and SPP at 7.
\375\ See, e.g., Ameren at 30; CAISO at 19; EEI at 20; Midwest
ISO at 18; and PJM at 2.
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287. Those commenters who do not support the Commission's proposal
generally argue that a bulletin board would be an unnecessary
requirement. Both CAISO and California Munis state that CAISO is busy
with other projects, and that a bulletin board would be low
[[Page 64135]]
on the list of necessary items.\376\ CAISO is concerned over the
proposed deadline for implementation, and argues that any deadline
should be after the launch of its MRTU. It also believes that regions
should be allowed to be flexible on whether to develop bulletin boards
and how many features the board should have. California PUC agrees that
a federal requirement is unnecessary, and that the Commission should
authorize, rather than require, action on bulletin boards. SPP also
advocates that the Commission should make its proposal a voluntary one,
rather than a regulatory requirement. Some commenters, such as EPSA,
NIPSCO, Ohio PUC, Steel Producers and North Carolina Electric
Membership, who do not object to the proposal, indicate that they do
not believe that bulletin boards will have a significant effect on
long-term contracting. FirstEnergy indicates that, although it does not
object to the proposal, it believes that sufficient information on the
market is already provided by private companies and thus RTOs do not
need to be further involved. Reliant states that bulletin boards would
not resolve any of the current impediments to long-term contracts, as
there are already sufficient mechanisms in the market to provide
information for buyers and sellers.
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\376\ CAISO at 19; California Munis at 18.
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288. Commenters' suggestions for implementing the bulletin board
requirement include: (1) A requirement that posts should not be viewed
as binding offers but rather as voluntary postings; \377\ (2) a
suggestion that price information not be required in postings to the
bulletin board; \378\ (3) a requirement that any significant costs of
the bulletin board should be borne by its users; \379\ (4) an expansion
of the data posted to include percentage and volume of bilaterally
contracted energy; \380\ (5) an expansion of the bulletin board to
cover other products such as ancillary services; \381\ (6) a
requirement that RTOs and ISOs collect and disseminate information on
the usefulness of bulletin boards; \382\ (7) a requirement that
bulletin boards provide common elements or generic features across all
organized markets; and (8) a mandated cost analysis of the bulletin
board by the RTO/ISO.\383\
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\377\ Ameren at 30-31.
\378\ Xcel at 11-12.
\379\ CAISO at 18-20; EEI at 21.
\380\ Industrial Coalitions at 33-35.
\381\ NEPOOL Participants at 18-21.
\382\ Pennsylvania PUC at 16.
\383\ Old Dominion at 19-20.
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289. Midwest ISO states that it already has an early version of a
portal in place on its Web site, and that it would involve minimal
costs to create a bulletin board for long-term contracts. Midwest ISO
recommends that, as an intermediate measure prior to the implementation
of a web portal, contracting parties provide essential terms--including
price, quantity, term, and receipt and delivery points--to the RTO or
ISO and fill out a form indicating the data they wish to be kept
confidential.\384\
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\384\ Midwest ISO at 19.
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290. NEPOOL Participants raises some legal and other issues for the
Commission to consider when developing its bulletin board requirement.
These include: (1) Ensuring that postings are not considered binding
offers under the Uniform Commercial Code; (2) not allowing the board to
substitute for regulated markets; and (3) ensuring that the same
antitrust and market manipulation rules that apply to market behavior
also apply to activity on the bulletin board.\385\
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\385\ NEPOOL Participants at 20.
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291. NSTAR states that it is concerned that data from the bulletin
board containing prices for long-term power could influence market
prices. Accordingly, it asks the Commission to consider additional
requirements to ensure that information posted on the boards is from a
representative cross-section of market participants, to reduce the
impact of the bulletin board on market prices.\386\
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\386\ NSTAR at 5-6.
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292. Industrial Customers state that the Commission should define
``long-term'' as substantially more than one year and consistent with
building cycles of new or expanded production capacity. They argue that
any entity making construction decisions on new facilities needs
knowledge of prices going forward to make investment decisions.
293. Many commenters argue that the Commission did not address in
its proposed regulations the actual causes behind the lack of long-term
contracts in the market. Several commenters point to the structure of
markets within the RTO system, which they assert causes an over-
reliance on spot markets and a lack of long-term contracts. They say
this structure includes LMP pricing, which provides a disincentive for
producers to contract for lower prices on a long-term basis. For
instance, APPA points to studies including one performed by Synapse
Energy Economics, Inc., indicating that there are structural barriers
to long-term contracting in the organized markets. Other commenters
point to the need for stability of market rules and uncertainty about
climate change policies as key factors in keeping parties from
contracting on a long-term basis.\387\ Reliant indicates that the issue
is actually a difference in perceptions between buyers and sellers
about the appropriate price of energy and the allocation of risk
between the buyers and sellers. NRECA points to several other issues
that affect long-term contracting in organized markets, including price
volatility, price risk, delivery risk and resource availability. Ohio
PUC echoes some of these concerns, noting that risks with recovering
capital costs are preventing new generation from being built in states
with retail access, and that unpredictable congestion charges and
uncertainty surrounding the working of RTO markets are also hurting
long-term contracting.
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\387\ See, e.g., SoCal Edison-SDG&E at 4; EPSA at 11-12.
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294. Commenters suggest several actions that the Commission should
take to remedy these broader concerns. Commenters, including NRECA,
Industrial Coalitions and Blue Ridge, ask the Commission to do its own
investigation of the bilateral contracting process and over-reliance on
the spot markets. North Carolina Electric Membership notes that a
requirement of ``full support'' from stakeholders for more complex RTO
or ISO market design changes may increase the stability and
predictability to these markets, which may facilitate longer term
contracting. Constellation states that the Commission should promote
rules to encourage contracting across seams and take measures to
provide sufficient transparency, information and regulatory certainty
to manage transactional risk. Cogeneration Parties argue that the
Commission should take action to improve price transparency in
organized markets, and assist in the creation of standard products and
contracting terms for long-term contracting. SoCal Edison-SDG&E argue
that local measures to improve regulatory stability would do more to
support long-term contracting than a Commission rulemaking. They point
to the California PUC proceeding to develop long- term resource
adequacy requirements as one such local measure, and argue that the
Commission should focus on the merits of individual RTO or ISO
proposals rather than a nationwide rulemaking. Finally, TAPS notes that
an important way to facilitate long-term contracts is to ensure that
load-serving entities can access necessary transmission resources.
[[Page 64136]]
However, TAPS is concerned by recent orders indicating that the
Commission may relieve RTOs of certain responsibilities they have under
Order No. 681 \388\ to plan for resource adequacy and maintain
simultaneous feasibility of financial rights. It argues that if the
Commission is serious about facilitating long-term contracts, it should
require RTOs and ISOs to live up to the letter and spirit of Order No.
681.
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\388\ Long-Term Firm Transmission Rights in Organized
Electricity Markets, Order No. 681, FERC Stats. & Regs. ] 31,226
(2006), order on reh'g, Order No. 681-A, 117 FERC ] 61,201 (2006).
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295. Several commenters call on the Commission to hold a technical
conference and require a stakeholder process to address the lack of
certain financial hedging instruments so as to reduce price uncertainty
for long-term contracts. For instance, both California Munis and SMUD
argue that buyers in CAISO lack options-type instruments for hedging
LMP congestion costs and lack a means to hedge against the cost of
marginal losses. Providing these hedges, they argue, would encourage
long term contracting.
296. Commenters raise a variety of other issues related to long-
term contracting. Midwest Energy states that it is concerned about the
impact of a Day-2 market on long-term contracts, and appreciates that
the Commission is not imposing Day-2 market structures on all RTOs and
ISOs.
297. California PUC notes that it is presently addressing long-term
contracting within its procurement proceedings. For instance, under the
California PUC's Resource Adequacy program, all California PUC
jurisdictional LSEs are required to procure necessary capacity on a
year-ahead basis. Additionally, California PUC requires LSEs to
identify longer-term needs and procure energy necessary to meet those
needs through a request for offer process that includes both long and
short-term contracts. California PUC questions the Commission's legal
basis for intervening in long-term contracting, stating that the NOPR
does not explain the statutory authority for the Commission's proposed
involvement in long-term energy supply contracts between generators and
LSEs. It notes that FPA section 215 does not authorize the Commission
to set or enforce compliance with standards for resource adequacy, and
that EPAct 2005 ``expressly retains state authority to assure the
reliability of the energy supply within their jurisdictions.'' \389\ It
seeks assurance that the Commission does not intend to exercise
jurisdiction over the wholesale energy market as a method of indirectly
modifying California's reliability processes.
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\389\ California PUC at 28 (citing 16 U.S.C. 824o(i)).
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298. Both New York PSC and NARUC state that the Commission should
not attempt to standardize long-term contracts. NARUC argues that
standardization would hurt state policy objectives such as integrated
resource planning, renewable portfolio standards and resource adequacy
requirements. New York PSC notes that any standardized forward products
should be developed through the RTO or ISO stakeholder process.
299. PJM notes that it held a stakeholder forum in January 2008 to
discuss greater opportunities for long-term contracting in PJM. This
forum resulted in identification of areas for future action, which
included: (1) Education of policy makers and the public on the need for
new infrastructure; (2) improved coordination of various agency and
regulatory decision makers on market issues; (3) predictability and
stability in regulatory rules; (4) improvements in siting for
transmission and generation; (5) ways of steering revenue to increase
the amount of new generation; (6) more effective demand response
programs to increase market elasticity and reduce potential for
exercise of market power; (7) a portfolio of purchases to vary prices
and terms for state-sanctioned auctions; (8) further examination of
existing market models such as the AF&PA proposal; and (9) additional
credit support for parties interested in long- term contracting,
through methods such as syndication of credit risk and government
guarantees.\390\
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\390\ PJM at 3-4.
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300. Finally, APPA notes that although it appreciates the effort
that PJM put into holding its long-term contracting forums, APPA
understands that no concrete proposals for improving long-term
contracting have emerged as a result of the forums. Accordingly, APPA
cannot endorse the idea of similar efforts by other RTOs as suggested
by the Commission in the NOPR, given the scarce resources of RTOs and
market participants. Instead, APPA supports preparation of an in-depth
analysis of long-term contracting practices for each RTO region by the
RTO's MMU, given the MMU's knowledge of conditions ``on the ground.''
This analysis should consider impediments to long-term contracting and
measures that could be taken to support long-term contracts of
sufficient length to support the building of new generation.
4. Commission Determination
301. We will require each RTO and ISO to dedicate a portion of its
Web site for market participants to post offers to buy or sell power on
a long-term basis. The Commission defines ``long-term'' as one year or
more for the purposes of this rule, but RTOs and ISOs may include
offers for contracts of less than a year on their Web sites as well.
The Web site should allow both buyers and sellers to post and read
offers for long-term power transactions. A majority of commenters
support this proposal, and we conclude that greater transparency from a
bulletin board for long-term power sales will benefit long-term
contracting.
302. We are convinced by the comments that the costs involved for
creation and upkeep of the bulletin board are likely to be minimal and
are justified by the increased transparency for potential sellers and
buyers, and should thus be recovered similarly to other Web site costs.
A few commenters suggest that bulletin board costs should be borne by
its users. If an RTO or ISO in consultation with its stakeholders
believes that costs of the bulletin board will be significant, it may
explain in its compliance filing how it plans to recover the costs,
including whether it plans to charge users of the bulletin board.
303. The Commission is not mandating any specific form for the Web
site beyond the requirements above. We will instead leave the
implementation to RTOs and ISOs and their stakeholders. This discretion
includes decisions over the type and amount of data to be posted by
participants, whether participants must include a proposed price in
their posting, as well as password and security requirements.
Commenters who have specific suggestions about the form and content of
the Web site bulletin boards, or concerns over cost issues, should
raise these suggestions with their RTOs or ISOs through the stakeholder
process. The compliance filing of each RTO or ISO will provide an
opportunity for interested persons to comment to the Commission on each
RTO's and ISO's method of compliance, such as the legal and other
concerns raised by NEPOOL Participants and others. The Commission does
not find it necessary to make a generic determination about these
concerns.
304. The Commission agrees with commenters that RTOs and ISOs
should not be held liable for the postings of contracting parties.\391\
Significant
[[Page 64137]]
liability protection for message board operators is already provided
under federal law by the safe harbor provisions of the Communications
Decency Act.\392\ We anticipate that these provisions will apply to
RTOs and ISOs. Consistent with comments received, however, we encourage
RTOs and ISOs to post a disclaimer on their Web sites indicating that
they are not responsible for the content posted by users, and outlining
the terms and conditions under which users may post offers to buy or
sell under long-term agreements.
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\391\ The Commission does not see why having such a bulletin
board should necessarily expose an RTO or ISO to antitrust
liability, as suggested by Midwest ISO. However, the Commission
suggests that RTOs and ISOs explain any such concerns in their
compliance filings.
\392\ 47 U.S.C. 230(c)(1) (``No provider or user of an
interactive computer service shall be treated as the publisher or
speaker of any information provided by another information content
provider.''). See, e.g., Universal Commun. Sys. v. Lycos, Inc., 478
F.3d 413 (1st Cir. 2007) (dismissing a suit against a content
provider for liability for posts on a community message board based
on the safe harbor provisions of the Communications Decency Act).
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305. In response to comments from NSTAR, the Commission is not
persuaded to forego the advantages of posting long-term contract term
proposals just because an entity might attempt to use the bulletin
board inappropriately. Further, we see no reason to mandate in this
proceeding specific limits on types of posting on RTO or ISO Web sites.
However, any attempt by posters to use this new feature to manipulate
the market price or market price indices will be subject to Commission
penalty or referral to other agencies having jurisdiction.\393\
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\393\ See Price Discovery in Natural Gas and Electric Markets,
104 FERC ] 61,121, at P 38 (2003).
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306. In response to the concerns raised by California PUC, New York
PSC and NARUC, the Commission notes that it is not taking any action at
this time to standardize long-term contracts, nor does the Commission
intend this bulletin board posting requirement to be a reliability
standard, to set a resource adequacy requirement, or to infringe on
state regulatory jurisdiction.
307. We anticipate that this requirement will enhance transparency
and help foster long-term contracting without standardizing RTO and ISO
approaches or intruding unduly into matters more appropriate for
markets and the private sector. The comments provide strong support for
the bulletin board proposal, and do not persuade us that there is any
reason to delay implementation of this requirement, despite CAISO's
request that we postpone it until after MRTU is complete. Some of the
other requirements commenters propose would require more
standardization and set requirements that are better left to the free
market and to the private sector. We do not wish to delay or undermine
this process by imposing too many requirements. Therefore, the
Commission will not require in this rulemaking other actions related to
long-term contracting recommended by some commenters.
308. As discussed in the NOPR, many of the broader issues
commenters raise herein regarding the structure and functionality of
organized markets are beyond the scope of this proceeding and would
require further development to be ripe for inclusion in a
rulemaking.\394\ The Commission further explored many of the issues
during the recent technical conference held to discuss the proposals of
American Forest and Portland Cement Association, et al. \395\ The
Commission continues to review the information it received at the
technical conference for possible action.
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\394\ NOPR, FERC Stats. & Regs. ] 32,628 at P 153, 161.
\395\ Supplemental Notice of Technical Conference, Capacity
Markets in Regions with Organized Electric Markets, Docket No. AD08-
4-000 (April 25, 2008).
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309. RTOs and ISOs are required to make a compliance filing within
six months of the date of publication of this rule in the Federal
Register. The filing should explain the actions the RTO or ISO has
taken or plans to take to comply with the long-term contracts bulletin
board requirement and provide information on the bulletin board the RTO
or ISO has chosen to implement. The Commission appreciates concerns of
commenters that RTOs and ISOs, such as CAISO, have market reforms in
progress, and these entities may take into account the timetable of
reforms in progress when developing their compliance plans. We find
that the compliance period of six months is an adequate time to make
any necessary adjustments to planned reforms and explain them in the
compliance filings.
C. Market-Monitoring Policies
310. In this section of the Final Rule, the Commission makes
reforms to enhance the market monitoring function and thereby improve
the performance and transparency of organized RTO and ISO markets. The
two principal areas addressed are the independence and functions of the
MMU, and information sharing. The Final Rule requires tariff provisions
that will remove the MMU from the direct supervision of RTO or ISO
management, and requires, in most instances, that the MMU report
directly to the RTO or ISO board of directors.
311. The Final Rule also imposes obligations on the RTOs and ISOs
to provide the MMU with adequate tools with which to carry out its
duties. The Final Rule broadens the reporting duties of the MMU,
clarifies that it is to refer to Commission staff any instances of
misconduct by the RTO or ISO, as well as by a market participant, and
expands the MMU's referral obligations to include perceived market
design flaws as well as instances of tariff or rule violations.
312. In the area of mitigation, the Final Rule separates the duties
of internal and external MMUs in the case of RTOs and ISOs that employ
a hybrid structure, and provides that for non-hybrid MMUs, mitigation
by the MMU should center on retrospective mitigation and the
calculation of inputs required for the RTO or ISO to conduct
prospective mitigation. Given the critical nature of MMU duties, the
Final Rule requires RTOs and ISOs to include in their tariffs ethical
standards for their MMUs. The Final Rule also requires RTOs and ISOs to
consolidate all of their MMU provisions into one section of their
tariffs.
313. In the area of information sharing, the Final Rule expands the
category of recipients for the information gathered by the MMU, and
broadens MMU reporting requirements. It also expands the abilities of
state commissions to obtain additional and more tailored information
from MMUs, while preserving confidentiality protections. The Final Rule
also reduces the lag time for the release of offer and bid data.
1. Background
314. Since the inception of organized energy markets, the
Commission has required RTOs and ISOs to employ a market monitoring
function. MMUs have consistently played a vital role in reporting on
the state of the markets and ferreting out wrongdoing by market
participants. In May of 2005, the Commission issued a Policy Statement
on Market Monitoring Units,\396\ which set forth the tasks MMUs were
expected to perform, and established a procedure for MMU referral of
suspected violations to Commission staff.
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\396\ Market Monitoring Units in Regional Transmission
Organizations and Independent System Operators, 111 FERC ] 61,267
(2005) (Policy Statement).
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315. Concerns raised by interested entities in the context of
individual RTOs and ISOs led the Commission to undertake a generic
examination of MMUs at a technical conference held on April 5,
2007.\397\ At that conference, the
[[Page 64138]]
issues receiving the bulk of the attention centered on the perceived
need for, and suggested methods of achieving, independence on the part
of MMUs so they can perform their assigned functions, and the content
and proper recipients of the MMUs' market data and analysis. These
issues accorded with the Commission's perception of the areas within
the market monitoring function that needed review and strengthening.
---------------------------------------------------------------------------
\397\ Notice and Agenda for the Conference, Review of Market
Monitoring Policies, Docket No. AD07-8-000 (Mar. 30, 2007).
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316. In the ANOPR and the NOPR, the Commission proposed numerous
reforms designed to strengthen MMU independence and broaden information
sharing by the MMUs. Many of these proposed reforms have been carried
forward to this Final Rule, while others have been modified or, in a
few cases, eliminated, based on the comments received from interested
entities. The resulting reforms set forth in the Final Rule provide the
MMUs with enhanced ability to monitor the markets and provide
interested entities with the ability to receive additional market
information, thereby improving market performance and transparency.
2. Independence and Function
317. In the NOPR, the Commission acknowledged the importance of MMU
independence, and stated that there are several means by which to
balance independence and accountability. The Commission proposed a
balanced and flexible approach that included oversight protection,
tariff safeguards and tools, the elimination of conflicts of interest,
and certain changes in the functions MMUs are expected to perform. The
Commission solicited comments on the proposed changes.
a. Structure and Tools
i. Commission Proposal
318. The Commission proposed that each RTO and ISO decide for
itself, through its appropriate stakeholder process, whether it will
have an external, internal or hybrid MMU structure. The Commission
declined to remove MMUs from oversight by their RTOs and ISOs, as the
MMU's principal duties involve monitoring RTO and ISO markets and
advising the RTO or ISO on market performance. The Commission noted
that the fact that MMUs also have reporting obligations to outside
parties does not change their relationship with the RTOs and ISOs,
which are, by Commission policy, required to maintain a market
monitoring function.
319. The Commission further proposed that each RTO or ISO include
in its tariff a provision imposing upon itself the obligation to
provide its MMU with access to market data, resources, and personnel
sufficient to enable the MMU to carry out its functions. The Commission
noted that the RTO or ISO should, in addition, be mindful of these
obligations in developing its market monitoring budget. Furthermore, to
ensure independence of the MMU and its analyses, the RTO or ISO tariff
should specifically provide that the MMU shall have access to the RTO's
or ISO's database of market information. The tariff should also specify
that any data created by the MMUs, including reconfiguring of the RTO
or ISO data, be kept within the MMU's exclusive control.
ii. Comments
320. Constellation states the Commission's proposals are on the
right track.\398\ Dominion Resources and EPSA agree.\399\ Potomac
Economics states that the Commission's proposals appear generally to be
consistent with the nature of the existing relationship between Potomac
Economics and the Midwest ISO, which allows Potomac Economics
sufficient independence to monitor both the market participants and the
market operator. Further, Potomac Economics, the Midwest ISO and state
regulators all see the current structure as providing needed
independence while ensuring responsiveness to regional needs.\400\
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\398\ Constellation at 16.
\399\ Dominion Resources at 8; EPSA at 12-13.
\400\ Potomac Economics at 7-8.
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321. Most commenters agree that the Commission should allow each
RTO or ISO to determine its own structural relationship with its MMU
through its stakeholder process.\401\
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\401\ Ameren, California PUC, EEI, EPSA, FirstEnergy, and North
Carolina Electric Membership.
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322. PG&E endorses the use of hybrid MMU structures (internal MMU
reporting to RTO or ISO management and external MMU reporting to the
RTO or ISO board), but emphasizes the RTO or ISO must meet the
following conditions: (1) both MMUs must have access to all data and
the ability to request data and information from market participants if
needed to perform market analysis functions; (2) both MMUs should
cooperate in assessing any issues regarding the markets, including
sharing identification of market problems developed by either MMU, and
sharing complaints or requests for investigation raised by any market
participant to either MMU; and (3) both MMUs must have adequate
resources and authority to refer matters to the Commission and its
Office of Enforcement.\402\
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\402\ PG&E at 14-15.
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323. Industrial Consumers believe the Commission should mandate the
hybrid structure for all RTOs or ISOs, reasoning that the external MMU,
if not dependent for its main salary or contract on services performed
for the RTO or ISO, is presumed to be independent. It cites the
California ISO's Market Surveillance Committee as a successful
example.\403\
---------------------------------------------------------------------------
\403\ Industrial Consumers at 21.
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324. Most commenters agree that the Commission should require each
RTO or ISO to include a tariff provision imposing on itself the
obligation to provide its MMU with access to market data, resources and
personnel sufficient to enable the MMU to carry out its functions. They
also agree that to ensure the MMU's independence, the MMU should have
access to the RTO's or ISO's database of market information. Further
they agree that any data created by the MMUs should be kept within the
exclusive control of the MMU.\404\ Three commenters state that the
Commission should consider the provisions of a recent settlement
agreement it approved as constituting ``best practices.'' \405\
Further, APPA states that the Commission must specifically incorporate
all of the MMU-related provisions of the PJM MMU Settlement Order into
the Final Rule because the provisions now appear in a settlement
agreement and have no precedential value.\406\ CAISO asks the
Commission to clarify that ``exclusive control'' means that an MMU has
the right to keep data it creates within its control, but has the
option to share such data. CAISO states it appears this right is
implicit in the Commission's proposal, but the Commission should make
it explicit.\407\ Reliant suggests that the Commission should clarify
that MMUs should have full access to RTO or ISO operational information
to determine if RTO operational decisions are negatively impacting
appropriate price signals.\408\
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\404\ Ameren, APPA, Exelon, California Munis, CAISO, EPSA,
FirstEnergy, Industrial Consumers, ISO New England, Midwest Energy,
Midwest ISO, Old Dominion, Pennsylvania PUC, PJM Power Providers,
Reliant, and SPP.
\405\ APPA, Exelon and Pennsylvania PUC (citing Allegheny
Electric Cooperative, Inc., et al. v. PJM Interconnection, LLC, 122
FERC ] 61,257 (2008) (PJM MMU Settlement Order)).
\406\ APPA at 6-7, 78-80.
\407\ CAISO at 12-13.
\408\ Reliant at 13.
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325. APPA and Ohio PUC state that MMU offices should be at the RTO
or ISO site.\409\ APPA, California PUC and TAPS believe that the
Commission should require a tariff provision
[[Page 64139]]
directing an MMU to report to the Commission any concerns it has with
inadequate access to market data, resources, or personnel.
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\409\ APPA at 80-81; Ohio PUC at 23.
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iii. Commission Determination
326. The Commission adopts the NOPR proposal that each RTO or ISO
should decide for itself the structural relationship it desires for its
MMU. Regional variances and preferences in this regard should be
respected, and we decline to mandate any one structure for the MMU
function.
327. We therefore reject the suggestion from Industrial Consumers
that we mandate a hybrid-type MMU structure consisting of both an
internal and an external monitor. While the hybrid structure can
provide many benefits, we have not observed that any RTOs or ISOs with
purely internal or external MMUs suffer deficiencies in performance as
a result. Nor would a hybrid MMU necessarily be more or less
independent than an internal or an external MMU: Hybrid MMUs receive
funding from their RTOs or ISOs, just as do internal and external MMUs.
Neither Industrial Consumers nor other commenters have presented
examples of dysfunctional MMUs, much less a dysfunction that can be
attributed to a particular organizational structure.
328. We also adopt the NOPR proposal that RTOs and ISOs include
provisions in their tariffs: (1) Obliging themselves to provide their
MMUs with access to market data, resources and personnel sufficient to
enable them to carry out their functions; (2) granting MMUs full access
to the RTO or ISO database; and (3) granting MMUs exclusive control
over any MMU-created data. Without the proper tools, it would be
impossible for MMUs to perform their functions.
329. We clarify, in accordance with CAISO's request, that MMUs may
share data under their exclusive control, subject to pertinent
confidentiality provisions. We also clarify, as requested by Reliant,
that access to the RTO or ISO database includes access to RTO or ISO
operational information.
330. We decline to adopt as ``best practices'' the provisions of
the recent settlement agreement entered into by PJM and a number of
interested parties concerning the structure, function and independence
of PJM's MMU (PJM/MMU Settlement Agreement).\410\ The provisions of
that agreement were specific to one RTO, and represented a negotiated
balancing of interests. It would be inappropriate to impose the
specifics of that settlement on all other RTOs and ISOs, and especially
to do so without notice and the opportunity to comment. However, we
observe that the PJM/MMU Settlement Agreement is in accord with our
determinations in this Final Rule regarding the appropriate MMU
structure and tools.\411\
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\410\ See PJM MMU Settlement Order, 122 FERC ] 61,257.
\411\ In the event of any inconsistencies, the requirements
imposed in this Final Rule, which have the force of regulation,
would control. Indeed, the PJM/MMU Settlement Agreement itself so
acknowledges, as the Commission noted in its order approving the
settlement. Id. P 24.
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331. We decline to require that MMU offices be at the RTO or ISO
site. While such a location may well have its advantages, it is also
possible that, in this age of electronic communications, other forms of
access may be satisfactory. In any event, this is a level of detail
that is best worked out on a case-by-case basis.
332. We find it unnecessary to require inclusion of a tariff
provision directing the MMU to report to the Commission any concerns it
may have with inadequate access to market data, resources or personnel.
As we noted in the NOPR, there are already adequate mechanisms for the
MMU to bring any noncompliance in this regard to the Commission's
attention.\412\
---------------------------------------------------------------------------
\412\ NOPR at P 182.
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b. Oversight
i. Commission Proposal
333. The Commission proposed in the NOPR that the MMU, for purposes
of supervision over its market monitoring functions, should report to
the RTO or ISO board rather than to management. The Commission further
proposed that management representatives on the board be excluded from
this oversight function. However, the Commission noted that, if RTOs
and ISOs deem it appropriate, they may have the MMU report to
management for administrative purposes, such as pension management,
payroll and the like. The Commission also proposed that, if an RTO or
ISO has a hybrid MMU structure with two market monitoring bodies, an
internal and an external one, the RTO or ISO may have the internal
market monitor report to management with respect to both its market
monitoring and administrative functions, and the external market
monitor report to the board. The Commission rejected the suggestion
that the MMU should report to a body outside of the RTO or ISO
structure.
334. The Commission also declined to impose a blanket requirement
that major changes in MMU status, such as termination of employment, be
made subject to Commission review. Such requirements are included in
the contractual arrangements of certain RTOs or ISOs, but the
Commission rejected imposing a ``one size fits all'' requirement on the
remaining RTOs or ISOs absent their consent.
ii. Comments
335. Commenters addressing the subject generally agreed that an MMU
should report to an RTO or ISO board rather than to management.\413\
APPA cautions that an RTO or ISO board must be prepared to take
appropriate oversight action when an MMU reports to it.\414\ FTC states
that given the importance of MMU independence and recent concerns in
this area, the Commission may wish to earmark this topic for periodic
review, including an analysis of best practices both in the United
States and abroad.\415\
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\413\ American Forest, APPA, CAISO, DC Energy, EPSA, FTC,
Industrial Consumers, ISO New England, LPPC, Midwest ISO, New York
PSC, North Carolina Electric Membership, NRECA, NYISO, Old Dominion,
PJM Power Providers, Reliant, SPP and TAPS.
\414\ APPA at 81.
\415\ FTC at 30.
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336. With respect to the proposed exception for hybrid MMUs, five
commenters support the proposal.\416\ For hybrids, most commenters
agree that the internal monitor may report to management if the
external monitor reports to the board. Another commenter, DC Energy,
opposes this proposal, arguing that all market monitors should report
to the board to ensure independence. TAPS states that the mix of duties
between internal and external market monitors varies from region to
region, with the external market monitor being ``weak'' in some cases
and the internal market monitor performing the essential duties. TAPS
proposes that the Commission require that the external market monitor
be responsible for the MMU duties spelled out in the NOPR (e.g.,
identifying ineffective market rules, reviewing the performance of the
market, and making referrals to the Commission).
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\416\ CAISO; California PUC; EEI; NYISO; and Reliant.
---------------------------------------------------------------------------
337. On the issue of reporting to a body other than the RTO or ISO,
Ohio PUC believes that an external MMU should report to the RTO's or
ISO's board of directors only as an interim step. It states that the
Commission's long-term goal should be total MMU independence, with the
MMUs reporting as consultants to a Federal-State Joint Board on Market
Monitor Oversight or to some other form of a joint-board construct,
manned by a Commissioner and state commissioner
[[Page 64140]]
or their designees. Ohio PUC believes this construct would provide MMU
autonomy and relieve the board of directors of the RTO or ISO from
arbitrating disputes between an RTO or ISO and the MMU.\417\
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\417\ Ohio PUC at 16-21.
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338. Four commenters disagree with the Commission's proposal not to
impose a blanket requirement that major changes in the MMU's employment
arrangements be subject to Commission review and approval.\418\ APPA
states that substantial changes such as contract termination and
renewal for external market monitors, or major changes in employment
arrangements for internal market monitors, should be subject to
Commission review and approval. It also suggests that the Commission
adopt the pertinent provision of the PJM/MMU Settlement Agreement as a
``best practice,'' reasoning that this would give MMUs a measure of job
security that might allow them to be more independent in their
assessments.\419\ California PUC and Steel Producers agree that
significant relational changes should be subject to Commission review,
including changes to the structure of an MMU or the dismissal of key
MMU personnel.\420\ TAPS states that Commission review of important
changes would provide a backstop to ensure MMU independence, and would
give market participants and the Commission a mechanism to assess
whether an RTO or ISO has fulfilled its obligations toward the MMU. It
argues that the Commission has not provided a valid reason not to
require approval of such MMU changes.\421\
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\418\ APPA; California PUC; Steel Producers; and TAPS.
\419\ APPA at 82.
\420\ California PUC at 34; Steel Producers at 11-12.
\421\ TAPS at 49.
---------------------------------------------------------------------------
iii. Commission Determination
339. We adopt the NOPR proposal requiring MMUs to report to the RTO
or ISO board of directors, with management representatives on the board
excluded from this oversight function. Removing the MMU from reporting
to management will give it the separation needed to foster
independence. If occasion demands, we will revisit this decision.
However, we decline to ``earmark'' it for periodic review as requested
by the FTC. We also adopt the NOPR proposal allowing RTOs and ISOs, if
they deem it appropriate, to permit the MMU to report to management for
administrative purposes, such as pension management, payroll and the
like.
340. Commenters generally agreed with our proposed exception for
hybrid MMUs, in which we suggested that the internal market monitor may
continue to report to management, while the external market monitor
should report to the board. But TAPS points out that in some hybrid
structures, the most important functions of the MMU are performed by
the internal market monitor, with the external market monitor playing a
much ``weaker'' role. We agree that such a division of labor presents a
problem, and could result in the rule being swallowed by the exception.
341. However, we decline to adopt TAPS's suggested solution of
requiring the external market monitor to assume responsibility for the
core MMU duties spelled out in this order (identifying ineffective
market rules, reviewing the performance of the markets, and making
referrals to the Commission). This solution might impose upon the RTO
or ISO an MMU structure that it does not want. Instead, we will require
that if the internal market monitor is responsible for carrying out any
or all of the above-cited core MMU functions, it must report to the
board (as must the external market monitor). This solution allows the
RTO or ISO to structure its MMU function in the way it deems most
suitable, while also ensuring that the market monitor that performs the
core MMU functions enjoys the independence from management that
reporting to the board accomplishes.
342. Ohio PUC suggests that reporting to the RTO or ISO board
should be an interim step only, and that ultimately MMUs should report
to a Federal-State Joint Board on Market Monitor Oversight. Not only
does an arrangement of this type raise jurisdictional concerns, it is
difficult to see how such a potentially cumbersome structure could
oversee MMUs in a timely and responsive manner. It is also doubtful
that such an arrangement could effectively replicate the existing close
exchange of data between the RTO or ISO and its MMU. Should the reforms
we adopt in this Final Rule fail to achieve the needed independence we
envision for MMUs, we will not hesitate to rectify the situation.
343. Several commenters propose that changes in the RTO/ISO/MMU
relationship, such as contract termination or the dismissal of key MMU
personnel, should be made subject to Commission review.\422\ We noted
in the NOPR that as of the date of its issuance, three of the RTOs and
ISOs had agreements in place that provided for such review.\423\ Since
that date a fourth has been added, that of PJM.\424\
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\422\ To the extent commenters request that structural changes
be made subject to Commission review, we note that such matters are
governed by tariff and any change to the MMU structure (such as
whether an MMU is internal, external or a hybrid) would require a
tariff filing.
\423\ Midwest ISO cannot terminate its agreement with its market
monitor (an independent contractor) without Commission approval.
Open Access Transmission and Energy Markets Tariff for the Midwest
Independent Transmission System Operator, Inc., Attachment S-1, FERC
Electric Tariff, Third Revised Volume No. 1, Second Revised Sheet
No. 1659 (2005). SPP cannot terminate its agreement with its
external market monitor without Commission approval. Southwest Power
Pool Open Access Transmission Tariff, FERC Electric Tariff Fourth
Revised Volume 1, Attachment AJ, Sec. 11, Second Revised Sheet No.
699 (2006). The same is true for ISO New England. Participants
Agreement among ISO New England, Inc. and the New England Power
Pool, et al., Sec. 9.4.5.
\424\ Settlement Agreement and Explanatory Statement of the
Settling Parties, Docket Nos. EL07-56-000 and EL07-58-000 (December
19, 2007), Attachment M, PJM Market Monitoring Plan, III.F.3.e. This
agreement was approved by the Commission in the PJM MMU Settlement
Order.
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344. These RTOs and ISOs have voluntarily consented to such review.
In the absence of such consent, we decline to impose a blanket
requirement that RTOs and ISOs make their MMUs' contractual and
employment arrangements subject to Commission review. Should the
situation arise in which an RTO or ISO terminates its MMU in such a way
as to violate its tariff requirements concerning MMU independence, the
Commission will address such a violation on case-by-case basis.
c. Functions
i. Commission Proposal
345. In the NOPR, the Commission proposed updating and expanding
the core tasks that our May 2005 Policy Statement on Market Monitoring
Units required MMUs to perform. We proposed that the MMU be responsible
for evaluating market rules, tariff provisions and market design
elements for their effectiveness, and proposing recommended changes;
reviewing and reporting on the performance of the wholesale markets;
and referring suspected wrongdoing to the Commission.
346. In furtherance of its goal of ensuring independent analysis on
the part of MMUs, the Commission also proposed that RTOs and ISOs
include a provision in their tariffs specifying that they may not alter
the reports generated by the MMUs or dictate the conclusions reached by
the MMUs, although they may establish a reasonable mechanism for review
and comment on MMU reports that are still in draft form. The
[[Page 64141]]
Commission noted that this proposal will enable the MMU to receive
potentially helpful comments, while removing the ability of the RTO or
ISO to unreasonably influence or impede the MMU's analysis.
ii. Comments
347. All but two commenters support the Commission's proposal
regarding the three core functions of an MMU.\425\ ISO New England
would add a fourth function, that of regular daily monitoring of the
wholesale market in order to obtain timely access to information that
would provide a broader context for evaluating particular types of
conduct, and that could speed and enhance detection of manipulative
behavior.\426\ TAPS would also add a fourth function, that of assessing
whether RTO benefits flow to consumers. It suggests that the MMU could
make this consumer-value assessment by examining, for example, whether
in LMP markets investment in transmission, generation and demand
response is occurring in areas with higher prices, and whether FTRs are
available, and are being used, to hedge transmission congestion costs
experienced by LSEs.\427\
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\425\ CAISO; California PUC; DC Energy; EEI; Industrial
Consumers; ISO New England; Midwest ISO; North Carolina Electric
Membership; NY TOs; PG&E; PJM; Reliant; SPP; and TAPS.
\426\ ISO New England at 18.
\427\ TAPS at 51-52.
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348. CAISO requests clarification that when an MMU evaluates
existing and proposed market rules, the Commission expects it to employ
its best judgment about effective use of resources, and does not expect
a formal evaluation for every existing market rule.\428\ California PUC
agrees that an MMU should identify ineffective market rules and tariff
provisions and recommend proposed rule and tariff changes; however, it
suggests the MMU's participation be limited to an advisory role.\429\
NY TOs and PJM state that MMUs should evaluate changes, but should not
get involved in implementing changes.\430\ PG&E believes the Final Rule
should authorize MMUs to access data necessary to assess the impact of
behavior outside of an RTO's or ISO's geographic footprint, commenting
that such access is needed in California because the state is very
dependent on imports. It also states that MMUs should report on the
effectiveness and comprehensiveness of mitigation as part of their
duties, even when they are not themselves directly involved in
implementation of such mitigation.\431\
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\428\ CAISO at 14.
\429\ California PUC at 34-35.
\430\ NY TOs at 3; PJM at 6.
\431\ PG&E at 15-16.
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349. Two commenters agree with the Commission's proposal that MMUs
should limit dissemination of information in those cases where
disclosure of a market design loophole could be exploited.\432\ APPA
believes MMUs should disclose such information at an appropriate time,
such as when tariff changes or software upgrades are adopted, in order
to maintain transparency.\433\ Reliant requests clarification as to
whether MMUs should provide the RTO or ISO, stakeholders and the
Commission with their views as to whether existing operations interfere
with appropriate market signals.\434\
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\432\ APPA; Reliant.
\433\ APPA at 83.
\434\ Reliant at 12-13.
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350. All three commenters addressing the subject agree that MMUs
should report violations of Standards of Conduct (18 CFR Part 158) or
Affiliate Restrictions rules (18 CFR 35.39) rules if uncovered in the
ordinary course of business.\435\ California PUC states that violations
should be referred to the appropriate state commission as well as to
the Commission.\436\
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\435\ California PUC; EPSA; and Midwest ISO.
\436\ California PUC at 36-37.
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351. Commenters agree that RTOs should not be allowed to alter
reports generated by an MMU.\437\ APPA does not support a tariff
provision allowing MMUs to submit their reports in draft form to RTOs
for review and comment. It states that the Commission approved a
specific prohibition against such review in the PJM/MMU Settlement
Agreement, and should adopt such a prohibition in this proceeding.\438\
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\437\ APPA; NRECA; NSTAR; Old Dominion; PJM; and SPP.
\438\ APPA at 83-84.
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352. Old Dominion suggests that if the MMU disagrees with a tariff
change that the RTO or ISO proposes to the Commission, the RTO or ISO
should file both its proposal and that of the MMU.\439\
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\439\ Old Dominion at 21-22.
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iii. Commission Determination
353. We adopt the MMU functions proposed in the NOPR, with
clarifying rewording. These functions expand and update the functions
already performed by MMUs in accordance with the Policy Statement and
codify the protocols for referrals to the Commission discussed
therein.\440\ The revised functions should provide MMUs with ample
authority to evaluate any needed changes to the markets and bring them
to the attention of concerned entities, to review and report on the
performance of the markets, and to refer suspected wrongdoing to the
Commission.
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\440\ Policy Statement, 111 FERC ] 61,267 at Appendix A.
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354. As we have previously acknowledged:
MMUs perform an important role in assisting the Commission in
enhancing the competitiveness of ISO/RTO markets. Competitive
markets benefit customers by assuring that prices properly reflect
supply and demand conditions. MMUs monitor organized wholesale
markets to identify ineffective market rules and tariff provisions,
identify potential anticompetitive behavior by market participants,
and provide the comprehensive market analysis critical for informed
policy decision making.[\441\]
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\441\ Id. P 1.
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Thus, the MMU functions we adopt are as follows:
(1) Evaluating existing and proposed market rules, tariff
provisions and market design elements, and recommending proposed
rule and tariff changes not only to the RTO or ISO, but also to the
Commission's Office of Energy Market Regulation staff and to other
interested entities such as state commissions and market
participants, with the caveat that the MMU is not to effectuate its
proposed market design itself (a task belonging to the RTO or ISO),
and with the further caveat that the MMU should limit distribution
of its identifications and recommendations to the RTO or ISO and to
Commission staff in the event it believes broader dissemination
could lead to exploitation, with an explanation of why further
dissemination should be avoided at that time;
(2) Reviewing and reporting on the performance of the wholesale
markets to the RTO or ISO, the Commission, and other interested
entities such as state commissions and market participants; and
(3) identifying and notifying the Commission's Office of
Enforcement staff of instances in which a market participant's
behavior, or that of the RTO or ISO, may require investigation,
including suspected tariff violations, suspected violations of
Commission-approved rules and regulations, suspected market
manipulation, and inappropriate dispatch that creates substantial
concerns regarding unnecessary market inefficiencies.
355. We decline to add as a fourth function ISO New England's
proposal regarding daily monitoring of the wholesale market, as this
function is included in the existing requirement to review and report
on the performance of the wholesale markets.
356. CAISO requests clarification that the Commission does not
expect an MMU to make a formal evaluation of every existing market
rule. We agree. The MMU's role is one of monitoring, not auditing, and
we do not expect it to
[[Page 64142]]
make a systematic and comprehensive review of every one of the
thousands of existing market rules. For this reason, we decline to
adopt TAPS's suggested fourth function of assessing whether RTO or ISO
benefits flow to consumers. Finally, we expect MMUs to be vigilant in
identifying problems and bringing them to the attention of the RTO or
ISO, the Commission, and other interested entities.
357. We agree that the MMU's role in recommending proposed rule and
tariff changes is advisory in nature, and that the MMU should not
become involved in implementing rule and tariff changes (unless a
tariff provision specifically concerns actions to be undertaken by the
MMU itself). Both the filing of proposed rule and tariff changes, and
the implementation of rule and tariff changes, are within the purview
of the RTO or ISO. However, we do expect the MMU to advise the
Commission, the RTO or ISO, and other interested entities of its views
regarding any needed rule and tariff changes. Likewise, in the event an
RTO or ISO files for a proposed tariff change with which the MMU
disagrees, we expect the RTO or ISO to inform the Commission of that
disagreement, although not necessarily to include a written MMU
proposal with its filing.
358. We also concur with PG&E that where data concerning activity
outside the geographical footprint of the RTO or ISO would be helpful
to the MMU in carrying out its functions, the MMU should seek out such
data. Likewise, where an MMU believes market design flaws interfere
with appropriate price signals, these flaws should be brought to the
attention of concerned entities. And, where information about a market
design flaw was not broadly disseminated because the MMU felt such
information could alert market participants to a market loophole, such
information can, and should, be provided once the danger of
exploitation of the loophole is past.
359. The California PUC requests that violations of the Standards
of Conduct or Affiliate Restrictions should be reported to the
appropriate state commission as well as to the Commission. We decline
to adopt this proposal. These are violations of Commission rules, not
of state rules or statutes, and therefore the Commission is the proper
body to investigate them.
360. We adopt the NOPR proposal that, by tariff, each RTO or ISO
may require its MMU to submit its report in draft form to the RTO or
ISO for review and comment, but may not alter the reports generated by
the MMU or dictate the MMU's conclusions. RTOs or ISOs need not require
submission of draft reports, but if they do, input from knowledgeable
employees may serve to strengthen the end product or catch errors of
fact or reasoning. In any event, the MMU is free to disregard any
suggestions with which it disagrees.
d. Mitigation and Operations
i. Commission Proposal
361. In order to strengthen MMU independence, the Commission
proposed in the NOPR that MMUs be removed from tariff administration,
including mitigation. This proposal was designed to free MMUs from a
role that might make them subordinate to the RTO or ISO. The Commission
regulates public utilities, and it is the public utilities that we hold
accountable for tariff implementation. To the extent this function is
performed by MMUs, the MMUs are assisting the RTOs and ISOs in the
administration of their tariff, which places the MMUs in a subordinate
position to the RTOs and ISOs. The proposal was also designed to remove
the bias that might arise from the MMUs' analyzing the health of the
markets they themselves had affected. The Commission solicited comments
on the activities that would be needed to make the transition to RTO or
ISO-administered mitigation, on any difficulties the MMU might be
anticipated to experience in monitoring mitigation performed by the RTO
or ISO, and any additional sensitivities that commenters wished to
raise regarding the proposal.
ii. Comments
362. Several commenters support the Commission's proposal to remove
MMUs from RTO and ISO tariff administration, including mitigation.\442\
However, many more oppose it.\443\
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\442\ Ameren; EPSA; FirstEnergy; Industrial Consumers; PG&E;
PJM; Reliant; SoCalEdison-SDG&E; and SPP.
\443\ American Forest; California PUC; Indianapolis P&L;
Industrial Coalitions; Maine PUC; NARUC; NEPOOL Participants; New
York PSC; North Carolina Electric Membership; Ohio PUC; Old
Dominion; OMS; Potomac Economics; and Xcel.
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363. The commenters who agree with the Commission's proposal
advance several arguments in support of it. Two entities cite two
conflicts of interest that may arise when an MMU is involved in
mitigation and tariff administration, the first occurring when an MMU
both evaluates market performance and conducts mitigation,\444\ and the
second occurring when an MMU assists in designing and finalizing a rule
for filing with the Commission and subsequently evaluates the
effectiveness of the rule in practice.\445\ Another commenter states
that an MMU should be limited to the three core functions the
Commission enunciated in the NOPR, leaving it free to advise the
Commission of perceived instances where the RTO or ISO itself has
failed to conduct economic dispatch in an efficient manner.\446\ Other
commenters state that the rules and actions related to mitigation
should be made explicit and, to the extent possible, be automated and
implemented via bright-line tests, in order to eliminate discretion in
their application.\447\
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\444\ Ameren at 33; PJM at 4-6.
\445\ Ameren at 33; PJM at 5-6.
\446\ FirstEnergy at 14-15.
\447\ Reliant at 13; Potomac Economics at 8-9.
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364. The commenters who oppose the Commission's proposal advance
several arguments why RTOs and ISOs should not perform mitigation.
Commenters suggest that the RTO or ISO staff and personnel who have
designed and implemented the markets, and whose compensation is based
upon those tasks, may have a vested interest in not identifying or
correcting problematic behavior, and may have an interest in not
imposing enforcement measures on what in effect are their customers, or
in refraining from mitigating a member that threatens to leave the RTO
or ISO.\448\ Other commenters remark that removing the MMU from
mitigation activities may deprive the MMU of much of the hands-on
administrative interaction with participants that is essential to
consumer protection.\449\ One commenter suggests that a better way to
address the issue is to issue additional orders limiting discretion in
applying mitigation, rather than removing MMUs from mitigation
activities.\450\ Other commenters argue that moving mitigation
responsibility from an MMU to the RTO or ISO would deprive the MMU of
timely, first-hand access to crucial information that could speed and
enhance detection of manipulative behavior, noting that after-the fact
mitigation (settlement price adjustment) would not be a function of the
market that the MMU would be able to view once it was removed from
tariff administration.\451\ ISO New England states that mechanistic
application of mitigation criteria by RTOs or ISOs would not readily
address shifts in bidding behaviors, and that as market participants
continuously search for
[[Page 64143]]
more profitable bidding strategies, the discretion of a skilled MMU to
investigate unusual bidding behavior inhibits experimentation with
deviant strategies and enhances deterrence.\452\ ISO New England states
that the Commission's conflict of interest concern is inconsistent with
grounding MMU independence and objectivity in its code of conduct and
contractual obligations, and notes that the MMU has nothing to gain
financially from mitigation.\453\ ISO New England and Maine PUC state
that moving the mitigation activity to the RTO or ISO could require
additional operational staff to perform tasks that MMU employees can
accomplish on an integrated basis and more efficiently, thereby
increasing RTO or ISO costs.\454\ NYISO estimates that an additional
five to eight employees would be required because of the need to
duplicate some functions in order for the MMU to monitor the RTO or
ISO's conduct of mitigation.\455\
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\448\ American Forest at 6; California PUC at 37-38;
Indianapolis P&L at 4; Industrial Coalitions at 21-22; Midwest ISO
at 24-26; Ohio PUC at 24-25; and OMS at 16-17.
\449\ American Forest at 7; ISO New England at 19-22; and NARUC
at 12-13.
\450\ American Forest at 7.
\451\ ISO New England at 20-21; Xcel at 12-13.
\452\ ISO New England at 21.
\453\ Id. at 21-22 (citing ISO New England Inc., 119 FERC ]
61,045, at P 123 (2007), reh'g granted in part and denied in part,
120 FERC ] 61,087 (2007)); NEPOOL Participants at 23 (citing ISO New
England Inc. 106 FERC ] 61,280, P 187 (2004), reh'g granted in part
and denied in part, 109 FERC ] 61,147 (2004); Order Authorizing RTO
Operations; 110 FERC ] 61,111 (2005); order on reh'g, 111 FERC ]
61,344 (2005); ISO New England Inc., 120 FERC ] 61,087, at P 52
(2007)).
\454\ ISO New England at 22; Maine PUC at 7.
\455\ NYISO at 16.
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365. Indianapolis P&L states that moving the mitigation function to
the RTO or ISO raises the potentially serious problem of retaliation,
because if RTO or ISO stakeholders disagree with the direction in which
the RTO or ISO wishes to move, the RTO or ISO could be tempted to use
the market mitigation power as a tool of persuasion.\456\ OMS states
that in the absence of a specific showing that an MMU is incapable of
applying mitigation measures appropriately, the Commission should
respect the decision of the RTO or ISO and stakeholders in this regard.
It also observes that RTOs and ISOs have greater incentive than MMUs
not to mitigate, as an entity might be inclined to withdraw from
membership in response. It does not regard a referral to the Commission
of an RTO's or ISO's failure to properly mitigate as a sufficient
remedy, as such referrals are kept confidential.\457\
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\456\ Indianapolis P&L at 4.
\457\ OMS at 8-9.
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366. SoCal Edison-SDG&E support the Commission's proposal only if
the following conditions occur: (1) Adequate assurance of effective
mitigation is provided; (2) MMUs have full access to data used for
mitigation; and (3) MMUs are allowed to participate in all activities
used to develop mitigation rules and specific mitigated bid levels for
individual generators.\458\ PG&E supports it only if: (1) RTO and ISO
tariffs are modified to include sufficient staff resources to perform
mitigation; (2) mitigation staff are free from the influence of other
RTO staff; and (3) mitigation staff has the right to report to the
Commission and its Office of Enforcement any loopholes or deficiencies
in mitigation design or implementation.\459\
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\458\ SoCal Edison-SDG&E at 4.
\459\ PG&E at 17.
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367. EEI, ISO New England, Maine PUC and New York PSC oppose the
proposal for cases where the RTO or ISO has a hybrid MMU
structure.\460\ Midwest ISO opposes the proposal when it is applied
mechanically to all RTOs and ISOs.\461\ NRECA states that any changes
in the Final Rule should not weaken mitigation, should not supersede
the PJM/MMU Settlement Agreement, and should follow the Final Rule in
Order No. 697.\462\ CAISO notes that its internal monitor does not
administer mitigation, but does administer an Enforcement Protocol
related to late fees and the untimely submission of outage reports and
meter data,\463\ and seeks guidance as to whether these activities
would constitute ``tariff administration'' under the Final Rule.\464\
TAPS does not oppose the proposal, but thinks MMUs can function better
doing mitigation.\465\
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\460\ EEI at 24-25, ISO New England at 19-22; Maine PUC at 7;
and New York PSC at 6-8.
\461\ Midwest ISO at 24-26.
\462\ Market-Based Rates For Wholesale Sales Of Electric Energy,
Capacity, And Ancillary Services By Public Utilities, Order No. 697,
FERC Stats. & Regs. ] 31,252, at P 241 (2007), order on reh'g, Order
No. 697-A, 73 FR 25,832 (May 7, 2008), FERC Stats. & Regs. ] 31,268
(2008).
\463\ Calif. Indep. Sys. Operator Corp., 106 FERC ] 61,179, at P
154; order on reh'g, 107 FERC ] 61,118; reh'g denied, 109 FERC ]
61,089 (2004); order on reh'g, 110 FERC ] 61,333 (2005).
\464\ CAISO at 15-16.
\465\ TAPS at 52-53.
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368. Potomac Economics and APPA offer compromise positions and
clarifications. APPA suggests that the MMU continue to review bids, but
refrain from participating directly in drafting proposed changes to the
mitigation rules; rather, the MMU would comment on the proposed rules
and, if necessary, become a separate intervenor in a Commission
proceeding if one were to occur.\466\
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\466\ APPA at 84-85.
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369. Potomac Economics observes that the aspects of mitigation that
the Commission appears to find objectionable are those that are applied
prospectively to participant offers and thus affect market outcomes
(such as altering the prices of offers or altering the physical
parameters of offers such as ramp rates and start-up time). Potomac
Economics proposes that the Commission clarify that the RTO or ISO
should be responsible for implementing these prospective mitigation
measures, while the MMU be allowed to be responsible for implementing
retrospective measures such as calculation of after-the-fact mitigation
true-ups for billing purposes and settlement price adjustments. Potomac
Economics also suggests that MMUs continue to be responsible for the
production of inputs into the mitigation process, such as reference
levels and the identification of system constraints, which rely on the
MMUs' intimate knowledge of the market and their software capabilities.
Potomac Economics believes that this bifurcation of labor would avoid
the wasteful duplication of software, staff and expertise that would be
needed for the RTO or ISO to mirror all of the MMU's mitigation
capabilities, that it contends the MMU would have to retain in order to
satisfy its market monitoring obligations.\467\
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\467\ Potomac Economics at 8-10.
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iii. Commission Determination
370. The proposal in the NOPR to remove MMUs from tariff
administration, and in particular from mitigation, engendered heated
disagreement amongst the commenters. Several supported the proposal,
although the majority disagreed with removing the MMU from mitigation.
The Commission has given careful consideration to the comments, and
acknowledges that there are valid concerns on both sides.
371. As we observed in the NOPR, and as many commenters noted as
well, there is an inherent conflict of interest in an MMU conducting
mitigation and also opining on the state of the market, the health of
which may in part reflect the results of its mitigation. We also
observed that by supporting RTOs and ISOs in tariff administration,
MMUs become subordinate to the RTO or ISO, thus weakening their
independence.
372. Many commenters, however, raise substantial concerns over
removing MMUs from mitigation, including the following: (1) There is a
greater conflict of interest for the RTO or ISO to administer
mitigation, as it has a vested interest in keeping its market
participants happy, especially the larger players who can threaten to
leave the
[[Page 64144]]
RTO or ISO if they choose; (2) the MMU serves as a useful buffer
between the RTO or ISO and the market participants, performing what is
often viewed as a hostile act; (3) there is an inherent tension between
mitigation and the RTO or ISO goal of promoting new markets; (4) the
MMU is better equipped by training and market access to detect the need
for mitigation; (5) removing the MMU from mitigation would distance it
from the market insights it needs to perform its monitoring functions;
(6) if removed from tariff administration, the MMU would not have
access to the mitigation settlement process and thus could not
adequately monitor the RTO's or ISO's mitigation performance; (7) there
would be much duplication of costs, since the MMU would have to retain
most of its mitigation capabilities in order to monitor the RTO's or
ISO's conduct of mitigation; (8) there would be extensive transition
costs and software licensing concerns; and (9) there is no empirical
evidence of an existing problem with the MMUs performing mitigation.
373. We find many of the objections raised by commenters
meritorious. However, we remain concerned that the unfettered conduct
of mitigation by MMUs makes them subordinate to the RTOs and ISOs and
raises conflict of interest concerns. Therefore, we adopt a compromise
approach, one that strikes the appropriate balance between allowing
modified participation by the MMUs in mitigation, while protecting
against the conflict of interest and subordination inherent in their
unfettered participation.
374. As the first element of this approach, we direct that in the
event an RTO or ISO employs a hybrid MMU structure, it may authorize
its internal MMU to conduct mitigation. An internal MMU is a part of
the RTO or ISO, and allowing it to conduct mitigation adequately
separates it from the monitoring duties of the external market monitor
and places mitigation within the RTO or ISO itself. However, this
solution only works if the external market monitor is charged with the
responsibility of reviewing the quality and appropriateness of the
mitigation conducted by the internal market monitor. We therefore
require that in the event an RTO or ISO with a hybrid MMU structure
permits its internal market monitor to conduct mitigation, it must
assign its external market monitor the responsibility, and give it
adequate tools, to monitor the quality and appropriateness of that
mitigation.
375. As the second element of our approach, we find useful Potomac
Economics' distinction between prospective and retrospective
mitigation. It is only prospective mitigation that affects the
operation of the market, and therefore it is only prospective
mitigation that creates a potential conflict of interest for an MMU.
Therefore, we direct that RTOs and ISOs may allow their MMUs,
regardless of whether it uses a hybrid structure, to conduct
retrospective mitigation. For these purposes, we consider prospective
mitigation to include only mitigation that can affect market outcomes
on a forward-going basis, such as altering the prices of offers or
altering the physical parameters of offers (e.g., ramp rates and start-
up times) at or before the time they are considered in a market
solution. All other mitigation would be considered retrospective. We
also determine that the MMU may provide the inputs required by the RTO
or ISO to conduct prospective mitigation, including determining
reference levels, identifying system constraints, cost calculations and
the like. This will enable the RTO or ISO to utilize the considerable
expertise and software capabilities developed by their MMUs, and reduce
wasteful duplication.
376. As noted by Potomac Economics and by PJM in its supplemental
comments, a number of our orders specifically lodge elements of
mitigation and administration within the MMUs. Many of these may
properly be considered retroactive mitigation, and the RTOs' or ISOs'
tariffs would not need to be adjusted to remove these responsibilities
from the MMU's purview. Should there be any question of categorization,
whether for existing or proposed tariff provisions, the RTO or ISO may
seek guidance from the Commission in its compliance filing.
377. We also direct that purely administrative matters, such as
those identified by CAISO (enforcement of late fees and the untimely
submission of outage reports and meter data), should be conducted by
the RTO or ISO, rather than the MMU. Such activities are remote from
the core duties that this Final Rule assigns to the market monitoring
function.
378. We also direct that the tariffs of RTOs and ISOs clearly state
which functions are to be performed by MMUs, and which by the RTO or
ISO. This separation of functions will serve to eliminate RTO or ISO
influence over the MMUs, and remove the concern that MMU assistance in
mitigation makes it subordinate to the RTO or ISO.
379. Finally, we direct the RTOs and ISOs to review their
mitigation tariff provisions with a view to making them as non-
discretionary as possible, whether performed by the MMU or by the RTO
or ISO, and to reflect any needed changes in their compliance filings.
This will go a long way toward removing the ability of either entity to
act in a discriminatory manner, and will facilitate the monitoring and
review of mitigation activities.
e. Ethics
i. Commission Proposal
380. In the NOPR, the Commission proposed that development of
particular ethics standards to be applied to MMUs should be left in the
first instance to the discretion of the RTOs and ISOs. However, the
Commission noted that these standards should include certain minimum
requirements, as follows: (1) Employees shall have no material
affiliation (to be defined by the RTO or ISO) with any market
participant or affiliate; (2) employees shall not serve as an officer,
employee, or partner of a market participant; (3) employees shall have
no material financial interest in any market participant or affiliate
(allowing for such potential exceptions as mutual funds and non-
directed investments); (4) employees shall not engage in any market
transactions other than the performance of their duties under the
tariff; (5) employees shall not be compensated, other than by the RTO
or ISO, for any expert witness testimony or other commercial services
to the RTO or ISO or to any other party in connection with any legal or
regulatory proceeding or commercial transaction relating to the RTO or
ISO or to the RTO or ISO markets; (6) employees may not accept anything
of value from a market participant in excess of a de minimis amount, to
be decided on by the RTO or ISO; and (7) employees must advise their
supervisor (or, in the case of the MMU manager, advise the RTO or ISO
board) in the event they seek employment with a market participant and
must disqualify themselves from participating in any matter that would
have an effect on the financial interest of such market
participant.\468\
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\468\ The Commission noted that some external MMUs may currently
have business associations that would be prohibited under these
proposed minimum requirements, such as unrelated consulting work for
participants in its RTO's or ISO's markets. If that is the case, the
Commission proposed that the RTO or ISO should propose a suitable
transition plan in its compliance filing. NOPR, FERC Stats. & Regs.
] 32 ,628 at n.200.
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ii. Comments
381. All commenters addressing the subject agree that ethical
standards should be imposed on MMU
[[Page 64145]]
employees.\469\ All but one of these commenters agree that the
standards should appear in a tariff provision, thus making the MMU
subject to an enforcement action. However, FirstEnergy, stating that it
is opposed to collecting from RTO or ISO members any penalties assessed
to an RTO or ISO, prefers that the MMU adopt ethics standards
internally and implement them by managing and disciplining its
employees.\470\ APPA and Ohio PUC suggest adding a provision to the
standards covering post-employment activities.\471\ Midwest ISO states
its market monitor performs independent work for other entities under
Commission-approved monitoring plans, and requests clarification that
the minimum guidelines the Commission proposes would not prohibit other
employees of the MMU's firm from performing independent monitoring for
other entities. Potomac Economics, the Midwest ISO's MMU, requests the
same clarification, noting that the work is not done on behalf of the
company.\472\ NRECA asserts that ethics standards should include civil
penalties.\473\
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\469\ Ameren; APPA; CAISO; California PUC; DC Energy; EEI;
FirstEnergy; Industrial Consumers; ISO New England; Midwest ISO;
North Carolina Electric Membership; NRECA; Ohio PUC; PG&E; PJM Power
Providers; Potomac Economics; Reliant; SPP; and TAPS.
\470\ FirstEnergy at 15-16.
\471\ APPA at 86; Ohio PUC at 25-26.
\472\ Midwest ISO at 26-27; Potomac Economics at 13.
\473\ NRECA at 53-54.
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382. Potomac Economics proposes that the Commission should include
the phrase ``other than the RTO or ISO'' after the first clause in
proposed minimum requirement (5), as omission of the phrase would
prohibit compensation of MMU employees for any expert witness testimony
or other commercial services on behalf of the Commission-approved RTO
or ISO, thus preventing the MMU from performing many of the required
market monitoring functions.\474\
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\474\ Potomac Economics at 11-13.
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iii. Commission Determination
383. There was widespread agreement among the commenters that
ethics standards should be imposed, and the importance of such
standards calls for their inclusion in the RTO's or ISO's tariff,
subject to enforcement by the Commission. (The manner of such potential
enforcement, including whether civil penalties might be imposed and the
avenue by which any such penalties might be collected, is beyond the
scope of this Final Rule.\475\) Therefore, we direct that each RTO and
ISO include in its tariff the minimum ethics standards set forth in the
NOPR, with certain modifications as set forth below.
---------------------------------------------------------------------------
\475\ See Revised Policy Statement on Enforcement, 123 FERC ]
61,156 (2008) (discussing the factors to be considered in
determining what, if any, remedies are to be imposed in the case of
violations of Commission rules and regulations).
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384. We note that the requirements we impose are minimums, and an
RTO or ISO is free to propose more stringent ones. Therefore, the
appropriate place to request additional requirements, such as the
suggested extension of the standards to post-employment activities,
would be in stakeholder meetings, or before the Commission when the RTO
or ISO makes its tariff compliance filing.
385. Midwest ISO and Potomac Economics request clarification that
the ethics standards do not prohibit employees of the MMU from
performing monitoring for entities other than RTOs or ISOs. We clarify
that if the employing entity is not a market participant in the
particular RTO or ISO for whom the MMU already performs market
monitoring, such engagement is permissible. However, if the employing
entity is a market participant in the RTO or ISO for whom the MMU
already performs market monitoring, the proposed work would entail the
same conflict of interest as would any other consulting services. We
are cognizant of the fact that if an MMU currently has such engagements
in place, it will take a certain amount of time to unwind the
association or make other suitable arrangements. We direct the RTO or
ISO to apprise the Commission of such engagements in its compliance
filing, and to propose a transition plan for dealing with them in a
manner consistent with the aims expressed in this Final Rule, as the
Commission proposed in the NOPR.\476\
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\476\ NOPR, FERC Stats. & Regs. ] 32,628 at P 200.
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386. We agree with Potomac Economics that the NOPR's regulatory
text inappropriately omitted the phrase ``other than the RTO or ISO''
after the first clause of proposed minimum ethical requirement (E).
(The phrase was included in the body of the NOPR itself). We direct
that the RTO and ISO tariffs should include the omitted phrase, and we
correct the regulatory text in this Final Rule.
387. We also note that both the body of the NOPR and the regulatory
text refer to ``employees,'' whereas the intent of the provision
encompasses both the MMU itself as well as its employees. We therefore
direct the RTOs and ISOs to specify that their MMU ethics standards
apply to the MMU itself as well as to its employees.
f. Tariff Provisions
i. Commission Proposal
388. The Commission proposed in the NOPR that RTOs and ISOs be
required to include in their tariffs, and centralize in one section,
all of their MMU provisions. We noted that including all MMU provisions
in the tariff will ensure they are made subject to the compliance
requirements that attach to tariff provisions, and thus will give to
interested parties notice and an opportunity to intervene when a tariff
filing is made.
389. The Commission also proposed that RTOs and ISOs include an MMU
mission statement in the introductory portion of its MMU tariff
section, setting forth the goals to be achieved by the MMU, including
the protection of both consumers and market participants by the
identification and reporting of market design flaws and market power
abuses.
390. The Commission further proposed that the RTOs and ISOs meet
these requirements at the time they make their compliance filings in
connection with this proceeding.
ii. Comments
391. Commenters support the proposal to locate all MMU provisions
in one section of the RTO or ISO tariffs.\477\ Two commenters agree
these provisions should include a mission statement.\478\ APPA states
the best starting point for this kind of statement is Attachment M to
the PJM/MMU Settlement Agreement.\479\ FirstEnergy opposes the option
of leaving existing MMU provisions in their current location in
addition to placing them in a new section of the tariff, since it
believes this would be administratively inconvenient and has the
potential to create inconsistencies.\480\ PG&E does not oppose posting
MMU provisions elsewhere than in the MMU section, so long as
appropriate cross-referencing is made.\481\
---------------------------------------------------------------------------
\477\ Ameren; APPA; California PUC; Constellation; DC Energy;
EEI; FirstEnergy; Industrial Consumers; ISO New England; Midwest
ISO; North Carolina Electric Membership; Old Dominion; PG&E;
Reliant; SPP; and Xcel.
\478\ APPA at 87; EEI at 25.
\479\ APPA at 87.
\480\ FirstEnergy at 14.
\481\ PG&E at 18-19.
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iii. Commission Determination
392. We adopt the NOPR proposal and direct RTOs and ISOs to include
in their tariffs, and centralize in one section, all of their MMU
provisions. We also direct RTOs and ISOs to include a mission statement
in the
[[Page 64146]]
introductory portion of their MMU tariff section, which is to set forth
the goals to be achieved by the MMU, including the protection of both
consumers and market participants by the identification and reporting
of market design flaws and market power abuses.
393. We adopt the suggestion that RTOs and ISOs may include various
MMU provisions elsewhere in their tariff as well as in the centralized
MMU section, if they believe context and clarity so require. However,
we are sympathetic to the concern that this duplicative listing may
create confusion. Therefore, we require RTOs and ISOs, if they make
such a duplicative listing, to clearly note that the provision in
question is also found in the centralized MMU section. We also direct
the RTO or ISO to include in its tariff a provision stating that in the
event of any inconsistency between provisions in the centralized MMU
section and provisions set forth elsewhere, the provisions in the
centralized MMU section control. Of course, the RTO or ISO should
attempt to avoid any such inconsistencies.
394. We direct RTOs and ISOs to include their centralized MMU
tariff sections in their compliance filings to be made in connection
with this Final Rule.
3. Information Sharing
a. Enhanced Information Dissemination
i. Commission Proposal
395. The Commission carried forward proposals in the NOPR that had
been advanced in the ANOPR, and which were designed to enhance the
dissemination of information by MMUs in several areas. Specifically,
the Commission proposed that MMUs report on aggregate market
performance on no less than a quarterly basis to Commission staff, to
staff of interested state commissions, and to the management and board
of directors of the RTOs or ISOs. The Commission also proposed the MMUs
make one or more of their staff members available for regular
conference calls with representatives from the Commission, state
commissions and the RTO or ISO. In the NOPR, the Commission stated that
the type of information to be released by the MMU may most fruitfully
continue to be developed on a case-by-case basis, so long as it
generally consists of market analyses of the type regularly gathered by
the MMUs in the course of business, and so long as it remains subject
to appropriate confidentiality restrictions.
396. The Commission proposed that market participants be included
in the dissemination of reports, which could be accomplished via
posting them on the RTO or ISO Web site. However, the Commission stated
that including market participants on conference calls would be
unwieldy, and proposed limiting participation on such calls to
Commission staff, RTO and ISO staff, staff of interested state
commissions, and staff of state attorneys general should they express a
desire to attend.
397. While the Commission noted that quarterly reports should not
be as extensive as the annual state of the market report, it also
stated that the annual state of the market reports have proven to be
useful documents, and proposed that the RTOs and ISOs include in their
tariffs a requirement for the MMUs to produce them, with the same
dissemination (or broader, if desired) as the quarterly reports.
398. The Commission also proposed that the time period for the
release of offer and bid data be reduced to three months, but that an
RTO or ISO could propose a shorter period with accompanying
justification or, if it demonstrates a potential collusion concern, a
four-month lag period or some other mechanism to delay the release of a
report if the release were otherwise to occur in the same season as
reflected in the data.
399. Additionally, the Commission proposed to retain the practice
of masking the identity of participants when releasing offer and bid
data. The Commission further proposed that the RTO or ISO include in
its compliance filing a justification of its policy regarding the
aggregation or lack thereof of offer data and of cost data, discussing
the manner in which it believes its policy avoids participant harm and
the possibility of collusion, while fostering market transparency.
ii. Comments
400. Commenters in general support information sharing policies for
MMUs,\482\ and many commenters noted that the Commission struck a good
balance between the need for information and the limitations of the
MMUs.\483\
---------------------------------------------------------------------------
\482\ See, e.g., DC Energy; EEI; EPSA; Exelon; NEPOOL
Participants; and Northeast Utilities.
\483\ See, e.g., EEI; EPSA.
---------------------------------------------------------------------------
401. Several commenters generally support the approach of
developing the types of material to be disseminated on a case-by-case
basis.\484\ EEI supports this flexible approach as long as the
information is developed in the ordinary course of business by the MMU
and is subject to the same confidentiality restrictions that are
applied to release of information as determined by each RTO or ISO, or
the Commission.\485\ Midwest Energy comments that as regulators of
retail markets, state commissions should be aware of how the market is
functioning.\486\ New York PSC states that the Commission should
clarify that its proposed rule is the minimum standard for the
dissemination of information and the MMUs that currently provide
information to state commissions under working procedures will not be
limited by the proposal.\487\
---------------------------------------------------------------------------
\484\ See, e.g., EEI; FirstEnergy; Midwest Energy; Ohio PUC; and
PJM Power Providers.
\485\ EEI at 26.
\486\ Midwest Energy at 4-5.
\487\ New York PSC at 10.
---------------------------------------------------------------------------
402. APPA does not oppose this proposal but comments that a
provision like the one in PJM's tariff, which allows the MMU to respond
to requests for studies or reports by states, should be included in all
RTO/ISO/MMU tariff sections.\488\ PG&E believes that to the extent that
state commissions need information about markets and market monitoring
reports, it should be made clear that if the MMUs have data available
as part of their overview of markets or preparation of reports, such
data should be made available to state commissions for their use in
analysis and oversight of market efficiency and trends.\489\ Joint
Commenters support an evaluation of the type of data each RTO or ISO
should provide, stating that RTOs and ISOs can further improve their
markets by describing in their compliance filings additional
information they will disseminate.\490\ Joint Commenters urge the
Commission to require each RTO or ISO to engage in a stakeholder
process to develop a detailed document governing the identification of
the type of additional information the RTO or ISO will disseminate, and
to describe the information to be disseminated in the compliance
filing. Joint Commenters recommend that the Commission require each RTO
or ISO to apply the following criteria: (1) RTOs and ISOs should
provide information to the extent it reasonably can be expected (a) to
facilitate improved market transparency, reliability or efficiency; (b)
to assist stakeholders in detecting market design or software flaws
and/or suspected market manipulation; or (c) to assist market
participants in their transaction activity; (2) provided that (a) the
dissemination of the information will not harm the competitive dynamics
[[Page 64147]]
of the market and (b) it is feasible from a resource allocation
standpoint for the RTO to disseminate the information.\491\
---------------------------------------------------------------------------
\488\ APPA at 87.
\489\ PG&E at 20.
\490\ Joint Commenters at 5.
\491\ Id.
---------------------------------------------------------------------------
403. NARUC believes that the Commission's proposal is a mistake,
commenting that the Commission should provide explicit standards that
assure that the states have the same access to data as does the
Commission.\492\ NARUC comments that (1) by granting such access, the
Commission can leverage market oversight while, as explicitly
acknowledged in the NOPR, giving state regulators access to data they
need to fulfill their statutory responsibilities; (2) states need
underlying data imbedded in aggregate information to verify and analyze
MMU findings; and (3) states also recognize the need to protect from
public disclosure information that could harm market participants or
facilitate collusion.\493\
---------------------------------------------------------------------------
\492\ NARUC at 13-14.
\493\ Id.
---------------------------------------------------------------------------
404. Commenters support the proposal to include market participants
in the dissemination of reports.\494\ NRECA, while supporting the
proposal, is concerned that these reports may be insufficient if they
do not provide the underlying data and assumptions used by the MMU to
reach its conclusions, on the ground recipients may only be getting the
RTO's or ISO's ``spin'' on the situation. NRECA suggests that the
Commission should ensure the MMU reports provide sufficient information
or provide a process whereby stakeholders can obtain access, subject to
appropriate confidentiality restrictions, to the data and findings
underlying MMU reports.\495\ NSTAR strongly supports including market
participants in the dissemination of information on market abuses, and
states that the reporting should be transparent as a deterrent and so
market participants can assess how well the markets are working and
whether changes are necessary.\496\
---------------------------------------------------------------------------
\494\ See, e.g., APPA; California PUC; Midwest ISO; Old
Dominion; and NSTAR.
\495\ NRECA at 54-55.
\496\ NSTAR at 8.
---------------------------------------------------------------------------
405. Several commenters do not support the Commission's proposal to
limit access by market participants to conference calls.\497\ APPA
recommends that conference calls be archived and posted on the RTO or
ISO Web site for market participants who cannot be on the call.\498\
Steel Producers and TAPS comment that the exclusion of market
participants from such conference call is inappropriate, and that RTO
or ISO stakeholder conference calls with numerous participants are
commonplace.\499\
---------------------------------------------------------------------------
\497\ See, e.g., APPA; Steel Producers; and TAPS.
\498\ APPA at 88.
\499\ Steel Producers at 12; TAPS at 57.
---------------------------------------------------------------------------
406. Commenters generally supported the Commission's proposal and
conclusions regarding quarterly and state of the market reports.\500\
APPA comments that certain annual state of the market reports are both
over-inclusive with the amount of data reported and under-inclusive in
terms of relevant data provided, and that MMUs should strive for
quality as well as quantity in the data provided. EPSA supports the
Commission's conclusion that the quarterly reports should not be as
extensive as the annual state of the market reports.\501\
---------------------------------------------------------------------------
\500\ See, e.g., EPSA; California PUC.
\501\ EPSA at 14-15.
---------------------------------------------------------------------------
407. Most commenters supported the reduction in lag time for offer
and bid data to three months.\502\ Several others wanted a shorter lag
time: one month,\503\ one week or less,\504\ or immediate
disclosure.\505\ Several commenters suggested giving RTOs and ISOs
flexibility to propose shorter or longer times.\506\ Citing two
studies, APPA argues that system lambdas should be disclosed at the
same time as bid and offer data.\507\ If the Commission requires a
shorter period of time to release offer and bid data, EEI argues it
should maintain and enhance the masking and aggregation features.\508\
Although it supports the three-month period, Midwest ISO prefers
leaving the decision to the stakeholders.\509\
---------------------------------------------------------------------------
\502\ See, e.g., EEI; California PUC; Industrial Consumers; ISO
New England; Joint Commenters; Midwest ISO; North Carolina Electric
Membership; NRECA; Reliant; SCE-SDG&E; and SPP.
\503\ Industrial Consumers at 23.
\504\ TAPS at 53-56.
\505\ APPA at 89-91.
\506\ EEI at 26-27 (citing regional factors); California PUC at
44; Joint Commenters at 4; and North Carolina Electric Membership at
19 (citing the need to prevent collusion); National Grid at 9; and
SoCalEdison-SDG&E at 4.
\507\ APPA at 89-91 (citing McCullough and Stewart, Ann, The
Missing Benchmark in Electricity Deregulation, McCullough Research
(Dec. 20, 2007); Dunn, William, Data Required for Market Oversight--
A Concept Paper for the Electric Market Reform Initiative of the
American Public Power Association, Sunset Point LLC (Dec. 8, 2007)
(Dunn Study)).
\508\ As an example, bid data should be aggregated in categories
of size and the coding used to describe bidders should be changed
periodically. EEI at 26-27.
\509\ Midwest ISO at 28-29.
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408. PG&E states that it is important that information about offer
and bid data be increasingly available as prices and price caps rise,
with disclosure of bid data sufficiently timely to permit review of
bids before the necessity to undertake any challenge to such sales.
PG&E also states that there is a need for increased market transparency
when prices hit established bid or price caps, as such bidding may be
designed to manipulate market prices and take advantage of temporary
conditions. PG&E requests the Commission to consider modifying its
disclosure requirements to provide for greater market transparency for
bids at caps, with discretionary authority to disclose participants who
bid in the region of any applicable price cap.\510\
---------------------------------------------------------------------------
\510\ PG&E at 20-22.
---------------------------------------------------------------------------
409. TAPS proposes immediate disclosure, arguing that competitive
markets thrive on information, not secrecy. More information in the
hands of a larger number of competitors, in its opinion, would reduce
the likelihood of collusion. TAPS cites competitive electric markets
operating successfully in Australia, England and Wales, where the
markets provide near real-time and historical data, including bid and
offer data. TAPS also asserts that large generation-portfolio holders
already know their offers for each of their multiple resources, and
allowing RTOs or ISOs to make it available for free and more quickly
would enable smaller market participants to compete on a level playing
field and assist with market monitoring.\511\
---------------------------------------------------------------------------
\511\ TAPS at 53-56 (citing the Dunn Study).
---------------------------------------------------------------------------
410. A few commenters opposed the Commission's proposal to reduce
the lag time from six to three months.\512\ Ameren states that six
months is a more appropriate time period to protect commercially
sensitive data and guard against abuse.\513\ Constellation does not
support the reduction in lag time for release of information, but says
if the Commission decides to do so, it should apply this policy to all
areas of the market and require MMUs to post bid and offer data for
demand and virtual markets under the same confidentiality
provisions.\514\ Ohio PUC states that the entities most likely to use
the data are the market participants themselves, and believes there is
little protection offered by masking the bidders' identities. It agrees
with the Commission's analysis of the tradeoffs in reducing the lag
period.\515\
---------------------------------------------------------------------------
\512\ See, e.g., Ameren; Constellation; and Ohio PUC.
\513\ Ameren at 36.
\514\ Constellation at 17.
\515\ Ohio PUC at 28.
---------------------------------------------------------------------------
411. All but two commenters support masking participant
identity.\516\ Ameren emphasizes the need to protect sensitive
[[Page 64148]]
market data.\517\ Dominion Resources and EEI oppose unmasking, Dominion
Resources stating that masking is needed to avoid the possibility of
bid or offer fixing, collusion, or other behavior detrimental to the
market.\518\ California PUC suggests unmasking after two years; it also
proposes to change masking on January 1 of each year to prevent market
participants from being able to figure out the market participants in
current data.\519\ SPP requests guidelines from the Commission on
aggregating the data to protect the participant's identity.\520\ Ameren
proposes a mechanism where MMUs could give parties who have submitted
false or inaccurate data the opportunity to correct any inaccuracies
before the report is made final and submitted to the Commission.\521\
---------------------------------------------------------------------------
\516\ See, e.g., Ameren; California PUC; Dominion Resources;
EEI; ISO New England; Midwest ISO; SoCalEdison and SDG&E; and SPP.
\517\ Ameren at 36.
\518\ Dominion Resources at 8; EEI at 26.
\519\ California PUC at 44.
\520\ SPP at 9.
\521\ Ameren at 36-37.
---------------------------------------------------------------------------
412. Two commenters oppose masking bidders' identities. Ohio PUC
and OMS believe there is little protection offered by such masking,
arguing that the more sophisticated market participants will infer
those identities and thus gain some further advantage over less
sophisticated market participants. These commenters further assert that
allowing third-party analysts to access data would increase the number
of parties examining the bid and offer data to determine if collusive
behavior exists.\522\ APPA states that market bid and offer data should
not be kept confidential, and the term ``commercially sensitive''
should not be used as a blanket exception.\523\
---------------------------------------------------------------------------
\522\ Ohio PUC at 28; OMS at 9-10.
\523\ APPA at 93.
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iii. Commission Determination
413. We adopt the proposal made in the NOPR, with certain
modifications. The Commission's goal of broadening information sharing
by the MMUs met with widespread approval, with a number of commenters
expressing the opinion that the Commission had struck the right balance
between the need for information on the one hand while recognizing the
MMUs' inability to provide unrestricted and unlimited amounts and types
of information on the other.
414. The information to be disseminated should consist of market
trends and the performance of the wholesale market, with details to be
developed on a case-by-case basis. In response to our request for
comments on whether there were a generic standard or test that could be
used to determine what specific information should be provided to state
commissions, Joint Commenters propose a two-part test, which we find
generally helpful. However, the test does not include some of the
confidentiality protections we have determined to be necessary, and we
decline to adopt it. We also hesitate to require RTOs and ISOs to
include in their tariffs specific details of the types of information
that an MMU might find useful to provide, or that stakeholders might
request. The nature of the information that may be helpful may vary
from region to region, and may well evolve over time. Therefore, while
an RTO or ISO is free to propose in its tariff details of the
information it desires its MMU to provide, we will not require any
particular menu. We are confident that MMUs will be responsive to
reasonable requests from interested parties, subject to time and
resource commitments.
415. Moreover, the degree of inclusion of underlying data and
assumptions is an area also best dealt with on a case-by-case basis. It
is not to be expected that MMUs would include all the raw data in their
possession. However, we would expect that they would provide, or make
available on request, sufficient data to enable users of their reports
to reasonably test the validity of their conclusions.
416. We also clarify that our proposed rule is not intended to
limit existing arrangements between MMUs and state commissions
regarding the provision of information, subject to appropriate
restrictions related to confidentiality concerns. Such arrangements are
an example of the sort of case-by-case determination we envision
developing in the area of information dissemination.
417. We disagree with NARUC's suggestion that explicit standards be
put in place guaranteeing that states have the same access to data as
does the Commission. While we favor the enhanced dissemination of
information to the states, there are some matters that are uniquely
within the purview of the Commission, such as referrals by MMUs of
suspected tariff violations or manipulation. We therefore decline to
adopt such explicit standards.
418. We agree with EPSA that quarterly reports should not be as
extensive as the annual state of the market reports. It was not our
intention that MMUs should be required to spend all their time on
report preparation, which could easily be the case if quarterly reports
were too extensive. Rather, we envision such quarterly reports as
serving the function of timely updates to the annual state of the
market report, emphasizing issues of concern. The details of what
should be included in these reports can be worked out by the MMUs with
input from interested stakeholders. We also agree with APPA that
quality rather than quantity is crucial, and urge MMUs to ensure that
the data they include in both their quarterly and their annual reports
meets the anticipated needs of the extended community that will make
use of them.
419. Several commenters object to the Commission's suggestion that
market participants be excluded from conference calls regarding market
updates. They note that stakeholder conference calls are commonplace,
and see no reason why a similar practice should not be adopted with
respect to MMU briefings. Upon reflection, we agree that the current
state of the technology permits such calls with little difficulty.
Therefore, we determine that market participants should not be excluded
from such calls, absent pressing technical concerns in any given
situation.
420. Our proposal to reduce the lag time for release of offer and
bid data to three months was supported by most commenters. Some
commenters requested a shorter lag time or immediate release. Others
proposed the release of additional information, such as system lambda.
421. Our proposal cuts the current lag time for most RTOs and ISOs
in half. Because this is a substantial change, RTOs and ISOs should
become accustomed to the new release time and observe its effects
before committing to an even shorter time. However, as we proposed in
the NOPR, we permit the RTOs and ISOs to propose a shorter time, with
accompanying justification, or a longer time of four months if they can
demonstrate a collusion concern. Alternatively, they may propose an
alternative mechanism if release of a report were otherwise to occur in
the same season as reflected in the data. These options provide the
flexibility requested by commenters.
422. We assume the data to be released would consist not only of
physical offers and bids but demand and virtual offer and bids as well.
However, if RTOs and ISOs object to such inclusion, they may address it
in their compliance filings. Likewise, if they desire to release
additional data such as system lambda, they may propose it in their
filings.
423. We adopt the NOPR proposal to retain the masking of
identities. The objection that sophisticated market participants may be
able to infer identities of those submitting offers and
[[Page 64149]]
bids does not resolve confidentiality concerns; if anything, it argues
for more protection, rather than less. We decline to establish a time
period for the eventual unmasking of identities, but invite RTOs and
ISOs to propose a period when such unmasking might be permitted, if
they believe it to be desirable.
424. We therefore adopt the proposals advanced in the NOPR,
modified as indicated. Each RTO and ISO is to include in its tariff a
requirement that the MMU is to prepare an annual state of the market
report on market trends and the performance of the wholesale market, as
well as less extensive quarterly reports, all of which are to be
disseminated to Commission staff, to staff of interested state
commissions, to the management and board of directors of the RTOs or
ISOs, and to market participants, with the understanding that
dissemination may be accomplished by posting on the RTO's or ISO's Web
site. MMUs are also to make one or more of their staff members
available for regular conference calls, which may be attended,
telephonically or in person, by Commission and state commission staff,
by representatives of the RTO or ISO, and by market participants. The
information to be provided in the MMU reports and in the conference
calls may be developed on a case-by-case basis, but is generally to
consist of market data and analyses of the type regularly gathered and
prepared by the MMU in the course of its business, subject to
appropriate confidentiality restrictions. We also determine that the
lag time for the release of offer and bid data be reduced to three
months; however, an RTO or ISO may propose a shorter period with
accompanying justification. Furthermore, if the RTO or ISO demonstrates
a potential collusion concern, it may propose a four-month lag period
or, alternatively, some other mechanism to delay release of the data if
it were otherwise to occur in the same season as reflected in the data.
The identity of market participants is to remain masked, although the
RTO or ISO may propose a time period for eventual unmasking. The RTO or
ISO is to include in its compliance filing a justification of its
policy regarding the aggregation or lack thereof of offer data and of
cost data, discussing the manner in which it believes its policy avoids
participant harm and the possibility of collusion, while fostering
market transparency.
b. Tailored Requests for Information
i. Commission Proposal
425. In the NOPR, the Commission carried forward the ANOPR proposal
allowing state commissions to make tailored requests for information
from MMUs regarding general market trends and performance, not to
include information designed to aid state enforcement actions against
individual companies. The Commission also proposed that a state
commission could, on a case-by-case basis, request the Commission to
authorize the release of otherwise proscribed data, if the state
commission demonstrated a compelling need for the information and could
insure adequate protections for commercially sensitive material. The
Commission proposed that before an MMU be allowed to release
information pertaining to a particular market participant, that the
participant be given the opportunity to object and to correct any
inaccurate information proposed to be released, and that the
availability of this protection be included in the RTO or ISO tariff.
The Commission also proposed that RTOs and ISOs develop, and include in
theirtariffs, confidentiality provisions that would protect
commercially sensitive material, but which would not be so restrictive
as to permit the release of little if any information.
ii. Comments
426. Several commenters generally support the Commission's proposal
regarding tailored requests for information.\524\ APPA comments that
the Commission should not bar MMUs from providing such assistance to
the states if MMUs believe they can do so without harming their own
mission.\525\ ISO New England states it has an information policy that
already allows it to release confidential market information to state
commissions under certain circumstances and subject to non-disclosure
protections.\526\ Duke Energy is concerned with giving the MMUs too
much discretion and potentially imposing an unreasonable burden on
them, but states that the guiding parameters set out by the Commission
make the proposal more acceptable.\527\ FirstEnergy states the MMU
should share analyses and information with state commissions only when
directly necessary to support state regulatory obligations, and agrees
that tailored requests from state commissions should not detract from
the MMU's core duties and must be made in light of budget and time
limitations.\528\
---------------------------------------------------------------------------
\524\ See, e.g., PJM Power Providers; SoCalEdison-SDG&E.
\525\ APPA at 92-93.
\526\ ISO New England at 26.
\527\ Duke Energy at 11.
\528\ FirstEnergy at 16.
---------------------------------------------------------------------------
427. The California PUC agrees that requests by state commissions
should not overly burden the MMUs but comments that this need not be
the case, noting that in California, CAISO and the California PUC have
been able to work out the wording, scope and timing of the California
PUC information requests in a reasonable and cooperative manner,
including the protection of sensitive commercial information with a
nondisclosure agreement. The California PUC and PG&E also comment that
the MMU's core function of reviewing and reporting on the performance
of wholesale markets should be understood to include reporting to state
commissions, and assert that data used in making MMU assessments of
market efficiency or competitiveness, reports to CAISO management or
boards, or reports to the Commission should be available to state
commissions as well.\529\
---------------------------------------------------------------------------
\529\ See, e.g., California PUC; PG&E.
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428. EEI and Reliant support allowing the MMUs to be receptive to
requests for information, as long as the information pertains to market
trends and is developed in the ordinary course of business. EEI and
Reliant comment that it is not reasonable for the MMUs to provide new
studies or analysis beyond their annual and quarterly reports, and
assert that state commissions may not treat MMUs as private consultants
to perform studies. These commenters also assert that states have their
own enforcement programs and should not rely on the MMU. Reliant
suggests that, if a state commission requesting MMU information cannot
agree with the RTO's or ISO's confidentiality provisions, the
Commission should clarify that the MMU should not be required to
disclose information to the state commission.\530\
---------------------------------------------------------------------------
\530\ See, e.g., EEI; Reliant.
---------------------------------------------------------------------------
429. The Kansas CC agrees with the Commission's proposal not to
require MMUs to provide information to aid in state enforcement efforts
or actions against individual utilities. However, it suggests that
sensitive market information could be provided to state commissions in
a manner that would uphold the confidential nature of the information
and protect the market. The Kansas CC requests that the Commission
consider alternative solutions that will preserve confidentiality,
while providing state commissions with
[[Page 64150]]
information necessary to fulfill their statutory and regulatory
charges.\531\
---------------------------------------------------------------------------
\531\ Kansas CC at 2.
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430. The Ohio PUC, noting the interconnectedness of retail rates to
wholesale markets, proposes a test to determine the type of information
that should be disseminated to state commissions. In its view, if a
state commission asks for it, and the MMU has it or can get it without
undue burden, it should be provided subject to confidentiality
provisions.\532\
---------------------------------------------------------------------------
\532\ Ohio PUC at 27, 29.
---------------------------------------------------------------------------
431. Several commenters do not support various aspects of the
Commission's proposal on tailored requests from state commissions. The
California PUC contends that the restrictions would cripple state
market monitoring, and asks the Commission how it would distinguish
between information designed to aid state enforcement actions from
information designed to allow states to monitor the market.\533\
---------------------------------------------------------------------------
\533\ California PUC at 48-49.
---------------------------------------------------------------------------
432. NARUC states that imposing the proposed limitations on state
access to information is inefficient and unnecessary, observing that
states operate in the public interest. NARUC argues that requiring
unnecessary proceedings over specific requests, at taxpayer or
ratepayer expense, is not good policy, and asserts that state
commissions have demonstrated their ability to maintain the integrity
of commercially sensitive materials.\534\
---------------------------------------------------------------------------
\534\ NARUC at 15.
---------------------------------------------------------------------------
433. The New York PSC states that limiting its ability to obtain
such information is unnecessary and unsupported by the record in this
proceeding, contending that the Commission has not demonstrated that
providing information to state commissions for state enforcement
purposes violates any provision of law or policy, and noting that the
purpose of the information may not be apparent in any event. It
suggests that in the event the MMU is concerned about budgetary and
time limitations, it could simply provide the state commission with the
raw data and allow the state commission to employ its resources to
derive the information or analysis sought. It proposes that if a state
commission is able to maintain the information on a confidential basis,
the MMU should be allowed to determine whether to provide the requested
information.\535\
---------------------------------------------------------------------------
\535\ New York PSC at 10-12.
---------------------------------------------------------------------------
434. OMS disagrees with the Commission that its proposed
restrictions on information access by state commissions are reasonable.
It asserts that the NOPR proposal limiting state commission requests to
the MMU to ``general market trends and performance'' represents a
significant reduction in the information its members already receive in
accordance with the Midwest ISO's tariff. OMS states that the
Commission should respect the arrangement currently in place for the
Midwest ISO, and permit that arrangement to be expanded, as necessary,
to meet the need of OMS and its state commission members. OMS also
asserts that state commissions should not be put in a position of
merely having to trust the findings of the MMU, but rather, should be
provided with the data and information necessary to evaluate and verify
the MMU's findings. It also states that the Commission's proposal to
prohibit state commissions from seeking information from the MMU that
would aid state enforcement is unreasonable, as many state commissions
do not have access to the data and information necessary to initiate
investigative actions that might eventually lead to enforcement
actions.\536\
---------------------------------------------------------------------------
\536\ OMS at 13-14.
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435. Other commenters provided suggestions and points of
clarification. The FTC encourages the Commission to devise ways that
would allow MMUs to provide services to state and federal agencies even
when the MMU does not have the extra resources. For example, it
suggests that the Commission could authorize fees to be paid by state
and federal agencies for services that primarily assemble and organize
existing MMU data, which is similar to how other agencies deal with
FOIA requests.\537\ The California PUC comments it is unclear if
``information regarding general market trends and performance'' would
be limited to aggregated data or if the state commissions would also
have access to raw data. It also states that this proposal would
restrict existing access to data, and would require states to obtain
Commission authorization and make a showing of a ``compelling need''
for that information.\538\ CAISO states that the Commission should
clarify whether its proposal applies only to requests or also to
subpoenas and court orders.\539\ TAPS opposes giving state commission
staffs preferential treatment in the ability to make requests for
information from the MMU.\540\
---------------------------------------------------------------------------
\537\ FTC at 31.
\538\ California PUC at 47-48.
\539\ CAISO at 16-17.
\540\ TAPS at 57.
---------------------------------------------------------------------------
436. Several of the commenters support the provision regarding the
development of confidentiality provisions, with limitations. The
California PUC asserts that the language is too vague, and suggests it
be revised to read ``The RTO should develop confidentiality provisions
in their tariffs that will protect commercially sensitive material, but
will be no more restrictive than necessary to protect that
information.'' The California PUC also notes that the California PUC
and CAISO have an established practice for sharing market information
that preserves confidentiality of data, and argues that the proposed
limitations are unnecessary and would disrupt already existing state
access to market data.\541\
---------------------------------------------------------------------------
\541\ California PUC at 46, 49.
---------------------------------------------------------------------------
437. The Maine PUC stresses the need for a greater level of
information sharing by ISO New England with state commissions. It
proposes that where there are protections in place to ensure that
confidential information remains confidential when disclosed to a state
commission, the Commission should direct ISO New England to share
confidential information with the state commissions in the same or
similar manner to its information sharing with the Commission.\542\
---------------------------------------------------------------------------
\542\ Maine PUC at 8-9.
---------------------------------------------------------------------------
438. The Ohio PUC and PJM request clear rules and definitions
relating to confidential information. The Ohio PUC states that the
Commission should require RTOs or ISOs to revisit the definitions of
``Confidential Information'' in their tariffs, asserting that in the
cases of PJM and the Midwest ISO, confidential information is whatever
a market participant declares it to be. PJM is concerned about the
treatment of confidential information, such as cost data, particularly
in the area of aggregated data that may be ``reverse engineered.'' PJM
states that the release of these data, in conjunction with other
industry information not necessarily known or even available to PJM,
could inflict commercial harm on a market participant and adversely
impact the competitiveness of the market. PJM requests clear, bright-
line rules regarding the treatment of confidential information, noting
it must deal with large volumes of such information that frequently are
the subject of requests from numerous public and private entities.\543\
---------------------------------------------------------------------------
\543\ See, e.g. , Ohio PUC; PJM.
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439. Reliant and SPP are concerned about the treatment of
confidential materials once in the hands of the state commissions.
Reliant is of the view that
[[Page 64151]]
state commissions should be required to identify the person who will
have access to the information, the person who will be the official
custodian for the information, and the purpose for the request. It
states that a state official should be required to sign a non-
disclosure agreement as a pre-condition of receiving data and, in
situations where the state cannot guarantee data confidentiality, such
as in the case where a state's public records regulations might require
disclosure, such data should not be shared. SPP is concerned that
unless the state commission can provide proof that information can and
will be kept confidential, that SPP should not be required to provide
that information to the state commission, and asks that the Commission
address the issue of relieving the RTO or ISO from any liability.\544\
---------------------------------------------------------------------------
\544\ See, e.g., Reliant; SPP.
---------------------------------------------------------------------------
440. PJM Power Providers states that given the serious potential
consequences associated with an improper release of sensitive market
data, the Commission should go to great lengths to ensure the
confidentiality of this information.\545\
---------------------------------------------------------------------------
\545\ PJM Power Providers at 18.
---------------------------------------------------------------------------
441. Commenters generally agree with the proposal to permit market
participants the opportunity to contest any data specific to them that
the MMU proposes to release. Duke Energy supports allowing market
participants an opportunity to contest information, but comments that
market participants should also have an opportunity to respond to data
and not just contest them, as they may want to provide context to data
even if they do not wish to dispute them.\546\ FirstEnergy agrees that
affected utilities should be given notice and have the opportunity to
comment.\547\
---------------------------------------------------------------------------
\546\ Duke at 11-12.
\547\ FirstEnergy at 16.
---------------------------------------------------------------------------
442. Several commenters support the Commission's proposal to allow
state commissions to request release of data from the Commission, with
limitations or additions. EEI supports the Commission releasing data if
the state demonstrates a compelling need and cannot obtain the data
from any other source, and if the Commission can adequately protect
commercially sensitive data.\548\ APPA believes that state entities
(including commissions, state attorney generals, legislators,
governors, and relevant electric retail regulatory authorities for
public power systems) and third parties should be allowed to request
information on a case-by-case basis directly from an MMU; if the MMU
believes it can provide the needed information it should not have to go
through the Commission, and only in the event the requestor is refused
the information by the MMU, would it be necessary to petition the
Commission.\549\ Duke Energy comments that affected market participants
should have recourse to appeal an MMU decision to the Commission, just
as a requester can petition the Commission.\550\
---------------------------------------------------------------------------
\548\ EEI at 28.
\549\ APPA at 94.
\550\ Duke at 12.
---------------------------------------------------------------------------
443. Other commenters strongly oppose the Commission's proposal
regarding submitting a request for the release of otherwise proscribed
information. NARUC believes the proposal is likely to hamper proper
state oversight, and argues that the Commission should not impose a
gatekeeper function to evaluate state commission information needs or
the legitimacy of their requests. NARUC argues this can only waste both
state and federal resources and ratepayer funds on unnecessary
proceedings.\551\
---------------------------------------------------------------------------
\551\ NARUC at 15-16.
---------------------------------------------------------------------------
444. The Ohio PUC questions how enforcement can occur without
access to market information, which it argues the Commission currently
controls. It asserts that the Commission must reevaluate its position
on this matter to ensure that state commissions have timely access to
market information and possess all the necessary tools to make certain
that customers' interests are protected against market abuses and
manipulation. It also suggests that it could take entity-specific
information subject to a confidentiality agreement, and then use that
information to pursue its own discovery under state law, in order to
pursue an enforcement action.\552\ OMS states that state commissions
should not be required to petition the Commission for access to data
and information that it feels should be theirs in the first place. OMS
strongly urges the Commission to reconsider its position in this
regard.\553\
---------------------------------------------------------------------------
\552\ Ohio PUC at 35.
\553\ OMS at 14-15.
---------------------------------------------------------------------------
445. OPSI does not agree with the Commission's proposal and
recommends that any rules adopted in this proceeding reflect the data
availability practices established in the PJM/MMU Settlement Agreement.
iii. Commission Determination
446. The enhanced information sharing provisions we adopt in this
Final Rule significantly expand the materials that state commissions
may receive. However, we are cognizant that state commissions might
from time to time desire additional information pertinent to their
particular needs. Therefore, we adopt the NOPR proposal that state
commissions may make tailored requests for information from the MMUs,
so long as the request is limited to information regarding general
market trends and the performance of the wholesale market. This
limitation is needed in light of the limited resources of the MMUs,
whose first order of business is evaluating market design, monitoring
the markets, and referring suspected wrongdoing to the Commission. If
this limitation were not imposed, the MMU could rapidly become an
unpaid consultant for the states, and would be unable to perform its
core functions.
447. We are cognizant of the observations by EEI and Reliant that
state commission requests for information, which would necessarily be
in addition to the information already produced in the MMUs' annual and
quarterly reports, may place an unreasonable burden on the MMUs. We
therefore direct that the MMUs, in the first instance, determine
whether a request would be unduly burdensome. If so, it need not
perform the requested study.
448. Many comments centered on the need for the confidentiality of
the materials provided by the MMU, and the means by which
confidentiality concerns could be addressed. Inasmuch as the material
to be provided in response to tailored requests for information will
consist of market trends and the performance of the wholesale market,
such confidentiality concerns may not prove to be as great a stumbling
block as some suggest. Where information to be provided raises
confidentiality concerns, the information may nonetheless be provided,
if appropriate non-disclosure agreements are executed. We direct the
RTOs and ISOs to develop confidentiality provisions for their tariffs,
and adopt the California PUC suggestion that such provisions be
designed so as to protect commercially sensitive material, but be no
more restrictive than necessary to protect that information. It will be
up to each RTO or ISO, together with its stakeholders, to propose the
confidentiality provisions they deem most appropriate, and to propose
them to the Commission in a tariff filing.
449. We note that our directive regarding the ability of state
commissions to make tailored requests for information is designed to
increase the dissemination of information, not
[[Page 64152]]
restrict it. As we have indicated elsewhere, the type of information to
be provided by the MMU may vary from region to region, and is governed
principally by the workload such requests impose on the MMU. Therefore,
unless the information violates confidentiality restrictions regarding
commercially sensitive material, is designed to aid state enforcement
actions, or impinges on the confidentiality rules of the Commission
with regard to referrals, it may be produced, so long as it does not
interfere with the MMU's ability to carry out its core functions.
450. We decline to require MMUs to turn over raw data if they do
not have the time to comply with a tailored request for information. If
the MMU determines that raw data may be provided, appropriately
redacted to meet confidentiality concerns, it may do so. However, it is
quite possible that gathering, organizing, reviewing, and explaining
such data might prove nearly as time consuming as responding in a
narrative fashion to a request for information. The MMU is not a
consultant for the states, and should not be placed in the position of
having to respond to every request for information submitted to it.
451. We also decline to eliminate our restriction on the state
commissions' ability to request information designed to aid state
enforcement actions. Of course, if a state receives information
regarding general market performance, and chooses to pursue a more
focused study with its own resources, there is no prohibition to its
doing so. The key considerations here are the burden placed on the MMU,
the nature of the material to be provided, and the need for
confidentiality. The MMU will be in the best position to determine if
the material requested would be unduly burdensome to produce. And the
RTO or ISO confidentiality provisions, as well as those of the
Commission, will govern whether the state commission can receive
information of a confidential nature.
452. A state commission need not turn an MMU into an arm of its
investigatory processes in order to carry out its duties. If a state
has information suggesting the need for an investigation, it can use
the full panoply of its powers and resources to pursue the matter on
its own. We know from long experience that investigations are very time
and resource-intensive, and were states to enlist the MMU's assistance
in this regard, it would leave the MMU with little ability to carry out
its core functions.
453. We note, however, that from time to time Commission staff
investigates matters of mutual interest to state commissions. It has
been staff's practice to work cooperatively with the states in such
cases, bearing in mind the confidentiality of materials obtained by
Commission staff in the course of an investigation. We direct staff to
continue its practice in this regard.
454. Whether requested information is designed to aid an
enforcement action can generally be answered by the particularized
nature of the request and the extent of the questions. As we have
stated, the information to be provided in response to a tailored
request for information should consist of market trends and the
performance of the wholesale market. At least one comment reinforces
the need for caution in this regard. The comment suggested that a state
body could take entity-specific information subject to a
confidentiality agreement and then use that information to pursue its
own discovery. This end run around the confidentiality provisions might
raise liability concerns on the part of both the MMU and the RTO or
ISO, and possibly the Commission itself, and underscores the need to be
sensitive to requests designed to support enforcement actions.
455. We adopt the NOPR proposal that market participants be given
the opportunity to contest any data specific to them. We also adopt the
proposed expansion of this provision to include the right to provide
context to the data, so long as the process does not unduly delay
release of the information.
456. CAISO asks that we clarify whether our proposal applies only
to requests or also to subpoenas and court orders. We clarify that our
proposal applies to requests. Whether subpoenas or court orders are to
be honored or contested lies outside the scope of this Final Rule and
is a matter to be addressed by the MMU and by the RTO or ISO, in
consultation with their attorneys.
457. We decline to adopt the FTC's suggestion that state and
federal agencies be given the ability to obtain data from the MMU
through the payment of fees. Such a fee arrangement could raise
conflict of interest concerns. More significantly, however, it would
reduce the MMU to the position of a consultant for hire, a role which
would necessarily distract it from its core functions.
458. We also adopt our NOPR proposal permitting state commissions
to petition the Commission for the release of otherwise proscribed
information. This provision is intended as a safety net to increase the
ability of states to receive information, not as a further restriction.
State commissions are free to direct their requests to the MMUs in the
first instance, but such requests should comply with the restrictions
we note above. If they do not, waiver of such restrictions is up to the
Commission, not to the MMUs.
459. Therefore, we carry forward our proposal from the NOPR,
modified as noted herein. MMUs are to entertain from state commissions
tailored requests for information regarding general market trends and
the performance of the wholesale market, but not for information
designed to aid state enforcement actions. Granting or refusing such
requests will be at the MMU's discretion, based on agreements worked
out between the RTO or ISO and the states, or otherwise based on time
and resource availability. Release of any confidential information is
to be subject to the confidentiality provisions in the RTO's or ISO's
tariff, and to the Commission's confidentiality restrictions. RTOs and
ISOs are to develop confidentiality provisions that will protect
commercially sensitive material, but which will be no more restrictive
than necessary to protect that information. State commissions are also
free to petition the Commission for the release of information that
does not fall within the parameters noted. And market participants are
free to contest the factual content of information to be released, or
to provide context for it, so long as such material does not unduly
delay release of the information.
c. Commission Referrals
i. Commission Proposal
460. In the NOPR, the Commission noted that its rules require that
information regarding its investigations be kept nonpublic unless, in
any given case, the Commission authorizes that it be publicly
disclosed. We proposed that the existing provisions regarding the
confidentiality of MMU referrals to the Commission, as well as the
confidentiality of the progress and results of its own investigations,
be retained. The Commission also noted that it intended to continue the
practice of Commission staff providing the MMUs with generic feedback
regarding enforcement issues.
ii. Comments
461. Several commenters support the Commission's proposal.\554\
APPA also suggests that the Commission has the obligation to act as
quickly as possible, so other government entities with a
[[Page 64153]]
legitimate interest in the matter are kept informed.\555\ ISO New
England comments that the proposed referral provisions are generally
consistent with, but more detailed than, ISO New England's existing
rules concerning the obligation of its MMU to identify and report on
market design flaws and to refer potential market manipulation to the
Commission.\556\
---------------------------------------------------------------------------
\554\ See, e.g., APPA, EEI, Midwest ISO, Reliant, and SPP.
\555\ APPA at 94.
\556\ ISO New England at 27.
---------------------------------------------------------------------------
462. Many commenters urge the Commission to reconsider its position
that state commissions not be informed when an MMU refers a matter to
the Commission.\557\ Some commenters assert that several states
maintain sufficient safeguards against public disclosure of
information, and any assumptions regarding the potential mishandling of
confidential information are misdirected and should be discounted.\558\
The California PUC and NRECA comment that the Commission should provide
information to the MMUs and state commissions about matters an MMU has
referred to the Commission, because it would help increase confidence
that the Commission investigates attempts to manipulate the
market.\559\ The Ohio PUC maintains that there must be a free exchange
of market data among the RTO or ISO, the MMU, and state commissions to
ensure markets are flourishing and to avoid manipulation.\560\
---------------------------------------------------------------------------
\557\ See, e.g., California PUC, NARUC, New York PSC, NRECA,
Ohio PUC, and OMS.
\558\ See, e.g., New York PSC, Ohio PUC, and OMS.
\559\ California PUC at 52-53.
\560\ Ohio PUC at 32.
---------------------------------------------------------------------------
463. NARUC comments that the Commission should inform affected
state commissions of MMU referrals because the commissions need
information about specific market participants both to properly
exercise their own regulatory authority and to avoid potentially
inconsistent outcomes and duplicative efforts.\561\ The New York PSC
comments that it is vital that state commissions be able to demonstrate
that the presence of a competitive market does not disable the state
from protecting retail ratepayers, and that the state commission is
capable of carrying out its statutory obligation in a competitive
market.\562\
---------------------------------------------------------------------------
\561\ NARUC at 16.
\562\ New York PSC at 13-15.
---------------------------------------------------------------------------
464. NRECA believes that an appropriate balance can be struck with
respect to information and emphasized that it is not seeking the
release of the names of individual entities or any competitively
sensitive information but is merely requesting statistical information
on, for example, numbers of entities referred, types of infractions,
and the resolution of referrals.\563\ OMS comments that state
commissions could be effective allies with the Commission in the
investigation and evaluation of the market participant behavior that
led the MMU to make the referral, and the Commission's concern that
informing state commissions of MMU referrals might discourage market
participants from self-reporting objectionable behavior is not
applicable to MMU referrals, as these referrals happen only because a
market participant has failed to self-report.\564\
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\563\ NRECA at 56.
\564\ OMS at 11.
---------------------------------------------------------------------------
iii. Commission Determination
465. We adopt the NOPR proposal retaining the confidentiality of
MMU referrals to the Commission, as well as the confidentiality of any
investigations that result from such referrals. By Commission rule, all
information and documents obtained during the course of an
investigation are non-public. They may not be released except to the
extent the Commission directs or authorizes in a given instance, unless
the material is already made public during an adjudicatory proceeding
or disclosure is required by the Freedom of Information Act.\565\ There
are sound policy reasons for this rule. As we noted in the NOPR,
release of such confidential information would impede the willingness
of market participants to cooperate in the investigation and to self-
report in the future. It could also injure innocent persons who might
be erroneously implicated or adversely affected by simply being
associated with an investigation.
---------------------------------------------------------------------------
\565\ 18 CFR 1b.9.
---------------------------------------------------------------------------
466. The Commission can only answer for its own abilities to keep
material confidential, and cannot put itself in the position of having
to interpret the extent of protections afforded by all the relevant
state rules, statutes, and case law that govern disclosure. Nor can it
expose itself to the potential liability it might incur by turning over
confidential materials, should such materials be misused by agencies or
individual state employees over whom the Commission has no control.
467. We also are not persuaded that release of information about
MMU referrals would avoid potentially inconsistent outcomes and
duplicative efforts. For that to be true, one would have to assume that
the scope of jurisdiction and the governing laws of the states in
question are identical to those of the Commission, which is clearly not
the case.
468. We are sympathetic to NRECA's request for statistical
information, and agree that, to the extent we can make our enforcement
actions more transparent, it is desirable to do so. To that end, we
recently announced that the staff of the Office of Enforcement will
prepare and publicly release annual reports summarizing its enforcement
activities for the preceding year, to be released at the close of our
fiscal year, September 30.\566\ The first such report was released on
November 14, 2007.\567\ In addition, it is the practice of Commission
staff to provide the MMU with generic feedback regarding enforcement
issues, and we will ensure that staff continues to do so.
---------------------------------------------------------------------------
\566\ Revised Policy Statement on Enforcement, 123 FERC ]
61,156, at P 12 (2008).
\567\ Report on Enforcement, Docket No. AD07-13-000 (2007).
---------------------------------------------------------------------------
469. We therefore decline to alter our rule and policy regarding
the confidential nature of MMU referrals to the Commission.
4. Pro Forma Tariff
a. Commission Proposal
470. In the NOPR, the Commission declined to propose a pro forma
tariff for the MMU sections of an RTO or ISO OATT, instead proposing
that RTOs and ISOs conform their tariffs to the requirements set forth
in this Final Rule. The Commission also proposed that each RTO or ISO
include protocols for the referral of tariff, rule, and market
manipulation violations to the Office of Enforcement, and for the
referral of perceived market design flaws and recommended tariff
changes to the Office of Energy Market Regulation.
b. Comments
471. A limited number of entities filed comments on the
Commission's proposal. The Midwest ISO agrees that requiring each RTO
or ISO to conform its tariff to the requirements of the Final Rule is
preferable to a pro forma tariff.\568\ EEI agrees that the Commission
has appropriately permitted RTOs and ISOs flexibility to tailor their
market monitoring provisions to their own regional variations.\569\
APPA suggests that the Commission use, as a possible template for the
relevant tariff provisions, the revised Attachment M to the PJM tariff
approved in the PJM MMU Settlement Order.\570\ SPP believes that it
already complies with the majority of the proposals the
[[Page 64154]]
Commission has set forth in this proceeding, but will comply with any
revisions that may be required by the Final Rule.\571\
---------------------------------------------------------------------------
\568\ Midwest ISO at 27.
\569\ EEI at 24.
\570\ PJM MMU Settlement Order, 122 FERC ] 61,257.
\571\ SPP at 10.
---------------------------------------------------------------------------
472. The California PUC, on the other hand, states that it does not
support a pro forma tariff because of its objections to several of the
MMU proposals in the NOPR, particularly the issues surrounding state
access to data.\572\
---------------------------------------------------------------------------
\572\ California PUC at 53.
---------------------------------------------------------------------------
c. Commission Determination
473. Given the degree of discretion this Final Rule allows RTOs and
ISOs to structure their relationship with their MMUs in the manner they
deem most suitable, a pro forma MMU tariff section would be
impractical. Therefore, we will not impose one.
474. We also decline to adopt PJM's MMU tariff section, Attachment
M, as a template for a centralized MMU tariff section. That document is
particularized to the needs of that RTO, and we therefore will not
require other RTOs and ISOs to follow it. We agree, however, that some
uniformity is desirable, particularly for market participants who
operate in multiple regions, and for regulators who often have occasion
to compare and contrast tariff provisions amongst the various RTOs and
ISOs.
475. We therefore suggest, but do not require, that RTOs and ISOs
consider structuring their MMU tariff sections to include the following
general categories, preferably in this general order: Introduction and
Purpose; Definitions; Independence and Oversight; Structure; Duties of
Market Monitor; Duties of RTO or ISO; Data Access, Collection, and
Retention; Information Sharing; Ethics; RTO- or ISO-Specific
Provisions; Protocol on Referrals of Investigations to the Office of
Enforcement; Protocol on Referrals of Perceived Market Design Flaws and
Recommended Tariff Changes to the Office of Energy Market Regulation.
476. We note that in our Policy Statement on Market Monitoring
Units,\573\ we prescribed the form and contents of an MMU referral to
the Office of Enforcement. We likewise include in this Final Rule
updated protocols for such referrals, as well as protocols for
referrals to the Office of Energy Market Regulation of perceived market
design flaws and recommended tariff changes.
---------------------------------------------------------------------------
\573\ Policy Statement, 111 FERC ] 61,267 at Appendix A.
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D. Responsiveness of RTOs and ISOs to Customers and Other Stakeholders
477. In this section of the Final Rule, the Commission requires
RTOs and ISOs to establish a means for customers and other stakeholders
to have a form of direct access to the board of directors, and thereby
to increase the boards of directors' responsiveness to these entities.
(By responsiveness, we mean an RTO or ISO board's willingness, as
evidenced in its practices and procedures, to directly receive concerns
and recommendations from customers and other stakeholders, and to fully
consider and take actions in response to the issues that are raised.)
The Commission requires each RTO or ISO to submit a compliance filing
demonstrating that it has in place, or will adopt, practices and
procedures to ensure that its board of directors is responsive to
customers and other stakeholders. The Commission will assess each RTO's
or ISO's filing using four criteria: (1) Inclusiveness; (2) fairness in
balancing diverse interests; (3) representation of minority positions;
and (4) ongoing responsiveness.
478. The Commission also directs each RTO and ISO to post on its
Web site its mission statement or organizational charter. The
Commission encourages each RTO and ISO to set forth in these documents
the organization's purpose, guiding principles, and commitment to
responsiveness to customers and other stakeholders, and ultimately to
the consumers who benefit from and pay for electricity services.
1. Background
479. Neither Order No. 888 \574\ nor Order No. 2000 \575\ mandated
specific RTO board governance requirements. In Order No. 2000, the
Commission stated that, given the early stage of RTO formation, it
would be counterproductive to impose a one-size-fits-all approach to
governance when RTOs may have varying structures based on their
regional needs.\576\ Therefore, the Commission indicated that it would
review governance proposals on a case-by-case basis.\577\ The
Commission also emphasized the importance of stakeholder input
regarding both the creation of RTOs and ongoing operations.\578\ The
Commission added that, in the case of a non-stakeholder board, it is
important that the board not become isolated.\579\
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\574\ Promoting Wholesale Competition Through Open Access Non-
Discriminatory Transmission Services by Public Utilities; Recovery
of Stranded Costs by Public Utilities and Transmitting Utilities,
Order No. 888, FERC Stats. & Regs. ] 31,036 (1996), order on reh'g,
Order No. 888-A, FERC Stats. & Regs. ] 31,048, order on reh'g, Order
No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g, Order No. 888-C,
82 FERC ] 61,046 (1998), aff'd in relevant part sub nom.
Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (DC
Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002).
\575\ Regional Transmission Organizations, Order No. 2000, FERC
Stats. & Regs. ] 31,089 (1999), order on reh'g, Order No. 2000-A,
FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Pub. Util. Dist.
No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (DC Cir.
2001).
\576\ The Commission noted that existing ISOs have varying forms
of governance. Some used a two-tier form of governance with a non-
stakeholder board and advisory committees of stakeholders while one,
CAISO, employed a decision making board consisting of both
stakeholders and non-stakeholders. Order No. 2000-A, FERC Stats. &
Regs. at 31,073.
\577\ Id. at 31,073-74.
\578\ Id.
\579\ Id.
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480. In the ANOPR, the Commission noted stakeholders' concerns that
RTOs and ISOs are not sufficiently responsive to customers and other
stakeholders, and that those parties should have some form of effective
direct access to the RTO or ISO board of directors.\580\ The Commission
inquired whether RTOs and ISOs should be required to create and
institute practices and procedures to ensure that customers and other
stakeholders have such access.\581\ The Commission also made a
preliminary proposal that the goal of enhancing customer and other
stakeholder access to the board could be achieved by either a board
advisory committee or a hybrid board.\582\
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\580\ ANOPR, FERC Stats. & Regs. ] 32,617 at P 148.
\581\ Id. P 149.
\582\ Id. P 151, 153. The Commission explained that a hybrid
board would be composed of both independent members and stakeholder
members, with each member holding a seat on the board and
participating fully in board decisions with an equal vote. Id. P
152.
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2. Commission Proposal
Responsiveness Obligation and Proposed Criteria
481. In the NOPR, the Commission proposed to require that customers
and other stakeholders have some form of effective direct access to the
RTO or ISO board of directors. The Commission indicated that while it
viewed the board advisory committee as particularly suitable for
enhancing responsiveness, it anticipated that each RTO or ISO and its
stakeholders would develop practices and procedures that best suit
their needs.\583\ The Commission reiterated its position that a one-
size-fits-all approach may not be beneficial given the varying
structure and needs of each regional entity. It therefore proposed to
establish a set of four criteria for RTOs and ISOs designed to ensure
that RTO and ISO
[[Page 64155]]
boards are responsive to their customers and other stakeholders.\584\
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\583\ Id. P 277.
\584\ NOPR, FERC Stats. & Regs. ] 32,628 at P 275.
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482. In order to demonstrate that RTOs and ISOs meet the
responsiveness obligation, the Commission proposed to require each one
to submit a compliance filing showing that it has in place or will
adopt practices and procedures to ensure responsiveness. The Commission
proposed to assess the filed practices and procedures of each RTO and
ISO using four criteria:
Inclusiveness--The business practices and procedures must
ensure that any customer or other stakeholder affected by the operation
of the RTO or ISO, or its representative, is permitted to communicate
its views to the RTO's or ISO's board of directors.
Fairness in Balancing Diverse Interests--The business
practices and procedures must ensure that the interests of customers or
other stakeholders are equitably considered and that deliberation and
consideration of RTO and ISO issues are not dominated by any single
stakeholder category.
Representation of Minority Positions--The business
practices and procedures must ensure that, in instances where
stakeholders are not in total agreement on a particular issue, minority
positions are communicated to the RTO's or ISO's board of directors at
the same time as majority positions.
Ongoing Responsiveness--The business practices and
procedures must provide for stakeholder input into the RTO's or ISO's
decisions as well as mechanisms to provide feedback to stakeholders to
ensure that information exchange and communication continue over time.
483. The Commission proposed that each RTO or ISO compliance filing
would be required to be submitted within six months of the date the
Final Rule is published in the Federal Register, and stated that it
would assess whether each filing satisfies the proposed requirement and
issue additional orders as necessary.\585\
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\585\ Id. P 92.
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3. Comments
484. Most of the commenters support the Commission's proposal and
the four responsiveness criteria that the Commission proposed in the
NOPR.\586\ Many also express support for the Commission not proposing a
one-size-fits-all solution, but instead allowing regions flexibility in
meeting the criteria.\587\ The comments fall loosely into three
categories: (1) Whether to establish an obligation for responsiveness;
(2) whether the four responsiveness criteria are appropriate or need
greater specificity; and (3) whether additional criteria should be
required.
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\586\ See, e.g., Ameren; Comverge; Constellation; EEI; Exelon;
Indianapolis P&L; Midwest ISO; New York PSC; NYISO; PJM; and PG&E.
\587\ See, e.g., Ameren; ATC; Constellation; Midwest ISO; NYISO;
PJM; and SoCal Edison-SDG&E.
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485. Among the RTOs and ISOs, CAISO, Midwest ISO, NYISO, PJM and
SPP argue that they already have responsiveness policies that they
believe satisfy the Commission's proposed criteria. Some stakeholders
concur that their RTO's or ISO's policies meet the proposed
criteria.\588\ APPA is skeptical that the proposals would have any
effect, arguing that the RTOs and ISOs would likely say that their
practices are already sufficiently responsive.\589\
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\588\ See Ameren and ATC discussing Midwest ISO; California PUC
discussing CAISO; New York PSC discussing NYISO; and NEPGA, NEPOOL
and NU discussing ISO New England.
\589\ APPA at 9, 97.
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486. Many commenters present examples of RTO or ISO practices that
are not fully effective. For example, IID notes that during
consideration of CAISO's proposal to subsidize the financing of certain
interconnection facilities, CAISO did not adopt any of the specific
tariff language IID recommended or sufficiently explain why it was
rejecting so many of IID's suggestions.\590\ TANC opines that time
frames for stakeholder review of CAISO initiatives are too short and
therefore appear to diminish the value of stakeholder input. As a
result, TANC submits that the Commission should require RTOs and ISOs
to employ methods of interacting with stakeholders that are intended to
achieve consensus on issues and that incorporate stakeholders early in
the decision-making process.\591\
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\590\ IID at 5.
\591\ TANC at 12.
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487. Connecticut and Massachusetts Municipals encourage the
Commission to not solely rely on an inclusive stakeholder process to
ensure that organized wholesale electric markets and market
administrators are providing, or facilitating the provision of,
reliable electric service at the lowest reasonable cost. They do not
agree that developing a stakeholder process that meets the four
criteria will alleviate the need for the Commission to conduct its own
investigation into the justness and reasonableness of proposed rates,
charges, market rules, and design changes.\592\
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\592\ Connecticut and Massachusetts Municipals at 9-10.
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488. Several commenters make recommendations about the four
criteria proposed by the Commission. For instance, Ameren urges the
Commission to make sure that the third criterion, representation of
minority positions, is not allowed to outweigh the second criterion,
fairness in balancing diverse interests. One way to do this, Ameren
argues, would be to ensure that entities that will ultimately incur a
major portion of the costs related to the changes to RTO or ISO market
rules have a proportionate say in the development of these rules and
any related modifications, through bicameral voting.\593\
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\593\ Ameren at 15-16, 37-40.
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489. TAPS asserts that the balancing criterion invites greater
deference to well-represented classes to the detriment of other
customers that the FPA requires the Commission to protect. CAISO
requests that the Commission consider clarifying one of the four
proposed criteria, fairness in balancing diverse interests, regarding
how an RTO or ISO would be expected to establish generically that the
consideration given to diverse interests is equitable.\594\
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\594\ CAISO at 10.
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490. Constellation asks the Commission to clarify its definition of
the term ``customer'' in its statement that ``access by customers and
other stakeholders to the board based on these criteria will provide
them with the opportunity to ensure that their concerns are
considered.'' It states that the term customer could be applied to non-
jurisdictional entities such as retail customers, and the Commission
has already ensured that state agencies that regulate the retail market
have access to RTO and ISO boards.\595\
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\595\ Constellation at 19.
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491. Other commenters recommend more detail regarding the
application of the proposed criteria. For example, APPA suggests new
mandates for RTO and ISO stakeholder processes to help meet the
proposed criteria: \596\ Mandated direct stakeholder access to RTO and
ISO boards at frequent intervals; presentation of minority positions on
RTO and ISO proposals directly to the board by minority stakeholders;
consideration of the use of both stakeholder advisory committees and
hybrid boards; open RTO and ISO board meetings, with agendas made
public in advance and opportunity for stakeholder comment on agenda
items;
[[Page 64156]]
elimination of ``self-perpetuating'' RTO and ISO boards; directors
elected by stakeholder vote, with multiple candidates for each seat and
stakeholder input into the slate selection; and administration of
customer satisfaction surveys by outside entities. ATC wants a
formalized mechanism within an RTO's or ISO's main stakeholder
committee for communicating minority views of stakeholder sectors to an
RTO's or ISO's board of directors.
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\596\ APPA at 10, 102.
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492. SMUD states that RTOs and ISOs should be required to
demonstrate that: (1) There is evenly divided industry sector
representation, (2) no one sector (or entity) can dominate the process,
(3) votes are taken to measure stakeholder sentiment, (4) there is a
formal process for the RTO or ISO to consider adoption of stakeholder
initiatives and (5) before the RTO or ISO can reject a stakeholder
position supported by a supermajority of stakeholders, it must
articulate its reasons in writing, including in any filing it makes
with the Commission.\597\
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\597\ SMUD at 9.
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493. Others suggest new criteria for improving responsiveness, such
as providing opportunities for customer and other stakeholder feedback
on budgets and costs. The Maine PUC argues that ISO New England has
insufficient cost incentives, and that the Commission should consider
requiring RTOs and ISOs to place a stronger emphasis on cost-
containment in administration and development of wholesale electric
markets.\598\ North Carolina Electric Membership and NRECA suggest an
additional criterion: Reliable service at just and reasonable rates.
According to NRECA, the Commission's goals in creating RTOs and ISOs
require that these entities ensure accountability to stakeholders for
keeping costs down while maintaining a high level of service quality.
NRECA also states that the Commission should require RTOs and ISOs to
present annual budget information to customers and stakeholders, along
with adequate detail, transparent assumptions and calculations of
estimates, and cost support. It further recommends that the Commission
require RTOs or ISOs with formula rates to develop their budget
presentations for stakeholders and customers using the format required
for a filing with the Commission to change previously approved rates.
NRECA states that the RTO's or ISO's budgeting process should ensure
that customers and other stakeholders have a timely opportunity for
review of the budget proposals offered and that each RTO or ISO should
submit to the Commission, as an informational filing, all of the budget
materials provided to stakeholders for review.\599\
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\598\ Maine PUC at 8.
\599\ NRECA at 59.
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494. Ameren suggests that RTOs and ISOs should be required to post
longer-term budgets, such as five-year budgets, so that market
participants can better monitor the costs and benefits of participating
in RTO and ISO Day 2 markets.\600\ NRECA states that the NOPR is silent
with respect to the matter of transparency in RTO and ISO budgets. Old
Dominion also requests that the Commission reinstate the proposals
contained in the ANOPR that would have improved transparency in the
budget process.\601\
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\600\ Ameren at 15-16, 37-40.
\601\ Old Dominion at 5.
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495. Some commenters ask for a formal cost-benefit review of any
significant action. Connecticut and Massachusetts Municipals request
that the Commission require RTOs and ISOs to perform cost-benefit
studies in support of proposed rates, charges, and related rules.
FirstEnergy also recommends that significant new RTO or ISO proposals
should require a formal cost-benefit analysis before being submitted to
the stakeholder process. If these proposals are implemented, they
argue, post-implementation cost-benefit analyses should be employed to
see if actual benefits have materialized. RTO or ISO initiatives that
fail to produce stakeholder benefits or achieve their stated objectives
should be modified, or if necessary, rescinded.\602\ LPPC also suggests
that the Commission should require cost-benefit analyses to be filed in
conjunction with any significant capital expenditures or tariff
changes. These cost-benefit analyses would be submitted with the annual
budgets for approval by the Commission in the case of capital
expenditures, or with section 205 filings for tariff changes.\603\
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\602\ FirstEnergy at 17.
\603\ LPPC at 19.
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496. Other commenters want improvements regarding notice of
meetings and time to review new proposals. TANC asserts that the
Commission should set minimal standards as to what constitutes
sufficient notice for convening stakeholder meetings and conference
calls, for the submission of stakeholder comments, and for subsequent
consideration of those comments prior to the RTO or ISO taking
action.\604\ ATC calls for a minimum amount of time afforded to
stakeholders to review and provide suggestions and feedback on final
versions of RTO or ISO filings before they are submitted to the
Commission. California Munis suggests that unless there is a physical
threat to system reliability or an exigent market condition, no
stakeholder meeting should be held without two weeks, and preferably
four weeks, minimum notice. It also argues that major market design and
policy meetings should not be held the same day, and preferably not on
back-to-back days. It further suggests that policy white papers should
be available no less than two weeks before the relevant stakeholder
meeting.
---------------------------------------------------------------------------
\604\ TANC at 13.
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497. Other commenters want feedback from the RTO or ISO on how
their views were taken into account in the decision-making process. ATC
calls for establishment of a formal ``feedback loop'' that would
provide greater transparency in how stakeholder views are received,
reviewed, and considered in an RTO's or ISO's decision-making process.
TANC argues that the Commission should require RTOs and ISOs to explain
how they considered comments during their decision-making
processes.\605\ TANC also asks the Commission to require the RTO or ISO
to answer specific questions that would describe the stakeholder
process employed for developing tariff revisions, and how customer and
other stakeholder concerns were rectified.
---------------------------------------------------------------------------
\605\ Id. at 20.
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498. Other commenters call for periodic reviews of the
effectiveness of stakeholder processes. LPPC suggests having a periodic
survey of customer satisfaction. ATC recommends that RTOs and ISOs be
required to submit annual reports to the Commission detailing their
adherence to the proposed responsiveness criteria. These reports would
provide the Commission with an ongoing mechanism for assessing whether
an RTO or ISO is following its approved practices for adhering to the
Commission's responsiveness criteria, whether those practices maintain
their effectiveness in meeting stakeholders' needs, and whether these
practices should be changed.\606\ California Munis believes that RTOs
and ISOs should be required to make a regular showing to the Commission
reviewing their stakeholder processes. NSTAR also encourages the
Commission to require RTOs and ISOs to undergo a periodic, independent
review of its stakeholder processes including sector membership
qualifications, voting weights, and other measures. It contends that
the Commission should oversee the review rather than leave it to the
stakeholders. This review and recommendation
[[Page 64157]]
should then be used to make constructive changes to the stakeholder
processes to ensure that all parties are properly represented.\607\
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\606\ ATC at 10.
\607\ NSTAR at 11.
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499. Other commenters want RTOs and ISOs to adopt one another's
best practices. For example, NRECA states that the Commission should
add a criterion for RTOs and ISOs to follow best practices. NRECA
describes the PJM liaison committee meeting process, which allows for
direct board access by requiring board member attendance at such
meetings, and criteria for vote reporting. NRECA further states that
requiring board member participation in substantive committee meetings
would provide opportunity for improved communications between
stakeholders and the board.\608\
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\608\ NRECA at 60.
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500. Other commenters have further suggestions for improving
responsiveness to the needs of customers and other stakeholders. Joint
Commenters urge the Commission to adopt three additional requirements
for RTOs and ISOs to include in their compliance filings: (1) Improved
dissemination of information, (2) well-designed independent operational
audits of RTOs and ISOs with stakeholder input, and (3) clarification
of the need to adhere to manuals and market rules except under clearly
predefined circumstances.\609\ LPPC suggests requiring the annual
publication of a strategic plan.
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\609\ Joint Commenters at 3.
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4. Commission Determination
501. Based on the various aspects of the proposed responsiveness
criteria that the comments address, we discuss three topics in order:
Whether to establish an obligation for responsiveness and whether the
four responsiveness criteria are appropriate; whether the criteria need
greater specificity; and whether additional criteria should be
required.
a. Responsiveness Obligation and Appropriateness of the Four
Responsiveness Criteria
502. The Commission adopts its proposal from the NOPR and
establishes by rule an obligation for each RTO and ISO to make reforms,
as necessary, to increase its responsiveness to the needs of customers
and other stakeholders. As further detailed below, each RTO and ISO
must explain in a filing to the Commission how it is fulfilling, or
will fulfill, this obligation. The Commission will assess each RTO's or
ISO's filing using the responsiveness criteria discussed below.
503. Although some commenters argue that this requirement is not
needed or that RTOs and ISOs are already sufficiently responsive, we
find this requirement necessary. For those RTOs and ISOs that may
already be satisfying customer needs adequately, this formal
requirement will help to focus the attention of RTO and ISO boards and
senior management on improvements in this area of great concern to
their customers and other stakeholders. As RTOs and ISOs developed, the
Commission emphasized that their decision-making processes must be
independent of control of any market participant or class of
participants. RTO and ISO independence remains fundamental, and we will
preserve it; however, we find that RTOs and ISOs must provide an avenue
for customers and other stakeholders to present their views on RTO and
ISO decision-making, and to have those views considered. Establishing
practices and procedures that would allow RTO and ISO boards to be
responsive to the concerns of customers and other stakeholders is
important to providing these entities with confidence in RTOs' and
ISOs' independent governance processes.
504. We will adopt the four responsiveness criteria as proposed in
the NOPR. Based on the comments received, we conclude that each of the
four criteria has a role in helping us to assess each separate
dimension of responsiveness. We also require each RTO and ISO to submit
a compliance filing demonstrating how it is responsive to customers and
other stakeholders, and we will assess each demonstration based on the
four criteria adopted herein.
505. In adopting the four criteria, we have carefully sought to
balance customers' and other stakeholders' need for effective access to
the boards of RTOs and ISOs, with the need for the independent
management of each RTO and ISO. Upon consideration of the comments, the
Commission finds that the four criteria are appropriate, balanced, and
suitably tailored to improve the responsiveness of RTOs and ISOs to
customers and stakeholders.
506. The first criterion, inclusiveness, is intended to ensure that
existing or newly-developed practices and procedures, are adequate to
bring the views of all customers or other stakeholders before the
board. Meeting this criterion will demonstrate that the RTO or ISO
actively provides for presenting customer and other stakeholder issues,
concerns, or proposals to its boards.
507. The second criterion, fairness in balancing diverse interests,
requires that each RTO and ISO ensures that its practices and
procedures for decision making consider and balance the interests of
their customers and stakeholders, and ensures that no single
stakeholder group can dominate. This is necessary to ensure that the
RTO or ISO may make well-informed decisions that reflect the full range
of competing interests that may be affected.
508. The third criterion, representation of minority interests to
the RTO and ISO boards, is also critical to ensure that customers and
other stakeholders have confidence in the decisions that come out of
RTO and ISO processes. This criterion will ensure that the minority
views of customers and stakeholders are forwarded, at the same time as
the majority views, to the boards during the deliberation process. The
Commission has often been notified that RTO and ISO decisions have been
made based only on the single view of the majority vote. While the
Commission will not intrude on the governance and decision-making
process of RTO and ISO boards and management, it will require that
those processes provide for appropriate consideration of minority
interests.
509. Finally, through the fourth criterion, ongoing responsiveness,
the Commission will require that RTOs and ISOs continue over time to
consider customer and other stakeholder needs as the architecture or
market environment of the RTO or ISO changes. This criterion is
necessary to ensure that responsiveness continues into the future. As
with the overall operations of each RTO and ISO, responsiveness to
customers and other stakeholders should continually be evaluated for
improvement.
510. In response to comments, we clarify that compliance with each
criterion must not diminish or limit the requirements for compliance
with the remaining criteria. For example, in response to Ameren, we
note that the third criterion does not mandate that minority interests
overrule majority decisions, rather it requires that the board be made
aware of the minority position where necessary. Taken together, the
criteria require that RTO and ISO boards be fully aware of the
positions of customers and other stakeholders to ensure that issues are
fully and fairly vetted.
[[Page 64158]]
b. Specificity of the Responsiveness Criteria
511. While some commenters state that the four responsiveness
criteria should be more specific,\610\ others support the criteria as
proposed, and we conclude that the Commission struck the appropriate
balance in the NOPR. The Commission's approach in addressing the
responsiveness of RTO and ISO boards is to create a regulatory
obligation for RTOs and ISOs to provide greater access in order to
better serve the needs of customers and other stakeholders, and to
leave the detailed implementation of this obligation for the RTOs and
ISOs to work out with their own customers and other stakeholders.
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\610\ See, e.g., APPA; ATC; California Munis; NRECA; and SMUD.
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512. As was discussed in the NOPR, and the ANOPR prior to that,
during the evolution of RTOs and ISOs, the Commission has allowed each
RTO and ISO to develop the necessary operational practices that best
suit the needs of its customers and other stakeholders. Differing
market designs, governance structures, and existing stakeholder
processes should be balanced with the need for independent decision
making to provide the greatest benefits to customers and other
stakeholders. To create a more expansive set of one-size-fits-all rules
would undo that long-held determination.
513. As a result, we do not agree with those commenters who contend
that the criteria should be made more specific or set out in more
detail. To the contrary, the requirements in this Final Rule will
achieve the Commission's goal: RTOs and ISOs will be obligated to
demonstrate that they are responsive to the needs of customers and
other stakeholders through a direct collaboration among the RTOs and
ISOs and their constituencies. Therefore, to specify how an RTO or ISO
would be expected to demonstrate compliance with the criteria, as
requested by some commenters, would not be consistent with our stated
objective in this section of the Final Rule. Upon each RTO's or ISO's
submittal of its compliance filing, parties will be free to raise
responsiveness issues specific to each RTO or ISO that they believe
have not been resolved satisfactorily. With regard to Constellation's
request, we clarify that we define ``customer'' as is defined in the
RTO's or ISO's tariff.
514. Each RTO or ISO should consider in a collaborative process
prior to the submittal of compliance filings the issues or methods that
customers and other stakeholders want to raise that they believe will
be helpful in satisfying the responsiveness criteria. As suggested in
comments filed on the NOPR, such issues and/or methods may include, but
need not be limited to, changes of stakeholder processes, board
selection methodologies, and monitoring and reporting on the
effectiveness of the RTO or ISO in meeting the responsiveness criteria.
c. Additional Criteria
515. We do not agree that additional criteria for responsiveness
are necessary at this time. Many of the criteria commenters propose
would require specific mandates from the Commission on items that could
be resolved by RTOs and ISOs through their own stakeholder procedures.
For example, establishing cost-containment requirements or requiring
the application of cost/benefit analyses for each RTO or ISO decision
in and of themselves are not measures of responsiveness, but rather are
practices and procedures that are best developed through the
collaborative efforts of each RTO or ISO and their respective customers
and other stakeholders. Our objective in requiring RTOs and ISOs to
demonstrate their responsiveness to customers and other stakeholders is
to ensure that the RTOs and ISOs, in collaboration with their customers
and other stakeholders, work toward developing regional solutions
suited to the region's needs.
5. Board Advisory Committee and Hybrid Board
516. In the NOPR, the Commission emphasized that various approaches
may satisfy the responsiveness criteria and encouraged each RTO or ISO
to develop an approach that best suits its own governance structure and
stakeholder needs. The Commission asked for comments on two proposed
approaches for achieving board responsiveness--a board advisory
committee composed of stakeholders and a hybrid board that includes
both independent and stakeholder members. The Commission indicated that
a board advisory committee would be a particularly strong approach to
improving RTO and ISO responsiveness.\611\
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\611\ NOPR, FERC Stats. & Regs. ] 32,628 at P 277.
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a. Comments
517. Commenters generally express support for the board advisory
committee as a method of ensuring board responsiveness.\612\ They argue
that the advisory committee is the better method of balancing the
interests of stakeholders without sacrificing the independence of RTO
or ISO boards. Others argue, however, that advisory boards do not
always allow for meaningful input from stakeholders because they do not
have decisional authority.
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\612\ See, e.g., DRAM at 27; Duke Energy at 2-3; Exelon at 16-
17; FirstEnergy at 17; ITC at 12-13; Midwest ISO at 38; NARUC at 19;
Old Dominion at 5; OMS at 17-18; Pennsylvania PUC at 20; PJM Power
Providers at 12 (board liaison committee); and Steel Producers at
14.
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518. National Grid urges the Commission to resist the inclination
to micromanage RTO and ISO governance structure. It states that
stakeholders who voluntarily participate in an RTO or ISO should be
able to develop their own governance.\613\ National Grid states that
the governance structures already in place among RTOs and ISOs are
products of stakeholder agreements and the Commission should not
overturn these compromises.\614\
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\613\ National Grid at 9.
\614\ Id. at 10.
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519. Several RTOs and ISOs note their support for the advisory
board concept by pointing to their own existing advisory boards. For
example, the Midwest ISO's Advisory Committee consists of 23
representatives from nine stakeholder groups. The Advisory Committee is
required to consider separately any measure that is the product of a
close vote in committee.\615\ PJM states that it successfully worked
with its stakeholders to develop and implement a Liaison Committee in
2007. PJM describes the Liaison Committee structure as an attempt to
respect the Board's independence in decision making while ensuring
accountability and clear communication with the membership.\616\
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\615\ Midwest ISO at 38.
\616\ PJM at 8.
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520. Commenters provide several suggestions to the Commission on
how best to structure an advisory board. NARUC suggests that the
Commission require that these advisory committees have open positions
for state commissions and state consumer advocates.\617\ PJM Power
Providers recommends that the Commission encourage RTOs or ISOs that
select an advisory board approach to recognize diversity as an
essential attribute for compliance with the Commission's criteria.
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\617\ NARUC at 19.
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521. PJM Power Providers also suggests that representation on the
advisory board should be subject to term limits to ensure diversity
over time.\618\ PJM Power Providers urges that the Commission encourage
representation on the advisory board to be limited to
[[Page 64159]]
a defined period with rotating membership. PJM Power Providers
recommends that no entity or its affiliates be permitted to have more
than one representative on the board advisory committee simultaneously.
The Midwest ISO TOs suggest that the advisory committee structure be
changed so that transmission owners have a percentage of votes
commensurate with the costs they would bear on major expenditures. DRAM
agrees with the use of a representative board advisory committee and
supports equal representation for demand resources.\619\ IID recommends
the establishment of an advisory committee to the CAISO Board
comprising voluntary representatives from neighboring balancing
authority areas bordering or internal to the CAISO.\620\
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\618\ PJM Power Providers at 11.
\619\ DRAM at 27.
\620\ IID at 8-9.
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522. ATC suggests that the Commission should require stakeholder
sector representatives to explain the degree to which a vote they cast
was supported by their sector's members, and why any minority within a
sector disagreed with the majority position. ATC also recommends that
RTOs and ISOs and their stakeholders should be allowed to propose
exactly how sectors' minority views on main stakeholder committee votes
should be conveyed to RTO and ISO boards.\621\
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\621\ ATC at 9. IID also suggests that the Commission's
oversight would be aided by requiring RTOs and ISOs to report both
majority and minority stakeholder positions to the Commission when
they file proposed changes to their rates and tariffs.
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523. Others comment on board selection and composition. The
Pennsylvania Commission suggests that the Commission may wish to
increase board responsiveness to stakeholders through modifications to
the board nominating and selection process. It says that one approach
might be to require that all board nominees be selected from an outside
consultant's list by a nominating committee that is largely or entirely
composed of stakeholder representatives, and/or representatives of the
states that the RTO or ISO serves. The Pennsylvania Commission further
offers that the Commission should consider prohibiting RTO or ISO
management from being part of, or participating in the deliberations
of, the board member nominating committee; this will avoid obligating
board members to management for their nomination or retention.\622\
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\622\ Pennsylvania PUC at 19.
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524. NSTAR states that while there are requirements for business
and technical expertise to serve on the ISO New England board, there is
no requirement that any of the members have any experience serving the
customers who ultimately pay for the entire market. As a result, NSTAR
requests that the Commission consider providing guidance on the
composition of boards to include more consumer representatives.\623\
The Ohio Commission recommends that the Commission require each RTO and
ISO to include on its board at least one individual with extensive
state regulatory experience.\624\ Moreover, it states that the
Commission should compel the RTO's or ISO's board to work with the
relevant regional state advisory committee.
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\623\ NSTAR at 10.
\624\ Ohio PUC at 38.
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525. Regarding hybrid boards, commenters are split on whether a
hybrid board represents a valid approach to ensuring board
responsiveness. Some commenters argue that a hybrid board is a good
alternative to a board advisory committee, and would provide a good way
for stakeholders to have input on RTO and ISO decision making. Many
more commenters, however, argue that the Commission should not allow
hybrid boards. They point to the potential to endanger the independence
of the RTO or ISO board and to create conflict of interest for
stakeholder board members.
526. TAPS supports the hybrid board approach and says that, with
adequate protections, appropriately structured hybrid boards are a
better means of achieving a responsive, accountable RTO or ISO than
another board advisory committee of stakeholders.\625\ TAPS also notes
that, by making stakeholders vested partners in board decision making,
hybrid boards can change the dynamic of the RTO or ISO, which, it
claims, often pits stakeholders against the RTO or ISO. Industrial
Consumers also support the hybrid board approach, and suggest that
stakeholder members be split equally between representatives of
supplier and consumer interests.\626\
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\625\ TAPS at 64.
\626\ Industrial Consumers at 24.
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527. Other commenters object to the idea of hybrid boards.
Industrial Coalitions state that hybrid boards would be unlikely to
provide adequate representation for end-use customers, and would
further diminish customers' already limited voice in RTO and ISO
governance. Industrial Coalitions argue that the proposed criteria for
hybrid boards are not sufficient to prevent conflicts of interest on
the part of board members.\627\ Also, NARUC argues that a hybrid board
conflicts with the goal of RTO and ISO independence, and would be
unwieldy and ineffective.\628\
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\627\ Industrial Coalitions at 24-32.
\628\ NARUC at 18-19.
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528. Duke Energy argues that hybrid boards could create the
appearance of, and provide the opportunity for, undue preference in
favor of stakeholder board members.\629\ ITC argues that mandating or
allowing hybrid boards would be a mistake, as this would sacrifice RTO
and ISO independence. ITC states that as long as the Commission allows
hybrid boards, there will be tremendous pressure on RTOs and ISOs to
form a hybrid board, or else be seen as being ``unresponsive'' by
stakeholder groups. ITC argues that hybrid boards would violate the
principles outlined in Order No. 890, and would allow stakeholders with
no interest in new development to block transmission projects. ITC also
states that hybrid boards will make it more difficult to develop
appropriate transmission pricing systems; for example, stakeholder
board members may seek to serve their own interests through allocation
of new project costs to others.
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\629\ Duke Energy at 2-3.
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529. The Pennsylvania PUC also notes concern regarding stakeholder
board members when the board may be required to review competitively
sensitive information in making decisions. It states that it is unclear
how, or whether, non-independent members would be prevented from
reviewing such material.\630\
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\630\ Pennsylvania PUC at 18.
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530. FirstEnergy opposes giving particular stakeholder
constituencies preferential rights or privileges under the name of
responsiveness, and states that attempts by state commissions to
elevate their stakeholder status to advice and approval over RTO or ISO
initiatives represent a serious threat to RTO and ISO
independence.\631\
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\631\ FirstEnergy at 17.
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531. OMS argues that allowing market participants to hold seats on
an RTO or ISO board would jeopardize independence. OMS explains that
stakeholder board members can be expected to act in the interests of
the companies with which they are affiliated.\632\ OMS is also
concerned that the members of a hybrid board would create directors
unable to fully and fairly exercise their business judgment
[[Page 64160]]
consistent with general corporate governance law.\633\
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\632\ OMS at 15.
\633\ Id. at 15-16.
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532. PJM concurs that hybrid boards are a poor solution given the
legal and practical pitfalls associated with these structures.\634\ PJM
concludes that the NOPR does not demonstrate how the inherent conflicts
in fiduciary duties (as well as issues of access to confidential data)
would be resolved through a hybrid board structure.\635\
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\634\ PJM at 9.
\635\ Id. at 10.
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533. The California PUC is sympathetic to the Commission's
objectives to improve customer access to RTO and ISO boards of
directors and believes that the Commission's proposal of flexibility on
this issue is appropriate. However, it states that the requirement that
RTOs and ISOs establish a board advisory committee is preferred over
the hybrid board approach and the CAISO already has such a mechanism in
place and could easily demonstrate to the Commission that it already
satisfies the objectives of the NOPR on this issue.\636\ The California
PUC also states that it is questionable whether the Commission has the
legal authority to take the type of actions to reform RTO and ISO
boards of directors that are being considered in the NOPR and urges the
Commission to proceed only by means of an RTO- or ISO-specific
adjudicative process under section 206 of the Federal Power Act. It
states that the creation of a hybrid board of directors would violate
Order Nos. 888 and 2000, and that the Commission lacks legal authority
to impose any reform pertaining to the makeup of the board of directors
of a state-created ISO.\637\
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\636\ Id. at 56.
\637\ California PUC at 54.
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b. Commission Determination
534. The Commission will not require RTOs or ISOs to adopt a
specific form of board structure--whether board advisory committee,
hybrid board, or other--in this rule or when evaluating their
compliance filings to determine whether their existing or proposed
structures and procedures are appropriately responsive to customers and
other stakeholders. The Commission agrees with commenters that a one-
size-fits-all approach is not appropriate, given the different needs of
each region. As the Commission noted in the NOPR, it views the board
advisory committee as a particularly strong mechanism for enhancing
responsiveness, and expects each RTO and ISO to work with its
stakeholders to develop the mechanism that best suits its needs.
535. The Commission will not require, as proposed by the Ohio
Commission, that at least one member of RTO or ISO boards have state
regulatory experience. Similarly, the Commission will not require, as
proposed by NARUC, that board advisory committees have open positions
for state commissions and state consumer advocates. However, these
suggestions may be considered by RTOs and ISOs during their own
deliberations on compliance with this Final Rule.
536. In response to the comments of California PUC, the Commission
notes that the approach adopted in this Final Rule to require each RTO
or ISO to submit a compliance filing demonstrating that it has in place
or will adopt practices and procedures to ensure that its board of
directors is responsive to customers and other stakeholders is within
its jurisdictional authority.\638\ The Commission is not mandating a
specific approach such as a hybrid board of directors in this
rulemaking, but is instead establishing a responsiveness objective that
each RTO or ISO may meet in its own way.
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\638\ See Order No. 2000, FERC Stats & Regs ] 31,089 at 31,039.
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537. Several commenters argue that the Commission should not allow
hybrid boards for legal or practical reasons, including concerns over
the independence of RTO and ISO boards. The Commission denied similar
requests to disallow hybrid boards in Order No. 2000, noting that RTOs
take many different forms to reflect the various needs of each
region.\639\ The Commission found that a case-by-case review of each
RTO board structure was best, with the general guidance that any board
including market participants should ensure that no one class would be
allowed to veto a decision reached by the rest of the board and that no
two classes could force through a decision that is opposed by the rest
of the board.\640\ We choose to follow our decision on hybrid boards in
Order No. 2000 here. As the Commission has found in other
circumstances, a hybrid governance structure may be constructed in a
way that allows for the expertise of various groups to inform the
decision-making process, while still remaining independent such that no
individual market participant is given undue influence over the
decisions of the board.\641\ Our ruling here is not meant to imply that
all hybrid board structures are acceptable. RTOs or ISOs wishing to
adopt a hybrid board will have to show in their compliance filings that
their proposals are consistent with the principles of Order No. 2000
and other relevant precedent. Commenters are free to raise any specific
objections to a hybrid board proposal in response to the RTO's or ISO's
compliance filing, and the Commission will be able to determine the
validity of those objections against a concrete proposal from the RTO
or ISO, if any such proposal is made.
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\639\ Id. at 31,073-74.
\640\ Id.
\641\ See Western Systems Coordinating Council, 96 FERC ]
61,348, at 62,296 (2001) (approving a hybrid board for WECC). While
the WECC is not an RTO, the Commission applied a similar standard to
the formation of the WECC board as it applied to RTOs in Order No.
2000.)
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6. Supermajority Requirement
538. In the NOPR, the Commission requested comment on whether RTOs
and ISOs should be encouraged (or required) to base their process for
selecting non-independent members of a board advisory committee, or the
board itself, on a supermajority vote of eligible stakeholders.
a. Comments
539. The few commenters that address the issue are split on whether
the Commission should require members of advisory boards or hybrid
boards to be chosen by a supermajority of stakeholders. Some commenters
are skeptical of using a supermajority. Others, such as Steel
Producers, believe that it could be beneficial for ensuring that
minority perspectives are heard, as those elected to the board by a
supermajority would be more likely to be responsive to viewpoints
beyond those of their own company or stakeholder segment. Steel
Producers argue that a supermajority voting requirement would provide
``minority'' stakeholders a meaningful voice and prevent one group of
stakeholders from selecting a disproportionate number of board
members.\642\
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\642\ Steel Producers at 14.
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540. A few commenters suggest that supermajority requirements may
be more useful for choosing representatives for specific market
sectors; members of each market sector would be allowed to choose their
own representatives by a supermajority rather than having voting among
the RTO or ISO as a whole.\643\ Other commenters argue that the
Commission should leave the decision on whether to require a
supermajority to regional preference.
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\643\ See APPA; California Munis.
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541. On the other hand, Comverge is concerned that the use of a
supermajority vote to choose board
[[Page 64161]]
representatives would make it difficult to reconcile minority positions
with demand response interests and suggests that the Commission
consider support for separate board advisory committees that are
intended primarily to represent demand response and demand-side
resources.\644\
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\644\ Comverge at 24.
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542. Xcel believes that the Commission should narrowly define
``stakeholder'' to ensure that a stakeholder is not simply any person
in the room. For example, in some organized markets, e.g., the Midwest
ISO, the advisory structure permits each stakeholder sector to ballot
only within its own sector, which reduces the risk of one sector
dominating the overall ballots.\645\
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\645\ Xcel at 14.
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543. SMUD indicates that its comments on the ANOPR urged adoption
of requirements that: (1) The RTO or ISO give stakeholders a formal
voting process to express their views, and (2) the RTO or ISO explain
when it ignores supermajority sentiments.\646\ SMUD claims that the
NOPR's more vague requirements are insufficient; thus specific
directives should be set forth in any final action.
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\646\ Id. at 12.
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544. PJM suggests that a supermajority requirement is not a
necessary or sufficient one, and argues that the Commission should
instead encourage RTOs or ISOs that choose to establish an advisory
board to recognize diversity as an essential attribute for compliance
with the Commission's guidelines.
545. Finally, ITC notes that a supermajority requirement, as
suggested in the NOPR, may or may not be beneficial for hybrid boards
and would further politicize the board selection process. Additionally,
ITC argues that because advisory committees do not have decision making
authority, a supermajority would not be necessary or appropriate for
choosing advisory committee members.\647\
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\647\ ITC at 12-13.
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b. Commission Determination
546. The Commission will leave it to each RTO or ISO, in
consultation with its customers and other stakeholders, whether to
select by supermajority vote members of any board advisory committee or
any non-independent board member. When determining whether to implement
a supermajority requirement, RTOs and ISOs should consider the goals of
achieving a voice for minority interests while also having a workable
process.
7. Posting Mission Statement or Organizational Charter on Web Site
547. In the NOPR, the Commission proposed to require that each RTO
and ISO post on its Web site a mission statement or charter for its
organization. The Commission encouraged each RTO and ISO to set forth
in either the mission statement or the organizational charter its
purpose, guiding principles, and commitment to responsiveness to
customers and other stakeholders, and ultimately to the consumers who
benefit from and pay for electricity services.
a. Comments
548. Most commenters who discuss the topic indicate that they
support the Commission's proposed requirement for RTOs or ISOs to post
a mission statement or organizational charter on their Web sites. Both
CAISO and NYISO report that they already post mission statements on
their Web site.\648\
----------------------------------------