Document ID: FERC-2007-1163-0005
Agency: ferc
Document Type: Rule
Title: Wholesale Competition in Regions With Organized Electric Markets
Posted Date: 2008-10-28T04:00Z

[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]                         

[[Page 64099]]

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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......................................

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         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

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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

[[Page 64103]]

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

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

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

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

    \44\ Midwest Energy at 3.
    \45\ Id.
---------------------------------------------------------------------------

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

    \46\ Reliant at 4.
    \47\ Allied Public Interest Groups at 4.
---------------------------------------------------------------------------

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

    \48\ Public Interest Organizations at 4.
    \49\ Id. at 13-14.
    \50\ Allied Public Interest Groups at 7.
---------------------------------------------------------------------------

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

    \51\ TAPS at 9.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    \90\ Ameren at 18.
    \91\ BP Energy at 14.
---------------------------------------------------------------------------

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

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

    \95\ Steel Producers at 4-5.
---------------------------------------------------------------------------

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

    \96\ California PUC at 13-14.
---------------------------------------------------------------------------

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

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

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

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

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

    \109\ California DWR at 12-13.
---------------------------------------------------------------------------

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

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

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

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

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

    \158\ NEPOOL Participants at 14.
---------------------------------------------------------------------------

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

    \159\ Constellation at 6.
    \160\ Id. at 7.
    \161\ Id. at 6-7.
---------------------------------------------------------------------------

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

    \162\ NOPR, FERC Stats. & Regs. ] 32,628 at P 77.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

[[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.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

    227. TAPS states that the fourth approach appears to allow market-
clearing prices to be set by the RTO or ISO at whatever payment an RTO 
or ISO makes to a demand response resource that reduces consumption 
during emergencies in return for a contractually established payment 
that, perhaps, was determined by a regulatory body other than the 
Commission and, therefore, would be outside of the Commission-approved 
market-clearing mechanism and on that basis rejects it.\318\ Comverge 
believes that the fourth approach presents two issues: (1) Participants 
are likely to ignore the market value of demand response before an 
emergency is declared; and (2) the emergency value of demand response 
would be substituted for the market value of power, which may reinforce 
the use of demand resource as an emergency-only resource.\319\ 
Similarly, Duke Energy states that this proposal is questionable 
because it would be difficult to determine exactly what price would be 
paid to non-demand response market participants, and the program price 
paid to participating demand response resources may not actually 
reflect these participants' or other parties' economic assessment of 
the hourly value of power. Emergency demand response resources do not 
submit bids, but just receive a payment, against which they must judge 
the cost of forgoing energy. Because there is no solicitation of value 
from resources, it would be difficult and unreliable to determine a 
single price that would be suitable both for the interrupted emergency 
demand response providers and for payment to other resource 
providers.\320\ Mr. Borlick gives approach four the most favorable 
review on the basis that it creates an incentive of demand response to 
bid its true interruptible cost and, therefore is more likely to 
produce economically efficient prices.\321\
---------------------------------------------------------------------------

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

    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\
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    \343\ NOPR, FERC Stats. & Regs. ] 32,628 at P 128.
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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\
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    \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.
---------------------------------------------------------------------------

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

    \352\ EEI at 18.
---------------------------------------------------------------------------

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

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

    \354\ Midwest ISO at 14-15.
---------------------------------------------------------------------------

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

    \355\ NYISO at 3.
---------------------------------------------------------------------------

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

    \356\ SPP at 6.
---------------------------------------------------------------------------

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

    \357\ California PUC at 20.
---------------------------------------------------------------------------

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

    \358\ Old Dominion at 16-19.
---------------------------------------------------------------------------

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

    \359\ California DWR at 37.
---------------------------------------------------------------------------

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

    \360\ Public Interest Organizations at 8.
---------------------------------------------------------------------------

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

    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).
---------------------------------------------------------------------------

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

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

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

    \367\ Id. P 155.
    \368\ Id. P 156-57.
---------------------------------------------------------------------------

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

    \369\ Id. P 158.
---------------------------------------------------------------------------

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

    \370\ Id. P 159.
---------------------------------------------------------------------------

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

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

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

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

    \384\ Midwest ISO at 19.
---------------------------------------------------------------------------

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

    \385\ NEPOOL Participants at 20.
---------------------------------------------------------------------------

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

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

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

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

    \389\ California PUC at 28 (citing 16 U.S.C. 824o(i)).
---------------------------------------------------------------------------

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

    \390\ PJM at 3-4.
---------------------------------------------------------------------------

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

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

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

    \393\ See Price Discovery in Natural Gas and Electric Markets, 
104 FERC ] 61,121, at P 38 (2003).
---------------------------------------------------------------------------

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

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

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

    \396\ Market Monitoring Units in Regional Transmission 
Organizations and Independent System Operators, 111 FERC ] 61,267 
(2005) (Policy Statement).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

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

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

    \401\ Ameren, California PUC, EEI, EPSA, FirstEnergy, and North 
Carolina Electric Membership.
---------------------------------------------------------------------------

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

    \402\ PG&E at 14-15.
---------------------------------------------------------------------------

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

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

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

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

    \409\ APPA at 80-81; Ohio PUC at 23.
---------------------------------------------------------------------------

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

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

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

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

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

    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).
---------------------------------------------------------------------------

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

    \417\ Ohio PUC at 16-21.
---------------------------------------------------------------------------

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

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

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

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

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

    \432\ APPA; Reliant.
    \433\ APPA at 83.
    \434\ Reliant at 12-13.
---------------------------------------------------------------------------

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

    \435\ California PUC; EPSA; and Midwest ISO.
    \436\ California PUC at 36-37.
---------------------------------------------------------------------------

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

    \437\ APPA; NRECA; NSTAR; Old Dominion; PJM; and SPP.
    \438\ APPA at 83-84.
---------------------------------------------------------------------------

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

    \439\ Old Dominion at 21-22.
---------------------------------------------------------------------------

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

    \440\ Policy Statement, 111 FERC ] 61,267 at Appendix A.
---------------------------------------------------------------------------

    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\]
---------------------------------------------------------------------------

    \441\ Id. P 1.

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

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

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

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

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

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

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

    \456\ Indianapolis P&L at 4.
    \457\ OMS at 8-9.
---------------------------------------------------------------------------

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

    \458\ SoCal Edison-SDG&E at 4.
    \459\ PG&E at 17.
---------------------------------------------------------------------------

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

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

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

    \466\ APPA at 84-85.
---------------------------------------------------------------------------

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

    \467\ Potomac Economics at 8-10.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

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

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

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

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

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

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

    \583\ Id. P 277.
    \584\ NOPR, FERC Stats. & Regs. ] 32,628 at P 275.
---------------------------------------------------------------------------

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

    \585\ Id. P 92.
---------------------------------------------------------------------------

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

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

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

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

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

    \590\ IID at 5.
    \591\ TANC at 12.
---------------------------------------------------------------------------

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

    \592\ Connecticut and Massachusetts Municipals at 9-10.
---------------------------------------------------------------------------

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

    \593\ Ameren at 15-16, 37-40.
---------------------------------------------------------------------------

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

    \594\ CAISO at 10.
---------------------------------------------------------------------------

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

    \595\ Constellation at 19.
---------------------------------------------------------------------------

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

    \596\ APPA at 10, 102.
---------------------------------------------------------------------------

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

    \597\ SMUD at 9.
---------------------------------------------------------------------------

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

    \598\ Maine PUC at 8.
    \599\ NRECA at 59.
---------------------------------------------------------------------------

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

    \600\ Ameren at 15-16, 37-40.
    \601\ Old Dominion at 5.
---------------------------------------------------------------------------

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

    \602\ FirstEnergy at 17.
    \603\ LPPC at 19.
---------------------------------------------------------------------------

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

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

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

    \606\ ATC at 10.
    \607\ NSTAR at 11.
---------------------------------------------------------------------------

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

    \608\ NRECA at 60.
---------------------------------------------------------------------------

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

    \609\ Joint Commenters at 3.
---------------------------------------------------------------------------

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

    \610\ See, e.g., APPA; ATC; California Munis; NRECA; and SMUD.
---------------------------------------------------------------------------

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

    \611\ NOPR, FERC Stats. & Regs. ] 32,628 at P 277.
---------------------------------------------------------------------------

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

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

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

    \613\ National Grid at 9.
    \614\ Id. at 10.
---------------------------------------------------------------------------

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

    \615\ Midwest ISO at 38.
    \616\ PJM at 8.
---------------------------------------------------------------------------

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

    \617\ NARUC at 19.
---------------------------------------------------------------------------

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

    \618\ PJM Power Providers at 11.
    \619\ DRAM at 27.
    \620\ IID at 8-9.
---------------------------------------------------------------------------

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

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

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

    \622\ Pennsylvania PUC at 19.
---------------------------------------------------------------------------

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

    \623\ NSTAR at 10.
    \624\ Ohio PUC at 38.
---------------------------------------------------------------------------

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

    \625\ TAPS at 64.
    \626\ Industrial Consumers at 24.
---------------------------------------------------------------------------

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

    \627\ Industrial Coalitions at 24-32.
    \628\ NARUC at 18-19.
---------------------------------------------------------------------------

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

    \629\ Duke Energy at 2-3.
---------------------------------------------------------------------------

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

    \630\ Pennsylvania PUC at 18.
---------------------------------------------------------------------------

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

    \631\ FirstEnergy at 17.
---------------------------------------------------------------------------

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

    \632\ OMS at 15.
    \633\ Id. at 15-16.
---------------------------------------------------------------------------

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

    \634\ PJM at 9.
    \635\ Id. at 10.
---------------------------------------------------------------------------

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

    \636\ Id. at 56.
    \637\ California PUC at 54.
---------------------------------------------------------------------------

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

    \638\ See Order No. 2000, FERC Stats & Regs ] 31,089 at 31,039.
---------------------------------------------------------------------------

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

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

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

    \642\ Steel Producers at 14.
---------------------------------------------------------------------------

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

    \643\ See APPA; California Munis.
---------------------------------------------------------------------------

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

    \644\ Comverge at 24.
---------------------------------------------------------------------------

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

    \645\ Xcel at 14.
---------------------------------------------------------------------------

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

    \646\ Id. at 12.
---------------------------------------------------------------------------

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

    \647\ ITC at 12-13.
---------------------------------------------------------------------------

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

    \648\ CAISO at 12; NYISO at 18.
---------------------------------------------------------------------------

    549. Other commenters provide additional thoughts on RTO and ISO 
mission statements on a more general level. Constellation also supports 
having a requirement that each RTO and ISO publish a mission statement 
setting forth the organization's purpose, guiding principles, and 
commitment to responsiveness to customers and other stakeholders. It 
advocates that the mission statement should reflect and include the 
minimum characteristics and functions that the Commission has required 
for each RTO and ISO in Order No. 2000.\649\
---------------------------------------------------------------------------

    \649\ Constellation at 19.
---------------------------------------------------------------------------

    550. North Carolina Electric Membership requests that the 
Commission require RTOs and ISOs revisit their mission statements to 
ensure that the statements are consistent with the Order No. 2000 core 
objectives. It asserts that paramount among the core objectives should 
be the twin goals of facilitating open access to the transmission grid 
and providing reliable electric service at an affordable cost to 
consumers. North Carolina Electric Membership adds that the mission 
statements should also set forth defined roles for the RTO and ISO 
boards and management, as well as defined roles for stakeholders in 
accomplishing the objectives set forth in those statements. Old 
Dominion also sees value in defining within the mission statement the 
roles of the board, RTO and ISO management and stakeholders to provide 
the clarity necessary to be sure that the organization is aligned with 
the RTO's and ISO's mission.\650\
---------------------------------------------------------------------------

    \650\ Old Dominion at 5.
---------------------------------------------------------------------------

    551. NRECA and Old Dominion argue that RTOs and ISOs should be 
required to include their mission statements in their tariffs and that 
the mission statements should include a focus on lowering costs for 
transmission and wholesale power customers. NRECA notes that absent 
from the mission statements currently posted on many RTO and ISO Web 
sites is a focus on ensuring that overall costs to consumers are 
consistent with the objective of ensuring just and reasonable rates for 
consumers.\651\
---------------------------------------------------------------------------

    \651\ NRECA at 62.
---------------------------------------------------------------------------

    552. Steel Producers note that an RTO's or ISO's mission statement 
and/or charter should not be utilized by the RTO and ISO, its 
stakeholders, or market participants to limit the range or scope of 
potential issues that the RTO or ISO and/or its respective stakeholder 
group(s) may need to address. They conclude that mission statements and 
charters should provide guidance, but should not foreclose discussion 
and action on pertinent matters of interest.\652\
---------------------------------------------------------------------------

    \652\ Steel Producers at 14-15.
---------------------------------------------------------------------------

    553. TAPS asserts that ``the Final Rule should require each RTO to 
file a mission statement that makes it accountable to consumers for 
meeting the purposes of the Federal Power Act.'' \653\ TAPS argues that 
the Federal Power Act's purpose is to ensure that electricity consumers 
pay the lowest prices possible for reliable service. TAPS concludes 
that by establishing consumer value as a core goal for RTOs and ISOs, 
the Commission would align the goals of these regional organizations 
with the objectives of state regulators, federal policy makers, and 
consumers.
---------------------------------------------------------------------------

    \653\ TAPS at 60.
---------------------------------------------------------------------------

    554. SMUD states that the NOPR failed to further discuss the issue 
of whether RTOs and ISOs should be required to publish a strategic 
plan, as was raised in the ANOPR. SMUD avers, however, that such a 
requirement is implicit in the NOPR discussion where RTOs and ISOs 
would be required to show that they have satisfied the criteria, 
including responsiveness to stakeholders. SMUD requests that the 
Commission clarify that its intent was to require RTOs and ISOs to 
publish strategic plans.
    555. FirstEnergy opposes an RTO or ISO mission statement that 
deviates from the contractual and tariff obligations under which the 
RTO or ISO currently operates, and states that any effort to adopt such 
a statement would be problematic, and a source of

[[Page 64162]]

additional and unneeded controversy among RTO and ISO 
stakeholders.\654\
---------------------------------------------------------------------------

    \654\ FirstEnergy at 17.
---------------------------------------------------------------------------

b. Commission Determination
    556. The Commission will require each RTO and ISO to post on its 
Web site a mission statement or organizational charter. The Commission 
encourages each RTO and ISO to include in its mission statement, among 
other things, 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. The mission statement or organizational charter may include 
additional information, such as elements from the RTO or ISO governing 
documents. The Commission does not expect that any explicit statement 
of the responsiveness objective would conflict with existing elements 
of the RTO's or ISO's mission.
    557. We find that this requirement will improve communication 
between RTOs and ISOs and their stakeholders and the community at 
large, as well as provide a statement of goals by which the RTO's and 
ISO's progress may be judged. If any RTO or ISO believes that there is 
a conflict between this requirement and the existing mission statement, 
contracts or tariff, the RTO or ISO may address this conflict in its 
compliance filing. In response to SMUD, we clarify that publication of 
a strategic plan is not implicit in the responsiveness obligation.
8. Executive Compensation
    558. In the NOPR, the Commission encouraged, but did not propose to 
require, each RTO and ISO to ensure that its management programs, 
including, but not limited to, incentive compensation plans for 
executive managers, give appropriate weight to stakeholder 
responsiveness.
a. Comments
    559. Commenters generally agree that RTOs and ISOs should link 
compensation plans for executive managers to customer service measures 
of performance, as indicated by customer satisfaction surveys and 
complying with the responsiveness criteria.
    560. LPPC asks for establishment of objective criteria for 
performance and executive compensation.\655\ Additionally, North 
Carolina Electric Membership argues that the Final Rule should require 
RTOs and ISOs to demonstrate that their executive management incentive 
programs are tied to their mission statements, including a focus on 
improving customer service, properly managing their markets, being 
responsive and accountable to stakeholders and consumers, and providing 
consumers with reliable service at an affordable cost.\656\
---------------------------------------------------------------------------

    \655\ LPPC at 18.
    \656\ North Carolina Electric Membership at 25-26.
---------------------------------------------------------------------------

b. Commission Determination
    561. The Commission continues to encourage, but not require, each 
RTO and ISO to ensure that its management programs, including executive 
compensation, give appropriate weight to responsiveness to customers 
and other stakeholders. If the RTO or ISO board is well-informed about 
the needs of customers and various stakeholders, it will set criteria 
for performance, appropriate goals and targets for the organization and 
its management and institute measures for achieving those targets. By 
focusing our requirements on having a well-informed board, we decline 
to intrude further into board prerogatives regarding management 
compensation.
9. Compliance Filing Requirement
    562. In the NOPR, the Commission determined that each RTO or ISO 
must comply with this proposed requirement by submitting a filing that 
proposes changes to its board responsiveness practices and procedures 
to comply with the proposed criteria or that demonstrates its practices 
and procedures already satisfy the criteria for board 
responsiveness.\657\ This filing would be submitted within six months 
of the date the Final Rule is published in the Federal Register. The 
Commission also stated that it will assess whether each filing 
satisfies the proposed requirement and issue additional orders as 
necessary.
---------------------------------------------------------------------------

    \657\ NOPR, FERC Stats. & Regs. ] 32,628 at P 276.
---------------------------------------------------------------------------

a. Comments
    563. Most commenters support a compliance filing requirement. 
However, some commenters expressed concern that RTOs and ISOs will 
merely submit documentation asserting that their existing processes 
already satisfy the responsiveness criteria, without working seriously 
with stakeholders to ensure that stakeholder input is sought on 
compliance. The California PUC states that it believes that CAISO 
already meets the requirements of the NOPR and asks the Commission to 
refrain from taking any further action regarding the responsiveness of 
RTOs and ISOs to stakeholders and customers needs.\658\
---------------------------------------------------------------------------

    \658\ California PUC at 56.
---------------------------------------------------------------------------

    564. Industrial Coalitions state that the Final Rule should not 
delegate to the RTO or ISO stakeholder processes the task of working 
out the details of the Commission's proposals. Industrial Coalitions 
are concerned that the Commission's approach will delay resolution of 
these important matters, to the detriment of customers. Accordingly, 
Industrial Coalitions urge the Commission to provide clear and 
consistent directives regarding the subject matter and timing of the 
RTO and ISO compliance filings.\659\
---------------------------------------------------------------------------

    \659\ Industrial Coalitions at 4.
---------------------------------------------------------------------------

b. Commission Determination
    565. The Commission requires each RTO or ISO to make a compliance 
filing that proposes changes to its responsiveness practices and 
procedures to comply with the responsiveness requirement or that 
demonstrates that its practices and procedures already satisfy the 
requirement for responsiveness. The compliance filing also must propose 
posting, or report the posting, of the RTO's or ISO's mission statement 
or organizational charter on its respective Web site. This filing shall 
be submitted within six months of the date this Final Rule is published 
in the Federal Register.
    566. We recognize that many of the existing RTOs and ISOs have a 
form of committee (whether advisory board or stakeholder committee) 
that functions within the RTO or ISO governance structure to provide 
stakeholder feedback. Given the number of comments from interested 
parties seeking improvement to their interactions with RTO and ISO 
boards and the effectiveness of these committees, it is important that 
the compliance filings required herein follow from consultation with 
customers and other stakeholders regarding satisfaction with existing 
processes and the appropriateness of improved processes. In the end, 
however, the filing is the RTO's or ISO's to make; we urge them to seek 
consensus but realize that complete agreement is not always achievable. 
This consultation process is worth additional time and effort, and 
should not cause an excessive delay, given the six-month time allowed 
for filing.
    567. Each RTO or ISO should explain in its compliance filing how it 
plans to satisfy, or currently satisfies, each responsiveness 
criterion. Furthermore, each RTO and ISO should include in its

[[Page 64163]]

compliance filing, for each criterion, an explanation of the process 
(e.g., stakeholder meetings, technical conferences, board discussions) 
that the RTO and ISO used to develop its compliance filing 
demonstration and describe major dissenting views. In the event RTOs or 
ISOs, working with their customers and other stakeholders, complete the 
responsiveness compliance requirements in less than six months, they 
may file them ahead of the specified due date. The Commission will 
assess whether each filing satisfies the proposed requirement and issue 
additional orders as necessary.

E. Other Comments

1. Comments
    568. A few commenters address topics other than the specific 
proposals in the NOPR. For example, some suggest we require, or promote 
as part of the Final Rule, the review of RTO and ISO seams and rate 
levels, performance benchmarking, moratoriums on new RTO or ISO 
products and services, cost-benefit analyses,\660\ time-sensitive rates 
for transmission and other non-market services with marginal costs 
caused by on-peak usage,\661\ interconnection requirements,\662\ tariff 
filings, and reviews related to the design and scope of independent 
operational audits of RTOs and ISOs.\663\ CAISO and the Cities filed 
reply comments in opposition to implementing time-sensitive rates.\664\
---------------------------------------------------------------------------

    \660\ AMPA at 2-6; APPA at 10, 19, 102-03; Indianapolis P&L at 
5;Industrial Coalitions at 23-24.
    \661\ California DWR at 3, 21-36, and 38-39.
    \662\ American Forest at 2.
    \663\ Joint Commenters at 6-10.
    \664\ CAISO and the Cities at 3.
---------------------------------------------------------------------------

    569. First Energy is opposed to RTOs and ISOs recovering from 
market participants penalties for NERC reliability violations caused by 
RTOs.\665\
---------------------------------------------------------------------------

    \665\ FirstEnergy at 19.
---------------------------------------------------------------------------

    570. Another commenter asked that the Commission avoid, to the 
extent possible, requiring compliance filings at times when RTOs and 
ISOs are focused on start up of new markets.\666\
---------------------------------------------------------------------------

    \666\ Ameren at 16.
---------------------------------------------------------------------------

    571. In its comments, Sorgo expresses concern that the April 2007 
Report to Congress on Competition in Wholesale and Retail Markets 
failed to address anticompetitive policies that may favor old power 
plants.\667\
---------------------------------------------------------------------------

    \667\ Sorgo at 1. The April 2007 Report to Congress on 
Competition in Wholesale and Retail Markets was developed by the 
Electric Energy Market Competition Task Force as directed by Section 
1815 of the Energy Policy Act of 2005.
---------------------------------------------------------------------------

    572. Allied Public Interest Groups states that the Commission 
should direct RTOs and ISOs to give comparable consideration to demand 
response resources in regional planning, and that regional planning 
should include scenario analyses evaluating the amounts of potentially 
available demand response resources.\668\
---------------------------------------------------------------------------

    \668\ Allied Public Interest Groups at 13-14.
---------------------------------------------------------------------------

2. Commission Determination
    573. The Commission appreciates the efforts involved in developing 
these comments and proposals submitted in this rulemaking. We note that 
these topics have already been addressed by the Commission in Order No. 
890 \669\ and Order No. 693.\670\ Accordingly, the Commission declines 
to expand the scope of this proceeding to encompass topics not 
presented in the NOPR. RTOs and ISOs and their stakeholders may address 
these topics, if they so choose, through their own processes for 
evolving RTO and ISO services and markets.
---------------------------------------------------------------------------

    \669\ Order No. 890 requires any public utility with an OATT to 
allow qualified demand response resources to participate in its 
regional transmission planning process on a comparable basis to 
generation resources and to allow qualified demand response to 
provide certain ancillary services. Order No. 890, ] FERC Stats. & 
Regs. ] 31,241 at P 479, 494, and 888.
    \670\ Order No. 693 requires the Electricity Reliability 
Organization to revise its reliability standards so that all 
technically feasible resource options, including demand response and 
generating resources, may be employed in the management of grid 
operations and emergencies. Order No. 693, FERC Stats. & Regs. ] 
31,242.
---------------------------------------------------------------------------

IV. Applicability of the Final Rule and Compliance Procedures

A. NOPR Proposal

    574. In the NOPR, the Commission proposed to apply the Final Rule 
to all RTOs and ISOs, and to require them to demonstrate compliance 
with the requirements in each of the four sections of the Final 
Rule.\671\ The Commission proposed to require each RTO and ISO to file 
a report to the Commission within six months of the Final Rule's 
effective date, or six months following its certification as an RTO or 
commencement of operations as an ISO. The Commission proposed that the 
compliance filing should describe whether the RTO or ISO already 
complies with the requirements of the Final Rule, or describe the 
entity's plans to attain compliance, including a timeline with 
intermediate deadlines and appropriate proposed tariff and market rule 
revisions. The Commission noted that it would assess whether each 
filing satisfies the proposed requirements and issue further orders for 
each RTO and ISO, as necessary.
---------------------------------------------------------------------------

    \671\ NOPR, 122 FERC ] 61,167 at P 283.
---------------------------------------------------------------------------

B. Comments

    575. The Commission received few comments on the applicability and 
compliance proposals. Ameren notes that the six-month period for 
compliance may coincide with the implementation period for the Midwest 
ISO's Ancillary Services Market. Accordingly, Ameren argues that the 
Commission should avoid, to the extent possible, requiring compliance 
filings at times when RTOs and ISOs are focused on the start of new 
markets.\672\
---------------------------------------------------------------------------

    \672\ Ameren at 16.
---------------------------------------------------------------------------

    576. CAISO requests clarification from the Commission as to whether 
the six-month compliance deadline is intended to apply to those market 
enhancements that CAISO already has planned under its Market Redesign 
and Technology Upgrade. CAISO notes that many of these upgrades, 
including allowing demand response to supply ancillary services and 
implementing enhanced shortage pricing, are on a separate timeline 
approved by the Commission.\673\
---------------------------------------------------------------------------

    \673\ CAISO at 2.
---------------------------------------------------------------------------

    577. NYISO states that it supports the compliance deadlines in the 
NOPR, and calls on the Commission to reject any proposal calling for 
shorter compliance periods. NYISO notes that given the number of 
changes to RTO or ISO market software, billing practices and 
organizational functions that would be required by the Final Rule, 
along with the time required to consult with stakeholders, the proposed 
deadlines are the minimum necessary time for preparation of compliance 
filings.\674\
---------------------------------------------------------------------------

    \674\ NYISO at 22.
---------------------------------------------------------------------------

C. Commission Determination

    578. As we proposed in the NOPR, we will require RTOs and ISOs to 
make a compliance filing within six months of the date that this Final 
Rule is published in the Federal Register. RTOs and ISOs should work 
with stakeholders and interested parties, where applicable, to comply 
with this rule and to develop their compliance filings.
    579. The six-month period appropriately recognizes that it is 
important for RTOs and ISOs to work with stakeholders and other 
interested parties to develop a compliance filing, and that (as NYISO 
contends) such processes take time. In response to Ameren and CAISO, we 
clarify that the compliance requirement is not meant to displace the 
timelines of any market improvements that RTOs or ISOs are currently 
undertaking. Each RTO and ISO should include in its compliance filing 
an update on the status of any relevant market design changes that are

[[Page 64164]]

in the process of being implemented and address any remaining issues 
not addressed by the ongoing changes. It need not change the schedule 
for implementing these other market design changes as a result of this 
Final Rule.
    580. The compliance filing should explain the action the RTO or ISO 
has taken, or plans to take, to comply with the requirements in each of 
the four sections of this Final Rule. It should also describe, where 
applicable, the process used to develop the compliance filing and 
describe any major dissenting views. The Commission will evaluate each 
compliance filing to determine whether it satisfies the requirements in 
this rule, and issue additional orders as necessary.
    581. As described above, RTOs and ISOs, in cooperation with their 
customers and stakeholders, also are required 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, including whether (and how) 
smaller resources can reliably and economically provide operating 
reserves and report their findings to the Commission. This assessment 
is due to the Commission within one year of the date that this Final 
Rule is published in the Federal Register.
    582. Finally, as described above, each RTO's and ISO's market 
monitoring unit is required to comment on the adequacy of market 
mitigation measures in its respective RTO's or ISO's shortage pricing 
proposal. This requirement will aid the Commission in evaluating the 
proposals once they are filed.
    583. In response to commenters who argue that the six-month 
requirement for submission of a compliance filing is either too long or 
too short, we find that the six-month period is an adequate amount of 
time for an RTO or ISO to work with stakeholders and other interested 
parties to develop a compliance filing. We note that RTOs and ISOs may 
make their compliance filing at any time prior to the end of the six-
month period.

V. Information Collection Statement

    584. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection requirements imposed by 
agency rules.\675\ Upon approval of a collection(s) of information, OMB 
will assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of this rule will not be penalized 
for failing to respond to these collections of information unless the 
collections of information display a valid OMB control number. This 
Final Rule amends the Commission's regulations to improve the operation 
of organized wholesale electric power markets. The objective of this 
Final Rule is to improve market design and competition in organized 
markets. Through this rule the Commission hopes to provide remedies by: 
(1) Ensuring that new criteria are established so that RTOs and ISOs 
are responsive to their customers and stakeholders; (2) improving 
market monitoring within RTOs and ISOs by requiring them to provide 
their Market Monitoring Units with access to market data and sufficient 
resources to perform their duties; (3) providing transparency in the 
marketplace by requiring RTOs and ISOs to dedicate portions of their 
Web sites so market participants can avail themselves of information 
concerning offers to buy or sell power on a long-term basis; and (4) 
requiring RTOs and ISOs to institute certain reforms in the demand 
response programs to remove several disincentives and barriers to 
demand response so as to provide for more efficient operation of 
markets and encourage new technologies. Filings by RTOs and ISOs would 
be made under Part 35 of the Commission's regulations. The information 
provided for under Part 35 is identified as FERC-516.
---------------------------------------------------------------------------

    \675\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    585. The Commission is submitting these reporting requirements to 
OMB for its review and approval under section 3507(d) of the Paperwork 
Reduction Act.\676\ The Commission solicited comments on the 
Commission's need for this information, whether the information will 
have practical utility, the accuracy of provided burden estimates, ways 
to enhance the quality, utility, and clarity of the information to be 
collected, and any suggested methods for minimizing the respondent's 
burden, including the use of automated information techniques. The 
Commission did not receive comments specifically addressing the burden 
estimates in the NOPR. Therefore we will use the same estimates here as 
in the NOPR.
---------------------------------------------------------------------------

    \676\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    Burden Estimate: The Public Reporting burden for the requirements 
contained in the Final Rule is as follows:

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
FERC-516 Task:
    Allow demand response to provide certain                   6               1             433           2,598
     ancillary services.........................
    Remove certain deviation charges............               5               1             288           1,440
    Permit aggregation of Retail Customers......               6               1           102.5             615
    Allow pricing to ration demand during a                    6               1             649           3,894
     shortage...................................
    Long-term contract postings.................               6               1              30             180
    MMUs........................................               6               1             129             774
    Require RTO board responsiveness to                        6               1             180           1,080
     customers..................................
    Require RTO self-assessment.................               6               1             650           3,900
                                                 ---------------------------------------------------------------
        Totals..................................  ..............  ..............  ..............          14,481
----------------------------------------------------------------------------------------------------------------

    Total Annual Hours for Collection: (Reporting + recordkeeping, (if 
appropriate)) = Total hours for performing tasks 1 through 8 as 
identified above = 14,481 hours.
    Information Collection Costs: The average annualized cost \677\ is 
expected to be:
---------------------------------------------------------------------------

    \677\ Differences in RTO/ISO staff hourly rates are to 
differentiate between administrative support staff and senior staff.

Legal expertise = $473,526 (2,368 hours @$200 an hour)
Technical Expertise = $712,038 (4,747 hours @$150 an hour) (RTO/ISO 
Senior Staff, Stakeholder participants)
Administrative Support = $108,701 (2,718 hours @$40 an hour)

[[Page 64165]]

IT Support = $236,448 (2,489 hours @ $95 an hour)
Participatory Expenditures = $2,160,000 (96 participants @$1,000 per 
day on average 4.5 days per activity for five of the eight activities 
identified above).
Total = $3,690,713.

    Title: FERC-516 ``Electric Rate Schedule Filings.''
    Action: Proposed Collections.
    OMB Control No: 1902-0096.
    Respondents: Business or other for profit, and/or not for profit 
institutions.
    Frequency of Responses: An initial filing to comply with the rule, 
and then on occasion as needed to revise or modify.
    Necessity of the Information: This Final Rule furthers the 
improvement of competitive wholesale electric markets and the provision 
of transmission services in the RTO and ISO regions. The Commission 
recognizes that significant differences exist among the regions, 
industry structures, and sources of electric generation, population 
demographics and even weather patterns. In fulfilling its 
responsibilities under sections 205 and 206 of the Federal Power Act, 
the Commission is required to address, and has the authority to remedy, 
undue discrimination and anticompetitive effects.
    586. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426 [Attention: Michael Miller, 
Office of the Executive Director, Phone: (202) 502-8415, fax: (202) 
273-0873, e-mail: michael.miller@ferc.gov. Comments on the requirements 
of the proposed rule may also be sent to the Office of Information and 
Regulatory Affairs, Office of Management and Budget, Washington, DC 
20503 [Attention: Desk Officer for the Federal Energy Regulatory 
Commission, fax (202) 395-7285, e-mail: oira_submission@omb.eop.gov.

VI. Environmental Analysis

    587. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\678\ The 
Commission concludes that neither an Environmental Assessment nor an 
Environmental Impact statement is required for this Final Rule under 
section 380.4(a)(15) of the Commission's regulations, which provides a 
categorical exemption for approval of actions under sections 205 and 
206 of the FPA relating to the filing of schedules containing all rates 
and charges for the transmission or sale subject to the Commission's 
jurisdiction, plus the classification, practices, contracts, and 
regulations that affect rates, charges, classifications, and 
services.\679 \
---------------------------------------------------------------------------

    \678\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, FERC Stats. & Regs. ] 30,783 (1987).
    \679\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

VII. Regulatory Flexibility Act Certification

    588. The Regulatory Flexibility Act of 1980 (RFA) \680\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. The RFA does 
not mandate any particular outcome in a rulemaking. It only requires 
consideration of alternatives that are less burdensome to small 
entities and an agency explanation of why alternatives were rejected.
---------------------------------------------------------------------------

    \680\ 5 U.S.C. 601-12.
---------------------------------------------------------------------------

    589. In drafting a rule an agency is required to: (1) Assess the 
effect that its regulation will have on small entities; (2) analyze 
effective alternatives that may minimize a regulation's impact; and (3) 
make the analyses available for public comment.\681\ In its NOPR, the 
agency must either include an initial regulatory flexibility analysis 
(initial RFA) \682\ or certify that the proposed rule will not have a 
``significant impact on a substantial number of small entities.'' \683\
---------------------------------------------------------------------------

    \681\ 5 U.S.C. 601-604.
    \682\ 5 U.S.C. 603(a).
    \683\ 5 U.S.C. 605(b).
---------------------------------------------------------------------------

    590. If in preparing the NOPR an agency determines that the 
proposal could have a significant impact on a substantial number of 
small entities, the agency shall ensure that small entities will have 
an opportunity to participate in the rulemaking procedure.\684\
---------------------------------------------------------------------------

    \684\ 5 U.S.C. 609(a).
---------------------------------------------------------------------------

    591. In its Final Rule, the agency must either prepare a Final 
Regulatory Flexibility Analysis (Final RFA) or make the requisite 
certification. Based on the comments the agency receives on the NOPR, 
it can alter its original position as expressed in the NOPR, but it is 
not required to make any substantive changes to the proposed 
regulation.
    592. The statute provides for judicial review of an agency's final 
certification or Final RFA.\685\ An agency must file a Final RFA 
demonstrating a ``reasonable, good-faith effort'' to carry out the RFA 
mandate.\686\ However, the RFA is a procedural, not a substantive, 
mandate. An agency is only required to demonstrate a reasonable, good-
faith effort to review the impact the proposed rule would place on 
small entities, any alternatives that would address the agency's and 
small entities concerns and their impact, provide small entities the 
opportunity to comment on the proposals, and review and address 
comments. An agency is not required to adopt the least burdensome rule. 
Further, the RFA does not require the RFA to assess the impact of a 
rule on all small entities that may be affected by a rule, only on 
those entities that the agency directly regulates and that will be 
directly impacted by the rule.\687\
---------------------------------------------------------------------------

    \685\ 5 U.S.C. 611.
    \686\ United Cellular Corp. v. FCC, 254 F.3d 78, 88 (DC Cir. 
2001); Alenco Communications, Inc. v. FCC, 201 F.3d 608, 625 (5th 
Cir. 2000).
    \687\ Mid-Tex Electric Coop., Inc. v. FERC, 773 F.2d 327 (DC 
Cir. 1985) (Mid-Tex).
---------------------------------------------------------------------------

A. NOPR Proposal

    593. In the NOPR, the Commission stated that most, if not all, of 
the transmission organizations to which this rule would apply do not 
fall within the definition of small entities.\688\ The Commission 
identified the characteristics of each of those organizations and all 
exceeded the standard size definition established in NAICS.\689\ It 
should be noted that due to typographical error in the NOPR, footnote 
292 omitted the word ``million'' when identifying the size standard 
applicable to utilities.
---------------------------------------------------------------------------

    \688\ NOPR, FERC Stats. & Regs. ]32,628 at P 291.
    \689\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. See 
5 U.S.C. 601(3), citing to Section 3 of the Small Business Act, 
U.S.C. 632. The Small Business Size Standards component of the North 
American Industry Classification System defines a small utility as 
one that, including its affiliates is primarily engaged in the 
generation, transmission, or distribution of electric energy for 
sale, and whose total electric output for the preceding fiscal years 
did not exceed 4 million MWh. 13 CFR 121.202 (Sector 22, Utilities, 
North American Industry Classification System (NAICS)) (2004).
---------------------------------------------------------------------------

    594. One of those requirements proposed in the NOPR was that ``RTO 
and ISOs must 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.'' \690\ The Commission reasoned that such 
action would reduce obstacles for small retail loads to be able to 
participate in organized markets by

[[Page 64166]]

allowing ARCs to assemble small demand responses that individually are 
too small to qualify for bidding into an RTO or ISO organized market 
and having ARCs assume many of the administrative tasks that retail 
customers may lack the resources or cannot afford. Simultaneously, as 
the Commission pointed out from comments received in response to its 
ANOPR, ARCs can reduce the RTO's and ISO's administrative burden of 
managing individual customers' demand response participation.\691\
---------------------------------------------------------------------------

    \690\ NOPR, FERC Stats. & Regs. ]32,628 at P 86.
    \691\ Id. P 83.
---------------------------------------------------------------------------

    595. Thus, in the NOPR, based on comments to the ANOPR, the 
Commission sought to ameliorate administrative burdens on small 
entities, specifically small retail customers to be able to participate 
in organized market and access demand response programs.
1. Comments
    596. APPA and TAPS argue that the inclusion of ARCs, while 
assisting small retail customers, disproportionately shifts the burden 
to relevant electric retail regulatory authorities. APPA does not 
support the Commission's proposal that RTOs presume that aggregation is 
allowed unless the relevant electric retail regulatory authority 
informs the RTO that it does not permit aggregation.\692\ APPA provides 
data on the number of power systems providing retail service in RTO 
regions and states that the vast majority of these are small utilities 
within the meaning of the RFA.\693\
---------------------------------------------------------------------------

    \692\ APPA at 3.
    \693\ Id. at 3.
---------------------------------------------------------------------------

    597. TAPS, while recognizing the Commission's efforts, also has 
concerns about the Commission's proposal. TAPS believes the ``proposal 
would place undue burdens on many individual nonregulated electric 
utilities to take affirmative regulatory actions to maintain their 
authority * * *.'' \694\ TAPS believes that if relevant electric retail 
regulatory authorities must assume the responsibility to notify RTOs 
then this places undue burden on municipal entities to become involved 
in lengthy legislative processes to make determinations that may have 
already been made on whether ARCs may aggregate the demand response of 
the municipals' loads.\695\
---------------------------------------------------------------------------

    \694\ TAPS at 13
    \695\ Id. at 17.
---------------------------------------------------------------------------

    598. APPA believes the Commission is giving the RTOs and ISOs 
authority to trump state and local laws and regulations when it allows 
RTOs and ISOs to accept bids from an ARC whether or not the laws and 
regulations of the relevant electric retail regulatory authority 
explicitly permits it.\696\ APPA believes that the retail regulatory 
authority will be placed in the position of having to make an 
administrative finding of whether aggregation by ARCs of retail end 
users is to be permitted. By APPA's count, only a small proportion of 
the 1,315 public power systems that provide retail electric service in 
states served by RTOs and ISOs have such laws or regulations. For the 
majority, this would result in a huge learning curve to become familiar 
with the process and consequently result in a ``very substantial 
undertaking.'' \697\ APPA estimates that approximately 1,307 of the 
power distribution systems located in states served by RTOs and ISOs 
are ``small utilities'' as the term is defined in the RFA. To require 
relevant electric retail regulatory authorities to consider an 
affirmative pronouncement on this issue is ``cumulatively a very 
substantial FERC-imposed burden on them.'' \698\
---------------------------------------------------------------------------

    \696\ APPA at 43.
    \697\ Id. at 44.
    \698\ Id. at 45.
---------------------------------------------------------------------------

    599. APPA believes that unless a system's relevant electric retail 
regulatory authority affirmatively informs an RTO or ISO that it 
permits such aggregation by third-party ARCs, the RTO or ISO should be 
required to assume that such aggregation is not permitted. Should the 
Commission not accept APPA's proposal, as an alternative APPA suggest 
that for relevant electric retail regulatory authorities governing 
public power systems located in RTO and ISO regions that exceed the RFA 
size requirement, they would have to consider the issue of third-party 
ARCs and aggregation of their retail customers. In the case of public 
power systems that do not meet the RFA size requirement, then the RTO 
or ISO would be responsible for making the assumption that aggregation 
by ARCs is not permitted.\699\
---------------------------------------------------------------------------

    \699\ Id. at 47.
---------------------------------------------------------------------------

    600. TAPS takes a similar position. It believes the NOPR can be 
interpreted to require municipal systems to take legislative or 
regulatory action specific to the third-party ARC issue and notify the 
RTO or ISO. For these municipal systems to respond particularly when 
they do not allow retail access will impose significant burdens on 
them. As an indication of the potential impact, TAPS identified the 
number of municipal systems served by their members including AMP-Ohio 
with 122 municipal electric systems in both Midwest ISO and PJM; 
Indiana Municipal Power Agency, which serves 51 municipal electric 
systems in Midwest ISO; and Wisconsin Public Power Inc. which serves 50 
municipal electric systems in Midwest ISO.\700\ TAPS reminds the 
Commission that Congress, through passage of the RFA, requires agencies 
to assess the impact on entities whose total electric output does not 
exceed 4 million MWh. TAPS notes that the Commission's certification in 
the NOPR recognized this responsibility, but failed to account for 
``the hundreds of small entities that it proposes to effectively put 
through this legislative or regulatory process.'' \701\
---------------------------------------------------------------------------

    \700\ TAPS at 19.
    \701\ Id. at 20.
---------------------------------------------------------------------------

    601. TAPS believes the Commission can achieve its objective by 
rewording its requirement to have relevant electric retail regulatory 
authorities notify the RTO or ISO when they permit third-party ARCs. 
Unless there is a notification, the RTO or ISO is to assume that third-
party aggregation is not permitted. By shifting the emphasis as to when 
the notification is to take place, hundreds of municipals would not be 
burdened by having to go through the legislative process. In addition, 
only systems with a total electric output exceeding 4 million MWh would 
have to go through the process. TAPS also proposes an additional 
alternative, namely that municipals with retail sales of more than 500 
million kWh as specified in PURPA would have to go through the 
process.\702\
---------------------------------------------------------------------------

    \702\ Id.
---------------------------------------------------------------------------

2. Commission Determination
    602. The Final Rule is applicable to all RTOs and ISOs. The 
Commission is requiring each RTO and ISO to make certain filings that 
reflect amendments to their tariffs to demonstrate they have either 
incorporated, or already have in place, processes that implement the 
requirements of this Final Rule. None of these entities, as identified 
in the NOPR, meets the RFA definition of a small entity--in particular, 
the last criterion of the definition ``and which is not dominant in its 
field of operation.'' \703\
---------------------------------------------------------------------------

    \703\ 5 U.S.C. 601(3) and 601(6) and 15 U.S.C. 632(a)(1) 
(defining ``small business concern'').
---------------------------------------------------------------------------

    603. In Mid-Tex, the court accepted the Commission's conclusion 
that, since virtually all of the public utilities that it regulates do 
not fall within the meaning of the term ``small entities'' as defined 
in the RFA, the Commission did not need to prepare a regulatory 
flexibility analysis in connection with its proposed rule governing the 
allocation of costs for construction work

[[Page 64167]]

in progress (CWIP).\704\ The CWIP rules applied to all public 
utilities. This Final Rule applies only to RTOs and ISOs, which are a 
subset of ``all public utilities'' for which the regulatory flexibility 
analysis was not required.
---------------------------------------------------------------------------

    \704\ Mid-Tex, 773 F.2d 327 at 342.
---------------------------------------------------------------------------

    604. In a subsequent court decision, American Trucking 
Associations, Inc. v. EPA,\705\ the U.S. Court of Appeals for the 
District of Columbia applied the decision in Mid-Tex to its 
determination. The Environmental Protection Agency (EPA) established a 
primary national ambient air quality standard for ozone and particulate 
matter. The basis of EPA's certification was that the standard 
regulated small entities indirectly through state implementation plans. 
The court found that because the states, not EPA, had the direct 
authority to impose the burden on small entities, EPA's regulation did 
not have a direct impact on small entities.
---------------------------------------------------------------------------

    \705\ American Trucking Ass'ns v. EPA, 175 F.3d 1027, 1044 (DC 
Cir. 1999), aff'd in part and rev'd in part sub nom., Whitman v. 
American Trucking Ass'ns, 531 U.S. 457 (2001).
---------------------------------------------------------------------------

    605. Here APPA and TAPS contend that hundreds of small municipal 
systems would have to undertake legislative or regulatory actions in 
order to respond to the RTO. We disagree with their contention. No 
relevant electric retail regulatory authority is required to take any 
action under this rule. For these reasons, the Commission certifies 
that this Final Rule will not have a significant economic impact on a 
substantial number of small entities.

VIII. Document Availability

    606. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    607. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    608. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours from FERC Online Support at 202-
502-6652 (toll free at 1-866-208-3676) or e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

IX. Effective Date and Congressional Notification

    609. These regulations are effective December 29, 2008. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996. The Commission will submit 
the Final Rule to both houses of Congress and the Government 
Accountability Office.

By the Commission. Commissioner Kelly concurring in part and 
dissenting in part with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

0
In consideration of the foregoing, the Commission amends part 35, 
Chapter I, Title 18, of the Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
In Sec.  35.28 add new paragraphs (b)(4) through (b)(8) and (g) to read 
as follows:

Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (b) Definitions * * *
    (4) Demand response means a reduction in the consumption of 
electric energy by customers from their expected consumption in 
response to an increase in the price of electric energy or to incentive 
payments designed to induce lower consumption of electric energy.
    (5) Demand response resource means a resource capable of providing 
demand response.
    (6) An operating reserve shortage means a period when the amount of 
available supply falls short of demand plus the operating reserve 
requirement.
    (7) Market Monitoring Unit means the person or entity responsible 
for carrying out the market monitoring functions that the Commission 
has ordered Commission-approved independent system operators and 
regional transmission organizations to perform.
    (8) Market Violation means a tariff violation, violation of a 
Commission-approved order, rule or regulation, market manipulation, or 
inappropriate dispatch that creates substantial concerns regarding 
unnecessary market inefficiencies.
* * * * *
    (g) Tariffs and operations of Commission-approved independent 
system operators and regional transmission organizations.
    (1) Demand response and pricing.
    (i) Ancillary services provided by demand response resources.
    (A) Every Commission-approved independent system operator or 
regional transmission organization that operates organized markets 
based on competitive bidding for energy imbalance, spinning reserves, 
supplemental reserves, reactive power and voltage control, or 
regulation and frequency response ancillary services (or its functional 
equivalent in the Commission-approved independent system operator's or 
regional transmission organization's tariff) must accept bids from 
demand response resources in these markets for that product on a basis 
comparable to any other resources, if the demand response resource 
meets the necessary technical requirements under the tariff, and 
submits a bid under the Commission-approved independent system 
operator's or regional transmission organization's bidding rules at or 
below the market-clearing price, unless not permitted by the laws or 
regulations of the relevant electric retail regulatory authority.
    (B) Each Commission-approved independent system operator or 
regional transmission organization must allow providers of a demand 
response resource to specify the following in their bids:
    (1) A maximum duration in hours that the demand response resource 
may be dispatched;
    (2) A maximum number of times that the demand response resource may 
be dispatched during a day; and
    (3) A maximum amount of electric energy reduction that the demand 
response resource may be required to provide either daily or weekly.
    (ii) Removal of deviation charges. A Commission-approved 
independent system operator or regional transmission organization with 
a tariff that contains a day-ahead and a real-time market may not 
assess a charge to a purchaser of electric energy in its day-ahead 
market for purchasing less power in the real-time market during a real-
time market period for which the Commission-approved independent system 
operator or regional transmission organization declares an operating 
reserve shortage or makes a generic request to reduce load to avoid an 
operating reserve shortage.

[[Page 64168]]

    (iii) Aggregation of retail customers. Each Commission-approved 
independent system operator and regional transmission organization must 
permit a qualified aggregator of retail customers to bid demand 
response on behalf of retail customers directly into the Commission-
approved independent system operator's or regional transmission 
organization's organized markets, unless the laws and regulations of 
the relevant electric retail regulatory authority expressly do not 
permit a retail customer to participate.
    (iv) Price formation during periods of operating reserve shortage.
    (A) Each Commission-approved independent system operator or 
regional transmission organization must modify its market rules 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.
    (B) A Commission-approved independent system operator or regional 
transmission organization may phase in this modification of its market 
rules.
    (2) Long-term power contracting in organized markets. Each 
Commission-approved independent system operator or regional 
transmission organization must provide a portion of its Web site for 
market participants to post offers to buy or sell power on a long-term 
basis.
    (3) Market monitoring policies.
    (i) Each Commission-approved independent system operator or 
regional transmission organization must modify its tariff provisions 
governing its Market Monitoring Unit to reflect the directives provided 
in Order No. 719, including the following:
    (A) Each Commission-approved independent system operator or 
regional transmission organization must include in its tariff a 
provision to provide its Market Monitoring Unit access to Commission-
approved independent system operator and regional transmission 
organization market data, resources and personnel to enable the Market 
Monitoring Unit to carry out its functions.
    (B) The tariff provision must provide the Market Monitoring Unit 
complete access to the Commission-approved independent system 
operator's and regional transmission organization's databases of market 
information.
    (C) The tariff provision must provide that any data created by the 
Market Monitoring Unit, including, but not limited to, reconfiguring of 
the Commission-approved independent system operator's and regional 
transmission organization's data, will be kept within the exclusive 
control of the Market Monitoring Unit.
    (D) The Market Monitoring Unit must report to the Commission-
approved independent system operator's or regional transmission 
organization's board of directors, with its management members removed, 
or to an independent committee of the Commission-approved independent 
system operator's or regional transmission organization's board of 
directors. A Commission-approved independent system operator or 
regional transmission organization that has both an internal Market 
Monitoring Unit and an external Market Monitoring Unit may permit the 
internal Market Monitoring Unit to report to management and the 
external Market Monitoring Unit to report to the Commission-approved 
independent system operator's or regional transmission organization's 
board of directors with its management members removed, or to an 
independent committee of the Commission-approved independent system 
operator or regional transmission organization board of directors. If 
the internal market monitor is responsible for carrying out any or all 
of the core Market Monitoring Unit functions identified in paragraph 
(g)(3)(ii) of this section, the internal market monitor must report to 
the independent system operator's or regional transmission 
organization's board of directors.
    (E) A Commission-approved independent system operator or regional 
transmission organization may not alter the reports generated by the 
Market Monitoring Unit, or dictate the conclusions reached by the 
Market Monitoring Unit.
    (F) Each Commission-approved independent system operator or 
regional transmission organization must consolidate the core Market 
Monitoring Unit provisions into one section of its tariff. Each 
independent system operator or regional transmission organization must 
include a mission statement in the introduction to the Market 
Monitoring Unit provisions that identifies the Market Monitoring Unit's 
goals, including the protection of consumers and market participants by 
the identification and reporting of market design flaws and market 
power abuses.
    (ii) Core Functions of Market Monitoring Unit. The Market 
Monitoring Unit must perform the following core functions:
    (A) Evaluate existing and proposed market rules, tariff provisions 
and market design elements and recommend proposed rule and tariff 
changes to the Commission-approved independent system operator or 
regional transmission organization, to the Commission's Office of 
Energy Market Regulation staff and to other interested entities such as 
state commissions and market participants, provided that:
    (1) The Market Monitoring Unit is not to effectuate its proposed 
market design itself, and
    (2) The Market Monitoring Unit must limit distribution of its 
identifications and recommendations to the independent system operator 
or regional transmission organization 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.
    (B) Review and report on the performance of the wholesale markets 
to the Commission-approved independent system operator or regional 
transmission organization, the Commission, and other interested 
entities such as state commissions and market participants, on at least 
a quarterly basis and submit a more comprehensive annual state of the 
market report. The Market Monitoring Unit may issue additional reports 
as necessary.
    (C) Identify and notify the Commission's Office of Enforcement 
staff of instances in which a market participant's or the Commission-
approved independent system operator's or regional transmission 
organization's behavior may require investigation, including, but not 
limited to, suspected Market Violations.
    (iii) Tariff administration and mitigation
    (A) A Commission-approved independent system operator or regional 
transmission organization may not permit its Market Monitoring Unit, 
whether internal or external, to participate in the administration of 
the Commission-approved independent system operator's or regional 
transmission organization's tariff or, except as provided in paragraph 
(g)(3)(iii)(D) of this section, to conduct prospective mitigation.
    (B) A Commission-approved independent system operator or regional 
transmission organization may permit its Market Monitoring Unit to 
provide the inputs required for the Commission-approved independent 
system operator or regional transmission organization to conduct 
prospective mitigation, including, but not limited to, reference 
levels, identification of system constraints, and cost calculations.
    (C) A Commission-approved independent system operator or regional 
transmission organization may allow its Market Monitoring Unit to 
conduct retrospective mitigation.

[[Page 64169]]

    (D) A Commission-approved independent system operator or regional 
transmission organization with a hybrid Market Monitoring Unit 
structure may permit its internal market monitor to conduct prospective 
and/or retrospective mitigation, in which case it must assign to its 
external market monitor the responsibility and the tools to monitor the 
quality and appropriateness of the mitigation.
    (E) Each Commission-approved independent system operator or 
regional transmission organization must identify in its tariff the 
functions the Market Monitoring Unit will perform and the functions the 
Commission-approved independent system operator or regional 
transmission organization will perform.
    (iv) Protocols on Market Monitoring Unit referrals to the 
Commission of suspected violations.
    (A) A Market Monitoring Unit is to make a non-public referral to 
the Commission in all instances where the Market Monitoring Unit has 
reason to believe that a Market Violation has occurred. While the 
Market Monitoring Unit need not be able to prove that a Market 
Violation has occurred, the Market Monitoring Unit is to provide 
sufficient credible information to warrant further investigation by the 
Commission. Once the Market Monitoring Unit has obtained sufficient 
credible information to warrant referral to the Commission, the Market 
Monitoring Unit is to immediately refer the matter to the Commission 
and desist from independent action related to the alleged Market 
Violation. This does not preclude the Market Monitoring Unit from 
continuing to monitor for any repeated instances of the activity by the 
same or other entities, which would constitute new Market Violations. 
The Market Monitoring Unit is to respond to requests from the 
Commission for any additional information in connection with the 
alleged Market Violation it has referred.
    (B) All referrals to the Commission of alleged Market Violations 
are to be in writing, whether transmitted electronically, by fax, mail, 
or courier. The Market Monitoring Unit may alert the Commission orally 
in advance of the written referral.
    (C) The referral is to be addressed to the Commission's Director of 
the Office of Enforcement, with a copy also directed to both the 
Director of the Office of Energy Market Regulation and the General 
Counsel.
    (D) The referral is to include, but need not be limited to, the 
following information.
    (1) The name[s] of and, if possible, the contact information for, 
the entity[ies] that allegedly took the action[s] that constituted the 
alleged Market Violation[s];
    (2) The date[s] or time period during which the alleged Market 
Violation[s] occurred and whether the alleged wrongful conduct is 
ongoing;
    (3) The specific rule or regulation, and/or tariff provision, that 
was allegedly violated, or the nature of any inappropriate dispatch 
that may have occurred;
    (4) The specific act[s] or conduct that allegedly constituted the 
Market Violation;
    (5) The consequences to the market resulting from the acts or 
conduct, including, if known, an estimate of economic impact on the 
market;
    (6) If the Market Monitoring Unit believes that the act[s] or 
conduct constituted a violation of the anti-manipulation rule of Part 
1c, a description of the alleged manipulative effect on market prices, 
market conditions, or market rules;
    (7) Any other information the Market Monitoring Unit believes is 
relevant and may be helpful to the Commission.
    (E) Following a referral to the Commission, the Market Monitoring 
Unit is to continue to notify and inform the Commission of any 
information that the Market Monitoring Unit learns of that may be 
related to the referral, but the Market Monitoring Unit is not to 
undertake any investigative steps regarding the referral except at the 
express direction of the Commission or Commission Staff.
    (v) Protocols on Market Monitoring Unit Referrals to the Commission 
of Perceived Market Design Flaws and Recommended Tariff Changes.
    (A) A Market Monitoring Unit is to make a referral to the 
Commission in all instances where the Market Monitoring Unit has reason 
to believe market design flaws exist that it believes could effectively 
be remedied by rule or tariff changes. The Market Monitoring Unit must 
limit distribution of its identifications and recommendations to the 
independent system operator or regional transmission organization and 
to the Commission in the event it believes broader dissemination could 
lead to exploitation, with an explanation of why further dissemination 
should be avoided at that time.
    (B) All referrals to the Commission relating to perceived market 
design flaws and recommended tariff changes are to be in writing, 
whether transmitted electronically, by fax, mail, or courier. The 
Market Monitoring Unit may alert the Commission orally in advance of 
the written referral.
    (C) The referral should be addressed to the Commission's Director 
of the Office of Energy Market Regulation, with copies directed to both 
the Director of the Office of Enforcement and the General Counsel.
    (D) The referral is to include, but need not be limited to, the 
following information.
    (1) A detailed narrative describing the perceived market design 
flaw[s];
    (2) The consequences of the perceived market design flaw[s], 
including, if known, an estimate of economic impact on the market;
    (3) The rule or tariff change(s) that the Market Monitoring Unit 
believes could remedy the perceived market design flaw;
    (4) Any other information the Market Monitoring Unit believes is 
relevant and may be helpful to the Commission.
    (E) Following a referral to the Commission, the Market Monitoring 
Unit is to continue to notify and inform the Commission of any 
additional information regarding the perceived market design flaw, its 
effects on the market, any additional or modified observations 
concerning the rule or tariff changes that could remedy the perceived 
design flaw, any recommendations made by the Market Monitoring Unit to 
the regional transmission organization or independent system operator, 
stakeholders, market participants or state commissions regarding the 
perceived design flaw, and any actions taken by the regional 
transmission organization or independent system operator regarding the 
perceived design flaw.
    (vi) Market Monitoring Unit ethics standards. Each Commission-
approved independent system operator or regional transmission 
organization must include in its tariff ethical standards for its 
Market Monitoring Unit and the employees of its Market Monitoring Unit. 
At a minimum, the ethics standards must include the following 
requirements:
    (A) The Market Monitoring Unit and its employees must have no 
material affiliation with any market participant or affiliate.
    (B) The Market Monitoring Unit and its employees must not serve as 
an officer, employee, or partner of a market participant.
    (C) The Market Monitoring Unit and its employees must have no 
material financial interest in any market participant or affiliate with 
potential exceptions for mutual funds and non-directed investments.
    (D) The Market Monitoring Unit and its employees must not engage in 
any

[[Page 64170]]

market transactions other than the performance of their duties under 
the tariff.
    (E) The Market Monitoring Unit and its employees must not be 
compensated, other than by the Commission-approved independent system 
operator or regional transmission organization that retains or employs 
it, for any expert witness testimony or other commercial services, 
either to the Commission-approved independent system operator or 
regional transmission organization or to any other party, in connection 
with any legal or regulatory proceeding or commercial transaction 
relating to the Commission-approved independent system operator or 
regional transmission organization or to the Commission-approved 
independent system operator's or regional transmission organization's 
markets.
    (F) The Market Monitoring Unit and its employees may not accept 
anything of value from a market participant in excess of a de minimis 
amount.
    (G) The Market Monitoring Unit and its employees must advise a 
supervisor 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 the market 
participant.
    (4) Offer and bid data. (i) Unless a Commission-approved 
independent system operator or regional transmission organization 
obtains Commission approval for a different period, each Commission-
approved independent system operator and regional transmission 
organization must release its offer and bid data within three months.
    (ii) A Commission-approved independent system operator or regional 
transmission organization must mask the identity of market participants 
when releasing offer and bid data. The Commission-approved independent 
system operators and regional transmission organization may propose a 
time period for eventual unmasking.
    (5) Responsiveness of Commission-approved independent system 
operators and regional transmission organizations. Each Commission-
approved independent system operator or regional transmission 
organization must adopt business practices and procedures that achieve 
Commission-approved independent system operator and regional 
transmission organization board of directors' responsiveness to 
customers and other stakeholders and satisfy the following criteria:
    (i) Inclusiveness. The business practices and procedures must 
ensure that any customer or other stakeholder affected by the operation 
of the Commission-approved independent system operator or regional 
transmission organization, or its representative, is permitted to 
communicate the customer's or other stakeholder's views to the 
independent system operator's or regional transmission organization's 
board of directors;
    (ii) 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 Commission-approved independent system operator's and 
regional transmission organization's issues are not dominated by any 
single stakeholder category;
    (iii) 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 Commission-approved independent system operator's 
and regional transmission organization's board of directors at the same 
time as majority positions; and
    (iv) Ongoing responsiveness. The business practices and procedures 
must provide for stakeholder input into the Commission-approved 
independent system operator's or regional transmission organization's 
decisions as well as mechanisms to provide feedback to stakeholders to 
ensure that information exchange and communication continue over time.
    (6) Compliance filings. All Commission-approved independent system 
operators and regional transmission organizations must make a 
compliance filing with the Commission as described in Order No. 719 
under the following schedule:
    (i) The compliance filing addressing the accepting of bids from 
demand response resources in markets for ancillary services on a basis 
comparable to other resources, removal of deviation charges, 
aggregation of retail customers, shortage pricing during periods of 
operating reserve shortage, long-term power contracting in organized 
markets, Market Monitoring Units, Commission-approved independent 
system operators' and regional transmission organizations' board of 
directors' responsiveness, and reporting on the study of the need for 
further reforms to remove barriers to comparable treatment of demand 
response resources must be submitted on or before April 28, 2009.
    (ii) A public utility that is approved as a regional transmission 
organization under Sec.  35.34, or that is not approved but begins to 
operate regional markets for electric energy or ancillary services 
after December 29, 2008, must comply with Order No. 719 and the 
provisions of paragraphs (g)(1) through (g)(5) of this section before 
beginning operations.

    Note: The following appendix will not be published in the Code 
of Federal Regulations.

Appendix--Abbreviated Names of Commenters

Alcoa--Alcoa, Inc.
Ameren--Ameren Services Company
American Forest--American Forest & Paper Association
AMPA--Arkansas Municipal Power Association
APPA--American Public Power Association
ATC--American Transmission Company, LLC
Beacon Power--Beacon Power Corporation
Blue Ridge--Blue Ridge Power Agency
BlueStar Energy--BlueStar Energy Services, Inc.
Mr. Borlick--Robert L. Borlick, Borlick & Associates
BP Energy--BP Energy Company
CAISO--California Independent System Operator Corporation
California DWR--California Department of Water Resources State Water 
Project
California Munis--California Municipal Utilities Association
California PUC--Public Utilities Commission of the State of 
California
Cogeneration Parties--Energy Producers and Users Coalition (EPUC) 
and the Cogeneration Association of California (CAC). EPUC is an ad 
hoc group representing the end-use and customer generation interests 
of the following: Aera Energy LLC; BP America, Inc. (including 
Atlantic Richfield Company); Chevron U.S.A., Inc.; ConocoPhillips 
Company; ExxonMobil Power and Gas Services, Inc.; Shell Oil Products 
US; THUMS Long Beach Company; Occidental Elks Hills, Inc.; and 
Valero Refining Company-California. CAC is an ad hoc association 
representing the power generation, power marketing and cogeneration 
operation interests of the following: Coalinga Cogeneration Company, 
Mid-Set Cogeneration Company, Kern River Cogeneration Company, 
Sycamore Cogeneration Company, Sargent Canyon Cogeneration Company, 
Salinas River Cogeneration Company, Midway Sunset Cogeneration 
Company and Watson Cogeneration Company.
Comverge--Comverge, Inc.
Connecticut and Massachusetts Municipals--Connecticut Municipal 
Electric Energy Cooperative and Massachusetts Municipal Wholesale 
Electric Company
Constellation--Constellation Energy Commodities Group, Inc., 
Constellation NewEnergy, Inc., and Constellation Power Source 
Generation, Inc.
DC Energy--DC Energy, LLC
Detroit Edison--Detroit Edison Company
Dominion Resources--Dominion Resources Services

[[Page 64171]]

DRAM--Demand Response and Advanced Metering Coalition
Duke Energy--Duke Energy Corporation
EEI--Edison Electric Institute
EnergyConnect--EnergyConnect, Inc.
Energy Curtailment--Energy Curtailment Specialists, Inc.
EnerNOC--EnerNOC, Inc.
E.ON U.S.--E.ON U.S. LLC
EPSA--Electric Power Supply Association
Exelon--Exelon Corporation
FTC--Federal Trade Commission
FirstEnergy--FirstEnergy Service Company, on behalf of FirstEnergy 
Solutions Corp. and the transmission- and distribution-owning 
utility subsidiaries of FirstEnergy Corp.: American Transmission 
Systems, Incorporated; The Cleveland Electric Illuminating Company; 
Jersey Central Power and Light Company; Metropolitan Edison Company; 
Ohio Edison Company; Pennsylvania Electric Company; Pennsylvania 
Power Company; and The Toledo Edison Company
IID--Imperial Irrigation District
IMEA--Illinois Municipal Electric Agency
Indianapolis P&L--Indianapolis Power and Light Company
Industrial Coalitions--The Coalition of Midwest Transmission 
Customers, Connecticut Industrial Energy Consumers, Industrial 
Energy Consumers of Pennsylvania, NEPOOL Industrial Customer 
Coalition, Industrial Energy Users-Ohio, West Virginia Energy Users 
Group, PJM Industrial Customer Coalition, American Iron and Steel 
Institute, and Portland Cement Association
Industrial Consumers--Electricity Consumers Resource Council, 
American Chemistry Council, American Iron and Steel Institute, 
Association of Businesses Advocating Tariff Equity, Council of 
Industrial Boiler Owners, and Wisconsin Industrial Energy Group
Integrys Energy--Integrys Energy Services, Inc.
ISO New England--ISO New England Inc.
ISO/RTO Council--ISO/RTO Council, which is comprised of the Alberta 
Electric System Operator; California Independent System Operator, 
Inc.; New Brunswick System Operator; Electric Reliability Council of 
Texas; Independent Electricity System Operator of Ontario; ISO New 
England Inc.; Midwest Independent Transmission System Operator, 
Inc.; New York Independent System Operator, Inc.; PJM 
Interconnection, LLC; and Southwest Power Pool, Inc.
ITC--International Transmission Company; Michigan Electric 
Transmission Company, LLC; and ITC Midwest LLC
Joint Commenters--Citadel Energy Products LLC, Citadel Energy 
Strategies LLC, Citadel Energy Investments Ltd.; and DC Energy LLC
Kansas CC--Kansas Corporation Commission
LPPC--Large Public Power Council
MADRI States--the State members of the Mid-Atlantic Distributed 
Resources Initiative
Maine PUC--Maine Public Utilities Commission
Midwest Energy--Midwest Energy, Inc.
Midwest ISO--Midwest Independent Transmission System Operator, Inc.
Midwest ISO TOs--Midwest ISO Transmission Owners: Ameren Services 
Company, as agent for Union Electric Company d/b/a AmerenUE, Central 
Illinois Public Service Company d/b/a AmerenCIPS, Central Illinois 
Light Co. d/b/a AmerenCILCO, and Illinois Power Company d/b/a 
AmerenIP; City of Columbia Water and Light Department (Columbia, 
Missouri); City Water, Light & Power (Springfield, Illinois); Duke 
Energy Shared Services for Duke Energy Ohio, Inc., Duke Energy 
Indiana, Inc., and Duke Energy Kentucky, Inc.; Great River Energy; 
Hoosier Energy Rural Electric Cooperative, Inc.; Indiana Municipal 
Power Agency; Indianapolis Power & Light Company; Manitoba Hydro; 
Michigan Public Power Agency; Minnesota Power (and its subsidiary 
Superior Water, L&P); Montana-Dakota Utilities Co.; Northern Indiana 
Public Service Company; Northern States Power Company, a Minnesota 
corporation, and Northern States Power Company, a Wisconsin 
corporation, subsidiaries of Xcel Energy Inc.; Northwestern 
Wisconsin Electric Company; Otter Tail Power Company; Southern 
Illinois Power Cooperative; Southern Indiana Gas & Electric Company 
(d/b/a Vectren Energy Delivery of Indiana); Southern Minnesota 
Municipal Power Agency; Wabash Valley Power Association, Inc.; and 
Wolverine Power Supply Cooperative, Inc.
NARUC--National Association of Regulatory Commissioners
National Grid--National Grid USA and its affiliates
NCPA--Northern California Power Agency
NEPGA--New England Power Generators Association, Inc.
NEPOOL Participants--New England Power Pool Participants Committee
New England Power Generators--New England Power Generators 
Association, Inc.
New York PSC--New York State Public Service Commission
NIPSCO--Northern Indiana Public Service Company
New Jersey BPU--New Jersey Board of Public Utilities
North Carolina Electric Membership--North Carolina Electric 
Membership Corporation
Northeast Utilities--Northeast Utilities
NRECA--National Rural Electric Cooperative Association
NSTAR--NSTAR Electric Company
NYISO--New York Independent System Operator, Inc.
NY TOs--Central Hudson Gas & Electric Corporation, Consolidated 
Edison Company of New York, Inc., Long Island Power Authority, New 
York Power Authority, New York State Electric & Gas Corporation, 
Orange and Rockland Utilities, Inc., and Rochester Gas and Electric 
Corporation
Ohio PUC--Public Utilities Commission of Ohio
Old Dominion--Old Dominion Electric Cooperative
OMS--Organization of MISO States, whose participating members are: 
Illinois Commerce Commission, Indiana Utility Regulatory Commission, 
Iowa Utilities Board, Kentucky Public Service Commission, Michigan 
Public Service Commission, Minnesota Public Utilities Commission, 
Montana Public Service Commission, Nebraska Power Review Board, 
Public Utilities Commission of Ohio, South Dakota Public Utilities 
Commission, Wisconsin Public Service Commission. Participating 
associate members are: Indiana Office of Utility Consumer Counselor, 
Iowa Office of Consumer Advocate and the Minnesota Office of Energy 
Security
OPSI--Organization of PJM States, Inc., whose state commission 
members include: Delaware Public Service Commission, District of 
Columbia Public Service Commission, Illinois Commerce Commission, 
Indiana Utility Regulatory Commission, Kentucky Public Service 
Commission, Maryland Public Service Commission, Michigan Public 
Service Commission, New Jersey Board of Public Utilities, North 
Carolina Utilities Commission, Public Utilities Commission of Ohio, 
Pennsylvania Public Utility Commission, Tennessee Regulatory 
Authority, Virginia State Corporation Commission, and Public Service 
Commission of West Virginia
Orion Energy--Orion Energy Systems, Inc.
Pennsylvania PUC--Pennsylvania Public Utility Commission
PG&E--Pacific Gas and Electric Company
PJM--PJM Interconnection, LLC
PJM Power Providers--PJM Power Providers Group
Potomac Economics--Potomac Economics, Ltd.
PPL Parties--PPL Brunner Island, LLC; PPL Edgewood Energy, LLC; PPL 
Electric Utilities Corporation; PPL EnergyPlus, LLC; PPL Great 
Works, LLC; PPL Holtwood, LLC; PPL Maine, LLC; PPL Martins Creek, 
LLC; PPL Montana, LLC; PPL Montour, LLC; PPL Shoreham Energy, LLC; 
PPL Susquehanna, LLC; PPL University Park, LLC; PPL Wallingford 
Energy LLC; and Lower Mount Bethel Energy, LLC
Public Interest Organizations--Citizen Power; Conservation Law 
Foundation; Environment Northeast; Environmental Law & Policy 
Center; Fresh Energy; Izaak Walton League; Natural Resources Defense 
Council; Northwest Energy Coalition; Office of the Ohio Consumers' 
Counsel; Pace Energy Project; PennFuture; Project for Sustainable 
FERC Energy Policy; Southern Alliance for Clean Energy; The Stella 
Group, Ltd.; Union of Concerned Scientists; and Western Grid Group
Reliant--Reliant Energy, Inc.
Retail Energy--Retail Energy Supply Association
SMUD--Sacramento Municipal Utility District
SoCal Edison-SDG&E--Southern California Edison Company and San Diego 
Gas & Electric Company
Sorgo--Sorgo Fuels, Inc.
SPP--Southwest Power Pool, Inc.
Steel Manufacturers--Steel Manufacturers Association
Steel Producers--Nucor and Steel Dynamics
TANC--Transmission Agency of Northern California

[[Page 64172]]

TAPS--Transmission Access Policy Study Group
Wal-Mart--Wal-Mart Stores, Inc.
Xcel--Xcel Energy Services, Inc., on behalf of Northern States Power 
Company, a Minnesota corporation; Northern States Power Company, a 
Wisconsin corporation; Southwestern Public Service Company; and 
Public Service Company of Colorado

Abbreviated Names of Reply Commenters

Allied Public Interest Groups--Clean Energy First, Conservation Law 
Foundation, Environment Northeast, Environmental Law & Policy 
Center, Fresh Energy, Natural Resources Defense Council, Northwest 
Energy Coalition, Office of the Ohio Consumers' Counsel, Pace Energy 
and Climate Center, Penn Future, Project for Sustainable FERC Energy 
Policy, Renewable Northwest Project, and Union of Concerned 
Scientists.
CAISO and the Cities--CAISO and the cities of Anaheim, Azusa, 
Banning, Colton, and Riverside, California

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

Wholesale Competition in Regions with Organized Electric Markets

Docket Nos. RM07-19-000 and AD07-7-000

(Issued October 17, 2008)

KELLY, Commissioner, concurring in part and dissenting in part:

    I write separately for two reasons. First, I want to emphasize 
the importance of competition to the operation of organized 
wholesale electric markets and the fact that many of the findings 
here will help foster that competition. Second, I write to express 
my misgivings about the potential impacts of several of the 
directives included in the Final Rule.
    I believe that many of the Final Rule's findings will promote 
competition, thereby helping the Commission to fulfill our statutory 
mandate to ensure adequate and reliable service at just and 
reasonable rates. In particular, I support the Final Rule's 
requirements that regional transmission organizations (RTOs) and 
independent system operators (ISOs): (1) Accept bids for certain 
ancillary services from demand response resources that meet 
technical requirements and submit a bid at or below the market-
clearing price; (2) permit qualified aggregators of retail customers 
to bid demand response on behalf of retail customers; and (3) 
eliminate deviation charges during system emergencies to a purchaser 
of electric energy for taking less energy in the real-time market 
than it purchased in the day-ahead market. I also agree with 
requiring RTOs/ISOs to include a tariff provision that commits to 
providing market monitoring units (or MMUs) with the data, 
resources, and personnel necessary to carry out the MMUs' functions.
    I continue to be troubled by the Final Rule's directive to each 
RTO or ISO with an organized energy market to make a compliance 
filing to propose any necessary reforms to allow for scarcity 
pricing in times of emergency by modifying market power mitigation 
rules. The Final Rule states that existing RTO/ISO rules ``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.'' I recognize that the majority has good intentions in 
requiring RTOs/ISOs to make this filing. However, I believe that, 
prior to allowing energy supply offer caps and demand bid caps to 
rise or be eliminated, the necessary generation and demand response 
infrastructure must be in place to give consumers the ability to 
respond to higher prices. As Commission staff noted in the 2006 FERC 
Staff Demand Response Assessment, advanced metering currently has 
low market penetration of less than six percent in the United 
States.\1\ Without providing consumers with the ability to respond 
to rising prices, I view the decision to allow energy supply offer 
caps and demand bid caps to rise or be eliminated as irresponsible.
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    \1\ Assessment of Demand Response and Advanced Metering: Staff 
Report, Docket No. AD06-2-000, at 26 (2006) (2006 FERC Staff Demand 
Response Assessment).
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    Additionally, I disagree with the Final Rule's decision to 
promote responsiveness of RTOs/ISOs by allowing them to adopt hybrid 
boards with stakeholder members. Having an independent board is the 
cornerstone of RTO/ISO policy. Providing for stakeholder 
representatives on an RTO/ISO board jeopardizes such an independent 
governing structure. I agree with Duke Energy's statement that 
``hybrid boards are contrary to the premise of independent RTO 
governance, and that the board advisory committee is a much more 
effective means of helping RTO boards to understand member issues 
and concerns.'' \2\ I also fear that a board with independent and 
non-independent members will suffer from a divisive atmosphere with 
suspicion as to whether non-independent board members are acting in 
the best interests of the RTO/ISO and its customers or in the best 
interest of the particular market participant represented by that 
non-independent board member. I also share Pennsylvania PUC's 
concern that it will be difficult to protect competitively sensitive 
information with non-independent members serving on the RTO/ISO's 
board.\3\ I believe that a board advisory committee is a better way 
to address RTO/ISO responsiveness to stakeholders while maintaining 
the independence of RTO/ISO boards.
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    \2\ Duke Energy Corporation Apr. 21, 2008 Comments, Docket No. 
RM07-19, at 2;-3.
    \3\ See Pennsylvania PUC Apr. 21, 2008 Comments, Docket No. 
RM07-19, at 18.
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    Finally, as I noted previously in my separate statement 
regarding the notice of proposed rulemaking (NOPR),\4\ I am 
concerned about the issue of MMUs being removed from tariff 
administration and mitigation. I note that a large number and 
variety of commenters were also concerned about the NOPR proposal, 
including American Forest, California PUC, Indianapolis P&L, ISO New 
England, Industrial Coalitions, Maine PUC, NARUC, NEPOOL 
Participants, New York PSC, North Carolina Electric Membership, Ohio 
PUC, Old Dominion, OMS, Potomac Economics, and Xcel. ISO New England 
stated that it ``disagrees with the proposition that an MMU's 
performance of mitigation functions compromises the MMU's 
independence or distracts an MMU from its core functions,'' \5\ 
referring to the arguments against MMUs' involvement in mitigation 
as ``unconvincing.'' \6\ Maine PUC stated that ``[t]he Commission 
has not demonstrated that there is a lack of independence or a 
conflict of interest in having those who are experts in the areas of 
market mitigation performing day-to-day mitigation.'' \7\ Industrial 
Coalitions called the Commission's proposal, ``objectionable because 
it would place responsibility for mitigation in the hands of the 
RTO/ISO staff that designed, and have a vested interest in the 
success of, market rules.'' \8\
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    \4\ Wholesale Competition in Regions with Organized Electric 
Markets, Notice of Proposed Rulemaking, 73 FR 12,576 (Mar. 7, 2008), 
FERC Stats. & Regs. ] 32,628 (2008) (Comm'r Kelly concurring in part 
and dissenting in part).
    \5\ ISO New England Apr. 21, 2008 Comments, Docket No. RM07-19, 
at 19.
    \6\ Id.
    \7\ Maine PUC Apr. 21, 2008 Comments, Docket No. RM07-19, at 7.
    \8\ Industrial Coalitions Apr. 21, 2008 Comments, Docket No. 
RM07-19, at 22.
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    I do not mean to imply that the Final Rule totally ignores these 
concerns. Indeed, the Final Rule does make changes to the NOPR 
proposal by drawing a distinction between RTOs/ISOs that have a 
single MMU and those that have hybrid MMUs, with both an 
``external'' and ``internal'' market monitor. Under these changes, a 
RTO/ISO may allow its MMU--whether it is a single MMU or a hybrid 
MMU--to perform retrospective mitigation. However, only a RTO/ISO 
with both an internal and external MMU may allow its internal MMU to 
continue to perform prospective mitigation.\9\ In those instances, 
the internal MMU may perform the prospective mitigation, but only if 
the RTO/ISO moves the responsibility and the tools to monitor the 
quality and appropriateness of the mitigation conducted by the 
internal MMU to its external MMU. Finally, both single MMUs and 
hybrid MMUs may provide the RTO/ISO with the inputs needed for the 
RTO/ISO to conduct prospective mitigation, including ``reference 
levels, identification of system constraints, and cost 
calculations.''
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    \9\ The Final Rule considers prospective mitigation to include 
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 at or before the time they are considered in a 
market solution.
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    After this long, drawn-out process, I question what problem we 
are actually trying to solve with this proposal. MMUs are 
professionals who have been performing mitigation in a competent, 
professional, and efficient manner for many years. I disagree with 
the misgivings expressed in the Final Rule that ``unfettered conduct 
of mitigation by MMUs makes them subordinate to the RTOs and ISOs 
and raises conflict of interest concerns.'' I do not think the 
record supports

[[Page 64173]]

that assertion. I am also concerned that the dictates of the Final 
Rule may put some RTOs/ISOs to unnecessary expense. While the Final 
Rule has evolved in a positive way on this issue, I believe it 
continues to be an answer in search of a problem.
    Accordingly, for the reasons stated above, I concur in part and 
dissent in part on this Final Rule.

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Suedeen G. Kelly

 [FR Doc. E8-25246 Filed 10-27-08; 8:45 am]

BILLING CODE 6717-01-P