Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 39904-40046 [E7-13675]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 72, Number 139 (Friday, July 20, 2007)]
[Rules and Regulations]
[Pages 39904-40046]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E7-13675]



[[Page 39903]]

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Part II





Department of Energy





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 Federal Energy Regulatory Commission



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18 CFR Part 35



Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and 
Ancillary Services by Public Utilities; Final Rule

Federal Register / Vol. 72, No. 139 / Friday, July 20, 2007 / Rules 
and Regulations

[[Page 39904]]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM04-7-000; Order No. 697]


Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities

Issued June 21, 2007.
AGENCY: Federal Energy Regulatory Commission, Department of Energy.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission (Commission) is 
amending its regulations to revise Subpart H to Part 35 of Title 18 of 
the Code of Federal Regulations governing market-based rates for public 
utilities pursuant to the Federal Power Act (FPA). The Commission is 
codifying and, in certain respects, revising its current standards for 
market-based rates for sales of electric energy, capacity, and 
ancillary services. The Commission is retaining several of the core 
elements of its current standards for granting market-based rates and 
revising them in certain respects. The Commission also adopts a number 
of reforms to streamline the administration of the market-based rate 
program.

DATES: Effective Date: This rule will become effective September 18, 
2007.

FOR FURTHER INFORMATION CONTACT: 
Debra A. Dalton (Technical Information), Office of Energy Markets and 
Reliability, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-6253.
Elizabeth Arnold (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
Washington, DC 20426, (202) 502-8818.

SUPPLEMENTARY INFORMATION: 

                            Table of Contents
 
                                                              Paragraph
                                                                 Nos.
 
I. Introduction............................................            1
II. Background.............................................            7
III. Overview of Final Rule................................           12
IV. Discussion.............................................           33
    A. Horizontal Market Power.............................           33
        1. Whether to Retain the Indicative Screens........           33
        2. Indicative Market Share Screen Threshold Levels            80
         and Pivotal Supplier Application Period...........
            a. Market Share Threshold......................           82
            b. Pivotal Supplier Application Period.........           94
        3. DPT Criteria....................................           96
        4. Other Products and Models.......................          118
        5. Native Load Deduction...........................          125
            a. Market Share Indicative Screen..............          125
            b. Pivotal Supplier Indicative Screen..........          143
            c. Clarification of Definition of Native Load..          150
            d. Other Native Load Concerns..................          153
        6. Control and Commitment..........................          156
            a. Presumption of Control......................          164
            b. Requirement for Sellers to have a Rate on             212
             File..........................................
        7. Relevant Geographic Market......................          215
            a. Default Relevant Geographic Market..........          215
             b. NERC's Balancing Authority Area and Default          247
             Geographic Area...............................
            c. Additional Guidelines for Alternative                 253
             Geographic Market and Flexibility.............
            d. Specific Issues Related to Power Pools and            279
             SPP...........................................
            e. RTO/ISO Exemption...........................          285
        8. Use of Historical Data..........................          292
        9. Reporting Format................................          302
        10. Exemption for New Generation (Formerly Section           307
         35.27(a) of the Commission's Regulations).........
            a. Elimination of Exemption in Section 35.27(a)          307
            b. Grandfathering..............................          327
            c. Creation of a Safe Harbor...................          335
        11. Nameplate Capacity.............................          339
        12. Transmission Imports...........................          346
            a. Use of Historical Conditions and OASIS                348
             Practices.....................................
            b. Use of Total Transfer Capability (TTC)......          363
            c. Accounting for Transmission Reservations....          365
            d. Allocation of Transmission Imports based on           370
             Pro Rata Shares of Seller's Uncommitted
             Generation Capacity...........................
            e. Miscellaneous Comments......................          376
            f. Required SIL Study for DPT Analysis.........          382
        13. Procedural Issues..............................          387
    B. Vertical Market Power...............................          397
        1. Transmission Market Power.......................          400
            a. OATT Requirement............................          403
            b. OATT Violations and MBR Revocation..........          411
            c. Revocation of Affiliates' MBR Authority.....          422
        2. Other Barriers to Entry.........................          428
        3. Barriers Erected or Controlled by Other Than The          452
         Seller............................................
        4. Planning and Expansion Efforts..................          454
        5. Monopsony Power.................................          459
    C. Affiliate Abuse.....................................          464
        1. General Affiliate Terms and Conditions..........          464

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            a. Codifying Affiliate Restrictions in                   464
             Commission Regulations........................
            b. Definition of ``Captive Customers''.........          469
            c. Definition of ``Non-Regulated Power Sales             484
             Affiliate''...................................
            d. Other Definitions...........................          496
            e. Treating Merging Companies as Affiliates....          499
            f. Treating Energy/Asset Managers as Affiliates          503
            g. Cooperatives................................          518
        2. Power Sales Restrictions........................          529
        3. Market-Based Rate Affiliate Restrictions                  544
         (formerly Code of Conduct) for Affiliate
         Transactions Involving Power Sales and Brokering,
         Non-Power Goods and Services and Information
         Sharing...........................................
            a. Uniform Code of Conduct/Affiliate                     546
             Restrictions--Generally.......................
            b. Exceptions to the Independent Functioning             553
             Requirement...................................
            c. Information Sharing Restrictions............          570
            d. Definition of ``Market Information''........          590
            e. Sales of Non-Power Goods or Services........          595
            f. Service Companies or Parent Companies Acting          599
             on Behalf of and for the Benefit of a
             Franchised Public Utility.....................
    D. Mitigation..........................................          604
        1. Cost-Based Rate Methodology.....................          606
            a. Sales of One Week or Less...................          606
            b. Sales of more than one week but less than             632
             one year......................................
            c. Sales of one year or greater................          658
            d. Alternative methods of mitigation...........          660
        2. Discounting.....................................          699
        3. Protecting Mitigated Markets....................          720
            a. Must Offer..................................          720
            b. First-Tier Markets..........................          776
            c. Sales that Sink in Unmitigated Markets......          794
            d. Proposed Tariff Language....................          825
    E. Implementation Process..............................          832
        1. Category 1 and 2 Sellers........................          836
            a. Establishment of Category 1 and 2 Sellers...          836
            b. Threshold for Category 1 Sellers and Other            845
             Proposed Modifications........................
        2. Regional Review and Schedule....................          869
    F. MBR Tariff..........................................          897
        1. Tariff of General Applicability.................          901
        2. Placement of Terms and Conditions...............          925
        3. Single Corporate Tariff.........................          928
    G. Legal Authority.....................................          938
        1. Whether Market-Based Rates Can Satisfy the Just           938
         and Reasonable Standard Under the FPA.............
        Consistency of Market-based Rate Program with FPA            956
         Filing Requirements...............................
        2. Whether Existing Tariffs Must Be Found to Be              972
         Unjust and Unreasonable, and Whether the
         Commission Must Establish a Refund Effective Date.
    H. Miscellaneous.......................................          975
        1. Waivers.........................................          975
            a. Accounting Waivers..........................          979
            b. Timing......................................          988
            c. Part 34 Waivers Blanket Authorizations......          993
        2. Sellers Affiliated with a Foreign Utility.......         1000
        3. Change in Status................................         1008
            a. Fuel Supplies...............................         1011
            b. Transmission Outages........................         1019
            c. Control.....................................         1027
            d. Triggering Events...........................         1033
            e. Timing of Reporting.........................         1035
            f. Sellers Affiliated with a Foreign Utility...         1040
        4. Third-Party Providers of Ancillary Services.....         1046
            a. Internet Postings and Reporting Requirements         1052
            b. Pricing for Ancillary Services in RTOs/ISOs.         1062
        5. Reactive Power and Real Power Losses............         1072
            a. Reactive Power..............................         1073
            b. Real Power Losses...........................         1075
V. Section-by-Section Analysis of Regulations..............         1077
VI. Information Collection Statement.......................         1105
VII. Environmental Analysis................................         1124
VIII. Regulatory Flexibility Act...........................         1125
IX. Document Availability..................................         1129
X. Effective Date and Congressional Notification...........         1132
Regulatory Text
Appendix A to Subpart H: Standard Screen Format
Appendix B to Subpart H: Corporate Entities and Assets
 sample appendix
Appendix C to the Final Rule: Required Provisions of the
 Market-Based Rate Tariff

[[Page 39906]]

 
Appendix D to the Final Rule: Regions and Schedule for
 Regional Market power Update Process
Appendix E to the Final Rule: List of Commenters and
 Acronyms
Attachment A to the Final Rule: MOELLER, Commissioner,
 dissenting in part
 

Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. 
Kelly, Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

    1. On May 19, 2006, the Commission issued a Notice of Proposed 
Rulemaking (NOPR), pursuant to sections 205 and 206 of the Federal 
Power Act (FPA),\1\ in which the Commission proposed to amend its 
regulations governing market-based rate authorizations for wholesale 
sales of electric energy, capacity and ancillary services by public 
utilities. In the NOPR, the Commission proposed to modify all existing 
market-based authorizations and tariffs so they would reflect any new 
requirements ultimately adopted in the Final Rule. After considering 
the comments received in response to the NOPR, the Commission adopts in 
many respects the proposals contained in the NOPR, but with a number of 
modifications.
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    \1\ 16 U.S.C. 824d, 824e.
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    2. This Final Rule represents a major step in the Commission's 
efforts to clarify and codify its market-based rate policy by providing 
a rigorous up-front analysis of whether market-based rates should be 
granted, including protective conditions and ongoing filing 
requirements in all market-based rate authorizations, and reinforcing 
its ongoing oversight of market-based rates. The specific components of 
this rule, in conjunction with other regulatory activities, are 
designed to ensure that market-based rates charged by public utilities 
are just and reasonable. There are three major aspects of the 
Commission's market-based rate regulatory regime.
    3. First is the analysis that is the subject of this rule: whether 
a market-based rate seller or any of its affiliates has market power in 
generation or transmission and, if so, whether such market power has 
been mitigated.\2\ If the seller is granted market-based rates, the 
authorization is conditioned on: affiliate restrictions governing 
transactions and conduct between power sales affiliates where one or 
more of those affiliates has captive customers; a requirement to file 
post-transaction electric quarterly reports (EQRs) containing specific 
information about contracts and transactions; a requirement to file any 
change of status; and a requirement for all large sellers to file 
triennial updates.\3\
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    \2\ The Commission also considers whether the seller or its 
affiliates can erect other barriers to entry (e.g., key sites for 
building new power supply; key inputs to power supply) in the 
relevant market and whether there is evidence of affiliate abuse or 
reciprocal dealing.
    \3\ During the past three years, the Commission has initiated 
over 20 investigations under section 206 of the FPA because of 
concerns of possible market power. Several of those investigations 
led to the revocation or voluntary relinquishing of market-based 
rate authority and the ordering of refunds by sellers.
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    4. Second, for wholesale sellers that have market-based rate 
authority and sell into day ahead or real-time organized markets 
administered by Regional Transmission Organizations (RTOs) and 
Independent System Operators (ISOs), they do so subject to specific 
RTO/ISO market rules approved by the Commission and applicable to all 
market participants. These rules are designed to help ensure that 
market power cannot be exercised in those organized markets and include 
additional protections (e.g., mitigation measures) where appropriate to 
ensure that prices in those markets are just and reasonable. Thus, a 
seller in such markets not only must have an authorization based on an 
analysis of that individual seller's market power, but it must also 
abide by additional rules contained in the RTO/ISO tariffs.
    5. Third, the Commission, through its ongoing oversight of market-
based rate authorizations and market conditions, may take steps to 
address seller market power or modify rates. For example, based on its 
review of triennial market power updates required of market-based rate 
sellers, its review of EQR filings made by market-based rate sellers, 
and its review of required notices of change in status, the Commission 
may institute a section 206 proceeding to revoke a seller's market-
based rate authorization if it determines that the seller may have 
gained market power since its original market-based rate authorization. 
The Commission may also, based on its review of EQR filings or daily 
market price information, investigate a specific utility or anomalous 
market circumstances to determine whether there has been any conduct in 
violation of RTO/ISO market rules or Commission orders or tariffs, or 
any prohibited market manipulation, and take steps to remedy any 
violations. These steps could include, among other things, disgorgement 
of profits and refunds to customers if a seller is found to have 
violated Commission orders, tariffs or rules, or a civil penalty paid 
to the United States Treasury if a seller is found to have engaged in 
prohibited market manipulation or to have violated Commission orders, 
tariffs or rules.
    6. The Commission recognizes that several recent court decisions by 
the United States Court of Appeals for the Ninth Circuit \4\ have 
created some uncertainty for sellers transacting pursuant to our 
market-based rate program. The cases raise issues with respect to the 
circumstances under which sellers' pre-authorized market-based rate 
sales may be subject to retroactive refunds and the circumstances under 
which buyers might be able to invalidate or modify contracts based on 
the argument that the contracts were entered into at a time when 
markets were dysfunctional. The Commission's first and foremost duty is 
to protect customers from unjust and unreasonable rates; however, we 
recognize that uncertainties regarding rate stability and contract 
sanctity can have a chilling effect on investments and a seller's 
willingness to enter into long-term contracts and this, in turn, can 
harm customers in the long run. The Commission recently provided 
guidance in this regard, noting that these Ninth Circuit decisions 
addressed a unique set of facts and a market-based rate program that 
has undergone substantial improvement since 2001, and reiterating that 
an ex ante finding of the absence of market power, coupled with the EQR 
filing and effective regulatory oversight qualifies as sufficient prior 
review for market-based rate contracts to satisfy the notice and filing 
requirements of FPA section 205.\5\ Through this Final Rule, the 
Commission is clarifying and further

[[Page 39907]]

improving its market-based rate program. Moreover, the Commission will 
explore ways to continue to improve its market-based rate program and 
processes to assure appropriate customer protections but at the same 
time provide greater regulatory and market certainty for sellers in 
light of the above court opinions.
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    \4\ See State of California, ex rel. Bill Lockyer v. FERC, 383 
F.3d 1006 (9th Cir. 2004), cert. denied (S. Ct. Nos. 06-888 and 06-
1100, June 18, 2007) (Lockyer); Public Utility District No. 1 of 
Snohomish County, Washington v. FERC, 471 F.3d 1053 (9th Cir. 2006) 
(Snohomish); Public Utilities Commission of the State of California 
and California Electric Oversight Board v. FERC, 474 F.3d 587 (9th 
Cir. 2007) (California Commission).
    \5\ CAlifornians for Renewable Energy, Inc. v. Cal. Pub. Util. 
Com'n, 119 FERC ] 61,058 (2007).
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II. Background

    7. In 1988, the Commission began considering proposals for market-
based pricing of wholesale power sales. The Commission acted on market-
based rate proposals filed by various wholesale suppliers on a case-by-
case basis. Over the years, the Commission developed a four-prong 
analysis used to assess whether a seller should be granted market-based 
rate authority: (1) Whether the seller and its affiliates lack, or have 
adequately mitigated, market power in generation; (2) whether the 
seller and its affiliates lack, or have adequately mitigated, market 
power in transmission; (3) whether the seller or its affiliates can 
erect other barriers to entry; and (4) whether there is evidence 
involving the seller or its affiliates that relates to affiliate abuse 
or reciprocal dealing.
    8. The Commission initiated the instant rulemaking proceeding in 
April 2004 to consider ``the adequacy of the current analysis and 
whether and how it should be modified to assure that prices for 
electric power being sold under market-based rates are just and 
reasonable under the Federal Power Act.'' \6\ At that time, the 
Commission noted that much has changed in the industry since the four-
prong analysis was first developed and posed a number of questions that 
would be explored through a series of technical conferences.
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    \6\ Market-Based Rates for Public Utilities, 107 FERC ] 61,019 
AT P 1(2004) (initiating rulemaking proceeding).
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    9. On April 14, 2004, the Commission issued an order modifying the 
then-existing generation market power analysis and its policy governing 
market power mitigation, on an interim basis.\7\ The April 14 Order 
adopted a policy that provided sellers a number of procedural options, 
including two indicative generation market power screens (an 
uncommitted pivotal supplier analysis and an uncommitted market share 
analysis), and the option of proposing mitigation tailored to the 
particular circumstances of the seller that would eliminate the ability 
to exercise market power. The order also explained that sellers could 
choose to adopt cost-based rates. On July 8, 2004, the Commission 
addressed requests for rehearing of the April 14 Order, reaffirming the 
basic analysis, but clarifying and modifying certain instructions for 
performing the generation market power analysis. Over the next year, 
the Commission convened four technical conferences, seeking input 
regarding all four prongs of the analysis.
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    \7\ AEP Power Marketing, Inc., 107 FERC ] 61,018 (April 14 
Order), order on reh'g, 108 FERC ] 61,026 (2004) (July 8 Order).
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    10. On May 19, 2006, the Commission issued a NOPR in this 
proceeding.\8\ The Commission explained that refining and codifying 
effective standards for market-based rates would help customers by 
ensuring that they are protected from the exercise of market power and 
would also provide greater certainty to sellers seeking market-based 
rate authority.
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    \8\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, Notice of 
Proposed Rulemaking, 71 FR 33102 (Jun. 7, 2006), FERC Stats. & Regs. 
] 32,602 (2006) (NOPR).
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    11. The regulations proposed in the NOPR adopted in most respects 
the Commission's existing standards for granting market-based rates, 
and proposed to streamline certain aspects of its filing requirements 
to reduce the administrative burdens on sellers, customers and the 
Commission. The Commission received over 100 comments and reply 
comments in response to the NOPR. A list of commenters is attached as 
Appendix E.

III. Overview of Final Rule

    12. In this Final Rule, the Commission revises and codifies in the 
Commission's regulations the standards for market-based rates for 
wholesale sales of electric energy, capacity and ancillary services. 
The Commission also adopts a number of reforms to streamline the 
administration of the market-based rate program. As set forth below, 
the Final Rule adopts in many respects the proposals contained in the 
NOPR, but with a number of modifications.

Horizontal Market Power

    13. In this Final Rule, the Commission adopts, with certain 
modifications, two indicative market power screens (the uncommitted 
market share screen (with a 20 percent threshold) and the uncommitted 
pivotal supplier screen), each of which will serve as a cross check on 
the other to determine whether sellers may have market power and should 
be further examined. Sellers that fail either screen will be rebuttably 
presumed to have market power. However, such sellers will have full 
opportunity to present evidence (through the submission of a Delivered 
Price Test (DPT) analysis) demonstrating that, despite a screen 
failure, they do not have market power, and the Commission will 
continue to weigh both available economic capacity and economic 
capacity when analyzing market shares and Hirschman-Herfindahl Indices 
(HHIs).
    14. With regard to control over generation capacity, the Commission 
finds that the determination of control is appropriately based on a 
review of the totality of circumstances on a fact-specific basis. No 
single factor or factors necessarily results in control. The Commission 
will require a seller to make an affirmative statement as to whether a 
contractual arrangement (energy management agreement, tolling 
agreement, specific contractual terms, etc.) transfers control and to 
identify the party or parties it believes controls the generation 
facility. Regarding a presumption of control, the Commission will 
continue its practice of attributing control to the owner absent a 
contractual agreement transferring such control, and we provide 
guidance as to how we will consider jointly-owned facilities.
    15. The Commission adopts its current approach with regard to the 
default relevant geographic market, with some modifications. In 
particular, the Commission will continue to use a seller's control area 
(balancing authority area) \9\ or the RTO/ISO market, as applicable, as 
the default relevant geographic market. However, where the Commission 
has made a specific finding that there is a submarket within an RTO, 
that submarket becomes the default relevant geographic market for 
sellers located within the submarket for purposes of the market-based 
rate analysis. The Commission also provides guidance as to the factors 
the Commission will consider in evaluating whether, in a particular 
case, to adopt an alternative geographic market instead of relying on 
the default geographic market.
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    \9\ As discussed below in the Horizontal Market Power section, 
the Commission adopts the use of balancing authority area instead of 
control area.
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    16. The Commission modifies the native load proxy for the market 
share screens from the minimum peak day in the season to the average 
peak native load, averaged across all days in the season, and clarifies 
that native load can only include load attributable to native load 
customers based on the definition of native load commitment in Sec.  
33.3(d)(4)(i) of the Commission's regulations. In addition, sellers are

[[Page 39908]]

given the option of using seasonal capacity instead of nameplate 
capacity.
    17. The Commission retains the snapshot in time approach based on 
historical data for both the indicative screens and the DPT analysis 
and disallows projections to that data. A standard reporting format is 
adopted for sellers to follow when summarizing their analysis.
    18. The Commission modifies the treatment of newly constructed 
generation and adopts an approach that requires all sellers to perform 
a horizontal analysis for the grant of market-based rate authority.
    19. With regard to simultaneous transmission import limit studies 
(SILs), the Commission adopts the requirement that the SIL study be 
used as a basis for transmission access for both the indicative screens 
and the DPT analysis. Further, the Commission clarifies that the SIL 
study as shown in Appendix E of the April 14 Order is the only study 
that meets our requirements. The Commission provides guidance regarding 
how to perform the SIL study, including accounting for specific OASIS 
practices.
    20. Finally, the Commission adopts procedures under which 
intervenors in section 205 proceedings may obtain expedited access to 
Critical Energy Infrastructure Information (CEII) or other information 
for which privileged treatment is sought.

Vertical Market Power

    21. With regard to vertical market power and, in particular, 
transmission market power, the Commission continues the current policy 
under which an open access transmission tariff (OATT) is deemed to 
mitigate a seller's transmission market power. However, in recognition 
of the fact that OATT violations may nonetheless occur, the Commission 
states that a finding of a nexus between the specific facts relating to 
the OATT violation and the entity's market-based rate authority may 
subject the seller to revocation of its market-based rate authority or 
other remedies the Commission may deem appropriate, such as 
disgorgement of profits or civil penalties. In addition, the Commission 
creates a rebuttable presumption that all affiliates of a transmission 
provider should lose their market-based rate authority in each market 
in which their affiliated transmission provider loses its market-based 
rate authority as a result of an OATT violation.
    22. With regard to other barriers to entry, the Commission adopts 
the NOPR proposal to consider a seller's ability to erect other 
barriers to entry as part of the vertical market power analysis, but 
modifies the requirements when addressing other barriers to entry. The 
Commission also provides clarification regarding the information that a 
seller must provide with respect to other barriers to entry (including 
which inputs to electric power production the Commission will consider 
as other barriers to entry). The Commission adopts a rebuttable 
presumption that ownership or control of, or affiliation with an entity 
that owns or controls, intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
generation capacity development; and sources of coal supplies and the 
transportation of coal supplies such as barges and rail cars do not 
allow a seller to raise entry barriers, but intervenors are allowed to 
demonstrate otherwise. The Final Rule also requires a seller to provide 
a description of its ownership or control of, or affiliation with an 
entity that owns or controls, intrastate natural gas transportation, 
intrastate natural gas storage or distribution facilities; sites for 
generation capacity development; and sources of coal supplies and the 
transportation of coal supplies such as barges and rail cars. The 
Commission will require sellers to provide this description and to make 
an affirmative statement that they have not erected barriers to entry 
into the relevant market and will not erect barriers to entry into the 
relevant market. The Final Rule clarifies that the obligation in this 
regard applies both to the seller and its affiliates, but is limited to 
the geographic market(s) in which the seller is located.

Affiliate Abuse

    23. With regard to affiliate abuse, the Commission adopts the NOPR 
proposal to discontinue considering affiliate abuse as a separate 
``prong'' of the market-based rate analysis and instead to codify 
affiliate restrictions in the Commission's regulations and address 
affiliate abuse by requiring that the provisions provided in the 
affiliate restrictions be satisfied on an ongoing basis as a condition 
of obtaining and retaining market-based rate authority. As codified in 
this Final Rule, the affiliate restrictions include a provision 
prohibiting power sales between a franchised public utility with 
captive customers and any market-regulated power sales affiliates\10\ 
without first receiving Commission authorization for the transaction 
under section 205 of the FPA. The Commission also codifies as part of 
the affiliate restrictions the requirements that previously have been 
known as the market-based rate ``code of conduct'' (governing the 
separation of functions, the sharing of market information, sales of 
non-power goods or services, and power brokering), as clarified and 
modified in this Final Rule. The Commission modifies certain of these 
provisions, including separation of functions and information sharing, 
consistent with certain requirements and exceptions contained in the 
Commission's standards of conduct.\11\ In the Final Rule the Commission 
defines ``captive customers'' as ``any wholesale or retail electric 
energy customers served under cost-based regulation'' and provides 
clarification that the definition of ``captive customers'' does not 
include those customers who have retail choice, i.e., the ability to 
select a retail supplier based on the rates, terms and conditions of 
service offered. In addition, among other clarifications, the 
Commission clarifies and modifies the definition of ``non-regulated 
power sales affiliate,'' and changes the term to ``market-regulated 
power sales affiliate.''
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    \10\ In the NOPR, the Commission proposed to define the term 
``non-regulated power sales affiliate.'' As discussed below, this 
Final Rule uses the term ``market-regulated power sales affiliate'' 
instead.
    \11\ 18 CFR part 358.
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    24. The Commission also provides clarification as to what types of 
affiliate transactions are permissible and the criteria used to make 
those decisions, and how the Commission will treat merging partners. In 
addition, the Commission codifies in the regulations a prohibition on 
the use of third-party entities, including energy/asset managers, to 
circumvent the affiliate restrictions, but does not adopt the NOPR 
proposal to treat energy/asset managers as affiliates. The Commission 
also provides clarification regarding the Commission's market-based 
rate policies as they relate to cooperatives.

Mitigation

    25. With regard to mitigation, in the Final Rule the Commission 
retains the incremental cost plus 10 percent methodology as the default 
mitigation for sales of one week or less; the default mitigation rate 
for mid-term sales (sales of more than one week but less than one year) 
priced at an embedded cost ``up to'' rate reflecting the costs of the 
unit(s) expected to provide the service; and the existing policy for 
sales of one year or more (long-term) sales.\12\ The

[[Page 39909]]

Commission will continue to allow sellers to propose alternative cost-
based methods of mitigation tailored to their particular circumstances. 
The Final Rule also states that the Commission will make its stacking 
methodology available for the public.\13\ In addition, the Commission 
will continue the practice of allowing discounting and will permit 
selective discounting by mitigated sellers provided that the sellers do 
not use such discounting to unduly discriminate or give undue 
preference.
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    \12\ We note here that we expect mitigated sellers adopting the 
default cost-based rates or proposing new cost-based rates will 
propose a cost-based rate tariff of general applicability for sales 
of less than one year, and sales of power for one year or longer 
will be filed with the Commission on a stand-alone basis.
    \13\ This is addressed in the Mitigation section discussion 
concerning the cost-based rate methodology for sales of more than 
one week but less than one year.
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    26. The Commission concludes that use of the Western Systems Power 
Pool (WSPP) Agreement may be unjust, unreasonable or unduly 
discriminatory or preferential for certain sellers. Therefore, in an 
order being issued concurrently with this Final Rule, the Commission is 
instituting a proceeding under section 206 of the FPA to investigate 
whether, for sellers found to have market power or presumed to have 
market power in a particular market, the WSPP Agreement rate for 
coordination energy sales is just and reasonable in such market.
    27. The Commission does not impose an across-the-board ``must 
offer'' requirement for mitigated sellers. While wholesale customer 
commenters have raised concerns relating to their ability to access 
needed power, the Commission concludes that there is insufficient 
record evidence to support instituting a generic ``must offer'' 
requirement.
    28. The Commission limits mitigation to the market in which the 
seller has been found to possess, or chosen not to rebut the 
presumption of, market power and does not place limitations on a 
mitigated seller's ability to sell at market-based rates in areas in 
which the seller has not been found to have market power.
    29. Finally, regarding mitigation, the Final Rule allows mitigated 
sellers to make market-based rate sales at the metered boundary between 
a mitigated balancing authority area and a balancing authority area in 
which the seller has market-based rate authority under the conditions 
set forth herein, including a record retention requirement, and 
provides a tariff provision to allow for such sales.

Implementation Process

    30. The Commission adopts the NOPR proposal to create a category of 
sellers (Category 1 sellers) that are exempt from the requirement to 
automatically submit updated market power analyses, with certain 
clarifications and modifications. In addition, the Commission adopts 
the NOPR proposal to implement a regional approach to updated market 
power analyses, but reduces the number of regions from nine to six.
    31. As for a standardized tariff, the Commission does not adopt the 
NOPR proposal to adopt a market-based rate tariff of general 
applicability that all market-based rate sellers will be required to 
file as a condition of market-based rate authority and to require each 
corporate family to have only one tariff, with all affiliates with 
market-based rate authority separately identified in the tariff. 
Instead, the Commission adopts specific market-based rate tariff 
provisions that the Commission will require to be part of a seller's 
market-based rate tariff. However, the Commission will allow a seller 
to include seller specific terms and conditions in its market-based 
rate tariff, but the Commission will not review any of these 
provisions, as they are presumed to be just and reasonable based on the 
Commission's finding that the seller and its affiliates lack or have 
adequately mitigated market power in the relevant market.

Miscellaneous Issues

    32. The Commission also provides clarifications in the Final Rule 
with regard to accounting waivers, Part 34 blanket authorizations, 
sellers affiliated with foreign entities, and the change in status 
reporting requirement. Further, the Commission abandons the posting 
requirements for third party sellers of ancillary services at market-
based rates as redundant of other reporting requirements.

IV. Discussion

A. Horizontal Market Power

1. Whether To Retain the Indicative Screens
    33. As discussed in detail below, the Commission is adopting in 
this Final Rule two indicative horizontal market power screens, each of 
which will serve as a cross-check on the other to determine whether 
sellers may have market power and should be further examined. Although 
some sellers disagree with the use of two screens or find flaws in 
them, we conclude that this conservative approach will allow the 
Commission to more readily identify potential market power. Sellers 
that fail either screen will be rebuttably presumed to have market 
power. However, such sellers will have full opportunity to present 
evidence (through the submission of a DPT analysis) demonstrating that, 
despite a screen failure, they do not have market power. No screen is 
perfect, but we believe this approach appropriately balances the need 
to protect against market power with the desire not to place 
unnecessary filing burdens on utilities.
    34. The first screen is the wholesale market share screen, which 
measures for each of the four seasons whether a seller has a dominant 
position in the market based on the number of megawatts of uncommitted 
capacity owned or controlled by the seller as compared to the 
uncommitted capacity of the entire relevant market.\14\
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    \14\ April 14 Order, 107 FERC ] 61,018 at P 100.
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    35. The second screen is the pivotal supplier screen, which 
evaluates the potential of a seller to exercise market power based on 
uncommitted capacity at the time of the balancing authority area's 
annual peak demand. This screen focuses on the seller's ability to 
exercise market power unilaterally. It examines whether the market 
demand can be met absent the seller during peak times. A seller is 
pivotal if demand cannot be met without some contribution of supply by 
the seller or its affiliates.\15\
---------------------------------------------------------------------------

    \15\ Id. at P 72.
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    36. Use of the two screens together enables the Commission to 
measure market power at both peak and off-peak times, and to examine 
the seller's ability to exercise market power unilaterally and in 
coordinated interaction with other sellers. Use of the two screens, 
therefore, provides a more complete picture of a seller's ability to 
exercise market power.\16\
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    \16\ Id.
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    37. As discussed more fully in the following sections, with regard 
to determining the total supply in the relevant market, the horizontal 
market power analysis centers on and examines the balancing authority 
area where the seller's generation is physically located. Total supply 
is determined by adding the total amount of uncommitted capacity 
located in the relevant market (including capacity owned by the seller 
and competing suppliers) with that of uncommitted supplies that can be 
imported (limited by simultaneous transmission import capability) into 
the relevant market from the first-tier markets.
    38. Uncommitted capacity is determined by adding the total 
nameplate or seasonal capacity \17\ of

[[Page 39910]]

generation owned or controlled through contract and firm purchases, 
less operating reserves, native load commitments and long-term firm 
sales.\18\ Uncommitted capacity from a seller's remote generation 
(generation located in an adjoining balancing authority area) should be 
included in the seller's total uncommitted capacity amounts. Any 
simultaneous transmission import capability should first be allocated 
to the seller's uncommitted remote generation. Any remaining 
simultaneous transmission import capability would then be allocated to 
any uncommitted competing supplies.
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    \17\ As discussed more fully below, in this Final Rule, the 
Commission gives sellers the option of using seasonal capacity 
instead of nameplate capacity.
    \18\ Sellers may deduct generation associated with their long-
term firm requirements sales, unless the Commission disallows such 
deductions based on extraordinary circumstances.
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    39. Capacity reductions as a result of operating reserve 
requirements should be no higher than State and Regional Reliability 
Council operating requirements for reliability (i.e., operating 
reserves). Any proposed amounts that are higher than such requirements 
must be fully supported and will be considered on a case-by-case basis. 
Moreover, if an intervenor provides conclusive evidence that a seller 
did not in actual practice comply with the NERC or regional reliability 
council operating reserve requirements, then we will take this into 
account in determining the amount of the operating reserve deduction. 
However, we emphasize that we expect each utility to meet its NERC and 
regional reliability council reserve requirements, and that absent a 
clear showing to the contrary by an intervenor, the required operating 
reserve requirement is what we will use as the deduction in the market-
based rate calculation.\19\
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    \19\ April 14 Order, 107 FERC ] 61,018 at P96.
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    40. The Commission does not expect that sellers will have planned 
generation outages scheduled for the annual peak load day. However, on 
a case-by-case basis, the Commission will consider credible evidence 
that planned generation outages for the peak load day of the year 
should be included based on the particular circumstances of the 
seller.\20\
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    \20\ As noted below, the market share screen deducts generation 
capacity used for planned outages (that were done in accordance with 
good utility practice) in all four seasons in order to reflect the 
typical operation of generation units.
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    41. With regard to the pivotal supplier analysis, after computing 
the total uncommitted supply available to serve the relevant market, 
the next step in this analysis involves identifying the wholesale 
market. The proxy for the wholesale load is the annual peak load 
(needle peak) less the proxy for native load obligation (i.e., the 
average of the daily native load peaks during the month in which the 
annual peak load day occurs). Peak load is the largest electric power 
requirement (based on net energy for load) during a specific period of 
time, usually integrated over one clock hour and expressed in 
megawatts, for the native load and firm wholesale requirements sales.
    42. To calculate the net uncommitted supply available to compete at 
wholesale, the pivotal supplier analysis deducts the wholesale load 
from the total uncommitted supply. If the seller's uncommitted capacity 
is less than the net uncommitted supply, the seller satisfies the 
pivotal supplier portion of the generation market power analysis and 
passes the screen. If the seller's uncommitted capacity is equal to or 
greater than the net uncommitted supply, then the seller fails the 
pivotal supplier analysis which creates a rebuttable presumption of 
market power.
    43. With regard to the wholesale market share analysis, which 
measures for each of the four seasons whether a seller has a dominant 
position in the market based on the number of megawatts of uncommitted 
capacity owned or controlled by the seller as compared to the 
uncommitted capacity of the entire relevant market, uncommitted 
capacity amounts are used, as described above, with the following 
variation. Planned outages (that were done in accordance with good 
utility practice) for each season will be considered. Planned outage 
amounts should be consistent with those as reported in FERC Form No. 
714. To determine the amount of planned outages for a given season, the 
total number of MW-days of outages is divided by the total number of 
days in the season. For example, if 500 MW of generation that is out 
for six days during the winter period the calculation of planned 
outages would be: (500 MW x 6)/91 or 33 MW.
    44. The market share analysis adopts an initial threshold of 20 
percent. That is, a seller who has less than a 20 percent market share 
in the relevant market for all seasons will be considered to satisfy 
the market share analysis.\21\ A seller with a market share of 20 
percent or more in the relevant market for any season will have a 
rebuttable presumption of market power but can present historical 
evidence to show that the seller satisfies our generation market power 
concerns.
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    \21\ The 20 percent threshold is consistent with Sec.  4.134 of 
the U.S. Department of Justice 1984 Merger Guidelines issued June 
14, 1984, reprinted in Trade Reg. Rep. P13,103 (CCH 1988): ``The 
Department [of Justice] is likely to challenge any merger satisfying 
the other conditions in which the acquired firm has a market share 
of 20 percent or more.''
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Commission Proposal
    45. In the NOPR, the Commission proposed to retain the indicative 
screens (pivotal supplier and market share) to assess horizontal market 
power that were initially adopted in April 2004.\22\ Because the 
indicative screens are intended only to identify the sellers that 
require further review, the Commission proposed to retain the 20 
percent threshold for the wholesale market share indicative screen, 
stating that the 20 percent market share threshold strikes the right 
balance in seeking to avoid both ``false negatives'' and ``false 
positives.'' The Commission also proposed to continue to measure 
pivotal suppliers at the time of the annual peak load in the pivotal 
supplier indicative screen, which is the most likely point in time that 
a seller will be a pivotal supplier. For this reason, the Commission 
did not propose to expand the pivotal supplier analysis to other time 
periods.
---------------------------------------------------------------------------

    \22\ See April 14 Order, 107 FERC  61,018.
---------------------------------------------------------------------------

Comments
    46. Numerous commenters question whether the Commission should 
retain the current indicative screens in whole or in part. For example, 
Southern, Duke and EEI advocate abandoning the market share indicative 
screen altogether. They argue that the market share indicative screen 
is ``fatally flawed'' because it does not take into account wholesale 
demand in the relevant market \23\ which makes it difficult for 
traditional utilities outside of RTOs/ISOs to pass.\24\ E.ON. US. and 
PNM/Tucson separately argue that one must consider the level of demand 
that is seeking supply and, more particularly, what ability sellers 
have to exercise market power over those buyers.\25\ In this regard, 
E.ON. US. and

[[Page 39911]]

PNM/Tucson argue that to the extent the market share screen does not 
consider wholesale demand, it is not a useful indicator, and in fact is 
almost universally a false indicator of the ability of a seller to 
exercise market power over demand. Also, EEI argues that because of 
design flaws inherent in the market share screen as well as the 
negative impact that the use of this test has had since 2004 on the 
development of competitive wholesale markets (through the inappropriate 
exclusion of the majority of non-RTO utilities from participating in 
that market), the market share screen should be eliminated for all 
market power screening and analysis purposes.\26\
---------------------------------------------------------------------------

    \23\ Southern at 11, Duke at 20, EEI at 6-7.
    \24\ Duke at 17, EEI at 8-9.
    \25\ E.ON. US. at 16-17 and PNM/Tucson at 5-6. According to 
E.ON. US. and PNM/Tucson, the past decade has seen strong 
development in the West of open access to transmission and the 
ownership of generating assets, solely or jointly, by formerly 
``captive'' wholesale customers. As a result, any analysis that has 
as its foundation division of the market into suppliers and 
presumptively captive customers is at odds with present reality, in 
which wholesale customers have a host of suppliers seeking their 
business. E.ON. US. and PNM/Tucson state that an illustration of how 
open access in the West has enhanced the ability of load serving 
entities to secure competitive resources on an efficient scale 
across control areas is provided by a recent Southwest Public Power 
Resources Group request for proposals for 255 MW in 2007, growing to 
962 MW by 2014 in four control areas--Arizona Public Service, Salt 
River Project, Western Area Power Administration-Desert Southwest 
Region and Tucson Electric. (The Southwest Public Power Resources 
Group represents thirty-nine public power entities in Arizona, 
California, and Nevada.) See Southwestern Public Utilities Issue 
Long-Term RFP, ELECTRIC POWER DAILY, July 14, 2006, at 3.
    \26\ EEI at 10.
---------------------------------------------------------------------------

    47. EEI contends that the Commission should use only the pivotal 
supplier screen for indicative screening purposes and the DPT pivotal 
supplier and market concentration analyses for the purposes of 
rebutting the presumption of generation market power that would result 
from the failure of the indicative pivotal supplier screen. EEI argues 
that if the Commission continues to use the market share screen as an 
initial screen, the Commission should not include a market share test 
as a component of any subsequent DPT analysis of market power.
    48. E.ON U.S. and PNM/Tucson generally agree, stating that market 
share is an unreliable measure of market power in competitive energy 
markets and that the courts have long recognized that market share is 
not a reliable indicator of market power in regulated markets.\27\ In 
particular, E.ON U.S. and PNM/Tucson argue that even a marginal failure 
of the market share screen results in a rebuttable presumption of 
market power that has tremendous consequences by forcing sellers to 
proceed to costly and time-consuming DPT analysis or agree to 
mitigation. As a result, the ``false positives'' arising from the 
market share screen dampen the vigor of competitive wholesale market 
participation by unnecessarily curtailing the market-based authority of 
entities that, in fact, lack market power (to the extent such entities 
choose not to pursue a costly and uncertain effort to rebut the 
presumption of market power created by the screen failure).\28\
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    \27\ Citing Cost Mgmt. Servs., Inc. v. Wash. Natural Gas Co., 99 
F.3d 937, 950-51 (9th Cir. 1996) (Cost Management); Rebel Oil Co., 
Inc. v. Atl. Richfield Co., 51 F.3d 1421, 1439 (9th Cir. 1995) 
(Rebel); S. Pac. Communications Co. v. AT&T Co., 740 F.2d 980, 1000 
(D.C. Cir. 1984) (Southern Pacific Communications); MCI 
Communications Corp. v. AT&T Co., 708 F.2d 1081, 1107 (7th Cir. 
1983) (MCI Communications); Mid-Tex. Communications Sys., Inc. v. 
AT&T Co., 615 F.2d 1372, 1386-89 (5th Cir. 1980) (Mid-Tex 
Communications); Almeda Mall, Inc. v. Houston Lighting & Power Co., 
615 F.2d 343, 354 (5th Cir. 1980) (Almeda).
    \28\ E.ON U.S. at 16; PNM/Tucson at 5-6.
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    49. Duke and Southern suggest that a wholesale contestable load 
analysis (also described as a ``competitive alternatives'' analysis) 
\29\ should be added to the indicative screens, which would consider 
the amount of excess market supply available to serve the amount of 
wholesale demand seeking supply.\30\ Generally, if available non-
applicant supply is at least twice the contestable load, advocates of 
the contestable load analysis believe that is sufficient to make a 
finding that the market is competitive.\31\ Other commenters agree that 
the market share indicative screen can diminish competition because 
sellers that are subjects of an FPA section 206 investigation tend to 
choose mitigation rather than challenge the presumption of market 
power.\32\
---------------------------------------------------------------------------

    \29\ Dr. Pace at 12.
    \30\ Duke at 21, Southern at 16-17.
    \31\ Dr. Pace at 16.
    \32\ E.ON U.S. at 15-16; PNM/Tucson at 5-6, EEI at 10.
---------------------------------------------------------------------------

    50. Duke argues that the Commission has yet to establish a need for 
using the market share indicative screen in addition to the pivotal 
supplier indicative screen in assessing the potential for the exercise 
of generation market power. In this regard, Duke argues that the 
Commission itself acknowledged in the April 14 Order (establishing the 
new indicative market power screens) that if a supplier passes the 
pivotal supplier indicative screen, it would not be able to exercise 
generation market power. Thus, Duke concludes that the use of any other 
indicative screens would appear to be redundant and an unwarranted 
burden on market-based rate sellers.\33\ Further, Duke submits that 
neither of the rationales originally cited by the Commission in support 
of the market share screen--its ability to identify ``coordinating 
behavior,'' or its ability to detect the exercise of market power in 
off-peak periods--has been validated. In this regard, Duke submits that 
the potential for ``coordinating behavior'' should consider overall 
market concentration levels as measured by HHIs and in any event, such 
behavior is already subject to oversight and substantial penalties 
under the antitrust laws and the Commission's recently adopted rule 
prohibiting market manipulation. Further, Duke claims that the nearly 
universal failure rate of load-serving utilities under the market share 
indicative screen in their control areas underscores its limited value 
as an indicator of off-peak market power.\34\
---------------------------------------------------------------------------

    \33\ Duke reply comments at 15 and n. 21.
    \34\ Duke reply comments at 15 and n. 22.
---------------------------------------------------------------------------

    51. Duke states that a review of filings by vertically integrated 
utilities that are not RTO participants shows that the vast majority 
have failed the market share screen in their control areas, and most 
have subsequently been forced to adopt some form of cost-based 
mitigation for wholesale sales in that market. Yet Duke is unaware of 
any credible evidence suggesting that any form of generation market 
power has been exercised by these utilities. Instead, Duke states that 
the Commission has revoked market-based rate authority and imposed 
mitigation on the basis of indicative screen results that suggest the 
potential for market power.\35\ APPA/TAPS counter that the Commission 
should not limit its response to market power only to instances of its 
actual exercise; they note that the Commission considers whether a 
seller and its affiliates have market power or have mitigated it, not 
whether it has been exercised.\36\
---------------------------------------------------------------------------

    \35\ Duke at 16.
    \36\ APPA/TAPS reply comments at 6-7, citing Duke at 16.
---------------------------------------------------------------------------

    52. Another commenter suggests substituting the HHI for the market 
share indicative screen or supplementing the indicative screens with 
the HHI, reasoning that the market must be evaluated, not just the 
individual market share.\37\
---------------------------------------------------------------------------

    \37\ Drs. Broehm & Fox-Penner at 2-4.
---------------------------------------------------------------------------

    53. Southern states that the Commission should rely upon any 
indicative screens only in conjunction with an optional ``expedited 
track'' safe harbor review. Under Southern's proposal, the indicative 
screens would be voluntary and those submitting to and passing the 
screens would be permitted to retain or obtain market-based rate 
authority, subject to a proceeding under section 206 of the FPA, under 
which the party seeking to challenge the rate must submit substantial 
evidence justifying revocation. If a seller fails the screen(s), or if 
it elects to submit a DPT rather than voluntarily submit the indicative 
screens, then a robust market power assessment should be used to 
determine whether (or the extent to which) the

[[Page 39912]]

seller should be permitted to sell power at market-based rates.
    54. In Southern's view, failure of the indicative screens should 
not give rise to a presumption of market power.\38\ Southern argues 
that mere failure to pass a screen, without more robust market power 
assessments, is an insufficient basis upon which to base a presumption 
of market power. Southern argues this is because, in the case of the 
pivotal supplier screen, the Commission itself admits that it does not 
give a full picture and that the DPT provides better information. With 
regard to the market share screen, Southern argues that the market 
share screen has even more basic problems as an indicator of market 
power. Southern states that, because of the market share analysis' 
serious flaws, the great majority of integrated franchised public 
utilities inevitably will fail the market share screen. Thus, with 
respect to integrated franchised public utilities, the market share 
screen serves no real purpose other than to state the obvious: 
Integrated franchised public utilities build and maintain adequate 
resources to serve their native loads and inevitably will have market 
shares greater than 20 percent in their home control areas under the 
Commission's computational procedures. Southern states that, since the 
DPT reduces the level of false positives and is a more definitive means 
for determining the existence of market power, the Commission should 
use the DPT as the default test.\39\ PPL agrees with Southern's 
proposal that the indicative screens be made voluntary.\40\
---------------------------------------------------------------------------

    \38\ Southern argues that, in the context of the indicative 
screens, the prejudice associated with integrated franchised public 
utility status is severe and instead of providing a fair or 
meaningful measure of market power, the market share screen operates 
to create a priori evidentiary presumption of guilt, the screen is 
improper, creates due process concerns, and should not be adopted 
for purposes of the final rule.
    \39\ Southern at 8, 11-13.
    \40\ PPL reply comments at 8.
---------------------------------------------------------------------------

    55. Southern states that if the market share screen is retained, it 
should be adjusted for forced outages because such capacity is not 
available. Southern also notes that forced outages are tracked and 
reported to the North American Electric Reliability Corporation (NERC), 
which presents generating unit availability statistics data for 
generator unit groups.\41\
---------------------------------------------------------------------------

    \41\ Southern at 14-15.
---------------------------------------------------------------------------

    56. NRECA disagrees with Southern's proposal, stating that forced 
outage deductions have little effect when applied to all sellers.\42\ 
It also believes that sellers do not mak