119 FERC ¶ 61,295 

UNITED STATES OF AMERICA 

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. 

ACTION: Final Rule 

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. 

EFFECTIVE DATE: This rule will become effective [Insert_Date 60 days after 

publication in the FEDERAL REGISTER].

FOR FURTHER INFORMATION CONTACT: 

Debra A. Dalton (Technical Information) 

Office of Energy Markets and Reliability 
Docket No. RM04-7-000 - 2 - 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6253 

Elizabeth Arnold (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-8818 

SUPPLEMENTARY INFORMATION:
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Market-Based Rates For Wholesale Sales Of Electric 

Energy, Capacity And Ancillary Services By Public 

Utilities 

Docket No. RM04-7-000 

ORDER NO. 697 

FINAL RULE 

TABLE OF CONTENTS

Paragraph Numbers

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 and Pivotal Supplier 

Application Period................................................................................................... 80.

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 File ........................................... 212.

7. Relevant Geographic Market............................................................................ 215.

a. Default Relevant Geographic Market........................................................... 215.

b. NERC’s Balancing Authority Area and Default Geographic Area ............. 247.

c. Additional Guidelines for Alternative Geographic Market and Flexibility 253.
Docket No. RM04-7-000 ii 

d. Specific Issues Related to Power Pools and SPP......................................... 279.

e. RTO/ISO Exemption.................................................................................... 285.

8. Use of Historical Data ...................................................................................... 292.

9. Reporting Format.............................................................................................. 302.

10. Exemption for New Generation (Formerly Section 35.27(a) of the 

Commission’s Regulations)................................................................................... 307.

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 Practices .................................... 348.

b. Use of Total Transfer Capability (TTC) ...................................................... 363.

c. Accounting for Transmission Reservations ................................................. 365.

d. Allocation of Transmission Imports based on Pro Rata Shares of Seller's 

Uncommitted Generation Capacity................................................................... 370.

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 Seller................................ 452.

4. Planning and Expansion Efforts ....................................................................... 454.

5. Monopsony Power............................................................................................ 459.

C. Affiliate Abuse .................................................................................................... 464.

1. General Affiliate Terms and Conditions .......................................................... 464.

a. Codifying Affiliate Restrictions in Commission Regulations...................... 464.

b. Definition of “Captive Customers”.............................................................. 469.

c. Definition of “Non-Regulated Power Sales Affiliate”................................. 484.

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 (formerly Code of Conduct) for 

Affiliate Transactions Involving Power Sales and Brokering, Non-Power Goods and 

Services and Information Sharing ......................................................................... 544.
Docket No. RM04-7-000 iii 

a. Uniform Code of Conduct/Affiliate Restrictions - Generally...................... 546.

b. Exceptions to the Independent Functioning Requirement ........................... 553.

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 on Behalf of and for the 

Benefit of a Franchised Public Utility............................................................... 599.

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 one year ................................... 632.

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 Proposed Modifications......... 845.

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 and Reasonable Standard 

Under the FPA ....................................................................................................... 938.

Consistency of Market-based Rate Program with FPA Filing Requirements ...... 956.

2. Whether Existing Tariffs Must Be Found to Be Unjust and Unreasonable, and 

Whether the Commission Must Establish a Refund Effective Date...................... 973.

H. Miscellaneous....................................................................................................... 976.

1. Waivers............................................................................................................. 976.

a. Accounting Waivers ..................................................................................... 980.

b. Timing .......................................................................................................... 989.

c. Part 34 Waivers Blanket Authorizations...................................................... 995.

2. Sellers Affiliated with a Foreign Utility......................................................... 1001.
Docket No. RM04-7-000 iv 

3. Change in Status ............................................................................................. 1009.

a. Fuel Supplies .............................................................................................. 1012.

b. Transmission Outages ................................................................................ 1020.

c. Control ....................................................................................................... 1028.

d. Triggering Events....................................................................................... 1034.

e. Timing of Reporting................................................................................... 1036.

f. Sellers Affiliated with a Foreign Utility ..................................................... 1041.

4. Third-Party Providers of Ancillary Services .................................................. 1047.

a. Internet Postings and Reporting Requirements.......................................... 1053.

b. Pricing for Ancillary Services in RTOs/ISOs ........................................... 1063.

5. Reactive Power and Real Power Losses......................................................... 1073.

a. Reactive Power........................................................................................... 1074.

b. Real Power Losses ..................................................................................... 1076.

V. Section-by-Section Analysis of Regulations ......................................................... 1078.

VI. Information Collection Statement ......................................................................... 1106.

VII. Environmental Analysis....................................................................................... 1125.

VIII. Regulatory Flexibility Act.................................................................................. 1126.

IX. Document Availability .......................................................................................... 1130.

X. Effective Date and Congressional Notification...................................................... 1133.

Appendix A: Standard Screen Format 

Appendix B: Corporate Entities and Assets sample appendix 

Appendix C: Required Provisions of the Market-Based Rate Tariff 

Appendix D: Regions and Schedule for Regional Market power Update Process 

Appendix E: List of Commenters and Acronyms 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff. 

Market-Based Rates For Wholesale Sales Of Electric 

Energy, Capacity And Ancillary Services By Public 

Utilities 

Docket No. RM04-7-000 

FINAL RULE 

ORDER NO. 697 

(Issued June 21, 2007) 

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 

 1

 16 U.S.C. 824d, 824e. 
Docket No. RM04-7-000 2 

response to the 

NOPR, the Commission adopts in many respects the proposals contained in the NOPR, 

but with a number of modifications. 

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) 

 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. 
Docket No. RM04-7-000 3 

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

 

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 

 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. 
Docket No. RM04-7-000 4 

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 Circuit4

 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 

 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). 
Docket No. RM04-7-000 5 

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 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 

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 

 5 CAlifornians for Renewable Energy, Inc. v. Cal. Pub. Util. Com’n, 119 FERC 

¶ 61,058 (2007). 
Docket No. RM04-7-000 6 

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. 

9. On April 14, 2004, the Commission issued an order modifying the thenexisting 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 

 6 Market-Based Rates for Public Utilities, 107 FERC ¶ 61,019 at P 1 (2004) 

(initiating rulemaking proceeding). 

7 AEP Power Marketing, Inc., 107 FERC ¶ 61,018 (April 14 Order), order on 

reh’g, 108 FERC ¶ 61,026 (2004) (July 8 Order). 
Docket No. RM04-7-000 7 

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. 

10. On May 19, 2006, the Commission issued a NOPR in this proceeding.8

 The 

Commission explained that refining and codifying effective standards for marketbased 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. 

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 

 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). 
Docket No. RM04-7-000 8 

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). 
Docket No. RM04-7-000 9 

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 

 9

 As discussed below in the Horizontal Market Power section, the Commission 

adopts the use of balancing authority area instead of control area. 
Docket No. RM04-7-000 10 

evaluating whether, in a particular case, to adopt an alternative geographic market 

instead of relying on the default geographic market. 

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 § 33.3(d)(4)(i) of the Commission’s regulations. In 

addition, sellers are 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 
Docket No. RM04-7-000 11 

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 
Docket No. RM04-7-000 12 

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 
Docket No. RM04-7-000 13 

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 affiliates10 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 

 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 “marketregulated power sales affiliate” instead. 

11 18 CFR part 358. 
Docket No. RM04-7-000 14 

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.” 

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 Commission will continue to 

 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. 
Docket No. RM04-7-000 15 

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. 

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. 

 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. 
Docket No. RM04-7-000 16 

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 marketbased 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 
Docket No. RM04-7-000 17 

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 crosscheck 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 
Docket No. RM04-7-000 18 

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

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 

 14 April 14 Order, 107 FERC ¶ 61,018 at P 100. 
Docket No. RM04-7-000 19 

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

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

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. 

 15 Id. at P 72. 

16 Id. 
Docket No. RM04-7-000 20 

38. Uncommitted capacity is determined by adding the total nameplate or seasonal 

capacity17 of 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. 

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 

 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. 
Docket No. RM04-7-000 21 

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

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

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 

 19 April 14 Order, 107 FERC ¶ 61,018 at P96. 

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. 
Docket No. RM04-7-000 22 

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. 
Docket No. RM04-7-000 23 

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. 

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 

 21 The 20 percent threshold is consistent with § 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.” 

22 See April 14 Order, 107 FERC ¶ 61,018.
Docket No. RM04-7-000 24 

supplier. For this reason, the Commission did not propose to expand the pivotal 

supplier analysis to other time periods. 

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 market23 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 PNM/Tucson argue that to the extent the 

 

 (continued...) 

 

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 
Docket No. RM04-7-000 25 

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 

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 

 

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. 
Docket No. RM04-7-000 26 

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 marketbased 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

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 

 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); MidTex. 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. 

29 Dr. Pace at 12. 
Docket No. RM04-7-000 27 

the amount of wholesale demand seeking supply.30 Generally, if available nonapplicant 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 a FPA section 206 

investigation tend to choose mitigation rather than challenge the presumption of 

market power.32 

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 

 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. 

33 Duke reply comments at 15 and n. 21. 
Docket No. RM04-7-000 28 

“coordinating behavior,” or its ability to detect the exercise of market power in offpeak 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

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 

 34 Duke reply comments at 15 and n. 22. 

35 Duke at 16. 
Docket No. RM04-7-000 29 

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

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

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 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, 

 

 (continued...) 

 

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

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

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 
Docket No. RM04-7-000 30 

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

 

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. 
Docket No. RM04-7-000 31 

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

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 make forced outage deductions in long-term contracts; therefore, it is 

inappropriate to make the deduction for the market power tests. 

57. While EPSA does not agree with some of the Commission’s proposed changes 

to the horizontal analysis in the NOPR (i.e., changes to the post-1996 exemption and 

the native load proxy), in general, EPSA supports the two indicative screens as a 

means for indicating that an entity might have market power. 

58. EPSA notes that it is time to move beyond the battle over crafting the perfect 

screens, arguing: 1) it is likely no such perfect screens exist, as evidenced by the fact 

that stakeholders and the Commission have gone through several iterations to get to 

today’s screens; and 2) in the end, the screens are only indicative measures. EPSA 

notes that failure of one or both of the screens does not brandish an entity with market 

 41 Southern at 14-15. 

42 NRECA reply comments at 18. 
Docket No. RM04-7-000 32 

power, but merely raises a flag that further analysis is necessary in order to assess an 

entity’s ability to exercise market power. The current state of wholesale electricity 

markets, EPSA argues, requires indicative screens that are neither definitive nor an 

aperture letting everything pass, but rather a sieve that catches potential problems for 

further examination. EPSA agrees with retention of both of the current indicative 

screens and the “next steps” set forth for those entities that fail one or both of those 

screens. 

59. Several other commenters also support retention of the indicative screens. 

Some of these commenters state that, because section 205 of the FPA requires rates to 

be just and reasonable, a market share indicative screen is appropriate to ensure that 

outcome. NRECA adds that “[b]ecause of past or present state regulation, many 

traditional public utilities have acquired dominant market shares of generation 

capacity in their own control areas—sufficient to enable them to exercise market 

power absent regulation of their behavior. NRECA submits that regardless of the 

cause the incumbent public utilities will remain the dominant firms in their own 

control areas absent significant new market entry in the form of new generation 

construction in the control area by independent firms, or significant transmission 

construction to permit entry by generation outside the control area. Morgan Stanley 

also favors retaining the market share indicative screen, noting that failure of the 

market share indicative screen does not mean the process is unfair, and asserting that 
Docket No. RM04-7-000 33 

exclusive reliance on the pivotal supplier indicative screen may compromise market 

power detection.43

60. With regard to the suggestion that the Commission adopt a contestable load 

analysis, several commenters criticize the contestable load analysis, stating that it 

changes the focus of the market power analysis from the seller to the market. They 

counter that the contestable load analysis is unsound, with APPA/TAPS citing 

Federal 

Trade Commission (FTC) comments in this proceeding that such an analysis is flawed.44 

NRECA states that commenters have not provided sufficient justification for using a 

contestable load analysis. 

61. With regard to Southern's suggestion that the indicative screens be made 

voluntary and function as a safe harbor, such that screen failure would simply mean 

that further review of the seller would be appropriate, but not merit a section 206 

 43 Morgan Stanley reply comments at 10-11. 

44 APPA/TAPS reply comments at 11, NRECA reply comments at 13-14. The 

FTC filed comments in this proceeding in January 2006 on the contestable load test. FTC 

states that "the historical contestable load proposal fails to include a number of 

potentially important considerations in its framework for assessing horizontal market 

power, and the elements that it does include are not considered in an economically sound 

manner. In sum, the proposal does not represent an analytical advance over existing 

techniques to evaluate horizontal market power, and it falls far short of the economically 

sound framework for market power analysis presented in the Merger Guidelines." The 

FTC defines the following specific problems with the contestable load analysis: the price 

is not considered in the assessment of available supply, contractual and legal restrictions 

on supply are ignored, and the contestable load analysis ignores transmission 

discrimination and transmission constraints, which delineate the market. 
Docket No. RM04-7-000 34 

investigation, NRECA states that Southern's argument is contrary to law. NRECA 

argues that, as the proponent of a tariff allowing it to charge market-based rates, the 

public utility has the burden of proof to demonstrate that its wholesale rates will be 

disciplined by competition. NRECA submits that failing the indicative screens 

indicates that the seller has not yet provided "'empirical proof'" that competition will 

drive down prices to just and reasonable levels as the FPA requires.45

Commission Determination

62. We adopt the proposal in the NOPR to retain both of the indicative screens. 

The intent of the indicative screens is to identify the sellers that raise no horizontal 

market power concerns and can otherwise be considered for market-based rate 

authority. At the same time, sellers that do not pass the indicative screens are 

allowed to provide additional analysis for Commission consideration. Because the 

indicative screens are intended to screen out only those sellers that raise no horizontal 

market power concerns, as opposed to other sellers that raise concerns but may not 

necessarily possess horizontal market power, we find it appropriate to use 

conservative criteria and to rely on more than one screen. A conservative approach at 

the indicative screen stage of the proceeding is warranted because, if a seller passes 

both of the indicative screens, there is a rebuttable presumption that it does not 

possess horizontal market power. 

 45 NRECA reply comments at 20-21. 
Docket No. RM04-7-000 35 

63. The rebuttable presumption of horizontal market power that attaches to sellers 

failing one of the indicative screens is just that—a rebuttable presumption. It is not a 

definitive finding by the Commission; sellers are provided with several procedural 

options including the right to challenge the market power presumption by submitting 

a DPT analysis, or, alternatively, sellers can accept the presumption of market power 

and adopt some form of cost-based mitigation.46 Accordingly, we will adopt the 

proposal to continue to use the two indicative screens and find that failure of either 

indicative screen creates a rebuttable presumption of market power. We reiterate our 

finding that "[f]ailure to pass either of the indicative screens . . . will constitute a 

prima facie showing that the rates charged by the seller pursuant to its market-based 

rate authority may have become unjust and unreasonable and that continuation of the 

seller’s market-based rate authority may no longer be just and reasonable."47

64. This approach, contrary to the claims of several commenters, will help to 

further competitive markets by allowing sellers without market power to sell power at 

 46 In the April 14 Order, the Commission stated that proposals for alternative 

mitigation in these circumstances could include cost-based rates or other mitigation that 

the Commission may deem appropriate. For example, a seller could propose to transfer 

operational control of enough generation to a third party such that the applicant would 

satisfy our generation market power concerns. April 14 Order, 107 FERC ¶ 61,018 at n. 

142. 

47 April 14 Order, 107 FERC ¶ 61,018 at P 209. 
Docket No. RM04-7-000 36 

market-based rates, and it will similarly give customers security that sellers that fail 

the screens are required to submit to further scrutiny and/or mitigation. 

65. The pivotal supplier and market share indicative screens measure different 

aspects of market power. As the Commission stated in the April 14 Order, the 

uncommitted pivotal supplier indicative screen measures the ability of a firm to 

dominate the market at peak periods. The uncommitted market share analysis 

provides a measure as to whether a supplier may have a dominant position in the 

market, which is another indicator of potential unilateral market power and the ability 

of a seller to effect coordinated interaction with other sellers. The market share 

screen is also useful in measuring market power because it measures a seller’s size 

relative to others in the market, in particular, the seller’s share of generating capacity 

uncommitted after accounting for its obligations to serve native load. The market 

share screen provides a snapshot of these market shares in each season of the year. 

Taken together, the indicative screens can measure a seller's market power at both 

peak and off-peak times.48 Both market share and pivotal supplier indicative screens 

are appropriate first steps for the Commission to use in determining if it needs a more 

robust analysis to determine whether the seller has market power. We conclude that 

having two screens as backstops to one another will better assist us in determining the 

existence of potential market power. Accordingly, we reject the suggestion of several 

 48 April 14 Order, 107 FERC ¶ 61,018 at P 72. 
Docket No. RM04-7-000 37 

commenters to abandon the market share indicative screen. We will retain both the 

pivotal supplier and market share indicative screens as described in the NOPR, as 

well as apply the rebuttable presumption of market power for those sellers that fail 

either indicative screen.49 

66. In addition, the Commission will not adopt suggestions to alter the indicative 

screens in order to incorporate a contestable load analysis, as proposed by EEI and 

others. As noted by the FTC, APPA/TAPS, and NRECA, the contestable load 

analysis is flawed because, among other things, it does not consider control of 

generation through contracts. The Commission explained in the April 14 Order that 

the roles of the indicative screens are meant to be complementary. The pivotal 

supplier indicative screen indicates whether demand can be met without some 

contribution of supply by the seller at peak times, while the market share indicative 

screen indicates whether the seller has a dominant position in the market and may 

therefore have the ability to exercise horizontal market power, both unilaterally and 

in coordination with other sellers. 50 The contestable load analysis is essentially a 

variant on the pivotal supplier screen with differences in the calculation of wholesale 

load and the test thresholds, because, like the pivotal supplier screen, it addresses 

 49 As we noted in the July 8 Order, a number of those commenters that proposed 

eliminating the market share screen had supported it as a viable alternative in the past. 

July 8 Order, 108 FERC ¶ 61,026 at P 87. 

50 April 14 Order, 107 FERC ¶ 61,018 at P 72. 
Docket No. RM04-7-000 38 

whether suppliers other than the seller can meet the demand in the relevant market. 

Therefore incorporating such an analysis would not improve our ability to establish a 

presumption of whether a seller has market power. The contestable load analysis 

therefore would add little useful information, and without the market share indicative 

screen, the Commission would have insufficient information because there would be 

no analysis of a seller’s size relative to the other sellers in the market, and no 

information on the seller's market power during off-peak periods. 

67. In addition, the contestable load analysis fails to consider the relative price of 

the competing supplies. Commenters have argued that if available non-applicant 

supply is at least twice the contestable load, the market is competitive. However, this 

analysis fails to consider whether the available non-applicant supply is competitively 

priced and, thus, in the market. This weakness in the contestable load analysis is 

addressed in the DPT analysis which considers only supply that is competitively 

priced. 

68. We also reject arguments by E.ON U.S. and PNM/Tucson that the wholesale 

market share screen should be replaced because, they argue, it does not consider the 

size of the wholesale supply in the relevant market relative to the wholesale demand 

in that market. E.ON. U.S. and PNM/Tucson are requesting an analysis very similar 

to the contestable load analysis, whose defining characteristic is measuring the 

wholesale supply market relative to wholesale demand, which, as stated above, is 

essentially the same as the pivotal supplier screen, and would therefore add little 

useful information to the screening process. 
Docket No. RM04-7-000 39 

69. We reject Duke’s claim that because neither of the rationales originally cited 

by the Commission in support of the market share indicative screen – its ability to 

identify “coordinating behavior,” or its ability to detect the exercise of market power 

in off-peak periods – has been validated, the wholesale market share indicative screen 

is unnecessary. Specifically, the Commission believes that the ability of market 

participants to exercise market power through "coordinating behavior" is a legitimate 

concern under the FPA, in addition to the fact that it has long been recognized by the 

antitrust authorities.51 The Commission also believes it is possible to exercise market 

power in off-peak periods because during such times the amount of supply in the 

market may be greatly reduced (e.g., because of planned outages for plant 

maintenance), meaning that a seller that is not dominant at peak times might be at offpeak. 

70. Moreover, we agree with APPA/TAPS that market-based rate assessments are 

used to determine the ability to exercise, not the exercise of, market power. The 

Commission need not wait passively until market power is exercised. Rather, it is 

incumbent on the Commission to set policies that will ensure that rates remain just 

and reasonable under section 205 of the FPA. Requiring sellers to submit screens 

that analyze the sellers’ potential to exercise market power is consistent with such a 

policy. 

 51 See 1992 FTC/DOJ 1992 Horizontal Merger Guidelines sec. 2.1. 
Docket No. RM04-7-000 40 

71. We are unpersuaded by E.ON U.S.’s and PNM/Tucson's argument that “false 

positives” arising from the market share screen dampen the vigor of competitive 

wholesale market participation by unnecessarily curtailing the market-based rate 

authority of entities that, according to E. ON. U.S. and PNM/Tucson, lack market 

power. We recognize that a conservative screen may result in some false positives, 

but must weigh that against the cost of the false negatives that would occur if we 

adopted a less conservative screen or eliminated the market share indicative screen. 

72. E.ON U.S. and PNM/Tucson, to support their point, cite several court cases in 

which market shares were alleged not to be reliable indicators of market power in 

regulated markets. However, the cases cited are not relevant to the issue of whether 

the Commission should retain the wholesale market share screen. The purpose of our 

indicative screens is to distinguish sellers that may raise horizontal market power 

concerns and those that do not; the market share screen is not the end of our 

horizontal 

market power analysis. In contrast, the cases cited by E.ON U.S. and PNM/Tucson52

involve allegations of unlawful restraint of trade in violation of the Sherman Act,53 a 

 52 Cost Management, 99 F.3d 937; Rebel Oil, 51 F.3d 1421; S. Pac. 

Communications, 740 F.2d 780; MCI Communications, 708 F.2d 1081; Mid-Tex 

Communications, 615 F.2d 1372; and Almeda, 615 F.2d 343.

53 15 U.S.C. 2, which states: Every person who shall monopolize, or attempt to 

monopolize, or combine or conspire with any other person or persons, to monopolize any 

part of the trade or commerce among the several States, or with foreign nations, shall be 

deemed guilty of a felony, and, on conviction thereof, shall be punished by fine not 

 (continued...) 

 
Docket No. RM04-7-000 41 

federal antitrust statute prohibiting trade monopolies. The focus in such cases (whether a 

company has violated the Sherman Act) and the standard for making such a 

determination is different than the focus of the Commission at the indicative screen stage 

of the horizontal market power analysis (identifying sellers that require further horizontal 

market analysis without making a definitive finding regarding market power). 

73. On both theoretical and practical grounds, we reject the argument by EEI and 

others that the market share indicative screen can diminish competition because some 

sellers that are the subject of a section 206 investigation choose mitigation rather than 

challenge the presumption of market power. First, mitigating a seller with market 

power ensures that the other sellers in the market cannot benefit from an artificially 

high market price due to the seller with market power exercising market power. 

Second, in our experience, sellers that choose mitigation rather than challenge the 

presumption of market power have market shares that are likely to indicate a 

dominant position in a geographic market.54 In addition, many sellers have 

 

exceeding $100,000,000 if a corporation, or, if any other person, $1,000,000, or by 

imprisonment not exceeding 10 years, or by both said punishments, in the discretion of 

the court.” 

54 See, e.g., Aquila, Inc., 112 FERC ¶ 61,307 (2005); Carolina Power & Light Co,.

113 FERC ¶ 61,130 (2005); The Empire District Electric Co., 116 FERC ¶ 61,150 

(2006); MidAmerican Energy Co., 117 FERC ¶ 61,178 (2006); Xcel Energy Services 

Inc., 117 FERC ¶ 61,180 (2006). 
Docket No. RM04-7-000 42 

successfully rebutted the presumption of market power after failing one of the 

indicative screens.55 

74. Further, we will not adopt the suggestion to substitute the HHI for the market 

share indicative screen or to supplement the indicative screens with the HHI. The 

indicative screens are used to separate sellers who are presumed to have market 

power from those that, absent extraordinary and transitory circumstances, clearly do 

not. We will not substitute the market share screen with an HHI screen because, as 

we have stated above, the seller’s market share conveys useful information about its 

ability to exercise market power, so eliminating the market share screen in favor of 

the HHI could increase the risk of false negatives.56 In addition, a high HHI can be 

the result of high market shares of sellers in the market other than the seller, and the 

focus of our analysis is on the sellert’s ability to exercise market power, so the HHI 

would provide little additional information to allow us to identify those sellers who 

clearly do not have market power. Finally, the HHI primarily provides information 

on the ability of sellers to exercise market power through coordinated behavior, while 

 55 See, e.g., Kansas City Power and Light Co., 113 FERC ¶ 61,074 (2005); PPL 

Montana, LLC, 115 FERC ¶ 61,204 (2006); PacifiCorp, 115 FERC ¶ 61,349 (2006); 

Tucson Electric Power Co., 116 FERC ¶ 61,051 (2006); Acadia Power Partners, LLC,

113 FERC ¶ 61,073 (2005). 

56 For example, in a market with one seller with a 35 percent market share and 13 

sellers each with 5 percent market shares, the HHI would be 1,550 (1,225 + 13(25)), 

which would not fail the 2,500 HHI threshold or even the proposed lower 1,800 HHI 

threshold. In such a market, a firm with a 35 percent market share could have the ability 

to exercise market power, which would not be picked up by an HHI screen. 
Docket No. RM04-7-000 43 

the market share screen primarily provides information on a particular seller’s ability 

unilaterally to exercise market power. We will not supplement the indicative screens 

with the HHI screen because the indicative screens are sufficiently conservative to 

identify those sellers that have a rebuttable presumption of market power, without 

having to add an additional layer of review at the initial stage. 

75. We clarify that sellers and intervenors may present alternative evidence such 

as a DPT study or historical sales and transmission data to support or rebut the results 

of the indicative screens. For example, intervenors could present evidence based on 

historical wholesale sales data or challenge the assumption that competing suppliers 

inside a balancing authority area have access to the market (such a challenge could 

take into account both the actual historical transmission usage at the time of the study 

as well as the amount of available transmission capacity at that time).57 A seller may 

present evidence in support of a contention that, notwithstanding the results of the 

indicative screens, it does not possess market power.58 However, sellers should not 

expect that the Commission will postpone initiating a section 206 investigation to 

protect customers 

 57 Id. at P 37. 

58 Id. at n. 11. 
Docket No. RM04-7-000 44 

while it examines this supplemental information if screen failures are indicated.59 

Nevertheless, the Commission may factor in this alternative evidence before deciding 

whether to initiate a section 206 investigation if the alternative evidence is appropriately 

supported, comprehensive and unambiguous, and conducive to prompt review by the 

Commission. 

76. We will not adopt Southern's suggestion that the indicative screens be made 

voluntary. We will continue to require that sellers submit the indicative screens or 

concede the presumption of market power before they file a DPT. However, as 

discussed above, a seller may submit with its indicative screens a DPT as alternative 

evidence. As stated above, submission of a DPT analysis as alternative evidence at 

the same time a seller submits the indicative screens may result in the Commission 

instituting a section 206 proceeding to protect customers, based on failure of an 

indicative screen, while the Commission considers the merits of the DPT analysis. 

77. We do not agree with Southern’s view that failure of the indicative screen(s) 

does not provide a sufficient basis to establish a rebuttable presumption of market 

power. The indicative screens are intended to identify the sellers that raise no 

horizontal market power concerns and can otherwise be considered for market-based 

rate authority. Sellers failing one or both of the indicative screens, on the other hand, 

 59 See, e.g., LG&E Energy Mtkg. Inc., 111 FERC ¶ 61,153 at P 21, 22 (2005); 

Tampa Electric Co., 110 FERC ¶ 61,206 at P 24, 25 (2005); Entergy Services, Inc., 

109 FERC ¶ 61,282 at P 36 (2004). 
Docket No. RM04-7-000 45 

are identified as sellers that potentially possess horizontal market power and for 

which a more robust analysis is required. The uncommitted pivotal supplier screen 

focuses on the ability to exercise market power unilaterally. Failure of this screen 

indicates that some or all of the seller’s generation must run to meet peak load. The 

uncommitted market share analysis indicates whether a supplier has a dominant 

position in the market. Failure of the uncommitted market share screen may indicate 

the seller has unilateral market power and may also indicate the presence of the 

ability to facilitate coordinated interaction with other sellers. It is on this basis that 

we find that a rebuttable presumption of market power is warranted when a seller 

fails one or both of the indicative screens. However, we agree with Southern that the 

DPT is a more definitive means for determining the existence of market power. As a 

result, we allow sellers that have failed one or both of the indicative screens to rebut 

the presumption of market power by performing the DPT. Further, because failure of 

one or both of the indicative screens only creates a rebuttable presumption of market 

power and sellers have a Commission-endorsed analysis that they can use to rebut 

that presumption (the DPT), we find without merit Southern’s view that the indicative 

screens create a priori evidentiary presumption of guilt, are improper, and create due 

process concerns. 

78. With regard to Southern’s suggestion that we use the DPT as the default test, 

we find that if we were to do so our ability to protect customers while the analysis is 

evaluated could be compromised. The DPT is a more involved and complex analysis. 

The Commission has also at times set a DPT analysis for evidentiary hearing which 
Docket No. RM04-7-000 46 

greatly extends the time between when the DPT is submitted to the Commission and 

when a final decision is rendered. The rates customers are subject to during the time 

period before the issuance of a Commission order addressing a seller’s DPT would 

not be subject to refund and, accordingly, the customers would be unprotected if the 

seller ultimately is found to have market power. However, under our current policy, 

and as adopted herein, if a seller wishes to file a DPT rather than the indicative 

screens it may do so. In doing so, the seller concedes that it fails the indicative 

screens, which concession establishes a rebuttable presumption of market power, and 

the Commission will issue an order initiating a section 206 proceeding to investigate 

whether the seller has market power and establishing a refund effective date for the 

protection of customers while the Commission evaluates the filed DPT. In the case 

of a seller that concedes the failure of one or both of the screens and submits the 

DPT in the same filing, the Commission is able to establish a refund effective date at 

an earlier time than if the seller were able to skip the screen stage entirely and file a 

DPT without conceding a screen failure. 

79. We will reject Southern's request that forced outages be deducted from 

capacity. As we stated in the July 8 Order, "forced outages are non-recurring events 

that do not reflect normal operating conditions."60 Allowing deduction of forced 

outages will generally not change indicative screen results, because all sellers will be 

 60 July 8 Order, 108 FERC ¶ 61,026 at P 68. 
Docket No. RM04-7-000 47 

able to deduct forced outages, offsetting each other. In the unlikely event that forced 

outage numbers were not completely offsetting, allowing forced outages in the 

indicative screens would benefit owners of relatively unreliable fleets at the expense 

of owners of relatively reliable fleets. 

2. Indicative Market Share Screen Threshold Levels and Pivotal 

Supplier Application Period

Commission Proposal

80. In the NOPR, the Commission proposed to retain the 20 percent threshold for 

the wholesale market share screen (i.e., with a market share of less than 20 percent, 

the seller would pass the screen). The Commission stated that since the screens are 

indicative, not definitive, a relatively conservative threshold for passing them was 

appropriate. Indeed, pursuant to the horizontal market power analysis, the 

Commission will not make a definitive finding that a seller has market power unless 

and until the more robust analysis, the DPT, is considered. 

81. The Commission proposed to continue the use of annual peak load in the 

pivotal supplier analysis and not to expand the pivotal supplier analysis to include 

monthly assessments. It stated that the pivotal supplier analysis examines the seller’s 

market power during the annual peak, and that the hours near that point in time are 

the most likely times that a seller will be a pivotal supplier. 
Docket No. RM04-7-000 48 

a. Market Share Threshold

Comments 

82. A number of commenters argue that 20 percent is too low a threshold for the 

market share indicative screen. Some point out that, given native load requirements, 

it is very difficult for investor-owned utilities outside of RTOs/ISOs to fall below the 

20 percent threshold for the market share indicative screen.61 Duke also notes that 

the 20 percent criterion is incompatible with regional planning requirements because, 

according to Duke, the amount of capacity needed to satisfy regional planning reserve 

margins "would place the utility at substantial risk of exceeding the 20 percent 

threshold."62 

83. E.ON U.S. argues that, because the courts have not considered a 20 percent 

market share to indicate a market power concern, associating a market share 

indicative screen failure with a presumption of market power is inappropriate.63 

Additionally, Progress Energy argues that it is inappropriate to associate failure of the 

market share screen with a presumption of market power when U.S. Department of 

 61 See, e.g., Southern at 8-9, Duke at 15-16, EEI at 8-9. 

62 Duke at 17. 

63 See E.ON U.S. at 14-15, n.18, citing PepsiCo, Inc. v. Coca-Cola Co., 315 F.3d 

101, 109 (2d Cir. 2003) (“Absent additional evidence, such as an ability to control prices 

or exclude competition, a 64 percent market share is insufficient to infer monopoly 

power.”); AD/SAT v. Associated Press, 181 F.3d 216, 229 (2d Cir. 1999) (concluding 

that 33 percent market share is insufficient to show a dangerous probability of monopoly 

power); United Air Lines, Inc. v. Austin Travel Corp., 867 F.2d 737, 742 (2d Cir. 1989) 

(finding that 31 percent market share does not constitute a national monopoly). 
Docket No. RM04-7-000 49 

Justice (DOJ) merger guidelines state that only firms with 35 percent or more market 

share have market power.64

84. PPL states that it agrees that the 20 percent threshold should be replaced by a 

35 percent threshold in the market share screen and argues that such an increase will 

avoid the false-positive failure rate of the indicative screens, and the cost, time and 

repercussions in the financial markets of the extended pendency of a market-based 

rate renewal proceeding while a DPT is conducted and considered.65 

85. In reply, APPA/TAPS state that there is no reason to raise the market share 

indicative screen threshold above 20 percent simply because investor-owned utilities 

have trouble passing the market share indicative screen.66 NRECA and TDU 

Systems note that the factors that EEI believes make it difficult to pass the indicative 

screens—a large amount of reserves and little available transfer capability—are 

precisely the factors to consider when evaluating whether a market is competitive.67 

86. Rather than raising the threshold level, TDU Systems propose to lower the 

threshold to 15 percent for the market share indicative screen, claiming that 20 

 64 Progress Energy at 7, citing EEI at 6-10. 

65 PPL reply comments at 7. 

66 APPA/TAPS reply comments at 12. 

67 NRECA reply comments at 16, TDU Systems reply comments at 10, citing EEI 

at 8. 
Docket No. RM04-7-000 50 

percent was never justified by the Commission or shown to be the right balance.68 

Citing Commission and judicial precedent, TDU Systems also note that the grant of 

market-based rate authority cannot be made without the discipline of market forces.69 

87. These commenters cite a recent decision of the U.S. Court of Appeals for the 

Ninth Circuit70 to buttress their positions, arguing that even market shares lower than 

20 percent can lead to market manipulation. 

88. In reply to these arguments, Duke states that certain commenters’ reliance on 

this is mistaken because that decision addressed market manipulation, not market 

power.

71 Duke asserts that virtually any supplier, regardless of its market share, has 

some ability to manipulate market outcomes by engaging in anomalous bidding 

practices. 

Commission Determination

89. The Commission will retain the 20 percent market share threshold for the 

indicative market share screen. EEI and others argue that the Commission should use 

a 35 percent threshold as a presumption of market power because the DOJ merger 

 68 TDU Systems at 7. 

69 TDU Systems at 5. 

70 Pub. Utils. Comm’n of Calif. v. FERC, 462 F.3d 1027, at 1039 (9th Cir. 2006) 

(CPUC) (“As became clear in hindsight, even those who controlled a relatively small 

percentage of the market [in the California market during 2000 and 2001] had sufficient 

market power to skew markets artificially.”). 

71 Duke reply comments at 18, citing CPUC. 
Docket No. RM04-7-000 51 

guidelines state that only firms with 35 percent or more market share have market 

power. As the Commission stated in the July 8 Order, however, in a market 

comprised of five equal-sized firms with 20 percent market shares, the HHI is 2,000, 

which is above the DOJ/FTC HHI threshold of 1,800 for a highly concentrated 

market, and in markets for commodities with low demand price-responsiveness like 

electricity, market power is more likely to be present at lower market shares than in 

markets with high demand elasticity.72 Therefore, we will retain a conservative 20 

percent threshold for this indicative screen. 

90. When arguing that a 20 percent threshold for the market share screen is too 

low, E.ON. U.S. and PNM/Tucson ignore that the indicative screens are based on 

uncommitted capacity, not total capacity. When calculating uncommitted capacity 

for the market share screen, a seller deducts from its total capacity the capacity 

dedicated to long-term sales contracts, operating reserves,73 planned outages, and 

native load74 as measured by the appropriate native load proxy. As a result, a 

substantial amount of seller capacity may not be counted in measures of market share. 

Therefore, it is inappropriate to compare market shares based on uncommitted 

capacity to the market shares in the cases that E.ON. U.S. and PNM/Tucson cite. 

 72 July 8 Order, 108 FERC ¶ 61,026 at P 96. 

73 April 14 Order 107 FERC ¶ 61,018 at P 94. 

74 Id. at P 100. 
Docket No. RM04-7-000 52 

91. We further note that other commenters have argued that the 20 percent 

threshold is too high. We disagree. The 20 percent threshold is meant to strike a 

balance between having a conservative but realistic screen and imposing undue 

regulatory burdens. The Commission’s experience in the context of market-based 

rate proceedings demonstrates this point. In the three years since the April 14 Order, 

the Commission has revoked the market-based rate authority of two sellers, thirteen 

sellers relinquished their market-based rate authority, and six companies satisfied the 

Commission’s concerns for the grant of market-based rate authority at the DPT 

phase. In addition, intervenors have the opportunity to present other evidence such as 

historical data in order to rebut the presumption that sellers lack market power.75 

Moreover, no commenter advocating a 15 percent threshold for the market share has 

shown why it is superior to the current 20 percent threshold. Therefore, we find that 

the 20 percent market share threshold strikes the right balance in seeking to avoid 

both “false negatives” and “false positives” and we will not reduce the wholesale 

market share screen to 15 percent, as suggested by TDU Systems. 

92. The Commission does not accept Duke's assertion that the market share 

indicative screen is incompatible with regional planning requirements. The April 14 

Order allows operating reserves necessary for reliability, as determined by state or 

 75 Id. at P 97. 
Docket No. RM04-7-000 53 

regional reliability councils,76 to be deducted from total capacity attributed to the 

seller. 

93. We also reject the argument that the 20 percent threshold is too low because of 

native load obligations of investor-owned utilities outside of RTOs. First, the 

calculation of 20 percent is the same regardless of whether a seller is located in an 

RTO or not. Second, as discussed herein, we allow for a native load deduction in the 

wholesale market share screen and are increasing the deduction to address concerns 

raised by investor-owned utilities and others. Given the increased native load 

deduction, our market share screen adequately incorporates investor-owned utilities’ 

native load obligations while necessarily maintaining the conservative nature of the 

screens. 

b. Pivotal Supplier Application Period

Comments

94. Some commenters recommend that the pivotal supplier indicative screen 

should be applied monthly, rather than just in a seller’s peak month. They reason that 

sellers, though not pivotal in the highest demand period, might be pivotal at different 

times of the year or in off-peak periods, such as in the spring or fall when power 

plants are on planned outages.77

 76 April 14 Order, 107 FERC ¶ 61,018 at P 96. 

77 See, e.g. APPA/TAPS at 66-67, NRECA at 19-20. 
Docket No. RM04-7-000 54 

Commission Determination

95. The Commission will not require the pivotal supplier indicative screen to be 

applied monthly, as some commenters suggest, because we believe it is unnecessary 

and overly burdensome to do so. Even though conditions of tight supply may occur 

at other times of the year or in abnormal operating conditions, the combination of the 

pivotal supplier analysis and the wholesale market share screen is sufficient, because 

suppliers with market power at such times are also likely to fail at least one of these 

screens. Moreover, if intervenors believe that a seller is pivotal during non-peak 

periods, they are permitted to file evidence to that effect. Accordingly, using only the 

peak month in the pivotal supplier indicative screen is appropriate. We note that if a 

seller fails the indicative screens and submits a DPT, it is required to provide a 

pivotal supplier analysis for each season and for both peak and non-peak hours. 

3. DPT Criteria

Commission Proposal

96. With regard to the DPT analysis, the Commission proposed to retain the 

current thresholds (20 percent for the market share analysis and 2,500 for the HHI 

analysis), as well as the current practice of weighing all the relevant factors presented 

in determining whether a seller does or does not have horizontal market power. The 

Commission proposed to continue to do so on a case-by-case basis, weighing such 
Docket No. RM04-7-000 55 

factors as available economic capacity, economic capacity, market share, HHIs, and 

historical sales and transmission data.78

Comments

97. Several commenters suggest changes to the DPT criteria. One suggested 

change is to emphasize79 or rely exclusively80 on the available economic capacity 

measure, in order to properly account for native load. For example, one commenter 

argues that the economic capacity prong of the DPT analysis is not a useful indicator 

of the presence or absence of market power when applied to vertically integrated 

utilities in their home control areas because that analysis completely disregards native 

load obligations, making this prong virtually unpassable by such utilities. This 

commenter also notes that even using the available economic capacity measure, a 

seller with a market share above 35 percent would fail the DPT “even though there is 

no real market power problem because the in-area wholesale customers have access 

to ample supplies of competitively priced power.”81 In this regard, he argues that the 

 78 Economic capacity means the amount of generating capacity owned or 

controlled by a potential supplier with variable costs low enough that energy from such 

capacity could be economically delivered to the destination market. Available economic 

capacity means the amount of generating capacity meeting the definition of economic 

capacity less the amount of generating capacity needed to serve the potential supplier's 

native load commitments. See generally April 14 Order, 107 FERC ¶ 61,018 at 

Appendix F. 

79 Dr. Pace at 9. 

80 Southern at 20-21, EEI at 15. 

81 Dr. Pace at 11-12 
Docket No. RM04-7-000 56 

DPT should be changed to take into account “competitive alternatives available for 

wholesale customers.”82

98. Several other commenters disagree with the 2,500 HHI threshold for the DPT. 

Some reason that a 2,500 HHI threshold is not well justified and that an 1,800 HHI 

threshold is more appropriate because this is the criterion used in a highly 

concentrated market. They argue that if a 2,500 HHI threshold is used, it should be 

used with a 15 percent market share because these are the criteria of the oil-pipeline 

test from which the HHI 2,500 criterion is obtained.83 State AGs and Advocates note 

that the Commission has never systematically attempted to correlate the results of the 

pivotal supplier indicative screen, the market share indicative screen, or the DPT 

(including HHI results) proposed in the NOPR with actual independently derived data 

and measures as to the existence of market power in any wholesale electricity market 

in the U.S.84 Without having done this type of systematic and quantitative evaluation 

of the proposed market power tests based on some type of independent verification, 

State AGs and Advocates contend that the Commission cannot be confident that the 

three proposed tests are reasonably accurate and, therefore, useful tests to determine 

 82 Dr. Pace at 12-13. 

83 APPA/TAPS at 78-79, TDU Systems at 18, Montana Counsel at 15 (referring to 

APPA/TAPS comments). 

84 State AGs and Advocates state that by “independently” derived measures of 

market power they mean measures derived using different methodologies (and more 

accurate methodologies) than the Commission proposed in the NOPR. 
Docket No. RM04-7-000 57 

the existence of market power in any electricity market. For example, State AGs and 

Advocates ask how the Commission knows if an HHI corresponds to the point at 

which market power begins, and whether it varies by factors such as input price, 

generation mix and different market structures through the country.85

99. Furthermore, State AGs and Advocates claim that the DPT is not an adequate 

tool for assessing market power "in any context." First, they state that the DPT will 

not discern bidding strategies of different suppliers. In addition, they assert that a 

DPT does not consider the differences between fundamentally different types of 

market structures: short-term energy only markets, short-term capacity markets, 

ancillary service markets, and long-term contract markets for energy and capacity.86

100. A number of commenters believe that the HHI threshold sufficient for passage 

of the DPT should remain at 2,500.87 PPL states that lowering the HHI threshold to 

1,800 will cause more false positives and direct capital away from the generation 

sector. 

101. EEI and Progress Energy recommend that only the pivotal supplier and HHI 

analyses of the DPT should be retained, particularly if the market share analysis 

under the indicative screens is retained. They argue that the pivotal supplier and HHI 

 85 States AGs and Advocates at 36-37. 

86 State AGs and Advocates reply comments at 6-7. 

87 MidAmerican reply comments at 2, citing EEI comments; PPL reply comments 

at 8; EEI reply comments at 23. 
Docket No. RM04-7-000 58 

analyses are more than sufficient to determine whether the potential for market power 

exists.88 

102. A few commenters are skeptical about the need for a DPT. Southern states 

that "granting market-based rates should not require the same analysis as for a 

merger," and that the Commission should reconsider using the DPT.89 In this regard, 

Southern argues that unlike mergers, which are difficult and costly to undo, the 

Commission has the ability to continuously police the exercise of market power. 

Further, Southern states that the Energy Policy Act of 2005 provides for stiff civil and 

criminal penalties. Southern adds that the Commission recently issued new rules 

against market manipulation to thwart exercises of market power. 

103. AARP expresses concern about the lack of competition in wholesale electric 

markets. It argues that market-based rate reviews are intended to determine whether 

the seller’s market-based rates will be just and reasonable, not whether a seller passes 

the various tests. AARP argues that real-world evidence that may not fit neatly 

within the specified market-based rate criteria must be considered before the 

Commission can conclude that a seller lacks market power. AARP states that, as the 

NOPR recognizes (PP 63-64), both historical and forward-looking evidence should 

be considered. 

 88 EEI at 10-12, Progress at 8. 

89 Southern at 19-20. 
Docket No. RM04-7-000 59 

Commission Determination

104. The Commission will continue to use the DPT for companies that fail the 

market power indicative screens. The DPT is a well-established test that has been 

used routinely by the Commission to analyze market power in the merger context 

The fact that it is used in section 203 cases does not demonstrate that it is 

inappropriate for market-based rate cases. Rather, it provides a well-established tool 

for assessing market power that is known and widely used in the electric industry. 

Moreover, in both contexts, the DPT allows for the calculation of market shares and 

market concentration values under a wide range of season and load conditions. 

105. Sellers failing one or more of the initial screens will have a rebuttable 

presumption of market power. If such a seller chooses not to proceed directly to 

mitigation, it must present a more thorough analysis using the DPT. The DPT is also 

used to analyze the effect on competition for transfers of jurisdictional facilities in 

section 203 proceedings,90 using the framework described in Appendix A of the 

Merger Policy Statement and revised in Order No. 642.91

 90 16 U.S.C. § 824b (2000). 

91 Inquiry Concerning the Commission’s Merger Policy Under the Federal Power 

Act: Policy Statement, Order No. 592, 61 Fed. Reg. 68,595 (1996), FERC Stats. & Regs., 

Regulations Preambles July 1996-December 2000 ¶ 31,044 (1996), reconsideration 

denied, Order No. 592-A, 62 Fed. Reg. 33,341 (1997), 79 FERC ¶ 61,321 (1997) (Merger 

Policy Statement); see also Revised Filing Requirements Under Part 33 of the 

Commission’s Regulations, Order No. 642, 65 Fed. Reg. 70,983 (2000), FERC Stats. & 

Regs., Regulations Preambles July 1996-December 2000 ¶ 31,111 (2000), order on reh’g, 

Order No. 642-A, 66 Fed. Reg. 16,121 (2001), 94 FERC ¶ 61,289 (2001). 
Docket No. RM04-7-000 60 

106. The DPT defines the relevant market by identifying potential suppliers based 

on market prices, input costs, and transmission availability, and calculates each 

supplier’s economic capacity and available economic capacity for each season/load 

condition.92 The results of the DPT can be used for pivotal supplier, market share 

and market concentration analyses. 

107. Using the economic capacity for each supplier, sellers should provide pivotal 

supplier, market share and market concentration analyses. Examining these three 

factors with the more robust output from the DPT will allow sellers to present a more 

complete view of the competitive conditions and their positions in the relevant 

markets. 

108. Under the DPT, to determine whether a seller is a pivotal supplier in each of 

the season/load conditions, sellers should compare the load in the destination market 

to the amount of competing supply (the sum of the economic capacities of the 

competing suppliers). The seller will be considered pivotal if the sum of the 

competing suppliers’ economic capacity is less than the load level (plus a reserve 

requirement that is no higher than State and Regional Reliability Council operating 

requirements for reliability) for the relevant period. The analysis should also be 

performed using available economic capacity to account for sellers’ and competing 

suppliers’ native load commitments. In that case, native load in the relevant market 

 92 Super-peak, peak, and off-peak, for Winter, Shoulder and Summer periods and 

an additional highest super-peak for the Summer. 
Docket No. RM04-7-000 61 

would be subtracted from the load in each season/load period. The native load 

subtracted should be the average of the native load daily peaks for each season/load 

condition. 

109. Each supplier’s market share is calculated based on economic capacity. The 

market shares for each season/load condition reflect the costs of the sellers’ and 

competing suppliers’ generation, thus giving a more complete picture of the sellers’ 

ability to exercise market power in a given market. For example, in off-peak periods, 

the competitive price may be very low because the demand can be met using low-cost 

capacity. In that case, a high-cost peaking plant that would not be a viable competitor 

in the market would not be considered in the market share calculations, because it 

would not be counted as economic capacity in the DPT. Sellers must also present an 

analysis using available economic capacity and explain which measure more 

accurately captures conditions in the relevant market. 

110. Under the DPT, sellers must also calculate the market concentration using the 

HHI based on market shares.93 HHIs have been used in the context of assessing the 

impact of a merger or acquisition on competition. However, as noted by the U.S. 

Department of Justice in the context of designing an analysis for granting marketbased pricing for oil pipelines, concentration measures can also be informative in 

 93 The HHI is the sum of the squared market shares. For example, in a market 

with five equal size firms, each would have a 20 percent market share. For that market, 

HHI = (20)2

 + (20)2 + (20)2 + (20)2 + (20)2 = 400 + 400 + 400 + 400 + 400 = 2,000. 
Docket No. RM04-7-000 62 

assessing whether a supplier has market power in the relevant market. “The 

Department and the Commission staff have previously advocated an HHI threshold of 

2,500, and it would be reasonable for the Commission to consider concentration in 

the relevant market below this level as sufficient to create a rebuttable presumption 

that a pipeline does not possess market power.”94

111. A showing of an HHI less than 2,500 in the relevant market for all season/load 

conditions for sellers that have also shown that they are not pivotal and do not 

possess a 20 percent or greater market share in any of the season/load conditions 

would constitute a showing of a lack of market power, absent compelling contrary 

evidence from intervenors. Concentration statistics can indicate the likelihood of 

coordinated interaction in a market. All else being equal, the higher the HHI, the 

more firms can extract excess profits from the market. Likewise a low HHI can 

indicate a lower likelihood of coordinated interaction among suppliers and could be 

used to support a claim of a lack of market power by a seller that is pivotal or does 

have a 20 percent or greater market share in some or all season/load conditions. For 

example, a seller with a market share of 20 percent or greater could argue that that it 

would be unlikely to possess market power in an unconcentrated market (HHI less 

than 1,000). As with our initial screens, sellers and intervenors may present evidence 

 94 See Comments of the United States Department of Justice in response to Notice 

of Inquiry Regarding Market-Based Ratemaking for Oil Pipelines, Docket No. RM94-1-

000 (January 18, 1994). 
Docket No. RM04-7-000 63 

such as historical wholesale sales. Those data could be used to calculate market 

shares and market concentration and could be used to refute or support the results of 

the DPT. The Commission encourages the most complete analysis of competitive 

conditions in the market as the data allow. 

112. We will continue to weigh both available economic capacity and economic 

capacity when analyzing market shares and HHIs. Based on our substantial 

experience in applying the DPT over the past decade, we have found that both 

analyses are useful indicators of suppliers' potential to exercise market power, and we 

are unwilling to rely solely on one measure or the other.95 For example, in markets 

where utilities retain significant native load obligations, an analysis of available 

economic capacity may more accurately assess an individual seller’s competitiveness, 

as well as the overall competitiveness of a market, because available economic 

capacity recognizes the native load obligations of the sellers. On the other hand, in 

markets where the sellers have been predominantly relieved of their native load 

obligations, an analysis of economic capacity may more accurately reflect market 

conditions and a seller’s relative size in the market. 

 95 See, e.g., Tampa Electric Company, 117 FERC ¶ 61,311 (2006); PacifiCorp, 

115 FERC ¶ 61,349 (2005); Tucson Electric Power Company, 116 FERC 

¶ 61,051(2006); Duke Power, a Division of Duke Energy Corporation, 111 FERC 

¶ 61,506 (2005); and Kansas City Power and Light Company, 113 FERC ¶ 61,074 

(2005). 
Docket No. RM04-7-000 64 

113. Likewise, we find the HHI market concentration measure to be useful in 

assessing the market power of individual sellers, and it complements the market share 

and pivotal supplier measures in the DPT stage of the analysis. Furthermore, no 

commenter has presented a compelling argument for why the Commission should 

lower or raise the HHI threshold in the DPT. Accordingly, we will retain 2,500 as the 

appropriate threshold for passing this part of the DPT for the reasons we stated in the 

April 14 Order.96 We will not adopt the suggestion to lower the market share 

threshold to 15 percent from 20 percent, for the reasons set forth above, in the NOPR 

and July 8 Order.97 Commenters have presented no compelling reason to do so, and 

in our experience since the April 14 Order, we have not seen cases where the HHI 

was over 2,500 and the seller’s market share was between 15 and 20 percent, which 

would be the type of situation about which APPA/TAPS and others are concerned. 

Accordingly, such a reform would not likely result in additional findings of market 

power. 

114. State AGs and Advocates claim that the DPT is not an adequate tool for 

assessing market power because it will not discern bidding strategies of different 

suppliers. However, State AGs and Advocates miss the point of the analysis: by 

 96 April 14 Order, 107 FERC ¶ 61,018 at P 111 (explaining that at less than 2,500 

HHI in the relevant market for all season/load conditions there is little likelihood of 

coordinated interaction among suppliers in a market). 

97 July 8 Order at P 95-97 and NOPR at P 41. 
Docket No. RM04-7-000 65 

determining whether a seller has capacity that can compete in the market under 

various season and load conditions, the DPT provides an accurate picture of market 

conditions. Examining market conditions allows the Commission to determine 

whether a seller has market power. The DPT does this by examining short-term 

energy markets and, in particular, sellers’ available generation capacity. In addition, 

absent entry barriers, and a specific finding of market power, the Commission has 

said that long-term markets are competitive. With regard to ancillary services, as 

discussed herein, the Commission requires market power analyses for those services 

to support a request for market-based rate authority. Assessing competing suppliers’ 

bidding strategies, ex ante, would not illuminate the state of the market and the ability 

of sellers to alter prices within it. 

115. We also reject Southern’s argument that the DPT analysis is unnecessary 

because of the Commission’s enhanced civil penalty authority and continuing 

policing of sellers with market-based rate authorization. While those are critical 

components of our program to ensure just and reasonable market-based rates, they are 

not a substitute for an analysis of the potential market power of sellers seeking 

market-based rate authority. In addition, Southern’s argument that rules against 

market manipulation will thwart all exercises of market power is speculative. 

116. We will not change the DPT to take into account competitive alternatives 

available for wholesale customers as proposed by a commenter. We stated above our 

reasons for rejecting use of a contestable load analysis in the indicative screens, and 

we reject it for the DPT for the same reasons. 
Docket No. RM04-7-000 66 

117. AARP and State AGs and Advocates argue that the Commission should 

consider evidence from actual market data in determining whether market power 

exists rather than rely on the results of the DPT to determine whether a seller has 

market power. We agree that actual market data is an important part of a 

determination of whether a seller may have market power. In this regard, we look at 

actual market data, both in the initial analysis and in ongoing monitoring of the EQR 

data. As the Commission stated in the April 14 Order, “[a]s with our initial screens, 

applicants and intervenors may present evidence such as historical wholesale sales. 

Those data could be used to calculate market shares and market concentration and 

could be used to refute or support the results of the Delivered Price Test.”98 In 

addition, as part of our ongoing monitoring activities, we examine the EQR data in an 

effort to identify whether market prices may indicate an exercise of market power. 

4. Other Products and Models

Comments

118. ELCON expresses concern over the entire horizontal market power analysis 

process: indicative screens, followed by DPT or mitigation for those that fail the 

indicative screens. ELCON notes that the evolution of these practices generally 

occurred in a series of highly contested proceedings, and did not benefit from the 

broader and more balanced review afforded by a generic rulemaking. ELCON states 

 98 April 14 Order, 107 FERC ¶ 61,018 at P 112. 
Docket No. RM04-7-000 67 

that its concern is that the practices unduly shift the burden of proof to potential 

victims of market power abuse. This concern would only be academic, ELCON 

continues, if the market structures were truly competitive and there were strong 

structural protections against the exercise of market power. But the hybrid nature of 

most regional markets, combined with inadequate infrastructure, creates an 

environment that discourages trust in market outcomes.99 

119. Some commenters urge the Commission to allow different product definitions, 

e.g., short-term power and long-term power, in the calculation of the indicative 

screens and the DPT. For example, NRECA argues that the Final Rule must require 

sellers to identify the relevant product markets, including the distinct products for 

which they seek market-based rate authority, and demonstrate that they lack market 

power in those product markets.100 The Montana Counsel argues that the 

Commission’s screens and DPT analysis models measure market power during 

certain test days for current time periods,101 and that capacity that is available to 

make short-term energy sales may not be available for long-term, firm power sales. 

Thus, the Montana Counsel asserts that the Commission may not rely exclusively on 

 99 ELCON at 4-5. 

100 NRECA at 16-18. 

101 Montana Counsel at 5-8. 
Docket No. RM04-7-000 68 

short-term or spot markets to measure whether there are competitive long-term 

markets. 

120. Other commenters remain divided over whether long-term power markets 

should be included in the market power analysis. PPL urges that long-term markets 

should not be considered in a market power analysis because of infeasibility and also 

because it violates the Commission's precedent that there is no long-term market 

power unless there exist barriers to entry.102 In contrast, NRECA and TDU Systems 

state that long-term markets need to be analyzed in the market power analysis 

because monopolies will probably persist into the future for many consumers103 and 

these consumers need protection. TDU Systems suggest using an installed capacity 

indicative screen for long-term markets.104 

121. State AGs and Advocates and NASUCA suggest that the Commission adopt 

behavioral modeling, such as game theory, rather than structural analysis, because the 

latter cannot capture market power behavior.105 NASUCA suggests that the 

Commission hold a technical conference to consider behavioral modeling. Duke 

disagrees with NASUCA's and others' calls for behavioral models, contending that 

 102 PPL reply comments at 2-3 and n.6, citing Exelon Corp., 112 FERC ¶ 61,011 at 

P 136 (2005). 

103 NRECA reply comments at 11, TDU Systems reply comments at 5-7. 

104 TDU Systems reply comments at 9. 

105 State AGs and Advocates at 29-30, NASUCA at 14-15. 
Docket No. RM04-7-000 69 

they are theoretically complex and data-intensive and do not meet the prerequisite of 

being simple, easily understood and readily verifiable by the Commission. 

Commission Determination

122. We will not generically alter the indicative screens or the DPT to allow 

different product analyses for short-term or long-term power as some commenters 

suggest. As the Commission has stated in the past, absent entry barriers, long-term 

capacity markets are inherently competitive because new market entrants can build 

alternative generating supply. There is no reason to generically require that the 

horizontal analysis consider those products that are affected by entry barriers. 

Instead, we will consider intervenors' arguments in this regard on a case-by-case 

basis. 

123. We reject ELCON’s contentions regarding the development of our horizontal 

market power analysis. While the screens and DPT criteria did arise out of specific 

cases, there have been numerous opportunities in this rulemaking for interested 

parties to express any concerns and propose alternatives, including technical 

conferences and numerous rounds of written comments. We believe that this 

rulemaking has given all interested parties ample opportunity to voice any and all 

options for revising the screens and DPT criteria and proposing alternatives, and has 

given us the opportunity to evaluate whether these tools remain appropriate. We 

conclude that they do. 

124. Finally, we will not adopt the suggestion by some commenters that behavioral 

modeling be used in addition to, or in place of, the indicative screens and the DPT. 
Docket No. RM04-7-000 70 

Although game theory has been used in laboratory experiments and in theoretical 

studies where the number of players and choices available to players are limited, we 

do not consider it a practical approach for the volume of analyses we must perform, 

particularly since a vast amount of choices are available and many of those are 

unobservable. The data gathering and analysis burden imposed on sellers and the 

Commission would be overly burdensome and impractical. 

5. Native Load Deduction

a. Market Share Indicative Screen

Commission Proposal

125. To reduce the number of “false positives” in the wholesale market share 

indicative screen, the Commission proposed in the NOPR to adjust the native load 

proxy for this screen. The Commission proposed to change the allowance for the 

native load deduction under the market share indicative screen from the minimum 

native load peak demand for the season to the average native load peak demand for 

the season. This change makes the deduction for the market share indicative screen 

consistent with the deduction allowed under the pivotal supplier indicative screen.

Comments

126. TDU Systems argue that the Commission provides no empirical evidence 

supporting this change—i.e., no evidence of an excessive number of false positives 

produced by the Commission’s current policy. TDU Systems also state that the 
Docket No. RM04-7-000 71 

Commission does not explain why it believes its current proxy “results in too much 

uncommitted capacity attributable to the seller.”106 In particular, TDU Systems state 

that the Commission does not explain what factors it used to determine the 

appropriate level of uncommitted capacity to which it compared the current proxy. 

127. APPA/TAPS agree, adding that the Commission proposal appears to be a 

results-driven effort to eliminate the need for some public utilities to submit a 

DPT.107 APPA/TAPS argue that the Commission’s “false positives” justification 

loses sight of the stakes involved in the market-based rate determination. They state 

that the price of a false positive associated with the initial screens will be the seller’s 

submission of the DPT. APPA/TAPS argue that that price pales in comparison to the 

unreasonably high prices and market power exercise that can result from a false 

negative. According to APPA/TAPS, it is thus entirely appropriate for the 

Commission to take a closer look when a utility fails the initial screens, even when 

the Commission ultimately allows market-based rate authorization.108

 106 TDU Systems at 13. 

107 APPA/TAPS at 68, citing Acadia Power Partners LLC, 111 F.E.R.C. ¶ 61,239 

(2005), and Kansas City Power & Light Co., 111 FERC ¶ 61,395 (2005), where the 

applying utilities failed the market share screen, but passed the pivotal supplier screen. In 

both cases, the company opted to submit a DPT, and after consideration, the Commission 

allowed the utilities to retain their market-based rate authority. Acadia Power Partners, 

LLC, 113 FERC ¶ 61,073 (2005); Kansas City Power & Light Co., 113 FERC ¶ 61,074 

(2005). 

108 APPA/TAPS at 68-70. 
Docket No. RM04-7-000 72 

128. In addition, APPA/TAPS state that, as well as lacking evidentiary basis, the 

proposed adjustment is not based on sound economic principles. APPA/TAPS argue 

that when the Commission originally adopted the native load proxy for the market 

share screen, it said the screen should reflect “all of the capacity that is available to 

compete in wholesale markets at some point during the season.”109 APPA/TAPS state 

that now the Commission proposes to eliminate even more of the capacity that is 

available to compete at some point in the season by increasing the proxy to the 

average native load peak demand for the season. 

129. APPA/TAPS further argue that adoption of the Commission’s proposal would 

mean that the market-based rate screens would make no assessment of off-peak 

periods, even though the Commission has said that the market share screen is 

intended to measure market power during off-peak times.110 They state that “screens 

should examine market power for the on-peak and off-peak periods of the different 

seasons.”111

130. Finally, APPA/TAPS argue that consistency across the two screens defeats the 

purpose of having more than one screen. The market share screen is intended to 

reflect capacity that could compete, including during off-peak periods. By contrast, 

 109 APPA/TAPS at 69, citing April 14 Order, 107 FERC ¶ 61,018 at P 92. 

110 April 14 Order, 107 FERC ¶ 61,018 at P 72. 

111 APPA/TAPS at 70, citing Kirsch SMA Affidavit at 8-9. 
Docket No. RM04-7-000 73 

the pivotal supplier screen is specifically intended to measure market power risks at 

system peak. 

131. APPA/TAPS offer that if the Commission nonetheless believes some 

consistency is desired it can achieve it by using a native load proxy for the market 

share screen based upon the average minimum loads. Such a proxy would be 

consistent with the Commission’s original intent of a screen that identifies “all of the 

capacity that is available to compete in wholesale markets at some point during the 

season.”112 

132. Other commenters generally support the Commission’s proposal to use 

seasonal average native load as the native load proxy for the market share indicative 

screen. Many state that the proposed native load proxy is a more accurate 

representation of native load obligations.113 Several commenters suggest excluding 

weekends and holidays from the proxy native load calculation because these periods 

are not representative of normal load hours.114 

 112 April 14 Order, 107 FERC ¶ 61,018 at P 92. 

113 See, e.g., Ameren at 3, FirstEnergy at 4-5. 

114 See, e.g., EEI at 17, PG&E at 6-7, Allegheny at 7-8, and Pinnacle at 34, both 

citing Pinnacle West Capital Corp., 109 FERC ¶ 61,295 (2004). Several commenters 

disagree with the suggestion that weekends and holidays should be excluded from the 

native load proxy, stating that it is unsupported and, moreover, excluding these hours 

means that native load proxy ceases to be average. TDU Systems reply comments at 8-9, 

NRECA reply comments at 16-17. 
Docket No. RM04-7-000 74 

133. EEI argues that even with this proposed change, the generation capacity 

required by a utility to serve its native load is still being understated.115 It states that 

utilities are required to meet the peak demands of their native load customers plus 

maintain a reserve margin for reliability purposes. This requirement directly 

determines the amount of generation capacity that a supplier can commit to the 

wholesale opportunity sales market. As such, EEI argues that the change proposed in 

the NOPR is a step in the right direction in terms of more accurately recognizing the 

amount of generation capacity required by a utility to meet native load requirements, 

but still understates the actual requirements. 

134. EEI contends that from a generation planning perspective, no one with any 

expertise in that area doubts the native load proxy described in the April 14 Order 

underestimates the amount of capacity that a supplier needs to meet native load 

requirements and therein both overstates the amount of capacity that the supplier has 

to compete in the wholesale market as well as the supplier’s market share. As a result 

of this overestimation of the capacity that a supplier would have to compete in the 

wholesale market, EEI contends that non-RTO vertically integrated utilities have 

failed the market share screen using the current native load proxy when many simply 

do not have market power. 116 EEI concludes that such a high number of “false 

 115 EEI at 24-25; see also Puget reply comments at 2. 

116 EEI reply comments at 24. 
Docket No. RM04-7-000 75 

positives” for market power that have occurred using the current proxy clearly 

supports the Commission’s proposal to move the native load proxy to the average 

peak load in the season. 

Commission Determination

135. We adopt the NOPR proposal to change the native load proxy under the 

market share indicative screen from the minimum native load peak demand for the 

season to the average of the daily native load peak demands for the season, making 

the native load proxy for the market share indicative screen consistent with the native 

load proxy under the pivotal supplier indicative screen. 

136. In this regard, we find that the market share screen should be calculated using 

as accurate a representation of market conditions for each season studied as possible. 

We find that using the current native load proxy using the minimum native load level 

for the season does not provide an accurate picture of the conditions throughout the 

season. 

137. We recognize that increasing the native load proxy will have the effect of 

reducing the market share for traditional utilities with significant native load 

obligations, and therefore may result in fewer failures of the wholesale market share 

screen for some sellers. However, we believe that such a result is justified. We are 

seeking a screen that provides a reasonably accurate picture of a seller’s position 

given market conditions across seasons, so that we can eliminate those sellers who 

clearly do not have market power and focus our analysis on those who might. We 

believe that a native load proxy based on the average of peak load conditions is more 
Docket No. RM04-7-000 76 

representative, and thus more accurate, than a proxy based on extreme (i.e., 

minimum) peak load conditions. We also believe that basing the native load proxy 

on the average of the peaks will make the screens more accurate in eliminating sellers 

without market power while focusing on ones that may have market power. 

138. For sellers that contend that the proposed native load proxy will result in too 

many false positives, we note that under the existing native load proxy, fewer than 25 

companies have been the subject of § 206 investigations since the April 14 Order. 

For entities that fear this change in native load proxy will lead to too many "false 

negatives," (companies with market power passing under the indicative screens), we 

note that intervenors can always challenge the presumption of no market power. 

Moreover, no intervenor in this proceeding has pointed to specific companies that 

have passed the screens but still have market power. 

139. We reject APPA/TAPS’ argument that changing the native load proxy would 

result in the market-based rate screens making no assessment of off-peak periods. In 

fact, the native load proxy we approve here is based on the average of the native load 

daily peaks which also include low load days. The use of the average peak demand 

for the native load proxy provides for an assessment of all periods, peak and off-peak 

seasons, because such a proxy considers peak native load of each day in each season. 

Combined with the pivotal supplier screen that captures the annual peak conditions, 

we find that the two screens adequately capture market conditions over the year. 

140. We also reject APPA/TAPS’ argument that consistency across the two screens 

defeats the purpose of having more than one screen. The screens in and of 
Docket No. RM04-7-000 77 

themselves are inherently different methodologies in that the pivotal supplier screen 

considers whether the seller’s generation must run to meet peak load, whereas the 

market share screen looks at the seller’s size relative to other sellers in the market. 

We are looking for an assessment of the uncommitted seasonal capacity available to 

sellers to compete in wholesale markets and, as stated above, find that the average of 

the daily peak loads in a season more accurately reflects seller’s commitments. 

141. APPA/TAPS suggest that if we do raise the native load deduction, we only 

raise it to the average minimum for the season, rather than the average native load 

peak demand for the season. The intent of the wholesale market share screen is to 

assess market conditions during the season, not only during off-peak hours. 

APPA/TAPS is misplaced in its assertion that our original intent was for the market 

share screen to focus solely on off-peak conditions. In the April 14 Order we stated 

that “by using the two screens together, the Commission is able to measure market 

power both at peak and off-peak times.” 117 Our statement simply recognizes that a 

seller with a dominant position in the market could have market power in the off-peak 

as well as the peak. Clearly the pivotal supplier analysis is designed to assess market 

power at peak times, but that does not imply that the wholesale market share screen is 

designed only to assess market power in the off-peak period. 

 117 April 14 Order at P 72. 
Docket No. RM04-7-000 78 

142. Finally, we will not exclude weekends and holidays from the market share 

native load proxy. Since we adopt herein the use of an average peak demand for the 

native load proxy for the market share screen, the exclusion of weekends and 

holidays would inappropriately skew the results. Use of an average load addresses 

the issue of the variability between unusually high or low load days, is more 

objective, and easily applied. If weekends and holidays are excluded, only 

approximately 70 percent of total load hours would be accounted for. The average 

native load measure that includes weekends and holidays, and which we adopt, is 

truly an average of all load conditions. 

b. Pivotal Supplier Indicative Screen

Commission Proposal

143. In the NOPR, the Commission proposed to retain the pivotal supplier screen’s 

native load proxy at its current level of the average of the daily native load peaks 

during the month in which the annual peak day load occurs.118 

Comments

144. Southern states that the pivotal supplier screen is conceptually sound; 

however, the manner of its current implementation reflects a significant flaw. In 

particular, Southern claims that the wholesale load (market size) is determined by the 

difference between the control area’s needle peak demand and the average of the 

 118 NOPR at P 44. 
Docket No. RM04-7-000 79 

daily peaks in that peak month. Southern argues that it is not at all clear how or why 

this mathematical exercise (which in its opinion reflects an “apples and oranges” 

comparison) provides any meaningful measure of competitive wholesale demand 

during any relevant period. 

145. For example, Southern continues, under some circumstances, all or a large 

portion of the wholesale load determined in this fashion could be the seller’s own 

native load. Subtracting the average daily peaks in the peak month from a single 

needle peak to derive a “proxy” for competitive wholesale demand necessarily 

assumes that all of this difference is unsatisfied wholesale market demand that is 

subject to competition. Southern argues that this is not a valid assumption and the 

Commission has provided no reason to believe that it is. Southern therefore urges the 

Commission to abandon this aspect of the interim pivotal supplier analysis and 

instead use an estimate of actual wholesale load, rather than deriving it indirectly 

through an arithmetic exercise. For example, the seller’s native load peak could be 

subtracted from the control area peak load on an “apples to apples” basis (for 

example, needle peaks, seasonal peaks, or average 

daily peaks) to derive, in Southern's view, a much better wholesale load proxy.119 

Southern asserts that such a reform would be relatively easy to implement and would 

yield much more meaningful results.120 

 

 (continued...) 

 

119 Southern notes that this suggested calculation would still overstate the amount 

of wholesale load open to competition because some portion of that wholesale load 
Docket No. RM04-7-000 80 

146. NRECA disagrees with Southern's proposed modification to the pivotal 

supplier screen to use actual wholesale load, stating Southern provides no evidence 

that this modification would provide a more accurate estimate of the wholesale load 

than the current approach.121

Commission Determination

147. We retain the average daily peak native load as the native load proxy used in 

the pivotal supplier screen, as proposed in the NOPR, and we reject Southern’s 

argument that our method of computing the native load proxy is unreasonable. 

Southern argues that because the wholesale demand is determined by subtracting the 

average daily peaks in the peak month from a single needle peak, the Commission is 

relying on an invalid assumption with regard to the wholesale demand during any 

relevant period. However, Southern’s claim that our deduction of the average of the 

daily native load peaks from the needle peak is a “mixing of apples and oranges” 

ignores our reasoning in the April 14 Order: 

 

would undoubtedly be covered with existing supply arrangements. It states that if it were 

required to net out the amount of wholesale load covered by those existing supply 

arrangements, a similar amount should be subtracted from the market resources deemed 

to be competing to serve the net wholesale load. 

120 Southern at 18-19. 

121 NRECA reply comments at 19-20. 
Docket No. RM04-7-000 81 

conditions in peak periods can provide significant opportunity to exercise 

market power. As capacity is utilized to meet demand there is less available 

to sell on the margin and often less competition. Only focusing on needle 

peaks that occur for a single hour and that are only known after the fact 

does not give an accurate reflection of the competitive dynamics of peak 

periods. As demand increases during peak periods, buyers and sellers are 

positioning themselves in the market with similar but incomplete 

information. Buyers are projecting their needs and trying to secure needed 

power, while sellers are negotiating to obtain the highest price for that 

power. With increasing demand, fewer units are available to serve 

anticipated peak needs and buyers bid to secure dwindling supply load 

increases. In addition, buyers must be prepared for the contingency that a 

unit will be forced out and they will need to purchase in a period of even 

greater scarcity.[122] 

148. Further, both native load proxies provide an adequate solution to a 

complicated issue. Resources used to serve native load fluctuate over the course of 

the day and through the seasons. As the Commission stated in the April 14 Order, 

"we recognize that not all generation is available all of the time to compete in 

wholesale markets and that some accounting for native load requirements is 

warranted here. However, wholesale and retail markets are not so easily separated 

such that a clear distinction can be made between generation serving native load and 

generation competing for wholesale load. Most utility generation units are not 

exclusively devoted to serving native load, or selling in wholesale markets."123 

149. For these reasons we continue to believe that the average of the native load 

peaks in the peak month is a reasonable proxy for the native load deductions under 

 122 April 14 Order, 107 FERC ¶ 61,018 at P 91. 

123 Id. at P 67. 
Docket No. RM04-7-000 82 

this screen. Moreover, we also find that Southern’s proposed method of estimating 

the actual wholesale load is inappropriate because it would artificially reduce the 

seller’s share of that load. This is because Southern’s methodology only deducts the 

seller’s native load peak from the control area peak (not the native load peaks of any 

other sellers in the control area), leaving the seller with a disproportionately small 

share of the remaining market. 

c. Clarification of Definition of Native Load

Commission Proposal

150. In the NOPR, the Commission expressed its belief that there has been some 

inconsistency in the way in which sellers have reflected native load in performing 

both the screens and the DPT analysis. Because the states are under various degrees 

of retail restructuring, the definition of native load customers has lacked precision. 

Accordingly, the Commission proposed to clarify that, for the horizontal market 

power analysis, native load can only include load attributable to native load 

customers as defined in §33.3(d)(4)(i) of the Commission’s regulations,124 as it may 

be revised from time to time. 

Comments

 124 18 CFR 33.3(d)(4)(i) provides: Native load commitments are commitments to 

serve wholesale and retail power customers on whose behalf the potential supplier, by 

statute, franchise, regulatory requirement, or contract, has undertaken an obligation to 

construct and operate its system to meet their reliable electricity needs. 
Docket No. RM04-7-000 83 

151. APPA/TAPS support the native load clarification, without providing 

additional explanation. A number of other commenters discussed the native load 

clarification in the context of defining retail contracts or provider of last resort 

(POLR) load as native load. PPL Companies request that this clarification not be 

adopted unless the Commission provides further clarification that an entity selling 

power to a retail customer under a long-term contract is able to deduct that capacity.

125

Commission Determination

152. We will adopt the NOPR proposal that, for the horizontal market power 

analysis, native load can only include load attributable to native load customers as 

defined in § 33.3(d)(4)(i) of our regulations. We address the comments of PPL 

Companies' and others below in the "Other Native Load Concerns" section. 

d. Other Native Load Concerns

Comments 

153. Some commenters suggest alterations to the definition of native load or to the 

circumstances when contract capacity may be deducted from total capacity. One 

commenter recommends that POLR load be counted as native load.126 Sempra 

argues that generators should be allowed to take native load deductions for power 

 125 PPL Companies at 14-17. 

126 Drs. Broehm and Fox-Penner at 11-12. 
Docket No. RM04-7-000 84 

supplied to franchised utilities that divested their generation.127 It argues that 

allowing such suppliers to claim native load deductions correctly assigns these 

obligations to the entities that actually commit the generation resources necessary to 

serve native load and results in a more accurate assessment of the suppliers’ 

remaining uncommitted capacity. It notes that such sales may be for terms of less 

than one year, and that under the Commission’s policy such suppliers cannot deduct 

those commitments as long-term firm sales. Sempra further points out that franchised 

utilities do not need a one-year or greater commitment to take a native load 

deduction. It concludes that marketers and other suppliers should thus be allowed to 

account for the native load commitments they undertake, regardless of the term of 

each underlying contract.128 

Commission Determination

154. We will not adopt suggestions that sellers receive native load deductions for 

all their POLR contracts or for all contracts that serve utilities that have divested their 

generation. Even in cases where independent power producers (IPPs) serve what 

used to be franchised public utilities' native load, IPPs do not serve it under the same 

 127 Sempra reply comments at 4-5. 

128 PSEG Companies in their reply comments also make similar arguments about 

native load that are noted above in the "Control and Commitment of Generation" section. 
Docket No. RM04-7-000 85 

terms as those utilities.129 Unlike franchised public utilities, IPPs may choose to exit 

the market once the contracts they sell power under have expired. However, we 

remind IPPs that POLR contracts with a term of one year or more may be deducted 

from total capacity under some circumstances. As the Commission explained in the 

July 8 Order, “applicants may deduct ‘load following’ and ‘provider of last resort’ 

contracts for terms of one year or more under certain conditions. Specifically, we 

will allow sellers to deduct long-term firm load following contracts to the extent that 

the seller has included in its total capacity a corresponding generating unit or longterm firm purchase contract that will be used to meet the obligation. The seller’s 

contractual peak load obligation under the contract should be used as the capacity 

adjustment in the pivotal supplier analysis and the seasonal baseline demand levels 

served under the contract should be used as the adjustments in the market share 

analysis. The residual capacity will be considered available for sales in the wholesale 

spot markets and treated as uncommitted capacity.”130 Also, in response to PPL 

Companies, we note that long-term (one year or more) firm contracts that cede 

control may always be deducted from total capacity. 

155. We will allow IPPs to deduct short term native load obligations if they can 

show that the power sold to the utility was used to meet native load. We agree with 

 129 See 18 CFR 33.3(d)(4)(i) for the definition of native load. 

130 See July 8 Order, 108 FERC ¶ 61,026 at P 66. 
Docket No. RM04-7-000 86 

Sempra that allowing such suppliers to claim native load deductions correctly assigns 

these obligations to the entities that actually commit the generation resources 

necessary to serve native load and results in a more accurate assessment of the 

suppliers’ remaining uncommitted capacity, and that such sales may be for terms of 

less than one year. Under our current policy such suppliers cannot deduct those 

commitments as long-term firm sales, whereas franchised utilities do not need a oneyear or greater commitment to take a native load deduction. 

6. Control and Commitment

Commission Proposal

156. The Commission noted in the NOPR that uncommitted capacity is determined 

by adding the total capacity of generation owned or controlled through contract and 

firm purchases less, among other things, long-term firm requirements sales that are 

specifically tied to generation owned or controlled by the seller and that assign 

operational control of such capacity to the buyer.131 The Commission further stated 

that long-term firm load following contracts may be deducted to the extent that the 

seller has included in its total capacity a corresponding generating unit or long-term 

firm purchase that will be used to meet the obligation even if such contracts are not 

 131 NOPR at P 46.
Docket No. RM04-7-000 87 

tied to a specific generating unit and do not convey operational control of the 

generation.132 

157. Noting that contracts can confer the same rights of control of generation or 

transmission facilities as ownership of those facilities, the Commission stated that if a 

seller has control over certain capacity such that the seller can affect the ability of the 

capacity to reach the relevant market, then that capacity should be attributed to the 

seller when performing the generation market power screens. The capacity 

associated with contracts that confer operational control of a given facility to an 

entity other than the owner must be assigned to the entity exercising control over that 

facility, rather than to the entity that is the legal owner of the facility.133

158. In the NOPR, the Commission stated that in recent years some owners have 

outsourced to third parties pursuant to energy management agreements the day-to-day 

activities of running and dispatching their generating plants and/or selling output. 

The Commission noted that the agreement may, directly or indirectly, transfer control 

of the capacity. The Commission expressed concern that under such third-party 

agreements, there may be instances where control of capacity has changed hands, but 

 132 Id.

133 Reporting Requirement for Changes in Status for Public Utilities with MarketBased Rate Authority, Order No. 652, 70 F. R. 8253 (Feb. 18, 2005), FERC Stats. & 

Regs., Regulations Preambles 2001-2005 ¶ 31,175 at P 47, order on

reh’g, Order No. 652-A, 111 FERC ¶ 61,413 (2005). 
Docket No. RM04-7-000 88 

this capacity has not been attributed to the correct seller for the purposes of the 

generation market power screens.134 

159. In cases examining whether an entity is a public utility, the Commission has 

examined the totality of the circumstances in evaluating whether the entity effectively 

has control over capacity that it manages.135 Likewise, in providing guidance 

regarding events that trigger a requirement to submit a notice of change in status, the 

Commission has indicated that, to determine whether control has been acquired, 

sellers should examine whether they can affect the ability of capacity to reach the 

relevant market. 

160. The Commission asked in the NOPR whether, in the interest of providing 

greater certainty and clarity regarding the determination of control, it should make 

generic findings or create generic presumptions regarding what constitutes control. 

In particular, the Commission sought comment on whether any of the following 

functions should merit a finding or presumption of control and, if so, on what basis: 

directing plant outages, fuel procurement, plant operations, energy and capacity sales, 

and/or credit and liquidity decisions.136 

 134 NOPR at P 48. 

135 D.E. Shaw Plasma Power, L.L.C., 102 FERC ¶ 61,265 at P 33-36 (2003) (D.E. 

Shaw); R.W. Beck Plant Management, Ltd., 109 FERC ¶ 61,315 at P 15 (2004) (Beck). 

136 NOPR at P 49. 
Docket No. RM04-7-000 89 

161. Alternatively, rather than focusing on these discrete functions, the 

Commission asked if it should establish a presumption of control for any entity that 

has some discretion over the output of the plant(s) that it manages. The Commission 

asked whether such an approach would promote greater certainty. The Commission 

also asked, if it adopted such a presumption, how it should address instances where 

discretion over plant output may be shared between more than one party.137 

162. The Commission proposed to clarify that, in the event it adopted any such 

presumptions, an individual seller could rebut the presumption of control on the basis 

of its particular facts and circumstances. In addition, the Commission proposed to 

clarify that an entity that controls generation from which jurisdictional power sales 

are made is required to have a rate on file with the Commission. If the rate authority 

sought is market-based rate authority, then that entity is subject to the same 

conditions and requirements as any other like seller. 138 

163. The intent of the Commission’s proposals was to provide greater certainty and 

clarity as to the treatment of capacity that is subject to energy management 

agreements and outsourcing of functions so that the capacity is properly reported (and 

studied) and to make clear that any entity to which control is attributed must receive 

 137 Id.

138 Id. at P 50. 
Docket No. RM04-7-000 90 

the necessary authorizations under the FPA in order to provide jurisdictional 

services.139

a. Presumption of Control

164. As an initial matter, most commenters support the Commission’s desire to 

provide greater clarity and certainty regarding the determination of control.140 In this 

regard, many commenters express concerns that attributing generation capacity to 

sellers that do not necessarily control that generation may result in the seller falsely 

appearing to have market power and ultimately result in unnecessary mitigation. 

Commenters also express the need for the determination of control to be consistent 

for both the market-based rate authorizations and the change in status filings. 

165. However, most commenters also oppose the Commission’s proposal to 

establish generic findings or generic presumptions regarding what constitutes control, 

arguing that such findings must be made on a case-by-case basis. Others suggest a 

rebuttable presumption that control lies with the owner unless specific facts indicate 

otherwise. 

 139 Id. 

140 See, e.g, Constellation at 18; EEI reply comments at 25; Financial Companies 

at 4; FirstEnergy at 5; Pinnacle at 4; Powerex at 7; SCE at 2. 
Docket No. RM04-7-000 91 

i. Fact Specific Determinations

Comments

166. Various commenters argue for a fact specific determination of control.141 For 

example, Alliance Power Marketing, a supplier of energy management services, 

argues that a case-by-case approach provides increased certainty for generators and 

asset managers who relied upon Commission precedent in developing their current 

arrangements.142 

167. Several commenters state that they have some sympathy with the 

Commission’s desire to provide certainty and clarity in this area, however, they do 

not agree that there should be generic presumptions regarding the indicia of control. 

One commenter argues that details of each contract vary, depending upon parties and 

circumstances involved as well as on conditions in the market place, and therefore it 

must be reviewed and evaluated with care.143 This commenter suggests that an 

individual seller should be obligated to submit its contracts to the Commission for 

review, and allowed to present its case on the basis of its particular facts and 

circumstances. 

 141 See, e.g., Constellation at 18; Duke at 24; EPSA at 38; PPL at 9 and reply 

comments at 11; APPA/TAPS at 76. 

142 Alliance Power Marketing reply comments at 7. 

143 Drs. Broehm and Fox-Penner at 6-7. 
Docket No. RM04-7-000 92 

168. Similarly, APPA/TAPS believe that the Commission is correct to assign 

capacity to a seller for purposes of running the screens/DPT; however, they point out 

that generic findings or presumptions would be helpful only if the particulars of a 

contract aligned with the factual assumptions underlying a presumption. Otherwise, 

they state that a presumption could produce wrong results.144 APPA/TAPS suggest 

that any arrangement that could create opportunities for sellers to coordinate their 

behavior with other competitors should be reported and that as part of the seller’s 

assigning control over long-term contracts for purposes of the screens/DPT, the 

Commission should require a seller to submit the relevant contracts with the marketbased rate application or triennial update and identify the contractual provisions that 

support the seller’s control determinations.145 APPA/TAPS suggest that marketing 

alliances or joint operating agreements can affect a seller’s market position and 

should be considered in the determination of control.146 

169. Powerex argues that clarity is particularly important as the new market 

manipulation rule makes it unlawful “to omit to state a material fact necessary in 

order to make the statements made, in the light of the circumstances under which they 

 144 APPA/TAPS at 76. 

145 Id. APPA/TAPS further note that confidentiality concerns can be addressed 

with appropriate protective orders. 

146 APPA/TAPS at 77 and 89. 
Docket No. RM04-7-000 93 

were made, not misleading.”147 In this regard, Powerex urges the development of a 

single principle or set of principles that need to be met to establish control over an 

asset. Powerex argues that the development of such principles will help take the 

guesswork out of compliance and provide greater certainty for the market, as 

compared to a laundry list of possible contract types. Powerex states that the control 

principle should focus on physical output as opposed to financial terms, since it is 

physical output that addresses the Commission's physical withholding concerns and 

relates to the agency's market screens.148

170. EEI, EPSA, and Reliant argue that the Commission should continue to look at 

the totality of circumstances and attach the presumption of control when an entity can 

affect the ability of capacity to reach the market.149

171. NYISO states that based on its experience in the administration of bid-based 

markets, what matters in the control of a plant is the ability to determine or 

significantly influence (a) the levels of the bids from the plant, and (b) the level of 

output from the plant. Accordingly, the Commission should focus directly on these 

critical facts, rather than creating presumptions based on indirect indicia of an ability 

to control these key competitive parameters. NYISO claims that plant engineering or 

 147 Powerex at 7 (quoting 18 CFR 1c.2(a)(2)). 

148 Powerex at 8. 

149 See, e.g., EEI at 19; EPSA at 37-38; Reliant at 5-6; SoCal Edison at 9. 
Docket No. RM04-7-000 94 

technical operations may be outsourced without conferring an ability to control price 

or output, so that the outsourcing is not of particular competitive significance. If, 

however, an entity could determine or significantly influence bids or output, then it 

would be reasonable for the Commission to place a burden on that entity to 

demonstrate that it is not in a position to benefit from a possible exercise of market 

power. NYISO claims that if more than one party is in a position to exercise control 

over bids or output, then both such parties should have the burden of rebutting this 

presumption. NASUCA concurs.150 Because of the fact-specific nature of these 

issues, the NYISO endorses the Commission’s proposal to allow individual sellers to 

rebut the presumption on the basis of their particular facts and circumstances.151

172. Westar argues determinations of control over generating plants are essential 

elements of the negotiated risk sharing arrangement in virtually every energy 

management contract and that the Commission should not change its precedent 

absent clear evidence of market uncertainty or a finding that the established 

guidelines are inappropriate.152 

 150 NASUCA reply comments at 15 (quoting NYISO at 6). 

151 NYISO at 5-6. 

152 See, e.g., Westar at 27-28. 
Docket No. RM04-7-000 95 

173. Southern suggests that the approach taken in Order No. 652, where the 

Commission provided an illustrative list of contracts and arrangements that involve 

changes of control, is reasonable.153

Commission Determination

174. As discussed in the sections that follow, the Commission concludes 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 electric industry remains a dynamic, developing industry, and no 

bright-line standard will encompass all relevant factors and possibilities that may 

occur now or in the future. If a seller has control over certain capacity such that the 

seller can affect the ability of the capacity to reach the relevant market, then that 

capacity should be attributed to the seller when performing the generation market 

power screens.154

175. Though we note the widespread support among commenters for the 

Commission’s effort to provide greater clarity and certainty regarding the 

determination of control, there are differing points of view as to what circumstances 

or combination of circumstances convey control. These circumstances vary 

depending on the attributes of the contract, the market and the market participants. 

 153 Southern at 23 (citing Order No. 652, FERC Stats. & Regs. 

RegulationsPreambles 2001-2005 ¶ 31,175 at P 83.

154 NOPR at P 47-48 (citing July 8 Order, 108 FERC ¶ 61,026 at P 65.) 
Docket No. RM04-7-000 96 

Thus, we conclude that it would be inappropriate to make a generic finding or generic 

presumption of control, but rather that it is appropriate to continue making our 

determinations of control on a fact-specific basis. 

176. We agree with commenters such as Powerex and Westar that the Commission 

should rely on a set of principles or guidelines to determine what constitutes control. 

This has been our historical approach and we find no compelling reason to modify 

our approach at this time. Accordingly, as suggested by EEI, EPSA and others, we 

will consider the totality of circumstances and attach the presumption of control when 

an entity can affect the ability of capacity to reach the market. Our guiding principle 

is that an entity controls the facilities when it controls the decision-making over sales 

of electric energy, including discretion as to how and when power generated by these 

facilities will be sold.155 

177. With regard to suggestions that we require all relevant contracts to be filed for 

review and determination by the Commission as to which entity controls a particular 

asset (e.g., with an initial application, updated market power analysis, or change in 

status filing), we will not adopt this suggestion. Under section 205 of the FPA, the 

Commission may require any contracts that affect or relate to jurisdictional rates or 

services to be filed. However, the Commission uses a rule of reason with respect to 

the scope of contracts that must be filed and does not require as a matter of routine 

 155 Order No. 652, FERC Stats. & Regs. Regulations Preambles 2001-2005 ¶ 

31,175 at P 18. 
Docket No. RM04-7-000 97 

that all such contracts be submitted to the Commission for review. Our historical 

practice has been to place on the filing party the burden of determining which entity 

controls an asset. As discussed below, we will require a seller to make an affirmative 

statement as to whether a contractual arrangement transfers control and to identify the 

party or parties it believes controls the generation facility. Nevertheless, the 

Commission retains the right at the Commission’s discretion to request the seller to 

submit a copy of the underlying agreement(s) and any relevant supporting 

documentation. 

ii. Rebuttable Presumption Regarding Ownership

Comments

178. MidAmerican argues that the Commission should adopt a presumption of 

control based on physical ownership of the generation (as adjusted for long-term sales 

or purchase power agreements). MidAmerican states that it is physical ownership 

that typically determines which entity controls the output of the generation and 

determines its ability to reach relevant markets. While many entities may have partial 

control over a unit’s output, it is the owner that is most likely to affect market 

power.156

179. Morgan Stanley states that as a general rule, when assessing market power, the 

Commission should specifically adopt a rebuttable presumption that the entity that 

 156 MidAmerican at 4 and 6-7. 
Docket No. RM04-7-000 98 

owns157 the generation asset controls the generation capacity.158 This presumption 

would shift if the asset owner relinquishes to a third-party the final decision-making 

authority over whether a unit runs (i.e., if the third-party can trump the asset owner's 

dispatch instruction, then the third-party has control over whether the capacity 

reaches the market). Morgan Stanley states that such final decision-making authority 

would include authority to schedule outages.159

180. FirstEnergy proposes that where a generation owner is a public utility under 

Part II of the FPA, the Commission should adopt a rebuttable presumption that such 

 157 Morgan Stanley states that consistent with Commission precedent, the 

generation owner would not include entities that have a “passive” ownership interest 

where, due to the nature of the interest, the interest holder does not have the right or 

ability to direct, manage, or control the day-to-day operations of jurisdictional facilities. 

Citing D.E. Shaw, 102 FERC ¶ 61,265, at 61,823 (2003) (noting that passive owners may 

possess certain consent or veto rights over fundamental business decisions in order to 

preserve their financial investment, including, but not limited to, the right to grant or 

withhold consent regarding: (1) material amendments to an LLC agreement under certain, 

specified circumstances; (2) issuance of new interests senior to the then-existing member 

interests in an LLC entity; (3) adoption of a new LLC agreement (or other operative or 

constituent documents) in connection with mergers, consolidations, combinations, or 

conversions in certain instances; (4) appointment of a liquidator (but only if the managing 

member of the LLC does not appoint one); and (5) assignment of investment advisory 

contracts under certain circumstances); GridFlorida LLC, 94 FERC ¶ 61,363, at 62,332 

(2001). 

158 Morgan Stanley would define final control over physical output as resting with 

the market participant that, under normal operating conditions, can override all other 

entities on the decision of whether to dispatch the generation unit or that can otherwise 

hold an entity accountable for a dispatch decision. It submits that such authority typically 

rests with the generation owner. Morgan Stanley at 4. 

159 See also Financial Companies at 6. 
Docket No. RM04-7-000 99 

owner controls all of the generating capacity that it owns.160 FirstEnergy asserts that 

even where another entity is responsible for day-to-day operation of a generating unit, 

the generation owner generally will retain managerial discretion over the operation of 

the unit and over the sale of power from that unit into the market.161

181. A number of commenters argue that jointly-owned plants should be assigned 

based on percentage of ownership.162 For example, Pinnacle states that, in the 

Southwest region, the joint ownership of base-load generating plants is the norm, and 

there is typically one party that has operational control over the facility. However, if 

the Commission refines the criteria for assigning generation to an entity based on 

 160 FirstEnergy similarly argues that there should be a rebuttable presumption that 

generation capacity purchased by an electric utility from a Qualified Facility (“QF”) as a 

result of a mandatory power purchase requirement established pursuant to the Public 

Utility Regulatory Policies Act (PURPA), 16 U.S.C. 824a-3(a), will be attributed to the 

seller rather than the purchaser. FirstEnergy argues that in many cases, the purchaser has 

little, if any, discretion over the dispatch of such units or the price at which energy is 

purchased. 

161 In its reply comments, PPL disagrees stating that, in assessing the entity that 

should be deemed to control capacity, whether assessing a contract to sell capacity or an 

asset management contract, the Commission should ask which party can benefit from an 

exercise of market power with regard to the supply at issue. PPL asserts that the flaw in 

FirstEnergy’s proposal is that when a firm obligation to sell power is in effect, the seller 

cannot benefit from exercising market power with regard to the MWs sold pursuant to 

that firm obligation. Likewise, a buyer that can count on delivery of firm power is the 

ultimate decision-maker as to its resale. The seller will have to buy replacement power 

(at the prevailing market rate) if its expected source is not available, and therefore cannot 

benefit from withholding that amount of power. Thus such an approach would overstate 

one counter party’s controlled capacity and understate the other’s. PPL reply comments 

at 11-13. 

162 See, e,g., Duke at 25. 
Docket No. RM04-7-000 100 

factors such as directing plant outages, fuel procurement, and plant operations (or 

similar factors), there is concern that jointly-owned generation may be attributed in 

whole to each of the owners if there is joint decision-making on such factors (e.g., if 

such decisions are made through a consortium of utilities forming a plant’s joint 

operating committee) and result in unintentional double counting. Pinnacle also 

raises a concern that where joint plant owners appoint one of the joint owners to 

operate the plant, the entire plant will be attributed to the operator, rather than being 

attributed to each of the joint owners in shares. According to Pinnacle, the Final Rule 

should clarify that capacity of jointly-owned plants operated by one of the owners 

will be assigned to each joint owner based on its percentage interest.163 Pinnacle 

states that the current rules under the 

interim screens with regard to assigning generating capacity to an entity appear to be 

workable. 164 

182. Many other commenters raise concerns about double counting in cases of 

shared control.165 For example, with regard to shared facilities, FirstEnergy states 

 163 Pinnacle at 4-5. See also MidAmerican at 6-7. 

164 EEI agrees that in such a situation, if both owners have input on how and where 

the capacity is sold, then the asset should be allocated based on ownership percentages. 

EEI at 20. 

165 See, e.g., Alliance Power Marketing reply comments at 8-9; Constellation at 6; 

MidAmerican at 6; PG&E at 8. 
Docket No. RM04-7-000 101 

that control of the plant should be attributed to the entity that is deemed to own the 

energy supplied from the plant. FirstEnergy offers that, if circumstances arise in 

which discretion over plant output is shared among more than one party, the 

Commission should permit the affected parties to resolve between themselves the 

entity to which capacity available in the unit will be attributed. FirstEnergy 

concludes that if the Commission adopts a regional approach to updated market 

power analyses, the Commission will be able to monitor those circumstances in 

which specified generation capacity is attributed to the wrong market participant.166

Commission Determination

183. With regard to the suggestion that we adopt a rebuttable presumption that the 

owner of the facility controls the facility, our historical approach has been that the 

owner of a facility is presumed to have control of the facility unless such control has 

been transferred to another party by virtue of a contractual agreement. We will adopt 

that approach. Accordingly, while we do not specifically adopt a rebuttable 

presumption that the owners control the facility, we will continue our practice of 

assigning control to the owner absent a contractual agreement transferring such 

control. 

184. We note that the Commission has developed precedent regarding the 

contractual arrangements that can transfer control. In these cases, the Commission 

 166 FirstEnergy at 7-8. 
Docket No. RM04-7-000 102 

has stated that control refers to arrangements, contractual or otherwise, that confer 

control of generation or transmission facilities just as effectively as they could 

through ownership.167 The capacity associated with contracts that confer operational 

control to an entity other than the owner thus must be assigned to the entity 

exercising control over that facility, rather than to the entity that is the legal owner of 

the facility, when performing the generation market power screens.168

185. With regard to FirstEnergy’s suggestion that the affected parties make a 

determination regarding the entity to whom capacity available in the generating unit 

will be attributed in order to avoid any unwarranted double counting in the attribution 

of control,169 the Commission agrees that this is a constructive and appropriate 

 167 Citizens Power and Light Corp., 48 FERC ¶ 61,210 at 61,777 (1989). See also

Bechtel Power Corp., 60 FERC ¶ 61,156 (1992) (finding that an entity that was 

contractually engaged to provide operation and maintenance services was not an 

“operator” of jurisdictional facilities because the entity did not “operate” the facilities at 

issue but rather, in essence, was functioning merely as the owner’s agent with respect to 

the operation of the jurisdictional facilities); D.E. Shaw, 102 FERC ¶ 61,265 at P 33-36 

(finding that a power marketer’s “investment adviser” affiliate was a public utility where 

it had sole discretion to determine the trades to be entered into by the power marketer, as 

well as the power to execute the contracts, and therefore operated jurisdictional facilities 

rather than acted as merely an agent of the owner); R.W. Beck , 109 FERC ¶ 61,315 at P 

15 (finding R.W. Beck Plant Management, Ltd. (Beck) was a public utility subject to the 

FPA in connection with its activities as manager of public utility Central Mississippi 

Generating Company, LLC because Beck effectively governed the physical operation of 

certain jurisdictional transmission and interconnection facilities and served as the 

decision-maker in determining sales of wholesale power).

168 NOPR at P 47-48 (citing July 8 Order, 108 FERC ¶ 61,026 at P 65). 

169 FirstEnergy at 7. 
Docket No. RM04-7-000 103 

approach. However, although we wish to avoid double counting as a general matter, 

the Commission will not rule out the possibility of double counting in circumstances 

where it is unclear what entity has control. For example, if different parties could 

control dispatch decisions under various circumstances, to err on the conservative 

side, the Commission may attribute generation to more than one seller for the 

purposes of the horizontal analysis. 

186. To determine whether there are contracts transferring control to a seller 

seeking market-based rate authority, similar to the requirements for change in status 

filings,170 the Commission will require sellers when filing an application for marketbased rate authority or an updated market power analysis, to make an affirmative 

statement as to whether any contractual arrangements result in the transfer of control 

of any assets, including whether the seller is conferring control to another entity or 

obtaining control of another entity’s assets. Moreover, in addition to requiring such 

affirmative statements as to whether any contractual arrangements result in the 

transfer of control of any assets,171 the Commission will require sellers, when filing 

 170 See Calpine Energy Services, L.P., 113 FERC ¶ 61,158 at P 13 (2005) (sellers 

making a change in status filing to report an energy management agreement are required 

to make an affirmative statement in their filing as to whether the agreement at issue 

transfers control of any assets and whether the agreement results in any material effect on 

the conditions that the Commission relied upon in the grant of their market-based rate 

authority). 

171 Such a statement should include contracts that transfer control to another party 

as well as contracts that transfer control to the seller. 
Docket No. RM04-7-000 104 

an application for market-based rates, an updated market power analysis, or a 

required change in status report with regard to generation, to specify the party or 

parties they believe has control of the generation facility and to what extent each 

party holds control. 

187. We understand that affected parties may hold differing views as to the extent 

to which control is held by the parties. Accordingly, we also will require that a seller 

making such an affirmative statement seek a "letter of concurrence" from other 

affected parties identifying the degree to which each party controls a facility and 

submit these letters with its filing. Absent agreement between the parties involved, or 

where the Commission has additional concerns despite such agreement, the 

Commission will request additional information which may include, but not be 

limited to, any applicable contract so that we can make a determination as to which 

seller or sellers have control. 

188. With regard to Pinnacle's concern regarding joint plant owners appointing one 

of the joint owners to operate the plant, we reserve judgment as a general matter. 

However, we understand that there may be situations where a jointly-owned 

generation facility is operated by one of the joint-owners for the benefit of and on 

behalf of all of the joint-owners. Under these circumstances, it may be reasonable to 

allocate capacity based on ownership percentages. Such a determination should be 

made on a case-specific basis. 

189. We remind sellers that in performing the horizontal market power analysis all 

capacity owned or controlled by the seller must be accounted for. In this regard, we 
Docket No. RM04-7-000 105 

expect that sellers, in performing such market power analyses, will clearly identify all 

assets for which they have control, or relinquished control, through contract. 

iii. Energy Management Agreements

Comments

190. Most commenters state that energy management agreements and the functions 

listed in the NOPR (directing plant outages, fuel procurement, plant operations, 

energy and capacity sales, and/or credit and liquidity decisions) should not be 

presumed to convey control. Financial Companies state that a generic presumption of 

control by energy managers will “chill a seller's willingness to provide energy 

management services.”172 Others suggest that the Commission should not adopt such 

a presumption and, in the alternative, should consider the specific aspects of an 

agreement. Additionally, some commenters request clarification on contract terms 

that are widely used in energy management agreements and may or may not convey 

control. 

191. Sempra and financial entities argue that the Commission should not adopt a 

presumption that energy management agreements confer control over generating 

capacity.173 They state that energy management and comparable agreements do not 

 172 Financial Companies at 9. 

173 Sempra at 12-13; Morgan Stanley at 5-6; Financial Companies at 7-8 and reply 

comments at 3-5. 
Docket No. RM04-7-000 106 

convey unlimited discretion and should not shift the presumption of control away 

from the entity that has final authority to dispatch the physical output of the plant. 

192. Constellation agrees that the Commission should focus on whether an energy 

manager may make decisions about physical operation without final authority from a 

plant owner.174 

193. Westar expresses concerns that the NOPR’s invitation to consider ultimate 

control to reside with any entity that has some discretion over the output of a plant 

would invite confusion and undercut the Commission’s declared objective to provide 

greater certainty and clarity in this area.175 Alliance Power Marketing also expresses 

concern that a presumption that some discretion constitutes control will discourage 

innovation in the market, particularly with regard to option contracts and third-party 

arrangements.176

194. Alliance Power Marketing differentiates between asset/energy managers 

acting purely as agents and those that do not meet the legal definition of agents, 

suggesting that a market facilitator meeting the criteria of an agent should be exempt 

from attribution of control. The agent criteria identified by Alliance Power 

Marketing are: (1) the entity holds legal indicia of an agent’s role; (2) the entity is 

 174 Constellation at 18. 

175 Westar at 28. 

176 Alliance Power Marketing reply comments at 8-9. 
Docket No. RM04-7-000 107 

neither a market participant nor an affiliate of a market participant; (3) the entity has 

limited, if any, financial stake in power market outcomes; and (4) the entity is subject 

to supervision or control in its activities on behalf of its principals.177 Alliance Power 

Marketing submits that agents do not control generation if they are acting on behalf 

of their clients, do not assume the risk of transactions, and never take title to power. 

Constellation notes that the Commission has previously recognized that an agent who 

is acting subject to the direction of the owner should be not found to have control of a 

facility.178 

195. Financial Companies disagree with Alliance Power Marketing’s 

differentiation. They caution the Commission about imposing overly restrictive 

limitations on which entities qualify as agents or independent contractors and 

recommend that the Commission reject Alliance Power Marketing’s proposal and 

suggest instead that ultimate decision-making authority is most relevant whether or 

not an agent is or is not a market participant.179 

196. In contrast, NASUCA submits that the Commission should presume that 

energy management agreements convey control when energy managers can control 

 177 Id. at 10-11. 

178 Constellation at 20 (citing Bechtel Power Corp., 60 FERC ¶ 61,156 at 61,572 

(1992)). 

179 Financial Companies reply comments at 3-4. 
Docket No. RM04-7-000 108 

generation output or the price or quantity of service offered.180 Even more 

specifically, NASUCA recommends that the Commission reject formulations that 

would cloak market power of energy managers who control or affect electricity 

pricing, or the pricing of critical cost components such as fuel. Instead the 

Commission should adopt a rule that at a minimum encompasses the exercise of 

control over prices, bids, or output, including the ability to affect the cost of fuel and 

other inputs to generation.181

Commission Determination

197. After careful consideration of the comments, the Commission will not adopt a 

presumption of control regarding energy management agreements or the functions 

outlined in the NOPR.182 We agree with commenters that energy management and 

comparable agreements do not necessarily convey unlimited discretion and control 

away from the entity that owns the plant. In this regard, as noted above, it is the 

totality of the circumstances that will determine which entity controls a specific asset. 

198. Further, the Commission will not adopt a presumption of control in the case of 

shared discretion over the output and physical operation of a plant. The Commission 

is aware that varying degrees of discretion may be shared in some cases, and believes 

that the determination of control in these cases is best addressed on a fact-specific 

 180 NASUCA reply comments at 13 (citing NYISO at 6). 

181 Id. at 15. 

182 NOPR at P 49. 
Docket No. RM04-7-000 109 

basis. As noted by Sempra, there may always be an element of discretion associated 

with the implementation of instructions or guidelines included in energy management 

agreements.183 

199. With regard to Alliance Power Marketing’s differentiation between 

asset/energy managers acting purely as agents and those that do not meet the legal 

definition of agents, and suggestion that “a market facilitator meeting the criteria of 

an agent should be exempt from attribution of control,” we find this differentiation in 

and of itself not determinative. Instead, consistent with our conclusion that the 

determination of control is appropriately based on a review of the totality of the 

circumstances on a fact-specific basis such that no single factor or factors necessarily 

results in control, it is the combination of the rights conveyed that determine control, 

not whether an entity considers itself to be an agent and not a market participant. 

iv. Specific Functions and Contract Terms

Comments

200. With regard to specific functions and specific contract terms, many 

commenters do not believe that functions such as directing plant outages, fuel 

procurement, plant operations, energy and capacity sales, and credit and liquidity 

merit a presumption of control. 

 183 Sempra at 13. 
Docket No. RM04-7-000 110 

201. NYISO and FirstEnergy both suggest that the functions listed in the NOPR 

may be outsourced without conveying ultimate control. According to EEI, the list of 

functions described in the NOPR would not provide greater guidance.184 Rather, EEI 

believes a focus on the ability to withhold will be more effective than establishing 

presumptions based on the functions described in the NOPR. In particular, EEI 

argues that establishing presumptions for these individual functions would be 

difficult, because often it would be a combination of various functions that would 

result in the ability to affect bringing the capacity to market.185

202. Duke believes that the Commission should avoid simplistic presumptions as to 

what constitutes control over resources for market power purposes and how and when 

specific generation should be imputed to market participants for purposes of the 

screen analysis. Duke argues that in a market power context, such determinations 

should be fact-driven and based on a pragmatic assessment of which party has the 

ability to withhold a specific amount of capacity from the market. For example, the 

Commission should not automatically impute control over capacity based solely on 

contract language that appears to convey some element of discretion over unit 

operation to a particular party, notwithstanding the absence of any real world ability 

for that entity to withhold that capacity from the market. Duke states that the 

 184 EEI reply comments at 25. 

185 EEI at 22. 
Docket No. RM04-7-000 111 

Commission should recognize that the ability to economically or physically withhold 

output from the market rests with the party that makes the final determination of 

whether generation (energy and/or capacity) will be offered into the market. Even a 

purchaser with dispatch rights may not have the ability to withhold supply, if the 

capacity owner has the right to schedule energy when the purchaser chooses not to do 

so. Similarly, a party with a contractual right to capacity (as opposed to energy), 

even with a call option for energy priced at market, does not have operational control 

over energy. Duke states that any contract in which rights to the energy ultimately 

revert to the owner/operator or for which energy is available only at a market price 

leaves control in the hands of the owner/operator. According to Duke, there should 

not be a blanket presumption that certain types of commercial arrangements or 

contractual language imply control in all instances.186

203. PG&E argues that any presumptions about control over generation should be 

based on whether a seller controls the dispatch of energy (i.e., can affect the ability of 

the capacity to reach the relevant market). This general presumption should cover all 

types of transactions and business arrangements, rather than trying to address every 

possible function. Such an approach will be more effective than establishing 

presumptions based on individual functions, as various factors may intersect or 

 186 Duke at 24-25. 
Docket No. RM04-7-000 112 

combine to provide this control. Relevant factors include authority over the use or 

provision of fuel to the plant.187

204. PPL expresses concern that any arrangement in which a gas supplier could 

receive the output of a gas-fired generator as payment for the gas it supplies to the 

generator, if it is the only supplier to that generator, may convey control. PG&E 

appears to agree, stating that authority over the use or provision of fuel to the plant is 

a relevant factor with regard to control.188 

205. EEI also appears to agree that fuel ownership may result in a change in control 

of plant output when, in the context of what triggers a change in status filing, it states: 

“The Commission should continue the current policy that changes in the ownership of 

fuel supplies in and of themselves need not be reported. Only if the change in 

ownership of inputs results in a change of control of the output of the plant should a 

change in status filing be required. If a public utility acquires fuel supplies, there is 

no need to notify the Commission, unless the business structure, like a tolling 

agreement, actually results in discretion over the plant output.”189

206. Sempra states that the Commission has generally treated energy management 

agreements as tolling agreements and requests that the Commission acknowledge the 

 187 PG&E at 7. 

188 Id. 

189 EEI at 21. 
Docket No. RM04-7-000 113 

differences between the two.190 APPA/TAPS state that particularly under tolling 

arrangements, while the supplier of fuel may not be operating the plant, it controls the 

plants’ production of energy for sale, thus affecting market outcomes.191 

Constellation argues that plant operations and sales of output are functions that may 

convey control, but notes that the variety of case-specific facts limits the benefit of a 

blanket presumption of control. 

207. Commenters also request that the Commission provide guidance regarding 

other contract types and terminology such as call option contracts (with liquidated 

damages), contracts that allow variance in volume or delivery point, QF contracts, 

RMR contracts, capacity contracts, and load obligations.192 

208. Finally, EEI seeks clarification that energy only contracts over 100 MW for a 

term greater than one year that do not include rights to specific capacity are one type 

of contract that does not transfer control.

 190 Sempra at 11-12. According to Sempra, under energy management 

agreements, energy managers typically sell power according to instructions or guidelines 

provided by the owner, and the energy manager is compensated on a fee-basis. Sempra 

states that in the case of tolling agreements, the tolling party generally has complete 

discretion over sales of output and assumes risk of sales transactions with the owner 

typically receiving a flat compensation and retaining authority over when to operate the 

facility. 

191 APPA/TAPS at 90. 

192 See, e.g., EEI reply comments at 25; EPSA at 38; Financial Companies reply 

comments at 7; FirstEnergy at 6; Reliant at 5; Duke at 25; PG&E at 7-8; PowerEx at 9-

13; PPL at 13; PPL reply comments at 13; PSEG at 13 and 18; Sempra reply comments at 

4; SoCal Edison at 10; Southern Company at 23. 
Docket No. RM04-7-000 114 

Commission Determination

209. In Order No. 652, the Commission provided a non-exclusive, illustrative list of 

contractual arrangements that are subject to the change in status filing requirement. 

The list includes agreements that relate to “operation (including scheduling and 

dispatch), maintenance, fuel supply, risk management, and marketing [of plant 

output]. These types of arrangements have in some cases also been referred to as 

energy management agreements, asset management agreements, tolling agreements, 

and scheduling and dispatching agreements.”193 The Commission clarifies that the 

illustrative list included in Order No. 652 provides guidance with regard to new 

applications for market-based rate authority and updated market power analyses as 

well as to change in status filings. 

210. With respect to requests for clarification of whether certain contractual 

arrangements transfer control (such as call option contracts; liquidated damages 

contracts; contracts that allow variance in volume, source, or delivery point; QF 

contracts; RMR contracts; capacity contracts; and load obligations), for the reasons 

stated above, the Commission declines to address particular contractual terminology 

in isolation. The label placed on a specific contract does not determine whether it 

conveys control. Such determination necessarily must be made on a fact-specific 

basis. 

 193 Order No. 652, FERC Stats. & Regs. Regulations Preamles 2001-2005 

¶ 31,175 at P 83. 
Docket No. RM04-7-000 115 

211. Similarly, with regard to EEI’s request for clarification that energy-only 

contracts over 100 MW for a term greater than one year that do not include rights to 

specific capacity are one type of contract that does not transfer control, for the 

reasons stated above, the Commission declines to address such a specific contractual 

arrangement generically. 

b. Requirement for Sellers to have a Rate on File

Comments

212. Alliance Power Marketing questions the Commission’s proposal to clarify that 

any entity that controls generation from which jurisdictional sales are made is 

required to have a rate on file. Alliance Power Marketing believes that this proposal 

appears more akin to an inquiry than a Proposed Rulemaking.194 Pinnacle requests 

clarification as to whether a non-jurisdictional entity is required to have a rate on file 

if that entity is the operator of a facility jointly-owned by jurisdictional and nonjurisdictional entities.195 

Commission Determination

213. With regard to comments concerning the Commission’s statement in the 

NOPR as to the need for an entity that controls generation from which jurisdictional 

power sales are made to have a rate on file, the Commission is reiterating, not 

 194 Alliance Power Marketing at 16. 

195 Pinnacle at 5. 
Docket No. RM04-7-000 116 

modifying, the existing obligation to make rate filings. Under section 205 of the 

FPA, 

every public utility shall file with the Commission... schedules 

showing all rates and charges for any... sale subject to the 

jurisdiction of the Commission, and the classifications, practices, 

and regulations affecting such rates and charges, together with all 

contracts which in any manner affect or relate to such rates, charges, 

classifications, and services.[196] 

Part II of the FPA defines a public utility as “any person who owns or operates facilities 

subject to the jurisdiction of the Commission.”197 Any entity not otherwise exempted 

from the Commission’s regulations that owns or operates jurisdictional facilities from 

which jurisdictional power sales are made is a public utility required to have a rate on file 

with the Commission, unless the Commission has determined that such an entity does not 

in fact have “control” over the jurisdictional facilities sufficient to deem it a public utility 

(for example, if its ownership is passive, or its operation of facilities is as an agent subject 

to the control of the owner of the facilities). For any entity that is a public utility, if its 

rate authority is market-based, then it is subject to the conditions of authorization by the 

Commission (including the requirement to demonstrate lack of generation market power 

by the submission of market screens as spelled out in the horizontal market power section 

of this Final Rule). If an entity is a public utility and making jurisdictional sales without 

 196 16 U.S.C. 824d(c). 

197 16 U.S.C. 824(e). 
Docket No. RM04-7-000 117 

having a rate on file, those sales may be subject to refund, and the entity may be subject 

to a civil penalty.198 

214. In response to Pinnacle, we clarify that if an entity has control of a 

jurisdictional facility and that entity is making jurisdictional sales, it would be a 

public utility subject to the jurisdiction of the Commission and would be required to 

have a rate on file with the Commission. However, if an entity is specifically 

exempted from the Commission’s regulation pursuant to FPA section 201(f), it would 

not be considered a public utility under the FPA and, accordingly, would not be 

required to have a rate on file. 

7. Relevant Geographic Market

a. Default Relevant Geographic Market

Commission Proposal

215. In the NOPR, the Commission proposed to continue to use its historical 

approach with regard to the relevant geographic market. The Commission stated that 

the default relevant geographic market is the control area where the generation owned 

or controlled by the seller is physically located and each of the control areas directly 

interconnected to that control area (with the exception of a generator interconnecting 

to a non-affiliate owned or controlled transmission system, in which case the relevant 

market is only the control area in which the seller is located). The Commission also 

 198 Vermont Electric Cooperative, Inc., 108 FERC ¶ 61,223 (2004), order on reh’g, 

110 FERC ¶ 61,232 (2005). 
Docket No. RM04-7-000 118 

proposed to continue to designate RTOs/ISOs with sufficient market structure and a 

single energy market in which a seller is located and is a member as the default 

relevant geographic market. In such circumstances the Commission would not 

require sellers to consider the first-tier markets to such RTOs/ISOs as being part of 

the default relevant geographic markets. In addition, the Commission noted in the 

NOPR that its experience with corporate mergers and acquisitions indicates that the 

same RTOs/ISOs that the Commission has identified as meeting the criteria for being 

considered a single market for purposes of performing the generation market power 

screens have, at times, been divided into smaller submarkets for study purposes 

because frequently binding transmission constraints prevent some potential suppliers 

from selling into the destination market. Therefore, the Commission sought comment 

on its approach under the market-based rate program of considering the entire 

geographic region under control of the RTO/ISO, with a sufficient market structure 

and a single energy market, as the default relevant market. We asked whether the 

Commission should continue its approach of considering the entire geographic region 

as the default market for purposes of the indicative screens but consider RTO/ISO 

submarkets for purposes of the DPT. 

Comments

216. With regard to the RTO/ISO market, several commenters state that, based on 

all the protections associated with structured RTO/ISO markets with Commissionapproved market monitoring and mitigation, the Commission should continue its 

current approach of allowing the entire geographic region of an RTO/ISO to be the 
Docket No. RM04-7-000 119 

default relevant market for the horizontal market power analysis.199 They state that 

retention of this standard will simplify preparation of market power analyses by 

sellers within qualified RTOs. 

217. Several commenters as well urge the Commission not to consider RTO or ISO 

submarkets. Sempra states that it recognizes that RTOs are at times divided into 

submarkets, such as for purposes relating to corporate merger and acquisition 

analyses, but it submits that the Commission should not consider RTO or ISO 

submarkets when conducting a market power analysis. Sempra states that the use of 

submarkets will result in uncertainty, confusion, and increased litigation as to the 

geographic boundaries of the “right” submarket that should be analyzed. According 

to Sempra, sellers that operate in RTO and ISO markets currently know with certainty 

the relevant geographic market for purposes of regulatory obligations such as 

reporting relevant changes in status, and the use of submarkets will eliminate that 

certainty and will open the door to competing definitions of submarkets. Sempra 

states that the existence of internal transmission constraints does not justify breaking 

up RTOs and ISOs into submarkets for purposes of the Commission’s market power 

analysis. Sempra states that notably, only RTOs and ISOs with sufficient market 

structure and a single energy market can be used as default geographic markets. 

 199 Wisconsin Electric at 5-7, FirstEnergy at 8-9, PG&E at 8-9, Xcel at 13-14, and 

Allegheny Energy Companies at 4-6. In addition, Ameren states that the Commission 

also should consider expanding the default geographic region beyond the footprint of a 

single RTO/ISO where contiguous RTOs/ISOs have a common market (Amerem at 4-5). 
Docket No. RM04-7-000 120 

These attributes allow RTOs, ISOs, and their members to adopt mechanisms, 

including local markets or mitigation, that address potential concerns about local 

market power resulting from transmission constraints.200

218. Similarly, EPSA, PG&E, PPL, ISO-NE, CAISO and NYISO support use of 

the entire RTO/ISO as the relevant geographic market where the RTOs/ISOs operate 

a single centralized market and generally where there are measures for monitoring 

and oversight.201 

219. In addition, EPSA offers that changes to the size of markets can be addressed 

on a case-by-case basis by sellers or when an intervenor presents specific evidence 

supporting reduction of the relevant geographic market.202 PG&E states that in the 

case of a single control area like CAISO, there is little rationale or basis to determine 

how to subdivide a control area. Where there may be intermittent congestion within 

certain areas, the control area as a whole has regional planning and monitoring, 

avoiding the need to subdivide. In addition, the empirical fact that most sellers make 

no effort to justify an alternate geographic market – whether larger or smaller – 

supports the control area as the appropriate measure.203

 200 Sempra reply comments at 1-3. 

201 EPSA at 11-12, PG&E at 8-9, and NYISO at 1-2. 

202 EPSA at 11-12. 

203 PG&E at 8-9. 
Docket No. RM04-7-000 121 

220. PPL states that if the Commission were to impose stringent market power tests 

based upon temporary transmission limitations beyond generators’ control (e.g., 

infrequent intra-control area transmission system limitations), the Commission could 

make worse an already tenuous financial situation for existing generators in such 

areas and continue to deter new generation investment. Defining a geographic 

market smaller than a control area may lead to high failure rates of the screens. PPL 

states that associated loss of market-based rate authority (if that is the remedy 

imposed by the Commission) could precipitate economic retirements of those needed 

generators. 

221. Finally, Ameren suggests that, for purposes of the DPT, the relevant 

geographic market should be the applicable RTO/ISO footprint, just as it is for 

purposes of the indicative screens, unless the Commission already has found the 

existence of a submarket in the relevant portion of the RTO/ISO. In such cases, the 

Commission should give due consideration to any existing Commission-approved 

market monitoring and mitigation regime already in place within the RTO/ISO that 

provides for mitigation of the submarket. If the relevant RTO/ISO does not have in 

place a mitigation program for an identified submarket, the Commission may then 

consider appropriate submarket-specific mitigation in connection with granting 

market-based rate authorization. 

222. On the other side of the issue, several commenters urge the Commission to 

consider internal transmission constraints and possible submarkets within 

RTOs/ISOs. The California Board proposes that the Commission permit RTOs to 
Docket No. RM04-7-000 122 

identify submarkets within their control area, as needed, to help determine possible 

local market power. The California Board states that if the Commission develops or 

approves criteria which sellers may use to expand their geographic market, then the 

same criteria must be applicable in RTOs to limit the size of a geographic market. 

The New Jersey Board states that intervenors should be allowed to present evidence 

that the relevant geographic market is smaller (or larger) than the default RTO/ISO 

market and states that evidence of binding transmission constraints is relevant when 

examining horizontal market power.204 

223. State AGs and Advocates state that almost any large default geographic 

market will have many transmission-constrained areas (load pockets) within it and 

that the Commission must require applicants for market-based rate authority to do a 

proper analysis of the degree of market power that is likely to be exercised by all 

sellers, including the applicants, in all relevant load pockets or transmissionconstrained regions or subregions in which the sellers control generation capacity. 

They state that all load pockets must be considered as appropriate geographic markets 

whenever they exist. 

224. APPA/TAPS state that the presumption of the RTO footprint as the default 

geographic market must be truly rebuttable, including rebuttals based upon evidence 

 204 New Jersey Board at 3-4. 
Docket No. RM04-7-000 123 

that the RTO itself treats an area as a separate market.205 APPA/TAPS state that in 

practice, however, the presumption appears to be irrebuttable. They argue that if 

known load pockets such as WUMS (or, for example, the Delmarva Peninsula, 

Southwest Connecticut, or the City of San Francisco, among others) do not rebut the 

geographic market presumption, the rebuttable presumption effectively becomes 

irrebuttable. APPA/TAPS recommend that in advance of each region’s market-based 

rate review, RTOs should provide market participants with transmission studies that 

reveal where binding transmission constraints arise so that those data can be used in 

addressing the proper relevant geographic market. In addition, APPA/TAPS state 

that in the § 203 context, the Commission has correctly found that transmission 

constraints lead to distinct geographic markets, at least when those constraints are 

binding. They submit that no reasonable basis exists to distinguish between the 

competitive analyses used to establish relevant geographic markets in the section 203 

and the section 205 contexts.206

225. In response to APPA/TAPS, EPSA states that in cases where the Commission 

denied a seller’s argument to change its relevant geographic market, the Commission 

carefully considered the positions of parties advocating a different market and simply 

found their arguments insufficient to warrant a modification to the market 

 205 APPA/TAPS at 56-63. 

206 APPA/TAPS at 61-62. 
Docket No. RM04-7-000 124 

definition.207 EPSA states that it cannot be said that a presumption is irrebuttable 

simply because the Commission has, to date, deferred to RTO/ISO mitigation 

mechanisms to this point. 

226. With regard to non-RTO areas, APPA/TAPS states that while the control area 

provides a reasonable starting point, the Commission’s obligation to base its marketbased rate decision on “empirical proof” requires reliance on specific facts that 

demonstrate whether the relevant geographic market should be the control area, or a 

smaller or larger area. APPA/TAPS further state that, for non-RTO areas, the seller 

should affirmatively address whether the geographic market should default to the 

control area or whether a smaller or larger area is appropriate, and support that result 

with evidence. They add that intervenors should also be allowed to introduce 

evidence regarding the question.208

227. With regard to both RTO/ISO and non-RTO areas, several other commenters 

urge the Commission to consider changing its existing policy on the default 

geographic market. State AGs and Advocates state that the best policy would be to 

have no “default” market criteria, but to have each applicant for market-based rates 

determine on an analytical basis what market area makes the most sense for its 

 207 EPSA reply comments at 9-11, citing APPA/TAPS at 56. 

208 APPA/TAPS at 53-62. 
Docket No. RM04-7-000 125 

circumstances based on the actual transmission constraints that it faces.209 NRECA 

states that using individual control areas or RTOs as the default market for evaluating 

a transmission provider’s market power fails to account for the binding transmission 

constraints and load pockets that have developed within those markets.210 

228. Morgan Stanley states that it supports the Commission's practice of relying on 

control areas and RTO/ISO regions when assessing market power as the default 

markets, but believes the Commission may be missing instances of market power by 

failing to also review known events that can create narrower or broader markets. For 

example, Morgan Stanley states that the Commission acknowledges that binding 

transmission constraints and the existence of load pockets can cause considerable 

market power issues. Therefore, Morgan Stanley asserts that the Commission should 

indeed consider whether a seller may possess the ability to exercise market power in a 

portion of an otherwise competitive market. To enable the Commission to do so, 

sellers should address known constraints in their description of the relevant 

geographic market in their market power filings, particularly in markets for which 

they are the control area operator.211

 209 State AGs and Advocates at 44-48. 

210 NRECA at 12. 

211 Morgan Stanley at 8. 
Docket No. RM04-7-000 126 

229. The California Commission states that while it agrees that designating a 

relevant geographic area will reduce uncertainty to all market participants, 

designation of a static geographic market in a dynamic market may defeat the 

purpose of market certainty and may have unintended adverse consequences over 

time. For example, with the implementation of locational marginal pricing (LMP) in 

the CAISO control area, there will be many submarket areas known as local areas. 

This will trigger “false negatives” (i.e., absence of market power even when there is 

market power) in a control area analysis. A seller may pass both screens and receive 

market-based rate authority when tested against the broader geographic control area, 

such as the entire CAISO control area market. However, the same seller may not 

pass the screens when tested against a particular sub-area or local area. Accordingly, 

the California Commission states that the Commission should be flexible in 

designating geographic areas to determine market power. The Commission should 

designate geographic areas by considering current and reasonably foreseeable 

regional developments, as the Commission currently does in merger cases following 

DOJ/FTC merger guidelines.212 Similarly, the Commission should consider the 

presence or absence of market power due to continuous developments of major 

market events (e.g., area outages, congestion due to new market developments, and 

 212 California Commission at 5-6. 
Docket No. RM04-7-000 127 

the development of load) that can have significant impact as inputs in the market 

power screening calculation. 

230. In contrast, EEI disagrees with those commenters that would require the seller 

in each filing to affirmatively address with supporting evidence whether the 

geographic market should default to the control area or RTO/ISO area. EEI states 

that this requirement would defeat the purpose of having default areas to expedite and 

simplify the market-based rate filing process, noting that it is more efficient for any 

affected party to have the right to challenge the selection of the default market, as 

exists under the proposed regulations.213

Commission Determination

231. The Commission will adopt in this Final Rule 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 balancing authority area214 or the 

RTO/ISO market, as applicable, as the default relevant geographic market.215 

However, where the Commission has made a specific finding that there is a 

 213 EEI reply comments at 26-27. 

214 As we discuss fully below, the Commission will adopt the use of “balancing 

authority area” instead of control area. As a result we use hereon the term balancing 

authority area. In addition, even though commenters use the term “control area” we will 

use the term “balancing authority area” in our response. 

215 In addition, the Commission will continue to require sellers located in and a 

member of an RTO/ISO to consider, as part of the relevant market, only the relevant 

RTO/ISO market and not first-tier markets to the RTO/ISO. 
Docket No. RM04-7-000 128 

submarket within an RTO/ISO, that submarket becomes the default relevant 

geographic market for sellers located within the submarket for purposes of the 

market-based rate analysis. 

232. With regard to traditional (non-RTO/ISO) markets, our default relevant 

geographic market under both indicative screens will be first, the balancing authority 

area where the seller is physically located,216 and second, the markets directly 

interconnected to the seller’s balancing authority area (first-tier balancing authority 

area markets).217 We also clarify that if a transmission-owning Federal power 

marketing agency (e.g., the Tennessee Valley Authority, Bonneville Power 

Administration) is the home or first-tier market to the seller, then that seller must treat 

that Federal power marketing agency’s balancing authority area as a relevant 

geographic market and file market power analysis 

on it just as it would any other relevant market.218 Under the indicative screens, we will 

consider only those supplies that are located in the market being considered (relevant 

 216 For applications by sellers with no physical generation assets (such as power 

marketers) that are affiliated with generation asset owning utilities, we will continue to 

evaluate the affiliate generation owner’s market power when evaluating whether to grant 

market-based rate authority to the power marketer. 

217 Where a generator is interconnecting to a non-affiliate owned or controlled 

transmission system, there is only one relevant market (i.e., the balancing authority area 

in which the generator is located.). 

218 See, e.g., Portland General Electric Co., 111 FERC ¶ 61,151 at P 7 (2005); 

Idaho Power Co., 110 FERC ¶ 61,219 at n.6, P 10 (2005); Florida Power Corp., 

113 FERC ¶ 61,131 at P 17 (2005).
Docket No. RM04-7-000 129 

market) and those in first-tier markets to the relevant market. For non-RTO sellers, we 

adopt a rebuttable presumption that the seller’s balancing authority area and each of its 

neighboring first-tier balancing authority areas are each relevant geographic markets. 

233. Although a number of commenters oppose the use of the balancing authority 

area as the default geographic market in traditional markets, they have submitted no 

compelling evidence that our historical approach is inadequate or insufficient for the 

typical situation. Indeed, using balancing authority areas allows the Commission and 

public to rely on publicly available data provided for balancing authority areas that 

are relevant to the market-based rate analysis discussed herein. These data are 

accurate and generally available. We will, however, continue to allow sellers and 

intervenors to present evidence on a case-by-case basis to show that some other 

geographic market should be considered as the relevant market in a particular case.219

We clarify that the seller must provide the Commission with a study based on the 

default geographic market, and we will allow sellers and intervenors to present 

additional sensitivity runs as part of their market power studies to show that some 

other geographic market should be considered as the relevant market in a particular 

case. This evidence would be an addition to the required study based on the relevant 

geographic market as referred to in this Final Rule. 

 219 We note that the Commission itself may explore whether an alternative 

geographic market is warranted based on the specific facts and circumstances of a given 

case. 
Docket No. RM04-7-000 130 

234. We do not adopt the suggestion by APPA/TAPS that the seller should 

affirmatively address whether the geographic market should default to the balancing 

authority area. We believe that EPSA’s argument that such a requirement would 

defeat the purpose of having default areas and add uncertainty into the market is more 

persuasive. By defining default geographic markets, we provide the industry as much 

certainty as possible while also providing affected parties the right to challenge the 

default geographic market definition and provide evidence in that regard.

235. With regard to RTO/ISO markets, we agree with many commenters that 

RTOs/ISOs with a sufficient market structure and a single energy market with 

Commission-approved market monitoring and mitigation provide strong market 

protections. As a general matter, sellers located in and members of the RTO/ISO 

may consider the geographic region under the control of the RTO/ISO as the default 

relevant geographic market for purposes of completing their horizontal analyses, 

unless the Commission already has found the existence of a submarket. 

236. Where the Commission has made a specific finding that there is a submarket 

within an RTO/ISO, we believe that the market-based rate analysis (both indicative 

screens and DPT) should consider that submarket as the default relevant geographic 

market. This is consistent with how the Commission has treated such submarkets in 

the merger context. For example, in some merger orders, the Commission has found 
Docket No. RM04-7-000 131 

that PJM-East, and Northern PSEG are markets within PJM;220 Southwestern 

Connecticut (SWCT) and Connecticut Import interface (CT) are separate markets 

within ISO-NE;221 and New York City and Long Island are separate markets within 

NYISO.222 Accordingly, we conclude that sellers located in these RTO/ISO 

submarkets should not use the entire PJM, ISO-NE and NYISO footprints as their 

relevant geographic markets for purposes of the market-based rate analysis. Instead, 

they should use as the default geographic market for their market-based rate analysis 

the submarkets that the Commission already has found constitute separate markets in 

those RTOs/ISOs. 

237. We agree with APPA/TAPS that if the Commission makes a specific finding 

that the relevant geographic market is one other than the balancing authority area or 

RTO/ISO geographic region, the Commission’s finding should define the default 

market going forward. For example, if the Commission finds that a submarket exists 

within an RTO, that submarket becomes the default geographic market for all sellers 

that own or control generation capacity within that submarket. 

 220 Exelon Corp., 112 FERC ¶ 61,011, reh’g denied, 113 FERC ¶ 61,299 (2005) 

(Exelon). We note that Exelon later terminated the merger. 

221 Wisvest-Connecticut, LLC, 96 FERC ¶ 61,101 (2001). The parties later 

withdrew their application under FPA section 203. 

222 National Grid plc, 117 FERC ¶ 61,080 (2006). 
Docket No. RM04-7-000 132 

238. To the extent that the Commission finds that a submarket exists within an 

RTO/ISO, intervenors or sellers can provide evidence to the contrary (i.e., the 

submarket, like our other default geographic markets, is rebuttable). In addition, if a 

seller or intervenor argues that the seller operates in an RTO/ISO submarket and 

presents sufficient evidence to support that conclusion, we will consider those 

arguments even if the Commission has not previously found that a submarket exists. 

239. As a general matter, because we recognize the arguments raised by 

commenters that defining default geographic markets (whether balancing authority 

area, RTO/ISO footprint or RTO/ISO submarket) may not be appropriate in all 

circumstances, on a case-by-case basis, we will allow sellers and intervenors to 

present additional sensitivity analyses223 as part of their market power analysis to 

show that some other geographic market should be considered as the relevant market 

in a particular case. For example, sellers or intervenors could present evidence that 

the relevant market is broader than a particular balancing authority area. Sellers and 

intervenors may also provide evidence that because of internal transmission 

limitations (e.g., load pockets) the relevant market (or markets) is smaller than the 

balancing authority area, RTO/ISO footprint or RTO/ISO submarket. We believe this 

is a balanced approach because it establishes a presumption that the Commission will 

in most cases rely on default geographic markets, while at the same time, the 

 223 These analyses should be in addition to, not in lieu of, the analysis based on the 

default geographic market. 
Docket No. RM04-7-000 133 

Commission will give sellers and intervenors the opportunity to argue that the facts of 

a particular case support the use of some other geographic area as the relevant 

market. 

240. We also provide, as discussed further below, guidance regarding the type of 

analysis required to rebut the default geographic markets including default markets 

for balancing authority areas, RTO/ISO markets, and RTO/ISO submarkets. 

241. In this regard, sellers can incorporate the mitigation they are subject to in 

RTO/ISO markets or RTO/ISO submarkets with Commission-approved market 

monitoring and mitigation as part of their market power analysis. For example, if a 

market power analysis shows that a seller has local market power, the seller may 

point to RTO/ISO mitigation rules as evidence that this market power has been 

adequately mitigated. We believe the added protections provided in structured 

markets with market monitoring and mitigation generally result in a market where 

prices are transparent and attempts to exercise of market power will be sufficiently 

mitigated. 

242. With respect to market concentration resulting within RTO/ISO submarkets, 

we will continue to consider existing RTO mitigation. The Commission will consider 

an existing Commission-approved market monitoring and mitigation regime already 

in place within the RTO/ISO that provides for mitigation of the submarket. For 

example, New York City will be treated as a separate default market for market-based 

rate study purposes. However, because it has existing In-City mitigation, we will 

assess whether any concerns over market power are already mitigated. We agree 
Docket No. RM04-7-000 134 

with Ameren that if the relevant RTO/ISO does not have in place a mitigation 

program for an identified submarket, the Commission may then consider whether 

and, if so, to what extent appropriate submarket-specific mitigation is needed. 

243. In response to APPA/TAPS’ statement that in practice the presumption of the 

RTO footprint as the default geographic market appears to be irrebuttable, this is 

simply not the case. The Commission carefully considers the positions and evidence 

submitted by parties advocating a different geographic market. Although we may 

have found that arguments made in a particular case were unconvincing, or that 

market power was adequately mitigated by existing mitigation,224 we did, and will 

continue to, provide the opportunity for sellers to rebut the presumption. Moreover, 

as discussed above, where the Commission has made a specific finding that there is a 

 224 See, e.g., Mystic I, LLC, 111 FERC ¶ 61,378 at P 14-19 (2005) (rejecting 

challenge to use of ISO-NE market as the relevant geographic market on the basis that 

local market power mitigation is in place: “[W]ithout specific evidence to the contrary, 

we are satisfied that ISO-NE has Commission-approved tariff provisions in place to 

address instances where transmission constraints would otherwise allow generators to 

exercise local market power and that these rules and procedures will apply in the 

NEMA/Boston zone within ISO-NE.”); Wisconsin Electric Power Co., 110 FERC 

¶ 61,340 at P 19-20, reh’g denied, 111 FERC ¶ 61,361 at P 13-15 (2005) (rejecting 

challenge to use of Midwest ISO market as the relevant geographic market on basis that 

local market power mitigation measures exist: “The tighter thresholds in NCAs such as 

WUMS in the Midwest ISO, and the resulting tighter mitigation of bids, are local market 

power mitigation measures” and should adequately address specific concerns regarding 

the possibility that Wisconsin Electric can exercise market power in the WUMS region). 

Accord AEP Power Marketing, Inc., 109 FERC ¶ 61,276 (2004), reh’g denied, 112 FERC 

¶ 61,320 at P 23-25 (2005), aff’d, Industrial Energy Users-Ohio v. FERC, No. 05-1435 

(D.C. Cir. Feb. 16, 2007) (use of PJM footprint as relevant geographic market; noting 

existence of Commission-approved market monitoring and mitigation). 
Docket No. RM04-7-000 135 

submarket within an RTO, that submarket (not the RTO footprint) becomes the 

default relevant geographic market for sellers located within the submarket for 

purposes of the market-based rate analysis. 

244. In this proceeding, we have considered expanding the default geographic 

region of a single RTO/ISO where contiguous RTOs/ISOs may have a common 

market as suggested by Ameren and find that there is insufficient support to make a 

generic finding that any contiguous RTOs/ISOs form a single geographic market. 

245. With regard to the California Board’s proposal that the Commission permit 

RTOs to identify submarkets within their balancing authority area, as needed to help 

determine possible local market power, we agree that this is an appropriate approach. 

However, we note that this is neither a new nor a novel approach. The Commission 

has historically considered the views of RTOs/ISOs in this regard and will continue 

to do so. We note, however, that to the extent RTOs/ISOs believe there is a market 

power issue within their RTO/ISO, they should notify the Commission promptly and 

not wait for an application by an entity seeking market-based rate authority or a 

current seller submitting an updated market power analysis. 

246. Finally, to avoid any possible uncertainty or confusion about the RTO/ISO 

submarket, we identify RTO/ISO submarkets that the Commission to date has found 

to constitute a separate market. The Commission found submarkets in the PJM 
Docket No. RM04-7-000 136 

market, PJM East and Northern PSEG.225 In Wisvest-Connecticut, LLC, the 

Commission also found two submarkets, SWCT and CT in ISO-NE. 226 In National 

Grid plc, the Commission again found two submarkets, New York City and Long 

Island, in NYISO.227 These RTO/ISO submarkets will be the default geographic 

markets for purposes of the market-based rate analysis. 

b. NERC’s Balancing Authority Area and Default Geographic Area

Commission Proposal

247. In the NOPR, the Commission noted that the North American Electric 

Reliability Corporation (NERC) no longer uses the designation of control area since it 

approved the Reliability Functional Model (Functional Model). The Commission 

sought comment as to whether or not the adoption of the NERC Functional Model 

should change the criteria for specifying the default relevant geographic market, and 

 225 See Exelon, 112 FERC ¶ 61,011 at P 122. 

226 The Commission stated that “clearly, during periods when transmission 

becomes so constrained such that no additional imports from outside the region are 

possible and generators located inside the region are the only suppliers that can sell inside 

the region, the region should be defined as a separate relevant geographic market. Such is 

the case with SWCT and CT in this proceeding.” SWCT was defined as the area inside 

the Southern Connecticut Import interface, and CT was defined as the area inside the 

Connecticut Import interface, which is essentially contiguous with the state of 

Connecticut itself. Wisvest-Connecticut, LLC, 96 FERC ¶ 61,101 at 61,401-02. 

227 In National Grid plc, 117 FERC ¶ 61,080 at P 26, the Commission used Sellers’ 

HHI numbers for two of the NYISO submarkets (New York City and Long Island) to 

assess horizontal market power, and found screen failures in both submarkets under the 

economic capacity analysis. Id. at P 31.
Docket No. RM04-7-000 137 

if so, in what way it should be specified and how readily available the relevant data 

is. 

Comments

248. Several commenters state that since NERC no longer uses control area 

designations, and its Functional Model refers to “balancing authority areas,” the 

Commission should modify slightly its approach to default geographic markets by 

simply replacing the term “control area” with “balancing authority area.” They state 

that such a change will align the Commission’s rules with NERC’s Functional Model, 

thus helping to avoid confusion.228 

249. NYISO states that the control area is a valid starting point for the analysis of 

market-based rates. NYISO states that under the most recent version of the 

Reliability Functional Model posted on the NERC website (version 3, April 21, 

2006), the “Balancing” and “Market Operations” functions appear to correlate to the 

traditional notion of a control area operator for purposes of assessing competitive 

markets. Thus, the adoption of the Functional Model would appear to create issues 

more of terminology than substance. NYISO states that, whatever the terminology, 

the process of defining geographic markets should focus on the area in which grid 

 228 E.ON U.S. at 19, PNM/Tucson at 21, and Indianapolis P&L at 4-5. 
Docket No. RM04-7-000 138 

operations generally facilitate the ability of generators to compete in the scheduling 

and dispatch of resources, and the ability of loads to purchase from such resources.229

Commission Determination

250. With regard to the use of the Functional Model by NERC, we agree with 

commenters that the Commission should modify slightly its approach to default 

geographic markets by replacing the term “control area” with “balancing authority 

area.” 

251. A balancing authority area means the collection of generation, transmission, 

and loads within the metered boundaries of a balancing authority, and the balancing 

authority maintains load/resource balance within this area.230 Similar to control area, 

a balancing authority area is physically defined with metered boundaries that we refer 

to as the balancing authority area. Every generator, transmission facility, and end-use 

customer must be in a balancing authority area.231 The responsibilities of a balancing 

authority include the following: (1) match, at all times, the power output of the 

generators within the balancing authority area and capacity and energy purchased 

from or sold to entities outside the balancing authority area, with the load within the 

 229 NYISO at 2-4. 

230 See “Glossary of Terms Used in Reliability Standards,” at 

http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp 

231 See Basic Operating Functions and Responsibilities: A White Paper by the 

Control Area Criteria Task Force. 

http://www.maac-rc.org/reports/documents/cactf_reliability_model_whitepaper_v2.pdf 
Docket No. RM04-7-000 139 

balancing authority area in compliance with the Reliability Standards; (2) maintain 

scheduled interchange and control the impact of interchange ramping rates with other 

balancing authority areas, in compliance with Reliability Standards; (3) have 

available sufficient generating capacity, and Demand Side Management to maintain 

Contingency Reserves in compliance with Reliability Standards; and (4) have 

available sufficient generating capacity, Demand Side Management, and frequency 

response to maintain Regulating Reserves and Operating Reserves in compliance 

with Reliability Standards.232 It is the interconnection and coordination between 

balancing authority areas that provides a foundation for the Commission to analyze 

transmission limitations and other transfers of energy and provides a reasonable 

measure of the relevant geographic market under typical circumstances. 

252. The Commission adopts in this Final Rule “balancing authority area,” instead 

of “control area.” We believe that such a change will align the Commission’s rules 

with NERC’s Functional Model, thus helping to avoid confusion. 

c. Additional Guidelines for Alternative Geographic Market and 

Flexibility 

Commission Proposal

253. In the NOPR, the Commission proposed to continue to provide flexibility by 

allowing sellers and intervenors to present evidence that the market is smaller or 

 

232 See Approved Reliability Standards. 

http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp 
Docket No. RM04-7-000 140 

larger than the default market. The Commission explained that when assessing an 

expanded geographic market pursuant to the horizontal analysis, it looks for 

assurance that no frequently recurring physical impediments to trade exist within the 

expanded market that would prevent competing supply in the expanded area from 

reaching wholesale customers. The Commission stated that any proposal to use an 

expanded market should include a demonstration regarding whether there are 

frequently binding transmission constraints during historical seasonal peaks examined 

in the screens and at other competitively significant times that prevent competing 

supply from reaching the customers within the expanded market. The Commission 

proposed to require that such a demonstration be made based on historical data, and 

said it would require that a sensitivity analysis be performed analyzing under what 

circumstances transmission constraints would bind. 

254. The Commission explained that it also considers whether there is other 

evidence that would support the existence of an expanded market, such as evidence 

that customers can access the resources outside of the default geographic market on 

similar terms and conditions as those inside the default geographic market. It stated 

that such evidence could be empirical or it could point to factors that indicate a single 

market. It noted that the Commission has previously stated that the operation of a 

single central unit commitment and dispatch function for the proposed geographic 

market would be an indicator of a single market, but that other evidence of a single 

market could include a demonstration that: there is a single transmission rate; there is 

a common OASIS platform for scheduling transmission service across separate 
Docket No. RM04-7-000 141 

control areas; or there is a correlation of price movements between the areas being 

considered as an expanded geographic market or other information regarding 

wholesale transactions in the proposed single market. The Commission stated that 

evidence of active trading throughout the proposed geographic market would also be 

considered. It stated that in determining whether two or more control areas are a 

single market it would weigh, on a case-by-case basis, all the factors presented. The 

Commission noted that once it has been established that historically there were no 

physical impediments to trade, there are several factors the Commission would 

consider, and no one factor would be dispositive. The Commission sought comment 

on this proposed guidance and, in particular, whether there are other factors it should 

consider when assessing a proposed expanded market and whether there are any 

factors that should be given more weight or are essential in determining the scope of 

the market. The Commission also asked whether it should apply the same criteria 

when determining whether the geographic market is smaller than the default 

geographic market. 

Comments

255. A number of commenters agree that it is appropriate to provide sellers 

flexibility in presenting evidence that the appropriate geographic market is broader 

than the default geographic market.233 Several state that greater Commission 

 233 Indianapolis P&L at 5-6, Puget at 9-11, Ameren at 4-5, Duke at 23-24, and 

Avista at 5-7. 
Docket No. RM04-7-000 142 

guidance is needed so that sellers wishing to argue for a broader market definition 

have clear objective criteria and can provide evidence that the Commission will find 

probative. 

256. Puget submits that the examples listed in the NOPR provide some guidance 

but are still too general to be of use to a seller submitting a new market power study. 

It states that the Commission should: (1) provide additional guidance on the levels of 

price convergence and trading activity across a proposed alternative market that will 

support a seller’s filing; (2) be more specific regarding the level of transmission 

constraints that will preclude a finding of an expanded market; and (3) not rely 

heavily, if at all, on transmission operation factors – such as common OASIS or 

common unit commitment and dispatch – that are not necessarily indicative of a 

common market.234

257. Southern states that the Commission’s proposed focus on evidence pertaining 

to frequently binding transmission constraints for purposes of considering a larger 

geographic market seems appropriate. However, Southern argues that the NOPR’s 

apparent requirement of additional evidence (beyond the absence of transmission 

constraints) to support a larger geographic market is unnecessary. Moreover, 

Southern submits that evidence of a single unit commitment and dispatch function, a 

single transmission rate, and a common OASIS platform is not likely to exist in the 

 234 Puget at 9-11. 
Docket No. RM04-7-000 143 

absence of an RTO or ISO. Accordingly, making such evidence a requirement for a 

larger geographic market would render illusory the opportunity for expansion for 

non-RTO/ISO sellers.235 

258. Avista agrees that the absence of these factors does not necessarily mean that a 

market contains impediments to trading or that wholesale customers are unable to 

secure supply from alternative sources. Avista supports the Commission’s proposal 

to state what type of evidence demonstrates active trading throughout the proposed 

geographic market. Avista submits that a regional geographic market could and 

should be established based upon: (1) the presence of an actively traded liquid 

trading hub within the relevant defined market area; (2) transparent pricing 

information from that hub being widely available; and (3) the presence of extensive 

direct or single-wheel transmission access, both for sellers into the competitive hub 

market and for buyers’ access to the hub market for purposes of serving load.236

259. Powerex supports the Commission's initial specification of evidence that may 

be used to support a demonstration of a broader or smaller geographic market. 

However, Powerex is concerned that the Commission's enumeration of relevant 

categories of evidence is at present a partial list, and is not sufficiently comprehensive 

to address the unique circumstances that are likely to be present in various regions. 

 235 Southern at 24-25. 

236 Avista at 5-7. 
Docket No. RM04-7-000 144 

Powerex states that the Commission should clarify that additional types of evidence 

may also be used to support the propriety of a broader or smaller market definition.

260. One commenter states that the appropriate definition of the relevant 

geographic market can be (and very often will be) conditional -- that is, when there 

are no binding transmission constraints on imports into the relevant control area, the 

relevant market appropriately encompasses a broader area than the default geographic 

market; and when transmission constraints into the control area are binding, the 

control area is the appropriate geographic market. Accordingly, sellers should be 

allowed (or encouraged) to present analytical results for several market definitions, 

dependent on the existence or nonexistence of binding transmission constraints, to 

sharpen the focus on when market power might be a real concern.237

261. APPA/TAPS generally agree that the factors set forth by the Commission for 

assessing whether an alternative geographic market is appropriate are reasonable, but 

urge that the factors be non-exclusive and non-prescriptive. In addition to the factors 

the Commission identified in the NOPR, APPA/TAPS suggest that a seller be 

allowed to point to any joint transmission planning and coordinated construction 

processes as evidence that the relevant market should be larger than its own control 

area.238 APPA/TAPS state that a seller that is correctly advancing efforts to expand 

 237Dr. Pace at 15-16. 

238 APPA/TAPS at 54. 
Docket No. RM04-7-000 145 

markets deserves to have that recognized and a seller that is not undertaking such 

efforts should live with the consequences of the resulting smaller market. 

262. PPL states that if the Commission is to consider the potential existence of 

geographic markets smaller or larger than a control area, it should carefully consider 

the specific circumstances surrounding the control area of concern, and use an 

objective review process. That is, the Commission should consider these factors 

through the following means: (1) evaluation of the historical frequency of, and times 

when, physical transmission constraints limit the ability to transmit power within and 

between control areas, RTOs, and other defined regions within which electricity 

system supply and demand are balanced in real-time; (2) consideration of correlations 

of electricity prices, and electricity price day-to-day changes, within and between 

control areas, RTOs, and other defined regions within which electricity supply and 

demand are balanced in real time; (3) reference to historical evidence of actual 

transactions (including swaps/exchanges, etc.) wherein power is delivered within, 

imported to, or exported from, control areas, RTOs and sub-regions of RTOs; and (4) 

consideration of operational paradigms for obtaining transmission services and the 

extent to which the system allows for transparent access to transmission services.239

263. Several commenters urge the Commission to provide flexibility by suggesting 

a trading hub for an alternative geographic market. E.ON U.S. and PNM/Tucson 

 239 PPL at 2-6. 
Docket No. RM04-7-000 146 

state that the Commission should take regional commercial patterns into account 

when evaluating proposals to use a larger or smaller market, and they support 

allowing a seller to present a market power analysis specific to a trading hub.240 

264. Indianapolis P&L asks that the Commission clarify that sellers can propose 

different geographic definitions in their screen analyses. Indianapolis P&L states that 

the NOPR is unclear as to whether different geographic markets can be proposed for 

the indicative screen analyses or only for additional, “second stage” analyses, such as 

the DPT.241 

265. Powerex seeks clarification on how the definition of "home control area" (the 

control area where the seller is located) applies to an entity that has small-volume 

contracts in multiple control areas remote from its physical location. Powerex asks 

whether contracts with third parties, to the extent they confer some level of "control," 

create a multitude of home control areas. Powerex seeks additional guidance, 

including whether the answer to the question depends on the quantity of generation 

available under each contract, the level of control, whether the seller is affiliated with 

the transmission provider in that control area, or the remoteness of the contracted 

generation from the sellers' physical location.242

 240 E.ON U.S. at 14-15, PNM/Tucson at 8-10. 

241 Indianapolis P&L at 5-6. 

242 Powerex at 13-17. 
Docket No. RM04-7-000 147 

266. Duke requests clarification of whether first-tier markets, which are part of a 

larger RTO/ISO market (with an energy market that has central commitment and 

dispatch and Commission-approved market monitoring and mitigation) can be 

represented as the entire RTO/ISO market. For example, in the case of the Duke 

Energy Carolinas’ control area, which is directly interconnected to the AEP 

transmission system, Duke queries whether all of PJM would be the relevant first-tier 

market for purposes of determining the simultaneous import limitations into the Duke 

Energy Carolinas control area.243

Commission Determination

267. As an initial matter, we acknowledge the desire for the Commission to provide 

greater guidance to sellers wishing to argue for a broader or smaller market 

definition. We continue to believe that default geographic markets are adequate and 

sufficient for the typical situation. However, defaults may not be appropriate in all 

circumstances. Therefore, we will attempt to provide additional guidance and 

clarification to help inform 

market participants regarding the factors we believe are significant to consider when 

defining the market.244 

 243 Duke at 28. 

244 Although the following discussion generally refers to an expanded market (i.e., 

arguing that two or more default geographic markets constitute a single market) the same 

guidance is applicable for arguing that the market is smaller than the default geographic 

market (e.g., a load pocket). 
Docket No. RM04-7-000 148 

268. First, we reiterate that reaching beyond the default geographic market in which 

an entity is located can mean addressing additional physical and other challenges than 

when trading within that market. When assessing an alternative geographic market, 

the Commission looks for assurance that no frequently recurring physical 

impediments to trade exist within the alternative geographic market that would 

prevent competing supply in the alternative geographic market from reaching 

wholesale customers. Any proposal to use an alternative geographic market (i.e., a 

market other than the default geographic market) must include a demonstration 

regarding whether there are frequently binding transmission constraints during 

historical seasonal peaks examined in the screens and at other competitively 

significant times that prevent competing supply from reaching customers within the 

proposed alternative geographic market. We will require that a demonstration be 

made based on historical data and that a sensitivity analysis be performed analyzing 

under what circumstances transmission constraints would bind. If the seller fails to 

show that there are no frequently binding constraints at these critical times, then the 

Commission may not consider other evidence of an expanded market 

since we regard this as a necessary condition that must be satisfied to justify an expanded 

market. 

269. The Commission also considers whether there is other evidence that would 

support the existence of an alternative geographic market. In deciding whether 

customers may be considered as part of an expanded geographic market, the 

Commission will consider evidence that they can access the resources outside of the 
Docket No. RM04-7-000 149 

default geographic market on similar terms and conditions as those inside the default 

geographic market. 

270. Any such evidence submitted to show that the seller’s customers have access 

to resources outside of their balancing authority area at terms and conditions similar 

to those at which they can access resources inside the balancing authority area could 

be empirical or it could point to factors that indicate a single market. For example, 

the Commission has previously stated that the operation of a single central unit 

commitment and dispatch function for the proposed geographic market would be an 

indicator of a single market. However, there are other ways to demonstrate that two 

or more balancing authority areas are indeed a single market. For example, other 

evidence of a single market could include a demonstration that: there is a single 

transmission rate; there is a common OASIS platform for scheduling transmission 

service across separate balancing authority areas; or there is a correlation of price 

movements between the areas being considered as an expanded geographic market or 

other information regarding wholesale transactions in the proposed single market. 

Evidence of active trading throughout the proposed geographic market would also be 

considered. 

271. In determining whether two or more balancing authority areas are a single 

market, the Commission would weigh, on a case-by-case basis, all relevant factors 

presented. As discussed above, there are several factors the Commission would 

consider once it has been established that historically there were no physical 

impediments to trade, and no one factor or factors would be dispositive. Rather, all 
Docket No. RM04-7-000 150 

factors will be considered and as a whole will indicate whether there exists a single 

market.245 

272. With regard to Puget’s request that the Commission provide additional 

guidance with regard to the levels of price convergence, trading activity, and 

transmission constraints that define a market, no such generic finding will encompass 

all possibilities and, therefore, in all instances define the market. Accordingly, we 

will not attempt to do so here. 

273. We also reject Southern’s contention that the Commission has somehow 

rendered “illusory” the opportunity for entities outside RTOs and ISOs to 

demonstrate a larger geographic market. 246 The examples provided by the 

Commission of ways an entity could demonstrate a larger geographic market were 

just that: examples.247 The Commission does not require an entity proposing an 

alternative geographic market to provide evidence other than historical transmission 

access. Sellers and intervenors in both RTO/ISO and non-RTO/ISO markets may 

 245 We agree with Powerex that the Commission's enumeration of relevant factors 

it would consider is not an exhaustive list. As stated above, no comprehensive list of 

factors captures all factors that could indicate a single market. Accordingly, the 

Commission will consider additional types of evidence that may be presented on a caseby-case basis. 

246 Southern at 25. 

247 Thus, we agree with Avista that expansion of the geographic market is not 

limited to only those instances where there is either: a single transmission rate; a 

common OASIS; or operation of a single central unit commitment and dispatch function. 
Docket No. RM04-7-000 151 

present any probative evidence based on historical data of transmission availability, 

wholesale sales, resource accessibility, and market prices. 

274. In response to Indianapolis Power & Light’s comments, we clarify that when a 

seller submits its screen analysis, it can also propose an alternative analysis based on 

the use of a geographic market larger than the default geographic market. However, 

such proposal should be made in addition to, not in lieu of, the screen analysis based 

on the default geographic market. 

275. With regard to using trading hubs as alternative market areas, the Commission 

understands that numerous electricity trading hubs have emerged over the past few 

years. A trading hub is a representative location at which multiple sellers buy and 

sell power and ownership changes hands, typically with trading of financial and 

physical products. For physical trades, the hub may represent a specific delivery 

point or set of points. Currently only select trading hubs account for the majority of 

physical power trading although there remains the possibility that market demand 

could initiate trading hubs for each balancing authority area. In evaluating market 

power, however, trading hub data alone does not provide a foundation for the 

Commission to analyze transmission limitations and other transfers of energy. 

Moreover, with regard to trading hubs, the combination of physical and diverse 

financial products, the low barriers for entry of new participants, and the unlimited 

potential for resale of limited physical output may not provide a reasonable measure 

of the relevant geographic market under typical situations, as a balancing authority 

area does. Therefore, while trading data may be considered in the illustration of 
Docket No. RM04-7-000 152 

relevant price correlation or of liquid trading activity to demonstrate that two or more 

balancing authority areas are indeed a single market, the Commission will not allow 

use of a trading hub to define a relevant geographic market. 

276. With regard to one commenter’s suggestion that the Commission should allow 

(or encourage) sellers to present analytical results for several market definitions 

because the appropriate definition of the relevant geographic market can be 

conditioned on the existence or nonexistence of binding transmission constraints, the 

Commission agrees in principle. The Commission provides an opportunity for 

sellers who fail one or more of the initial screens to present a more thorough analysis 

using the DPT. As the April 14 Order states “the [DPT] defines the relevant market 

by identifying potential suppliers based on market prices, input costs, and 

transmission availability, and calculates each supplier’s economic capacity and 

available economic capacity for each season/load condition.”248 In addition, in the 

Merger Policy Statement the Commission stated that the flows on a transmission 

system can be very different under different supply and demand conditions (e.g. peak 

vs. off-peak). Consequently, the amount and price of transmission available for 

suppliers to reach wholesale buyers at different locations throughout the network can 

vary substantially over time. If this is the case, the DPT analysis should treat these 

 248 AEP Power Marketing, Inc., 107 FERC ¶ 61,018 at P 106. 
Docket No. RM04-7-000 153 

narrower periods separately and separate geographic markets should be defined for 

each period.249

277. The Commission believes that the DPT can address the dynamic nature of 

markets. Under the DPT, the amount and price of transmission available for 

suppliers to reach wholesale buyers at different locations throughout the network 

during different season/load conditions (e.g., peak vs. off-peak) can be analyzed. For 

example, an area may become constrained only during the highest load levels, in 

which case the relevant geographic market could differ across seasons, and separate 

geographic markets could be defined for each period. However, as discussed earlier, 

in an effort to provide as much regulatory certainty as possible, the Final Rule adopts 

as the default geographic market the balancing authority area or the RTO footprint, as 

applicable, but allows sellers or intervenors to propose alternative markets based on 

historical transmission and sales data. 

278. We clarify in response to Powerex that sellers should do market power studies 

for each balancing authority area where they own or control assets (i.e., should study 

all balancing authority areas where generation assets they own or control are located) 

regardless of the quantity or location of generation they control (subject to the terms 

adopted herein regarding Category 1 sellers). Also, to the extent a market power 

study is required, sellers should study each balancing authority area where they own 

 249 Merger Policy Statment, FERC Stats. & Regs. Regulations Preambles July 

1996-December 2000 ¶ 31,044 at 30,132. 
Docket No. RM04-7-000 154 

or control assets regardless of whether the seller is affiliated with the transmission 

provider in that balancing authority area. The Commission also clarifies for Duke 

that if the first-tier markets for a seller (whether or not the seller is a member of the 

RTO) are part of a larger RTO/ISO market, all of the RTO/ISO market would be a 

relevant first-tier market for purposes of determining the simultaneous import 

limitations.

d. Specific Issues Related to Power Pools and SPP

Commission Proposal

279. In the NOPR, the Commission proposed to continue its practice of designating 

an RTO/ISO in which a seller is located as the default relevant geographic market if 

the RTO/ISO has sufficient market structure and a single energy market with 

Commission approved market monitoring and mitigation. 

Comments

280. A number of commenters urge the Commission to consider power pools as 

geographic market areas. Midwest Energy claims that, “under current Commission 

policy, sellers of power in RTOs/ISOs with a full-fledged single central commitment 

and dispatch system are allowed to treat the full RTO footprint as the relevant 

geographic market, thereby facilitating qualification for market-based rates. Sellers 

in a Commission-approved RTO without a single central commitment and dispatch 
Docket No. RM04-7-000 155 

system are relegated to a relevant market defined by their own control area.”250 

Midwest Energy urges the Commission to consider changing its existing policy to 

create a presumption that the relevant geographic market for a Commission-approved 

RTO is the region covered by a single transmission tariff.251 Alternatively, Midwest 

Energy states that the Commission could require, in addition to a regional tariff, the 

implementation of a Commission-approved market monitor and a centrally 

dispatched energy imbalance market. It states that these changes would allow sellers 

to treat the Southwest Power Pool (SPP) region as the relevant geographic market. 

281. Westar states that the Commission should find that a transmission region with 

a single OATT, non-pancaked transmission rates, a common OASIS platform for 

scheduling transmission, and approved market monitoring (e.g., SPP) presumptively 

qualifies as a single region for purposes of the market power screens. Westar states 

that although the NOPR identifies single unit commitment and/or centralized dispatch 

of generation to be an important characteristic of a regional market, the Commission 

has not always done so. For example, the Commission did not identify this as a 

defining characteristic when it accepted other RTOs/ISOs as a single region for 

market-based rate purposes, such as New England. The Commission also did not rely 

upon centralized dispatch in authorizing market-based power sales across the 

 250 Midwest at 1-3. 

251 Midwest at 1-3, 4-8. 
Docket No. RM04-7-000 156 

California, New York or PJM markets. Westar states that the Commission should 

find that SPP meets the criteria for a single market once its energy imbalance market 

(EIM) becomes operational.252

282. In its reply comments, Southwest Coalition disagrees with those commenters 

requesting that SPP qualify as a single geographic region for sellers in its region once 

its EIM is operational. Southwest Coalition states that Westar has not presented any 

evidence for the Commission to change course with SPP in this rulemaking. It 

asserts that SPP currently has underway a variety of market implementation 

proceedings, of which Westar is a party, through which the Commission can make a 

reasoned decision regarding SPP's status. As such, Southwest Coalition states that 

this generic rulemaking proceeding is not the appropriate vehicle for considering 

Westar's request. In addition, Southwest Coalition states that Westar’s request 

represents an improper request for rehearing of the Commission's March 20, 2006 

Order in SPP's market implementation proceeding. Southwest Coalition requests 

that, if the Commission were to consider Westar's request in this proceeding, the 

Commission should reject Westar's request for a Commission finding that SPP is a 

single geographic region for purposes of the Commission's market power screens.253

 252 Westar at 3-6. 

253 Southwest Industrial Customer Coalition reply comments at 2-9. 
Docket No. RM04-7-000 157 

283. Puget argues that applying the control area default to utilities in the Pacific 

Northwest is arbitrary, and does not result in an accurate measurement of a seller’s 

potential market power in the region’s energy markets. According to Puget, the 

relevant geographic market for the purpose of measuring horizontal market power in 

the Pacific Northwest is the United States portion of the Northwest Power Pool, 

which is dominated by a transmission system operated by Bonneville Power 

Administration. Puget submits that many of the criteria outlined in the NOPR – 

particularly those addressing parallel price movements, single transmission rates, and 

active trading – are met in this geographic region. Utilities in the Pacific Northwest 

would like to have the opportunity to make a showing to the Commission that the 

relevant geographic market for measuring market power in their region is an area 

other than their home and first-tier control areas.254

Commission Determination

284. We decline to address whether additional regions of the country qualify as 

relevant geographic markets. Through this Final Rule, we set forth several examples 

of criteria that sellers can use in proposing an alternative geographic market. 

Individual sellers can challenge our default geographic market and provide evidence 

to support their proposal. Intervenors will have the opportunity to comment prior to 

the Commission rendering a decision. 

 254 Puget at 9-11. 
Docket No. RM04-7-000 158 

e. RTO/ISO Exemption

Commission Proposal

285. In the April 14 Order, the Commission concluded that it would no longer 

exempt sellers located in markets with Commission-approved market monitoring and 

mitigation from providing generation market power analyses, on the basis that 

requiring sellers located in such markets to submit screen analyses provides an 

additional check on the potential for market power.255 The Commission did not 

address this point in the NOPR. 

Comments

286. In their comments in this proceeding, Reliant, NRG and FirstEnergy urge the 

Commission to reinstate the exemption.256 Reliant states that reinstating the 

exemption would be appropriate because real-time market monitoring by an 

independent market monitor consistent with Commission-approved rules and 

Commission-approved targeted mitigation address identification of market power 

concerns as well as mitigation of market power in those markets and, therefore, 

eliminate the value of any separate market power analysis submitted by an individual 

 255 107 FERC ¶ 61,018 at P 186. The Commission had previously stated that all 

sales, including bilateral sales, into an ISO or RTO with Commission-approved market 

monitoring and mitigation would be exempt from the Supply Margin Assessment test 

and, instead, would be governed by the specific thresholds and mitigation provisions 

approved for the particular market. AEP Power Marketing, Inc., 97 FERC ¶ 61,219 at P 

176 (2001). 

256 Reliant at 6-7; NRG at 7; and FirstEnergy at 33. 
Docket No. RM04-7-000 159 

seller. Reliant states that Commission-approved market monitoring and mitigation 

provide the Commission with a better and more sophisticated picture of market power 

issues in RTO/ISO markets as compared to a seller’s market power analysis, which 

looks only at market power at a fixed moment in time. 

287. Reliant states that if the Commission decides not to reinstate the exemption, it 

is critical that the Commission continue to use RTO/ISO markets as the default 

geographic market for sellers with generation located in those markets. Reliant states 

that the key to the determination of relevant geographic markets is the extent to which 

sellers can compete in the defined market. RTO/ISO markets with centralized 

markets provide a platform for all sellers located in the pertinent RTO/ISO market to 

compete. Thus, Reliant states that it is entirely appropriate to consider such markets 

as the default market unless and until an intervenor can show that this is no longer 

appropriate (e.g., due to transmission constraints).257

288. In its reply comments, PSEG states that while it believes that the RTO/ISO 

exemption would be warranted at least for regions with pervasive market monitoring 

unit (MMU) oversight such as PJM, it recognizes that some affected parties may not 

be comfortable with a blanket exemption. It suggests that the Commission’s 

regulations should take account of the fact that the Commission has approved 

comprehensive MMU oversight of markets and that MMUs take their duties seriously 

 257 Reliant at 6-7. 
Docket No. RM04-7-000 160 

and routinely exercise their authority. Accordingly, PSEG proposes that evidence of 

active MMU oversight supply the basis for obviating the need to conduct a market 

power study for a particular zone or sub-zone of an RTO or ISO.258 

289. APPA/TAPS, in contrast, state that reinstating the RTO/ISO exemption would 

represent an abdication of the Commission’s responsibilities259 

Commission Determination

290. The Commission declines the request that it reinstate the pre-April 14 Order 

exemption for sellers located in markets with Commission-approved market 

monitoring and mitigation from providing generation market power analyses. The 

Commission will continue to require generation market power analyses from all 

sellers, including those in RTO/ISO markets. All sellers are required to receive 

authorization from the Commission prior to undertaking market-based rate sales, and 

as discussed herein, all new applicants for market-based rate authority are required to, 

among other things, provide a horizontal market power analysis. The first step for a 

seller seeking market-based rate authority is to file an application to show that it and 

its affiliates do not have, or have adequately mitigated, market power. Sellers can 

refer to RTO/ISO monitoring and mitigating as a factor. We believe that a single 

market with Commission-approved market monitoring and mitigation and transparent 

 258 PSEG reply comments at 5-6. 

259 APPA/TAPS reply comments at 2-3. 
Docket No. RM04-7-000 161 

prices provides added protection against a seller’s ability to exercise market power 

but cannot replace the generation market power analysis. 

291. To address Reliant’s concern, we note that, as discussed above, we will use 

RTO/ISO markets (including Commission findings with regard to RTO/ISO 

submarkets) as the default geographic market for the indicative screens for sellers 

with generation in those markets. 

8. Use of Historical Data

Commission Proposal

292. The Commission proposed in the NOPR to retain the “snapshot in time” 

approach for the indicative screens, so that sellers are required to use the most 

recently available unadjusted 12 months’ historical data. The Commission stated that 

historical data are more objective, readily available, and less subject to manipulation 

than future projections. The Commission proposed to continue to permit sellers to 

make adjustments to data that are essential to perform the indicative screens provided 

that the seller fully justifies the need for the adjustments, justifies the methodology 

used, provides all workpapers in support, and documents the source data. 

293. However, the Commission proposed to allow, for the DPT analysis, sellers and 

intervenors to account for changes in the market that are known and measurable at the 

time of filing.260 The Commission noted that this proposal mirrors the Commission’s 

 260 See 18 CFR 35.13(a). 
Docket No. RM04-7-000 162 

approach in connection with its merger analysis. Sellers and intervenors proposing 

known and measurable changes to be considered in the DPT analysis would bear the 

burden of proof for their adjustments to historical data. The Commission sought 

comment on whether the Commission should provide a limitation on the time period 

past the historical test period for which sellers can account for changes, what that 

time period should be, and how flexible or inflexible that limitation should be. In 

addition, the Commission sought comment on exactly what types of changes should 

be allowed and under what circumstances. 

Comments

294. Various commenters generally support the Commission’s proposal to use 

historical data for the indicative screens and allow known and measurable changes for 

the DPT.261 Some suggestions made as to what should be considered known and 

measurable changes include: allowing only changes that occur between updated 

market power analysis filings262 and allowing only publicly available data or 

company information.263 Powerex expresses concern that known and measurable 

 261 See, e.g., EEI at 23, PPL at 17-19; Powerex at 18-19. 

262 See, e.g., Ameren at 6. Ameren proposes that if a seller chooses to rely on an 

historical period with no changes, the Commission should honor that choice and not 

allow intervenors to introduce suggested known and measurable changes. Conversely, if 

a seller proposes to adjust the historical period for certain known and measurable 

changes, Ameren states that the Commission should permit intervenors to introduce 

competing known and measurable changes. Id. at 6-7. 

263 Drs. Broehm and Fox-Penner at 12-13 (any adjustments to historical base year 

 (continued...) 

 
Docket No. RM04-7-000 163 

changes may not be publicly available.264 PG&E suggests that the Commission 

evaluate on a case-by-case basis whether the seller or intervenor can prove that the 

change is both foreseeable and reasonable. It says that the Commission should not 

impose a time restriction on such changes provided that the seller provides the 

necessary support for changes that it claims are known and measurable.265

295. A number of commenters suggest that sellers should be permitted to account 

for known and measurable changes in both the indicative screens and the DPT.266 

Southern states that the Commission “should not . . . restrict the ability of parties to 

provide the Commission with the best possible information and analysis.”267 Duke 

states that in all instances the objective should be to obtain the most accurate and 

timely assessment of the seller’s ability to exercise market power under current 

market conditions.268 

296. NRECA states that the screens should incorporate imminent changes and that 

an example of known and measurable changes that should be included in initial 

 

must be known and measurable at the time of filing; new capacity additions should only 

be accounted for if they are on-line or under construction). 

264 Powerex at 18-19. 

265 PG&E at 9-10. 

266 PG&E at 2; Southern at 25-26; Duke at 26; NRECA at 21-23. 

267 Southern at 26. 

268 Duke at 26. 
Docket No. RM04-7-000 164 

applications and triennial filings is the capacity freed up by expiring long-term 

contracts. It submits that these contracts will expire on a known schedule and, if the 

market is competitive, the seller should not be allowed to assume that the capacity 

will remain committed to the buyer.269

297. PPL argues that long-term contracts should retain the current definition as 

those expiring in one year or more, and recommends not considering contracts that 

take effect after one year but before the triennial update is due. It argues that buyers 

could withhold signing contracts and force a market power finding. PPL also notes 

that a notice of change in status must be filed at the expiration of contracts that 

increase the seller's capacity by 100 MW or more and that the Commission can 

initiate a section 206 investigation at that point if need be.270

Commission Determination

298. We will continue to require the use of historical data for both the indicative 

screens and the DPT in market-based rate cases. The indicative screens are designed 

as a tool to identify those sellers that raise no generation market power concerns and 

can otherwise be considered for market-based rate authority. Accordingly, the 

indicative screens are conservative in nature and not generally subject to debates over 

projected data, which may unnecessarily prolong proceedings and create regulatory 

 269 NRECA at 21-23. See also APPA/TAPS at 13-15. 

270 PPL reply comments at 3-4. 
Docket No. RM04-7-000 165 

uncertainty. However, in light of adopting a regional approach with regard to 

regularly scheduled updated market power analyses, we will require the use of the 

actual historical data for the previous calendar year. Requiring all sellers in a region 

to provide analyses using the same data set further enhances the Commission’s ability 

to evaluate market power and identify any discrepancies between market studies. 

299. After careful consideration of the comments received, the Commission will 

not adopt the NOPR proposal that the DPT analysis allow sellers and intervenors to 

account for changes in the market that are known and measurable at the time of filing. 

Instead, the Commission will adopt its current practice that sellers are required to use, 

in the preparation of a DPT for a market-based rate analysis, unadjusted historical 

data and, consistent with the above discussion, the Commission will require the use 

of the actual historical data for the previous calendar year. The Commission has 

stated that historical data are more objective, readily available, and less subject to 

manipulation than future projections. 

300. We acknowledge that the Commission’s approach in its merger analysis 

requires applicants and intervenors to account for changes in the market that are 

known and measurable at the time of filing. However, we find that the purpose of 

using the DPT in market-based rate proceedings is different from that in merger 

analysis. Intrinsically, a merger analysis is forward-looking to identify what effect, if 

any, there will be on competition if the proposed merger is consummated. Even 

though the Commission has the ability to reopen a merger proceeding under its 

section 203(b) authority, it is difficult and costly to undo a merger, so the 
Docket No. RM04-7-000 166 

Commission is cognizant of the need to analyze what might happen as a result of a 

proposed merger and put any necessary mitigation in place prior to consummation of 

the merger. 

301. In contrast, the market-based rate analysis is a “snapshot in time” approach. 

When the Commission evaluates an application for market-based rate authority, the 

Commission’s focus is on whether the seller passes both of the indicative screens 

based on unadjusted historical data. Likewise, when a seller fails one of the screens 

and the Commission evaluates whether that seller passes the DPT, the Commission’s 

focus is on whether the seller passes the DPT based on unadjusted historical data. 

The Commission’s grant of market-based rate authority is conditioned, among other 

things, on the seller’s obligation to inform the Commission of any change in status 

from the circumstances the Commission relied upon in granting it market-based rate 

authority. As such, the Commission’s market-based rate program is designed to 

require sellers to report, and enable the Commission to examine, changes in facts and 

circumstances on an ongoing basis. Such a reporting requirement provides the 

Commission with ongoing monitoring in addition to its right to require any marketbased rate seller to provide an updated market power analysis at any time. 

Accordingly, the market-based rate change in status reporting requirement allows the 

Commission to evaluate changes when they actually happen rather than relying on 

projections, making it unnecessary and redundant for the Commission to allow sellers 

to account for known and measurable changes in the DPT for market-based rate 

purposes. For these reasons and the reasons explained in the April 14 and July 8 
Docket No. RM04-7-000 167 

Orders and existing Commission precedent, the Commission reaffirms that the 

indicative screens and DPT analyses should be based on unadjusted historical data. 

9. Reporting Format

Commission Proposal

302. In the NOPR, the Commission proposed to require all sellers to submit the 

results of their indicative screen analysis in a uniform format to the maximum extent 

practicable and appended a proposed format. This format, provided in Appendix C of 

the NOPR, was intended to promote consistency and aid the Commission in the 

decision-making process. The Commission sought comment on this proposal. 

Comments

303. Although only a few comments were received on this topic, those comments 

support the proposal to adopt a uniform reporting format for the indicative screens. 

APPA/TAPS suggest that the proposed uniform format should help all market 

participants, especially when assessing the filings of a number of public utilities as 

part of the proposed regional review process. APPA/TAPS state that the uniformity 

should also help the Commission analyze market-based rate filings on a consistent 

basis, thus increasing market participant confidence in those assessments.271 Other 

commenters concur with the Commission's proposal for a uniform reporting format. 

 271 APPA/TAPS at 35. 
Docket No. RM04-7-000 168 

They state that a uniform reporting format will increase consistency and thus aid the 

Commission in its decision making process.272 

304. One commenter suggests formatting and presentation changes to the NOPR’s 

Appendix C reporting form. These changes include creating sections for items such 

as the calculation of seller and market uncommitted capacity and rearranging some in 

a more logical fashion.273 

Commission Determination

305. We will adopt the reporting format as proposed in the NOPR, maintaining the 

same order of items as in the form provided in Appendix C of the NOPR, but note 

that this form now appears as Appendix A of this Final Rule. We believe 

standardizing the submission format has benefits to all market participants. As noted, 

it appears that commenters as well are generally supportive of this proposal to require 

all sellers to submit the results of their indicative screen analyses in a uniform format. 

306. Also, we will adopt many of the formatting changes suggested in the 

comments. The row letter will be the first column and a better delineation of sections 

will increase the comprehensibility of the form. The revised form can be found in 

Appendix A.274 

 272 Drs. Broehm and Fox-Penner at 12. 

273 Dr. Pace at 8-9. 

274 The "Workpapers" column is meant to provide an easy way to find sources and 

ensure that all submissions are properly sourced. Hence, the items in that column (e.g., 

 (continued...) 

 
Docket No. RM04-7-000 169 

10. Exemption for New Generation (Formerly Section 35.27(a) of the 

Commission’s Regulations)

a. Elimination of Exemption in Section 35.27(a)

Commission Proposal

307. The Commission’s regulations provide that any public utility seeking 

authorization to engage in market-based rate sales is not required to demonstrate a 

lack of market power in generation with respect to sales from capacity for which 

construction commenced on or after July 9, 1996.275 In the NOPR, the Commission 

noted that when it established the exemption in Order No. 888 it indicated that it 

would consider whether a seller citing § 35.27(a) nevertheless possesses horizontal 

market power if specific evidence is presented by an intervenor.276 

308. The Commission stated in the NOPR that although it remains committed to 

encouraging new entry of generation, it is concerned that the continued use of the § 

35.27(a) exemption may become too broad and, over time, would encompass all 

 

"Workpaper 5") were merely meant to be illustrative and do not require that information 

be submitted on specific workpapers or that workpapers be submitted in a particular 

order. 

275 18 CFR 35.27(a). The regulation reads: “Notwithstanding any other 

requirements, any public utility seeking authorization to engage in sales for resale of 

electric energy at market-based rates shall not be required to demonstrate any lack of 

market power in generation with respect to sales from capacity for which construction 

has commenced on or after July 9, 1996. 

276 NOPR at P 67. 
Docket No. RM04-7-000 170 

market participants as all pre-July 9, 1996 generation is retired. Accordingly, the 

Commission proposed in the NOPR to eliminate the exemption in § 35.27(a) and to 

require that all new sellers seeking market-based rate authority on or after the 

effective date of the Final Rule and all sellers filing updated market power analyses 

on or after the effective date of the Final Rule must provide a horizontal market 

power analysis of all of their generation, whether or not it was built after July 9, 

1996. Because the Commission allows a seller to make simplifying assumptions 

where appropriate and to submit a streamlined analysis, the Commission explained 

that any additional burden imposed on sellers by this reform would be minimal. In 

addition, the Commission anticipated that those entities that otherwise would have 

relied on the exemption would, in most cases, qualify as Category 1 sellers and 

therefore no longer be required to file updated market power analyses as a routine 

matter. The Commission sought comment on this proposal. 

Comments

309. Many commenters support the Commission’s proposed elimination of the § 

35.27(a) exemption, stating that there should be a level playing field for market-based 

rate sellers so that all market participants would be required to perform the generation 

market power screens.277 A number of commenters support the Commission’s 

position that there is a valid concern that over time the exemption would encompass 

 277 Progress Energy at 2; PG&E at 10; FirstEnergy at 9; TDU Systems at 2; New 

Jersey Board at 2; NASUCA at 7; Drs. Broehm/Fox-Penner at 13. 
Docket No. RM04-7-000 171 

all generation as older generating units are retired and new generation is built.278 

Several commenters state that the Commission correctly observes that the indefinite 

continuation of the exemption would ultimately result in the automatic grant of 

market-based rate authority to all sellers as pre-1996 generation is retired.279 They 

further state that eliminating the exemption will not impose significant new burdens, 

deter new entry into a market, or create any unreasonable disincentive or impediment 

for the construction of future generating capacity.280 Contrary to the assertions of 

several commenters, FirstEnergy states that the elimination would encourage 

merchant power developers to expand generation in markets where they do not 

already have a dominant position which, in turn, would dilute market power concerns 

in these markets. 

310. NRECA and APPA/TAPS maintain that, despite EPSA’s, Mirant’s, and PPL’s 

assertions to the contrary,281 the Commission did not create the exemption as an 

incentive to encourage new generation investment.282 APPA/TAPS elaborates 

further, agreeing with the Commission that many new entrants would qualify as 

 278 See PG&E at 10; APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1. 

279 APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1. 

280 See FirstEnergy at 10; APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 

1. 

281 EPSA at 12-13; Mirant at 11; PPL at 19- 20. 

282 NRECA reply comments at 11; APPA/TAPS reply comments at 16-17. 
Docket No. RM04-7-000 172 

Category 1 sellers and, therefore, would not have to submit updated market power 

analyses and that other entrants could make simplifying assumptions to demonstrate 

that they qualify for market-based rate authority.283 These commenters contend that 

the benefits of eliminating the exemption far outweigh any added burdens to ensure 

that all market participants are treated equally and to ensure that rates for 

jurisdictional sellers are just and reasonable.284

311. In support of the elimination of the § 35.27(a) exemption, NASUCA 

acknowledges that under current procedures, if all the generation owned or controlled 

by an applicant for market-based rate authority and its affiliates in the relevant 

control area is new generation, such seller is not required to provide a horizontal 

market power analysis because of the exemption under § 35.27(a).285 NASUCA 

asserts that under the current rule, there is no limit on the amount of post-July 9, 1996 

generation that could be exempt from the Commission’s analysis of market power. In 

addition, a commenter explains that the potential to exercise market power has no 

relation to whether generating plants were built before or after 1996.286 ELCON 

suggests that generators that were built after July 9, 1996 are capable of exercising 

 283 See APPA/TAPS at 27. 

284 APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1. 

285 NASUCA at 7. 

286 Drs. Broehm/Fox-Penner at 13. 
Docket No. RM04-7-000 173 

market power.287 In addition, FirstEnergy points out that merchant power plant 

developers have begun to aggregate fleets of newer generating plants to which this 

exemption is applicable, and may now be able to exercise generation market 

power.288 PG&E adds, “in situations where all generation owned or controlled by an 

applicant and its affiliates in the relevant market is new generation, should they 

control sufficient generation, the applicants and its affiliates may freely exercise 

market power.”289 In addition, Morgan Stanley supports elimination of the 

exemption stating that maintaining the exemption would have unintended 

consequences going forward.290 

312. Among those who oppose elimination of the exemption, Constellation asserts 

that it would send an unfavorable signal to market participants that the rules may be 

changed with a retroactive effect, which in turn would deter investment.291 

Constellation also contends that the Commission offers no support and/or analysis to 

demonstrate its inference that older generating units will be retired in significant 

quantities to make a substantial difference to the screening analysis of any seller. 

PPL submits, among other ill-effects, that the elimination will deter investment in 

 287 ELCON at 6. 

288 See FirstEnergy at 9-10. 

289 PG&E at 10. 

290 Morgan Stanley at 13-14. 

291 Constellation at 30. 
Docket No. RM04-7-000 174 

areas where there is a limited supply and the new entrant may be deemed pivotal. In 

addition, PPL contends that some sellers relied on the presumption that they would 

not need to demonstrate a lack of market power in financing, constructing, and 

operating their new power plants.292

313. EPSA opposes the elimination of the exemption under § 35.27(a). EPSA 

states that the electric industry needs incentives for new generation and does not need 

disincentives if capital is to be invested on a timely basis to meet future demand and 

enhance competition.293 EPSA asserts that the exemption encourages the 

development of competitive supply outside of organized markets.294 Similarly, NRG 

contends that the elimination of the § 35.27(a) exemption will delay and deter 

investment in load pockets. NRG also argues that eliminating the exemption runs 

counter to the Commission’s policy of encouraging investment in electric power 

infrastructure to enhance reliability and market liquidity.295 

314. In addition, EPSA argues that the purpose of the exemption was to encourage 

new generation investment by competitive suppliers especially in areas of the country 

that are mostly dominated by utility-owned generation.296 Specifically, EPSA 

 292 PPL at 19-20. 

293 EPSA at 12. 

294 EPSA reply comments at 6. 

295 NRG at 2. 

296 EPSA at 13. 
Docket No. RM04-7-000 175 

explains that it is in these regions of the country where affiliated generation is largely 

treated as native load and, thus, is excluded from the market power analysis even 

though it represents most of the capacity in the region.297 EPSA explains that, even if 

a small increment of competitive supply is introduced into the market, the analysis 

might detect market power when measured against relatively small existing 

generation. Therefore, without the exemption, a new competitive supplier would fail 

the test and would have to utilize cost-based rates.298 

315. Allegheny argues that the Commission overlooks the reason why it initially 

adopted the exemption. Allegheny states that, in Order No. 888, the Commission 

determined that long-term generation markets are competitive.299 Allegheny further 

argues that “the Commission cannot ‘gloss over’ its prior reasoning without 

discussion, and without showing that there has been a fundamental change in facts 

 297 In its reply comments NASUCA disagrees, submitting that there are other 

regions where a seller with a fleet of newer exempted generating plants could exercise 

market power or bid the output strategically to drive prices up. NASUCA reply 

comments at 4-5. 

298 EPSA at 13. 

299 Allegheny at 8-9 (citing Promoting Wholesale Competition Through Open 

Access Non-discriminatory Transmission Services by Public Utilities and Recovery of 

Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, FERC Stats. 

& Regs.Regulations Preambles January 1991-June 1996 ¶ 31,036 at 31,657 (1996), order 

on reh'g, Order No. 888-A, FERC Stats. & Regs. Regulations Preambles July 1996-

December 2000 ¶ 31,048 (1997), 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 part and rev'd 

in part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. 

Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 (2002)). 
Docket No. RM04-7-000 176 

and circumstances that have [sic] caused long-term markets to be no longer 

competitive.”300 PPL asserts that the Commission in Order No. 888 recognized the 

power that the opportunity of free entry has to eliminate market power concerns and 

stated that open access advancements removed structural impediments for new 

entrants competing with existing market participants.301 

316. Mirant and EPSA expand on arguments that eliminating the exemption will 

deter investment. They argue that, when reserve levels are tight in a control area 

where the host utility has lost or forgone its market-based rate authority, a 

competitive supplier would have to weigh the risks as to whether the Commission 

would authorize it to make market-based rate sales if it were to build a new asset in 

that control area.302 They contend that there is no incentive for a competitive supplier 

to build new generation if its sales will be mitigated at some level of cost-based 

rates.303 In particular, Mirant explains that if a municipal utility issued a request for 

proposals (RFP) for 600 MW of power commencing in 2010 and terminating in 2020, 

with the current exemption competitive suppliers could bid on the RFP knowing that 

the supplier would be authorized to sell the output of its new generating station at 

market-based rates. However, Mirant asserts that if the exemption were eliminated, a 

 300 Allegheny at 9 (citation omitted). 

301 PPL at 20. 

302 Mirant at 11-12; EPSA at 13-14. 

303 EPSA at 13; Mirant at 12. 
Docket No. RM04-7-000 177 

supplier would have to get Commission approval for market-based rate sales prior to 

bidding on the RFP. 304

317. Mirant disagrees with the Commission’s contention that eliminating the 

exemption would not affect many sellers and that the cost of compliance would be 

minimal. Mirant states that five of its subsidiaries would have to file updated market 

power analyses if the exemption were eliminated because they own more than 500 

MW in the relevant market or control area and would not qualify as Category 1 

sellers. Mirant argues that its cost of compliance would increase because it would 

have to prepare four updated market power analyses, each costing $20,000 to prepare 

and file. 305 In its reply comments, APPA/TAPS state that Mirant’s increased cost is 

paltry compared to the over $3.4 billion in generation revenues reported by Mirant in 

2005, which APPA/TAPS suggest is in no small part due to Mirant’s market-based 

rate sales.306 

 304 Mirant at 11-12. Mirant elaborates: “In calculating the pivotal supplier and 

market share screens, an applicant is allowed to deduct from its installed capacity the 

amount of capacity that is committed under a long-term sale, but the seller is presented 

with a Catch-22. The seller cannot enter into a long-term sales contract at market-based 

rates without prior Commission authorization, but the seller cannot pass the applicable 

indicative screens without deducting the amount of the capacity sold under long-term 

contract. Retaining the exemption eliminates this problem and is consistent with 

Commission precedent regarding competitive forward markets.” Id. at 12. 

305 Mirant at 11. 

306 APPA/TAPS reply comments at 17. 
Docket No. RM04-7-000 178 

318. Some commenters contend that the Commission’s concern that over time all 

older generation will be retired and the Commission will be unable to analyze sellers 

for market power is not a valid concern in the immediate or mid-term; they state that 

the most recent retirement announcements concern generation assets that were built 

in the 

1940s and 1950s.307 PPM and Allegheny argue that the Commission offers no evidence 

or observations to quantify the magnitude of future retirements.308 Some commenters 

assert that, in order for this speculative concern to become realistic, the retirement of 

generating units that were constructed in the 1980s would have to become commonplace, 

and it will take decades for this situation to materialize. As such, they suggest that the 

Commission revisit this issue in 5 to 10 years rather than act prematurely.309

319. PPM suggests that, if the Commission wishes to limit the overall amount of 

generation that is exempt for purposes of conducting a horizontal market power 

analysis, an alternative approach would be to keep the exemption and phase in 

exempted units over time. Thus, units that were built after 1996 but before 1999 

 307 Mirant at 10; EPSA at n.2, citing for example: 

http://pjm.com/planning/project-queues/gen-retirements/20060601-pjm-gen-retir-listpublic-future.pdf. 

308 PPM at 6; Allegheny at 8. 

309 EPSA at 15; Mirant at 10. 
Docket No. RM04-7-000 179 

would lose the exemption in 2010, while facilities built in 2001 would lose it in 2015, 

and so on.310 

Commission Determination

320. The Commission adopts the proposal set forth in the NOPR and eliminates the 

exemption provided in § 35.27(a). All sellers seeking market-based rate authority, or 

filing updated market power analyses, on or after the effective date of this Final Rule 

must provide a horizontal market power analysis for all of the generation they own or 

control. As a number of commenters recognize, over time the exemption would 

become too broad and would encompass all market participants as pre-July 9, 1996 

generation is retired. In addition, we note that even assuming for the sake of 

argument that there are not a large number of retirements, the current exemption 

would allow sellers to grow unabated as load increases and could result in such 

sellers gaining a dominant position in the market without being subject to any 

horizontal market power analysis. Thus, continuing the exemption would result in 

unintended consequences where all sellers would be given an automatic presumption 

that they lack market power in generation. Accordingly, the Commission finds that 

eliminating the exemption in § 35.27(a) and requiring every new seller to submit a 

 310 PPM at 6. 
Docket No. RM04-7-000 180 

generation market power analysis will allow the Commission to ensure that the seller 

does not have market power in generation.311

321. We do not believe that this change will have an adverse effect on the majority 

of sellers that have previously relied on the § 35.27(a) exemption. The sellers that 

have taken advantage of the exemption will largely qualify as Category 1 sellers, and 

thus will be unaffected to the extent that they will not be required to file a regularly 

scheduled updated market power analysis. For those sellers seeking market-based 

rate authority for the first time (e.g., building new generation facilities), and those 

that do not qualify as Category 1 sellers, there are several mechanisms or alternatives 

that can help to minimize the burden of submitting a horizontal market power 

analysis. For example, a seller, where appropriate, can make simplifying 

assumptions, such as performing the indicative screens assuming no import capacity 

or treating the host balancing authority area utility as the only other competitor.312 

We expect that, for most sellers, the cost of compliance and document preparation 

occasioned by the elimination of § 35.27(a) will not be burdensome. To the extent 

that there are greater costs for some sellers, we find that the benefit of ensuring that 

markets do not become less competitive over time outweighs any additional costs. 

 311 We note that the Commission may change its policy if it provides, as it does 

here, a reasoned analysis indicating that prior policies are being deliberately changed and 

the basis for that change. E.g., B&J Oil and Gas v. FERC, 353 F.3d 71 (D.C. Cir. 2004). 

312 See April 14 Order, 107 FERC ¶ 61,018 at P 69, 117. 
Docket No. RM04-7-000 181 

Equally important, the elimination of § 35.27(a) will place all sellers on the same 

footing. On this basis, we disagree with commenters that eliminating the exemption 

would send an unfavorable signal to market participants and deter investment. 

322. We also disagree with commenters that find our rationale for adopting the 

exemption in 1996 necessarily constrains our decision making at this time. In light of 

our experience over the past decade and our desire to have a more rigorous marketbased rate program, combined with the concern that over time generation will be 

retired, we believe a more conservative approach for granting market-based rate 

authority is appropriate and will provide us a better means to ensure that customers 

are protected. 

323. We find unpersuasive Mirant’s concern that, if the § 35.27 exemption were 

eliminated, a seller would have to get Commission approval for market-based rate 

sales prior to bidding on an RFP. If Mirant is concerned that certain RFPs require, 

among other things, that all bidders have in place all regulatory requirements 

including any applicable market-based rate authority, we find that RFPs typically 

afford bidders ample opportunity to put together their bids and put in place any 

necessary regulatory approvals. In this regard, we note that if a potential seller 

wishes to participate in an RFP but does not have market-based rate authority, the 

seller can file for such authorization and request expedited treatment and the 

Commission will use its best efforts to process the request as quickly as possible. 

324. With regard to the specific argument raised by Mirant, if a prospective seller 

wins an RFP, then the capacity would be counted as committed capacity, and 
Docket No. RM04-7-000 182 

therefore would not adversely affect the results of the seller’s generation market 

power screen (which analyzes uncommitted capacity). If the entity loses the RFP, 

then it would not build the plant. In either case, the need for market-based rate 

authorization does not appear to discourage new investment by competitive suppliers 

as Mirant suggests. 

325. Some commenters assert that the retirement of generating units that were 

constructed in the 1980s would have to become commonplace before the 

Commission’s concern is realized that over time all older generation will be retired. 

Others contend that it will take decades for this situation to materialize. However, 

commenters have provided no evidence that the elimination of § 35.27(a) will create 

a regulatory barrier to new construction or otherwise depress the building of new 

generation facilities, and we need not wait for an inevitable adverse circumstance to 

materialize. 

326. Finally, we will not implement PPM’s suggestion that we retain the exemption 

and apply a phasing in approach whereby generating units would lose the exemption 

over time based on the date on which the units were built. Such an approach would 

create several “classes” of generation facilities which would result in confusion for 

both the Commission and market participants. This confusion would become more 

acute in situations where market participants may own a number of generating 

facilities located in the same balancing authority area or relevant geographic market, 

each of which may be considered a different “class” of generator in terms of filing 

horizontal market power analyses. Moreover, given the regional review and schedule 
Docket No. RM04-7-000 183 

for updated market power analyses discussed below in this rule, we believe that a 

phased-in approach would become overly problematic and unmanageable for market 

participants as a whole. Therefore, we will not accept PPM’s suggestion. 

b. Grandfathering

Comments

327. EPSA and Mirant suggest grandfathering units for which construction 

commenced between July 9, 1996 and May 19, 2006, the date of issuance of the 

NOPR, when generation owners were put on notice that the Commission was 

considering eliminating the exemption in § 35.27(a).313 Constellation proposes that 

the exemption not be eliminated entirely but be limited to generation with 

construction that commenced on or after July 9, 1996, but before the effective date of 

the Final Rule in this proceeding.314 Constellation and EPSA also contend that this 

would be consistent with the Commission’s prior decision to grandfather from PJM’s 

mitigation any generating units that were built in reliance on the post-1996 

exemption.315 

 313 EPSA at 15; Mirant at 13. 

314 See Constellation at 31; PPL reply comments at 20. 

315 Constellation at 31, citing PJM Interconnection, LLC, 110 FERC ¶ 61,053 at P 

60-62 (grandfathering the exemption from mitigation for generating units for which 

construction commenced on or after the date the exemption became effective and before 

the date when PJM filed its proposal to eliminate the exemption for all generation units) 

(PJM), order on reh’g, 112 FERC ¶ 61,031 at P 38 (2005) (PJM II), order on reh’g, 

114 FERC ¶ 61,302 (2006); EPSA at 16-17. 
Docket No. RM04-7-000 184 

328. Although NASUCA agrees with the Commission’s proposal to eliminate the 

new generator exemption, NASUCA raises a concern about the prospective treatment 

of sellers with generating plants built after July 9, 1996 that initially received marketbased rate authority without any generation market power assessment. NASUCA 

notes that its understanding is that, “the Commission would effectively “grandfather” 

the market-based rate status for owners of these newer power plants,316 at least until 

the time of the next applicable triennial review, when a market power analysis would 

be required for continuation of market-based rate authority.”317 Specifically, 

NASUCA explains that a Category 2 seller who recently obtained market-based rate 

authority, could have up to three years of future market-based rate sales with no 

review of its horizontal market power, while any that fall into Category 1 would be 

exempted entirely from the triennial review process and thus “grandfathered” 

indefinitely and able to sell at market-based rates without passing any market power 

test. If this “grandfathering” is not intended, then, according to NASUCA, the 

 316 NASUCA at 10 n.12, “[T]he Commission would require that all new applicants 

seeking market-based rate authority on or after the effective date of the final rule issued 

in this proceeding, whether or not all of their or their affiliates’ generation was built after 

July 9, 1996, must provide a horizontal market power analysis of their generation.” Citing 

NOPR at P 71 (emphasis added). 

317 Id. at n.13, “[W]ith regard to triennial reviews, the Commission’s proposal to 

eliminate the section 35.27(a) exemption would require that, in its triennial review, a 

seller must perform a horizontal market power analysis of all of its generation regardless 

of when it was built, thus eliminating any special treatment of generation built after 

July 9, 1996.” Citing NOPR at P 72. 
Docket No. RM04-7-000 185 

Commission should clarify that new market power assessments must be made now 

for those sellers whose market power has never been reviewed.318 Otherwise, 

NASUCA contends that their rates could be vulnerable to challenge because they are 

established solely on the basis of market price.319

Commission Determination

329. We will not adopt commenters’ proposals with regard to the grandfathering of 

any generating units that were built relying on the exemption in § 35.27(a). As 

discussed above, we find establishing "classes" of generation facilities would result in 

confusion for both the Commission and market participants. In this regard, no 

commenter has demonstrated that harm would result from having to submit a 

horizontal market power analysis, and no commenter has claimed that it would lose 

its financing or that its financing would be adversely affected as a result of the 

elimination of the exemption in § 35.27(a). Moreover, as the Commission stated in 

Order No. 888, intervenors could present evidence that a seller seeking market-based 

rates for sales from new generation possesses market power, and sellers were aware 

that they may have to submit a horizontal market power analysis even if their 

 318 NASUCA at 10-11. 

319 Id. at 11, citing FPC v. Texaco, Inc., 417 U.S. 380 (1974) (stating that the 

prevailing price in the marketplace cannot be the final measure of just and reasonable 

rates) (Texaco). See also NASUCA reply comments at 7-8 (asserting that for any 

grandfathered sellers the market is the final determinant of price, an impermissible result 

under Texaco.) 
Docket No. RM04-7-000 186 

generation fell within the exemption.320 Therefore, we will require that all sellers 

seeking market-based rate authority for the first time on or after the effective date of 

the Final Rule in this proceeding must provide a horizontal market power analysis 

that includes all generation that the seller owns or controls. 

330. All existing sellers that fall in Category 2 must provide a horizontal market 

power analysis that includes all generation that each seller owns or controls when it 

files its regularly scheduled updated market power analysis. To the extent a Category 

1 seller acquires enough generation to be reclassified as a Category 2 seller, that 

seller will be required to submit a change in status report and provide a horizontal 

market power analysis. 

331. Further, with regard to PJM, in establishing whether units constructed after 

July 9, 1996 should be exempt from PJM’s existing market power mitigation rules, 

we initially approved the post-1996 exemption based on the concern that the price 

cap regulation or the mitigation rules in PJM might deter market entry and would 

create certain equity issues. However, we reconsidered our position and found that 

the exemption was unduly discriminatory by creating two classes of reliability must 

run generators: one that is price or offer capped and another that is not. Equally 

important, other RTOs/ISOs applied local market mitigation rules to all generation 

 320 See Order No. 888-A, FERC Stats.& Regs.Regulations Preambles July 1996-

December 2000 ¶ 31,048 at 30,188 (“[T]he policy eliminates the [generation dominance] 

showing only as a matter of routine in each filing.”) 
Docket No. RM04-7-000 187 

within their respective areas regardless of when the generator was built, and we 

determined that comparable authority for PJM would allow it to address local market 

power issues.321 We concluded that units built on or after July 9, 1996 had the same 

ability to exercise market power as counterparts that were built prior to July 9, 1996. 

Accordingly, the Commission terminated the blanket exemption, but in the case of 

units that were built with the expectation that they would not be subject to mitigation, 

the Commission allowed the exemption to be grandfathered.322

332. Our reasons for grandfathering units in PJM are dissimilar enough that our 

holding in the PJM orders should not affect our decision here. The factors that led to 

the establishment and later the termination of the exemption from mitigation in PJM 

are unrelated to the reasons for instituting and, now, eliminating the express 

exemption in § 35.27(a). In PJM and PJM II, the Commission considered whether 

local market power mitigation might deter new entry and whether new units were 

built with the expectation that they would not be subject to mitigation. The 

Commission grandfathered units that could reasonably have relied on the exemption 

after it went into effect in their zone.323 In contrast, in this proceeding the 

 321 PJM, 110 FERC ¶ 61,053 at P 59. 

322 PJM II, 112 FERC ¶ 61,031 at P 38. 

323 Nevertheless, the Commission stated that the units would still be subject to 

mitigation if PJM or its market monitor concluded that they exercised significant market 

power. Id. at P 60. 
Docket No. RM04-7-000 188 

Commission desires a more rigorous market-based rate program and is concerned that 

over time generation will be retired leaving less and less generation subject to our 

horizontal analysis or sellers relying on the § 35.27 exemption will otherwise grow to 

a degree that they have market power in the relevant market in which they are 

located. The Commission’s primary statutory obligation under FPA sections 205 and 

206 is to ensure that rates are just and reasonable, and we believe the elimination of 

the exemption will better provide us with the ability to screen all market participants’ 

ability to exercise horizontal market power regardless of whether their generation 

units were constructed before or after July 9, 1996. Therefore, we will not allow any 

grandfathering as part of this proceeding. 

333. NASUCA’s concerns regarding entities that originally enjoyed the § 35.27 

exemption are addressed by our decision, discussed below in the Implementation 

Process section of this Final Rule, to require a seller that believes it qualifies as 

Category 1 to make a filing with the Commission at the time that its updated market 

power analysis for the seller’s region would otherwise be due (based on the regional 

schedule set forth in Appendix D). That filing should explain why the seller meets 

the Category 1 criteria and should include a list of all generation assets (including 

nameplate or seasonal capacity amounts) owned or controlled by the seller and its 

affiliates grouped by balancing authority area. Thus, a seller that previously qualified 

for the § 35.27 exemption and that believes it qualifies as a Category 1 seller would 

be required to provide support for its claim to Category 1 status. This filing will give 

the Commission and interested parties an opportunity to review and, if appropriate, 
Docket No. RM04-7-000 189 

challenge a seller’s claim that it qualifies as a Category 1 seller. To the extent that an 

intervenor has concerns about a seller’s potential to exercise market power, the 

Commission will entertain them at that time.324 In addition, a seller that previously 

qualified for the § 35.27 exemption and that believes it qualifies as a Category 2 

seller will be required to file an updated market power analysis based on the regional 

schedule set forth in Appendix D. 

334. While it is true that a portion of these sellers will continue to sell at marketbased rates for a time until their updated market power analyses (in the case of 

Category 2 sellers) or their filings addressing qualification as Category 1 sellers are 

due, no commenter has submitted compelling evidence that Category 1 sellers have 

unmitigated market power. We will rely on our change in status requirements that 

require, among other things, all sellers that obtain or acquire a net increase of 100 

MW in owned or controlled generation to make a filing with the Commission and to 

provide the effect, if any, such an increase in generation has on the indicative screens. 

Additionally, all sellers must file EQRs of transactions no later than 30 days after the 

end of each reporting quarter. Furthermore, the Commission retains the ability to 

require an updated market power analysis from any seller at any time. With these 

procedures in place, we believe NASUCA’s concerns are addressed. 

 324 Moreover, if specific concerns regarding market power exist, interested persons 

may file a complaint pursuant to FPA section 206. 
Docket No. RM04-7-000 190 

c. Creation of a Safe Harbor

Comments

335. NRG urges the Commission to create a “safe harbor” such that “if the 

generation owner controls less than 20 percent of the capacity in an organized market, 

the Commission should irrebuttably presume that the new entry will not contribute to 

market power and thus no demonstration is required to obtain market-based rate 

authority for the new capacity.”325 NRG states that only where an owner controls 

more than 20 percent of capacity in a relevant market should the presumption be 

rebuttable and subject to challenge by intervening parties. It is NRG’s contention that 

the creation of such a “safe harbor” retains most of the benefits of the Commission’s 

current policy under § 35.27(a), while preserving its flexibility to investigate where a 

seller adding generating capacity already has a large market share. NRG believes that 

this codifies the general approach the Commission took in Order No. 888326 and 

 325 NRG at 5 & n.8, suggesting that the use of a 20 percent market share in the safe 

harbor proposal replicates one of the two screens that the Commission proposes in the 

NOPR to use as a general screen for market power in all markets reviewed for marketbased rate authority. NRG argues that a 20 percent market share screen is wellestablished and appropriate for use in reviewing the market power implications 

associated with the addition of new generation. The use of a lightened, single screen 

approach to review the market power implications of new generation is appropriate, 

argues NRG, in that new generation expands the supply available in a market. According 

to NRG, for organized markets administered by RTOs that have in place Commissionapproved market monitoring and mitigation authority, subjecting new generation only to 

a 20 percent market share screen is appropriate in light of the existing controls over the 

exercise of market power. 

326 Id. at n.9, citing Order No. 888, FERC Stats. & Regs. Regulations Preambles 

 (continued...) 

 
Docket No. RM04-7-000 191 

responds to the Commission’s evolving concerns in this area, while at the same time 

facilitating new entry in the organized markets where sufficient safeguards exist.327 

NRG contends that new generation, timely developed and brought online, is 

imperative; thus, a “safe harbor” for new generation is necessary. 

336. Ameren agrees that there is a need for the Commission to address the § 35.27 

exemption before it encompasses all generating capacity, however, Ameren submits 

that the Commission should allow an exemption for new generation under certain 

circumstances. Ameren argues that “the Commission should amend its regulations to 

provide that new generation that represents less than 20 percent of the uncommitted 

capacity at peak in the relevant geographic market be exempt from the requirement of 

a horizontal market power analysis, so long as the owner of, or entity that controls, 

such capacity and its affiliates own no other generation or transmission facilities 

(other than interconnection facilities) in the relevant market.”328 Ameren submits that 

the Commission should allow the seller to file a letter which identifies: (1) the 

transmission system it is interconnected to; (2) the amount of uncommitted capacity it 

 

January 1991-June 1996 ¶ 31,036 at 31,657. 

327 Id. at n.10. Under NRG’s proposal, the Commission would also need to apply 

the safe harbor analysis to the notice of change of status for the suppliers’ existing 

generation, when the notice of change is triggered by the addition of new generation 

capacity. Failure to do so would mean the lightened review appropriate for new 

generation would not, in effect, produce the intended lessening of regulatory burden. 

328 Ameren at 7-8. 
Docket No. RM04-7-000 192 

controls; and (3) the Commission-approved market power study that it relied on to 

determine that its uncommitted capacity is less than twenty percent of the net 

uncommitted capacity in the relevant geographic market. Ameren contends that this 

abbreviated process would reduce a seller’s cost of compliance and administrative 

burdens.329

Commission Determination

337. The Commission will not create a safe harbor.330 For the reasons set forth in 

the April 14 Order and reiterated in the July 8 Order, there will be no safe harbor 

exemption from the generation market power screen based upon a seller’s size.331 

While there is no safe harbor exemption from the screens based on the seller’s size, 

any seller, regardless of size, has the option of making simplifying assumptions in its 

analysis where appropriate that do not affect the underlying methodology utilized by 

these screens. 

338. Further, while we eliminate the § 35.27 exemption in this Final Rule, we note 

that sellers that have enjoyed that exemption historically have been required to 

 329 Id. 

330 We note that although Category 1 sellers are not required to provide a regularly 

scheduled updated market analysis, such an approach does not establish a safe harbor 

because all sellers will be required to perform the indicative screens as part of their initial 

applications, make change in status filings and file EQRs. 

331 See April 14 Order, 107 FERC ¶ 61,018 at P 69, 117; July 8 Order, 108 FERC 

¶ 61,026 at P 107 (the Commission explained that small sellers are able to use 

simplifying assumptions). 
Docket No. RM04-7-000 193 

address the other parts of the market-based rate analysis, vertical market power, 

affiliate abuse, and other barriers to entry.332 Therefore, the Commission believes 

that, on balance, any additional cost of compliance or administrative burden due to 

this change will not be substantial compared to a seller’s investment and revenues.333 

11. Nameplate Capacity

Commission Proposal

339. In the NOPR, the Commission proposed to allow sellers the option of using 

seasonal capacity instead of nameplate capacity, as is currently required. The 

Commission indicated that the seller must be consistent in its choice and thus must 

choose either seasonal or nameplate capacity and use it consistently throughout the 

analysis. The Commission stated that it believed the use of seasonal capacity ratings 

more accurately reflects the seasonal real power capability and is not inconsistent 

with industry standards and, therefore, it may be more convenient for sellers to 

acquire and compile the associated data. The Commission added that it did not think 

the use of such ratings will materially impact results. The Commission sought 

comment on this proposal, including comment as to whether this information is 

publicly available to all market participants. 

 332 As described in this Final Rule, we consolidate the transmission market power 

and other barriers to entry analyses into one vertical market power analysis. In addition, 

we discontinue considering affiliate abuse as a separate part of the analysis and instead 

codify affiliate restrictions in our regulations. 

333 NOPR at P 71. 
Docket No. RM04-7-000 194 

Comments

340. Many commenters on this topic express strong support for the proposal to 

substitute seasonal capacity for nameplate capacity.334 The reason most commonly 

cited is that seasonal capacity is a more accurate representation of actual output. 

Several commenters state that firms should be allowed to use net seasonal 

capacity,335 which allows for station service requirements and energy consumed by 

environmental equipment. MidAmerican points out that station usage, including 

environmental equipment, can approach 10 percent of overall output in steam 

plants.336 EEI states that coal plants, which make up 51 percent of generation in the 

United States, are required to comply with both federal and state regulations that 

mandate emission reductions. The plants are equipped with scrubbers and other 

emissions reduction technology that require a portion of the power produced by the 

plant in order to operate, thereby reducing the output available to serve customers. 

For companies with a large percentage of their generation coming from coal, the 

reduced output from such equipment could be significant.337 PG&E favors using 

 334 Duke at 22; First Energy at 10; Southern at 26; SoCal Edison at 8. 

335 EEI at 18; PNM/Tucson at 10; Allegheny at 7-8; Pinnacle West at 5-6; PPL at 

17. 

336 MidAmerican at 8. 

337 EEI at 18. 
Docket No. RM04-7-000 195 

seasonal capacity if it could be filed confidentially, because it maintains that it is 

commercially sensitive information.338 

341. PG&E requests clarification that if sellers are allowed to submit seasonal 

capacity, they are allowed to de-rate hydroelectric capacity resources based on 

historical output for the past five years, as specified in the April 14 Order.339 

Powerex supports seasonal ratings as more accurate, because hydroelectric systems 

are often able to generate in excess of nameplate ratings and these “peak capability” 

ratings are typically reflected in seasonal determinations, and seasonal ratings better 

reflect operating conditions that can impact the capacity ratings of renewable 

resources. 340 

342. APPA/TAPS support the adoption of seasonal capacity ratings if they are 

consistently used, and request that the Commission clarify that the seasonal capacity 

ratings be used for all plants in a geographic region “so that the consistency benefits 

of the regional reviews are not diminished.”341 

 338 PG&E at 10-11. 

339 April 14 Order, 108 FERC ¶ 61,018 at P 126. The July 8 Order allowed this 

method to be used for wind resources as well. July 8 Order, 108 FERC ¶ 61,026 at P 

129. 

340 Powerex at 20. 

341 APPA/TAPS at 35. 
Docket No. RM04-7-000 196 

Commission Determination

343. We will adopt the NOPR proposal that allows sellers to use seasonal capacity. 

We clarify that each seller must be consistent in its choice and thus must choose 

either seasonal or nameplate capacity and use it consistently throughout the analysis. 

In addition, a seller using seasonal capacity must identify in its submittal from what 

source the data was obtained.342 We also note and adopt the Energy Information 

Administration (EIA) definition of seasonal capacity as it is reported on Form EIA860, Schedule 3, Part B, Line 2, which provides that seasonal capacity is the "net 

summer or winter capacity."343 EIA instructions elaborate that "net capacity should 

reflect a reduction in capacity due to electricity use for station service or 

auxiliaries,"344 which includes scrubbers and other environmental devices. 

344. With regard to energy-limited resources, such as hydroelectric and wind 

capacity, in lieu of using nameplate or seasonal capacity in their submissions, we will 

allow such resources to provide an analysis based on historical capacity factors 

 342 In the July 8 Order, the Commission stated that “[w]ith respect to data that is 

only available from commercial sources, we clarify that commercial sources may be used 

to the extent the data is made available to intervenors and other interested parties. 

Applicants utilizing commercial information to perform the screens should include it in 

their filing.” July 8 Order, 108 FERC ¶ 61,026 at P 121. 

343 EIA-860 Instructions are available at 

http://www.eia.doe.gov/cneaf/electricity/forms/eia860/eia860.pdf 

344 Tip Sheet for Reporting on Form EIA-860, “Annual Electric Generator Report” 

at item "III. Schedule 3B, Line 2 and Schedule 3D, Line 2: Net Capacity" available at 

http://www.eia.doe.gov/cneaf/electricity/forms/eia860/tipsheet.doc 
Docket No. RM04-7-000 197 

reflecting the use of a five-year average capacity factor including a sensitivity test 

using the lowest capacity factor in the previous five years, and in recognition of 

Powerex’s concern that hydroelectric systems can generate in excess of nameplate 

ratings and these “peak capability” ratings, the highest capacity factor in the previous 

five years. Our approach in this regard will more accurately capture hydroelectric or 

wind availability.345 

345. We will not adopt APPA/TAPS’ suggestion that we require use of either 

nameplate capacity or seasonal capacity throughout a region. While we appreciate 

APPA/TAPS’ concern for data consistency for analysis purposes, we note that 

although we adopt a regional approach for the filing of updated market power 

analyses, the horizontal market power analysis itself continues to focus on the seller 

seeking to obtain or retain market-based rate authority. We find that consistency of 

data is critical within each individual analysis as results could vary depending on the 

assumptions taken. However, because we are not necessarily analyzing the entire 

region within a single study, we will not mandate the use of either nameplate capacity 

 345 In the April 14 Order, we explained that commenters expressed concerns 

regarding the appropriate measure of the capacity of hydroelectric units given that 

hydroelectric facilities are energy-limited units. Our experience with Western markets 

shows that market outcomes can be significantly different during low water years. We 

agree with the comments raised by Western market participants and conclude that 

properly accounting for water availability will provide a better picture of competitive 

conditions in the West. Moreover, while not as critical in other parts of the country as in 

the West, the same principle regarding water availability applies to all electricity markets, 

and we will permit all sellers to de-rate hydroelectric capacity in the analysis. 
Docket No. RM04-7-000 198 

or seasonal capacity on a regional basis, but instead will allow sellers to choose either 

nameplate or seasonal capacity, and require them to identify the choice and use it 

consistently throughout the analysis.346 

12. Transmission Imports

346. In the NOPR, the Commission proposed to continue to measure limits on the 

amount of capacity that can be imported into a relevant market based on the results of 

a simultaneous transmission import capability study. A seller that owns, operates or 

controls transmission is required to conduct simultaneous transmission import 

capability studies for its home control area and each of its directly-interconnected 

first-tier control areas consistent with the requirements set forth in the April 14 Order, 

as clarified in Pinnacle West Capital Corp.347 These studies are used in the pivotal 

supplier screen, market share screen, and DPT to approximate the transmission 

import capability. When centering the generation market power analysis on the 

transmission providing utility’s first-tier control area (i.e., markets), the transmissionproviding seller should use the methodologies consistent with its implementation of 

its Commission-approved OATT, thereby making a reasonable approximation of 

simultaneous import capability that would have been available to suppliers in 

 346 When submitting a change in status filing regarding horizontal market power, 

sellers should use the same assumptions they used (e.g., use of nameplate or seasonal 

ratings) in their most recent market power analysis. 

347 110 FERC ¶ 61,127 (2005). 
Docket No. RM04-7-000 199 

surrounding first-tier markets during each seasonal peak. The transfer capability 

should also include any other limits (such as stability, voltage, Capacity Benefit 

Margin, or Transmission Reliability Margin) as defined in the tariff and that existed 

during each seasonal peak. The “contingency” model should use the same 

assumptions used historically by the transmission provider in approximating its 

control area import capability. 

347. The Commission also proposed to reaffirm the exclusion of control areas that 

are second-tier to the control area being studied. In addition, it proposed that a 

seller’s pro rata share of simultaneous transmission import capability should be 

allocated between the seller and its competitors based on uncommitted capacity. The 

Commission sought comment on this proposal. 

a. Use of Historical Conditions and OASIS Practices 

Comments

348. Montana Counsel states that transmission capability used in the tests should 

not be greater than the capability measures that are shown on the OASIS or that are 

used to measure ATC into markets unless there is a demonstrated change in available 

transmission capability.348 In particular, Montana Counsel states that the 

Commission’s requirement that sellers follow historical OASIS practice during each 

historical seasonal peak is essential; otherwise, companies could submit screens using 

 348 Montana Counsel at 4. 
Docket No. RM04-7-000 200 

transmission availability numbers that differ substantially from those which sellers 

and transmission providers use in day-to-day activities in providing transmission 

market access.349 In Montana Counsel’s view, one cannot rely on capacity being able 

to reach a market based upon hypothetical transmission availability, as the 

Commission appropriately recognizes. 

349. In response to Montana Counsel’s assertion to use OASIS postings, PPL 

Companies maintain that the Commission should continue to use simultaneous import 

limit studies. OASIS postings do not adjust for transmission rights controlled by 

unaffiliated resources that may be used to compete against the seller in wholesale 

markets. PPL Companies state: “The Commission should reject this proposal and 

continue to rely on [SILs]. The Commission properly has found that using actual 

OASIS postings understates import capability because OASIS postings do not take 

into account the capacity that may be imported as a result of existing reservations.”350

350. EEI and Southern request clarification of a perceived conflict in Appendix E, 

which instructs sellers to use Commission criteria for calculating simultaneous import 

capability and also to strictly follow their OASIS practices.351 They recommend that 

the Commission clarify that if historical practices are different from Appendix E, 

 349 Id. at 14. 

350 PPL Companies reply comments at 9-11. 

351 EEI at 27-29; Southern at 32. 
Docket No. RM04-7-000 201 

historical practices should be used to calculate simultaneous transmission import 

capability and to allocate this transmission capability. 

351. Duke asserts that scaling methods for calculating simultaneous transmission 

import capability should not be solely limited to historical practices used by the seller 

to post ATC on OASIS. Duke proposes a collaborative method involving the seller 

and transmission customers. Duke states: "the Commission should allow applicants 

flexibility to use the appropriate methodology for SIL determinations including 

collaborative, regional efforts – so that screen results for control area markets can be 

accurate. For example, the Commission should not be overly prescriptive as to the 

scaling methodology to be used in such a collaborative effort, as long as the 

methodology is clearly defined and supported by the applicants."352 PPL Companies 

support the collaborative effort proposed by Duke, stating that sellers should have 

“the option of proposing alternative [SILs] for first-tier markets, but would have to 

justify and document the proposed deviations.”353

352. Southern states that the SIL study requires “blind” scaling (scaling that does 

not consider economic dispatch) because only generation that is “on-line” is used. 

Southern states that to the extent a transmission provider does not customarily 

employ blind scaling, its use would not be consistent with historical practice. It 

 352 Duke at 27-28. 

353 PPL Companies reply comments at 9-11 
Docket No. RM04-7-000 202 

asserts that a problem with blind scaling is that it does not necessarily reflect reality 

and therefore has the potential to understate, perhaps significantly, the simultaneous 

import limit.354 EEI seeks clarification that the Commission is not requiring blind 

scaling in a manner that requires proportionate increases and decreases to generation 

resources. EEI requests clarification that scaling is allowed to include expert 

judgment reflecting how generation resources would likely be scaled up or down in a 

real-time operating environment. EEI contends that expert judgment in some cases 

may determine simultaneous import capability by scaling load rather than generation 

resources. EEI requests that the Commission defer to expert judgment in scaling and 

not be overly prescriptive as to whether generation or load is scaled to determine 

simultaneous import capability.355 

353. PPL Companies contend the simultaneous import capability should not be 

limited by load in a control area. Since generators within the control area may sell 

power within or outside the control area, the Commission should consider the market 

prices of surrounding regions. If the prices are 105 percent or less, compared to 

control area prices, then the Commission should assume the resident control area 

 354 Southern at 35 and 36. 

355 EEI at 24. 
Docket No. RM04-7-000 203 

resources will remain within the control area and not result in economic withholding 

within the seller’s area.356

Commission Determination 

354. The Commission will continue to require sellers to submit the Appendix E 

analysis, i.e., the SIL study, to calculate aggregated simultaneous transfer capability 

into the balancing authority area being studied.357 The Commission reaffirms that the 

SIL study is “intended to provide a reasonable simulation of historical conditions”358

and is not “a theoretical maximum import capability or best import case scenario.”359 

To determine the amount of transfer capability under the SIL study, “historical 

operating conditions and practices of the applicable transmission provider (e.g., 

modeling the system in a reliable and economic fashion as it would have been 

operated in real time) are reflected.”360 In addition, the “analysis should not deviate 

from” and “must reasonably reflect” its OASIS operating practices361 and “the 

 356 PPL Companies at 8. 

357 Benefits of using a uniform transmission import model include: transparency, 

consistency, clarity, and reasonable assurance that system conditions have been 

adequately captured. 

358 In this regard, actual flows during the study periods may be used as a proxy for 

the simultaneous transmission import limit. 

359 NOPR at P 77. 

360 Id.

361 By OASIS practices, we mean sellers shall use the same OASIS methods and 

studies used historically by sellers (in determining simultaneous operational limits on all 

 (continued...) 

 
Docket No. RM04-7-000 204 

techniques used must have been historically available to customers.”362 We also 

reaffirm that the power flow cases (which are used as inputs to the SIL study) should 

represent the transmission provider’s tariff provisions and firm/network reservations 

held by seller/affiliate resources during the most recent seasonal peaks.363 

355. The Commission will also continue to allow sensitivity studies, but the 

sensitivity studies must be filed in addition to, and not in lieu of, an SIL study. We 

clarify that sensitivity studies are intended to provide the seller with the ability to 

modify inputs to the SIL study such as generation dispatch, demand scaling, the 

 

transmission lines and monitored facilities) to estimate import limits from aggregated 

first-tier control areas into the study area. In this sense, sellers are modeling first-tier 

balancing authority areas as if they are the transmission operator/security coordinator 

(monitoring reliability) operating an OASIS for the aggregated first-tier footprint. We 

recognize that sellers are not the balancing authority area operators of first-tier balancing 

authority areas and in some instances, sellers may not be familiar with all aspects of their 

first-tier balancing authority areas' transmission system limits. However, sellers should 

be familiar with major constraints, path limits, and delivery problems in these 

neighboring transmission systems. If a seller participates in regional planning studies and 

day-to-day coordination with neighboring first-tier balancing authority areas then this 

will provide a reasonable basis for including transmission system constraints of first-tier 

balancing authority areas in SIL study calculations. In using OASIS practices the SIL 

study shall capture real-life physical limitations of first-tier balancing authority areas that 

impede power flowing from remote first-tier resources into the seller’s study. 

362 Id. at P 77, 78. 

363 Network reservations include any grandfathered transmission rights applicable 

to the seller or its affiliated companies. 
Docket No. RM04-7-000 205 

addition of new transmission and generation facilities (and the retirement of 

facilities), major outages, and demand response.364

356. The Commission agrees with Montana Counsel and clarifies for PPL 

Companies that a SIL study must reflect transmission capability no greater than the 

capability measures that were historically shown on the OASIS or that were 

historically used to measure transmission capability into markets unless there is a 

demonstrated change in transmission capability, and account for the actual practice of 

posting ATC to OASIS in order to capture a realistic approximation of first-tier 

generation access to the seller’s market. Further, and in response to EEI and 

Southern’s comments, the Commission clarifies that when actual OASIS practices 

conflict with the instructions of Appendix E, sellers should follow OASIS practices 

and must provide adequate support in the form of documentation of these processes. 

357. We disagree with Duke's argument that a seller's (generation or load) scaling 

methods should not be limited to historical OASIS practices when conducting an SIL. 

Using historical practices provides an appropriate method to obtain a transparent and 

measurable analysis of a seller's actual balancing authority area transmission 

conditions and practices. Improper or theoretical scaling methods which do not 

represent a seller’s actual transmission practices may have the effect of allowing 

 364 We note that several sellers from the Western Interconnection have relied on 

Western Electricity Coordinating Council (WECC) path ratings for their SIL studies. 

The Commission has accepted these ratings when sellers have demonstrated that they are 

simultaneously feasible and take into account any interdependencies between paths. 
Docket No. RM04-7-000 206 

more competing generation into the balancing authority area than could actually be 

accommodated. This in turn has the effect of reducing a seller's generation market 

share and perhaps causing the seller to inappropriately pass the market share screen (a 

false negative).365 In addition, relying on historical OASIS practices gives a seller 

the data needed to support its conclusions. 

358. With regard to Duke and PPL's request that the Commission allow sellers to 

submit a flexible SIL study based on regional collaboration, the Commission finds 

that such an approach does not satisfy our concerns and may result in an unrealistic 

representation of the market. 

359. Southern states that to the extent a transmission provider does not customarily 

employ blind scaling, its use would not be consistent with historical practice. 

We agree and, as noted herein, the horizontal analysis and the SIL study are designed to 

study historical and realistic conditions during peak seasons. Accordingly, in this 

circumstance, sellers should follow their OASIS practices and must provide adequate 

support in the form of documentation of these processes. 

360. With regard to EEI's argument that the Commission should consider allowing 

expert judgment in predicting real-time scaling techniques that will likely be used in 

real-time market environments, the Commission requires the use of a study that 

captures historical transmission operating practices. The SIL study is not a prediction 

 365 See, e.g., Pinnacle West Capital Corp., 117 FERC ¶ 61,316 (2006). 
Docket No. RM04-7-000 207 

of import possibilities; rather, it is a simulation of historical conditions. We assume 

that such historical conditions are the result of "expert judgment" used when 

determining generation dispatch and/or scaling techniques to make transmission 

capacity available during actual system conditions. Accordingly, this expert 

judgment is captured when conducting an SIL study that is based on historical 

operating practices. 

361. In response to PPL’s comments that the SIL should not be limited by load in a 

balancing authority area, the Commission reiterates that the SIL study is a benchmark 

of historical conditions, including peak load. It is a study to determine how much 

competitive supply from remote resources can serve load in the study area. 

Increasing the load in the study area beyond historical peak levels makes the study 

less realistic and can bias the study.366 The Commission does, however, consider 

sensitivity studies on a case-by-case basis, when submitted in addition to the SIL 

study and supported by record evidence. For example, in Puget Sound Energy, Inc.'s 

(Puget) updated market power analysis filing, Puget demonstrated that the 

simultaneous transmission import limit was greater than the peak load in its balancing 

 366 We note that there may be a circumstance where additional supplies could be 

imported above the market's study year peak load. If such a circumstance occurs, we will 

allow the seller to submit a sensitivity analysis in this regard and we will consider such an 

analysis on a case-by-case basis. 
Docket No. RM04-7-000 208 

authority area, and the Commission allowed Puget to use a simultaneous transmission 

import limit based on its peak load.367 

362. PPL also contends the simultaneous import capability should not be limited by 

load in a balancing authority area since generators within the balancing authority area 

may sell power within or outside the balancing authority area. Accordingly, PPL 

believes that the Commission should consider the market prices of surrounding 

regions. The Commission disagrees. We base the SIL on historical conditions that 

actually existed during the study periods. In this regard, PPL has provided no 

compelling reason for the Commission to abandon historical evidence in favor of a 

theoretical estimation of what could have occurred. We find that PPL’s approach 

would make the studies more subjective and thus less accurate and more prone to 

dispute and controversy. 

b. Use of Total Transfer Capability (TTC)

Comments

363. Southern asserts that the Commission’s assumption that all TTC values posted 

on OASIS platforms are non-simultaneous is not correct. Southern states that 

although many TTC values may be calculated on a point-to-point non-simultaneous 

basis, some TTC values are simultaneous, thus accounting for "loop flow" created by 

other paths. Southern contends that those transmission providers that post 

 367 Puget Sound Energy, Inc., 111 FERC ¶ 61,020 at P 13 (2005). 
Docket No. RM04-7-000 209 

simultaneous TTC values on OASIS should have the flexibility to add these TTC 

values to calculate simultaneous transmission import capability for the control area. 

Southern believes that conflicts can occur between the generic methods presented in 

the Appendix E interim market screen order and actual OASIS practices used by 

transmission providers to post TTC. 

Commission Determination

364. Southern’s suggestion that the Commission allow the use of simultaneous TTC 

values is consistent with the SIL study provided that these TTCs are the values that 

are used in operating the transmission system and posting availability on OASIS. 

The simultaneous TTCs368 must represent more than interface constraints at the 

balancing authority area border and must reflect all transmission limitations within 

the study area and limitations within first-tier areas. The source (first-tier remote 

resources) can only deliver power to load in the seller's balancing authority area if 

adequate transmission is available out of its first-tier area, adequate transmission is 

available at the seller’s balancing authority area interface, and transmission is 

internally available. Thus, the TTC must be appropriately adjusted for all applicable 

(as discussed below) firm transmission commitments held by affiliated companies 

that represent transfer capability not available to first-tier supply. Sellers submitting 

simultaneous TTC values must provide evidence that these values account for 

 368 The simultaneous TTCs include seller’s balancing authority area and 

aggregated first-tier areas. 
Docket No. RM04-7-000 210 

simultaneity, account for all internal transmission limitations, account for all external 

transmission limitations existing in first-tier areas, account for all transmission 

reliability margins, and are used in operating the transmission system and posting 

availability on OASIS. 

c. Accounting for Transmission Reservations

Comments

365. Duke and EEI propose that short-term firm reservations should not be 

subtracted from simultaneous import limits because longer firm reservation requests 

can displace control of these transmission holdings.369 EEI explains, “it is 

inappropriate to net out transmission capacity that is not reserved to commit longterm generation resources to load. Short-term firm transmission reservations, some 

as short as one week in duration, provide flexibility to the market and will not 

necessarily persist for the duration, or even large portions, of the MBR authorization 

period. Therefore, they should not be used to reduce the estimate of simultaneous 

import capability."370 

366. Southern agrees, referring to the nature of short-term reservations as “transient 

and unpredictable.”371 Southern states: "In most cases, short-term purchases by the 

applicant essentially allow the market to provide generation within the applicant’s 

 369 Duke at 26-29. 

370 EEI at 25-26. 

371 Southern at 36-37. 
Docket No. RM04-7-000 211 

control area instead of the applicant utilizing its ‘owned’” generation capacity. 

Alternatively, the associated import capability is released to the market. In either 

case, these short-term reservations should not be used to inflate artificially the 

applicant’s market share in conjunction with a screen or DPT evaluation."372

367. APPA/TAPS state that the Commission should revisit the treatment of firm 

transmission reservations held by third parties. In the July 8 Rehearing Order (at P 

49), the Commission stated that the SIL study assumed that “all reservations 

historically controlled by non-affiliates would have been used to compete to inject 

energy into the transmission provider’s control area market if market power or 

scarcity was driving market prices above other regional prices.” However, if the 

holder of the reservation is using the transfer capability to serve its own load, it will 

not be available to third parties to respond to a price increase on the part of the 

transmission provider/sellers. APPA/TAPS state that presumably the capacity 

resources associated with the import will be reflected in the capacity total of the party 

that controls the resource’s output. Excluding the transfer capability associated with 

the resource will not result in a double-deduction. Rather, failing to exclude the 

transfer capability will result in a double-counting of competing supply. Thus, 

 372 Id. at 37. 
Docket No. RM04-7-000 212 

APPA/TAPS assert that the Commission should revise the treatment of transfer 

capability held by third parties on a firm basis.373

Commission Determination

368. The Commission agrees with Duke, EEI and Southern that short-term firm 

reservations can be unpredictable, driven by real time system conditions, and do not 

necessarily indicate that the associated transmission capacity is not available for 

competing supplies (or to import seller’s supplies during the study periods). 

Accordingly, we conclude that, in calculating simultaneous transmission import 

limits, short-term firm reservations of 28 days or less in effect during the study 

periods need not be accounted for.374 While we find that firm transmission 

reservations less than or equal to 28 days in duration are usually unpredictable, we 

believe that firm transmission reservations of a longer duration are not related to the 

unpredictable nature of real time events and are based upon planned and predictable 

 373 APPA/TAPS at 53. 

374 We understand that short-term firm reservations are often used for 

unpredictable events and real-time system conditions. We note that most unpredictable 

conditions that sellers hold short-term firm reservations for, including generator forced 

outages and weather events, are less than one month in duration. Accordingly, we will 

allow applicants to not account for short-term firm reservations of one month or less, and 

since the shortest month is 28 days long, we are setting this limit at 28 days. Any firm 

reservation longer than 28 days in duration must continue to be accounted for in the SIL 

study. 
Docket No. RM04-7-000 213 

events. Therefore, the Commission will require sellers to account for firm and 

network transmission reservations having a duration of longer than 28 days.375

369. With regard to APPA/TAPSs’ concern, we clarify that the seller’s firm, 

network, and grandfathered transmission reservations longer than 28 days, including 

reservations for designated resources to serve retail load, shall be fully accounted for 

in the simultaneous import limit study. We further clarify that reservations held by 

third parties to import power into the seller’s home area should be accounted for by 

allocating transmission import capability to those parties, and then allocating the 

remaining SIL pro rata. 

d. Allocation of Transmission Imports based on Pro Rata Shares of 

Seller's Uncommitted Generation Capacity

Comments

370. Duke and EEI support the Commission proposal to allocate imports on a pro 

rata basis into a study area based on uncommitted capacity in surrounding areas.376 

371. However, Powerex expresses concern that pro rata allocation of uncommitted 

capacity is not a realistic representation of the physical capability of the system, since 

pro rata allocation assumes that the system can import up to the simultaneous import 

limit over any combination of transmission paths. Powerex argues that, in reality, 

 375 The simultaneous import limit study must account for short-term firm 

transmission rights including point-to-point on-peak/off-peak transmission reservations 

(firm or network transmission commitments) which have been stacked, or successively 

arranged, into an aggregated point-to-point transmission reservation longer than 28 days. 

376 Duke at 26-29, EEI at 25-26. 
Docket No. RM04-7-000 214 

some paths become constrained before others, so the allocation of import capability 

should take account of the physical limitations of the transmission system. Powerex 

asks that the Commission allow sellers to use allocation methods that are consistent 

with physical system limitations, where sellers provide documentation showing that 

the allocation methods used in the screens are realistic or conservative.377 

372. Morgan Stanley asks the Commission to clarify its proposal of allocating 

transmission imports pro rata between the seller and its competitors based on 

uncommitted capacity. Morgan Stanley wonders if the Commission made a 

typographical error and intended to propose an allocation based on committed 

capacity. Morgan Stanley believes only the transmission provider (seller) would have 

uncommitted capacity.378

Commission Determination

373. The Commission agrees with Duke and EEI that the current practice of 

allocating simultaneous import capability pro rata to sellers based on uncommitted 

capacity should be continued.379 However, some clarification may be helpful. 

 377 Powerex at 24-25. 

378 Morgan Stanley at 15. 

379 Allocation of the simultaneous transmission import capability, into the seller’s 

market, to affiliated and unaffiliated uncommitted first-tier generation is done in the 

indicative screen, after conducting the SIL study, in order to estimate uncommitted 

capacity market shares from first-tier balancing authority areas. 
Docket No. RM04-7-000 215 

374. Powerex raises concern over the pro rata allocation of uncommitted generation 

capacity and asserts that this is not a realistic representation of the physical capability 

of the system since pro rata allocation assumes that the system can import up to the 

simultaneous import limit over any combination of transmission paths. In this regard, 

we note that pro rata allocation of transmission capacity based on first-tier 

uncommitted generation capacity is an approximation and is consistent with the 

manner in which we conduct the SIL study. In particular, when determining the 

simultaneous import limit, first-tier balancing authority areas are combined into a 

single area. The import capability of the study area is the simultaneous transfer limit 

from the aggregated first-tier market area into the study area.380 We then allocate 

imports based on transmission capacity (limited by the physical capabilities of the 

transmission system as determined by the SIL 

study) pro rata based on sellers' first-tier uncommitted generation capacity.381 We 

recognize that such an approximation may not fit all cases. Accordingly, with regard to 

allocating transmission imports, sellers can submit additional sensitivity studies based on 

factors suggested by Powerex, and intervenors may rebut the allocations of import 

 380 April 14 Order, 107 FERC ¶ 61,018 at Appendix E. 

381 The SIL study also accounts for transmission reservations when determining 

the amount of imports available to reach the study area as discussed herein and in the 

April 14 and July 8 Orders. 
Docket No. RM04-7-000 216 

capability made by seller. The Commission will consider such arguments on a case-bycase basis. 

375. Morgan Stanley asks if the Commission made a typographical error and 

intended to propose an allocation based on committed capacity rather than 

uncommitted capacity. The Commission clarifies that pro rata allocation is used to 

assign shares of simultaneous transmission import capability to uncommitted 

generation capacity in the aggregated first-tier balancing authority areas to determine 

how much uncommitted generation capacity can enter the study area. Morgan 

Stanley appears to confuse our use of the term uncommitted capacity, apparently 

believing we are referring to uncommitted transmission capacity. That is not the case 

as we are referring to uncommitted generation capacity. The reason the use of 

uncommitted generation capacity is appropriate is because our screens analyze 

seller’s relative uncommitted generation capacity rather than installed generation 

capacity or, as suggested by Morgan Stanley, committed generation capacity. In 

particular, the SIL study determines the amount of simultaneous transmission 

capacity available to be imported by competing supplies from remote resources in 

first-tier markets. The supplies that are available to be imported and thus compete are 

necessarily “uncommitted.” Further, it is our experience that uncommitted generation 

capacity can be held by any number of market participants based on market 

conditions at a given time. In other words, we do not agree with an assumption that 

the transmission provider is likely to be the only market participant with uncommitted 

power supplies.
Docket No. RM04-7-000 217 

e. Miscellaneous Comments 

Comments 

376. PG&E states that RTOs/ISOs having knowledge and control over the entire 

control area are best suited to perform SIL studies. PG&E requests that the 

Commission allow an exemption where, in the absence of an accepted SIL study by 

an RTO/ISO, the seller may substitute historical import levels in place of the SIL 

study. In addition, PG&E requests that the Commission confirm that sellers that pass 

screens for each 

relevant geographic market without considering imports need not provide a simultaneous 

import analysis.

382

377. Powerex has concerns about how feasible it is for marketers to obtain nonpublic data from their transmission provider that is needed to conduct a screen (e.g., a 

SIL study) on their own. Powerex notes that Bonneville Power Administration 

(BPA) and Northwest Power Pool (NWPP) do not, as a practice, conduct and post 

simultaneous transmission import capability studies. Therefore, Powerex asserts that 

 382 PG&E at 11-12. PG&E also requests that the Commission clarify how to 

perform the simultaneous import limitation to avoid the need for repetitive studies. 

However, PG&E did not specify what clarification was sought in this regard. 
Docket No. RM04-7-000 218 

the Commission should maintain the current flexibility of allowing marketers to 

submit credible proxy study calculations based on publicly available information.383

Commission Determination

378. The Commission will continue to require the SIL study for the indicative 

screens and DPTs in order to assure that restrictions regarding importing first-tier 

supply are captured for seasonal peak conditions. Benefits of using a uniform 

transmission import model include: transparency, consistency, clarity, and 

reasonable assurance that system conditions have been adequately captured. As also 

stated above, the Commission provides sellers flexibility to provide sensitivity 

analyses by modifying inputs to the SIL study. 

379. In regard to PG&E's belief that RTOs/ISOs are best equipped to conduct SIL 

calculations, the Commission will continue to require transmission-providing sellers 

to perform the SIL studies as necessary. To the extent that an RTO/ISO conducts 

transmission studies and makes that information available, a seller may rely on the 

information obtained from its RTO/ISO to conduct its SIL study. Further, the 

Commission clarifies that to the extent the transmission-owning seller can 

demonstrate it passes the screens for each relevant geographic market without 

considering imports, it need not submit a SIL study.384 

 383 Powerex at 5-25. 

384 April 14 Order, 107 FERC ¶ 61,018 at P 85. 
Docket No. RM04-7-000 219 

380. Powerex requests that it be able to submit proxies in place of a SIL study. The 

Commission notes that transmission-providing sellers are required to be the first to 

file SIL studies, which makes the required data available to non-transmission owning 

sellers for use in performing their generation market power analyses.385 However, as 

the Commission stated in the April 14 Order, 

an applicant may provide a streamlined application to show that it passes our 

screens. Thus, with respect to simultaneous import capability, if an applicant can 

show that it passes our screens for each relevant geographic market without 

considering imports, no such simultaneous import analysis needs to be provided. 

Further, we recognize that certain applicants will not have the ability to perform a 

simultaneous import capability study. Accordingly, if an applicant demonstrates 

that it is unable to perform a simultaneous import study for the control area in 

which it is located, the applicant may propose to use a proxy amount for 

transmission limits. We will consider such proposals on a case-by-case basis.[386] 

381. In this regard, we note that we have accepted proxy amounts for transmission 

limits and will continue to consider such requests on a case-by-case basis.387

f. Required SIL Study for DPT Analysis

Comments

382. EEI and Southern propose that the Commission not mandate SIL studies as the 

only method for calculating import limits for DPT analysis. EEI states that while 

such a study may be an appropriate tool for indicative screens, the DPT is a more 

 385 July 8 Order, 108 FERC ¶ 61, 026 at 46. 

386 April 14 Order, 107 FERC ¶ 61,018 at P 85. 

387 See, e.g., Tampa Electric Co., 110 FERC ¶ 61,026 at P 32 (2005) (using the 

largest ATC into the control area at the time the study is conducted is a conservative 

assumption for import capability and an acceptable proxy for the SIL study). 
Docket No. RM04-7-000 220 

comprehensive study and the Commission should allow for more precise, nonstandardized approaches for calculating simultaneous import capability for use in the 

DPT.388 Southern states that the apparent purpose of Appendix E is to provide a 

somewhat standardized approach to assessing simultaneous import capability that 

goes hand-in-hand with the simplified tools used to develop a preliminary assessment 

of generation market power. It argues that where a seller presents a more thorough 

generation analysis pursuant to a DPT, it should be permitted to offer a more 

thorough analysis of transmission import capability.389

383. NRECA responds that the Commission should not allow sellers to substitute 

alternative measures of simultaneous import capability in the DPT. NRECA states 

that while a seller should be allowed to conduct a SIL study that is more refined than 

the one required of all sellers, “the applicant’s alternative analysis should be 

submitted in addition to, and not in lieu of, the required analysis” in the DPT.390 It 

argues that otherwise, each seller will do the analysis a bit differently so that the 

analysis will favor passing the tests. According to NRECA, the worst-case scenario 

is that there will be no standardized approach, which would exacerbate the existing 

problems created by inadequate access to the data underlying the sellers’ market 

 388 EEI at 24-25. 

389 Southern at 4, 37-38. 

390 NRECA reply comments at 24-25. 
Docket No. RM04-7-000 221 

power analysis and the lack of standard reporting and increase the burdens on 

intervenors and the Commission staff in evaluating applications for market-based 

rates and market power updates. NRECA states that one advantage of requiring all 

sellers to use a standard analysis, in addition to whatever other analysis they may 

choose to offer, is that it can more effectively bring to light the problems now hidden 

from view in the seller’s historical practices, resulting in increased transparency. 

Commission Determination

384. For the reasons stated herein regarding the need to as accurately as possible 

account for transmission limitations when considering power supplies that can be 

imported into the relevant market under study, the Commission adopts the 

requirement for use of the SIL study as a basis for transmission access for both the 

indicative screens and the DPT analysis. 

385. The lack of flexibility in creating a simultaneous transmission import limit has 

been identified by several commenters. However, the Commission believes it has 

provided sellers sufficient flexibility to adequately represent their process for making 

transmission available to unaffiliated supply. The Commission shares NRECA’s 

concerns that opening the process to alternative study methods without a specified 

standard may result in deviations from reasonable depictions of transmission limits 

historically applied to first-tier suppliers and will likely bias such studies to the 

benefit of the seller. 

386. With regard to the DPT analysis, there are several primary reasons for the 

continued use of simultaneous transmission import limit studies: uniformity of 
Docket No. RM04-7-000 222 

modeling affiliated and unaffiliated supply, consideration of simultaneity, 

consideration of seller and affiliate transmission commitments and reservations, 

consideration of all internal transmission limitations, consideration of all external 

transmission limitations existing in first-tier areas, consideration of the seller’s (or the 

seller’s transmission provider’s) practices for posting ATC, and consideration of peak 

seasonal conditions. By requiring the SIL study in the DPT analysis, the Commission 

assures that all factors important in determining transmission access to the seller’s 

market are taken into account. 

13. Procedural Issues

Commission Proposal

387. In the NOPR, the Commission noted that Order No. 662391 addressed concerns 

that CEII claims in market-based rate filings are overbroad. In Order No. 662, the 

Commission stated that it is willing to consider on a case-by-case basis requests for 

extensions of time to prepare protests to market-based rate filings where an intervenor 

demonstrates that it needs additional time to obtain and analyze CEII. In Order No. 

662, the Commission encouraged the parties in cases in which CEII is filed to 

promptly negotiate a protective order governing access to the CEII, or privately 

negotiate for the submitter to provide the data to interested parties pursuant to an 

 391 Critical Energy Infrastructure Information, Order No. 662, 70 FR 37031 

(June 28, 2005), FERC Stats. & Regs. Regulations Preambles 2001-2005 ¶ 31,189 

(June 21, 2005). 
Docket No. RM04-7-000 223 

appropriate non-disclosure agreement. The Commission sought comments in the 

NOPR on whether CEII designations remain a concern since issuance of Order No. 

662. 

388. The Commission also sought comments regarding whether the comment 

period (generally 21 days from the date of filing) provided for parties to file 

responses to the indicative screens and DPT analyses is sufficient. The Commission 

asked what would be an appropriate comment period if it were to establish a longer 

period for submitting comments on indicative screen and DPT analyses. 

Comments

389. A number of commenters note that intervenors should be given adequate time 

to respond to CEII designations. APPA/TAPS suggest that the Commission provide 

a process to allow interested market participants to obtain CEII authorization in 

advance of a region’s triennial updates. They submit that such authorization would 

apply to all sellers in the region where market-based rate authority is up for review 

and would necessitate that the requester file only one request.392 Montana Counsel 

states that intervenors should also be given adequate time to respond to 

confidentiality claims with regard to non-CEII data. 393

390. A number of commenters support extending the comment period for market-

 392 APPA/TAPS at 35-36. 

393 Montana Counsel at 23-24. 
Docket No. RM04-7-000 224 

based rate filings. Ameren supports a 30-day comment period on the basis that 30 

days has proven to be a sufficient comment period for § 203 filings.394 Morgan 

Stanley recommends a 45- to 60-day comment period if the Commission adopts a 

regional approach for updated market power analyses.395 NRECA states that under a 

regional filing process, a 21-day comment period is inadequate when several updated 

market power analysis filings are reviewed at once, and instead advocates a 90-day 

comment period from the notice of the filing or from the date of a completed filing if 

additional data is requested by the Commission.396 

Commission Determination

391. In this Final Rule, we adopt procedures under which intervenors in section 205 

proceedings may obtain expedited access to CEII or other information for which 

privileged treatment is sought. A request for access to information for which CEII 

status or privilege treatment has been claimed generally takes a few weeks for the 

Commission to process under the standard process found in 18 CFR 388.112 and 

388.113.397 Such a delay in receiving such information may make it difficult for an 

 

 (continued...) 

 

394 Ameren at 8. 

395 Morgan Stanley at 14. 

396 NRECA at 29. 

397 This is due, in part, to the fact that the Commission’s regulations require notice 

and an opportunity for the submitter to comment on the request. The Commission 

recently consolidated the notice and opportunity to comment provision in 18 CFR 
Docket No. RM04-7-000 225 

intervenor to submit timely comments. 

392. An expedited process does exist for section 203 filings. Section 33.9 of the 

Commission's regulations398 states that a seller seeking to protect any part of its 

application from public disclosure must also submit a proposed protective order. 

Parties may sign the proposed protective order and obtain CEII or privileged 

materials in a more 

timely manner, without having to spend time negotiating the terms of a protective order 

or waiting for the Commission to process the request through its standard request process. 

393. In order to ensure that intervenors have access in a timely manner to relevant 

information for which privileged treatment is claimed, we will adopt language similar 

to § 33.9 in this Final Rule, to be codified at 18 CFR 35.37(f). We intend that the 

proposed protective order will be self implementing and not require action by the 

Commission; once a party signs the proposed protective order and returns it to the 

party submitting protected material, the submitter is expected to provide the material 

promptly to the requester. We note that the Commission’s Model Protective Order is 

available on the Commission’s Internet site and may be used as a guide in preparing 

 

388.112(d) with the notification prior to release found in 18 CFR 388.112(e). See 

Critical Energy Infrastructure Information, Order No. 683, FERC Stats. & Regs. ¶ 31,228 

(2006). 

398 18 CFR 33.9. 
Docket No. RM04-7-000 226 

proposed protective orders.399 To expedite processing, the regulation will require that 

the seller provide the CEII or privileged material to the requester within five days 

after the protective order is signed and submitted to the seller. 

394. With respect to APPA/TAPS’s suggestion to make CEII authorization regionwide to coincide with region-wide analysis, we do not believe such a step is 

necessary or advisable at this time. Our goal with CEII has always been to limit 

access to those with a legitimate need for the information. We do not expect that all 

market participants in a region will want to comment on all updated market power 

analyses within that region. Moreover, we anticipate that our regulatory change 

requiring submission of a proposed protective order will go a long way to resolving 

past difficulties in obtaining non-public information in a timely manner. 

395. With regard to the comment period for parties to file responses to updated 

indicative screens, we believe, as we discuss below in the section on Implementation, 

that extending the comment period for regional updated market power analyses will 

allow intervenors a better opportunity to review and comment on those filings, 

especially considering the large number of filings that will be submitted at one time. 

Hence, we will establish a 60-day comment period for updated market power 

analyses that are filed in accordance with the schedule in Appendix D. 

396. With regard to the comment period for initial applications and for DPT 

 399 See http://www.ferc.gov/legal/admin-lit/model-protective-order.pdf. 
Docket No. RM04-7-000 227 

analyses ordered as part of a section 206 proceeding, the Commission will retain the 

current 21-day comment period. However, we remain willing to consider on a caseby-case basis requests for extensions of time beyond 21 days to submit comments on 

these filings. 

B. Vertical Market Power

397. In the NOPR, the Commission proposed to replace the existing four-prong 

analysis (generation market power, transmission market power, other barriers to 

entry, affiliate abuse/reciprocal dealing) with an analysis that focuses on horizontal 

market power and vertical market power. Accordingly, it proposed that issues 

relating to whether the seller and its affiliates have transmission market power or 

whether they can erect other barriers to entry be addressed together as part of the 

vertical market power part of the analysis. 

Comments

398. As a general matter, commenters expressed support for the proposed 

consolidation of the transmission market power and other barriers to entry prong into 

one vertical market power analysis.400 According to EPSA, analyzing vertical market 

dominance in one single prong could be a positive step, provided that the elements of 

 400 See Duke at 30; Southern at 38-40; EPSA at 18-19. 
Docket No. RM04-7-000 228 

the prong are explicitly specified and effectively enforced.401 No commenter 

opposed the Commission’s proposal in this regard.

Commission Determination

399. In light of the reasons discussed in the NOPR and the comments received, the 

Commission will adopt the NOPR proposal to consolidate the transmission market 

power analysis and other barriers to entry analysis into one vertical market power 

analysis. 

1. Transmission Market Power

Commission Proposal

400. In the NOPR, the Commission noted that it recognized that Order No. 888 did 

not eliminate all potential to engage in undue discrimination and preference in the 

provision of transmission service,402 and that it had issued a Notice of Inquiry and a 

NOPR regarding whether reforms are necessary to the Order No. 888 pro forma

OATT.403 The Commission concluded that any concerns regarding the adequacy of 

 401 EPSA at 18-19. 

402 In Order No. 2000, the Commission found that “opportunities for undue 

discrimination continue to exist that may not be remedied adequately by [the] functional 

unbundling [remedy of Order No. 888]...” Regional Transmission Organizations, Order 

No. 2000, FERC Stats. & Regs., Regulations Preambles July 1996-December 2000 

¶ 31,089 at 31,105 (1999), order on reh’g, Order No. 2000-A, FERC Stats. & Regs., 

Regulations Preambles July 1996-December 2000 ¶ 31,092 (2000), aff’d sub nom. Public 

Utility District No. 1 of Snohomish County, Washington v. FERC, 272 F.3d 607 (D.C. 

Cir. 2001). 

403 See Preventing Undue Discrimination and Preference in Transmission Service, 

 (continued...) 

 
Docket No. RM04-7-000 229 

the OATT should be addressed in that proceeding and not in the MBR Rulemaking 

proceeding. Therefore, in the NOPR the Commission proposed to continue to find 

that, where a seller or any of its affiliates owns, operates or controls transmission 

facilities, a Commission-approved OATT, as modified as a result of the OATT 

Reform Rulemaking, will adequately mitigate transmission market power. 

401. In the NOPR, the Commission further stated that the finding that an OATT 

adequately mitigates transmission market power rests on the assumption that 

individual sellers comply with their OATTs. If they do not, violations of the OATT 

may be cause to revoke market-based rate authority or to subject the seller to other 

remedies the Commission may deem appropriate, such as disgorgement of profits or 

civil penalties.404 However, before the Commission will consider revoking an 

entity’s market-based rate authority for a violation of the OATT, there must be a 

nexus between the OATT violation and the entity’s market-based rate authority. 

402. In addition, the Commission proposed that, if it determines, as a result of a 

significant OATT violation, that the market-based rate authority of a transmission 

provider will be revoked within a particular market, each affiliate of the transmission 

 

70 FR 55796 (Sept. 23, 2005), FERC Stats. & Regs., ¶ 35,553 (2005); Preventing Undue 

Discrimination and Preference in Transmission Service, Notice of Proposed Rulemaking, 

71 FR 32636 (Jun. 6, 2006), FERC Stats. & Regs. ¶ 32,603 (2006); Preventing Undue 

Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12266 

(Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241 (2007), reh’g pending.

404 NOPR at P 91 (citing The Washington Water Power Co., 83 FERC ¶ 61,282 

(1998)). 
Docket No. RM04-7-000 230 

provider that possesses market-based rate authority will have it revoked in that same 

market on the effective date of revocation of the transmission provider’s marketbased rate authority.405 

a. OATT Requirement 

Comments

403. Several commenters state that merely having an OATT on file does not 

sufficiently mitigate vertical market power and that a utility’s interpretation and 

implementation of its OATT can effectively eviscerate market power protections.406 

Some commenters do not believe that tariff changes alone will effectively mitigate 

vertical market power in the future and therefore request a post-implementation 

proceeding one year after the issuance of a final rule in the OATT Reform 

Rulemaking to explore the effectiveness of the updated OATT in assessing vertical 

market power.407

404. EPSA states that the outcome of the OATT Reform Rulemaking will 

determine the strength and efficacy of the vertical market power screen and stresses 

the interrelationship of that proceeding to this proposed rule; EPSA continues to 

 405 NOPR at P 91. 

406 See, e.g., Suez/Chevron at 6; Reliant at 8. 

407 Suez/Chevron at 6; EPSA at 20. 
Docket No. RM04-7-000 231 

advocate that the reform of Order No. 888 and the ability of the OATT to mitigate 

against market power effectively be evaluated on an ongoing basis.408

405. APPA/TAPS similarly state that, for purposes of the vertical market power 

analysis, it is too early to tell whether the OATT, as modified in the OATT Reform 

Rulemaking, will mitigate transmission market power.409 TDU Systems argue that 

the proposals governing transmission planning and expansion in the OATT Reform 

Rulemaking are inadequate to mitigate the vertical market power of transmissionowning public utilities.410

406. The New York Commission states that the presence of an OATT may mitigate 

a seller’s transmission market power, but only with respect to generator access to the 

transmission system. It submits that vertically integrated utilities may be able to 

exercise transmission market power in a manner that would not necessarily violate 

their OATTs, such as through outage scheduling (e.g., delaying repair and 

maintenance of transmission lines in a load pocket in which an affiliated generator is 

located), transmission investment (e.g., delaying or minimizing its investment in the 

bulk electric transmission system in a load pocket in which an affiliated generator is 

located), or voltage support (e.g., inadequate support of voltage requirements and 

 408 EPSA reply comments at 2, 5. 

409 APPA/TAPS at 6. 

410 TDU Systems at 24. 
Docket No. RM04-7-000 232 

being slow to correct voltage support shortcomings).411 EPSA agrees with the New 

York Commission that the Commission cannot assume that any transmission provider 

with a Commission-approved OATT on file has adequately mitigated transmission 

market power and that “the Commission should require these utilities to demonstrate 

that they do not have the incentive or ability to engage in such behavior, before they 

are granted MBR status.”412 

407. On the other hand, several commenters support the Commission’s proposal to 

maintain the long-standing presumption that a Commission-approved OATT will 

adequately mitigate transmission market power.413 EEI states that the comprehensive 

approach that the Commission has taken to reform the OATT in the OATT Reform 

Rulemaking is the best approach to assess the adequacy of the OATT to mitigate 

transmission market power. EEI states that the Commission should continue to find 

that a Commission-approved OATT, as modified as a result of the OATT Reform 

Rulemaking, adequately mitigates transmission market power.414

 411 New York Commission at 2-4.

412 EPSA reply comments at 5-6 (citing New York Commission at 2-4). 

413 Duke at 29-32; EEI at 44-45; Southern at 38-40; MidAmerican reply comments 

at 2. 

414 EEI reply comments at 31-35. 
Docket No. RM04-7-000 233 

Commission Determination

408. The Commission will adopt the NOPR proposal that, to the extent that a public 

utility with market-based rates, or any of its affiliates, owns, operates, or controls 

transmission facilities, the Commission will require that a Commission-approved 

OATT be on file before granting such seller market-based rate authorization. We 

recognize that the Commission has granted a number of entities waiver of the 

requirement to file an OATT where the filing entity satisfies the Commission’s 

standards for the grant of such waivers.415 The Commission will continue to grant 

waiver of the OATT requirement on a case-by-case basis, and will continue to allow 

sellers to rely on the grant of such waiver to satisfy the vertical market power part of 

the analysis. If a seller that previously received waiver of the OATT requirement 

seeks to continue to rely on that waiver to satisfy the vertical market power part of the 

analysis, it must make an affirmative statement in its updated market power analysis 

that it previously received such a waiver, that such waiver remains appropriate, and 

the basis for that claim. In addressing our vertical market power concerns, a seller, 

including its affiliates, that does not own, operate or control transmission facilities 

 415 Black Creek Hydro, Inc., 77 FERC ¶ 61,232 at 61,941 (1996) (granting waiver 

of Order No. 888 for public utilities that can show that they own, operate, or control only 

limited and discrete transmission facilities (facilities that do not form an integrated 

transmission grid), until such time as the public utility receives a request for transmission 

service). 
Docket No. RM04-7-000 234 

must make an affirmative statement that neither it, nor any of its affiliates, owns, 

operates or controls any transmission facilities. 

409. In the NOPR, we stated that concerns regarding the adequacy of the OATT 

should be addressed in the OATT Reform Rulemaking. The Commission received 

over 6,000 pages of comments relating to potential reforms to the pro forma OATT in 

that proceeding, and on February 16, 2007 issued a Final Rule adopting numerous 

improvements to the pro forma OATT that will further limit opportunities for 

transmission providers to unduly discriminate against transmission customers. As a 

result, we do not address in this Final Rule specific reforms to the OATT. In 

addition, the Commission declined in Order No. 890 to establish a one-year review 

period for the reformed pro forma OATT. The Commission stated it will continue to 

actively monitor compliance with its orders and, as necessary, institute further 

proceedings to meet its statutory obligation to remedy undue discrimination.416

410. In response to the concerns of the New York Commission and EPSA that 

vertically integrated utilities may exercise vertical market power without violating 

their OATTs through actions such as outage scheduling, investment decisions and 

inadequate voltage support, we note that the OATT does address such matters as the 

planning and expansion of facilities, the duty to provide firm and non-firm service 

and good utility practice. These provisions impose definite obligations on 

 416 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 42. 
Docket No. RM04-7-000 235 

transmission providers. As additional examples, outage scheduling aimed at affecting 

market prices may constitute market manipulation, and inadequate voltage support 

may violate a reliability standard under FPA section 215. These provisions 

adequately address the concerns of the New York Commission and EPSA. 

b. OATT Violations and MBR Revocation 

Comments

411. A number of commenters agree with the Commission that market-based rate 

authority should not be revoked unless and until the Commission finds a direct nexus 

between the OATT violation and the entity’s market-based rate authority.417 EEI 

states that the Commission should not presume that an OATT violation is sufficient 

cause to revoke a transmission provider’s market-based rate authority because there is 

no basis for such a presumption.418 Instead, EEI argues that the Commission should 

carefully review all facts and circumstances before determining that an OATT 

violation was a willful exercise in undue discrimination intended to benefit a seller’s 

sales at market-based rates.419 

 417 EEI reply comments at 31-35; MidAmerican reply comments at 2. See also

Duke at 29 (OATT violation should be a material violation and related in some way to 

the seller exercising market power). 

418 EEI reply comments at 31-35. 

419 EEI reply comments at 34; PNM/Tucson at 10-12. 
Docket No. RM04-7-000 236 

412. EPSA asserts that any violation of an entity’s OATT in order to favor its own 

sales or its affiliates would create a nexus to the entity’s market-based rate authority. 

If the Commission does not clarify this point, EPSA requests explanation regarding 

what exactly would constitute a nexus between an OATT violation and an entity’s 

market-based rates.420

413. TDU Systems state that it is unclear what the nexus requirement entails. They 

propose that if the transmission provider or one of its affiliates has market-based rate 

authority, there should be a rebuttable presumption that a violation of the OATT has 

the requisite nexus to support revocation of the market-based rate authority of the 

transmission provider and its affiliates.421 TDU Systems state that it should be up to 

a seller to rebut that presumption. 

414. APPA/TAPS assert that the nexus standard adds an unnecessary and counterproductive test.422 APPA/TAPS submit that if an OATT violation denies, delays, or 

diminishes the availability of transmission service or raises its costs, that alone should 

suffice for consideration of revocation of market-based rate authority. They argue 

that whether the violation had a nexus to the seller’s market-based rate sales may be 

irrelevant. APPA/TAPS state that a nexus requirement could divert the Commission 

 420 EPSA at 23-24. 

421 TDU Systems at 21-23. 

422 APPA/TAPS at 81-82. 
Docket No. RM04-7-000 237 

and injured parties through needless disputes about whether the alleged violator used 

the OATT violation to enable a specific sale under its market-based rate tariff 

authority, ignoring the larger picture painted by the transmission provider’s 

anticompetitive conduct and exercise of transmission market power. Thus, instead of 

the “nexus” standard, APPA/TAPS states that the Commission should require that the 

OATT violation be “material,” i.e., one that denies customers the just, reasonable and 

non-discriminatory and comparable transmission service that is essential to mitigation 

of transmission market power.423

415. Reliant suggests that the Commission should strengthen its vertical market 

power analysis by looking at the extent to which a transmission provider has denied 

transmission access to competing suppliers and should seek justification for such 

denials.424 For those transmission providers seeking market-based rate authority, 

Reliant asserts that any suppliers unable to reach a customer as a result of an 

inappropriate denial should not be included as competing generation in the 

transmission provider’s horizontal market power screens until the transmission 

provider remedies the problem.425

 423 Id. at 82. 

424 See Reliant at 8-9. 

425 See id. 
Docket No. RM04-7-000 238 

416. Duke urges the Commission to clarify that a seller’s market-based rate 

authority should not be subject to limitation or revocation if it participates in an RTO 

that is the subject of an OATT violation. According to Duke, once the transmission 

owner transfers control over its facilities to an RTO, adherence to the OATT is in the 

control of the RTO, not the transmission owner.426

Commission Determination

417. We will adopt the NOPR proposal to revoke an entity’s market-based rate 

authority in response to an OATT violation only upon a finding of a nexus between 

the specific facts relating to the OATT violation and the entity’s market-based rate 

authority, and reiterate our statement in the NOPR that an OATT violation may 

subject the seller to other remedies the Commission may deem appropriate, such as 

disgorgement of profits or civil penalties.427 As stated in the NOPR, the finding that 

an OATT adequately mitigates transmission market power rests on the assumption 

that individual entities comply with the OATT and there may be OATT violations in 

circumstances that, after applying the factors in the Enforcement Policy Statement,428

merit revocation or limitation of market-based rate authority. We find, however, that 

 426 Duke at 29-32. 

427 NOPR at P 91 (citing The Washington Water Power Company, 83 FERC 

¶ 61,282 (1998)). 

428 Enforcement of Statutes, Orders, Rules and Regulations, Policy Statement on 

Enforcement, 113 FERC ¶ 61,068 (2005) (Enforcement Policy Statement). 
Docket No. RM04-7-000 239 

it is inappropriate to revoke a seller’s market-based rate authority for an OATT 

violation unless there is a nexus between the specific facts relating to the OATT 

violation and the seller’s market-based rate authority. This will ensure that our 

actions are not arbitrary or capricious and that they are based on an adequate factual 

record. We will not, as TDU Systems suggest, adopt a rebuttable presumption that 

any OATT violation has the requisite nexus to support revocation of market-based 

rate authority. There is a wide range of types of OATT violations, including ones 

that may be inadvertent and ones that are neither intended to affect, nor in fact affect, 

the market-based rate sales of the transmission provider or its affiliates. We therefore 

believe adoption of a general rebuttable presumption of a nexus for any and all OATT 

violations is not justified.

418. Several commenters sought clarification regarding what would constitute a 

sufficient nexus between the specific facts relating to the OATT violation and the 

seller’s market-based rate authority. Determining what constitutes a sufficient factual 

nexus is best left to a case-by-case consideration. The wide range of positions among 

commenters on how to define a sufficient factual nexus itself suggests that this 

finding is best made after review of a specific factual situation. Some commenters 

assert that a finding of a “material” violation of the OATT would be sufficient. We 

disagree. While a seller’s inconsequential OATT violation would not serve as a basis 

for revoking that entity’s market-based rate authority, our view is that revocation is 

warranted only when an OATT violation has occurred and the violation had a nexus 

to the market-based rate authority of the violator or its affiliates. 
Docket No. RM04-7-000 240 

419. The Commission emphasizes that we have discretion to fashion remedies for 

OATT violations that relate to the violator’s market-based rate authority in instances 

in which we do not find sufficient justification for revocation of that authority. For 

example, in appropriate circumstances, we may modify or add additional conditions 

to the violator’s market-based rate authority or impose other requirements to help 

ensure that the violator does not commit future, similar misconduct. We also will 

consider whether to impose sanctions such as assessment of civil penalties for 

particularly serious OATT violations in addition to revocation of the violator’s 

market-based rate authority. 

420. We agree with Duke that a seller’s market-based rate authority should not be 

subject to limitation or revocation if it participates in an RTO that is the subject of an 

OATT violation committed by the RTO. We note, however, that if the seller itself is 

involved in an OATT violation, the Commission will investigate the seller’s actions 

where appropriate, and may revoke market-based rate authority even though the seller 

is in an RTO. 

421. With regard to Reliant’s suggestion that the Commission should examine the 

extent to which a transmission provider has denied transmission access to competing 

suppliers as part of its vertical market power analysis, we will allow intervenors on a 

case-by-case basis to file evidence if they believe they have been denied transmission 

access in violation of the OATT. Depending on specific facts, such denials could 

constitute an OATT violation and could warrant remedies such as a reduction of 

competing supplies for purposes of the horizontal analysis. 
Docket No. RM04-7-000 241 

c. Revocation of Affiliates’ MBR Authority

Comments

422. Some commenters oppose the proposal to revoke the market-based rate 

authority of all affiliates of a transmission provider within a particular market, 

regardless of whether they were involved in the transmission provider’s violation of 

its OATT. These commenters argue that the proposal to revoke all affiliates’ marketbased rate authority ignores the principles of the Commission’s code of conduct and 

standards of conduct, including provisions restricting the sharing of market 

information and requiring separation of functions.429 They argue that, in light of the 

separation of a company’s marketing function and transmission function under the 

standards of conduct, a company’s market-based rates should not be revoked because 

of an OATT violation by an affiliated transmission owner unless there has also been a 

violation of the standards of conduct, and there is a nexus between the standards of 

conduct violation and the OATT non-compliance.430 They assert that, unless there is 

a violation of the standards of conduct, merchants will have no involvement in the 

actions of transmission providers.431 

 429 See Ameren at 8-11; PNM/Tucson at 10-12; EEI reply comments at 33-35; 

Avista at 12-13; EEI at 54; Indianapolis P&L at 6-7. 

430 See PG&E at 3, 12-14; Xcel at 2 and 16 

431 PG&E at 13. 
Docket No. RM04-7-000 242 

423. Xcel submits that, before imposing a penalty that would effectively penalize 

the merchant function, the Commission should require a demonstration that a utility’s 

transmission function violated the OATT so as to knowingly benefit the activities of 

its merchant function.432 Xcel and Allegheny Energy state that the Commission 

should not penalize the merchant side of an entity when the OATT violation by the 

transmission provider causes no harm, was not the result of deliberate manipulative 

conduct, was not part of a pattern of misconduct, or did not involve senior 

management of the transmission provider. 433 Similarly, Indianapolis P&L advocates 

punishment of a marketing or generation-only affiliate only to the extent such affiliate 

colludes or conspires with such OATT mis-administration or if such an affiliate 

financially benefits from such an act.434 

Commission Determination

424. In response to concerns raised by commenters, we do not adopt the proposal 

from the NOPR to revoke the market-based rate authority of each affiliate of a 

transmission provider that loses its market-based rate authority within a particular 

market as a result of the transmission provider’s OATT violation. Rather, we will 

create a rebuttable presumption that all affiliates of a transmission provider should 

 432 Xcel at 16-17. See also Avista at 12-13; PNM/Tucson at 10-12. 

433 Allegheny Energy at 9-10; Xcel at 16-17. 

434 Indianapolis P&L at 6-7. 
Docket No. RM04-7-000 243 

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. We will allow an affiliate of a transmission provider to retain its marketbased rate authority in a market area if the affiliate overcomes the rebuttable 

presumption with respect to that market area.

425. This issue generally will arise when a transmission provider merits revocation 

of its market-based rate authority as a result of an OATT violation. We have long 

held that the existence of an OATT is deemed to mitigate vertical market power by a 

transmission provider and its affiliates in a particular market. An OATT violation by 

a transmission provider that merits revocation of the transmission provider’s marketbased rate authority in a particular market will, at a minimum, raise the question 

whether the transmission provider’s affiliates continue to qualify for market-based 

rates in that market under the standards that we have established.435 As a result, we 

 435 We observe that specific situations in which transmission providers have 

agreed to resolve staff allegations that they engaged in OATT violations have involved 

transactions with affiliates. See Idaho Power Company, et al., 103 FERC ¶ 61,182 

(2003) (settlement of, among other issues, a practice whereby a transmission provider 

permitted its merchant function to request non-firm transmission to enable the merchant 

function to make off-system sales that by definition were not used to serve native load, so 

that the transmission did not qualify for the “native load” priority specified in section 

28.4 of the transmission provider’s OATT); Cleco Corporation, et al., 104 FERC 

¶ 61,125 (2003) (settlement between Enforcement staff and a transmission provider (and 

others in the corporate family) that provided a unique type of transmission service for its 

affiliate that was neither made available to non-affiliates nor included in its FERC tariff); 

Tucson Electric Power Company, 109 FERC ¶ 61,272 (2004) (operational audit in which 

staff found that, among other matters, a transmission provider permitted its wholesale 

merchant function to purchase hourly non-firm and monthly firm point-to-point 

 (continued...) 

 
Docket No. RM04-7-000 244 

believe that it is appropriate to establish a rebuttable presumption that if we find that 

a transmission provider should lose its market-based rate authority in a particular 

market, all affiliates of the transmission provider should also lose their market-based 

rate authority in the same market.

426. We are mindful, however, that the circumstances of a particular affiliate may 

not always justify the imposition of a remedy so severe as revocation of market-based 

rate authority in a particular market when its affiliated transmission provider loses its 

market-based rate authority in that market as a result of an OATT violation. To 

ensure that a determination to revoke market-based rate authority in a particular 

market for a transmission provider and all of its affiliates that possess such authority 

is adequately based upon record evidence, we will allow an opportunity for each such 

affiliate to make a showing that it should retain its market-based rate authority or that 

 

transmission service using an off-OASIS scheduling procedure while the transmission 

provider did not post on its OASIS the availability of capacity on these paths); South 

Carolina Electric & Gas Company, et al., 111 FERC ¶ 61,217 (2005) (settlement of 

Enforcement staff allegation that a transmission provider made available firm point-topoint transmission service to its affiliated merchant function that did not submit 

transmission schedules with specific receipt points for the service as required by section 

13.8 of the transmission provider’s OATT); and MidAmerican Energy Company, 

112 FERC ¶ 61,346 (2005) (operational audit in which staff found, among other things, 

that a transmission provider permitted its wholesale merchant function to (a) use network 

transmission service to bring short-term energy purchases onto its system while it 

simultaneously made off-system sales, inconsistently with the preamble to Part III of the 

transmission provider’s OATT and section 28.6 of its OATT; and (b) confirm firm 

network transmission service requests without identifying a designated network resource 

or acquiring an associated network resource, in some instances using this service to 

deliver short-term energy purchases used to facilitate off-system sales, inconsistent with 

section 29.2 or section 30.6 of the transmission provider’s OATT). 
Docket No. RM04-7-000 245 

enforcement action against it should be less severe than revocation. The 

determination whether an affiliate has overcome the rebuttable presumption depends 

on an analysis of specific facts in the record. Relevant facts would include, for 

example, whether (1) the affiliate knew of, participated in, or was an accomplice to 

the OATT violation, (2) the affiliate assisted the transmission provider in exercising 

market power, or (3) the affiliate benefited from the violation. 

427. Consistent with our approach to revocation of a transmission provider’s 

market-based rates, the Commission clarifies that a decision to revoke the marketbased rate authority of the transmission provider’s affiliates in the affected market 

will also be based on a finding that the transmission provider’s violation of its OATT 

has a nexus to the market-based rate authority of those affiliates. 

2. Other Barriers to Entry

Commission Proposal

428. The Commission proposed in the NOPR that, in order for a seller to 

demonstrate that it satisfies the Commission’s vertical market power concerns, it 

must demonstrate that neither it nor its affiliates can erect other barriers to entry (i.e., 

barriers other than transmission). In this regard, the Commission proposed to 

continue to require a seller to provide a description of its affiliation, ownership or 

control of inputs to electric power production (e.g., fuel supplies within the relevant 

control area); ownership or control of gas storage or intrastate transportation or 

distribution of inputs to electric power production; and ownership or control of sites 

for new generation capacity development. The Commission also proposed to require 
Docket No. RM04-7-000 246 

sellers to make an affirmative statement that they have not erected barriers to entry 

into the relevant market and that they cannot do so. 

429. In addition, the Commission proposed to provide additional regulatory 

certainty by clarifying which inputs to electric power production the Commission will 

consider as other barriers to entry in its vertical market power review, and sought 

comments on this proposal. Specifically, the Commission proposed that the analysis 

continue to include the consideration of ownership or control of sites for development 

of generation in the relevant market, fuel inputs such as coal facilities in the relevant 

market, and the transportation, storage or distribution of inputs to electric power 

production such as intrastate gas storage and distribution systems, and rail cars/barges 

for the transportation of coal. 

430. The Commission also clarified that sellers need not address interstate 

transportation of natural gas supplies because such transportation is regulated by this 

Commission.436 The Commission explained that its open access regulations 

adequately prevent sellers from withholding interstate pipeline capacity. In addition, 

interstate pipeline capacity held by firm shippers that is not utilized or released is 

 436 NOPR at P 93 (citing Pipeline Service Obligations and Revisions to 

Regulations Governing Self-Implementing Transportation Under Part 284 of the 

Commission’s Regulations, Order No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & 

Regs. Regulations Preambles January 1991-June 1996 ¶ 30,939 (Apr. 8, 1992)). 
Docket No. RM04-7-000 247 

available from the pipeline on an interruptible basis. As to the commodity, the 

Commission noted that Congress has found the natural gas market competitive.437

431. The Commission also sought comment on whether ownership or control of 

other inputs to electric power production should be considered as potential barriers to 

entry and, if so, what criteria the Commission should use to evaluate evidence that is 

presented. 

Comments

432. Several commenters state that the Commission’s other barriers to entry criteria 

are long-standing, well established and thus no expansion of current policy is 

necessary.438 They submit that the requirement that the analysis include the 

consideration of ownership or control of sites for development of generation in the 

relevant market, fuel inputs such as coal supplies in the relevant market, and the 

transportation, storage or distribution of inputs to electric power production such as 

intrastate gas storage and distribution systems, and rail cars/barges for the 

transportation of coal, is broad and provides sufficient information for the 

Commission to assess the seller’s potential to erect barriers to entry. They assert that 

this information, coupled with the proposal to require sellers to make an affirmative 

 437 NOPR at P 93 (citing Natural Gas Wellhead Decontrol Act of 1989, Pub.L. No. 

101-60, 103 Stat. 157 (1989); Natural Gas Policy Act of 1978, section 601 (a) (1), 15 

U.S.C. 3431 (deregulating the wellhead price of natural gas)). 

438 Allegheny Energy at 9-10; Southern at 38-40; EEI at 44-45. 
Docket No. RM04-7-000 248 

statement that they have not erected barriers to entry into the relevant market and that 

they cannot do so, provides the Commission with appropriate information.439

433. APPA/TAPS suggest that the proposed entry barriers affirmation should be 

signed and affirmed by a senior corporate official.440 However, APPA/TAPS state 

that the Commission should not codify the specific entry barriers that it will consider 

given the ever-changing nature of electricity markets.441 They submit that while 

illustrations of entry barriers can provide guidance to sellers and market participants, 

the Commission should not limit the kinds of entry barriers it will consider. 

434. Sempra states that, to the extent the new analytic framework (the consolidation 

of the former transmission market power and other barriers to entry factors into the 

vertical market power analysis) would recognize existing precedent and not work to 

place additional burdens on market-based rate sellers, Sempra would support it.442 

435. Several sellers support continuation of the Commission’s policy that sellers 

need not address natural gas and its interstate transportation as part of their vertical 

market power analysis.443 In contrast, a commenter states that the Commission 

 439 See, e.g., New Jersey Board at 3. 

440 APPA/TAPS at 6, 85. 

441 APPA/TAPS at 6, 84-85. 

442 Sempra at 6-7. 

443 See Constellation at 25; Duke at 30; PG&E at 13; Sempra at 6. 
Docket No. RM04-7-000 249 

should not make a blanket exemption for sellers or their affiliates who own or control 

natural gas pipeline capacity. Notwithstanding the Commission’s statement that 

natural gas interstate pipelines are regulated by the Commission and that the 

regulations adequately prevent sellers from withholding capacity, this commenter 

argues that the natural gas open access rules do not adequately mitigate vertical 

market power in all situations. It encourages the Commission to require sellers with 

significant firm interstate pipeline capacity rights to demonstrate that they do not 

have vertical market power.444

436. APPA/TAPS state that the Commission should clarify that it will consider 

control over interstate natural gas transportation if the issue is raised in a marketbased rate proceeding.445 APPA/TAPS state that even if sellers do not have to 

address interstate gas transportation as part of the vertical market power test, 

intervenors should not be precluded from raising concerns and introducing evidence 

regarding a seller’s position in the interstate natural gas transportation market as a 

potential entry barrier and APPA/TAPS seek clarification in this regard.446 

437. Several commenters state that the markets for the other inputs to generation 

factor (e.g., fuel supply other than natural gas, transportation and storage) are 

 444 Drs. Broehm and Fox-Penner at 14-15. 

445 APPA/TAPS at 82-85. 

446 APPA/TAPS at 6. 
Docket No. RM04-7-000 250 

workably competitive and provide few opportunities for a seller to raise entry 

barriers. They therefore suggest that the Commission create a rebuttable presumption 

that the markets for other factor inputs such as coal, oil and distillate commodity 

markets, the transportation and storage of these fuels, sites for new plants, etc., are 

workably competitive. They urge that, absent a showing to the contrary, ownership 

or control of such assets need not be analyzed.447 In this regard, Duke states that the 

Commission should allow sellers to make the representation that they cannot erect 

such barriers, while allowing other parties to introduce evidence challenging such an 

assertion.448

438. PG&E states that, similar to the rules for interstate transportation of natural 

gas supplies (under which Commission open access regulations adequately prevent 

sellers from withholding interstate gas pipeline capacity), state regulation of access to 

gas storage, natural gas pipelines, or natural gas distribution should be a basis for 

finding that an entity with ownership or control of such assets cannot erect barriers to 

entry or otherwise hold or exercise vertical market power in the generation market.449

439. SoCal Edison urges the Commission to clarify that, with regard to sites for 

building generation, mere ownership of real estate does not reasonably support an 

 447 See, e.g., Duke at 30-32; Constellation at 23-27. 

448 Duke at 30-32. 

449 See PG&E at 3, 13-14. 
Docket No. RM04-7-000 251 

inference of a barrier to entry, and that sellers are not required, in the first instance, to 

make any affirmative demonstration of the absence of potential that their real estate 

holdings might constitute a theoretical barrier to entry. Rather, the Commission 

should clarify that it would pursue such inquiry only to the extent colorable issues are 

raised by way of protest or intervention.450 Sempra states the Commission should 

modify the regulatory text in three respects. First, the Commission should explicitly 

exclude from the definition of “inputs to electric power production” in proposed § 

35.36(a)(4) interstate transportation of natural gas supplies (both ownership/control of 

facilities as well as ownership/control of capacity) and the gas commodity itself. 

Second, the Commission should also exclude from the definition of “inputs to electric 

power production” intrastate natural gas facilities or distribution facilities, 

particularly where such facilities are operated under pervasive state regulations and in 

accordance with open access principles. Third, the Commission should make clear in 

this provision and at § 35.27(e) of its proposed regulations (pertaining to a seller’s 

vertical market power analysis), that the only “inputs” that need to be addressed are 

those present in the seller’s relevant geographic market(s).451

 450 SoCal Edison at 2, 19. 

451 Sempra at 6. 
Docket No. RM04-7-000 252 

Commission Determination

440. As discussed above, the Commission will adopt the NOPR proposal to 

consider a seller’s ability to erect other barriers to entry as part of the vertical market 

power analysis, but we will modify the requirements when addressing other barriers 

to entry. We also provide clarification below 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) and we 

modify the proposed regulatory text in that regard. 

441. In this rule, the Commission draws a distinction between two categories of 

inputs to electric power production: one consisting of natural gas supply, interstate 

natural gas transportation (which includes interstate natural gas storage), oil supply, 

and oil transportation, and another consisting of 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. 

442. With regard to the first category, based upon the comments received and 

further consideration, the Commission will not require a description or affirmative 

statement with regard to ownership or control of, or affiliation with an entity that 

owns or controls, natural gas and oil supply, including interstate natural gas 

transportation and oil transportation. 
Docket No. RM04-7-000 253 

443. In the case of natural gas, prices for wellhead sales were decontrolled by 

Congress.452 Further, the Commission has granted other sellers blanket authority to 

make sales at market rates. In the case of transportation of natural gas, pipelines 

operate pursuant to the open and non-discriminatory requirements of Part 284 of the 

Commission’s regulations.453 These regulations mandate that all available pipeline 

capacity be posted on the pipelines’ website, and that available capacity cannot be 

withheld from a shipper willing to pay the maximum approved tariff rate. 

444. Similarly, we note that oil pipelines are common carriers under the Interstate 

Commerce Act, specifically under section 1(4), and are required to provide 

transportation service "upon reasonable request therefore"454 and that Congress has 

not chosen to regulate sales of oil. 

 452 INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002); Natural Gas Decontrol Act of 

1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., at 6 (1989). 

453 See, e.g., Pipeline Service Obligations and Revisions to Regulations Governing 

Self-Implementing Transportation Under Part 284 of the Commission’s Regulations, 

Order No. 636, 57 FR 13267 (Apr. 16, 1992), FERC Stats. & Regs. Regulations 

Preambles January 1991-June 1996 ¶ 30,939 (Apr. 8, 1992); Regulation of Short-Term 

Natural Gas Transportation Services and Regulation of Interstate Natural Gas 

Transportation Services, Order No. 637, FERC Stats. & Regs. Regulations Preambles 

July 1996 - December 2000 ¶ 31,091 (Feb. 9, 2000); order on reh'g, Order No. 637-A, 

FERC Stats. & Regs. Regulations Preambles July 1996 - December 200) ¶ 31,099 

(May 19, 2000); reh'g denied, Order No. 637-B, 92 FERC ¶ 61,062 (2000); aff’d in part 

and denied in part.

454 49 App. U.S.C. 1(4).
Docket No. RM04-7-000 254 

445. In response to APPA/TAPS’ request for clarification, we note that as an initial 

matter, to the extent intervenors are concerned about a seller’s market power from 

ownership or control of interstate natural gas transportation, this would be actionable 

first in a complaint proceeding under section 5 of the Natural Gas Act before turning 

to market-based rate consequences. 

446. With regard to the second category, in light of the comments received, and 

upon further consideration, the Commission adopts a rebuttable presumption that 

sellers cannot erect barriers to entry with regard to the ownership or control of, or 

affiliation with any 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.455 To date, the Commission has not found such 

ownership, control or affiliation to be a potential barrier to entry warranting further 

analysis in the context of market-based rate proceedings. However, unlike the first 

category of inputs, the Commission does not have sufficient evidence to remove these 

inputs from the analysis entirely. Accordingly, we will rebuttably presume 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 

 455 We modify the definition of “inputs to electric power production” in 18 CFR 

35.36(a)(4) to reflect this clarification. 
Docket No. RM04-7-000 255 

transportation of coal supplies such as barges and rail cars do not allow a seller to 

raise entry barriers, but will allow intervenors to demonstrate otherwise. We note 

that this rebuttable presumption only applies if the seller describes and attests to these 

inputs to electric power production, as described herein. 

447. With regard to this second category of inputs to electric power production, we 

will require 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, 

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, with some modifications to the affirmative statement from 

what was proposed in the NOPR. Instead of requiring sellers to make an affirmative 

statement that they have not erected barriers to entry into the relevant market, we will 

require sellers 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. We clarify 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. 

448. We therefore modify the proposed regulations to require 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; sources of coal 

supplies and the transportation of coal supplies such as barges and rail cars, to ensure 
Docket No. RM04-7-000 256 

that this information is included in the record of each market-based rate proceeding. 

In addition, a seller is required to make an affirmative statement that it has not erected 

barriers to entry into the relevant market and will not erect barriers to entry into the 

relevant market. 

449. While some commenters raise concerns that codification of these possible 

barriers may inappropriately limit the analysis of a seller’s potential to erect other 

barriers to entry, we clarify that we are codifying what showing a seller must make in 

order to receive authority to make sales of electric power at market-based rates. By 

so doing, we are not preventing intervenors from raising other barriers to entry 

concerns for consideration on a case-by-case basis. This approach will allow unique 

or newly developed barriers to entry to be brought before the Commission. 

450. We will not adopt APPA/TAPS’ proposal that the affirmation be signed and 

affirmed by a senior corporate officer. Section 35.37(b) of the Commission’s 

regulations requires sellers to “provide accurate and factual information and not 

submit false or misleading information, or omit material information, in any 

communication with the Commission...”456 The Commission has ample authority to 

enforce its regulations, and therefore does not believe that it is necessary in these 

circumstances to require the affirmative statement to be signed by a senior corporate 

official. 

 456 18 CFR 35.41(b) (formerly 18 CFR 35.37(b)). 
Docket No. RM04-7-000 257 

451. The changes made to the evaluation of other barriers to entry, as described 

above, should not be more burdensome on market-based rate sellers than that which 

is currently in place. For the most part, the Commission is maintaining its current 

policy, with some variation and additional guidance on what is required. The policy 

adopted in this Final Rule should provide sellers with additional clarity regarding 

what needs to be addressed as a potential other barrier to entry and the way in which 

to address it.

3. Barriers Erected or Controlled by Other Than The Seller

Comments

452. APPA/TAPS state that entry conditions and barriers, regardless of origin, need 

to be considered in both the horizontal and vertical market power tests.457

APPA/TAPS state that the Commission should not focus solely on entry barriers 

erected by the seller itself and that the Commission must be receptive to claims that 

entry barriers in the seller’s market provide or enhance market power, even if the 

seller itself did not erect the barriers.458 Another commenter states that the 

Commission should maintain a separate evaluation on other barriers to entry that are 

not caused by a seller, thus requiring a seller to address barrier to entry issues to the 

relevant market, even if those barriers are not caused by a seller or its affiliates. 

 457 APPA/TAPS at 6. 

458 APPA/TAPS at 82-84. 
Docket No. RM04-7-000 258 

Commission Determination

453. The Commission finds that it is not reasonable to routinely require sellers to 

make a showing regarding potential barriers to entry that others might erect and that 

are beyond the seller’s control. However, we will allow intervenors to present 

evidence in this regard, and by this means we will be able to assess the existence of 

barriers to entry beyond the seller’s control but which may affect the seller’s ability to 

exercise market power. Should a potential barrier in the relevant market be raised by 

an intervenor, the Commission will address such claims on a case-by-case basis. 

4. Planning and Expansion Efforts

454. In the NOPR, the Commission noted that several commenters had suggested 

that a transmission planning and expansion process can ameliorate vertical market 

power, and, accordingly, the Commission was seeking comment on the issues of 

transmission planning and expansion in the notice of proposed rulemaking in the 

OATT Reform Rulemaking. The Commission sought comment in the NOPR on 

whether the planning and expansion efforts in the OATT Reform Rulemaking would 

address commenters’ concerns here. 

Comments

455. APPA/TAPS state that there will be a continuing need to address transmission 

market power issues, even after adoption of a revised pro forma OATT, because the 
Docket No. RM04-7-000 259 

improvements in transmission planning and expansion will not be immediately 

felt.459 EPSA states that it advocates robust, independent and mandatory regional 

planning as a means to combat vertical market power and ensure competitive 

markets.460

456. TDU Systems recommend that the Commission revoke a transmission 

provider’s market-based rate authority if it fails to build transmission to 

accommodate the needs of its transmission customers demonstrated through an open, 

joint planning process.461 TDU Systems submit that willful failure to plan, maintain 

and expand the transmission system to meet transmission customers’ needs is an 

abuse of vertical market power and creates structural barriers to competition. 

457. ELCON states that while it is encouraged by proposals in the OATT Reform 

Rulemaking, it recommends that transmission market power be the subject of a new 

rulemaking.462 Similarly, EPSA asserts that a technical conference to develop the 

barriers to entry portion of the screens would help ensure an open, accessible, and 

robust competitive market.463

 459 APPA/TAPS at 80-85 

460 EPSA at 27. 

461 TDU Systems at 21-23 

462 ELCON at 5-6. 

463 EPSA at 28. 
Docket No. RM04-7-000 260 

Commission Determination

458. We find that our reforms to the pro forma OATT to require coordinated 

transmission planning on a local and regional level address the concerns raised by 

commenters. While we recognize that the transmission planning reforms in Order 

No. 890 are still in the process of being implemented, failure to plan, maintain and 

expand the transmission system in accordance with the applicable, Commissionapproved OATT has always been, and will continue to be, an OATT violation. Order 

No. 890 provides for revocation of an entity’s, and possibly that of its affiliates, 

market-based rate authority in response to an OATT violation upon a finding of a 

specific factual nexus between the violation and the entity’s market-based rate 

authority.464 Should such a violation occur, the Commission will address it in that 

context. The Commission does not find that the need exists to convene a technical 

conference in this regard. The OATT Reform Rulemaking dealt extensively with this 

issue and the Commission finds that it has been adequately addressed in Order No. 

890. 

5. Monopsony Power

459. In the NOPR, the Commission sought comment on whether the exercise of 

buyer’s market power by the transmission provider should be considered a potential 

 464 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1743, 1747. 
Docket No. RM04-7-000 261 

barrier to entry and, if so, what criteria the Commission should use to evaluate 

evidence that is presented. 

Comments

460. Allegheny states that the NOPR provided no explanation for why a 

transmission provider’s buyer’s market power should be relevant to the analysis.465 

EEI argues that the Commission should not consider buyer’s market power as a 

barrier to entry because it is not relevant to the analysis. According to EEI, the 

market-based rate analysis considers the ability of the applicant to exercise market 

power as a seller, not a buyer, which is consistent with the Commission’s authority 

under section 205 of the FPA, which regulates the sale of electricity. EEI asserts that 

states generally have jurisdiction over the purchase of electricity by franchised 

utilities.466

461. EPSA argues that if a utility holds a dominant purchasing position in the 

wholesale marketplace that allows it to exert excessive and discretionary buying 

power (of both supply and supply generation facilities), the exercise of market power 

will then lie with the buyer, not the seller. This problem is exacerbated when such a 

purchasing utility also owns, controls or dispatches its own proprietary supply and the 

relevant transmission system. 

 465 Allegheny Energy at 10. 

466 EEI at 43. 
Docket No. RM04-7-000 262 

462. EPSA states that some would argue that the Commission cannot order 

economic dispatch or competitive solicitation because the FPA grants the 

Commission jurisdiction over sales, not purchases. However, EPSA submits that the 

Commission would not be mandating purchases, but eliminating the exercise of 

market power which directly raises the prices for wholesale sales. In so doing, the 

Commission would be using its tools under sections 205 and 206 of the FPA to 

ensure just and reasonable wholesale rates by allowing competitive alternatives to 

enter the market and protecting consumers from practices that will result in excessive 

rates and charges. EPSA argues that the Commission must develop a transparent, 

methodical process for assessing this segment of the vertical market power analysis. 

EPSA submits that load serving entities that are transmission providers must, in 

addition to providing enhanced transmission services, facilitate accessible long-term 

markets through all-source competitive procurement processes, preferably via state 

created and supervised means, with independent third party oversight. It asserts that 

the Commission must achieve and ensure these goals through a transparent, welldeveloped process. EPSA requests that the Commission convene a technical 

conference in order to fully develop that process and ensure that barriers to entry are 

properly mitigated.467

 467 EPSA at 26-27. 
Docket No. RM04-7-000 263 

Commission Determination

463. EPSA’s proposal not only raises jurisdictional issues, but EPSA has failed to 

provide specific instances in which the exercise of monopsony power has taken place 

and has provided no guidance as to how buyer market power should be measured 

(even assuming the Commission has jurisdiction to address it). The Commission 

does not believe it is appropriate to attempt to address these difficult issues without 

specific evidence of monopsony power and a clear delineation of the state-federal 

jurisdiction issues that would arise in the context of a specific seller and specific set 

of circumstances. For the same reason, we will not grant EPSA’s request to convene 

a technical conference to address such issues generically. Until EPSA or others 

provide such information concerning a particular seller in either a market-based rate 

proceeding or a complaint, we defer judgment on the many difficult issues raised by 

EPSA. 

C. Affiliate Abuse 

1. General Affiliate Terms and Conditions

a. Codifying Affiliate Restrictions in Commission Regulations

 Commission Proposal

464. In the NOPR the Commission proposed to discontinue referring to affiliate 

abuse as a separate “prong” of the market-based rate analysis and instead proposed to 

codify in the regulations at 18 CFR part 35, subpart H, an explicit requirement that 

any seller with market-based rate authority must comply with the affiliate power sales 

restrictions and other affiliate restrictions. The Commission proposed to address 
Docket No. RM04-7-000 264 

affiliate abuse by requiring that the conditions set forth in the proposed regulations be 

satisfied on an ongoing basis as a condition of obtaining and retaining market-based 

rate authority. The Commission indicated that a seller seeking to obtain or retain 

market-based rate authority will be obligated to provide a detailed description of its 

corporate structure so that the Commission can be assured that the Commission’s 

requirements are being applied correctly. In particular, the Commission proposed 

that sellers with franchised service territories be required to make a showing 

regarding whether they serve captive customers and to identify all “non-regulated” 

power sales affiliates, such as affiliated marketers and generators.468 

465. The Commission further proposed that, as a condition of receiving marketbased rate authority, sellers must adopt the MBR tariff (included as Appendix A to 

the NOPR) which includes a provision requiring the seller to comply with, among 

other things, the affiliate restrictions in the regulations. The Commission noted that 

failure to satisfy the conditions set forth in the affiliate restrictions will constitute a 

tariff violation. The Commission sought comment on these proposals 

 468 In the NOPR, the Commission proposed to use the term “non-regulated power 

sales affiliate.” As discussed below, this Final Rule uses the term “market-regulated 

power sales affiliate” instead. “Market-regulated” power sales affiliates, for purposes of 

this rule, refers to sellers that sell at market-based rates rather than cost-based rates. If 

such sellers are public utilities, technically, they are not unregulated since they must 

receive market-based rate authority from the Commission and are subject to ongoing 

oversight by the Commission. See discussion infra. 
Docket No. RM04-7-000 265 

Comments

466. As a general matter, commenters support the Commission’s proposal to codify 

the affiliate restrictions in the Commission’s regulations.469 No comments were 

received opposing the proposal to codify affiliate restrictions in the Commission’s 

regulations. 

Commission Determination

467. The Commission will adopt the proposal in the NOPR to discontinue 

considering affiliate abuse as a separate “prong” of the market-based rate analysis and 

instead codify in the Commission’s regulations in § 35.39 an explicit requirement that 

any seller with market-based rate authority must comply with the affiliate restrictions. 

This will address affiliate abuse by requiring that the conditions set forth in the 

regulations be satisfied on an ongoing basis as a condition of obtaining and retaining 

market-based rate authority. Included in the regulations will be a provision expressly 

prohibiting power sales between a franchised public utility with captive customers 

and any market-regulated power sales affiliates without first receiving Commission 

authorization for the transaction under section 205 of the FPA. Also included in the 

regulations will be the requirements that have previously been known as the marketbased rate “code of conduct,” as those requirements have been revised in this Final 

Rule. 

 469 See generally APPA/TAPS at 7; 85-86. 
Docket No. RM04-7-000 266 

468. Additionally, although we do not adopt the proposal to require that, as a 

condition of receiving market-based rate authority, sellers must adopt the MBR tariff 

(included as Appendix A to the NOPR), we do adopt a set of standard tariff 

provisions that we will require each seller to include in its market-based rate tariff, 

including a provision requiring the seller to comply with, among other things, the 

affiliate restrictions in the regulations. We further adopt the proposal that failure to 

satisfy the conditions set forth in the affiliate restrictions will constitute a tariff 

violation. 

b. Definition of “Captive Customers”

Commission Proposal

469. The Commission stated in the NOPR that, among other things, in the 

Commission’s Final Rule on transactions subject to section 203 of the FPA, the 

Commission defined the term “captive customers” to mean “any wholesale or retail 

electric energy customers served under cost-based regulation.”470 The Commission 

sought comment on whether the same definition should be used for purposes of this 

rule. 

 470 Transactions Subject to FPA section 203, Order No. 669-A, 71 FR 28422 

(May 16, 2006), FERC Stats. & Regs. ¶ 31,214 (2006). See also Repeal of the Public 

Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding 

Company Act of 2005, Order No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & 

Regs. ¶ 31, 213 (2006). 
Docket No. RM04-7-000 267 

Comments

470. While a number of commenters support the Commission’s proposal to codify 

the affiliate abuse “prong” in the Commission’s regulations,471 they comment that the 

proposed affiliate abuse restrictions do not do enough to protect retail customers from 

affiliate abuse.472 NASUCA argues that affiliate abuse restrictions should be 

applicable to any affiliate with any retail customers, whether or not the retail affiliate 

is a “franchised” utility, whether or not it has a state-imposed “service obligation,” 

and whether or not its customers are characterized as “captive.” NASUCA submits 

that the Commission should not rely on a state’s adoption of a retail access regime for 

any determination that a customer is not captive. Further, although NASUCA 

comments that the Commission’s proposed definition for “captive customers” is an 

improvement from the text of the proposed regulation (which contains no definition 

of “captive customers”), NASUCA suggests it could also invite distinctions turning 

on the meaning of “cost-based regulation” that might cause future uncertainty in 

some circumstances and a corresponding loss of customer protection.473 

471. New Jersey Board argues that when customers lack realistic alternatives to 

purchasing power from their local utility, regardless of a legal right to competitive 

 471 New Jersey Board at 3. 

472 NASUCA at 20-30. 

473 NASUCA at 20-30. 
Docket No. RM04-7-000 268 

power suppliers, such customers are still captive. New Jersey Board states that most 

customers in retail choice states still rely on the provider-of-last-resort for electric 

service and, thus, are still captive customers.474 New Jersey Board comments that, 

due to the relatively young retail choice and deregulation programs in many states, “it 

would be premature to declare electric retail choice to be vibrant enough to leave 

consumer protection from affiliate abuses completely to the marketplace.”475 New 

Jersey Board states that, even where there are a few providers that comprise the 

market, such oligopolies often exhibit the same lack of competition and high prices as 

are seen in a monopoly market. Thus, affiliate abuse would remain a concern where 

utilities would be granted market-based rate authority.476

472. AARP similarly comments that the proposed definition of “captive customers” 

fails to capture the potential for adverse impacts on retail customers of “default” 

suppliers and thus, the coverage of the Commission’s affiliate restrictions should be 

expanded to prevent customers from bearing the costs of non-regulated marketing 

affiliates of the public utility they rely on for reliable service.477 

 474 New Jersey Board reply comments at 3-4. 

475 Id. at 5. 

476Id. 

477 AARP at 10-11. 
Docket No. RM04-7-000 269 

473. ELCON suggests that “captive customers” should be defined as any end-users 

that do not have real competitive opportunities.478 It recommends that the 

Commission adopt a case-specific approach to identifying captive customers to 

account for the failure of retail competition in many restructured states. 

474. A number of other commenters argue that the proposed definition of “captive 

customers” is too broad479 and would improperly include customers with competitive 

alternatives. They state that the Commission should clarify that “captive customers” 

does 

not include customers in states with retail choice.480 Duke recommends that the 

Commission define “captive customer” as “any electric energy customer that cannot 

choose an alternative energy supplier.”481 Duke adds that initial commenters, such as 

ELCON, provide no support for their assertion that state retail access programs do not 

generate effective competition and that most provider-of-last-resort customers are 

actually captive. 

 478 ELCON at 2, 7-8. 

479 Ameren at 11-14; Allegheny at 12-13; EEI at 44; FirstEnergy at 13; Duke at 4, 

32; and Duquesne at 4.

480 Constellation argues that customers are not to be considered “captive” and a 

seller is therefore not considered a franchised public utility when a retail choice program 

is in place for the public utility’s retail customers. Constellation at 4. 

481 Duke at 32-36. Duke reply comments at 22-23. 
Docket No. RM04-7-000 270 

475. Ameren comments that while there are sellers with market-based rate authority 

that have no captive wholesale customers for energy, but do have a cost-based rate 

schedule for reactive power supply, the fact that a seller has wholesale customers 

under a single cost-based rate for reactive power should not render the entity a seller 

with “captive customers” and therefore, subject to the affiliate restrictions.482 It states 

that such a seller would have no ability to transfer benefits from its “captive 

customers” (customers taking reactive power services at cost-based rates) to subsidize 

its unregulated market-based rate sales, given the different products at issue and the 

restrictions of the cost-based rates for reactive power. 

476. APPA/TAPS submit that the definition of “captive customers” should include 

wholesale transmission customers captive to the transmission provider’s system.483 

APPA/TAPS state that affiliate abuse not only raises costs to wholesale customers, it 

can also harm competition such as through cross-subsidization that provides the seller 

with an unfair competitive advantage. Therefore, APPA/TAPS state that wholesale 

transmission customers captive to the transmission provider’s system are particularly 

vulnerable to this kind of competitive harm and should be included in the definition 

of “captive customers” in the regulations.484

 482 Ameren at 12. 

483 APPA/TAPS at 7, 86-87

484 Id. at 86-87. 
Docket No. RM04-7-000 271 

477. EEI responds to APPA/TAPS’ comment by stating that it is “completely 

unnecessary” to include transmission dependent utilities in the definition of captive 

customers since Order No. 888 already provides sufficient protections for 

transmission customers. Additionally, EEI replies that transmission dependent 

utilities are like customers with retail choice who have chosen to stay under costbased rates while other transmission customers have broader options. EEI responds 

that the Commission does not currently consider such customers captive and there is 

no reason to change this policy.485

Commission Determination

478. The Commission adopts the NOPR proposal to define “captive customers” as 

“any wholesale or retail electric energy customers served under cost-based 

regulation.” 

479. The Commission clarifies in response to several comments 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. Retail customers who choose to be served under cost-based rates but have 

the ability, by virtue of state law, to choose one retail supplier over another, are not 

considered to be under "cost-based regulation" and therefore are not “captive.” 

 485 EEI reply comments at 35-36. 
Docket No. RM04-7-000 272 

480. As the Commission has explained, retail customers in retail choice states who 

choose to buy power from their local utility at cost-based rates as part of that utility’s 

provider-of-last-resort obligation are not considered captive customers because, 

although they may choose not to do so, they have the ability to take service from a 

different supplier whose rates are set by the marketplace. In other words, they are not 

served under cost-based regulation, since that term indicates a regulatory regime in 

which retail choice is not available.486 On the other hand, in a regulatory regime in 

which retail customers have no ability to choose a supplier, they are considered 

captive because they must purchase from the local utility pursuant to cost-based rates 

set by a state or local regulatory authority.487 Therefore, with this clarification, the 

Commission will adopt the definition of “captive customers” proposed in the NOPR 

and clarifies, that, as the Commission did in Order No. 669-A, we will include the 

definition of captive customers in the regulations. Regarding wholesale customers, 

sellers should continue to explain why, if they have wholesale customers, those 

customers are not captive. 

481. We note that it is not the role of this Commission to evaluate the success or 

failure of a state’s retail choice program including whether sufficient choices are 

 486 Duquesne Light Holdings, Inc., 117 FERC ¶ 61,326 at P 38 (2006). 

487 Where a utility has captive retail customers, but industrial customers have retail 

choice, we would consider that utility to have captive customers because the retail 

residential customers are captive. 
Docket No. RM04-7-000 273 

available for customers inclined to choose a different supplier. In this regard, the 

states are best equipped to make such a determination and, if necessary, modify or 

otherwise revise their retail access programs as they deem appropriate. Further, to 

the extent a retail customer in a retail choice state elects to be served by its local 

utility under provider-of-last-resort obligations, the state or local rate setting 

authority, in determining just and reasonable cost-based retail rates, would in most 

circumstances be able to review the prudence of affiliate purchased power costs and 

disallow pass-through of costs incurred as a result of an affiliate undue preference. 

482. We also decline to include transmission customers in the definition of “captive 

customers” for purposes of market-based rates. We agree with EEI that the 

Commission's open access policies protect transmission customers from the exercise 

of vertical market power. In this regard, we note that the Commission recently issued 

Order No. 890, which revised the pro forma OATT to ensure that it achieves its 

original purpose of remedying undue discrimination. Order No. 890 provided greater 

clarity regarding the requirements of the pro forma OATT and greater transparency in 

the rules applicable to the planning and use of the transmission system, in order to 

reduce opportunities for the exercise of undue discrimination, make undue 

discrimination easier to detect, and facilitate the Commission’s enforcement of the 

tariff. 

483. In response to Ameren’s comments that a seller with wholesale customers 

under a single cost-based rate for reactive power should not be considered a seller 

with “captive customers” subject to the affiliate restrictions, we agree that such 
Docket No. RM04-7-000 274 

customers are not captive for purposes of market-based rates. The concerns 

underlying the affiliate restrictions do not apply to sales of reactive power because 

those sales are typically either made to transmission providers so that the 

transmission provider can satisfy its obligation to provide reactive power or made by 

the transmission provider under its applicable OATT. 

c. Definition of “Non-Regulated Power Sales Affiliate”

Commission Proposal

484. Proposed § 35.36(a)(6) defined “non-regulated power sales affiliate” as “any 

non-traditional power seller affiliate, including a power marketer, exempt wholesale 

generator, qualifying facility or other power seller affiliate, whose power sales are not 

regulated on a cost basis under the FPA.” 

Comments

485. A number of commenters seek clarification and modification of the 

Commission’s proposed definition of “non-regulated power sales affiliate.” 

486. Southern requests clarification that a franchised public utility does not become 

a non-regulated power sales affiliate simply because it may make some wholesale 

sales under market-based rate authority. 

487. SoCal Edison argues that the Commission offers no explanation for including 

Qualifying Facilities (QFs) in the definition of “non-regulated power sales affiliate.” 

It states that the proposed definition of non-regulated power sales affiliate would 

subject QFs that may not have market-based rate authority to the code of conduct. It 

states that the NOPR proposal would constitute a departure from traditional PURPA 
Docket No. RM04-7-000 275 

implementation and from the Commission’s recently revised regulations reaffirming 

that QF contracts created pursuant to a statutory regulatory authority’s 

implementation of PURPA are exempt from review under sections 205 and 206 of the 

FPA.488 PG&E asserts that the Commission should clarify the meaning of “nonregulated power sales affiliate” so that it does not encompass all affiliates such as 

parent companies or the natural gas LDC function of the regulated, franchised 

utility.489

488. Xcel states that it is not clear whether the following result was intended, but 

the definition arguably could cover a “traditional” utility with a franchised retail 

service territory that had converted all of its wholesale sales from cost-based to 

market-based rates. According to Xcel, not all utilities will be selling at cost-based 

rates at wholesale, even though they may still be doing so at retail in franchised 

service territories.490 Xcel does not believe that it would be reasonable to exclude 

from the definition of “non-regulated power sales affiliate” a utility that serves retail 

customers under a franchised service territory. Xcel also comments that the 

Commission should allow a waiver provision for utilities’ subsidiaries or affiliates to 

be treated under the Commission’s affiliate sales rules as affiliated utilities rather than 

 488 SoCal Edison at 4-6. 

489 PG&E at 14-21. 

490 Xcel at 15. 
Docket No. RM04-7-000 276 

as “non-regulated power sales affiliates.”491 Xcel believes that the proposed 

definition would generally serve to demarcate affiliates that should be treated as 

regulated from those that should be treated as non-regulated under the Commission’s 

affiliate rules but states that it is not desirable or beneficial to draw a completely 

bright line between the two. Xcel states that some flexibility may be beneficial for 

both utilities and their customers and the Commission should not foreclose innovative 

structures by adopting hard and fast rules.492 

489. NASUCA also suggests revisions to this definition, out of concern that several 

of the terms used (non-regulated, non-traditional, regulated on a cost basis) are vague, 

inaccurate and unnecessary.493 NASUCA suggests that the term be renamed “power 

sales affiliate with market-based rates” and defined as “any power seller affiliate 

utility, including a power marketer, exempt wholesale generator, qualifying facility or 

other power seller affiliate, with market-based rates authorized under these rules or 

Commission orders.”494

 491 Id. 

492 Id. at 16. 

493 NASUCA at 30. 

494 Id. at 30. 
Docket No. RM04-7-000 277 

Commission Determination 

490. The Commission will modify the definition of “non-regulated power sales 

affiliate,” and change the term to “market-regulated power sales affiliate.”495 In 

response to various commenters, we clarify that this definition is intended to apply 

only to non-franchised power sales affiliates (whose power sales are not regulated on 

a cost basis under the FPA, e.g., affiliates whose power sales are made at marketbased rates) of franchised public utilities. Additionally, while we recognize that we 

have used the term “non-regulated” in the past, we believe that “market-regulated” is 

a more appropriate description for the entities we intend to capture in this definition. 

Accordingly, in this Final Rule, we revise the definition of “market-regulated power 

sales affiliate” to mean “any power seller affiliate other than a franchised public 

utility, including a power marketer, exempt wholesale generator, qualifying facility or 

other power seller affiliate, whose power sales are regulated in whole or in part at 

market-based rates.” Because the revised definition includes only non-franchised 

public utilities, it does not apply to a franchised public utility that makes some sales 

at market-based rates.496 

 495 NOPR at Proposed Regulations at 18 CFR 35.36 (a)(6). We adopt this 

regulation at 18 CFR 35.36 (a)(7). 

496 However, under the standards of conduct, a wholesale merchant function that 

engages in such sales must function independently of the utility’s transmission function. 

18 CFR 358(d)(3) and 18 CFR 358.4(a)(1).
Docket No. RM04-7-000 278 

491. Xcel posits a somewhat different scenario under which it believes that a 

franchised public utility would fall within the definition of “non-regulated power 

sales affiliate,” namely, if such utility makes no wholesale sales that are regulated on 

a cost basis (making only wholesale sales at market-based rates) but serves retail 

customers under a franchised service territory. With the revision to the definition of 

“market-regulated power sales affiliate” that we adopt here, such a utility would not 

fall within the definition of “market-regulated power sales affiliate” since it has a 

franchised service territory. 

492. In addition, we note that the Commission has historically placed affiliate 

restrictions only on the relationship between a franchised public utility with captive 

customers and any affiliated market-regulated power sales affiliate. Nevertheless, we

believe that there may be circumstances in which it also would be appropriate to 

impose similar restrictions on the relationship of two affiliated franchised public 

utilities where one of the affiliates has captive customers and one does not have 

captive customers. In such a case, there is a potential for the transfer of benefits from 

the captive customers of the first franchised utility to the benefit of the second 

franchised utility and ultimately to the joint stockholders of the two affiliated 

franchised public utilities. Commenters in the instant proceeding did not address the 

potential for affiliate abuse in this situation (i.e., between a franchised public utility 

with captive customers and an affiliated franchised public utility without captive 

customers). Accordingly, we do not generically impose the affiliate restrictions on 
Docket No. RM04-7-000 279 

such relationships but will evaluate whether to impose the affiliate restrictions in such 

situations on a case-by-case basis. 

493. However, to avoid confusion between references to a “franchised public utility 

with captive customers” and a “franchised public utility without captive customers” 

we will revise the definition of “franchised public utility” in § 35.36(a) (5) to remove 

the reference to captive customers. Accordingly, “franchised public utility” will be 

defined as “a public utility with a franchised service obligation under state law.” 

Further, we will revise other sections of the affiliate restrictions to specifically use the 

term “franchised public utility with captive customers” to clarify when the affiliate 

restrictions apply. 

494. Additionally, not all qualifying facilities are necessarily included in the 

proposed definition of “market-regulated power sales affiliate.” Only those 

qualifying facilities whose market-based rate sales fall under the Commission’s 

jurisdiction would fall within the definition of “market-regulated power sales 

affiliate.” To the extent that some of a qualifying facility’s sales are regulated under 

the FPA, even if other sales are regulated by the states, such a qualifying facility 

would be considered a market-regulated power sales affiliate by virtue of its FPA 

jurisdictional sales. 

495. Additionally, the Commission clarifies that the definition of “market-regulated 

power sales affiliate” does not encompass all affiliates such as parent companies or 

the natural gas LDC function of the regulated franchised utility; rather, it only 

includes non-franchised, power sales affiliates (sellers) that sell power in whole or in 
Docket No. RM04-7-000 280 

part at market based rates, and not an affiliated service company or others who are 

not authorized to make sales of power.

d. Other Definitions

In the NOPR, the Commission proposed to adopt a restriction on affiliate 

sales of electric energy, whereby no wholesale sale of electric energy could 

be made between a public utility seller with a franchised service territory 

and a non-regulated power sales affiliate without first receiving 

Commission authorization under FPA section 205. This restriction would 

be a condition of obtaining and retaining market-based rate authority, and a 

failure to satisfy that condition would be a violation of the seller’s marketbased rate tariff.497 

Comments

496. Constellation proposes that the language in the proposed affiliate sales 

restriction provision be amended to use the defined term “franchised public utility” 

by replacing the phrase “public utility Seller with a franchised service territory” with 

“Seller that is a franchised public utility.” Constellation submits that this change 

would make clear that the affiliate restrictions apply only if the seller is affiliated with 

a public utility that has captive customers, which it states appears to be the 

Commission’s intent.498 

497. FirstEnergy proposes that a definition of franchised service territory be added 

to the regulations to clarify that the affiliate sales restriction would only apply to 

 497 NOPR at P 108. 

498 Constellation at 13-17. 
Docket No. RM04-7-000 281 

transactions involving public utilities with captive retail customers, and would not 

apply in areas in which there is retail choice.499 

Commission Determination

498. The Commission’s intent was that the affiliate sales restriction in proposed 

§ 35.39(a) (now § 35.39(b)) would apply where a utility with a franchised service 

territory with captive customers proposes to make wholesale sales at market-based 

rates to a market-regulated power sales affiliate, or vice versa. Accordingly, we will 

revise § 35.39(a) (now § 35.39(b)) to replace “public utility Seller with a 

franchised service territory” with “franchised public utility with captive customers.” 

In light of this clarification, we do not believe it necessary to add a definition of 

franchised service territory to the regulations, as proposed by FirstEnergy. 

e. Treating Merging Companies as Affiliates 

Commission Proposal

499. In the NOPR, the Commission noted that, for purposes of affiliate abuse, 

companies proposing to merge are considered affiliates under their market-based rate 

tariffs while their proposed merger is pending, and sought comments regarding at 

what point the Commission should consider two non-affiliates as merging partners.500 

 499 See, e.g., FirstEnergy at 12-13. 

500 NOPR at P 116. 
Docket No. RM04-7-000 282 

Comments

500. PG&E comments that affiliate sales regulations should not apply to contracts 

that pre-date the announcement of a merger. PG&E states that the Commission 

should allow merging companies sufficient time (e.g., 30 days) after the 

announcement of a merger before enforcing the affiliate sales regulations in order to 

give the merging companies time to acquire the necessary information and documents 

to prevent a company from being held responsible for activities of the merging 

company that it has no knowledge of or control over.501

Commission Determination

501. The Commission will continue to require that, for purposes of affiliate abuse, 

companies proposing to merge will be treated as affiliates under their market-based 

rate tariffs while their proposed merger is pending.502 The Commission will adopt 

the proposal to use the date a merger is announced as the triggering event for 

considering two non-affiliates as merging partners. In this regard, we reject PG&E's 

proposal that the Commission allow an additional 30 days after an announced merger 

to begin treating, for the purpose of affiliate abuse, merging partners as affiliates. 

 501 PG&E at 14-21. 

502 Cinergy, Inc., 74 FERC ¶ 61,281 (1996); Consolidated Edison Energy, Inc., 

83 FERC ¶ 61,236 at 62,034 (1998); Central and South West Services, Inc., 82 FERC 

¶ 61,101 at 61,103 (1998); Delmarva Power & Light Company, 76 FERC ¶ 61,331 at 

62,582 (1996) ("[T]he self-interest of two merger partners converge sufficiently, even 

before they complete the merger, to compromise the market discipline inherent in arm’slength bargaining that serves as the primary protection against reciprocal dealing."). 
Docket No. RM04-7-000 283 

With the extensive discussions, negotiations and review that precede the formal 

announcement of plans to merge, there is sufficient time for companies to acquire the 

necessary information and documents related to the proposed merger, particularly 

given that utilities are on notice of our policy in this regard. 

502. The Commission clarifies that the requirement that merging companies be 

treated as affiliates while the proposed merger is pending only applies prospectively 

from the date the merger is announced and does not apply to any contracts entered 

into that pre-date the announcement of the merger.503 However, in the case of an 

umbrella agreement that pre-dates the announcement of the merger, any transactions 

under such umbrella agreement that are entered into on or after the date the merger is 

announced would be subject to the affiliate restrictions. Further, if an announced 

merger does not go forward, the affiliate restrictions will cease to apply as of the date 

the announcement is made that the merger will not go forward.

f. Treating Energy/Asset Managers as Affiliates

Commission Proposal

503. In the NOPR, the Commission proposed that unaffiliated entities that engage 

in energy/asset management of generation on behalf of a franchised public utility 

with captive customers be bound by the same affiliate restrictions as those imposed 

 503 This is consistent with the standards of conduct, which require transmission 

providers to post information concerning potential merger partners as affiliates within 

seven days after the potential merger is announced. 18 CFR 358.4(b)(3)(v). 
Docket No. RM04-7-000 284 

on the franchised public utility and the non-regulated power sales affiliates.504 The 

Commission recognized that there has been an increased range of activities engaged 

in by asset or energy managers.505 The Commission noted that although asset 

managers can provide valuable services and benefit consumers and the marketplace, 

such relationships also could result in transactions harmful to captive customers.506 

Accordingly, the Commission proposed that an entity managing generation for the 

franchised public utility should be subject to the same affiliate restrictions as the 

franchised public utility (e.g., restrictions on affiliate sales and information sharing). 

The Commission referenced a settlement in which Enforcement staff alleged that an 

affiliated power marketer acting as an asset manager for three generation-owning 

affiliates violated § 214 of the FPA.507 As a result, if a company is managing 

generation assets for the franchised public utility, such entity would be subject to the 

same information sharing provision as the franchised public utility with regard to 

 504 NOPR at P 117, 130, 131. 

505 Id. at P 124 citing Kevin Heslin, A few thoughts on the industry: Ideas from 

session at Globalcon, Energy User News, July 1, 2002, at 12 (Noting that prior to 

deregulation, “an energy manager had relatively straightforward tasks: understanding 

applicable tariffs, evaluating the possible installation of energy conservation measures 

(ECMs), and considering whether to install on-site generation” but that “now, an energy 

manager has to be conversant with a far greater number of issues” such as complex legal 

issues and financial instruments like derivatives.) 

506 Id. 

507 Id. at P 124 (citing Cleco Corp., 104 FERC ¶ 61,125 (2003) (Cleco)). 

507 NOPR at P 130. 
Docket No. RM04-7-000 285 

information shared with non-regulated affiliates, such as power marketers and power 

producers.508 Similarly, asset managers of a non-regulated affiliate’s generation 

assets would be subject to the same affiliate restrictions as the market-regulated 

power sales affiliate, including the information sharing provision.509

Comments

504. Morgan Stanley comments that unaffiliated asset and energy managers should 

not be treated as affiliates of owners of the managed portfolios and that it would be 

overly inclusive for the Commission to adopt a presumption of control that would 

treat the energy manager as a franchised utility for purposes of the affiliate abuse 

rules.510 Financial Companies argue that the Commission should not apply the 

affiliate abuse restrictions generically to all unaffiliated energy managers that provide 

management services to a franchised utility or its affiliates. Rather, the Commission 

should evaluate applicability of the affiliate abuse restrictions on a case-by-case 

basis.511 

505. Allegheny claims that the Commission failed to consider the costs to 

customers, which are likely to be substantial through the loss of efficiencies by 

 

509 Id. at P 131. 

510 Morgan Stanley at 9. 

511 Financial Companies at 11-12. 
Docket No. RM04-7-000 286 

treating asset managers as affiliates.512 Allegheny claims that there will be higher 

costs because: (1) the affiliated asset manager will need to pass added costs on to the 

franchised utility; (2) if the affiliated asset manager cannot pass on costs, it may no 

longer provide the service and the utility may need to set up duplicative asset 

management capability, resulting in higher costs; or (3) the franchised utility will 

need to hire a third-party asset manager, presumably more expensive.513 

Constellation makes a similar argument about the substantial costs and reduction of 

efficiencies by discouraging energy/asset management agreements.514 

506. EPSA states that it opposes the Commission’s proposal to treat asset managers 

as affiliates. It submits that asset managers are not legally affiliates of the companies 

with which they have a contract. If the basis for the proposal to treat asset managers 

as affiliates is for transparency purposes, EPSA says that all such contracts and 

transactions with asset managers are already reportable under the change in status 

final rule.515

507. Alliance Power Marketing argues that by imposing affiliate abuse restrictions 

on entities acting on behalf of a regulated public utility or its non-regulated affiliates, 

the Commission seeks to alter the fundamental principle of responsibility and liability 

 512 Allegheny at 14-15. 

513 Allegheny at 15. 

514 Constellation at 6. 

515 EPSA at 28-32. 
Docket No. RM04-7-000 287 

of the regulated entity by making the third-party also directly accountable, thus 

blurring the lines of accountability. Furthermore, a critical element in applying 

affiliate abuse restrictions to entities’ action on behalf of generation owners lies in 

having a stake in the outcome rather than just considering some direct or indirect 

control. Alliance Power Marketing asserts that evaluating control over the outcome 

as the threshold for asset managers could sweep up many entities, such as 

RTOs/ISOs, governmental and cooperative entities, that could have jurisdictional and 

practical ramifications.516 

508. A number of other commenters oppose the Commission’s proposal to treat 

unaffiliated energy/asset managers as part of the franchised public utility. They argue 

that the current code of conduct already provides the protections sought by such a 

proposal and the Commission fails to explain the need for such expanded 

regulation.517 Furthermore, they submit that such proposal does not consider the 

additional costs to consumers through lost efficiencies.518 

 516 Alliance Power Marketing at 17-37. 

517 Allegheny Energy Companies at 10-16; PG&E at 14-21. 

518 Allegheny Energy Companies at 10-16. 
Docket No. RM04-7-000 288 

509. PG&E argues that the Commission proposal to consider “entities acting on 

behalf of and for the benefit of [the utility/affiliate]” as part of the utility/affiliate 

itself is unnecessary and overly broad.519 

510. Indianapolis P&L does not oppose the Commission’s proposal to treat asset 

managers as affiliates for the limited purposes of the code of conduct, standards of 

conduct or inter-affiliate transaction issues, but it states that the Commission should 

not treat unaffiliated asset managers as affiliates when determining how much 

generating capacity should be attributed to a generation asset owner.520

511. Financial Companies and Morgan Stanley both state in their reply comments 

that the Commission should not impose affiliate restrictions on unaffiliated energy 

managers, as the Commission provides no basis for such requirement521 and no 

evidence that energy managers can engage in cross-subsidization of unregulated 

affiliates.522

Commission Determination

512. From the various comments submitted it is apparent that our proposal has 

created confusion as to our intent with regard to the treatment of energy/asset 

 519 PG&E at 14-21. 

520 Indianapolis P&L at 7-10. 

521 Morgan Stanley reply comments at 14. 

522 Financial Companies reply comments at 6. 
Docket No. RM04-7-000 289 

managers under the proposed affiliate restrictions. Accordingly, we clarify and 

simplify our approach, as discussed below. 

513. The Commission is concerned that there exists the potential for a franchised 

public utility with captive customers to interact with a market-regulated power sales 

affiliate in ways that transfer benefits to the affiliate and its stockholders to the 

detriment of the captive customers. Therefore, the Commission has adopted certain 

affiliate restrictions to protect the captive customers and, in this Final Rule, is 

codifying those restrictions in our regulations. To that end, we make clear that such 

utilities may not use anyone, including energy/asset managers, to circumvent the 

affiliate restrictions (e.g., independent functioning and information sharing 

prohibitions). Accordingly, we adopt and codify in our regulations at §§ 35.39(c)(1) 

and 35.39(g) an explicit prohibition on using third-party entities to circumvent 

otherwise applicable affiliate restrictions. 

514. We note that energy/asset managers provide a variety of services for 

franchised public utilities and market-regulated power sales affiliates, including, but 

not limited to, operating generation plants (sometimes under tolling agreements), 

acting as billing agents, bundling transmission and power for customers, and 

scheduling transactions. However, regardless of the relationships and duties of an 

energy/asset manager to a franchised public utility or its non-regulated affiliate, the 
Docket No. RM04-7-000 290 

energy/asset manager may not act as a conduit to circumvent the affiliate 

restrictions.523 

515. This approach is consistent with past Commission orders that have identified 

the potential that affiliated exempt wholesale generators or qualifying facilities could 

serve as a conduit for providing below-cost services to an affiliated power marketer at 

the expense of captive customers of the public utility operating companies and 

imposed restrictions to prevent this.524

516. Although several commenters assert that the costs of asset management will 

increase as a result of requiring asset managers to observe the affiliate restrictions, 

they did not provide any examples of why the costs would increase. The 

Commission notes that under this Final Rule, all asset managers are not required to 

observe the affiliate restrictions, only those asset managers which control or market 

generation of the franchised public utility with captive customers or a marketregulated power sales affiliate of a franchised public utility with captive customers. 

In those instances, the need to protect captive customers outweighs any generalized 

assertions of increased cost. 

 523 The Commission is adopting 18 CFR 35.39(g) which prohibits a franchised 

public utility with captive customers and a market-regulated power sales affiliate from 

using anyone as a conduit to circumvent any of the affiliate restrictions, including the 

affiliate sales restriction and the information sharing provision.

524 Southern Company Services, Inc., 72 FERC ¶ 61,324 at 62,408 (1995). 
Docket No. RM04-7-000 291 

517. We note that to the extent that a franchised public utility with captive 

customers and one or more of its non-regulated marketing affiliates obtains the 

services of the same energy/asset manager, such an arrangement would create 

opportunities to harm captive customers depending on how the energy/asset manager 

is structured. For example, without internal separation between the energy/asset 

managers' regulated and non-regulated businesses, there would exist opportunities to 

harm captive customers. 

g. Cooperatives

Comments

518. Suez/Chevron asks the Commission to clarify that jurisdictional utilities 

organized as cooperatives are not exempt from the affiliate abuse rules and that all 

jurisdictional public utilities with captive customers, including utilities organized as 

cooperatives, must comply with the affiliate abuse rules.525

519. El Paso E&P argues that it would appear that the proposed affiliate restrictions 

would apply to power sales at market-based rates made by G&T cooperatives to their 

state-regulated member distribution cooperatives. It states that based on the 

definition of a “franchised public utility” as “a public utility with a franchised service 

obligation under state law and that has captive customers,” distribution cooperatives 

that are granted franchised service territories by state regulatory agencies would be 

 525 Suez/Chevron at 10-12. 
Docket No. RM04-7-000 292 

included in this definition. El Paso E&P asserts that a G&T cooperative with 

authority to sell power at market-based rates would be defined as a non-regulated 

power seller and, accordingly, sales made by a G&T cooperative at market-based 

rates to its affiliated member distribution cooperatives would, under the proposed 

regulations, be required to comply with the requirements of the rule. 526 

520. However, El Paso E&P argues that the Commission has previously stated that 

affiliate abuse is not a concern for cooperatives owned by other cooperatives because 

the cooperatives’ ratepayers are its members. El Paso E&P alleges that the 

Commission has never sufficiently explained the basis for its prior statements. 

According to El Paso E&P, the Commission’s prior statements are based on the 

findings in Hinson Power527 that lack of concern with the potential for affiliate abuse 

is premised on the absence of captive customers that would be subject to the exercise 

of market power. El Paso submits that the fact that ratepayers of the distribution 

cooperative are also members of such cooperatives should not alleviate the 

Commission’s concern about potential affiliate abuse issues. El Paso E&P claims 

that industrial customers of distribution cooperatives with franchised service 

territories are captive to service from the generation and transmission and distribution 

 526 El Paso E&P at 4-9. 

527 Hinson Power Company, 72 FERC ¶ 61,190 (1995). 
Docket No. RM04-7-000 293 

cooperatives that serve them and are in need of protection from the Commission to 

ensure that they are charged just and reasonable rates.528

521. NRECA submits that El Paso misreads the proposed regulations by classifying 

distribution cooperatives as a “public utility Seller” under the proposed regulations 

and NRECA comments that it is not aware of any distribution cooperatives that 

would be classified as “public utility Sellers” thus triggering the restriction on 

affiliate sales without first receiving Commission approval. NRECA states that 

nearly all distribution cooperatives are not regulated as public utilities under the FPA 

because they either have Rural Electrification Act (REA) financing or sell less than 4 

million MWh per year and thus do not qualify as a “public utility” under § 201(f) of 

the FPA. Furthermore, NRECA comments that very few distribution cooperatives 

sell any electricity for resale. Thus, they would not need to obtain market-based rate 

authority under section 205 even if they were not relieved of that obligation by 

section 201(f).529 NRECA also comments that the Commission has explained the 

reasoning behind not requiring cooperatives to comply with the affiliate abuse 

requirements by stating that “in the case of a cooperative, the cooperative’s members 

 528 El Paso E&P at 4-9. 

529 NRECA supplemental reply comments at 5-6. 
Docket No. RM04-7-000 294 

are both the ratepayers and the shareholders, and thus there is no potential danger of 

shifting benefits from one to another.”530

522. El Paso E&P responds that NRECA incorrectly interprets the scope of the 

proposed affiliate restriction and that NRECA ignores the definition of “franchised 

public utility” as “a public utility with a franchised service obligation under state law 

and that has captive customers.” El Paso E&P submits that this definition clearly 

includes distribution cooperatives. El Paso E&P further replies that the fact that 

distribution cooperatives are not “public utilities” regulated by the Commission is 

irrelevant because the Commission is not proposing to regulate sales by such 

distribution cooperatives. Rather, it is proposing to regulate wholesale sales by the 

generation and transmission cooperatives to their member distribution cooperatives. 

Therefore, El Paso E&P argues, the Commission should clarify the regulations to 

ensure that generation and transmission cooperatives are covered under the affiliate 

restrictions.531

523. El Paso E&P also responds that NRECA’s attempt to divorce a generation and 

transmission cooperative’s market-based rate sales to its distribution cooperative 

members from the distribution cooperative’s sales to captive customers ignores the 

cooperative structure. It states that a generation and transmission cooperative is 

 530 NRECA supplemental reply comments at 9. 

531 El Paso E&P answer to reply comments at 2-3. 
Docket No. RM04-7-000 295 

comprised of its member distribution cooperatives and both the generation and 

transmission and distribution cooperatives act in concert in connection with sales to 

industrial customers.532 El Paso E&P also submits that NRECA’s argument suggests 

that the Commission has no jurisdiction over sales to state-regulated franchised 

public utilities that are not cooperatives.533 According to El Paso E&P, the captive 

customers of distribution cooperatives are in need of the same protection from the 

Commission notwithstanding that the distribution cooperatives are regulated by the 

states.534 

524. El Paso E&P also states that wholesale electric sales approved by the 

Commission must be passed through at the retail level. Thus, El Paso E&P states that 

it is not sufficient to suggest that the Commission need not be concerned because the 

distribution cooperatives’ rates are subject to state regulation.535 Finally, El Paso 

E&P responds that NRECA cannot seek the protection of this Commission when its 

members are purchasers of power, and then claim its members should be exempt 

from scrutiny when they are sellers to captive customers such as El Paso E&P. It 

 532 Id. at 3. 

533 Id. 

534 Id. at 4. 

535 Id. 
Docket No. RM04-7-000 296 

asserts that captive customers of generation and transmission and their member 

distribution cooperatives are in need of protection.536

Commission Determination

525. FPA § 201(f) specifically exempts from the Commission’s regulation under 

Part II of the FPA, except as specifically provided, electric cooperatives that receive 

REA financing or sell less than 4 million megawatt hours of electricity per year.537 

Thus, such electric cooperatives are not considered public utilities under the FPA and 

our market-based rate regulations do not apply to those electric cooperatives. 

Further, with respect to distribution-only cooperatives, they either do not meet the 

“public utility” definition because they do not own or operate facilities used for 

wholesale sales or transmission in interstate commerce or, if they do own or operate 

such facilities, they are exempted from Part II regulation by virtue of FPA § 201(f). 

In this regard, we note that NRECA states that it is unaware of any distribution 

cooperatives in the United States that would be “public utility Sellers” under the 

proposed regulations.538 Such a cooperative would not be subject to the affiliate 

restrictions in the proposed regulations at § 35.39. 

 536 Id. at 5. 

537 16 U.S.C. 824(e)-(f) (2006). 

538 NRECA reply comments at 5. 
Docket No. RM04-7-000 297 

526. For electric cooperatives that are public utility sellers and not exempted from 

public utility regulation by FPA § 201(f), as discussed above, the Commission will 

continue to treat such electric cooperatives as not subject to the Commission’s 

affiliate abuse restrictions, based on a finding that transactions of an electric 

cooperative with its members do not present dangers of affiliate abuse through selfdealing. Even if an electric cooperative is not statutorily exempted from our 

regulation under Part II of the FPA, we conclude that a waiver of § 35.39 is 

appropriate. As the Commission has previously explained, “affiliate abuse takes 

place when the affiliated public utility and the affiliated power marketer transact in 

ways that result in a transfer of benefits from the affiliated public utility (and its 

ratepayers) to the affiliated power marketer (and its shareholders).”539 However, as 

the Commission has previously stated in many market-based rate orders over the 

years,540 where a cooperative is involved, the cooperative’s members are both the 

ratepayers and the shareholders. Any profits earned by the cooperative will enure to 

 539 Heartland Energy Services, Inc., 68 FERC ¶ 61,223 at 62,062 (1994). 

540 Hinson Power Company, 72 FERC ¶ 61,190 (1995). See also, e.g., People’s

Electric Corp., 84 FERC ¶ 61,215 at 62,042 (1998) (application raised no issues of 

affiliate abuse because the seller was operated by a cooperative whose ratepayers were 

also its owners); Old Dominion Electric Cooperative, 81 FERC ¶ 61,044 at 61,236 

(1997).
Docket No. RM04-7-000 298 

the benefit of the cooperative’s ratepayers. Therefore, we have found that there is no 

potential danger of shifting benefits from the ratepayers to the shareholders.541

527. Finally, we agree with NRECA’s argument that the issue that El Paso E&P 

discusses in its comments is not a concern that can be addressed through affiliate 

restrictions in market-based rates, but is rather more of a concern of discrimination in 

the allocation of benefits and burdens among retail ratepayers. The Commission does 

not possess jurisdiction to review a distribution cooperative’s retail rates; that issue 

falls under state law. Moreover, El Paso E&P’s argument that wholesale electric 

sales approved by the Commission must be passed through at the retail level is 

misplaced. As the courts have previously held, state commissions are not precluded 

from reviewing the prudence of a company’s purchasing decisions, and may disallow 

pass-through of wholesale purchase costs unless the purchaser had no legal right to 

refuse to make a particular purchase.542 

528. Therefore, for the reasons stated above, the Commission will continue to 

follow its current precedent and find that electric cooperatives that are public utility 

 541 Old Dominion Electric Cooperative, 81 FERC ¶ 61,044 at 61,236 (1997). 

542 Arkansas Power & Light Co. v. Missouri Public Service Commission, 829 F. 

2d 1444 at 1451-52 (8th Cir. 1987). See also Pike County Light & Power v. Pennsylvania 

Public Utility Commission, 465 A.2d 735 at 737-78 (1983); Nantahala Power & Light 

Co. v. Thornburg, 476 U.S. 953 at 965-67 (1986); Mississippi Power & Light Co. v. 

Mississippi ex rel. Moore, 487 U.S. 354 at 369 (1988). 
Docket No. RM04-7-000 299 

sellers and not exempted from public utility regulation by FPA § 201(f) are not 

subject to the Commission’s affiliate abuse requirements. 

2. Power Sales Restrictions

Commission Proposal

529. In the NOPR the Commission proposed to continue the policy of reviewing 

power sales transactions between regulated and “non-regulated” affiliates under 

section 205 of the FPA. This policy means, among other things, that a general grant 

of market-based rate authority does not apply to affiliate sales between a regulated 

and a non-regulated affiliate, absent express authorization by the Commission. 

530. The Commission proposed to amend the regulations to include a provision 

expressly prohibiting power sales between a franchised public utility543 and any of its 

non-regulated power sales affiliates without first receiving authorization for the 

transaction under section 205 of the FPA. 

531. Additionally, although it did not propose to codify the requirement in the 

regulatory text, the Commission proposed that sellers seeking authorization to engage 

in affiliate transactions will continue to be obligated to provide evidence as to 

 543 As proposed in the NOPR, the term “franchised public utility” was defined as 

“a public utility with a franchised service obligation under state law and that has captive 

customers.” As set forth below, to avoid confusion between references to a franchised 

public utility with captive customers and one without, we revise the proposed regulations 

to delete the reference to customers in the definition and to specifically use the term 

“franchised public utility with captive customers” to clarify when the affiliate restrictions 

apply. 
Docket No. RM04-7-000 300 

whether there are captive customers that would trigger the application of the affiliate 

restrictions. The Commission stated that if the Commission finds, based on the 

evidence provided by the seller, that the seller has no captive customers, the affiliate 

restrictions in the regulations would not apply. 

532. The Commission proposed to continue its prior approach for determining what 

types of affiliate sales transactions are permissible and the criteria that should be used 

to make those decisions, including evaluation of the Allegheny and Edgar criteria.544 

Although it did not propose to codify a safe harbor provision in the regulations, the 

Commission noted that when affiliates participate in a competitive solicitation 

process, application of the Allegheny criteria would constitute a safe harbor that 

affiliate abuse conditions are satisfied in a transaction between a franchised public 

utility and its affiliates. The Commission emphasized, however, that using a 

 544 Boston Edison Company Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 

(1991) (Edgar), describing three types of evidence that can be used to show that an 

affiliate power sales transaction is above suspicion ensuring that the market is not 

distorted and captive ratepayers are protected: (1) evidence of direct head-to-head 

competition between the affiliate and competing unaffiliated suppliers in a formal 

solicitation or informal negotiation process; (2) evidence of the prices non-affiliated 

buyers were willing to pay for similar services from the affiliate; or (3) benchmark 

evidence that shows the prices, terms, and conditions of sales made by non-affiliated 

sellers. Allegheny Energy Supply Company, LLC, 108 FERC ¶ 61,082 (2004) 

(Allegheny), stating four guidelines that help the Commission determine if a competitive 

solicitation process satisfies the Edgar criteria: (1) it is transparent; (2) products are well 

defined; (3) bids are evaluated comparably with no advantage to affiliates; and (4) it is 

designed and evaluated by an independent entity. 
Docket No. RM04-7-000 301 

competitive solicitation is not the only way to address concerns that an affiliate 

transaction does not pose undue preference concerns.545

533. The Commission said it continues to believe that tying the price of an affiliate 

transaction to an established, relevant market price or index such as in an RTO or ISO 

is acceptable benchmark evidence and mitigates affiliate abuse concerns so long as 

that benchmark price or index reflects the market price where the affiliate transaction 

occurs. The Commission proposed to allow affiliate transactions based on a nonRTO price index only if the index fulfills the requirements of the November 19 Price 

Index Order546 for eligibility for use in jurisdictional tariffs. The Commission sought 

comment on whether evidence other than competitive solicitations, RTO price or 

non-RTO price indices, or benchmarks described in the NOPR should be accepted in 

an application for authority to engage in market-based affiliate power sales. In 

addition, the Commission proposed to consider two merging partners as affiliates as 

of the date a merger is announced, and sought comments on this proposal (or whether 

to use the date the § 203 application is filed with the Commission, or another time). 

The Commission also proposed that unaffiliated entities that engage in energy/asset 

 545 Although our focus and discussion in this rule is affiliate abuse with respect to 

affiliates that sell at market-based rates, affiliate concerns also arise with respect to 

affiliate sales at cost-based rates. See, e.g., Duke Energy Corp. and Cinergy Corp., 

113 FERC ¶ 61,297 at P 113-116 (2005), reh’g denied, 118 FERC ¶ 61,077 (2007). 

546 Order Regarding Future Monitoring of Voluntary Price Formation, Use of Price 

Indices In Jurisdictional Tariffs, and Closing Certain Tariff Dockets, 109 FERC ¶ 61,184 

(2004) (November 19 Price Index Order). 
Docket No. RM04-7-000 302 

management of generation on behalf of a franchised public utility or non-regulated 

utility be bound to comply with the same affiliate restrictions as those imposed on the 

franchised public utility and the non-regulated power sales affiliate. 

534. The Commission said it continues to believe that tying the price of an affiliate 

transaction to an established, relevant market price or index such as in an RTO or ISO 

is acceptable benchmark evidence and mitigates affiliate abuse concerns so long as 

that benchmark price or index reflects the market price where the affiliate transaction 

occurs. The Commission proposed to allow affiliate transactions based on a nonRTO price index only if the index fulfills the requirements of the November 19 Price 

Index Order547 for eligibility for use in jurisdictional tariffs. The Commission sought 

comment on whether evidence other than competitive solicitations, RTO price or 

non-RTO price indices, or benchmarks described in the NOPR should be accepted in 

an application for authority to engage in market-based affiliate power sales. In 

addition, the Commission proposed to consider two merging partners as affiliates as 

of the date a merger is announced, and sought comments on this proposal (or whether 

to use the date the § 203 application is filed with the Commission, or another time). 

The Commission also proposed that unaffiliated entities that engage in energy/asset 

management of generation on behalf of a franchised public utility or non-regulated 

 547 Id. 
Docket No. RM04-7-000 303 

utility be bound to comply with the same affiliate restrictions as those imposed on the 

franchised public utility and the non-regulated power sales affiliate. 

Comments

535. Industrial Customers urge the Commission to recognize that when an affiliate 

transaction has been subject to a state-approved process, separate section 205 

approvals for such transactions should not be required. If, however, the Commission 

does maintain the section 205 approval, “the imprimatur of state commission 

approval should create a rebuttable presumption that the transaction is just and 

reasonable.”548 NASUCA comments that the Commission should not assume the 

reasonableness of all affiliate sales under contracts with prices linked to spot markets 

or other auction results.549 

536. Other commenters urge the Commission to clarify that, while requests for 

proposals consistent with the Allegheny and Edgar standards and affiliate sales based 

on market index prices constitute a safe harbor for affiliate abuse, those should not be 

the only safe harbors.550 The Commission should state it is willing to consider other 

information and evidence, including affiliate sales reviewed and authorized by a state 

regulatory agency, as safe harbors as well.551

 548 Industrial Customers at 16-18. 

549 NASUCA at 20-29. 

550 Indianapolis P&L at 7-10. 

551 FirstEnergy at 12-27. 
Docket No. RM04-7-000 304 

537. New Jersey Board disagrees with comments that the Commission should 

consider state approval of affiliate sales as a safe harbor and responds that the 

Commission should assure that affiliate abuse does not take place and not ignore 

affiliate sales based on actions and oversight by state commissions.552

538. State AGs and Advocates oppose the Commission’s proposal to find affiliate 

sales of wholesale power just and reasonable if such sales are made through an 

auction that reflects certain guidelines such as those set forth in Edgar and Allegheny. 

Instead, State AGs and Consumer Advocates state that the Commission should 

develop behavioral market power tests that apply to all market structures and that 

each auction should be assessed separately and evaluated on the merits of the 

proposal.553

539. Industrial Customers oppose the Commission’s proposal to rely on an 

RTO/ISO benchmark price or index to mitigate affiliate abuse concerns and argues 

that tying an affiliate transaction to a price index should not allow utilities to escape 

scrutiny.554

Commission Determination

540. The Commission adopts the proposal to continue its approach for determining 

what types of affiliate transactions are permissible and the criteria used to make those 

 552 New Jersey Board reply comments at 6. 

553 State AGs and Advocates reply comments at 12-13. 

554 Industrial Customers at 16-18. 
Docket No. RM04-7-000 305 

decisions. Although we are not codifying a safe harbor in our regulations, when 

affiliates participate in a competitive solicitation process for power sales, we will 

consider proper application of the Allegheny guidelines to constitute a safe harbor 

that the affiliate abuse concerns are satisfied in a transaction between a franchised 

public utility with captive customers and its non-regulated power sales affiliate. The 

Commission will consider proposed competitive solicitations on a case-by-case basis. 

We again emphasize that using a competitive solicitation by applying the Allegheny

and Edgar guidelines is not the only way an affiliate transaction can address our 

concerns that the transaction does not pose undue preference concerns. We will 

consider other approaches on a case-by-case basis. Also, to the extent a seller is not 

bound by the affiliate restrictions because neither the seller nor the buyer has captive 

customers, we find that the Edgar principles do not apply and the seller does not need 

to make a filing with regard to a proposed competitive solicitation.555 

541. A number of commenters urge the Commission to find that a state-approved 

solicitation process creates a rebuttable presumption that an affiliate transaction 

satisfies the Commission’s affiliate abuse concerns. The Commission will consider a 

state-approved process as evidence in its consideration as to whether our affiliate 

abuse concerns have been adequately addressed, but the Commission will not treat a 

 555 Southern California Edison Co., 109 FERC ¶ 61,086 at P 35 (2004) (noting that 

Commission’s concern in cases involving sales to affiliates has been the potential for 

cross-subsidization at the expense of the public utility’s captive customers). 
Docket No. RM04-7-000 306 

state-approved process as creating a rebuttable presumption that our affiliate abuse 

concerns have been addressed. In this regard, the Commission has a responsibility 

under section 205 of the FPA to ensure that all jurisdictional rates charged are just 

and reasonable and not unduly discriminatory or preferential. While a state-approved 

solicitation process may provide evidence that the wholesale rates proposed as a 

result of that process are just and reasonable and do not involve any undue 

discrimination or preference, we do not believe it is appropriate to create a rebuttable 

presumption. 

542. Further, the Commission will continue to allow an established, relevant market 

price or index such as in an RTO or ISO to be used as a benchmark for the 

reasonableness of the price of an affiliate transaction. In this regard, we disagree with 

commenters that relying on such prices or indices allows utilities to escape 

Commission scrutiny. Such an index is acceptable benchmark evidence and mitigates 

affiliate abuse concerns so long as that benchmark price or index reflects the market 

price where the affiliate transaction occurs (i.e., is a relevant index).556 The 

Commission previously stated that the added protections in structured markets with 

 556 Brownsville, 111 FERC ¶ 61,398 at P 10 (2005). See also Portland General 

Elec. Co., 96 FERC ¶ 61,093 at 61,378 (2001); FirstEnergy Trading, 88 FERC ¶ 61,067 

at 61,156 (1999). 
Docket No. RM04-7-000 307 

central commitment and dispatch and market monitoring and mitigation (such as 

RTOs/ISOs) generally result in a market where prices are transparent.557

543. In addition, while the Commission has found in the past that certain non-RTO 

price indices are acceptable indicators of market prices, we continue to recognize that 

price indices at thinly traded points can be subject to manipulation and are otherwise 

not good measures of market prices as discussed in the Price Index Policy 

Statement558 and November 19 Price Index Order. Therefore, the Commission will 

allow affiliate transactions based on a non-RTO price index only if the index fulfills 

the requirements of the November 19 Price Index Order for eligibility for use in 

jurisdictional tariffs and reflects the market price where the affiliate transaction 

occurs (i.e., is a relevant index).559

3. Market-Based Rate Affiliate Restrictions (formerly Code of Conduct) 

for Affiliate Transactions Involving Power Sales and Brokering, NonPower Goods and Services and Information Sharing

Commission Proposal

544. The Commission stated in the NOPR that it continues to believe that a code of 

conduct is necessary to protect captive customers from the potential for affiliate 

 557 April 14 Order, 107 FERC ¶ 61,018 at P 189. 

558 Policy Statement on Natural Gas and Electric Price Indices, 104 FERC 

¶ 61,121 (2003) (Price Index Policy Statement). 

559 November 19 Price Index Order, 109 FERC ¶ 61,184 at P 40-69. 
Docket No. RM04-7-000 308 

abuse. In light of the repeal of the Public Utility Holding Company Act of 1935560

and the fact that holding company systems may have franchised public utility 

members with captive customers as well as numerous non-regulated power sales 

affiliates that engage in non-power goods and services transactions with each other, 

the Commission stated that it is important to have in place restrictions that preclude 

transferring captive customer benefits to stockholders through a company’s nonregulated power sales business. Therefore, the Commission stated its belief that it is 

appropriate to condition all market-based rate authorizations, including authorizations 

for sellers within holding companies, on the seller abiding by a code of conduct for 

sales of non-power goods and services and services between power sales affiliates. In 

addition, the Commission stated that greater uniformity and consistency in the codes 

of conduct is appropriate and, therefore, proposed to adopt a uniform code of conduct 

to govern the relationship between franchised public utilities with captive customers 

and their “non-regulated” affiliates, i.e., affiliates whose power sales are not regulated 

on a cost basis under the FPA. The Commission proposed to codify such affiliate 

restrictions in the regulations and to require that, as a condition of receiving marketbased rate authority, franchised public utility sellers with captive customers comply 

 560 Repeal of the Public Utility Holding Company Act of 1935 and Enactment of 

the Public Utility Holding Company Act of 2005, Order No. 667, 70 FR 75592 (Dec. 20, 

2005), FERC Stats. & Regs. Regulations Preambles 2001-2005 ¶ 31,197 (2005). 
Docket No. RM04-7-000 309 

with these restrictions. The Commission proposed that the failure to satisfy the 

conditions set forth in the affiliate restrictions will constitute a tariff violation. 

545. The Commission sought comments on this proposal and on whether the 

specific affiliate restrictions proposed in the NOPR are sufficient to protect captive 

customers. In particular, the Commission sought comments on what changes, if any, 

should be adopted. 

a. Uniform Code of Conduct/Affiliate Restrictions - Generally

Comments

546. Some commenters support codifying the code of conduct affiliate restrictions 

in the regulations and comment that it will lead to consistent codes of conduct across 

all sellers, thus creating greater transparency, and will aid the Commission’s 

enforcement efforts.561 ELCON argues that the ability of large utility holding 

companies with one foot in “competition” and one foot in “regulation” creates a 

myriad of potential problems.562 Several state agencies and consumer commenters 

generally support the proposal to codify uniform code of conduct restrictions in the 

Commission’s regulations.563 NASUCA comments that the separation of function 

 561 ELCON and EPSA support codifying a uniform code of conduct. ELCON at 2 

and EPSA at 28. 

562 ELCON at 3. 

563 Id. at 6-10, New Jersey Board at 2, and NRECA at 11. 
Docket No. RM04-7-000 310 

requirements should apply to any affiliate with retail customers, not just to affiliates 

who are franchised public utilities.564 

547. FP&L, however, does not believe it is unduly preferential to have different 

codes of conduct.565 Indianapolis P&L argues that a single tariff/code of conduct 

does not make sense for diversified energy companies with geographically 

widespread operations.566 

548. FP&L states that the Commission should include in the regulatory text the 

statement that the affiliate restrictions are waived where a seller demonstrates that 

there are no captive customers.567 EEI states that utilities already found not to have 

captive customers because of retail choice should be grandfathered and should not 

have to request waiver of the code of conduct again.568 

Commission Determination 

549. The Commission will adopt the proposed affiliate restrictions with certain 

modifications and clarifications. These restrictions govern the separation of 

functions, the sharing of market information, sales of non-power goods or services, 

and power brokering. The Commission will require that, as a condition of receiving 

 564 NASUCA at 20-29. 

565 FP&L at 3. 

566 Indianapolis P&L at 12. 

567 FP&L at 5-6. 

568 EEI at 43; EEI reply comments at 35. 
Docket No. RM04-7-000 311 

and retaining market-based rate authority, sellers comply with these affiliate 

restrictions unless otherwise permitted by Commission rule or order. As discussed 

herein, these affiliate restrictions govern the relationship between franchised public 

utilities with captive customers and their “market-regulated” affiliates, i.e., affiliates 

whose power sales are regulated in whole or in part on a market-based rate basis. 

550. Failure to satisfy the conditions set forth in the affiliate restrictions will 

constitute a violation of the market-based rate tariff. As discussed in greater detail 

below, the Commission agrees with many of the commenters that the requirements 

and exceptions in the affiliate restrictions should follow those requirements and 

exceptions codified in the standards of conduct, where applicable.569 The 

 569 On November 17, 2006, the D.C. Circuit vacated the Order No. 2004 standards 

of conduct orders as they related to natural gas pipelines and remanded the orders to the 

Commission. National Fuel Gas Supply Corporation v. FERC, 468 F.3d 831 (D.C. Cir. 

2006). The court found that the rulemaking record did not support the Commission’s 

attempt to extend the standards of conduct beyond pipelines’ relationships with their 

marketing affiliates to also govern pipelines’ relationships with numerous non-marketing 

affiliates, such as producers, gatherers, and local distribution companies (which Order 

No. 2004 defined as “energy affiliates”). In response to this decision, the Commission 

issued an interim rule on January 9, 2007 reinstating those provisions of Order No. 2004 

that were not specifically appealed to the D.C. Circuit. Standards of Conduct for 

Transmission Providers, Order No. 690, 72 FR 2427 (Jan. 19, 2007); FERC Stats. & 

Regs. ¶ 31,237 (Jan. 9, 2007); order on reh’g, Standards of Conduct for Transmission 

Providers, Order No. 690-A, 72 FR 14235 (Mar. 27, 2007); FERC Stats. & Regs. 

¶ 31,243 (2007). On January 18, 2007, the Commission issued a Notice of Proposed 

Rulemaking proposing to make the changes in the Interim Rule permanent and seeking 

comment on whether the restrictions covering relationships between electric transmission 

providers and non-marketing affiliates that are engaged in energy transactions should be 

retained. Standards of Conduct for Transmission Providers, Notice of Proposed 

Rulemaking, 72 FR 3958 (Jan. 29, 2007), FERC Stats. & Regs. ¶ 32,611 (2007).
Docket No. RM04-7-000 312 

Commission believes that modeling these restrictions and the exceptions to those 

restrictions on the standards of conduct will lead to greater consistency and 

transparency and a greater understanding of permissible activities. 

551. The Commission clarifies that any sellers that have previously demonstrated 

and been found not to have captive customers, and therefore have received a waiver 

of the market-based rate code of conduct requirement in whole or in part, will not be 

required to request another waiver of the associated affiliate restrictions. However, 

those sellers are still under the obligation to report to the Commission any changes in 

status that may affect the basis on which the Commission relied in granting their 

waiver, consistent with the requirements of Order No. 652.570 Additionally, those 

sellers also will be required to meet the requirements necessary to maintain their 

market-based rate authority when they file their regularly scheduled updated market 

power analyses. As a result, they will be required to demonstrate that they continue 

to lack captive customers in order to support a continued waiver of the affiliate 

restrictions in the regulations. Sellers will also need to explain why any wholesale 

customers are not captive, as explained above. 

552. In response to FP&L and EEI, because we clarify in this Final Rule that, where 

a seller demonstrates and the Commission agrees that it has no captive customers, the 

 570 Reporting Requirement For Changes in Status For Public Utilities with MarketBased Rate Authority, Order No. 652, 70 FR 8253 (Feb. 18, 2005), FERC Stats. & Regs., 

Regulations Preambles January 2001-December 2005 ¶ 31,175, order on reh’g, Order No. 

652-A, 111 FERC ¶ 61,413 (2005). 
Docket No. RM04-7-000 313 

affiliate restrictions will not apply, the Commission does not believe it is necessary to 

include in the regulatory text a provision stating that the affiliate restrictions are 

waived where a seller demonstrates and the Commission agrees that it has no captive 

customers. 

b. Exceptions to the Independent Functioning Requirement

Commission Proposal Regarding Separation of Employees and 

Shared Employees

553. In the NOPR, the Commission proposed regulatory language in § 35.39(b)(2) 

(now § 35.39(c)(2)) codifying the independent functioning requirement. Specifically, 

the Commission stated, to the maximum extent practical, the employees of a nonregulated power sales affiliate will operate separately from the employees of any 

affiliated franchised public utility. 

554. The Commission did not propose to include any exceptions to the independent 

functioning requirements. However, the Commission invited commenters to propose 

additions to, substitutions for or elimination of the proposed affiliate restrictions.571 

Comments

555. A number of commenters request that the Commission modify the affiliate 

restrictions to adopt some of the requirements and exceptions consistent with those 

codified in Order No. 2004, such as allowing the sharing of senior officers and 

members of the board of directors, field and maintenance employees and support 

 571 NOPR at P 132. 
Docket No. RM04-7-000 314 

employees. According to EPSA, the affiliate restrictions should provide specifically 

for permissible sharing of officers (not just sharing of support personnel) between a 

franchised public utility and a non-regulated power sales affiliate. EPSA notes that 

Order No. 2004 allows for shared officers as long as they do not direct, organize or 

execute day-to-day business transactions.572

556. Duke comments that treatment of shared employees under the affiliate 

restrictions should follow the obligations adopted in the standards of conduct. For 

example, Duke urges the Commission to allow the sharing of officers and 

directors.573 Additionally, Avista states that the proposed affiliate restrictions should 

distinguish between operational and non-operational employees.574 

557. PG&E urges the Commission to clarify which employees cannot be shared. 

PG&E states that prohibiting employees involved in general operation of generation 

facilities, who lack control over generation availability, from being shared would be 

overly broad and unduly restrictive.575 PPL similarly requests clarification of which 

employees would be deemed “shared employees” under the affiliate restrictions.576 

 572 EPSA at 31. 

573 Duke at 43. See also EPSA at 31; FirstEnergy at 26.

574 Avista at 7-10. 

575 PG&E at 14-21. 

576 PPL reply comments at 21-22. 
Docket No. RM04-7-000 315 

558. NiSource requests that the Commission create an exception to allow the 

sharing between operational employees of the franchised public utility and its nonregulated sales affiliates of any information necessary to maintain the safe and 

reliable operation of the bulk power system, similar to the exception in the standards 

of conduct at § 358.5(b)(8) of the Commission’s regulations.577

559. EEI and FirstEnergy also request that the independent functioning requirement 

and information sharing restrictions in the proposed affiliate restrictions should have 

an exception for sharing employees and market information for emergency 

circumstances affecting system reliability.578 

560. On the other hand, Morgan Stanley urges the Commission not to adopt a 

blanket exception to the affiliate restrictions for emergency situations because the 

commenters’ proposal regarding what constitutes an “emergency” is vague and leaves 

too much discretion to the individual sellers. Additionally, Morgan Stanley explains 

that communications with an affiliate during an emergency may not adequately 

address an emergency; sharing information with all sellers in the market would 

provide a better foundation to deal with any emergency.579

 577 NiSource at 1. 

578 EEI at 44; FirstEnergy at 22. 

579 Morgan Stanley reply comments at 7-8. 
Docket No. RM04-7-000 316 

Commission Determination

561. The Commission will revise the independent functioning requirement of the 

affiliate restrictions to include exceptions relating to permissibly shared senior 

officers and members of boards of directors, shared support personnel, and shared 

field and maintenance personnel. With regard to permissibly shared individuals, the 

Commission will impose a “no-conduit rule” similar to that in the standards of 

conduct.580 Under the no conduit rule, to be codified at § 35.39(g), a permissibly 

shared employee is prohibited from acting as a conduit for disclosing market 

information to employees, officers or directors that are not shared. 

562. The Commission agrees that a franchised public utility with captive customers 

and its market-regulated power sales affiliates should be permitted to share senior 

officers and members of the board of directors to conduct corporate governance 

functions, and to take advantage of the efficiencies of corporate integration.581 

Therefore, the Commission is adopting an exception at § 35.39(c)(2)(d) that permits a 

franchised public utility with captive customers and its market-regulated power sales 

affiliate to share senior officers and members of the board of directors. Specifically, 

a franchised public utility with captive customers and its market-regulated power 

sales affiliate may share senior officers and members of boards of directors provided 

 580 18 CFR 358.4(a)(5) (shared senior officers and directors); 18 CFR 358.5(b)(7) 

(general “no conduit” rule covering employees). 

581 Order No. 2004-A at P 134. 
Docket No. RM04-7-000 317 

that these individuals do not participate in directing, operating or executing 

generation or market functions.582 In addition, to prevent permissibly shared senior 

officers or members of the board of directors from using their preferential access to 

market information to harm captive customers, consistent with the no-conduit rule 

codified at § 35.39(g), the permissibly shared senior officers and directors may not 

act as a conduit to provide market information to non-shared employees of the 

franchised public utility with captive customers or its market-regulated power sales 

affiliates. 

563. The Commission also agrees that it is appropriate to codify an exception that 

permits the sharing of support employees between the franchised public utility with 

captive customers and its market-regulated power sales affiliates comparable to the 

standards of conduct exception, likewise subject to the no-conduit rule.583 

564. The Commission rejects Duke’s request that the Commission include a nonexhaustive list of examples of permissible shared support employees within the body 

of § 35.39. However, we clarify that the types of permissibly shared support 

employees under the standards of conduct are the types of permissibly shared support 

employees that will be allowed under the affiliate restrictions in § 35.39(c)(2)(c). 

Such employees include those in legal, accounting, human resources, travel and 

 582 See 18 CFR 358.4(a)(5). 

583 Order No. 2004 at P 99-101. 
Docket No. RM04-7-000 318 

information technology.584 Because permissibly shared employees may have access 

to market information, they are prohibited from acting as a conduit to provide market 

information to employees of the franchised public utility with captive customers and 

the market-regulated power sales affiliates that are not permitted to be shared. 

565. The Commission also agrees to codify an exception to the independent 

functioning requirement to allow franchised public utilities with captive customers 

and their market-regulated power sales affiliates to share field and maintenance 

employees. Field and maintenance employees perform purely manual, technical or 

mechanical duties that are supportive in nature and do not have planning or direct 

operational responsibilities. Such employees would likely be part of shared work 

crews to do repair or maintenance work on facilities or equipment. Examples of 

activities that may be performed by shared field and maintenance employees are 

reading meters, replacing parts in generators, restringing transmission lines, snow 

removal or maintaining roadways. The key is that these employees do not also 

perform operational duties.585 A field or maintenance employee cannot be shared if 

that employee also engages in marketing activities, makes decisions that would affect 

marketing activities, or controls generation. We also consider the immediate 

supervisors of field and maintenance employees as permissibly shared employees so 

 584 Id. at P 96. 

585 Id. at P 145-146. 
Docket No. RM04-7-000 319 

long as they cannot control operations, e.g. restrict or shut down generation 

facilities.586

566. The Commission agrees with commenters that allowing the sharing of field 

and maintenance employees between a franchised public utility with captive 

customers and its market-regulated power sales affiliates is unlikely to harm captive 

customers, provided that those shared employees do not act as a conduit for sharing 

market information with employees of the franchised public utility with captive 

customers or market-regulated power sales affiliates. The permissibly shared field 

and maintenance employees are required to observe the no-conduit rule. 

567. The Commission disagrees with NiSource that a broad exception to the 

independent functioning and information sharing requirement is needed for the 

reliable operation of the bulk power system. Such an exception would be so broad 

that it would swallow the rule and create too many opportunities for shared 

employees to take actions to harm captive customers based upon their decision 

making authority and control over the bulk power system. The Commission will 

consider requests for waiver of the affiliate restriction requirements to address the 

specific circumstances of the operation of a bulk power system and notes that, 

 586 See id. at P 145-46. As discussed later, such actions would be permitted in 

emergency circumstance affecting system reliability. 
Docket No. RM04-7-000 320 

subsequent to NiSource’s comments, the Commission granted a partial waiver of the 

code of conduct requirements for the situation described in NiSource’s comments.587 

568. While the Commission does not agree with NiSource’s proposal for a broad 

exception to the affiliate restrictions for everyday operations of the bulk power 

system, the Commission does agree with EEI and FirstEnergy that the affiliate 

restrictions should contain an exception related to emergency circumstances affecting 

system reliability. As such, the Commission will adopt an exception to the 

independent functioning requirement and the information sharing restrictions for 

emergency circumstances affecting system reliability comparable to the exception in 

the standards of conduct.588 The exception will apply to both the independent 

functioning requirements and the information sharing restrictions. The Commission 

will modify proposed § 35.39(d) (to be codified at § 35.39(c)(2)(b)) to add a 

 587 Northern Indiana Public Service Company and Whiting Clean Energy, Inc., 

116 FERC ¶ 61,248 (2006). Northern Indiana Public Service Company (NIPSCO) 

sought a waiver of the code of conduct so that it could perform its duties as a balancing 

authority. Specifically, NIPSCO wanted the ability to have access to real-time 

information regarding the amount of energy being delivered to NIPSCO from its affiliate, 

Whiting Clean Energy, Inc. (Whiting) The Commission granted a partial waiver limited 

to Whiting providing NIPSCO with the real-time information NIPSCO needed to carry 

out its responsibilities as a balancing authority in accordance with the requirements of the 

North American Electric Reliability Council (NERC), NERC approved regional 

reliability organization and the Midwest Independent Transmission System Operator, 

Inc. Id. at P 13. The Commission also reminded NIPSCO that its employees were 

prohibited from being a conduit for improperly sharing Whiting’s generation information. 

Id. 

588 18 CFR 358.4(a)(2). 
Docket No. RM04-7-000 321 

provision that states that, notwithstanding any other restrictions in this section, in 

emergency circumstances affecting system reliability, a market-regulated power sales 

affiliate and the franchised public utility with captive customers may take the 

necessary steps to keep the bulk power system in operation. The relaxation of the 

requirements during system emergencies is intended to ensure that the franchised 

public utility with captive customers and market-regulated power sales affiliate(s) can 

maintain reliability of the power grid. However, the market-regulated power sales 

affiliate or the franchised public utility must report to the Commission and disclose to 

the public on its website each emergency that resulted in any deviation from the 

restrictions of § 35.39(c)(2)(b), within 24 hours of such deviation. Reports to the 

Commission of emergency deviations under the affiliate restrictions in § 

35.39(c)(2)(b) will be made using the “EY” docket prefix. 

569. The Commission and the public will be able to monitor the frequency of these 

emergency deviations through the reporting requirement. Members of the public can 

seek redress from the Commission if they feel that the exception has been abused or 

used improperly. 

c. Information Sharing Restrictions

Commission Proposal

570. In the NOPR, the Commission proposed regulatory language to codify the 

information sharing restrictions. Specifically, the Commission proposed that the 

regulations provide that all market information sharing between a franchised public 

utility and a non-regulated power sales affiliate will be disclosed simultaneously to 
Docket No. RM04-7-000 322 

the public. This includes, but is not limited to any communication concerning power 

or transmission business, present or future, positive or negative, concrete or 

potential.589 

Comments

571. Ameren supports codification of the information sharing restrictions, but 

recommends that proposed § 35.39(c) be revised to allow permissibly shared senior 

officers and directors to receive market information so long as they do not act as a 

conduit to improperly share such information, akin to the standards of conduct. 

572. Avista argues that the Commission should allow officers to be shared by 

affiliates, subject to the no-conduit rule.590 EEI argues that for corporate governance 

and accountability purposes, there should be an exception to the information sharing 

prohibitions for shared senior officers, subject to the no conduit rule.591 

573. EPSA also asks the Commission to provide a specific time period for the 

length of time that posted information needs to remain on the website.592 

574. PPL comments that the Commission should clarify which situations would 

permit deviations from the code of conduct regarding information sharing. 

 589 See NOPR at P 121, 129. 

590 Avista at 2. 

591 EEI at 44. 

592 EPSA at 31-32 
Docket No. RM04-7-000 323 

Specifically, it suggests that the Commission adopt, for the affiliate restrictions, the 

standards of conduct exception that permits the sharing of information to comply with 

Nuclear Regulatory Commission (NRC) requirements.593

575. A number of commenters argue that the Commission should not adopt the 

two-way information sharing prohibition in the uniform code of conduct because they 

disagree that a communication from the non-regulated power sales affiliate to the 

franchised public utility could potentially harm captive customers.594 

576. Duke notes that while the two-way restriction is consistent with the default 

code of conduct that the Commission has used since 1999, the Commission has 

approved many codes of conduct that contain one-way restrictions (i.e., codes that 

restrict a franchised public utility from sharing marketing information with its nonregulated power sales affiliates, but do not place a similar restriction on a nonregulated power marketer from sharing market information with its affiliated 

franchised utility.) Duke says the Commission has failed to explain the elimination 

of previously-approved one-way restrictions.595 It submits that the one-way code of 

conduct is sufficient to address affiliate abuse concerns and that the two-way code of 

 593 PPL reply comments at 21-22 citing Interpretive Order Relating to the 

Standards of Conduct, 114 FERC ¶ 61,155 (2006), order on request for additional 

clarification, 115 FERC ¶ 61,202 (2006). 

594 Allegheny Energy Companies’ Comments at 3; Duke at 37-40; PG&E at 20, 

FirstEnergy at 23 and FP&L at 4. 

595 Duke at 38. 
Docket No. RM04-7-000 324 

conduct requirement will impose substantial costs on market-based rate sellers with 

no discernible benefits.596 According to Duke, a number of market participants have 

made important organizational and commercial decisions based on current policies 

and precedents allowing one-way communications. In the absence of any basis for 

reversing that policy, Duke submits that the Commission should reconsider its 

proposal to mandate two-way information sharing restrictions. 

577. In addition, Duke argues that only two commenters, EPSA and ELCON, 

expressed even generalized support for a standardized code of conduct containing the 

two-way code restriction, but did not address the underlying policy issues of why or 

how a traditional utility’s regulated customers could be harmed if their unregulated 

affiliate were to share market information with the utility.597

578. According to FP&L, the proposed two-way information sharing restriction 

does not provide any additional protection for captive customers. Rather, such a 

restriction may place artificial and unnecessary barriers on a company’s ability to 

conduct business.598 According to FP&L, the two-way restriction proposed in § 

35.39(c) (to be codified at § 35.39(d)) concerning the communication of all market 

information between a franchised public utility and its non-regulated power sales 

 596 Duke reply comments at 20-21. 

597 Id. at 20. 

598 FP&L at 4. 
Docket No. RM04-7-000 325 

affiliates is unnecessary if sales of capacity and energy between those entities are 

prohibited under the specific terms of the market-based rate tariff. It submits that, if 

the Commission nevertheless concludes that a two-way restriction on 

communications should be adopted, then the final regulations should provide an 

exception if, in the market-based rate tariff, the non-regulated power sales affiliates 

have restricted sales to, and purchases from, their franchised public utility affiliate 

without having received advance Commission approval pursuant to a separate filing 

under section 205 of the FPA.599 

579. Similarly, EEI argues that the Commission has not explained how the two-way 

information sharing prohibition protects captive customers.600

Commission Determination

580. The Commission will revise the information sharing prohibitions to adopt 

certain exceptions. As discussed earlier with regard to the independent functioning 

requirement, we are creating exceptions to permit shared senior officers and members 

of a board of directors, as well as to permit shared field and maintenance employees. 

Permissibly shared employees may share all types of market information. However, 

the information sharing provision, like all the affiliate restrictions, is subject to the 

“no-conduit” rule that we codify in the regulations. The no-conduit rule allows 

 599 Id. at 4-5. 

600 EEI at 45. 
Docket No. RM04-7-000 326 

permissibly shared employees to receive market information so long as they are not 

conduits for sharing that information with employees that are not permissibly shared. 

In addition, as also discussed earlier in the independent functioning section, market 

information may be shared to address emergency circumstances affecting system 

reliability in order to keep the bulk power system in operation, provided that the 

subsequent reporting provisions are followed. 

581. In response to PPL Companies’ concern as to communications relating to 

nuclear power plants, the Commission clarifies that the types of communications 

permitted under the standards of conduct for nuclear safety and regulatory 

requirements are also permitted under the affiliate restrictions.601 Specifically, the 

Commission permitted transmission providers to communicate with affiliated and 

nonaffiliated nuclear power plants to enable the nuclear power plants to comply with 

the requirements of the NRC as described in the NRC’s February 1, 2006 Generic 

Letter 2006-002, Grid Reliability and the Impact on Plant Risk and the Operability of 

Offsite Power.602 

 601 Interpretive Order Relating to the Standards of Conduct, 114 FERC ¶ 61,155 

(2006), order on request for additional clarification, 115 FERC ¶ 61,202 (2006). 

602 Nuclear Regulatory Commission’s Generic Letter 2006-002, Grid Reliability 

and the Impact on Plant Risk and the Operability of Offsite Power. February 1, 2006. 

OMB Control No.: 3150-0011. Transmission providers may share with affiliates 

information to operate and maintain the transmission system and information required to 

maintain interconnected facilities. However, transmission providers may not share 

transmission or marketing information that would give a transmission provider’s 

marketing or energy affiliates undue preference over a transmission provider’s non-

 (continued...) 

 
Docket No. RM04-7-000 327 

582. In response to EPSA’s request regarding the specific time period that posted 

material needs to remain on the website, the Commission concludes that it is 

appropriate to use the requirements set forth regarding OASIS postings in 18 CFR 

37.7(b). Specifically, the material must be posted for 90 days and then be retained 

and made available upon request for download for five years from the date when first 

posted. The archived material must be available in the same electronic form used as 

when it was originally posted. 

583. The Commission will adopt the two-way information sharing restriction in 

proposed § 35.39(c) (now § 35.39(d)). The purpose of the affiliate restrictions in § 

35.39 is to ensure that franchised public utility sellers with captive customers will not 

be able to engage in affiliate abuse to the detriment of those captive customers. One 

way the Commission achieves this is by restricting the sharing of information 

between a franchised public utility with captive customers and a market-regulated 

power sales affiliate. The Commission has long required a seller to address any 

potential affiliate abuse concerns before receiving Commission authorization to sell at 

market-based rates. The Commission has previously held that “[t]here are many 

ways for the affiliated public utility and the affiliated power marketer to exchange 

information that would exacerbate affiliate abuse concerns.”603 Therefore, the 

 

affiliated customers in energy markets. 114 FERC ¶ 61,155 (2006). 

603 Heartland Energy Services, Inc., 68 FERC ¶ 61,223 (1994). 
Docket No. RM04-7-000 328 

Commission required that the sellers “ensure that market information is not shared 

among affiliates.”604

584. The Commission later reaffirmed this in stating the general standards under 

which it reviews applications for market-based rate authority, including a 

demonstration by an affiliate that “there are adequate procedures in place to ensure 

that market information is not shared between it and the affiliate public utility.”605 

585. With regard to Duke's suggestion that we have failed to explain the elimination 

of the one-way restriction, we will provide the following example of our concern in 

this regard. 

586. One example of how of improper sharing of information could harm captive 

customers is a circumstance where both a franchised public utility and its marketregulated power sales affiliate are considering whether to bid into an RFP to provide 

power. If the market-regulated power sales affiliate has absolute freedom to inform 

its franchised public utility affiliate that it intends to bid into the RFP, including but 

not limited to the price and quantity it intends to offer, the franchised public utility 

affiliate has the ability and incentive to use that information to benefit its 

stockholders at the expense of its captive customers (e.g., by either not bidding into 

the RFP or doing so at a price above that of its affiliate). 

 604 Id. 

605 LG&E Power Marketing, Inc., 68 FERC ¶ 61,247 (1994). 
Docket No. RM04-7-000 329 

587. While we recognize that some sellers may need to adjust their activities to 

comply with the two-way information restriction, we do not believe that such 

adjustments will impose significant costs upon those sellers. Furthermore, as 

explained above, we believe that the two-way information sharing restriction will 

provide captive customers a more complete protection from affiliate abuse. We find 

that any potential cost to sellers is outweighed by the increased protection a two-way 

information sharing restriction provides to captive customers. 

588. Therefore, to ensure that all captive customers are protected from the potential 

for affiliate abuse, the Commission will adopt the proposed two-way information 

restriction in § 35.39(d). Any sellers whose activities are currently governed by a 

code of conduct with a one-way information restriction will be deemed to have 

adopted a two-way information restriction as of the effective date of this Final Rule. 

589. The Commission restates that the affiliate restrictions only apply when captive 

customers exist; therefore, if the Commission has found that there are no captive 

customers, then, consistent with § 35.39(b) through (g), the affiliate restrictions, 

including the prohibition on information sharing, will not apply.

d. Definition of “Market Information”

Comments

590. Progress Energy urges the Commission to clarify the definition of the term 

“market information” which it argues is arbitrarily broad and may include public as 
Docket No. RM04-7-000 330 

well as non-public market information.606 SoCal Edison states that the Commission 

should only prohibit the sharing of non-public market information among a utility and 

its market-regulated power sales affiliates, as outlined in the standards of conduct.607 

EPSA also asserts that the Commission should clarify that the simultaneous posting 

requirement should apply to the communication of all non-public market information 

(not all market information). It notes that Order No. 2004 specifically applies to nonpublic transmission information, not all transmission information. 

Commission Determination

591. The Commission previously explained that “market information” includes 

information on sales or purchases that will not be made (as well as purchases and 

sales that will be made), as well as any information concerning a utility’s power or 

transmission business – broker-related or not, past, present or future, positive or 

negative, concrete or potential, significant or slight.608 In an effort to provide 

additional clarity and regulatory certainty, we will provide further guidance and adopt 

and codify in § 35.36(a)(8) the following definition of market information: 

“market information means non-public information related to the electric energy and 

power business including, but not limited to, information regarding sales, cost of 

 606 Progress Energy at 36-37. 

607 SoCal Edison at 3-6. 

608 UtiliCorp United, Inc., 75 FERC ¶ 61,168 (1996). 
Docket No. RM04-7-000 331 

production, generator outages, generator heat rates, unconsummated transactions, or 

historical generator volumes. Market information includes information from either 

affiliates or non-affiliates.” 

592. The Commission clarifies that the definition does not prohibit the disclosure of 

publicly available information. We find that, because of its very nature of being 

publicly available to all entities, restrictions on sharing publicly available information 

are unnecessary. In addition, the definition does not prohibit the sharing of 

transmission information. The standards of conduct already prevent improper 

disclosures of non-public transmission information by a transmission provider to its 

marketing and energy affiliates, which would include both the franchised public 

utility with captive customers and the market-regulated power sales affiliate.609 

593. Further, as we have indicated, a principal purpose of the affiliate restrictions is 

to ensure that the interaction between a franchised public utility and its marketregulated affiliate does not result in harm to the franchised public utility’s captive 

customers. Therefore, we clarify that, as a general matter, the definition of “market 

information” includes information that, if shared between a franchised public utility 

and a market-regulated affiliate, may result in a detriment to the franchised public 

utility’s captive customers. Therefore, market information includes, but is not limited 

to, information concerning sales and purchases that will not be made such as in 

 609 18 CFR 358.5(a) and (b) (2006). 
Docket No. RM04-7-000 332 

circumstances where parties have discussed a potential contract but no agreement has 

been reached. In contrast, market information does not include information that 

would not result in an advantage to the recipient that could be used to the detriment of 

the franchised public utility’s captive customers. For example, a franchised public 

utility with captive customers and its market-regulated power sales affiliate may 

share information related to the relocation of the franchised public utility’s 

headquarters, business opportunities outside the United States, general turbine safety 

information and internal procedures for general maintenance activities (other than 

scheduling). We clarify that the definition of “market information” includes, but is 

not limited to, written, printed, verbal, audiovisual, or graphic information. 

594. We are adding language to the information sharing restriction of § 35.39(d)(1) 

to make clear that disclosures of market information are prohibited, unless 

simultaneously disclosed to the public, if the information could be used to the 

detriment of captive customers. For example, if a franchised public utility with 

captive customers conducts negotiations with an unaffiliated generator to acquire 

power, but does not reach an agreement, the franchised public utility with captive 

customers is prohibited from sharing with its market-regulated power sales affiliate 

any non-public information it acquired through the unsuccessful negotiations unless 

such information is simultaneously disclosed to the public. Information relating to 

any other entities’ electric energy or power business is also subject to the sharing of 

market information restriction if such information could be used to the detriment of 

captive customers. Also subject to the information sharing restriction is information 
Docket No. RM04-7-000 333 

regarding brokering activities, past sales and purchase activities, and the availability 

or price of inputs to generation such as natural gas supply if such information could 

be used to the detriment of captive customers. For example, a franchised public 

utility with captive customers is restricted from disclosing to its market-regulated 

power sales affiliate any non-public information about a non-affiliated generator’s 

upcoming maintenance or outage schedules or information about the non-affiliated 

generator’s historical generation volumes, unless such information is simultaneously 

disclosed to the public. In addition, neither the franchised public utility with captive 

customers nor its market-regulated power sales affiliate may tell the other that it 

intends to sell power to a third party, including but not limited to the price and 

quantity it intends to offer, unless such information is simultaneously disclosed to the 

public. Similarly, a market-regulated power sales affiliate is likewise restricted from 

telling its franchised public utility affiliate with captive customers about any other 

business opportunity that it is considering or is undertaking, unless such information 

is simultaneously disclosed to the public. 

e. Sales of Non-Power Goods or Services

Commission Proposal

595. In the NOPR, the Commission proposed regulatory language to codify the 

requirements governing sales of non-power goods or services. The Commission 

proposed that sales of any non-power goods or services by a franchised public utility 

to a market-regulated power sales affiliates will be at the higher of cost or market 

price, and that sales of any non-power goods or services by a market-regulated power 
Docket No. RM04-7-000 334 

sales affiliate to an affiliated franchised public utility will not be at a price above 

market. 

Comments

596. PG&E argues that, while charging the high of cost or market price may be 

appropriate for sales of goods, it is “inoperable and inappropriate” for sales of 

services because market prices for sales of service by a third party may be hard to 

ascertain due to limited providers and that prices from a third party provider will not 

take into account efficiencies resulting from a utility and its affiliate sharing 

services.610 PG&E further comments that charging the higher of cost or market, as 

proposed, may increase costs for both the utility and the affiliate by discouraging the 

efficient sharing of services. Therefore, PG&E proposes that instead of charging the 

higher of cost or market price for non-power services, the Commission should allow a 

proxy for the market price such as the fully-loaded cost plus a reasonable profit, e.g., 

five percent.611

Commission Determination

597. The Commission will adopt the NOPR proposal to codify the requirement that 

sales of non-power goods and services by a franchised public utility with captive 

customers to a market-regulated power sales affiliate be at the higher of cost or 

market price, unless otherwise authorized by the Commission. This requirement, 

 610 PG&E at 20-21. 

611 Id. at 21. 
Docket No. RM04-7-000 335 

along with other requirements in the affiliate restrictions, protect a franchised public 

utility’s captive customers against inappropriate cross-subsidization of marketregulated power sales affiliates by ensuring that the utility with captive customers 

does not recover too little for goods and services that the utility provides to a marketregulated power sales affiliate.612 We also adopt the NOPR proposal to codify the 

requirement that sales of any non-power goods or services by a market-regulated 

power sales affiliate to an affiliated franchised public utility with captive customers 

will not be at a price above market, unless otherwise authorized by the Commission. 

This requirement protects a utility’s captive customers against inappropriate crosssubsidization of market-regulated power sales affiliates by ensuring that the utility 

with captive customers does not pay too much for goods and services that the utility 

receives from a market-regulated power sales affiliate. 

598. We note that PG&E fails to provide the Commission with any specific 

examples of non-power services for which there is no corresponding third-party 

provider. Therefore, we are not persuaded by PG&E that there is a need or a benefit 

to changing our precedent on this issue. We will adopt the affiliate restrictions as 

proposed and require that sales of non-power goods or services by a franchised public 

utility with captive customers to a market-regulated power sales affiliate be at the 

higher of cost or market price. Nevertheless, we will address on a case-by-case basis 

 612 See generally National Grid plc and Keyspan Corp., 117 FERC ¶ 61,080 at P 

65-66 (2006), reh’g pending. 
Docket No. RM04-7-000 336 

arguments that charging the higher of cost or market for certain sales of non-power 

services may not be appropriate in a particular case. 

f. Service Companies or Parent Companies Acting on Behalf of and 

for the Benefit of a Franchised Public Utility

Commission Proposal

599. The Commission proposed in the NOPR to treat companies that are acting on 

behalf of and for the benefit of franchised public utilities with captive customers, for 

purposes of the affiliate provisions, as that franchised public utility. Likewise, in the 

case of non-regulated affiliates, the proposed affiliate provisions treat companies that 

are acting on behalf of and for the benefit of non-regulated affiliates, for purposes of 

the affiliate provisions, as the non-regulated affiliates.613

Comments

600. EEI asks the Commission to clarify that the code of conduct (affiliate 

restrictions) provisions to be codified in the regulations do not preclude the use of 

service companies that manage assets for both regulated and unregulated affiliates.614 

EEI submits that the language of proposed §§ 35.39(b) (now § 35.39(c)) uses 

“entities acting on behalf of and for the benefit of a franchised pubic utility (such as 

entities managing the electric generation assets of the franchised public utility)” 

whereas the NOPR text reads “entities acting on behalf of and for the benefit of a 

 613 NOPR at 83-84. 

614 EEI at 45-46.
Docket No. RM04-7-000 337 

franchised public utility (such as service companies and entities managing the 

generation assets of the franchised pubic utility).” EEI argues that the treatment of 

service companies as part of the franchised public utility in the preamble to the 

NOPR is different from the language in the proposed regulation and makes the 

Commission’s intent unclear. It submits that many companies use service companies 

to provide support activities to the franchised utility and non-regulated affiliates 

consistent with the no-conduit rule. EEI asks the Commission to clarify that the 

standardization of the code of conduct is not intended to change this practice. PG&E 

claims that under a plain reading of the proposed regulation, a parent company that 

acts on behalf of either the utility or the affiliate will be considered a part of the 

utility or affiliate, and communication with either entity will be restricted under 

proposed § 35.39(c) (now § 35.39(d)).615 It argues that the Commission 

should only consider a holding company or parent company as an affiliate subject to 

the information sharing prohibitions if it engages in energy transactions on its own 

behalf.616 

601. Southern states that it is unclear how the Commission intends to address and 

apply the requirements of separation of functions and information sharing in the 

 615 PG&E at 16-17. 

616 PG&E at 17. 
Docket No. RM04-7-000 338 

context of public utility holding companies that have system pooling agreements.617 

Southern recommends the Commission refine the definition of “non-regulated power 

sales affiliate” at least insofar as that term is used in the proposed separation of 

functions and information sharing provisions to exclude pooled system affiliates of 

traditional franchised utilities where affiliate interactions and sharing of benefits and 

burdens of pooled operations are addressed under an arrangement filed and approved 

under section 205.618 

602. EEI requests that the Commission clarify that, in circumstances where sales 

between affiliates have been made in connection with an approved system agreement, 

such agreements continue to govern.619 Southern requests that the Final Rule clarify 

that affiliated operating companies may continue to operate on a pooled basis.620 

Southern states that traditional centralized service company affiliates providing 

 617 Southern at 49. 

618 Southern at 50. 

619 EEI at 46-49. 

620 Southern at 44-52. Southern also asks that the Commission revise the affiliate 

abuse regulations to include a definition of “pooled system affiliates” and clarify that the 

definition of non-regulated power sales affiliate excludes “pooled system affiliates” of 

traditional franchised utilities. Southern states that any definition of “pooled system 

affiliates” should address both existing arrangements (that have been reviewed and 

approved by the Commission) and prospective arrangements. 
Docket No. RM04-7-000 339 

system pooling support services under filed and approved system agreements should 

not be treated as non-regulated power sales affiliates.621 

Commission Determination

603. The Commission clarifies that it did not intend to include service companies as 

“entities acting on behalf of and for the benefit of a franchised public utility” for 

purposes of the separation of functions provision in § 35.39(b) (now § 35.39(c)) to 

the extent that such service companies do not engage in generation or marketing 

activities.622 Although service companies not engaged in generation or marketing 

activities are not included in the coverage of § 35.39(e), they may not act as a conduit 

for providing non-public market information between a franchised public utility and a 

market-regulated power sales affiliate. However, unless otherwise permitted by 

Commission rule or order, service companies cannot be used to direct, organize or 

execute generation or marketing activities for both the franchised public utility and 

the market-regulated power sales affiliate(s). In response to Southern’s and EEI’s 

request to clarify that affiliated operating companies may continue to operate as a 

pool or pursuant to an approved system agreement, nothing in this Final Rule 

 

621 Southern at 48-52. 

622 As proposed in the NOPR, the separation of functions provision provided that 

“entities acting on behalf of and for the benefit of a franchised public utility (such as 

entities managing the generation assets of the franchised public utility) are considered 

part of the franchised public utility.” In this Final Rule, we modify the parenthetical in 

that provision to state: “(such as entities controlling or marketing power from the 

electrical generation assets of the franchised public utility).” See 18 CFR 35.39(c)(1). 
Docket No. RM04-7-000 340 

precludes pool operation pursuant to filed tariffs or agreements approved by the 

Commission and nothing in this rule changes filed system agreements approved by 

the Commission. To the extent that individual companies enter into new pooling or 

system agreements, the Commission will continue to review those agreements on a 

case-by-case basis to ensure that, among other things, affiliate transactions meet the 

requirements of section 205 of the FPA and otherwise satisfy our affiliate abuse 

concerns. 

D. Mitigation

604. In the NOPR, the Commission sought comment on whether the default 

mitigation adopted in the April 14 Order is appropriate as currently structured. The 

Commission’s current default mitigation rates are as follows: (1) sales of power of 

one week or less will be priced at the seller’s incremental cost plus a 10 percent 

adder; (2) sales of power of more than one week but less than one year (sometimes 

referred to as “mid-term sales”) will be priced at an embedded cost “up to” rate 

reflecting the costs of the unit or units expected to provide the service; and (3) new 

contracts for sales of power for one year or more will be priced at a rate not to exceed 

the embedded cost of service, and the contract will be filed with the Commission for 

review and approved prior to the commencement of service.623

 623 April 14 Order, 107 FERC ¶ 61, 018 at P 151; see also NOPR at P 22, 137. 
Docket No. RM04-7-000 341 

605. In the NOPR, the Commission sought comment on the following four issues 

that have arisen in implementing cost-based mitigation: (i) the rate methodology for 

designing cost-based mitigation; (ii) discounting; (iii) protecting customers in 

mitigated markets; and (iv) sales by mitigated sellers that “sink” in unmitigated 

markets. 

1. Cost-Based Rate Methodology

a. Sales of One Week or Less

Commission Proposal

606. The Commission noted that two principal issues concerning rate methodology 

have arisen in implementing the April 14 Order. The first relates to power sales of 

one week or less being made at incremental cost plus 10 percent.624 The Commission 

noted that sellers have argued that this is a departure from the Commission’s 

historical acceptance of “up to” rates for short-term energy sales, including sales of 

one week or less, and sought comment on whether to continue to apply a default rate 

for such sales that is tied to incremental cost plus 10 percent. The Commission 

sought comment as to: (i) whether there are problems associated with using “up to” 

rates for shorter-term sales and, if so, what are they; (ii) whether the current approach 

 624 In a number of instances, the NOPR referred to these sales as “sales of less than 

one week,” and a number of commenters likewise used “sales of less than one week” in 

their comments. We clarify that the reference in the NOPR should have been to “sales of 

one week or less,” consistent with the April 14 and July 8 Orders. Accordingly, for 

purposes of this Final Rule, we use “sales of one week or less” even if the commenters 

used “sales of less than one week.” 
Docket No. RM04-7-000 342 

provides utilities a disincentive to offer their power to wholesale customers in their 

local control area for short-term sales; and (iii) whether an “up to” rate adequately 

mitigates market power for such sales. 

Comments

607. While not opposing the default rate, APPA/TAPS state that as an alternative, 

sales of one week or less could occur under the traditional “split the savings” 

methodology.625 APPA/TAPS submit that both of these methods are consistent with 

the Commission’s observation that “[a]bsent market power, a generator would 

typically run if it had excess power and could cover its incremental costs plus some 

return.”626

608. While the Carolina Agencies claim that sales of one week or less should not 

carry a capacity charge, they concede that a reasonable contribution to the mitigated 

supplier’s fixed costs may be appropriate (e.g., by including a modest adder over the 

supplier’s incremental cost of energy).627

609. NRECA and AARP ask the Commission to retain the incremental cost plus 10 

percent methodology for mitigating sales of one week or less.628 NRECA expresses 

a concern that the Commission’s default cost-based rates (for all three products - 

 625 APPA/TAPS at 45-46. 

626 Id. (quoting April 14 Order, 107 FERC ¶ 61,018 at P 152). 

627 Carolina Agencies at 11. 

628 NRECA at 30; AARP at 8. 
Docket No. RM04-7-000 343 

sales of one week or less; sales of more than one week but less than one year; and 

sales of one year or longer) may be subject to gaming by larger public utilities, 

especially because the sellers hold all of the critical data. It asserts that if sellers have 

too much leeway in choosing which units they will use to calculate their incremental 

or embedded costs, the default cost-based rates will not provide an effective rate 

ceiling, and the purpose of the default mitigation will be undermined. NRECA 

proposes that the Commission require sellers subject to default cost-based rates to 

submit both pre- and post-approval filings supporting the mitigated cost-based rates 

for short-and mid-term sales. NRECA suggests that the seller justify its mitigated 

rates beforehand by demonstrating its incremental costs or embedded costs, as 

appropriate, and then file after-the-fact quarterly reports of the actual sales and the 

actual incremental or embedded costs incurred in making these sales.629 NRECA 

suggests that this approach would subject mitigated cost-based rate sales to a costbased formula rate, and therefore to refund, upon Commission review of the quarterly 

compliance filing.630

610. NASUCA urges the Commission to require that all mitigated rates, and any 

rate discounts, whether for more or less than one year in duration, must be filed and 

 629 Suez/Chevron voice a similar concern, adding that a true-up provision would 

also help improve transparency with regard to the cost of mitigated sales for the benefit 

of state commissions. Suez/Chevron at 13-14. 

630 NRECA at 30-32. 
Docket No. RM04-7-000 344 

made subject to public scrutiny and Commission review under section 205 of the 

FPA.631 NASUCA is concerned that under the NOPR, only rates to be in effect for 

more than one year are required to be filed publicly in advance and subject to protest, 

intervention, prior Commission review and revision. It argues, however, that section 

205 contains no exception from the filing requirement for sales of less than one 

year.632 Given that all new rate schedules and contracts affecting rates must be 

publicly filed, NASUCA asks the Commission not to reduce section 205’s procedural 

safeguards for sales of less than one year at cost-based rates (i.e., by not requiring that 

they be subject to prior notice and review).633 

611. Some commenters oppose the incremental cost plus 10 percent default rate, 

with several alleging that it deviates from prior Commission precedent without 

sufficient justification and fails to adequately compensate sellers.634 Some 

commenters also allege that such an approach will deter new entry and gives sellers 

the incentive to sell outside the mitigated market. 

612. For example, Westar states that the Commission’s reasoning in the July 8 

Order which explained that the cost plus 10 percent default rate represents a 

 631 NASUCA at 18-19; NASUCA reply comments at 16-18. 

632 NASUCA at 18 (citing NOPR at P 22). 

633 Id. at 18-19. 

634 MidAmerican at 9-11, Westar at 24. 
Docket No. RM04-7-000 345 

“conservative proxy for a reasonable margin available in a competitive market,”635

suffers from two fatal flaws. First, the Commission failed to distinguish or even 

mention Terra Comfort wherein, Westar and Duke submit, the Commission found 

that 10 percent adders provide no contribution to fixed costs, and it rejected the 

argument that “utilities routinely forego these margins and sell at 110 percent of 

incremental cost.”636 Second, according to Westar, in adopting this default rate the 

Commission relied heavily upon an order that applied the formula in an RTO under 

entirely different circumstances.637 

613. MidAmerican and Westar note that, in support of the default rate, in the April 

14 Order the Commission cited a PJM tariff provision pursuant to which generators 

dispatched out of economic merit have their bids mitigated to incremental costs plus 

10 percent to prevent them from exercising market power and, at the same time, 

providing revenues which include a margin.638 MidAmerican and Westar contend 

that this is merely an example of a mitigation mechanism, not a rationale for a broadscale default mitigation scheme that ignores years of precedent.639 They submit that 

 635 July 8 Order, 108 FERC ¶ 61,026 at P 155. 

636 Westar at 24 (quoting Terra Comfort Corp., 52 FERC ¶ 61,241 at 61,839-40 

(1990)); Duke at 8-9, n.9. 

637 Westar at 25 (citing PJM Interconnection, L.L.C., 107 FERC ¶ 61,112, at 

61,366 (2004), order on reh’g, PJM Interconnection, L.L.C., 110 FERC ¶ 61,053 (2005)). 

638 April 14 Order, 107 FERC ¶ 61,018 at P 152, n.146. 

639 MidAmerican at 10; Westar at 25. 
Docket No. RM04-7-000 346 

the PJM tariff mitigates bids for a select set of generators. They state that, regardless 

of the level of their bids, those generators are still paid the market clearing price 

because only the offer is capped. Further, because PJM’s methodology applied this 

offer cap only to a limited number of hours, MidAmerican and Westar state that 

sellers were also free to bid above the cap in the majority of the hours of the year.640 

In contrast, MidAmerican and Westar claim that the incremental cost plus 10 percent 

default rate is an absolute cap on revenues that would apply to all sales of one week 

or less in length.641

614. Although the July 8 Order explained that incremental cost plus 10 percent was 

a backstop, default rate, and that entities were free to propose alternative mitigation 

schemes, MidAmerican asserts that this ignores the fact that the Commission has 

routinely accepted alternative cost-based rates for sales of one week or less. As such, 

MidAmerican maintains that there is no reason why “split the savings” rates, or rates 

reflecting a demand charge, could not be used as a default rate for mitigated sales of 

one week or less.642

615. Several commenters also argue that the energy-only incremental cost plus 10 

percent methodology does not allow for proper recovery of capacity-based costs on 

 640 Id. 

641 Id. 

642 MidAmerican at 13. 
Docket No. RM04-7-000 347 

sales of one week or less thereby artificially depressing the prices of these short-term 

sales and possibly deterring new entry.643 These commenters state that sellers should 

be allowed to recover a contribution to their fixed/capacity costs. 

616. Some commenters contend that the default cost-based rates create an incentive 

to sell outside the mitigated market because they recover less than cost-based rates 

historically accepted that included a demand charge. However, they assert that 

setting rates that require buyers to make a reasonable contribution to the seller’s fixed 

costs for the use of the capacity would create an incentive for the seller to make sales 

within its mitigated control area.644 Duke and the Oregon Commission add that 

allowing recovery of capacity-based costs also ensures that wholesale customers bear 

their fair share of system costs.645 

617. Several commenters also claim that by artificially depressing short-term sales 

prices, the default rate transfers wealth from the supplier’s retail customers to 

wholesale customers.646 Such retail customers, these commenters state, have paid the 

fully-allocated costs of the system and obtain revenue credits to their costs from the 

 643 Pinnacle at 10; Ameren at 15; Duke at 8; MidAmerican at 9-11; Westar at 24; 

Drs. Broehm and Fox-Penner at 15-16; Xcel at 9; Progress Energy at 9; PPL reply 

comments at 17-18; EEI at 29; NRG at 5, 11. 

644 See, e.g., Duke at 9. 

645 Id. at 10; Oregon Commission reply comments at 2. 

646 Westar at 16; Progress Energy at 9; EEI at 33-34; Pinnacle at 10; MidAmerican 

at 9. 
Docket No. RM04-7-000 348 

supplier’s short-term sales. Where short-term sales are made on a non-interruptible 

basis, and the incremental cost plus 10 percent rate prices them only at incremental 

running cost, Progress Energy contends that wholesale purchasers are receiving the 

benefits of capacity without cost.647 Progress Energy and EEI submit that retail 

native load customers, as a result, lose the economic benefits that would otherwise 

accrue to them through revenue credits from short-term wholesale sales.648 

Wholesale customers charged through an embedded cost-of-service are also harmed, 

Progress Energy adds, because they lose the economic benefits that would otherwise 

accrue to them through revenue credits from short-term wholesale sales.649 

618. Progress Energy and Duke instead favor an “up to” cost-based default rate for 

sales of one week or less.650 For such sales, Progress Energy supports an “up to” rate 

design flexible enough to allow rates as low as the mitigated seller’s incremental 

costs and as high as 100 percent of the seller’s capacity and energy costs. According 

to Progress Energy, a mitigated seller could choose to make sales as low as its 

incremental cost when either (1) the unmitigated market price of competing sellers 

dictates that price, or (2) the mitigated seller needs to sell its excess generation at that 

price to maintain a minimum generation control margin. Given that there is a short-

 647 Progress Energy at 9-10. 

648 Id. at 10, n.13; EEI at 29. 

649 Progress Energy at 10, n.13. 

650 Progress Energy at 10; Duke at 8. 
Docket No. RM04-7-000 349 

term market for capacity, Progress Energy asks that the default cost-based rates 

include a price structure that allows pricing of capacity-only sales.651 

619. Xcel suggests that the Commission should allow for an even higher emergency 

price in situations where purchasers need to make a purchase not simply to achieve 

economic benefits but where the purchaser is capacity deficient. Xcel submits that in 

such instances, a purchaser plainly obtains a capacity benefit from the purchase of 

such power. Historically, the Commission has allowed an emergency rate of $100 

per MWh for emergency service. Given that gas prices have dramatically increased 

since that standard rate began to be utilized, Xcel claims that an emergency rate of the 

higher of cost plus 10 percent or $1,000 per MWh would be appropriate in the present 

environment.652 

Commission Determination

620. The Commission will retain the incremental cost plus 10 percent methodology 

as the default mitigation for sales of one week or less, while continuing to allow 

sellers to propose alternative cost-based methods of mitigation tailored to their 

particular circumstances. As discussed more fully below, we clarify that in retaining 

the incremental cost plus 10 percent methodology as the default mitigation for sales 

 651 Progress Energy at 10. 

652 Xcel at 10. 
Docket No. RM04-7-000 350 

of one week or less we do not otherwise limit a seller’s ability to propose different 

cost-based rates for sales of one week or less.653

621. Although a number of commenters suggest that the Commission should adopt 

a different default cost-based ratemaking methodology for sales of one week or less, 

they have failed to persuade us that the existing default rate is inappropriate. As the 

Commission has previously stated, an incremental cost rate that allows a fair recovery 

of the incremental cost of generating with a 10 percent adder to provide for a margin 

over incremental cost is reasonable.654 Incremental costs plus 10 percent represents a 

conservative proxy for a reasonable rate available in a competitive market.655 On this 

basis, we find incremental cost plus 10 percent to be an appropriate default rate. 

Moreover, we allow sellers the opportunity to design, support, and propose other 

cost-based rates that they believe are more appropriate for their particular 

circumstances. 

622. Several commenters note that the Commission has permitted various costbased rate methodologies prior to the April 14 Order, including a split-the-savings 

formula. These entities express concern that the use of the incremental cost plus 10 

percent methodology as the default mitigation rate for sales of one week or less 

 653 For that matter, we also do not limit a seller’s ability to propose and support 

different cost-based rates for any of the default cost-based rates. 

654 April 14 Order, 107 FERC ¶ 61,018 at P 152. 

655 July 8 Order, 108 FERC ¶ 61,026 at P 155. 
Docket No. RM04-7-000 351 

forecloses the possibility of other cost-based pricing methodologies. However, this is 

not the case. Rather than precluding alternative mitigation proposals, the April 14 

Order allows sellers to propose case-specific tailored mitigation, or adopt the default 

cost-based rate. The April 14 Order described the default mitigation rate as “a 

backstop measure” intended to ensure a just and reasonable rate.656 The Commission 

re-emphasized this in its July 8 Order explaining: “In the instant case, the 10 percent 

adder is to be used only as a backstop or default measure in the event that an 

applicant does not opt to propose its own mitigation.”657 

623. As such, the incremental cost plus 10 percent rate represents a default, costbased rate to protect customers from the potential exercise of market power and 

provide sellers regulatory rate certainty by establishing a “safe harbor.” Any 

proposal for alternative cost-based rates will be considered on a case-by-case basis. 

624. Further, with regard to including capacity charges in rates for one week or 

less, a seller may propose to recover such charges and the Commission will consider 

these charges based on the specific facts and circumstances presented. Rather than 

ignoring alternative forms of cost-based rates, as some commenters claim, the 

Commission’s policy offers sellers the opportunity to propose such alternatives. 

 656 April 14 Order, 107 FERC ¶ 61,018 at P 148. 

657 July 8 Order, 108 FERC ¶ 61,026 at P 157 (emphasis added). 
Docket No. RM04-7-000 352 

625. Use of the default rate as set forth in the April 14 and July 8 Orders also is not 

inconsistent with Terra Comfort, as some commenters claim. As explained above, 

contrary to some commenters’ allegations, the Commission does not confine 

mitigated sellers to rates that forego a contribution to fixed/capacity costs. In Terra 

Comfort, the Commission explained that “most utilities maintain on file for all 

services flexible demand charge ceilings designed to reflect a 100-percent 

contribution to the fixed costs of their facilities.”658 The Commission then added that 

utilities are not obligated to “forego these margins and sell at 110 percent of 

incremental costs.”659 In the April 14 Order, the Commission, consistent with its 

holding in Terra Comfort, explained that “as a backstop measure, we will also 

provide ‘default’ rates to ensure that wholesale rates do not go into effect, or remain 

in effect, without assurance that they are just and reasonable.”660 Contrary to Duke’s 

assertion that this default rate suggests that sellers do not have economic justification 

(or need) to recover a share of their fixed/capacity costs in the prices charged for such 

transactions,661 the Commission’s policy allows “applicants to propose case-specific 

mitigation tailored to their particular circumstances that eliminates the ability to 

 658 Terra Comfort Corp., 52 FERC at 61,839. 

659 Id. 

660 April 14 Order, 107 FERC ¶ 61,018 at P 148. 

661 Duke at 9 (citing Terra Comfort, 52 FERC at 61,839). 
Docket No. RM04-7-000 353 

exercise market power, or adopt cost-based rates such as the default rates herein.”662 

The Commission explained in the April 14 Order that “[p]roposals for alternative 

mitigation in these circumstances could include cost-based rates or other mitigation 

that the Commission may deem appropriate.”663 Consistent with industry practice 

and Commission precedent, therefore, where mitigated sellers can properly justify 

such contributions, they may propose to recover contributions to fixed/capacity costs 

under the Commission’s mitigation policy. 

626. Such alternative mitigation has been proposed and accepted. For example, 

Progress Energy correctly notes that one of its subsidiaries proposed as mitigation - 

and the Commission approved - a cost-based “up-to” capacity charge and a costbased energy charge for the subsidiary’s power sales of less than one year, including 

sales of one week or less, in the mitigated control area.664 Progress Energy is correct 

in observing that this decision was consistent with the Commission’s long-standing 

policy of permitting the pricing of short-term sales at cost-based “up-to” capacity 

 662 April 14 Order, 107 FERC ¶ 61,018 at P 147. 

663 April 14 Order, 107 FERC ¶ 61,018 at n.142. 

664 Carolina Power & Light, 113 FERC ¶ 61,130 at P 23-24 (2005) (citing Detroit 

Edison Co., 78 FERC ¶ 61,149 (1997) (approving a demand charge for power sales for 

periods of an hour up to one year); Illinois Power Co., 57 FERC ¶ 61,213, at 61,699-700 

(1991) (permitting utilities to include in their rates an amount above incremental costs to 

provide a contribution to fixed costs)). 
Docket No. RM04-7-000 354 

charges and cost-based energy charges.665 Rather than artificially depressing the 

prices of short-term sales, exacting a wealth transfer, or limiting a seller’s ability to 

respond to market conditions, as Progress suggests, the default cost-based rate for 

sales of one week or less provides a backstop measure intended to protect customers 

by ensuring that, in the event a seller loses or relinquishes its market-based rate 

authority, there is a readily available cost-based rate under which such sellers may 

choose to transact , and the mitigated seller by establishing a refund floor that 

provides it with rate certainty. 

627. As to some commenters’ suggestion that the incremental cost plus 10 percent 

methodology, and cost-based rates in general, adversely affect retail rates because 

they exact a wealth transfer from the supplier’s retail customers to wholesale 

customers, the July 8 Order rejected such claims on the ground that they were 

“unsupported and speculative.”666 Not only do these claims remain unsupported but 

they suggest that the Commission should allow wholesale rates in excess of a just and 

reasonable rate. This result would not be just and reasonable. As the Commission 

stated in the July 8 Order, “our rate making policy is designed to provide for recovery 

of prudently incurred costs plus a reasonable return on investment.”667 Moreover, the 

 665 Progress Energy at 8-9. 

666 July 8 Order, 108 FERC ¶ 61,026 at P 140, 154. 

667 Id. at P 152. 
Docket No. RM04-7-000 355 

Commission explained that “the opportunity for the applicants to propose alternative, 

tailored mitigation measures should allow adequate consideration of the effect on 

investment and customers.”668

628. We will not adopt Progress Energy’s request that the default rate be modified 

to include a price structure allowing pricing of capacity-only sales. Progress Energy 

fails to provide adequate justification to provide for such a rate in our default costbased rates. For example, Progress Energy states that there is a short-term market for 

capacity-only sales but fails to explain how this market is a power sales market (for 

which our default cost-based rates apply) rather than an ancillary services market 

which is not contemplated in the default cost-based power sales rates. Nevertheless, 

as noted above, a mitigated seller has the opportunity to propose and justify an 

alternative to the default rate. 

629. Similarly, in response to NASUCA’s request that the Commission require all 

mitigated rates and discounts to be filed under section 205 of the FPA, we note that 

all mitigation proposals must be filed with the Commission for review. These filings 

are noticed and interested parties are given an opportunity to intervene, comment, or 

protest the submittal. With regard to discounts, as we explain in the discounting 

section of this Final Rule, discounts made to customers, like all other rates, are 

required to be reported in the seller’s EQRs. 

 668 Id. at P 154 
Docket No. RM04-7-000 356 

630. We also note that the Commission stated in the April 14 Order that where a 

seller proposes to adopt the default cost-based rates (or where it proposes other costbased rates), it must provide cost support for such rates.669 The Commission will 

examine the proposed rates on a case-by-case basis. With regard to sales of one week 

or less, where the seller fails to provide sufficient cost support, the Commission will 

direct the seller to submit a compliance filing to provide the formulas and 

methodology according to which it intends to calculate incremental costs.670 We note 

here that, to the extent a seller proposes a cost-based rate formula, we will require the 

rate formula used be provided for Commission review and such formula included in 

the cost-based rate tariff including formulas used in calculating incremental cost. 

631. The Commission also has set proposed default cost-based rates for hearing 

when appropriate.671 We believe that this case-by-case review of proposed default 

cost-based rates adequately addresses NRECA’s and Suez/Chevron’s concerns. 

Moreover, to the extent that an entity contends that a mitigated seller is flowing 

 669 April 14 Order, 107 FERC ¶ 61,018 at P 208. See Entergy Services, Inc., 

115 FERC ¶ 61,260 at P 49 (2006) (accepting cost-based rates based on incremental cost 

plus 10 percent, noting that filing included the formula and methodology according to 

which seller intends to calculate incremental costs). 

670 See, e.g., Aquila, Inc., 112 FERC ¶ 61,307 at P 26 (2005); Oklahoma Gas and 

Electric Co., 114 FERC ¶ 61,297 at P 19 (2006). 

671 AEP Power Marketing, Inc., 112 FERC ¶ 61,047 at P 28 (2005). 
Docket No. RM04-7-000 357 

inappropriate costs through its formula rate, section 206 of the FPA provides a 

process for filing a complaint. 

b. Sales of more than one week but less than one year 

Commission Proposal

632. In the NOPR, the Commission sought comment on issues related to the design 

of an "up to" cost-based rate. The Commission noted in the NOPR that it has allowed 

significant flexibility in designing “up to” rates in the past, and invited comments on 

whether such flexibility is still warranted. In particular, the Commission noted that 

there are often disputes over which units are “most likely to participate” or “could 

participate” in coordinated sales, and asked if it should continue to allow utilities 

flexibility in selecting the particular units that form the basis of the “up to” rate. If 

not, the Commission asked which units should form the basis of an “up to” rate, and 

how such a rate should be calculated. In addition, parties were invited to comment on 

whether a standard rate methodology should be prescribed that would allow a seller 

to avoid a hearing on this issue. The Commission asked whether a methodology that 

is based on average costs (both variable and embedded) would allow a seller to avoid 

a hearing because it eliminates the seller’s discretion in designating particular units as 

“likely to participate.” The Commission also inquired as to whether there are other 

approaches that would accomplish a similar objective. 
Docket No. RM04-7-000 358 

Comments

i. Selecting the particular units that form the basis of the “up to” 

rate

633. Regarding whether the Commission should continue to allow utilities 

flexibility in selecting the particular units that form the basis of the “up to” rate, EEI 

argues for flexibility because selection of generating units for these short-terms sales 

is made with the goal of minimizing the cost-of-service to the utility’s native load 

customers.672 Several commenters note that the Commission has the ability to verify 

the validity of the seller’s analysis through an audit of the company’s records to 

monitor transactions made under the “up to” rates.673

634. Pinnacle asks the Commission to establish a stacking methodology that 

determines default units most likely to run while allowing utilities to propose a 

different stack based on historical operational sales data. Pinnacle also urges the 

Commission to clarify that the variable cost for the unit can be defined as the system 

incremental cost.674

635. Other commenters raise concerns with respect to the discretion given to 

utilities to choose units used to calculate the ceiling.675 They submit that taking only 

 672 EEI at 30-31. 

673 MidAmerican at 12; Duke reply comments at 14; EEI reply comments at 20. 

674 Pinnacle at 11. 

675 See, e.g., NC Towns at 4-5; NRECA at 30-32 (utilities with a portfolio of 

generation units of various vintages and operating characteristics could manipulate the 

 (continued...) 

 
Docket No. RM04-7-000 359 

a small snapshot of certain generating plants to develop cost-based rates will subject 

buyers to the discretion of sellers possessing market power. 

636. APPA/TAPS, the Carolina Agencies and AARP oppose allowing mitigated 

sellers too much flexibility in designing mitigation methods on the grounds that such 

an approach would result in market-based rates disguised as cost-based mitigated 

rates.676 For mid-term sales, APPA/TAPS and AARP urge the Commission to 

require a well-supported analysis of the units most likely to provide the service.677 

637. The Carolina Agencies ask the Commission to consider whether pricing 

service based on the costs of units “likely to participate” is sufficiently rigorous to 

meet the operative statutory standards. They oppose the “units most likely to 

participate” method on the basis that the cost and dispatch assumptions used in the 

underlying analyses are subjective and difficult to verify. The Carolina Agencies 

state that the identified “likely to participate” units often wind up being those units on 

the system with the highest fixed costs, regardless of whether the units are of a type 

that one might expect to be cycled or ramped for short-term sales. If mitigated 

 

rate ceiling and undermine mitigation). 

676 APPA/TAPS at 44-45; Carolina Agencies at 24-25; AARP at 8. 

677 APPA/TAPS at 46; AARP at 8. Alternatively, both APPA/TAPS and the 

Carolina Agencies agree that the Commission’s proposal to use an average embedded 

cost basis for mid-term sales would be acceptable and would avoid the need to make 

determinations about units most likely to run. APPA/TAPS at 4, 44-47; Carolina 

Agencies at 24. 
Docket No. RM04-7-000 360 

utilities are allowed to continue using this method, the Carolina Agencies urge the 

Commission to develop a set of generic guidelines that will yield more rigorous, less 

subjective analyses.678

ii. Standard default rate methodology to allow a seller to avoid a 

hearing

638. With regard to whether a standard methodology should be prescribed that 

would allow a seller to avoid a hearing on rate methodology (e.g., a methodology that 

is based on average costs (both variable and embedded)), many commenters urge the 

Commission to continue to allow flexibility rather than imposing a standard 

methodology based on average costs.679 

639. Westar argues that the use of a standard methodology based on average costs 

would constitute a radical departure from long-settled Commission policy. Westar 

states that in Opinion No. 203, the Commission found that cost-based pricing cannot 

keep pace with fluctuating markets,680 and that imposing average cost pricing would 

 678 Carolina Agencies at 24. 

679 See, e.g., Westar at 14; MidAmerican at 11; PPL reply comments at 17-18; 

Southern at 66-67; Duke at 10; Progress Energy at 10-12; Xcel at 10; EEI at 30-31. 

680 Similarly, Southern states that the use of an “up to” rate design protects 

customers against unreasonably high prices (the purpose of mitigation in the first place), 

while giving mitigated sellers the ability to respond to pricing and market dynamics. 

Southern at 66; see also EEI reply comments at 19-20; Xcel at 10. 
Docket No. RM04-7-000 361 

only exacerbate the market inefficiencies that result under cost-based rate making by 

eliminating pricing flexibility and lowering ceiling rates.681

640. Westar adds that public utilities have the statutory right under section 205 to 

propose and file their rates, and that the Commission lacks the power to impose rates 

upon public utilities.682 Westar therefore opposes standardizing cost-based rates in 

any manner that would curb a mitigated seller’s section 205 discretion to select a 

pricing methodology.683 Westar contends that the Commission’s section 206 

authority to require rate changes is limited to instances where the Commission finds 

that the utility’s presumptively just and reasonable existing rate is unjust and 

unreasonable, and that the Commission’s proposed alternative is just and 

reasonable.684 According to Westar, the NOPR offers no support for a finding that 

the wide variety of previously approved cost-based rate methodologies are no longer 

just and reasonable, and must be replaced with a standardized rate method.685

 681 Westar at 14, 23. 

682 Id. at 17-18, 23-24 (citing Atlantic City Electric Company v. FERC, 295 F.3d 

1, 9 (D.C. Cir. 2002)). 

683 See Westar at 14, n.26 (claiming that an average cost methodology would 

eliminate the seller’s discretion in designating particular units as “likely to participate” in 

cost-based sales and conflicts with utilities’ fundamental rights under section 205 of the 

FPA, and long-standing precedent under the “units most likely” methodology.) 

684 Id. at 18 (citing Tennessee Gas Pipeline Company v. FERC, 860 F.2d 446, 456 

(D.C. Cir. 1988)); see also id. at 23-24. See also MidAmerican reply comments at 22. 

685 Westar at 24. 
Docket No. RM04-7-000 362 

641. Duke and PPL support “up to” rates686 based on the embedded costs of the 

units most likely to provide the service.687 According to Duke, the average costs of 

all units in a utility’s installed generating capacity base could be quite different than 

the costs of the specific units most likely to participate in the short-term wholesale 

market.688 As such, Duke claims that a system-average cost approach could force the 

mitigated seller to charge non-native load customers less than the cost actually 

incurred for generating power whenever incremental costs are greater than average 

costs, thereby creating a disincentive for the mitigated seller to market wholesale 

power in a control area where it does not have market-based rate authority.689 

642. Progress Energy states that it opposes a standardized methodology because it 

will not send appropriate price signals to customers or appropriately compensate the 

 686 Drs. Broehm and Fox-Penner also support the use of an “up to” rate because it 

offers flexibility in conducting transactions. However, they suggest a methodology that 

reflects the incremental cost of new entry to encourage new investment and allow sellers 

a reasonable opportunity to earn a fair return on their investment. According to Drs. 

Broehm and Fox-Penner, the weakness of setting a price cap based on embedded cost 

stems from disputes that arise over which units are selected as the basis for the price cap. 

Because the cost of new entry methodology would allow the price cap to be formulaic 

and generic based on the estimate of the annualized total cost of building a new 

combustion turbine peaking facility, they suggest that this approach would minimize 

discretion in determining the foundation of a cost-based rate. Drs. Broehm and FoxPenner at 16. 

687 Duke at 10; Duke reply comments at 13-14; PPL reply comments at 17-18. 

688 Duke at 10; see also MidAmerican at 9-11; PPL reply comments at 17-18; 

Southern at 66-67. 

689 Duke at 10; Duke reply comments at 14. 
Docket No. RM04-7-000 363 

seller for costs where the seller’s generating units or the customer’s usage deviates 

materially from the standardized methodology. Rather than adopting a “units most 

likely” approach, Progress Energy prefers a methodology that identifies units based 

on load conditions that are more closely associated with typical market clearing 

opportunities, between the average of monthly minimum loads and the average of 

monthly peak loads. Such an approach, Progress Energy argues, better represents 

conditions where sales occur.690

643. While supporting flexibility in the design of up-to rates,691 Ameren urges the 

Commission to prescribe a standard methodology that sellers could opt to use to 

avoid prolonged and costly factual disputes. Ameren asserts that a formula rate based 

on information from FERC Form No. 1, where available, and incorporating the AEP 

Methodology692 could easily form the basis of such a standard methodology.693

 690 Progress Energy at 11-12. 

691 Ameren maintains that allowing mitigated sellers to sell at cost-based “up to” 

rates from which the seller may discount adequately mitigates the seller’s market power 

while still allowing that entity to participate in competitive markets. Ameren states that 

“up to” rates thus can benefit customers by resulting in a more robust market. Ameren at 

15. 

692 American Electric Power Company, 88 FERC ¶ 61,141 at 61,453-54 (1999). 

Under this methodology, Ameren explains that a seller must develop a cost-based annual 

rate, which then is divided by 52 to derive a weekly rate, which then is divided by 5 to 

derive a daily peak rate, which then is divided by 16 to derive an hourly peak rate. 

Ameren at 15. 

693 Ameren at 16. 
Docket No. RM04-7-000 364 

644. Because of concerns with regard to the discretion given to sellers to choose 

units used to calculate the cost-based rate, the NC Towns assert that a standard, 

system-average ratemaking methodology would provide a certainty beneficial to both 

utilities and wholesale customers, as well as help reduce protracted negotiations and 

litigation surrounding parties’ concepts of a cost-based rate.694

645. For mid-term sales that carry a capacity charge, the Carolina Agencies contend 

that charge should be based on the utility’s fully allocated system-wide cost of 

capacity. The Carolina Agencies state that energy associated with the purchased 

capacity also should be priced on a system average basis, in order to adhere to the 

principle that capacity and energy charges be developed on a consistent basis.695 For 

these mid-term sales, the Carolina Agencies also support giving Load Serving 

Entities (LSEs) located within the mitigated utility’s control area an option between: 

(1) locking-in their price for capacity and/or energy in advance of delivery, at the 

mitigated utility’s forecasted cost of energy and its cost-based tariff rate for capacity; 

or (2) having their charges determined through a formula rate that would charge 

purchasers an annually-updated price reflecting the utility’s actual system-wide 

average costs.696

 694 NC Towns at 4-5. 

695 Carolina Agencies at 11; see also APPA/TAPS at 46-47, n.50 (citing Florida 

Power & Light Co., 66 FERC ¶ 61,227 at 61,532 (1994)). 

696 Carolina Agencies at 11. 
Docket No. RM04-7-000 365 

646. The Carolina Agencies add that any change in the Commission’s pricing 

policy that would yield more reasonable cost-based rates must be coupled with a 

“must-offer” requirement. Lower cost-based rates without a concurrent “must–offer” 

requirement, they argue, will only provide the mitigated utility with an even greater 

incentive to sell all its available power beyond the mitigated region, thereby 

exacerbating the problems of depleted supply and profiteering by remaining 

suppliers.697 

647. For mid-term sales, NRECA asks the Commission to enforce a matching or 

consistency principle. Here, NRECA advocates using the same generating units “as 

the basis for the fixed and variable costs in determining the default embedded-cost 

rate. In no case should a seller be allowed to mix high-fixed-cost units with highvariable-cost units to artificially inflate the embedded-cost rate. If a seller can show 

that a portfolio of generating units is likely to be used to provide service, then the 

seller might be permitted to use a weighted average of the fixed and variable costs of 

the portfolio.”698

Commission Determination

648. Under the Commission’s current policy, the default mitigation rate for midterm sales (sales of more than one week but less than one year) is priced at an 

 697 Carolina Agencies at 25. 

698 NRECA at 32. 
Docket No. RM04-7-000 366 

embedded cost “up to” rate reflecting the costs of the unit(s) expected to provide the 

service. The Commission will retain this approach as the default mitigation for midterm sales. As is the case with sales for one week or less, sellers may choose to adopt 

the default cost-based rate or propose alternative cost-based rates. 

Selecting the particular units that form the basis of the “up to” 

rate

649. When a seller adopts the default cost-based mid-term rate or otherwise 

proposes a cost-based rate designed on the unit or units expected to run, the 

Commission will continue to allow the seller flexibility in selecting the particular 

units that form the basis of the “up to” rate. Entities that included various proposals 

for “up to” cost-based rate methodologies in their comments may propose those or 

other methodologies as alternatives to the default cost-based rates, and the 

Commission will consider any such proposal on a case-by-case basis. Any seller 

proposing an alternative mitigation methodology, including a cost-based 

methodology with demand or capacity charges, carries the burden of justifying its 

proposal. 

650. We agree with commenters that the Commission has the ability to verify the 

validity of the seller’s analysis and will continue to do so in our review of proposed 

cost-based rates. We will continue to conduct our own analysis of whether a 

proposed cost-based rate is just and reasonable and, if warranted, will set such a 

proposed rate for evidentiary hearing where there are issues of material fact. 
Docket No. RM04-7-000 367 

651. In response to the concerns raised by some commenters regarding the 

discretion given to sellers in the design of “up-to” rates, as noted above, the 

Commission considers all evidence when reviewing a cost-based rate proposal and, if 

a company has not justified selection of certain generating units, we will not accept 

the proposed rate. Under the FPA, we have the authority to accept, reject, or modify 

a proposed rate based on an analysis of the specific facts and circumstances. 

652. Further, we find that the approach we adopt in this regard allowing sellers 

flexibility in designing “up to” rates for purposes of mitigation, subject to 

Commission review and approval, is consistent with the Commission’s historical 

approach to the pricing of cost-based rates. Because the Commission will have the 

opportunity to review a seller’s proposed “up to” rates, we find that allowing 

mitigated sellers flexibility in choosing which units are used to calculate the proposed 

cost-based rate will not result in market-based rates being disguised as cost-based 

mitigated rates. 

653. In response to Pinnacle's suggestion that the Commission make available a 

stacking methodology to be used to determine which units are most likely to run, we 

will do so for informational purposes and will make the methodology available on the 

FERC Internet site. We also note, however, that sellers may propose to use their own 

stacking methodology. 

654. With regard to the Carolina Agencies’ question of whether pricing service 

based on the costs of units “likely to participate” is sufficiently rigorous to meet the 

operative statutory standards, we find that it is. Historically, the Commission has 
Docket No. RM04-7-000 368 

allowed such an approach and the Carolina Agencies have failed to convince us that, 

whether or not the underlying analysis is difficult to verify, the approach does not 

result in just and reasonable rates. In addition, with regard to Carolina Agencies’ 

position with regard to a “must-offer” provision, we discuss proposals for a “mustoffer” provision below in the section on protecting mitigated markets. 

Standard default rate methodology to allow a seller to avoid a 

hearing

655. Regarding a standard default rate methodology that would allow a seller to 

avoid a hearing on rate methodology (e.g., a methodology that is based on average 

costs (both variable and embedded)), we note that the Commission has approved 

various rate methodologies in the past. Rather than adopting a specific default rate 

methodology in this Final Rule, we affirm that, to the extent the Commission has 

previously accepted a particular rate methodology, that methodology is presumed to 

be just and reasonable until the Commission makes a contrary finding.699 

656. The Commission will continue to allow sellers flexibility in designing “up to” 

cost-based rate proposals as alternatives to the default methodology. Entities that 

 699 In response to Westar, as discussed herein, Commission precedent supports 

flexibility in designing cost-based rates and we are not proposing to standardize costbased rates here. Upon loss or surrender of market-based rate authority a seller has a 

number of options on how to make wholesale power sales. It can revert to a cost-based 

rate tariff on file with the Commission, file a new proposed cost-based rate tariff, or 

propose other mitigation. While we provide a default cost-based rate methodology, we 

also allow a seller to submit its own cost-based mitigation. On this basis, a seller’s filing 

rights under section 205 of the FPA are not eroded and we are not finding methodologies 

different from the default methodology necessarily to be unjust and unreasonable. 
Docket No. RM04-7-000 369 

included various proposals for “up to” cost-based rate methodologies in their 

comments may propose those or other methodologies as alternatives to the default 

cost-based rates, and the Commission will consider any such proposal on a case-bycase basis.700 Any seller proposing an alternative mitigation methodology carries the 

burden of justifying its proposal. 

657. We acknowledge that a standard default rate methodology may provide, as 

several commenters suggest, some level of certainty and avoid prolonged factual 

disputes. However, we are persuaded by the concerns expressed by others that 

designing a standard default rate methodology based, for example, on average costs 

may not account for the actual costs of the units making the sales, and thus may not 

allow the seller to recover its costs. 

c. Sales of one year or greater

Comments

658. While the NOPR did not propose changes to the default pricing for long-term 

sales (sales of one year or more), several entities filed comments on that issue. 

APPA/TAPS and AARP reiterate their support for pricing such sales on an embedded 

cost basis.701 They submit that the Commission should not depart from its default 

cost-based mitigation policy with regard to long-term sales. The NC Towns also 

 700 In response to Pinnacle’s request for clarification that the variable cost for the 

unit can be defined as the system incremental cost, a mitigated seller can make that 

argument in support of an alternative cost-based mitigation methodology. 

701 APPA/TAPS at 47; AARP at 8. 
Docket No. RM04-7-000 370 

favor using system average costs in a rate base, rate of return model for determining 

long term cost-based rates.702 Similarly, the Carolina Agencies assert that long-term 

sales to embedded LSEs should be priced at the mitigated utility’s fully allocated 

average embedded cost of capacity and system average energy costs. As with shortterm sales, the Carolina Agencies urge the Commission to allow the embedded LSEs 

the choice between: (1) locking-in their price at the mitigated utility’s embedded cost 

rates; or (2) agreeing to have their charges determined through an annually updated 

formula rate that reflects the utility’s actual system-wide average costs.703

Commission Determination

659. We will retain our existing policy for sales of one year or more (long-term) 

sales. Specifically, we will continue to require mitigated sellers to price long-term 

sales on an embedded cost of service basis and to file each such contract with the 

Commission for review and approval prior to the commencement of service.704 We 

discuss below the Carolina Agencies’ request for a “must offer” requirement. 

d. Alternative methods of mitigation

Commission Proposal

660. In the NOPR, the Commission noted that sellers that are found to have market 

power (i.e., after the Commission has ruled on a DPT analysis), or that accept a 

 702 NC Towns at 4. 

703 Carolina Agencies at 12-13. 

704 April 14 Order, 107 FERC ¶ 61,018 at P 151, 155. 
Docket No. RM04-7-000 371 

presumption of market power, can either accept the Commission’s default cost-based 

mitigation measures or propose alternative methods of mitigation. With regard to 

alternative methods of mitigation, the Commission asked in the NOPR whether it 

should allow as a means of mitigating market power the use of agreements that are 

not tied to the cost of any particular seller but rather to a group of sellers. The 

Commission asked whether the use of such agreements as a mitigation measure 

would satisfy the just and reasonable standard of the FPA. 

Comments

661. Many commenters favor allowing alternative mitigation methods tied to the 

costs of a group of sellers, in particular the Western Systems Power Pool Agreement 

(WSPP Agreement),705 or transparent competitive market prices in regional markets. 

Xcel asserts that the FPA does not require a mitigated rate to reflect a utility’s own 

cost-of-service.706 

662. E.ON U.S. supports mitigation that sets prices at competitive market levels. It 

claims that cost-based rate mitigation eliminates the potential for new competition in 

a mitigated area. In this regard, E.ON U.S. argues that profits are available only 

when market prices are below the mitigated utility’s cost-based rates, which reduces 

the incentive for investment in new generation as long as buyers can obtain below 

 705 Westar at 26-27; Pinnacle at 10; Ameren at 16-17; PG&E at 22; MidAmerican 

at 12; Xcel at 8; PPL reply comments at 18; and PNM/Tucson reply comments at 2-3. 

706 Xcel reply comments at 7. 
Docket No. RM04-7-000 372 

market-price energy from generation facilities of the mitigated utility’s ratepayers.707 

E.ON U.S. adds that mitigation reflective of competitive prices results in mitigated 

sellers that are indifferent as to the buyer’s location and competitive price signals to 

which buyers can respond accordingly.708

Use of the WSPP Agreement Rate to Mitigate Market Power

663. Several entities suggest that the rates under the WSPP Agreement may be an 

appropriate alternative mitigation method.709 Westar asserts that the purpose of the 

cost-based rate schedules under the WSPP Agreement is to mitigate perceived market 

power,710 and notes that the Commission has also accepted use of the WSPP 

 707 E.ON U.S. reply comments at 3; see also EPSA at 13. 

708 E.ON U.S. reply comments at 3. 

709 See, e.g., Westar at 26 (“The Commission developed and approved the rates 

under Schedules A and C of the WSPP Agreement as ‘rates that are within the zone of 

reasonableness and that are just and reasonable under the [Federal Power Act]’” (citing 

Western Systems Power Pool, 55 FERC ¶ 61,099, at 61,321 (WSPP), order on reh’g, 

Western Systems Power Pool, 55 FERC ¶ 61,495 (1990), aff’d in relevant part and 

remanded in part sub nom. Environmental Action and Consumer Federation of America 

v. FERC, 996 F.2d 401 (D.C. Cir. 1992), order on remand, 66 FERC ¶ 61,201 (1994)); 

Pinnacle at 10; PG&E at 22. 

710 Westar at 26 (citing Pacific Gas and Electric Company, 38 FERC ¶ 61,242 

(1987) (accepting WSPP Agreement on experimental basis); Pacific Gas and Electric 

Company, 50 FERC ¶ 61,339 (1990) (reducing the ceiling price on economy energy and 

capacity service under Schedules A, B and C from $245/MWh to $124/MWh); WSPP; 

Western Systems Power Pool, 83 FERC ¶ 61,099 (1998) (order accepting amendments); 

Western Systems Power Pool, 85 FERC ¶ 61,363 (1998) (Letter Order accepting revised 

WSPP Agreement); Western Systems Power Pool, Inc., 95 FERC ¶ 61,483 (2001) (order 

accepting amendments)). 
Docket No. RM04-7-000 373 

Agreement to mitigate market power in various contexts.711 Westar contends that 

parties to the WSPP Agreement may sell under the cost-based rate schedules of the 

WSPP Agreement regardless of whether they have a separate tariff and authorization 

from the Commission.712 Thus, Westar claims that the NOPR’s implicit question 

whether additional authorization is needed to make mitigated sales is misplaced since 

the WSPP Agreement, as an accepted tariff/rate schedule, establishes the lawful filed 

rate. 

664. Pinnacle notes that the WSPP Agreement’s price caps were established based 

on a system-wide average cost and serve to put entities without market-based rate 

authority on a similar footing. In Pinnacle's view, such agreements enhance liquidity 

in the regional markets and facilitate transactions due to the commonality of terms 

and conditions.713 

665. PG&E adds that the WSPP Agreement is the most commonly used 

standardized power sales contract in the electric industry. PG&E states that the 

WSPP membership continuously updates the WSPP Agreement to ensure that it 

 711 Id. (citing, among other cases, Western Resources, Inc., 94 FERC ¶ 61,050, at 

61,247 (2001) (accepting WSPP Agreement to mitigate potential affiliate preference 

concerns between prospective merger partners)). 

712 Id. at 27 (citing NorthPoint Energy Solutions, Inc., 107 FERC ¶ 61,181 (2004) 

(rejecting wholesale cost-based rate tariff as unnecessary in light of seller’s intent to 

make sales under the WSPP Agreement)). 

713 Pinnacle at 10. 
Docket No. RM04-7-000 374 

represents up-to-date terms for power sales contracts and notes that the process of 

updating its terms involves a diversified, experienced group of market participants 

focused on developing an appropriate rate for short-term sales. PG&E concludes that 

the terms of the WSPP tariff should be an accepted alternative rate to the default rate 

determined by the Commission.714 

666. In contrast, APPA/TAPS and AARP oppose alternative mitigation methods 

tied to the costs of a group of sellers because there is no assurance that the group rate 

would reflect the costs of the seller subject to mitigation.715 Further, APPA/TAPS 

have concerns that selecting the appropriate group and obtaining the necessary cost 

information could be extremely difficult and controversial.716

Commission Determination

667. We will address on a case-by-case basis whether the use of an agreement that 

is not tied to the cost of any particular seller but rather to a group of sellers is an 

appropriate mitigation measure. 

668. With regard to the WSPP Agreement, as discussed below, we conclude that 

use of the 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 

 714 PG&E at 22. 

715 APPA/TAPS at 47; AARP at 8. 

716 APPA/TAPS at 41. 
Docket No. RM04-7-000 375 

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. 

669. The WSPP Agreement was initially accepted by the Commission on a nonexperimental basis in 1991,717 providing for flexible pricing for coordination sales 

and transmission services. Currently, there are over 300 members of the WSPP 

Agreement located from coast to coast in the United States and Canada, including 

private, public and governmental entities, financial institutions and aggregators, and 

wholesale and retail customers. The WSPP Agreement as it exists today permits 

sellers of electric energy to charge either an uncapped market-based rate (for public 

utility sellers, they must have obtained separate market-based rate authorization from 

the Commission to do this), or an “up to” cost-based ceiling rate. For sellers without 

market-based rate authority, the cost-based ceiling rate under the WSPP Agreement 

consists of an individual seller’s forecasted incremental cost plus an “up-to” demand 

charge based on the costs of a sub-set (eighteen sellers) of the original WSPP 

Agreement members, not necessarily the costs of any one seller. The up-to demand 

charge is based on the average fixed costs of the generating facilities of that sub-set 

of WSPP Agreement members; it was designed to reflect the costs of a hypothetical 

 717 WSPP, 55 FERC ¶ 61,099 (1991). Prior to 1991, the WSPP Agreement was 

used for three years on an experimental basis. See Western Sys. Power Pool, 50 FERC 

¶ 61,339 (1990) (extending the initial two-year period for an additional year). 
Docket No. RM04-7-000 376 

average utility member in 1989. The only limitations are: (1) that the trades by 

Commission-regulated public utilities must be short-term (lasting one year or less), 

and (2) that they be priced at or below the ceilings for sellers without market-based 

rate authority. 

670. In a number of recent orders, the Commission accepted the use of the WSPP 

Agreement as a mitigation measure subject to the outcome of the instant proceeding 

and any determinations that the Commission makes regarding mitigation in this 

proceeding. In those cases, we explained that the WSPP Agreement contains a 

Commission-approved cost-based rate schedule that has been found to be just and 

reasonable. Further, we noted that parties to the WSPP Agreement have “the option 

of transacting under the WSPP Agreement and thus can make sales under the WSPP 

Agreement without any further authorization from the Commission.”718 

671. Though the Commission has allowed sellers to charge flexible cost-based 

ceiling rates that are not necessarily based on a particular seller’s own costs (such as 

the WSPP Agreement ceiling rate), we are concerned that the evolution and use of the 

WSPP Agreement ceiling rate and the evolution of competitive markets have resulted 

in circumstances in which the WSPP rate may no longer be just and reasonable for 

 718 Westar Energy, Inc., 116 FERC ¶ 61,219 at P 33 (2006); The Empire Dist. 

Elec. Co., 116 FERC ¶ 61,150 at P 12 (2006); Xcel Energy Services, Inc., 117 FERC 

¶ 61,180 at P 49 (2006). However, we note that a review of EQR data indicates that of 65 

sellers reporting contracts under the WSPP Agreement, 56 sellers reported sales under 

that agreement in 2006. Fifty-five of these sellers reported sales that were identified as 

market-based rate sales. 
Docket No. RM04-7-000 377 

sellers that are found to have market power or are presumed to have market power in 

a particular market, i.e., sellers under the WSPP Agreement that do not have marketbased rate authority or that lose or relinquish market-based rate authority. 

672. We recognize that the ceiling rate under the WSPP Agreement has been found 

to be a just and reasonable cost-based rate by this Commission as well as by the U.S. 

Court of Appeals for the D.C. Circuit,719 and that it has been in use for over 15 years 

by sellers irrespective of whether they have market power. Nevertheless, the WSPP 

Agreement ceiling rate contains extensive pricing flexibility and relies in part on 

market forces to set the rate at or below the demand charge cap, and we believe he 

WSPP Agreement rate needs to be revisited in light of its widespread use and changes 

in electric markets since 1991. When originally approved by the Commission in 

1991, there were 40 members under the WSPP Agreement; now there are over 300 

members. Additionally, the WSPP Agreement is now used by entities not only in the 

Western Interconnection, but throughout the continental United States. Further, the 

demand charge component of the WSPP Agreement ceiling rate is based on the costs 

of only 18 of the original WSPP members in 1991 (utilizing 1989 data) and does not 

reflect the costs of the members that joined the agreement since 1991. 

673. For these reasons, concurrently with issuance of this Final Rule, we are 

instituting in Docket No. EL07-69-000 a proceeding under section 206 of the FPA to 

 719 Environmental Action and Consumer Federation of America v. FERC, 

996 F.2d 401 (D.C. Cir. 1993). 
Docket No. RM04-7-000 378 

investigate whether the WSPP Agreement ceiling rate is just and reasonable for a 

public utility seller in a market in which such seller has been found to have market 

power or is presumed to have market power. All interested entities will have an 

opportunity to address this issue through a paper hearing. 

674. As noted above, the Commission has accepted, subject to the outcome of this 

rulemaking proceeding, the use of the WSPP Agreement ceiling rate as mitigation by 

a number of sellers. These sellers may continue to use the WSPP Agreement ceiling 

rate as mitigation, subject to refund (and the refund effective date established in 

Docket No. EL07-69-000) and subject to the outcome of the section 206 proceeding. 

Market-Based Proposals for Mitigation

Comments

675. Commenters are generally concerned that where the Commission’s current 

mitigation approach focuses on a seller’s own cost of service, it imposes cost-based 

rates on a mitigated utility in the home control area regardless of whether the prices 

of alternative sources of supply in the mitigated market exceed the mitigated seller’s 

cost-based rates.720 Rather than relying on cost-based price caps that may bear no 

relationship to market conditions, several commenters support allowing mitigation 

methods based on transparent competitive market prices in regional markets.721 

 720 See, e.g., Xcel at 7-9. 

721 Duke at 3, 13-14; Drs. Broehm and Fox-Penner at 16-17; MidAmerican at 12-

13; E.ON U.S. at 10-12; Southern at 65, n. 104, 66; Ameren at 14; Xcel at 8-9; 

 (continued...) 

 
Docket No. RM04-7-000 379 

Commenters suggest various market indicia that the Commission could use as price 

proxies in market-based mitigation alternatives.722 

676. Because different markets may be uncompetitive for different reasons, and the 

same mitigation measure is not necessarily equivalent in all situations, several 

commenters urge the Commission to consider more tailored, market-based rate 

approaches to mitigation on a case-by-case basis.723 MidAmerican suggests that any 

specific index chosen could be reflected in the tariff of mitigated sellers (for sales up 

to one year) or in agreements filed with the Commission (for sales of one year or 

longer).724

 

PNM/Tucson at 12,14; EEI at 26-29; Dr. Pace at 23; PPL reply comments at 17-18; and 

Oregon Commission reply comments at 2-3. 

722 For example, Duke (prices from an adjoining LMP market that are transparent 

and contemporaneously available); MidAmerican (reference prices for the region or from 

neighboring LMP markets, published index prices reported by public subscription 

services, or prices capped at levels reported in the Commission’s Electric Quarterly 

Report for sales in neighboring markets); Xcel (proximate price indexes where available, 

the WSPP Agreement, a utility’s own sales in areas where it does not possess market 

power, competitive solicitations with a sufficient amount of bidders or opportunity cost 

pricing); EEI (published index prices at liquid regional trading hubs or LMP nodal prices 

for adjacent Day 2 RTOs); the Oregon Commission (price at a frequently traded energy 

hub or an LMP determined by an adjoining RTO would be appropriate price indexes). If 

an appropriate and valid price index is not available, the Oregon Commission would 

require the seller to make mitigated sales at cost-based rates. 

723 MidAmerican at 14; NYISO at 8; Duke at 13-14; Drs. Broehm and Fox-Penner 

at 15. 

724 MidAmerican reply comments at 5. 
Docket No. RM04-7-000 380 

677. Duke explains that market-based rate mitigation alternatives could be applied 

to mitigated sellers whose control area markets are adjacent to a Commissionapproved market. If the proxy prices are established in markets that the Commission 

has found to be functionally competitive, Duke contends that the price will by 

definition be just and reasonable. Duke submits that the Commission approved 

similar mitigation for sales by the LG&E Parties sinking in the Big Rivers control 

area capped at the Midwest ISO’s LMP at the Big Rivers control area interface.725 

678. E.ON U.S. argues that allowing index-based price caps as a mitigation option 

is just and reasonable because such sales are either subject to the market monitoring 

provisions of an RTO, or in the case of price indices, are structured according to the 

Commission’s instructions with regard to market price reporting. They add that 

index-based price caps are efficient because: (a) they can be used to address pricing 

requirements for varying time commitments; (b) they meet the Commission’s criteria 

for accurate and timely reporting; and (c) they do not require the administrative 

overhead and complexity associated with calculating and reporting cost-based 

rates.726

679. MidAmerican and the Oregon Commission submit that using an appropriate 

price index as a proxy could ensure that prices are derived from competitive 

 725 Duke at 14 (citing LG&E Energy Marketing Inc., 113 FERC ¶ 61,229 at P 30 

(2005)). 

726 E.ON U.S. at 12. 
Docket No. RM04-7-000 381 

conditions and do not reflect the market power of the mitigated seller (or, for that 

matter, of any seller).727 Duke, MidAmerican, and the Oregon Commission reason 

that allowing a published price index would effectively make the mitigated seller a 

price taker rather than a price setter.728 E.ON U.S., PNM/Tucson, and Indianapolis 

P&L also suggest that requiring cost-based mitigation may result in sellers giving up 

their market-based rate authority in mitigated areas due to the significant time and 

expense of developing a cost-of-service filing.729 Where sellers opt to give up 

market-based rate authority, these commenters conclude that buyers will be harmed 

by a reduction in the number of competitive options available to them in mitigated 

markets. 

680. MidAmerican claims that using price indices would (a) eliminate the incentive 

for round-trip transactions; (b) alleviate the need to determine whether the need for 

mitigation should be based on the point of delivery, the sink location, or some other 

determinant; and (c) reduce contention over how to calculate cost-based rates.730 EEI 

and the Oregon Commission conclude that allowing mitigated rates to be based on 

competitive market prices would: (1) maintain supply choices for captive customers 

 727 MidAmerican at 13; Oregon Commission reply comments at 2; see also PPL 

reply comments at 17-18. 

728 Duke at 14; MidAmerican at 13-14; Oregon Commission reply comments at 2. 

729 Indianapolis P&L at 11; E.ON U.S. at 11; PNM/Tucson at 13. 

730 MidAmerican reply comments at 3-4, 20. 
Docket No. RM04-7-000 382 

by encouraging mitigated suppliers to participate actively in the mitigated markets; 

(2) avoid the unintended consequences of cost-based rate mitigation (e.g., incentive to 

sell outside the mitigated region); (3) help to ensure that buyers continue to receive 

accurate price signals and not inappropriately lean on cost-based rates in times of 

peak demand; and (4) be consistent with the Commission’s goal of encouraging 

competitive market solutions.731 

681. APPA/TAPS reject this reasoning, arguing that a dominant supplier has other 

incentives not to sell to captive customers beyond just the availability of a higher 

price elsewhere, including the desire to disadvantage competing suppliers within its 

control area. Therefore, even if a market price index is used as a mitigation 

alternative, APPA/TAPS submit that a “must offer” obligation remains necessary.732 

682. According to some commenters, capping mitigated prices at the levels of 

relevant price indices would also reduce the market distortions that exist under dual 

price systems.733 E.ON U.S., Xcel, PNM/Tucson, Duke, EEI, MidAmerican and the 

Oregon Commission generally contend that allowing market-based rate mitigation 

methods would reduce the incentive, arising from price disparities in dual-price 

systems (a regime where a seller has market-based rate authority in some markets but 

 731 EEI reply comments at 12; Oregon Commission reply comments at 3. 

732 APPA/TAPS reply comments at 15. 

733 PNM/Tuscon at 13-14; MidAmerican at 14; EEI at 26; see also, CAISO at 6. 
Docket No. RM04-7-000 383 

is limited to cost-based sales in other market(s)), for mitigated sellers to seek marketbased rate sales beyond the mitigated market.734 This, in turn, would obviate the 

need for a “must offer” requirement or mitigation of sales outside the mitigated 

region. Somewhat similarly, EEI warns that if the Commission implements a “must 

offer” obligation, suppliers may not apply for market-based rate authorization in 

markets where they are likely to fail any of the market power screens.735 

683. Some commenters add that the Commission surrenders nothing in terms of 

consumer protection by allowing market-based price caps as a mitigation option. In 

their view, permitting such mitigation will likely increase the willingness of sellers to 

engage in market transactions in mitigated areas and result in buyers paying no more 

than what is already recognized as a just and reasonable competitive market price.736

684. MidAmerican, E.ON U.S., PNM/Tucson, and Indianapolis P&L all note that 

the Commission (1) has found that inter-affiliate sales are permissible at RTO price 

indices, and (2) proposes in the NOPR (at P 113-14) to extend this policy to market 

indices satisfying the November 19 Price Index Order.737 These commenters argue 

that if sales at a meaningful market index are per se just and reasonable for affiliate 

 734 E.ON U.S. at 10-11; Xcel at 8-9; PNM/Tucson at 13; Duke at 9; EEI at 28; 

MidAmerican at 14; Oregon Commission reply comments at 3. 

735 EEI reply comments at 18. 

736 Duke at 14; APPA/TAPS at 64; MidAmerican at 13. 

737 MidAmerican at 13; E.ON U.S. at 11; PNM/Tucson at 12; Indianapolis P&L at 

7. 
Docket No. RM04-7-000 384 

transactions, there is no reason why such sales are not per se just and reasonable for 

non-affiliate transactions.738 PNM/Tucson add that even in regions without 

organized RTO/ISO markets, sellers with market-based rate authority have 

established highly liquid trading hubs (e.g., Four Corners or Palo Verde) that also 

produce market prices that are readily available, transparent, can serve as an 

appropriate proxy, and satisfy the Commission’s index pricing standards.739

685. Another commenter supports the adoption of more market-oriented approaches 

to mitigation. For daily and hourly transactions, this commenter asks the 

Commission to be receptive to rates tied to an acceptable price index at a liquid 

trading point. For long term transactions, rather than focusing on average embedded 

costs, which this commenter claims are likely to be a poor proxy for market rates, the 

Commission should consider capacity and associated energy rates that provide a 

competitive rate of return on new generation units built in the region. Where 

transmission constraints bind only occasionally and the seller does not have market 

power absent such constraints, this commenter reasons that it is rational to only apply 

mitigated rates to sales made at the time such constraints are binding. Similarly, 

where indicative screens or the DPT analysis point to the existence of a market power 

 738 E.ON U.S. at 11; Indianapolis P&L at 11; MidAmerican reply comments at 5. 

739 PNM/Tucson at 13. 
Docket No. RM04-7-000 385 

problem in a well-defined seasonal or peak period, this commenter favors confining 

rate mitigation to sales made in the relevant market during that period.740

686. APPA/TAPS acknowledge that cost-based rates do not achieve competitive 

wholesale markets.741 Ideally, wholesale customers should have a meaningful choice 

of suppliers whose costs are disciplined by competitive forces and remedies focused 

on fostering structurally competitive markets will help to ensure that future 

consumers have choices. Until such structural remedies are fully implemented, 

APPA/TAPS maintain that mitigated sellers should sell at cost-based rates.742 

687. APPA/TAPS and Morgan Stanley do not categorically oppose the use of price 

indices as a mitigation alternative that could be justified with substantial evidence, 

but urge caution and ask the Commission not to assume that the index relied upon is a 

just and reasonable, and comparable, proxy for the mitigated market.743 Morgan 

Stanley explains that given the price variation among transmission nodes, it is not 

possible to generically find that any one index-based price would be an adequate 

proxy for another node(s). APPA/TAPS explain that a thinly traded market, or one 

separated by transmission constraints, could create volatility or arbitrage possibilities 

 740 Dr. Pace at 23-24. 

741 APPA/TAPS at 48. 

742 Id. at 48-49. 

743 APPA/TAPS reply comments at 13; Morgan Stanley reply comments at 2, 8-

10. 
Docket No. RM04-7-000 386 

that would leave captive customers worse-off than a cost-based mitigated rate. They 

add that appropriate price proxies may not be available for all products, and that 

RTO-administered real-time or day-ahead markets would not generally provide 

acceptable proxies for price mitigation in markets for weekly, monthly or annual 

sales. APPA/TAPS also note that the Southeast has no real liquid trading hubs.744 

While urging the Commission to continue requiring cost-based mitigation, Morgan 

Stanley does not oppose allowing mitigated sellers to justify an index-based 

mitigation approach as appropriate for their specific circumstances. According to 

Morgan Stanley, such an approach may prove justifiable where a viable, liquid index 

exists within or adjacent to the territory in which a finding of market power exists.745 

688. NRECA likewise is concerned that there is no assurance that (1) the external 

market price would be a competitive price; (2) external markets are a reasonable 

proxy for non-existent competitive market prices in the mitigated market; and (3) 

there are sufficient monitoring and enforcement mechanisms to ensure these first two 

conditions are continually being met.746 Unless these three concerns are addressed, 

NRECA asserts that the Commission may not lawfully rely on an external market 

price as a proxy in a mitigated market, particularly where the FPA is clear that the 

 744 APPA/TAPS reply comments at 14-15. 

745 Morgan Stanley reply comments at 9-10. 

746 NRECA reply comments at 31-33. 
Docket No. RM04-7-000 387 

Commission may not approve market-based rates absent “empirical proof” that 

“existing competition would ensure that the actual price is just and reasonable.”747 

Moreover, where “Congress could not have assumed that ‘just and reasonable’ rates 

could conclusively be determined by reference to market price,”748 NRECA argues 

that the Commission may not rely exclusively on market prices but rather must have a 

regulatory “escape hatch” or “safeguard” mechanism749 if actual competitive 

pressures alone cannot keep rates just and reasonable. NRECA, similar to 

APPA/TAPS, is concerned that proxy indices are irrelevant oftentimes because they 

are too far removed from the mitigated market to be adequately representative. While 

NRECA admits that such indices may be adequate in some instances, it takes the 

position that, at most, the Commission could entertain proxy index proposals from 

mitigated sellers on a case-by-case basis.750 

689. The Carolina Agencies are similarly concerned that market-based indices 

based on LMPs from adjacent markets in many hours will reflect transmission 

congestion that may not be representative of congestion patterns in the mitigated 

market, and therefore must not be deemed a just and reasonable proxy for an entirely 

 747 Id. at 32 (quoting Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486, 

1510 (D.C. Cir. 1984)). 

748 Id. (quoting FPC v. Texaco, 417 U.S. 380, 399 (1974)). 

749 Id. (quoting Louisiana Energy & Power Auth. v. FERC, 141 F.3d 364, 370-71 

(D.C. Cir. 1998)). 

750 Id. at 33. 
Docket No. RM04-7-000 388 

different market. Moreover, LSEs in RTOs with Day 2 markets have some ability to 

limit their exposure to LMP spikes through the use of hedging tools (i.e. Auction 

Revenue Rights and Financial Transmission Rights). However, the Carolina 

Agencies argue, LSEs in mitigated markets would face these LMP gyrations from 

adjacent markets as proxy prices without any hedging protections. These agencies 

further claim that there are no other sources of non-LMP price information in their 

region that are reliable enough to serve as proxy prices.751 In the Carolina Agencies’ 

view, because price information from non-LMP markets is mostly illiquid, nontransparent and easily manipulated due to the low volume of transactions, such 

reference prices are unlikely to be an accurate and reasonable proxy for competitive 

prices in the mitigated control area. They state that, as the Commission has reported, 

“some electric power markets are almost entirely opaque both to regulators and to 

price takers. In these markets (such as electricity in the Southeast), so little 

information is available that price indices either do not develop or have little value in 

price discovery.”752 The Carolina Agencies also wonder how a meaningful proxy 

could be determined for a market price in a control area where a dominant supplier 

has market power.753

 751 Carolina Agencies reply comments at 2-3, 10, 14-18. 

752 Id. at 18, n. 11 (citing Federal Energy Regulatory Commission – Office of 

Market Oversight and Investigations, 2004 State of the Market Report (June 2005)). 

753 Id. at 15, n. 9. 
Docket No. RM04-7-000 389 

690. The Carolina Agencies and NASUCA oppose providing mitigated utilities 

with the option of filing cost-based rates or choosing the market rates of a 

neighboring control area.754 NASUCA adds that commenters articulate no legal 

theory by which mitigated sellers should be allowed any market rate or how the 

Commission has power to grant any waiver of the rate filing and review requirements 

of section 205 of the FPA.755 Rather than allowing mitigated rates to be determined 

by market prices in adjacent market areas, NASUCA urges the Commission to deny 

any form of market rates to mitigated utilities and require such suppliers to comply 

with section 205 of the FPA by filing their rates subject to the traditional review to 

ensure just and reasonable rates.756

691. If the presence of transmission constraints in a dominant transmission 

provider’s control area allow it to charge supra-competitive market-based rates there, 

APPA/TAPS submit that the Commission must require these constraints to be 

addressed.757 These commenters ask the Commission to impose mitigating 

conditions on market-based rate authority to increase access to existing transmission 

facilities as well as to expand their transmission access through rolled-in upgrades. 

 754 Id. at 18-19; NASUCA reply comments at 18-19. 

755 NASUCA reply comments at 18-19. 

756 Id. 

757 APPA/TAPS at 50. 
Docket No. RM04-7-000 390 

For example, APPA/TAPS,758 and the Carolina Agencies759 suggest that the 

Commission could condition the market-based rate authority of a mitigated seller on 

the demonstrated willingness of vertically-integrated transmission owners to jointly 

plan and construct new generation projects with market participants, and/or to 

participate with them in collaborative, open regional transmission planning processes. 

692. Xcel responds that, aside from such a requirement being impractical, the 

Commission has no legal authority to impose a condition requiring joint planning of 

new facilities nor jurisdiction over the construction of new facilities.760 Xcel states 

that the FPA does not provide the Commission with certificate jurisdiction over 

generation facilities or otherwise, nor does the Commission have the authority to 

order utilities to enter into such a contract.761

Commission Determination

693. The Commission continues to believe that proposed alternative methods of 

mitigation should be cost-based. However, as discussed below, while we will not 

allow the use of alternative “market-based” mitigation on a generic basis, we will 

 758 Id. at 40-41, 49, 50-51. 

759 Carolina Agencies at 12, n.10. 

760 Xcel reply comments at 9-10. 

761 Id. at 10. Duke likewise opposes any proposal granting an automatic 

entitlement to participate in new generation planned by the mitigated utility, arguing that 

the commercial terms of any joint ownership arrangements must be negotiated by the 

parties. Duke reply comments at 11; see also, EEI reply comments at 8-9. 
Docket No. RM04-7-000 391 

permit sellers to submit alternative non-cost-based mitigation proposals for 

Commission consideration on a case-by-case basis. 

694. A variety of suggestions have been made such as basing mitigated prices on: 

prices from an adjoining LMP market that are transparent and contemporaneously 

available; published index prices; prices capped at levels reported in the Electric 

Quarterly Reports for sales in neighboring markets; a utility’s own sales in areas 

where it does not possess market power; and competitive solicitations with a 

sufficient amount of bidders or opportunity cost pricing. However, while some 

commenters suggest that market-based rate mitigation may cure several of the costbased mitigation regime’s alleged ailments, they fail to convincingly address a 

fundamental concern with such mitigation. That is, why a market-based price from 

one market would be a relevant and appropriate proxy price to mitigate market power 

found in a different market. 

695. Specifically, we reject Duke’s argument that we should allow market-based 

rate mitigation alternatives to be used by mitigated sellers whose control area markets 

are adjacent to a Commission-approved market because if the proxy prices are 

established in markets that the Commission has found to be functionally competitive, 

the price will by definition be just and reasonable. Although Duke is correct that a 

price in a market may be presumed to be just and reasonable in the market in which it 

has been approved, Duke’s claim fails because that price has not been shown to be 
Docket No. RM04-7-000 392 

just and reasonable for other markets with differing competitive circumstances.762 

Duke’s argument also fails to recognize that the Commission does not certify markets 

as competitive; rather, we make determinations on whether individual sellers in a 

market have market power. In addition, contrary to Duke’s view, the Commission’s 

acceptance of proposed mitigation in the Big Rivers control area does not support 

Duke’s proposal in this regard. In LG&E Energy Marketing Inc.,

763 the Commission 

accepted a proposal that capped - at the Midwest ISO’s LMP price at the Big Rivers 

control area interface - all market-based sales by LG&E sinking in the Big Rivers 

control area not sold pursuant to contractual agreements already in existence. 

However, Duke fails to point out that, when LG&E proposed to mitigate its sales into 

the Big Rivers control area, LG&E was a member of the Midwest ISO and, 

accordingly, capping LG&E’s sales price at the Midwest ISO LMP at the Big Rivers 

interface was appropriate. 

696. Commenters raise many reasons why allowing the use of an index could be 

beneficial such as: using an appropriate price index as a proxy could ensure that 

prices are derived from competitive conditions and do not reflect the market power of 

the mitigated seller; allowing a published price index would effectively make the 

 762 E.ON U.S.’ proposal that the use of index-based price caps subject to the 

market monitoring provisions of an RTO is a just and reasonable mitigation option 

equally fails to address whether the index-based price is relevant to the market in which 

the sale is made. 

763 113 FERC ¶ 61,229 (2005). 
Docket No. RM04-7-000 393 

mitigated seller a price taker rather than a price setter; use of an index price would 

eliminate the incentive for round-trip transactions and alleviate the need to determine 

whether the need for mitigation should be based on the point of delivery, the sink 

location, or some other determinant; would maintain supply choices for captive 

customers by encouraging mitigated suppliers to participate actively in the mitigated 

markets; would help to ensure that buyers continue to receive accurate price signals 

and not inappropriately lean on cost-based rates in times of peak demand; and, would 

be consistent with the Commission’s goal of encouraging competitive market 

solutions. 

697. However, we agree with Morgan Stanley and others that, given price 

variations among transmission nodes, we should not generically find that one indexbased price is necessarily an adequate proxy for another node. Commenters urging 

the Commission to consider such alternatives on a case-by-case basis acknowledge 

that different markets may be uncompetitive for different reasons.764 While 

commenters speak of “relevant price indexes,” their comments contain little more 

than undeveloped proposals and limited discussion as to how such an index would be 

chosen, and why it would be an appropriate proxy for the mitigated market. For 

example, commenters fail to explain how a proxy price based on existing competition 

from one market with distinct traits such as transmission congestion ensures a just 

 764 MidAmerican at 14; NYISO at 8; Duke at 13-14; Drs. Broehm and Fox-Penner 

at 15. 
Docket No. RM04-7-000 394 

and reasonable price in another market that has its own unique traits and 

circumstances. Deriving prices from competitive conditions, making a mitigated 

seller a price taker rather than a price setter, and reducing market distortions are all 

goals commenters claim market-based mitigation can help achieve. Nonetheless, the 

use of an external market price to establish the just and reasonable price in the 

mitigated market has not yet been shown to be appropriate. 

698. While we will not allow the use of “market-based” mitigation on a generic 

basis, we nevertheless will permit sellers to submit non-cost-based mitigation 

proposals, such as the use of an index or an LMP proxy, for Commission 

consideration on a case-by-case basis based on their particular circumstances. Sellers 

choosing to propose such alternative mitigation will carry the burden of showing why 

and how the proposed index-based price is relevant, appropriate and a just and 

reasonable price for the mitigated market.While several commenters also seek to have 

the Commission make market-based rate authorization of mitigated sellers contingent 

upon their pledging to jointly plan and construct future generation projects with 

market participants, or pursue other structural conditions, they have not justified 

imposing such a burden. For those sellers that are affected with a market power 

concern, we discuss elsewhere in this Final Rule the means by which we will require 

adequate mitigation. Moreover, we believe that we have adequately addressed these 

concerns related to planning in our recent Order No. 890, where we require all 

jurisdictional transmission owners to engage in transmission planning with other 
Docket No. RM04-7-000 395 

market participants. Therefore, we find no reason to mandate a mitigated seller’s 

participation in such arrangements. 

2. Discounting

Commission Proposal

699. In the NOPR, the Commission explained that a supplier authorized to sell 

under an “up to” cost-based rate has an incentive to discount its sales price when the 

market price in the supplier’s local area is lower than the cost-based ceiling rate. 

During these periods, a rational seller will discount its sales to maximize revenue. In 

the past, the Commission has encouraged discounting as an efficient practice that can 

maximize revenues to reduce the revenue requirements borne by requirements 

customers. 

700. Here, the primary issue is whether a seller can “selectively” discount, i.e., 

offer different prices to different purchasers of the same product during the same time 

period. The Commission invited comment on whether selective discounting should 

be allowed for sellers that are found to have market power or have accepted a 

presumption of market power and are offering power under cost-based rates. If so, 

the Commission sought comment on what mechanisms (reporting or otherwise), if 

any, are necessary to protect against undue discrimination. By contrast, were it to 

forbid selective discounting, the Commission asked for comment on whether it 

should require the utility to post discounts to ensure that they are available to all 

similarly-situated customers. 
Docket No. RM04-7-000 396 

Comments

701. Some commenters favor selective discounting because it provides an 

opportunity to meet competition where necessary to retain and attract business. They 

add that the contracting flexibility afforded by selective discounting allows sellers to 

modify rates and tailor sales based on customer-specific factors such as load 

characteristics and credit ratings. They argue that such flexibility maximizes liquidity 

and available capacity and energy.765 

702. MidAmerican and Indianapolis P&L both state that § 206 of the FPA already 

prohibits undue discrimination and provides well-established procedures for entities 

that have been subjected to undue discrimination.766 Westar notes that the 

Commission’s long-standing policy is to allow selective discounting and asserts that 

discounting to customers who have competitive alternatives is not unduly 

discriminatory. 767 

703. PG&E maintains that it is just and reasonable for a seller to offer a discount 

below its cost-based mitigated rate if the seller will gain other (non-market power) 

 765 See, e.g., Indianapolis P&L at 10; MidAmerican at 15-16; Duke at 10-11; EEI 

at 34; PG&E at 23; Progress Energy at 12. 

766 MidAmerican at 15; Indianapolis P&L at 10. 

767 Westar at 26 (citing Town of Norwood v. FERC, 587 F.2d 1306, 1312 & n.17 

(D.C. Cir. 1978) (rate disparity may be justified by, inter alia, differences in the 

customers’ level of risk aversion and bargaining power)); see Policy for Selective 

Discounting by Natural Gas Pipelines, 111 FERC ¶ 61,309, reh’g denied, 113 FERC ¶ 

61,173 (2005) (affirming Commission’s 16-year policy to allow selective discounting by 

interstate natural gas pipelines when necessary to meet competition). 
Docket No. RM04-7-000 397 

advantages such as repeat customers or lower transaction costs. PG&E also suggests 

that principles of efficiency and competition support providing selective discounts to 

entities with larger needs.768 

704. Duke contends that sales arising from selective discounting spread fixed costs 

over more units of service, thereby reducing the “up to” rate.769 Moreover, without 

the ability to selectively discount, Duke submits that utilities will not have the 

opportunity to compete for many wholesale transactions in the mitigated control 

area.770 

705. Southern asserts that if selective discounting were eliminated, then the 

resulting loss of a low-cost source of supply would harm the customers. In 

Southern’s view, captive customers also lose because of foregone opportunities to 

optimize capacity nominally dedicated to native load service.771 EEI adds that where 

a mitigated seller is already precluded from making market-based rate sales within 

mitigated areas, selective discounting does not give rise to conditions that support the 

potential exercise of market power.772 

 768 PG&E at 23. 

769 Duke at 11. 

770 Id. 

771 Southern at 67. 

772 EEI at 31; see also PG&E at 23. 
Docket No. RM04-7-000 398 

706. Other commenters generally oppose allowing mitigated sellers to selectively 

discount sales. For example, TDU Systems claim that selective discounting is 

unnecessary because a seller subject to cost-based mitigation in its home control area 

would not face competition by definition. They also contend that selective 

discounting would allow mitigated sellers to engage in price discrimination in a noncompetitive market, thereby permitting the seller to exercise market power by 

economically or physically withholding capacity to increase the posited market price. 

Thus, in the TDU Systems’ view, a rule allowing selective discounting would 

effectively grant market-based rate authority in a non-competitive market, in 

contravention of the requirements of the FPA.773 

707. While NC Towns generally encourage discounts to cost-based rates, they 

oppose selective discounting because they do not believe that the size of a load 

should be a factor when determining whether to give a buyer a discount.774

708. APPA/TAPS question why a dominant seller would offer discounts to captive 

customers with no other viable supply options. They add that there is no evidence 

that local, competing generation exists or that there is available transmission capacity 

that could support significant imports. In order to avoid discrimination, APPA/TAPS 

advocate requiring a mitigated supplier to offer captive customers any discounts that 

 773 TDU Systems at 19-21. 

774 NC Towns at 5. 
Docket No. RM04-7-000 399 

it offers to other purchasers.775 Factors such as a customer’s capacity factor, credit 

rating or fuel costs may justify adjustments to seller-specific cost-based rates, but 

such factors, argue APPA/TAPS, should be reflected in the seller’s cost-based rates 

rather than through selective discounting.776 

709. If selective discounting is permitted, TDU Systems and NRECA urge the 

Commission to require sellers to file reports of the discounts offered, and encourage 

the Commission to vigorously enforce its market manipulation and affiliate 

transactions rules.777 

710. Suez/Chevron urges the Commission to require selective discounts to be 

contemporaneously offered to similarly-situated buyers, and separately identified in 

the mitigated seller’s EQR.778 To minimize the potential for market power abuse 

when a mitigated seller selectively discounts to an affiliate,779 Suez/Chevron supports 

 775 APPA/TAPS reply comments at 15-16; APPA/TAPS at 44-48. 

776 APPA/TAPS reply comments at 16. 

777 TDU Systems at 24; NRECA at 32. 

778 NC Towns and Morgan Stanley state that any discount the seller wishes to offer 

should be required to be posted with sufficient time for other interested parties to take 

advantage of the offer. NC Towns at 5-6; Morgan Stanley at 7. 

779 Suez/Chevron states that sellers should be required to post any affiliate 

discounts on their OASIS. Suez/Chevron at 13.
Docket No. RM04-7-000 400 

requiring a presumption that nonaffiliated buyers are similarly-situated, and therefore 

entitled to the same discount as a mitigated seller offers to its affiliate.780 

711. PG&E, in contrast, opposes requiring the seller to make discounts available to 

all similarly-situated entities. According to PG&E, it would be difficult to determine 

which entities are in fact similarly-situated because the seller would have to consider 

multiple factors, such as quantity of load, timing, flexibility, credit rating, and 

purchases history.781

712. Ameren disagrees with a posting requirement, arguing that the Commission’s 

requirements for separate filings and advance approval of affiliate power sales 

provide the appropriate oversight and mechanisms necessary to police discounting 

concerns regarding selective discounts favoring affiliates. Ameren concludes that a 

requirement to post discounts is unduly burdensome given that the only discounts of 

concern are in the affiliate sales, which are subject to separate filing requirements.782 

PG&E, in turn, notes that the affiliate restrictions also provide protection against the 

use of selective discounts to benefit affiliates.783

 780 Suez/Chevron at 12-13. 

781 PG&E at 24. 

782 Ameren at 17-18. 

783 PG&E at 23. 
Docket No. RM04-7-000 401 

Commission Determination

713. We will continue our practice of allowing discounting from the default costbased mitigated rates for short- and mid-term sales and will permit selective 

discounting by mitigated sellers provided that the sellers do not use such discounting 

to unduly discriminate or give undue preference. We believe that selective 

discounting that does not constitute undue discrimination can improve liquidity, 

available capacity and energy, and customer supply options. In other words, nondiscriminatory discounting can provide benefits to the market. 

714. APPA/TAPS question why a dominant seller would offer discounts to captive 

customers with no other viable supply options, and the TDU Systems comment that 

selective discounting is unnecessary because a mitigated seller by definition would 

not face competition in its home control area. However, in times when there are 

viable alternatives, a seller under an “up to” cost-based rate has an incentive to 

discount its sales price when the market price in the seller’s mitigated market is lower 

than the cost-based ceiling rate. Allowing a mitigated seller to non-discriminatorily 

discount the rate when there are viable alternatives in the market benefits customers 

by providing more supply options in such instances. 

715. Discounting also can maximize revenue by optimizing capacity nominally 

dedicated to native load service, allowing the supplier to spread fixed costs over more 

units of service. Maximizing revenue in this manner can help reduce the “up to” rate, 

and therefore the revenue requirements borne by captive customers. The 

Commission has previously determined that requiring a mitigated entity to limit sales 
Docket No. RM04-7-000 402 

to its ceiling rates “is at odds with the longstanding policy of allowing ‘up to’ costbased rates.”784 

716. The FPA requires that all rates charged by public utilities for the sale for resale 

of electric energy be “just and reasonable.”785 If a seller’s cost-based rate has been 

found to be just and reasonable by the Commission, it follows that discounted rates 

below such a cost-based rate are also just and reasonable.786 However, a seller may 

not lawfully discount to gain, or profit from, market power advantages. We 

emphasize that section 205 of the FPA prohibits public utilities, in any power sale 

subject to the Commission's jurisdiction, from granting any undue preference or 

advantage to any person787 and also prohibits undue discrimination.788 

717. With regard to comments that the Commission establish a reporting 

mechanism, under the Commission’s existing reporting requirements entities making 

power sales must submit EQRs containing: a summary of the contractual terms and 

conditions in every effective service agreement for all jurisdictional services, 

 784 Duke Power, 113 FERC ¶ 61,192 at P 17 (2005). 

785 16 U.S.C. 824d(a). 

786 Public Service Company of Oklahoma, 54 FERC ¶ 61,021, at 61,032 and fn. 8 

(1991) (“If PSO’s rates set at full cost are reasonable in the presence of market power, it 

follows that PSO’s rates reflecting less than a 100- percent contribution to fixed costs are 

also reasonable in the presence of market power.”). 

787 16 U.S.C. 824d(b). 

788 16 U.S.C. 824e(a). 
Docket No. RM04-7-000 403 

including market-based and cost-based power sales and transmission services; and, 

transaction information for effective short-term (less than one year) and long-term 

(one year or greater) power sales during the most recent calendar quarter.789 Through 

this reporting requirement, the Commission monitors the rates charged by mitigated 

sellers. 

718. Several commenters also seek to have the Commission require selective 

discounts to be posted and contemporaneously offered to similarly-situated buyers. 

Some seek a presumption that nonaffiliated buyers are similarly situated whenever a 

mitigated seller offers an affiliate a discount. The Commission will not require 

mitigated sellers to contemporaneously post in a public forum all discounts provided 

for cost-based sales (i.e., where the sale is made at a price below the maximum up-to 

cost-based rate approved by the Commission in that tariff or rate schedule). 

Proponents of a posting requirement have not justified nor demonstrated how the 

Commission’s EQR requirement fails to provide an adequate means by which to 

monitor such discounts. In addition, many sales are made below the cost-based cap, 

and the commenters’ proposals would place an undue burden on sellers that would be 

required to contemporaneously post rates that the Commission has already deemed to 

be just and reasonable. Accordingly, the Commission will not require the 

 789 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 

(May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (2002). Required data sets for contractual 

and transaction information are described in Attachments B and C of Order No. 2001. 
Docket No. RM04-7-000 404 

contemporaneous posting of discounted cost-based rates. Finally, commenters have 

provided no basis to conclude that nonaffiliated buyers are similarly situated 

whenever a mitigated seller offers an affiliate a discount, and we will not adopt the 

proposed presumption in this regard. Thus, sellers may selectively discount only if 

they do so in a manner that is not unduly discriminatory or preferential. 

719. Further, we agree with MidAmerican that identifying discriminatory selective 

discounting requires fact-specific evaluations. Because individual proceedings are 

the best instrument available to the Commission for such efforts, allegations of undue 

discrimination arising from selective discounting are best addressed on a case-by-case 

basis. 

3. Protecting Mitigated Markets

a. Must Offer 

Commission Proposal

720. Under the Commission’s current mitigation policy, a seller that loses marketbased rate authority in its home control area is limited to charging cost-based rates in 

that control area; however, there is no requirement that the seller offer its available 

power to customers in that home control area. Instead, the seller is free to market all 

of its available power to purchasers outside that control area if it chooses to do so. If, 

for example, market prices outside the mitigated seller’s control area exceed the costbased caps within the mitigated control area, then the seller will, other things being 

equal, have an incentive to sell outside. As noted in the NOPR, wholesale customers 

have argued that default cost-based mitigation of this kind is of little value if a seller 
Docket No. RM04-7-000 405 

can market its excess capacity at market-based rates in other control areas. In the 

NOPR, the Commission sought comment on whether its current policy is appropriate, 

and if not, what further restrictions are needed. The Commission asked whether it 

should adopt a form of “must offer” requirement in mitigated markets to ensure that 

available capacity (i.e., above that needed to serve firm and native load customers) is 

not withheld. If so, the Commission asked if such a “must offer” requirement should 

be limited to sales of a certain period to help ensure that wholesale customers use that 

power to serve their own needs, rather than simply remarketing that power outside the 

control area and profiting790 If it were to adopt such a “must offer” requirement, the 

Commission asked what rules there should be to define the "available" capacity that 

must be offered , in order to avoid case-by-case disputes over this issue. 

Comments

721. Wholesale customers generally support a “must offer” requirement,” stating 

that it is needed to ensure that power is available for purchase in the mitigated market 

and to protect them from incurring higher costs to serve load.791 They argue that the 

 790 In this regard, the Commission asked if there should be an annual open season 

under which the mitigated seller offers its available capacity to local customers for the 

following year at the cost-based ceiling rate and, if customers do not commit to purchase 

that capacity, then the seller would be free to sell the remaining capacity at market-based 

rates where it has authority to do so. 

791 See, e.g., APPA/TAPS at 40-42 (also urging the Commission to apply any 

“must offer” requirement to captive customers in the seller’s transmission service area); 

Carolina Agencies at 10-13; NRECA at 35; Montana Counsel at 19; TDU Systems at 19; 

NC Towns at 6-8 (asking the Commission to require mitigated utilities to serve wholesale 

 (continued...) 

 
Docket No. RM04-7-000 406 

existence of a dual price system (a regime where a seller has market-based rate 

authority in some markets but is limited to cost-based sales in other market(s)) creates 

an incentive for a mitigated seller to sell its power outside of the mitigated market 

whenever market prices in the outside market are above the mitigated seller’s costbased price. They are concerned particularly with the situation where a wholesale 

customer faces few or no alternatives in the mitigated market due to transmission 

constraints. 

722. APPA/TAPS, the Carolina Agencies and NRECA claim that the Commission 

has both the authority and obligation to remedy undue discrimination in wholesale 

sales, which are clearly set forth in sections 205 and 206 of the FPA.792 They 

specifically argue that a “must offer” condition is within the Commission’s authority 

as a remedy for the unjust and unreasonable rates and undue discrimination (refusal 

to sell in the mitigated control area) that are a consequence of the mitigated seller’s 

accumulation of market power.793 Several commenters reason that, similar to 

 

customers in the mitigated control area at long-term system average cost-based rates in 

order to maintain reliability). See also MidAmerican reply comments at 9-12 (arguing 

that the APPA/TAPS and Carolina Agencies proposals suffer from significant policy 

flaws). 

792 APPA/TAPS and Carolina Agencies supplemental comments at 4, 9-18 (citing, 

among others, 16 U.S.C. 824d(a), 824d(b), 824e(a); Associated Gas Distributors v. 

FERC, 824 F.2d 981, 998 (D.C. Cir. 1987)).

793 NRECA reply comments at 41 (citing New York v. FERC, 535 U.S.1, 27 

(2002); Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 683-88 (D.C. 

Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002)); Carolina Agencies at 

 (continued...) 

 
Docket No. RM04-7-000 407 

imposing reporting requirements and other conditions on a grant of market-based rate 

authority, where a seller no longer has market-based rate authority in its home control 

area, the Commission may impose a “must offer” condition on the continuation of 

market-based rate authorization outside a mitigated seller’s control area.794 

APPA/TAPS and the Carolina Agencies argue that the Commission already imposed 

a must-offer obligation on the continued availability of market-based rate authority 

for sellers in the California markets.795 

723. APPA/TAPS also assert that while Order No. 888 rejected a generic obligation 

that would have required sellers to continue wholesale sales past the expiration of the 

 

4-5; Carolina Agencies reply comments at 2. See also Montana Counsel at 19 (citing 

Atlantic Ref. Co. v. Public Serv. Comm’n of N.Y., 360 U.S. 378 (1959) and United Gas 

Improvement Co. v. Callery Properties, Inc., 382 U.S. 223 (1965), two cases in which the 

Montana Counsel claim that the Supreme Court, in recognition of the market power of 

natural gas producers and the public interest provisions of the NGA, “virtually ordered” 

the Commission to exercise its jurisdiction to condition producer natural gas certificates 

and rate orders to limit gas prices); APPA/TAPS and Carolina Agencies supplemental 

comments at 2, 18-30; NRECA supplemental comments at 6-7. 

794APPA/TAPS at 37-38; APPA/TAPS reply comments at 8; Montana Counsel at 

21-22; Carolina Agencies at 4-5; Carolina Agencies reply comments at 3-4. 

795 APPA/TAPS and Carolina Agencies supplemental comments at 27 (citing San 

Diego Gas & Elec. Co. v. Sellers of Energy and Ancillary Servs. Into Mkts. Operated by 

the Cal. Ind. Sys. Operator and the Cal. Power Exch., 93 FERC ¶ 61,294, at 62,010-11 

(2000) (extended-refund-period condition), order on rehearing and clarification, 97 FERC 

61,275, at 62,243-44 (2001), order on rehearing and clarification, 99 FERC ¶ 61,160 

(2002), on rehearing and clarification, 105 FERC ¶ 61,065 (2003), petitions for rev. 

granted in part sub nom. Bonneville Power Auth. v. FERC, 422 F.3d 908 (9th Cir. 2005) 

and Public Utils. Comm’n of Cal. v. FERC, 462 F.3d 1027, 1043 (9th Cir. 2006) 

(discussing must-offer condition)). 
Docket No. RM04-7-000 408 

contract(s) in question in that proceeding, Order No. 888 explained that the 

Commission can impose an obligation to continue service on a case-by-case basis.796 

724. APPA/TAPS and the Carolina Agencies argue that a dominant public utility’s 

physical withholding of generation in the mitigated market in order to make marketbased sales elsewhere results in undue discrimination that the Commission has an 

obligation to remedy. They assert that because wholesale customers in the mitigated 

market are harmed through decreased supply, increased market concentration, and 

increased prices, these customers are exposed to the type of injury against which the 

FPA was designed to protect.797 The Carolina Agencies also maintain that, whether 

or not exporting behavior can be considered economically efficient, such behavior 

results in undue discrimination between (i) the mitigated utility’s native load and (ii) 

LSEs located within the mitigated utility’s home control area.798 This outcome, the 

Carolina Agencies continue, violates the FPA’s mandate that rates be just, reasonable 

 796 APPA/TAPS at 39 (citing Order No. 888 - “we continue to believe that the 

extent to which a customer could demonstrate a reasonable expectation of continued 

service at the existing contract rate (or at a cost-based rate, if that was the customer’s 

expectation) is best addressed on a case-by-case basis”); see also Order No. 888, FERC 

Stats. & Regs. ¶ 31,036, at 31,805 & n.652 (1996) (explaining that although the 

Commission determined “not to impose a regulatory obligation on wholesale 

requirements suppliers to continue to serve their existing requirements customers,” “any 

party claiming to be aggrieved by a utility’s alleged abuse of generation market power 

under a wholesale requirements contract can file a complaint with the Commission under 

Section 206”); see also Montana Counsel at 22. 

797 APPA/TAPS and Carolina Agencies supplemental comments at 19. 

798 Carolina Agencies at 6. 
Docket No. RM04-7-000 409 

and not unduly discriminatory regardless of whether the mitigated utility’s decision to 

export power is a conscious “withholding” for anticompetitive ends.799 APPA/TAPS 

and Carolina Agencies add that vertically-integrated utilities with substantial 

generation in their home control areas frequently have the ability and incentive to 

discriminate against their wholesale customers, who compete against them on both 

the wholesale and retail level.800 

725. APPA/TAPS and Carolina Agencies maintain that undue discrimination 

occurs if a dominant public utility unjustifiably disadvantages a class of market 

participants. They cite case law that the D.C. Circuit found “upholds the power of the 

Commission to subject approval of a set of voluntary transactions to a condition that 

providers open up the class of permissible users.”801 Absent relevant circumstances 

that render two sets of customers differently situated, they assert that it is unduly 

discriminatory for a public utility to sell wholesale power to one set of customers (at 

market-based rates) while denying service to another set (to whom sales, if made, 

 799 Id. at 9. 

800 APPA/TAPS and Carolina Agencies supplemental comments at 16 (citing FPC 

v. Conway Corp., 426 U.S. 271, 278 (1976) to further argue that the Commission can and 

must take account of competition at retail when determining whether such discrimination 

exists.) 

801 Id. at 13 (citing Central Iowa Power Coop. v. FERC, 606 F.2d 1156, 1172 

(D.C. Cir. 1979); and quoting Associated Gas Distributors v. FERC, 824 F.2d 981, 999 

(D.C. Cir. 1987)). APPA/TAPS and Carolina Agencies claim that in this case, a must 

offer requirement would expand the class of buyers of the mitigated seller’s wholesale 

services to include customers from the mitigated utility’s home control area. 
Docket No. RM04-7-000 410 

would need to be priced at cost-based rates). They contend there is no justification 

for disparate treatment in such a case and, therefore, the Commission is obligated 

under sections 205 and 206 to remedy such undue discrimination by either denying or 

conditioning the grant of market-based rate authority outside of the mitigated home 

control area. A “must offer” condition, they claim, would satisfy this obligation by 

preventing undue discrimination.802 

726. APPA/TAPS and the Carolina Agencies further allege that, while it may not 

be unduly discriminatory for a utility to elect to sell to the wholesale customer who 

will pay the highest price, it is unduly discriminatory if the price differential is based 

upon mitigation required as a result of the seller’s market power.803 Where sellers 

claim a right to seek the highest prices, APPA/TAPS and the Carolina Agencies 

counter that this profit maximization impulse can neither justify the exercise of 

market power nor insulate it from correction.804 

727. According to APPA/TAPS and the Carolina Agencies, it is also unduly 

discriminatory for a mitigated seller to make market-based rate sales outside its home 

control area when constraints on that entity’s own transmission system prevent 

embedded customers from similarly accessing those markets as buyers. They argue 

 802 Id. at 15-16. 

803 Id. at 30. 

804 Id. at 31. 
Docket No. RM04-7-000 411 

that refusal to sell wholesale power supplies to embedded LSE customers at fullycompensatory cost-based rates effectively compounds the de facto denial of access by 

exacerbating both the discrimination and the resulting harm.805 According to 

APPA/TAPS and the Carolina Agencies, the claim that mitigated sellers are merely 

engaging in economically efficient behavior ignores the market power that the sellers 

possess.806 They state that when captive customers have few or no supply 

alternatives in the mitigated market and are constrained from accessing opportunities 

in the broader market (even with open access tariffs), and the dominant supplier sells 

its excess capacity beyond the mitigated market, the resulting reduction in output in 

the mitigated market is not addressed simply by prohibiting the mitigated seller from 

selling at unmitigated prices in the mitigated region.807 They conclude that it would 

be unjust and unreasonable to permit or facilitate such withholding by allowing 

unconditioned sales at market-based rates outside a mitigated supplier’s home control 

area; this would reserve the benefits of competitive markets exclusively to dominant 

public utility sellers.808

728. A number of commenters claim that a “must offer” requirement is necessary 

due to their lack of viable options in mitigated control areas. For example, 

 805 Id. at 30-31. 

806 APPA/TAPS at 6-7; Carolina Agencies reply comments at 6. 

807 APPA/TAPS reply comments at 6-7. 

808 APPA/TAPS supplemental comments at 30-31. 
Docket No. RM04-7-000 412 

Fayetteville submits that it finds itself without transmission access to make short-term 

energy purchases to displace its higher cost generation.809 Fayetteville contends that 

Progress Energy’s dominant position, as well as Fayetteville’s inability to access 

alternative suppliers due to the inadequacy of Progress Energy’s transmission system, 

gives Progress Energy unmitigated market power.810 

729. The Carolina Agencies add that, while economic efficiency is a worthy goal in 

structurally sound markets where participants have ready and equal access to 

meaningful choices, the idea of economic efficiency cannot justify a mitigated 

supplier’s behavior in a control area where its market power arises from import 

limitations or other factors that deprive captive LSEs of viable options. Nor can, they 

claim, the goal of economic efficiency trump the Commission’s clear duty to protect 

customers by ensuring that rates are just, reasonable, and not unduly 

discriminatory.811 

730. The Carolina Agencies dispute the claim that there is no need for a “must 

offer” requirement given the Commission’s authority to penalize market 

manipulation. They question whether refusal to sell in the mitigated market would be 

 809 Fayetteville reply comments at 5. 

810 Id. at 6. See also Montana Counsel at 15-23 (where market power is found, 

sellers should be required to offer power to meet the requirements of dependent 

customers at cost). 

811 Carolina Agencies reply comments at 9. 
Docket No. RM04-7-000 413 

actionable under the anti-manipulation rules if there is no obligation to offer power to 

embedded LSEs.812

731. NRECA and others ask the Commission to reject the claim that a “must offer” 

requirement would impede a mitigated seller’s ability to fulfill its retail crediting 

obligations.813 NRECA responds that retail customers can sometimes benefit from 

cost-based rates; if competition reduces the market price to a seller’s marginal cost, 

no contribution to fixed costs would be recovered. Commenters note that not all 

utilities are subject to rules requiring the sharing of profits from off-system sales. 814 

NRECA argues that a utility’s authority to make off-system sales at market-based 

rates is a privilege granted by the Commission; if the Commission restricts or 

conditions that privilege, any obligation the public utility has under state law or 

regulation to sell excess energy or capacity is pre-empted by the requirements of 

federal regulation.815 The Carolina Agencies and NRECA add that a “must offer” 

 812 Carolina Agencies reply comments at 10-11. 

813 See, e.g., NRECA reply comments at 37-39; Carolina Agencies at 17 (citing 

April 14 Order, 107 FERC ¶ 61,018 at P 140, 154, where they claim that the Commission 

rejected arguments that cost-based mitigation rates adversely affect retail rates, because 

such rates provide for the recovery of the mitigated utility’s longer-term costs, and 

because the adverse impact claims were “unsupported and speculative.”); Fayetteville 

reply comments at 7, 9-10. 

814 NRECA reply comments at 38; Carolina Agencies at 8. 

815 NRECA reply comments at 38-39 (citing Entergy La., Inc., v. La. Pub. Serv. 

Comm’n, 539 U.S. 39 (2003); Miss. Power & Light Co. v. Mississippi ex rel. Moore, 487 

U. S. 354 (1988); Nantahala Power & Light Co. v. Thornburg, 476 U. S. 953 (1986)); see 

 (continued...) 

 
Docket No. RM04-7-000 414 

requirement would serve the intended purpose of the Commission’s mitigation 

policy, which is to protect wholesale customers from the exercise of actual and 

potential market power, not to preserve a utility’s ability to reduce retail rates nor its 

ability to engage in a certain volume of off-system power sales.816

732. NRECA, APPA/TAPS and the Carolina Agencies all set forth proposals in 

their comments for implementing a “must offer” requirement.817 NRECA suggests 

requiring a mitigated seller to hold an annual open season to offer long-term service 

(one year or more), as well as requiring a mitigated seller to offer shorter-term 

capacity and energy.818 While not favoring an annual open season, APPA/TAPS and 

the Carolina Agencies each propose “must-offer” parameters to govern short- and 

long-term sales.819 For both short- and long-term sales, the Carolina Agencies would 

offer captive customers an option between (1) locking-in their price at the mitigated 

utility’s embedded cost rates or (2) agreeing to have their charges determined through 

 

also Carolina Agencies reply comments at 7-8 (where a utility is satisfying a 

countervailing regulatory mandate (such as a “must offer” obligation, it cannot be held to 

be violating the cost minimization duty)). 

816 Carolina Agencies at 17; Carolina Agencies reply comments at 7-8; NRECA 

reply comments at 35. 

817 NRECA at 35; APPA/TAPS at 40-42; Carolina Agencies at 10-13. 

818 NRECA at 35-36. 

819 APPA/TAPS at 40-42; Carolina Agencies at 10-13. 
Docket No. RM04-7-000 415 

an annually updated formula rate that reflects the mitigated utility’s actual systemwide average costs.820 The APPA/TAPS proposal also includes an obligation to offer 

captive customers participation on proposed generation projects.821 Both 

APPA/TAPS and the Carolina Agencies would limit any “must-offer” to loads 

actually located in the mitigated control area. 

733. NRECA also proposes two alternatives to a “must offer” requirement. First, 

NRECA suggests that the Commission give captive wholesale customers a right of 

first refusal to purchase at a market price energy or capacity that the mitigated seller 

proposes to sell outside the mitigated market.822 The weakness of this approach, 

NRECA acknowledges, is that it would allow the mitigated seller to charge wholesale 

customers a supra-competitive price in the mitigated market given that the marketbased rate outside the control area would be higher than the cost-based rate in the 

seller’s control area. 823

 820 Carolina Agencies at 12-13. 

821 APPA/TAPS at 41. 

822 NRECA reply comments at 36-37. 

823 NRECA at 36-37. MidAmerican disagrees, arguing that market-based prices 

are not by definition always higher than cost-based prices in the mitigated region. 

Rather, the Commission has encouraged open access transmission and market 

competition because economically efficient market-based rates can be lower than costbased rates. At the same time, where a price index at a trading hub may be lower than the 

seller’s incremental cost, MidAmerican argues that a seller should never be required to 

sell at rates below its incremental cost. MidAmerican reply comments at 21. 
Docket No. RM04-7-000 416 

734. NRECA also suggests as an alternative an enforceable commitment to provide 

sufficient additional transmission import capacity to mitigate the generation market 

power. It states that such a commitment could be implemented by re-dispatching 

resources, relinquishing transmission reservations, or physically upgrading the 

transmission grid. This would allow additional suppliers to make sales in the 

mitigated region, thereby mitigating the seller’s generation market power. NRECA 

contends that this approach would directly address the larger issue of the need to 

eliminate transmission bottlenecks and load pockets that give rise to generation 

market power.824 

735. The Carolina Agencies also propose that mitigated utilities be required to 

investigate and report on transmission expansion or other actions that could remove 

structural impediments causing market power. The Carolina Agencies claim that 

such a requirement is consistent with the Commission’s affirmative duty to remedy 

undue discrimination, an area in which the Commission has broad authority to craft 

remedies.825

736. Other commenters argue against imposition of a “must offer” requirement, 

stating that it would encourage inefficiencies, undermine competition, discourage 

investment, and perpetuate market power. They also assert that such a requirement 

 824 NRECA at 37. 

825 Carolina Agencies at 16 (citing the OATT Reform NOPR at P 210 and n.203). 
Docket No. RM04-7-000 417 

goes beyond any cost-of-service requirement that the Commission has ever 

adopted.826 They question the need for a “must offer” requirement, claiming that 

existing Commission statutory authority, regulations, and enforcement mechanisms 

already sufficiently guard against the market power abuse and market manipulation 

concerns that “must offer” proponents claim such a provision is needed to prevent.827 

737. EEI and Progress Energy claim that when the Commission establishes a costbased rate in a mitigated market, it ensures that the rate meets the just and reasonable 

and not unduly discriminatory requirements of sections 205 and 206 of the FPA, and 

thus there is no further Commission action that is required to mitigate the indicated 

market power.828

738. Several commenters that argue against imposition of a “must offer” 

requirement state that wholesale customers have not presented sufficient evidence to 

justify the generic imposition of such a requirement. They state that there have been 

no specific instances cited where a wholesale customer in a mitigated market was 

unable to obtain service, much less evidence that such instances are commonplace. 

 826 See, e.g., Xcel at 5; Progress Energy reply comments at 5. APPA/TAPS and 

NRECA respond that as long as the rate is cost-compensatory, and therefore just and 

reasonable, it provides an adequate return and the mitigated supplier is not disadvantaged 

by making such sale. APPA/TAPS reply comments at 9; NRECA reply comments at 31, 

35, 38. 

827 See, e.g., EEI at 36; Progress Energy at 17. 

828 EEI at 37; Progress Energy at 13.
Docket No. RM04-7-000 418 

739. Duke/Progress Energy argue that the Commission must make a finding that 

rates or practices are unjust, unreasonable, or unduly discriminatory as a predicate to 

taking action, and that in the case of a generic rulemaking, “the Commission ‘cannot 

rely solely on “unsupported or abstract allegations.”’”829 They cite National Fuel Gas 

Supply Corp. v. FERC,830 where the D.C. Circuit, describing Tenneco Gas v. 

FERC,

831 stated “[t]he court [in Tenneco] ‘upheld Order 497 in relevant part because 

FERC presented an adequate justification – by advancing both (i) a plausible 

theoretical threat of anti-competitive information-sharing between pipelines and their 

marketing affiliates and (ii) vast record evidence of abuse.’”832 They note that the 

D.C. Circuit contrasted Tenneco with Order No. 2004 (at issue in National Fuel), 

where “‘FERC has cited no complaints and provided zero evidence of actual abuse 

between pipelines and their non-marketing affiliates.’” They assert that the D.C. 

Circuit concluded that “‘[p]rofessing that an order ameliorates a real industry 

problem but then citing no evidence demonstrating that there is in fact an industry 

problem is not reasoned decisionmaking.’” 833

 829 Duke/Progress Energy supplemental coments at 21 (quoting Transmission 

Access Policy Study Group v. FERC, 225 F.3d 667, 688 (D.C. Cir. 2000) (TAPS)). 

830 468 F.3d 831, 840 (D.C. Cir. 2006) (National Fuel). 

831 969 F.2d 1187 (D.C. Cir. 1992) (Tenneco). 

832 Duke/Progress Energy supplemental comments at 22 (quoting National Fuel, 

468 F.3d at 840). 

833 National Fuel, 468 F.3d at 843-44. 
Docket No. RM04-7-000 419 

740. According to Duke/Progress Energy, the commenters favoring a “must offer” 

requirement “have presented no evidence whatsoever to support the conclusion that 

any systemic discrimination is occurring or that any party is suffering any actual 

harm under the discrimination theory they have posited.”834 Duke/Progress Energy 

offer several examples where they have sold power to LSEs within their control areas 

after the Commission imposed cost-based mitigation for those sales as evidence that 

there is no basis for expecting mitigated utilities to abandon long-standing customers 

and “decades of intersystem coordination and mutual assistance, whereby utilities 

take whatever measures are possible . . . to help their neighbors maintain 

reliability.”835

741. A number of commenters assert that the Commission’s statutory authority to 

require wholesale sales under §§ 202(b) and 202(c) of the FPA is limited and cannot 

justify the imposition of a “must offer” requirement in this context.836 Southern 

explains that the Commission has forced power sales by a jurisdictional public utility 

to wholesale customers under § 202(b) of the FPA only if such customers have 

 834 Duke/Progress Energy supplemental comments at 23 (citing TAPS, 225 F.3d at 

688, (emphasis in original)); see also Xcel reply comments at 6-7 (parties havenot 

provided any supporting rationale that would justify a “must offer” requirement over 

other potential purchasers); EEI supplemental comments at 3 (commenters have failed to 

demonstrate that there is discrimination warranting generic action). 

835 Duke/Progress Energy supplemental comments at 17 and n.7. 

836 See, e.g., Pinnacle at 8; EEI at 35-36; Progress Energy reply comments at 5, 

n.5; Duke reply comments at 6. 
Docket No. RM04-7-000 420 

proven they lack service alternatives. Southern states that it would be unreasonable 

to impose a generic obligation to serve at wholesale by means of a “must offer” 

requirement, absent particularized findings based on a properly developed record that 

wholesale customers lack reasonable alternatives.837 

742. EEI agrees that the Commission’s § 202(b) authority is clearly aimed at 

individual transactions where a wholesale customer cannot access supply, with ample 

due process safeguards to ensure that a requirement to sell is truly warranted and will 

not harm the seller.838 EEI states that the Commission cannot turn such a provision 

into a blanket regulatory requirement without violating the intent of Congress and 

inappropriately bypassing these safeguards, nor is such a blanket requirement 

warranted.839

743. Several commenters question the legal support for a “must offer” requirement, 

arguing that the FPA does not contain an express obligation to serve wholesale 

customers,840 and that neither section 205 nor section 206 of the FPA authorize the 

 837 Southern at 60. 

838 EEI reply comments at 16. 

839 EEI at 35-36 (citing El Paso Electric Co. v. FERC, 201 FERC F.3d 667 (5th Cir. 

2000)). 

840 MidAmerican at 18-19; EEI at 33; Southern at 59; Westar at 17; Duke at 12; 

E.ON U.S. reply comments at 1-2; Progress at 13. 
Docket No. RM04-7-000 421 

Commission to mandate or prohibit sales, as long as they are made at just, reasonable, 

and non-discriminatory rates approved by the Commission.841 

744. Many commenters also contest claims that sales outside the mitigated control 

area at market-based rates constitute withholding or undue discrimination. Westar 

and others suggest that offering generation for sale outside of the mitigated control 

area at the prevailing market price to serve demand does not constitute withholding. 

They state that withholding generally refers to either physical withholding (not 

offering to sell) or economic withholding (offering to sell only at inflated prices), 

which in either case is intended to raise prices.842 Duke/Progress Energy claim that 

“the Commission has confirmed that it is ‘legitimate economically rational’ behavior 

for a market participant to export power in order to sell at higher prices outside a 

control area rather than to sell at lower capped prices within a control area.”843 

Westar similarly argues that, absent evidence of manipulation or fraud, a “’seller of a 

commodity is acting quite rationally and legally to withhold his supply from the 

market if he believes that in the future the commodity will command a higher price – 

assuming, of course, the seller is under no legal duty to sell.’”844 Westar and E.ON 

 841 EEI at 35; Progress Energy at 13-14; E.ON U.S. reply comments at 1-2; Duke 

reply comments at 5-6. 

842 EEI reply at 2; Duke/Progress Energy at 15. 

843 Duke/Progress Energy at supplemental comments 16 (quoting San Diego Gas 

& Elec. Co., 103 FERC ¶ 61,345 at P 63 (2003)). 
Docket No. RM04-7-000 422 

U.S. reason that the Commission’s market behavior rules already address economic 

withholding concerns.845

745. MidAmerican adds that in the limited instances where a wholesale customer 

cannot obtain service, and where an obligation to serve exists, the Commission can 

address the issue in fact-specific proceedings of individual sellers.846 Duke suggests 

that the “must offer” proponents have failed to demonstrate why “self-supply,” 

including new construction and supply from external resources, is not a viable option 

in at least some instances.847 Duke states, for example, that the Carolina Agencies 

submit that LSEs will have few if any practical supply options if a mitigated supplier 

is not subject to a must offer requirement. However in Duke’s view, the Carolina 

Agencies fail to demonstrate why “self-supply,” including construction of local 

 844 See Westar at 11, n.23 (quoting United States v. Reliant Energy Services Co., 

420 F. Supp. 2d 1043, 1059 (N.D. Cal. 2006)); see also EEI at 36. 

845 Westar at 12; E.ON U.S. reply comments at 7. In adopting those rules, Westar 

submits that the Commission specifically rejected arguments that “withholding for an 

anti-competitive purpose can only be remedied by way of a generic “must offer”

obligation,” stating that “[i]n fact, where a seller intentionally withholds capacity for the 

purpose of manipulating market prices, market conditions, or markets rules for electric 

energy or electricity products, it has done so without a legitimate business purpose in 

violation of Market Behavior Rule 2.” Westar at 12 (quoting Investigation of Terms and 

Conditions of Public Utility Market-Based Rate Authorizations, 107 FERC ¶ 61,175 at P 

27 (2004) (emphasis added)). 

846 MidAmerican at 19.

847 Duke reply comments at 10. APPA/TAPS responds that the Commission has 

recognized that not all LSEs can build their own generation. APPA/TAPS reply 

comments at 9 (citing April 14 Order, 107 FERC ¶ 61,018 at P 155). 
Docket No. RM04-7-000 423 

generation by their members, is not a viable option in at least some instances. Nor do 

they demonstrate lack of ability to secure supply from resources external to the 

control area. Duke submits that even where construction of new generation may not 

be cost-effective, “self-supply” includes purchasing as well as self-build. Duke 

argues that lack of an economic self-build option at a given time does not relieve an 

LSE of its obligation to acquire generation resources through alternate means such as 

long-term purchases.848

746. Several commenters similarly challenge the claim that choosing to make sales 

outside the mitigated control area at market-based rates is discriminatory. EEI notes 

that not all rate distinctions are prohibited by section 205(b) of the FPA. It states that 

only undue discrimination between customers of the same class that is not justified by 

cost of service differences, operating conditions, or other considerations is 

forbidden.849 In this proceeding, Duke/Progress Energy claim that wholesale 

customers are seeking a superior product to that offered to other customers outside 

the mitigated control area: “a Commission-enforced right to a free and unilateral call 

 848 Duke reply comments at 10. 

849 EEI reply comments at 13-14 (citations, including Wisconsin Michigan Power 

Co., 31 FPC 1445 (1964); CED Rock Springs LLC, 116 FERC ¶ 61,163 at P 39 (2006) 

(In examining potential undue discrimination, the Commission properly focuses on 

whether “there are any similarly situated projects that have been treated differently.”); see 

also Badger Power Marketing Authority, 116 FERC ¶ 61,200 at P 10 (2006) (approving a 

rate that is essentially the same as the rate charged another similarly-situated customer)).
Docket No. RM04-7-000 424 

option to buy any available energy generated by [m]itigated [u]tility assets at costbased prices, exercisable during peak periods when market prices are high.”850 

747. EEI adds that the courts also recognize that the just and reasonable standard 

allows – and can even require – rate differences to reflect different locations and 

classes of customers.851 EEI and Progress Energy therefore contend that, once the 

Commission has determined whether a seller may sell at market-based rates or must 

use mitigated rates in various markets, the seller must be allowed to sell electricity at 

the just and reasonable rates approved for the different markets.852

748. MidAmerican claims that customer concerns that a mitigated seller will unduly 

discriminate between the seller’s native load and wholesale customers in the 

mitigated region are baseless because the Commission’s jurisdiction does not extend 

to a comparison of retail and wholesale rates. MidAmerican states that while a seller 

typically has an obligation to serve retail customers in a franchised service area, that 

obligation does not extend to wholesale customers. Therefore, MidAmerican states 

 850 Duke/Progress Energy supplemental comments at 9. 

851 EEI reply comments at 14-15 (citing Town of Norwood, Massachusetts v. 

FERC, 202 F.3d 392 at 402 (1st Cir. 2000) (“[D]ifferential treatment does not necessarily 

amount to undue preference where the difference in treatment can be explained by some 

factor deemed acceptable by the regulators (and the courts).”); City of Vernon, California 

v. FERC, 983 F.2d 1089 at 1093 (D.C. Cir. 1993)).

852 Id. at 15; Progress Energy at 13. 
Docket No. RM04-7-000 425 

there is no issue of undue discrimination between retail and wholesale rates that 

either requires or allows a “must offer” requirement.853

749. Xcel and others submit that wholesale customers are seeking a preference or 

entitlement through a “must offer” requirement and are in fact calling for 

discrimination by asserting a preference to power available for sale by a mitigated 

seller over all other purchasers, even those who value it more highly,854 and have 

provided no evidence to justify such a preference or entitlement over other potential 

purchasers.855 Duke/Progress Energy state that customer claims that “they are 

victims of market power and therefore need some specially tailored remedy” is 

erroneous, and that “[b]y imposing cost-based rates . . . within their control area, the 

Commission has fully mitigated any market power concerns.”856 Xcel and others 

also note that the LSEs have no reciprocal obligation to purchase power if a “must 

offer” requirement were imposed upon mitigated sellers.857

 853 MidAmerican reply comments at 7; see also, Duke reply comments at 6. 

Compare APPA/TAPS reply comments at 3 (“The Commission is not called upon to 

decide a struggle between wholesale and retail ratepayers, but to set a just and reasonable 

wholesale rate, which a Commission-approved cost-based rate surely is.”). 

854 Xcel reply at 6-7 ; EEI supplemental comments at 4-5. 

855 Xcel reply comments at 6-7; Progress Energy reply comments at 2, 4, 7-11; 

Duke reply comments at 7, n.10. 

856 Duke/Progress Energy supplemental comments at 13 (citing Duke Power, 113 

FERC ¶ 61,192 at P 22).

857 Xcel reply comments at 7; Progress Energy reply comments at 6; MidAmerican 

reply comments at 9. 
Docket No. RM04-7-000 426 

750. According to Duke and others, when a mitigated supplier sells excess 

generation at market-based rates outside of the mitigated control area, it is exhibiting 

economic behavior.858 Such behavior encourages trading within and across regions, 

making markets more competitive. Similarly, Westar contends that a “must offer” 

requirement prevents markets from allocating scarce resources to customers who 

value them the most, hindering optimal resource allocation.859 Westar states that this 

is inefficient because “the highest cost generation may not be displaced by the seller’s 

lower cost energy.”860

751. EEI, Progress Energy, and others also claim that a “must offer” requirement 

would effectively take economic benefits away from the mitigated utility’s retail 

native load and transfer them to wholesale customers in the mitigated control area.861 

Some of these commenters claim that a “must offer” requirement may result in a 

windfall for the wholesale customer originally seeking protection from the seller’s 

market power at the expense of the mitigated utility and its native load customers.862 

 858 Duke at 11; Xcel at 6; Southern at 56-57; EEI reply comments at 11. 

859 Westar at 13 (citing Pacific Gas and Electric Company, 38 FERC ¶ 61,242 at 

61,790 (1987)). 

860 Id. (quoting Pacific Gas and Electric Company, 38 FERC at 61,790, n.19). 

861 See, e.g., EEI at 33; Progress Energy at 14, 16; Entergy at 2; Westar at 16; see 

also Dr. Pace at 24-25. 

862 PPL reply comments at 14; Duke reply comments at 2, 7-8; Progress Energy at 

16; E.ON U.S. at 13-14; Duke at 12-13; MidAmerican at 27. 
Docket No. RM04-7-000 427 

PNM/Tucson adds that sales made by a utility pursuant to a “must offer” requirement 

could affect reliability by making capacity unavailable to meet state-established 

reserve margins.863

752. Xcel and Duke point out that a “must offer” requirement at cost-based rates 

may result in a lost opportunity cost to the seller.864 A number of commenters assert 

that mitigation is intended to assure that selling utilities do not benefit from the 

exercise of market power; it is not to guarantee preferential treatment for particular 

customers to obtain below-market generation through an obligation to serve.865

753. Some commenters further contend that a “must offer” requirement would 

create significant wealth transfers from mitigated sellers as a result of arbitrage 

opportunities. For example, wholesale customers would accept the mitigated offer 

any time the “must offer” price was below the market price, either in or outside of the 

mitigated region.866 E.ON U.S. is concerned that a “must offer” requirement giving a 

buyer the option to buy power at mitigated prices will inevitably result in external 

third parties negotiating with such a buyer to obtain longer-term access to the 

mitigated power.867

 863 PNM/Tucson at 18. 

864 Xcel at 8; Duke reply comments at 3, n.4. 

865 Xcel at 5; EEI reply comments at 10, 12; Progress Energy at 14. 

866 Progress Energy at 16; Westar at 16. 

867 E.ON U.S. at 13. 
Docket No. RM04-7-000 428 

754. In addition, EEI and others argue that a “must offer” requirement would 

reduce competition and stifle development by providing a disincentive for sellers to 

develop new generation resources.868 New entrants would be deterred from building 

generation due to the disparity between cost-based and market-based rates;869 other 

sellers in the mitigated region effectively would be mitigated because they would not 

be selected by buyers unless their price is below the mitigated price of the “must 

offer” requirement.870 At the same time, EEI asserts that the mitigated seller would 

perpetuate its market power by increasing its capacity in the mitigated control area.871

755. Progress Energy and MidAmerican add that a “must offer” requirement would 

impede a mitigated seller’s ability to fulfill its retail crediting obligations and to 

provide adequate and reliable service to its native load retail customers, which bear, 

through their retail rates, the fixed costs of the generation to serve them.872

 868 EEI at 37; Progress Energy at 16; MidAmerican at 22. APPA/TAPS responds 

that it is in fact the mitigated seller’s constrained transmission system that keeps LSEs 

captive and prevents new entry that could reduce the seller’s market power. APPA/TAPS 

reply comments at 9. 

869 EEI reply comments at 10. 

870 MidAmerican reply comments at 8. 

871 EEI reply comments at 10. 

872 See, e.g., Progress Energy at 14-15; E.ON U.S. at 12-13; PNM Tucson at 18; 

MidAmerican at 21. 
Docket No. RM04-7-000 429 

756. Southern, Duke and others further suggest that a “must offer” requirement 

could undermine the required planning and operations processes of utility systems 

purchasing the “must offer” output.873 They argue that a “must offer” requirement 

could bias shorter-term operating decisions where, for example, an LSE has the 

opportunity to purchase peak supply in real time at less than market prices, thereby 

avoiding incurring any fixed costs on a day-ahead basis to ensure peak supply 

availability.874 They contend that this would eliminate incentives for the LSEs to 

plan to meet their resource needs and shift planning obligations at the expense of a 

mitigated utility’s native load customers.875

757. Another commenter is also wary of a “must offer” requirement, reasoning that 

such a requirement is normally designed to mitigate physical withholding. This 

commenter states that it may work well in an organized power market where an 

independent operator ensures that the power is used to serve the local needs caused 

by reliability or local resource deficiency. However, without an independent 

 873 Southern at 61; Progress Energy at 16; Duke reply comments at 9-10; EEI reply 

comments at 10-11. 

874 Southern at 63. 

875 Duke reply comments at 8-11. APPA/TAPS counters that where a “must offer” 

requirement would not, by its own terms, obligate a seller to build, an LSE that relied 

exclusively on “must offer” sales would be taking risks that capacity to support those 

sales might no longer be available. APPA/TAPS reply comments at 9. 
Docket No. RM04-7-000 430 

operator, a “must offer” requirement may be more difficult to administer.876 In 

advocating for separate market policies and tests for short- and long-term markets, 

this commenter prefers a price cap for short-term products rather than a “must offer” 

requirement, asserting that a price cap for short-term products is preferable to a “must 

offer” approach because it is more economically efficient, fair, and easier to 

administer.877 For long-term products, this commenter takes the position that, “[i]n 

situations where a lack of long-term transmission and/or a lack of long-term supply 

alternatives exist, it is difficult to think of an alternative to full cost-of-service 

rates.”878 They add that these cost-based rates should offer both fair prices and 

adequate investment returns to suppliers in the destination market with rate-of-return 

levels that fully enable incumbent suppliers to make appropriate investments to meet 

such cost-based obligations.879 

758. Entergy raises a concern that in the NOPR the Commission erred by failing to 

define what constitutes available capacity. It asserts that there is difficulty in 

 876 Drs. Broehm and Fox-Penner at 16-17. 

877 Drs. Broehm and Fox-Penner supplemental comments at 3. Drs. Broehm and 

Fox-Penner advocate other approaches, such as use of a proxy price when transmission 

constraints are not binding and use of default cost-based rates when they are binding. 

878 Id.

879 Id.
Docket No. RM04-7-000 431 

calculating available capacity because of uncertainty regarding: (1) loads; (2) 

qualifying facility puts; (3) unit performance; and (4) fuel arrangements and prices.880

Commission Determination

759. After careful consideration of the arguments raised by commenters, we will 

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, we conclude that there is insufficient record evidence to 

support instituting a generic “must offer” requirement. 

760. As discussed above, some commenters argue that undue discrimination occurs 

if a mitigated seller refuses to sell power to customers in the mitigated balancing 

authority area and instead sells that power at market-based rates to customers outside 

the mitigated balancing authority area. Some commenters also contend that it is 

unduly discriminatory for a mitigated seller to make market-based rate sales to 

competitive markets outside the mitigated balancing authority area when constraints 

on that seller’s own transmission system prevent embedded customers from similarly 

accessing those markets as buyers. However, these commenters have not provided 

any evidence of specific instances in which the harms they identify have, or are, 

occurring. Without such evidence, we decline to impose a generic remedy such as a 

“must offer” requirement. 

 880 Entergy at 2-3. 
Docket No. RM04-7-000 432 

761. In National Fuel, the D.C. Circuit vacated a final rule of the Commission, 

Order No. 2004, as applicable to natural gas pipelines because of the expansion of the 

standards of conduct to include a new definition of energy affiliates. The court 

explained that the Commission relied on both theoretical grounds and on record 

evidence to justify this expansion. The court concluded that the Commission’s record 

evidence did not withstand scrutiny and, thus, concluded the expansion was arbitrary 

and capricious in violation of the Administrative Procedure Act.881 While the court 

left open the possibility of the Commission relying solely on a theoretical threat of 

abuse, it cautioned that if the Commission chooses to take that approach, “it will need 

to explain how the potential danger . . . unsupported by a record of abuse, justifies 

such costly prophylactic rules.”882 In addition, the court said the Commission would 

need to explain why individual complaint procedures were insufficient to ensure 

against abuse.883 

762. We find here that, although wholesale customer commenters have raised 

theoretical concerns that they will be unable to access power absent a “must offer” 

requirement, they have not provided any concrete examples of harm nor explained 

how the potential harm justifies the generic remedy they seek. Given the lack of 

 881 National Fuel, 468 F.3d at 844. 

882 Id.

883 Id.
Docket No. RM04-7-000 433 

evidence in the record that wholesale customers in mitigated markets will be unable 

to obtain power supplies at reasonable rates, we conclude that there is insufficient 

basis for instituting a generic “must offer” requirement. Indeed, the record includes 

evidence of utilities continuing to make cost-based sales after loss or surrender of 

market-based rate authority.884

763. In addition, consistent with the guidance provided in National Fuel, 

commenters advocating a generic “must offer” have not demonstrated that existing 

procedures and remedies under the FPA are inadequate to deal with specific cases 

that may arise. To the contrary, we find that there are potential remedies available on 

a case-by-case basis to a wholesale customer alleging undue discrimination or other 

unlawful behavior on the part of a mitigated seller. For example, a wholesale 

customer can file a complaint pursuant to section 206 of the FPA. It also can bring an 

action under section 202(b) of the FPA.885 In addition, it can bring an action pursuant 

to the statutory prohibition in section 222 of the FPA against market manipulation. 

764. While we do not impose a generic “must offer” requirement in this Final Rule, 

we do not rule out the possibility that we might find the imposition of a “must offer” 

 884 See Duke reply comments at 7 and n.10; Progress Energy reply comments at 

9-11; Duke/Progress Energy supplemental comments at 17 and n.7. 

885 See, e.g, City of Las Cruces, New Mexico v. El Paso Electric Co., 87 FERC 

¶ 61,220 (1999) (“In our view, section 202(b) allows the Commission to direct a public 

utility to take three separate actions: (1) establish a physical connection of its 

transmission facilities with the facilities of one or more eligible persons; (2) sell energy to 

eligible persons; or (3) exchange energy with eligible persons.”) 
Docket No. RM04-7-000 434 

requirement, or some other condition on the seller’s market-based rate authority, to be 

an appropriate remedy in a particular case depending on the facts and circumstances, 

as we have done in the past.886 We note that the Commission has previously imposed 

a “must offer” requirement as a condition of market-based rate authority for sellers in 

the California markets.887 There, the record demonstrated a problem in a limited 

geographic area that warranted a “must offer” remedy to prevent unjust and 

unreasonable rates from being charged during certain times and under certain 

conditions. If a wholesale customer were to present specific evidence documenting 

that a transmission provider either denied the customer’s request for transmission 

service, in violation of the OATT, or was unreasonably delaying responding to a 

request for transmission service, in violation of the OATT, we might find the 

imposition of a “must offer” requirement on a transmission provider to be an 

appropriate remedy.888 As the Commission recently explained in Order No. 890, 

transmission providers must process requests for transmission service “as soon as 

 886 If an intervenor believes a “must-offer” requirement is the only way to mitigate 

market power, it may present evidence to that effect in a particular proceeding. 

887 See San Diego Gas & Elec. Co., 95 FERC ¶ 61,418 at 62,557 (2001) (“After 

carefully considering the record, the Commission reaffirmed its general finding that, as a 

result of the seriously flawed electric market structure and rules for wholesale sales of 

electric energy in California, unjust and unreasonable rates were charged and could 

continue to be charged during certain times and under certain conditions, unless certain 

targeted remedies were implemented.”) 

888 We are not prejudging here that such facts warrant imposition of a “must offer” 

requirement. 
Docket No. RM04-7-000 435 

reasonably practicable after receipt” of such requests889 and must post performance 

metrics that are intended “to enhance the transparency of the study process and shed 

light on whether transmission providers are processing request studies in a nondiscriminatory manner.”890 Order No. 890 explained that “the revised pro forma

OATT will greatly enhance our oversight and enforcement capabilities by increasing 

the transparency of many critical functions under the pro forma OATT, such as ATC 

calculation and transmission planning.”891 Here too, we reiterate that the Commission 

“intends to use its enforcement powers with respect to the OATT in a fair and evenhanded manner, pursuant to the principles set forth in the Policy Statement on 

Enforcement.”892

765. In addition to our conclusion that there is not sufficient record evidence to 

support the imposition of a generic “must offer” requirement, we are also concerned 

that adoption of a “must offer” requirement would present a number of difficult 

implementation and logistical problems.893 

 889 Preventing Undue Discrimination and Preference in Transmission Service, 

Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 1296 (2007) (Order No. 890). 

890 Id. at P 1308. 

891 Id. at P 1721. 

892 Id. at P 1714. 

893 Because we have decided not to impose a generic “must offer” requirement in 

this Final Rule, we do not address the merits of the particular must-offer proposals made 

 (continued...) 

 
Docket No. RM04-7-000 436 

766. For example, given the difficulties associated with calculations of available 

transfer capability,894 we foresee similar disputes over the calculation of available 

generation capacity were we to impose a generic “must offer” obligation. For 

instance, how far in advance should such calculations occur – one hour, one day, one 

month, or some other time frame? Would such calculations be derived on a generator 

specific basis or on a system basis (and how is transmission factored in)? Would the 

Commission or the industry need to develop a standard method of calculating 

available generation capacity? How would available generation capacity be allocated 

to potential purchasers? 

767. We also are concerned that adopting a “must offer” requirement could harm 

other markets. For example, if a mitigated seller is required to offer its available 

power first to customers in the mitigated market, such a requirement may effectively 

preclude the mitigated seller from participating in adjoining markets particularly at 

times when additional supply is most needed (i.e., when prices in the adjoining 

market are high). Such a policy may serve to assist one set of customers at the 

expense of other customers that see their supply options reduced. 

 

by commenters. 

894 OATT Reform NOPR at PP 37-41 (outlining problems that result from 

inconsistent available transfer capacity calculation, including missed opportunities for 

transactions, frequent errors, and undue discrimination). 
Docket No. RM04-7-000 437 

768. Parties have asserted that imposing a must offer requirement may discourage 

long-term planning, while others have disagreed with those arguments. Given that 

we do not impose any must offer obligation in this rule, we need not and do not 

address these arguments. If the Commission considers imposing a “must offer” 

requirement in an individual case, affected parties can raise these arguments at that 

time. 

769. Though APPA/TAPS and the Carolina Agencies are correct that the 

Commission has previously imposed a “must offer” requirement as a condition of 

market-based rate authority for sellers in the California markets, as discussed above, 

that holding supports our approach here. There, the record demonstrated a problem 

in a limited geographic area that warranted a “must offer” remedy to prevent unjust 

and unreasonable rates from being charged during certain times and under certain 

conditions. By contrast, here APPA/TAPS and the Carolina Agencies urge us to 

impose a generic remedy on all mitigated sellers in all markets without a showing that 

there is a concrete problem justifying imposition of a “must offer” requirement in all 

markets. 

770. Given that we have not adopted a “must offer” requirement in this Final Rule, 

we need not, and do not, address arguments asserting that we lack legal authority to 

do so. If the Commission should adopt any such requirement in an individual case, 

affected parties can raise any related legal arguments at that time and nothing in this 

rule precludes them from doing so. 
Docket No. RM04-7-000 438 

771. For many of the same reasons that we decline to impose a “must offer” 

requirement, we also decline to adopt the “right of first refusal” requirement proposed 

by NRECA. Under this approach, a wholesale customer in the mitigated market 

would be given a right of refusal to purchase, at the market price, power that the 

mitigated seller proposes to sell outside the mitigated market. For the reasons 

provided above, there is insufficient record evidence to support imposition of such an 

across-the-board requirement. 

772. A “right of first refusal” also would carry significant administrative burdens. 

Such an approach would invite disputes about what constitutes a legitimate offer by a 

third party to purchase power which establishes the basis for the offered rate. There 

also may be disputes if more than one wholesale customer wants to purchase the 

power in question. We are also concerned about the long-term viability of a rate 

setting that is based on mitigated sellers repeatedly negotiating tentative power sale 

arrangements with would-be buyers in first-tier markets only to have those offers 

withdrawn so the sale could be made to another buyer. Under such a regime, buyers 

from outside the mitigated market may be disinclined to invest resources to negotiate 

tentative contracts knowing that there is a significant chance that another buyer from 

within the mitigated market will usurp their position and instead get the sale. 

773. There are also administrative concerns with how the Commission or third 

parties could be certain what the actual price and conditions of service would be for 

the sale in the first-tier market unless the contract was actually executed. 
Docket No. RM04-7-000 439 

774. In response to NRECA’s suggestion that an enforceable commitment to 

provide sufficient additional transmission import capacity to mitigate generation 

market power be considered as an alternative, the Commission notes that, consistent 

with the April 14 Order, a seller that fails one of the generation market power screens 

is allowed to propose alternative mitigation that the Commission may deem 

appropriate.895 As a result, a mitigated seller could propose, as alternative mitigation, 

to provide additional transmission capacity by, for example, committing to relinquish 

transmission reservations or to physically upgrade the transmission grid. 896 The 

Commission would consider such proposals on a case-by-case basis. Moreover, a 

primary purpose of Order No. 890 is to “increase the ability of customers to access 

new generating resources and promote efficient utilization of transmission by 

requiring an open, transparent, and coordinated transmission planning process.”897 

775. In particular, we believe recent actions we took in Order No. 890 address the 

Carolina Agencies’ proposal that mitigated utilities be required to investigate and 

report on transmission expansion or other actions that could remove structural 

impediments exacerbating market power. In Order No. 890, the Commission adopted 

 895 April 14 Order, 107 FERC ¶ 61,018 at P 147, 148 n.142. 

896 See, e.g., Westar Energy, Inc., 115 FERC ¶ 61,228, order on reh’g, 117 FERC 

¶ 61,011 (2006), order on further reh’g, 118 FERC ¶ 61,237 (2007) (concerning such 

mitigation proposed in the context of a disposition of jurisdictional facilities). 

897 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 3. 
Docket No. RM04-7-000 440 

a number of reforms designed to mitigate transmission market power, including a 

requirement that all transmission providers develop a coordinated, open and 

transparent transmission planning process that would, among other things, enable 

customers to request studies evaluating potential upgrades or other investments that 

could reduce congestion or integrate new resources and loads.898 The requests for 

these economic planning studies and the responses will be posted on the transmission 

provider’s OASIS site, subject to confidentiality requirements.899 We believe these 

steps may assist in reducing structural impediments that contribute to market power. 

b. First-Tier Markets

Commission Proposal

776. In the NOPR, the Commission sought comment on whether it is appropriate to 

continue to allow sellers that are subject to mitigation in their home control area to 

sell power at market-based rates outside their control area. The Commission asked if 

this represents undue discrimination or otherwise constitutes "withholding" in the 

home control area that is inconsistent with the FPA's mandate that rates be just, 

reasonable and not unduly discriminatory, or, instead, if this reflects economically 

efficient behavior and encourages necessary trading within and across regions, 

particularly in peak periods when marginal prices rise above average embedded costs. 

 898 Id. at P 544. 

899 Id. at P 546 (to be codified at 18 CFR 37.6 (b)(2)(iii)). 
Docket No. RM04-7-000 441 

777. The Commission also asked if it should find that any seller that has lost 

market-based rate authority in its home control area should be precluded from selling 

power at market-based rates in adjacent (first tier) control areas. 

Comments

778. A number of commenters state that there is no basis for prohibiting a mitigated 

seller from selling excess power at market-based rates in adjacent control areas, as the 

Commission will have determined that the seller does not have the ability to exercise 

market power in any of those adjacent control areas.900 Some commenters also claim 

that prohibiting these sales would limit market activity and constrain the benefits of 

competitive pricing by excluding sellers from markets in which they do not possess 

market power.901 

779. PNM/Tucson contends that prohibiting sales of available capacity at marketbased rates in adjacent control areas where the seller does not possess market power 

would be a disproportionate response that would render the Commission’s market-bymarket analysis meaningless.902 Moreover, PNM/Tucson and MidAmerican warn 

that independent power producers have no incentive to invest in new resources in 

 900 Ameren at 18-19; see also Duke at 12 (citing Florida Power Corp., 113 FERC ¶ 

61,131 at P 24 (2005)); Southern at 56; PNM/Tucson at 19-20 ; Xcel at 5-6; EEI at 33; 

and PPL reply comments at 15-16. 

901 MidAmerican at 22-23; PPL at 24-25; EEI at 28. 

902 PNM/Tucson at 19-20. 
Docket No. RM04-7-000 442 

markets where prices are effectively constrained to the level of another entity’s 

embedded costs.903

780. Southern asks the Commission not to impose mitigation that will create flaws 

in markets that may have periods of genuine temporary scarcity but where the seller 

does not possess market power.904 Southern states that prohibiting a mitigated seller 

from responding to price signals in neighboring markets will adversely affect 

efficient resource development and contradicts the Commission’s desire to promote 

competitive markets and resource adequacy.905 Further, foreclosing markets 

otherwise accessible to resources nominally dedicated to native load service may 

impair the optimization of those resources by impairing a full response to price 

signals. This, Southern adds, would harm native load customers because the 

mitigated utility would be unable to optimize surplus resources, as mandated through 

state retail credit obligations, thereby depriving retail customers of the benefits of 

system optimization.906

781. Another commenter agrees that a mitigated seller should be allowed to sell 

available capacity at market-based rates in markets where that seller does not possess 

 903 MidAmerican at 22, PNM/Tucson at 17. 

904 Southern at 64-65. 

905 Id. at 57. 

906 Id.
Docket No. RM04-7-000 443 

market power, provided that this does not raise prices in the mitigated region.907 This 

commenter asserts that such sales facilitate regional trading and market efficiency in 

developing competitive markets.908 Another commenter contends that unless “costs” 

are defined in a way that effectively allows competitive market rates to be charged, 

revoking a seller’s market-based rate authority in markets where the seller does not 

possess market power would reduce the mitigated seller’s incentive to supply 

available power to the market, deprive the mitigated seller and its customers of 

legitimate economic rent, subsidize those buyers with access to the mitigated rates, 

and create a rationing problem among buyers with access to the mitigated-rate 

power.909

782. MidAmerican states that, if the Commission were to eliminate a seller’s 

market-based rate authority in all regions, the mitigated prices should only apply 

prospectively. MidAmerican reasons that existing transactions negotiated in the 

 907 Drs. Broehm and Fox-Penner at 16. The NYISO also supports market-based 

rate sales in competitive markets where the mitigated seller does not possess market 

power. According to the NYISO, with regard to the NYISO, PJM Interconnection, LLC 

and ISO-New England, the Commission can ensure that sellers respond to market price 

signals by designing market power mitigation in a manner that will permit even mitigated 

sellers to receive the applicable market clearing price. For example, any cost-based rate 

mitigation imposed could limit the maximum bids that the seller may submit without 

limiting the revenues that the mitigated seller may receive. NYISO at 10. 

908 Drs. Broehm and Fox-Penner at 16. See also PPL at 24; MidAmerican at 17; 

E.ON U.S. at 12-13; EEI at 28; Duke at 11. 

909 Dr. Pace at 21. 
Docket No. RM04-7-000 444 

absence of market power should not be altered, since these previously-negotiated 

transactions would have no impact on a seller’s willingness to make future sales to 

customers in the home control area.910

783. Other commenters oppose allowing mitigated sellers to sell at market-based 

rates outside the home control area on the basis that it encourages and provides 

incentives for the seller to engage in physical or economic withholding of its 

generation output in the home control area. These commenters indicate that their 

concerns in this regard would be addressed if mitigation is combined with a 

requirement that the mitigated seller make power available to customers within the 

mitigated control area. APPA/TAPS state that, absent a “must offer” requirement, it 

is not clear that prohibiting mitigated sellers from making market-based sales outside 

their home control areas would necessarily prompt the mitigated seller to sell power 

in its home control area.911 

784. However, APPA/TAPS ask the Commission not to rule out across-the-board 

revocation of market-based rate authority as it may be necessary to motivate 

mitigated sellers to undertake the kind of structural measures needed to mitigate 

market power on a long-term basis. If the Commission adopts a policy to revoke or 

condition market-based rate authority beyond the home control area, APPA/TAPS 

 910 MidAmerican at 23. 

911 APPA/TAPS at 43. 
Docket No. RM04-7-000 445 

state that the policy should not be limited to just the first-tier control area. Rather, 

the revocation or conditions should apply to any market where the seller can use 

generation located in or originally delivered to its control area to sell outside that 

mitigated area.912

785. The Carolina Agencies state that a generic prohibition on market-based rate 

sales outside the mitigated market appears likely to inhibit regional trade to a greater 

extent than is necessary to protect the interests of embedded LSEs.913 Both the 

Carolina Agencies and NC Towns state that there is no clear need to prohibit 

mitigated sellers from making market-based sales outside their home control areas if 

a “must offer” requirement is adopted.914 According to the Carolina Agencies, a 

mitigated seller should be free to engage in market-based rate sales in other control 

areas as long as that utility has provided embedded LSEs a reasonable opportunity to 

purchase capacity and/or energy. 

786. As to any claim that it would be unduly discriminatory for the Commission to 

deny or condition the market-based rate authority of a utility that passes the screens in 

markets beyond its mitigated home control area, APPA/TAPS and the Carolina 

Agencies submit that mitigated sellers are not similarly-situated to the other utilities 

 912 APPA/TAPS at 43-44. 

913 Carolina Agencies at 19. 

914 Id. at 18-19; NC Towns at 7. 
Docket No. RM04-7-000 446 

selling at market-based rates in those other competitive markets. They assert that 

other sellers’ market-based rate sales do not implicate those sellers’ ability to 

withhold supply from disfavored wholesale customers in a mitigated control area. 

Moreover, they argue that it elevates the importance of the screens above the FPA to 

argue that granting unconditioned market-based rate authority to one seller who 

passes the screens obligates the Commission to grant unconditioned authority to all 

who pass the screens. In their view, the Commission would be failing its duty under 

the FPA if it permitted physical withholding by a dominant utility, as such actions 

would be unjust, unreasonable, and unduly discriminatory.915

787. ELCON advocates suspending any mitigated seller’s market-based rates in all 

markets it can access. Short of this long-term fix, ELCON asserts that other 

proposals such as “must offer” requirements will be prone to fail because of likely 

unintended consequences.916

788. Morgan Stanley favors requiring mitigated sellers to post the mitigated price 

and other material terms on a publicly-available website for all sales to be made from 

the units that are part of the portfolio covered by the Commission’s market power 

 915 APPA/TAPS and Carolina Agencies supplemental comments at 36-37. 

NRECA adds that “the FPA does not bar – as unduly discriminatory – Commission 

imposition of remedies in a non-discriminatory fashion, including banning sales outside 

the mitigated market: the statute protects buyers, not sellers, from undue discrimination.” 

NRECA reply comments at 41; see also Carolina Agencies at 16 (citing the OATT 

Reform NOPR at P 210 and n.203). 

916 ELCON at 11. 
Docket No. RM04-7-000 447 

finding, regardless of where the actual sale sinks.917 Morgan Stanley asserts that 

effective mitigation can only occur if it is imposed on all sales from a mitigated 

supplier’s generation portfolio and urges the Commission not to focus on who the 

purchaser is or where the power sinks.918 If a mitigated seller chooses to offer its 

excess power only outside the mitigated region and simply refuses to sell inside its 

home market, Morgan Stanley is concerned that the market in the “home” territory 

would be even less competitive than if the seller were allowed to sell there on an 

unmitigated basis. 919

789. CAISO states that, where a competitive supply of imports into a mitigated 

control area does not exist, market power mitigation mechanisms or other incentive 

schemes will be necessary to ensure that the local supplier makes all of its capacity 

available to supply energy and ancillary services to the home control area.920 CAISO 

asks the Commission to provide greater clarity on the extent to which the antifraud 

and anti-manipulation rules adopted in Order No. 670 prohibit economic and physical 

 917 Morgan Stanley at 7; Morgan Stanley reply comments at 6. 

918 Morgan Stanley reply comments at 6. The Oregon Commission responds that 

such broad mitigation would not benefit wholesale customers in the mitigated region and 

would harm the supplier’s native retail load by transferring wealth to marketers like 

Morgan Stanley. Oregon Commission reply comments at 4; see also MidAmerican reply 

comments at 13-14 (arguing that Morgan Stanley’s proposal would be an arbitrary and 

capricious redistribution of income and allow windfall arbitrage profits). 

919 Morgan Stanley at 6. 

920 CAISO at 16. 
Docket No. RM04-7-000 448 

withholding of resources. In particular, CAISO asks the Commission to provide 

greater clarity on the deceptive conduct criteria it would use to determine whether a 

particular case of physical or economic withholding would be a violation of the new 

Part 47 regulations. CAISO explains that greater clarity in this area will help ISO and 

RTO market monitors in developing effective RTO/ISO market power mitigation 

rules tailored for the types of physical and economic withholding that are not 

addressed under Part 47 regulations. 

Commission Determination

790. After careful consideration of the arguments raised by commenters, we will 

retain our current policy and limit mitigation to the market in which the seller has 

been found to possess, or chosen not to rebut the presumption of, market power. We 

will not place limitations on a mitigated seller’s ability to sell at market-based rates in 

balancing authority areas in which the seller has not been found to have market 

power. 

791. The Commission authorizes sales of electric energy at market-based rates if 

the seller and its affiliates do not have, or have adequately mitigated, horizontal and 

vertical market power in generation and transmission, and cannot erect other barriers 

to entry. As the Commission has explained, “The consideration of market power is 

important in determining if customers have genuine alternatives to buying the seller's 
Docket No. RM04-7-000 449 

product.”921 Commenters favoring revocation of a mitigated seller’s market-based 

rate authority in markets where there has been no finding of market power, as well as 

those supporting broadening mitigation to first-tier markets, have not provided a 

sufficient legal basis for such a policy. Where the record demonstrates that a seller 

does not have market power in a market, or has adequately mitigated any market 

power, the Commission has authorized such a seller to transact under market-based 

rates.922 As the April 14 Order explained, “Market-based rates will not be revoked 

and cost-based rates will not be imposed until there has been a Commission order 

making a definitive finding that the applicant has market power ....”923

792. We recognize that wholesale customer commenters are generally concerned 

that allowing mitigated sellers to sell outside their mitigated markets at market-based 

rates could encourage such sellers not to offer generation for sale within the mitigated 

market. However, we agree with the Carolina Agencies that a generic prohibition 

against such sales could inhibit regional trade to a greater extent than necessary to 

protect captive LSEs. We note that even some wholesale customer commenters 

acknowledge that it is not clear that prohibiting mitigated sellers from making 

market-based sales beyond their mitigated region would prompt the mitigated seller 

 921 Louisville Gas & Elec. Co., 62 FERC at 61,144. 

922 Florida Power Corp., 113 FERC ¶ 61,131 at P 24. 

923 April 14 Order, 107 FERC ¶ 61.018 at P 149. 
Docket No. RM04-7-000 450 

to sell power in the mitigated market. For these reasons, we limit mitigation to the 

areas in which the seller has market power. 

793. For the reasons stated above, we disagree with Morgan Stanley’s assertion that 

effective mitigation can only occur if it is imposed on all sales from a mitigated 

seller’s generation portfolio. In addition, though we appreciate CAISO’s request for 

greater clarity on the criteria the Commission will use to determine whether economic 

and physical withholding has occurred, such a determination must be made on a caseby-case basis. 

c. Sales that Sink in Unmitigated Markets

Commission Proposal 

794. In the NOPR, the Commission stated that some companies have proposed 

limiting mitigation to sales that “sink in” the mitigated market, that is, so that 

mitigation would only apply to end users in the mitigated market. However, in 

MidAmerican Energy Company,924 the Commission stated that limiting mitigation to 

sales that “sink in” the mitigated market would improperly limit mitigation to certain 

sales, namely, only to sales to buyers that serve end-use customers in the mitigated 

market. The Commission reasoned that limiting mitigation in this manner would 

improperly allow market-based rate sales within the mitigated market to entities that 

 924 114 FERC ¶ 61,280 at P 29-33 (2006), reh’g pending (MidAmerican). 
Docket No. RM04-7-000 451 

do not serve end-use customers in the mitigated market.925 The Commission stated 

that such a limitation would not mitigate the seller’s ability to attempt to exercise 

market power over sales in the mitigated market and is inconsistent with the 

Commission’s direction in the April 14 and July 8 Orders. On rehearing of the April 

14 Order, it was argued that access to power sold under mitigated prices should be 

restricted to buyers serving end-use customers within the relevant geographic market 

in which the seller has been found to have market power. In particular, arguments 

were made that a seller should not be required to make sales at mitigated prices to 

power marketers or brokers without end-use customers in the relevant market. In the 

July 8 Order, the Commission rejected the suggestion that mitigated sellers be 

restricted to selling power only to buyers serving end-use customers, and has since 

rejected tariff language that proposes to do so. 

795. In the NOPR, the Commission sought comment on whether it should modify 

or revise its current policy. The Commission sought comment on whether and, if so, 

how it should allow market-based rate sales by a mitigated seller within a mitigated 

market if those sales do not “sink” in that control area. 

Comments

796. While some commenters generally seek to allow a mitigated seller to make 

sales at market-based rates if those sales do not “sink” in the mitigated market, other 

 925 Id. at P 31. 
Docket No. RM04-7-000 452 

commenters support the current policy of requiring all of a mitigated supplier’s sales 

in the mitigated market to be cost-based. The State AGs and Advocates go even 

further and encourage the Commission to apply its mitigation policy to all wholesale 

sales that sink in the mitigated market, regardless of the seller, arguing that the impact 

of market power on price is market-wide in scope.926

797. APPA/TAPS support the current policy of requiring cost-based rate mitigation 

for all sales in the mitigated market regardless of whether the sales ultimately sink in 

an unmitigated market. APPA/TAPS argue that allowing market-based rate sales in a 

mitigated market would yield unlawful rates because the mitigated seller would be 

making market-based rate sales in a market where it has, or is presumed to have, 

market power.927 

798. The NYISO agrees that mitigation should not be limited to sales that “sink in” 

the mitigated market, at least in clearing price auctions such as those administered by 

the NYISO. The clearing prices are established by the interaction of all eligible 

buyers and sellers, and the NYISO reasons that there would be no practical basis, nor 

 926 State AGs and Advocates at 43-44. 

927 APPA/TAPS at 47-48. To limit marketers’ arbitrage opportunities, 

APPA/TAPS suggest limiting any “must offer” obligation to sales that sink in the seller’s 

control area. The seller could make additional sales in its control area at the cost-based 

rate, but would not be obligated to do so because purchasers for loads outside of the 

seller’s control area would presumably have other power supply options. 
Docket No. RM04-7-000 453 

economic justification, for carving out marketers or brokers who may export their 

purchases.928

799. The Carolina Agencies express concern that limiting mitigation to sales that 

sink in a mitigated market would reduce supply options for LSEs embedded in that 

mitigated market. They contend that unrestricted exports from a mitigated market 

increase the prices charged by other sellers due to scarcity. Even when a sale sinks 

outside the mitigated market, the Carolina Agencies claim that round-trip gaming will 

continue, and they question the Commission’s ability to effectively detect and stop 

such gaming by attempting to trace megawatts via NERC tag data or other means. 

However, the Carolina Agencies submit that with a properly structured “must offer” 

requirement in place, there is no reason to bar market-based rate sales based on the 

location of the point of sale or even the identified sink.929 

800. Other commenters support allowing sales of power within a mitigated market 

that nonetheless sink in unmitigated markets (i.e., markets where the seller does not 

possess market power) to be made at market-based rates.930 As discussed below, they 

 928 NYISO at 8-10. The NYISO suggests that the Commission can avoid concerns 

regarding exports to neighboring markets by applying any cost-based mitigation it 

imposes to limit the maximum bids that the seller may submit, without limiting the 

revenues that the mitigated seller may receive. Id.

929 Carolina Agencies at 20. 

930 See, e.g., PPL reply comments at 16. 
Docket No. RM04-7-000 454 

offer various proposals on what factors should determine whether a sale should be 

priced at market-based rates. 

801. Several commenters state that the relevant inquiry should be whether the 

power serves load (sinks) in a control area where generation market power is an 

issue. MidAmerican and the Oregon Commission submit that there is no reason to 

mitigate sales over which the seller is unable to exercise market power.931 Rather, 

MidAmerican asks the Commission to refocus on whether a seller could exercise 

market power, not on the physical location where a change in ownership of energy 

occurs. MidAmerican argues that if a mitigated seller cannot exercise market power 

over sales made directly in an outside competitive market, such seller cannot exercise 

market power over sales made in its home control area that are for export to that 

outside competitive market.932 Rather than protecting the ultimate buyers, these 

commenters submit that mitigating such sales would transfer wealth from the 

mitigated seller to subsequent entities that can charge market prices in later 

transactions.933

802. MidAmerican and the Oregon Commission claim that if the Commission 

requires mitigated sellers to mitigate all their sales in the mitigated market such an 

 931 MidAmerican at 26; Oregon Commission reply comments at 5; see also Westar 

at 20. 

932 MidAmerican at 25-26; see also Dr. Pace at 18-20. 

933 MidAmerican at 26; Oregon Commission reply comments at 5. 
Docket No. RM04-7-000 455 

outcome would encourage gaming, such as round-trip or ricochet transactions.934 

MidAmerican maintains that such gaming can be eliminated when mitigation applies 

only to sales sinking within the mitigated control area.935 

803. Duke, E.ON U.S., Westar, Mid-American, Ameren, and Xcel all assert that the 

availability of supply alternatives to wholesale purchasers should be a determining 

factor when deciding whether to permit market-based rates for sales that sink in 

unmitigated markets.936 E.ON U.S. points out that the Commission in the April 14 

Order noted that the foundation of the market power analysis under the Delivered 

Price Test is the “destination market.” As such, E.ON U.S. asserts that a relevant 

factor in determining whether to permit a sale at market-based rates should be the 

level of choice in supply available to the purchaser, not where the product 

originates.937 

804. Westar contends that when the buyer is purchasing to serve load in control 

areas where the seller lacks market power, the buyer presumably has access to other 

competitive alternatives and has voluntarily entered into the agreement. Therefore, 

 934MidAmerican at 26-27; Oregon Commission reply comments at 6. 

935 MidAmerican at 27. 

936 Duke at 13; E.ON U.S. at 6; Westar at 20; MidAmerican at 25; Ameren at 19-

20; and Xcel at 13. 

937 E.ON U.S. at 6. 
Docket No. RM04-7-000 456 

the Commission should not second guess the buyer’s decision.938 Westar adds that 

prohibiting all sales in the mitigated control area elevates form over substance 

because parties can simply alter the implementing details of their transaction to 

accomplish the same result.939

805. Westar argues that the Commission’s stated concern in MidAmerican with a 

seller’s “ability to attempt to exercise market power over sales in its control area” is 

misplaced; the Commission’s traditional market power analysis is only concerned 

with the “incentive” and “ability” to exercise market power, not with “attempts” to do 

so.940 As such, it is “ability” and not “attempts” to exercise market power that is a 

key determinant of whether an actual market power problem exists. 

806. Westar further claims that the Commission is not bound by precedent to 

prohibit all market-based rate sales in a mitigated control area, pointing out that the 

Commission has accepted four proposals after the July 8 Order that limit mitigation 

 938 Westar at 20. 

939 Id. at 21. 

940 Id. at 21 (citing MidAmerican Energy Company, 114 FERC ¶ 61,280 (2006), 

reh’g pending; Exelon Corp., 112 FERC ¶ 61,011, at P 134 (“As we have said in 

numerous contexts, we are concerned about a merger’s effect on the merged firm’s ability 

and incentive to harm competition.”), order on reh’g, 113 FERC ¶ 61,299 (2005); 

Oklahoma Gas and Electric Company, 105 FERC ¶ 61,297, at P 35 (2003) (“Both the 

ability and incentive to raise prices by restricting access are necessary for a vertical 

market power problem to exist.”); NiSource Inc., 92 FERC ¶ 61,068, at 61,239 (2000) 

(“Because the merged company must have both the ability and incentive to adversely 

affect electricity prices or output, and the merged company will lack the former, no 

further findings are necessary.”)). 
Docket No. RM04-7-000 457 

to sales that sink in the mitigated control areas.941 Moreover, Westar claims that the 

July 8 Order appears to address the question of who may buy power from a mitigated 

seller, not where mitigated sales can occur. This leads Westar to conclude that the 

Commission did not originally intend to preclude mitigated sellers from making 

market-based sales to buyers over which the seller lacks generation market power, 

regardless of where the sales occur. Westar urges the Commission to return to this 

principle.942

807. Xcel urges the Commission to focus on the parties’ intent and whether 

alternative supply options are available to the purchaser at the time of contracting, 

rather than focusing on where energy purchased in the transaction actually sinks in 

real time. At the time of the transaction, if the purchaser can confirm: (i) it intends to 

use the power outside of the mitigated control area, and (ii) there are existing 

transmission arrangements to actually use the power elsewhere, Xcel maintains that it 

should not matter what the purchaser subsequently does with the power in real 

 941 Id. at 22 (citing American Electric Power Service Corp., Docket Nos. ER96-

2495-026, et al. (Jan. 13, 2006) (letter order accepting uncontested settlement applying 

mitigation to sales that sink in the mitigated control area); AEP Power Marketing, Inc., 

112 FERC ¶ 61,320 (2005) (dismissing rehearing requests as moot because of utility’s 

commitment to mitigate sales “that sink within AEP-SPP”); South Carolina Electric and 

Gas Company, 114 FERC ¶ 61,143 (2006) (order accepting utility’s commitment to 

mitigate sales that “sink” in its home control area, subject to a compliance filing); LG&E 

Energy Marketing, Inc., 113 FERC ¶ 61,229 (2005) (ordering the utility to apply the 

proposed mitigation to sales that sink in the mitigated control area)). 

942 Westar at 22-23. 
Docket No. RM04-7-000 458 

time.943 Xcel and MidAmerican also favor adopting market-index or proxy based 

mitigation as a way to reduce the concern about where sales actually sink when trying 

to ensure proper mitigation.944 

808. EEI, PPL, PNM/Tucson, and Pinnacle take the position that the Commission 

should consider point of delivery when deciding whether to permit market-based rate 

sales.945 EEI asks the Commission to allow mitigated sellers to make market-based 

rate sales if the delivery point in the contract or sale confirmation is outside the 

mitigated market, or if the buyer has transmission service to take the power outside 

the mitigated market. In other words, buyers who choose delivery points inside the 

mitigated market and do not move the power out will pay mitigated rates, but buyers 

who choose delivery points inside the mitigated market but move the power outside 

the mitigated market will pay market-based rates.946 

809. EEI asserts that its proposal is consistent with the Commission policy that the 

mitigation must focus on the geographic market that is mitigated, not the type of 

customer purchasing the power. EEI concludes that the proposal will minimize the 

 943 Xcel at 13. While MidAmerican does not object to Xcel’s proposal, it submits 

that its own proposal regarding use of market-based indices would provide additional 

assurance that a seller would not manipulate prices by arranging round-trip transactions 

into a mitigated control area. MidAmerican reply comments at 19-20. 

944 Xcel at 11-138, ; MidAmerican reply comments at 4. 

945 EEI at 38; PPL at 25 (supporting EEI’s comments); Pinnacle at 9; PNM/Tucson 

at 14-15. 

946 EEI at 38. 
Docket No. RM04-7-000 459 

impacts on competitive transactions as well as avoid a remedy that will have a 

negative impact on the liquidity of the competitive market.947 

810. PNM/Tucson agree that the Commission should use the point of delivery as a 

determining factor. They contend that transmission tags alone - which they explain 

are a reliability tool to ensure systems balance from a transmission perspective - are 

inadequate to monitor market transactions or ensure that sales sink outside a 

mitigated control area.948

811. PNM/Tucson, Pinnacle, E.ON U.S., MidAmerican and PPL all generally argue 

that sales at or beyond the transmission interface of a mitigated control area should 

not be mitigated if the seller lacks market power in the adjacent control area.949 

MidAmerican asserts that the Commission’s market power analyses demonstrate that 

the seller has no market power over sales at the border (sales requiring no additional 

transmission to exit the mitigated region).950 PNM/Tucson, Pinnacle and E.ON U.S. 

maintain that prohibiting market-based rate sales at these transmission interfaces 

 947 EEI at 41. 

948 PNM/Tucson at 14-15. 

949 PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 5-8; MidAmerican at 29-30; 

PPL reply comments at 16. 

950 MidAmerican at 29-30. 
Docket No. RM04-7-000 460 

would prevent cross border sales at these unique locations and reduce market 

liquidity in markets where the seller does not possess market power.951 

812. E.ON U.S. and MidAmerican urge the Commission to view interface/border 

transactions as fundamentally different from sales in, or sinking in, a control area. 

These commenters reason that, at transmission interfaces, a buyer has competitive 

choices from sellers in both control areas that abut the interface, as well as from any 

seller that can transmit power to that interface from any control area. As a result, 

buyers taking title to power at a transmission interface for delivery outside the 

mitigated control area have competitive choices that do not require transacting with 

the supplier found to have market power within the mitigated control area(s).952 

Moreover, E.ON U.S. claims that mitigating transactions at control area interfaces 

could reduce a utility’s profits from off-system sales, thereby affecting retail 

ratepayers by reducing offsets that affect the costs of their retail rates.953 

813. PNM/Tucson, Pinnacle, E.ON U.S., and MidAmerican note that the 

Commission indicated in LG&E that sales at the border need not be mitigated along 

with sales “wholly in” a control area.954 PNM/Tucson and MidAmerican urge the 

 

 (continued...) 

 

951 PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 8.

952 E.ON U.S. at 6; MidAmerican reply comments at 22-23. 

953 E.ON U.S. at 8. 

954 PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 8; MidAmerican reply 
Docket No. RM04-7-000 461 

Commission to codify in the Final Rule LG&E’s holding that sales at the 

transmission interface of a mitigated control area are not “in” the control area, and 

therefore need not be mitigated.955 E.ON U.S. similarly asks the Commission to 

define sales “in” a control area as those where title to power transfers at a physical 

location wholly within such control area, and should not include sales where title 

transfers at a transmission interface.956

814. Xcel, in comparison, argues that any buyer purchasing power at a generator 

bus or elsewhere in a mitigated control area for purposes of moving that power out of 

the mitigated market should be treated no differently than a buyer who takes delivery 

of purchased power outside of the mitigated region. According to Xcel, mitigation to 

discipline market power is unnecessary in either of these cases and the location of the 

delivery point does not matter.957

815. Both Dalton Utilities and the Carolina Agencies state that it would be wrong to 

assume that every contract involving a mitigated supplier is unjust and unreasonable 

and must be abrogated to protect consumers.958 Dalton Utilities urge the Commission 

 

comments at 23. 

955 PNM/Tucson at 16; MidAmerican reply comments at 23. 

956 E.ON U.S. at 5. 

957 Xcel at 12. 

958 Dalton Utilities reply comments at 4-9; Carolina Agencies at 22-23. 
Docket No. RM04-7-000 462 

to clearly state in the final rule that it does not generically abrogate existing long-term 

market-based rate wholesale requirements and transmission contracts, nor is it 

requiring such abrogation in subsequent proceedings that revoke the market-based 

rate authority of a public utility found to possess market power.959 Dalton Utilities 

asks the Commission to grandfather existing long-term market-based wholesale 

contracts in the final rule.960

816. The Carolina Agencies add that the effect on existing contracts of a decision to 

retain the current mitigation policy of prohibiting sales at market-based rates in a 

mitigated market should be determined on a case-by-case basis. These entities reason 

that simply because market power may exist (or a presumption that it exists has not 

been rebutted) does not in every instance mean that the seller actually abused its 

market position to extract unreasonable terms from its purchaser. The circumstances 

of each contract must be examined to determine whether its terms reflect the exercise 

of market power. The Carolina Agencies and Dalton Utilities conclude that generic 

abrogation or reformation of existing agreements is neither warranted nor consistent 

 959 Dalton Utilities reply comments at 6, 9. 

960 Id. at 6-7. Duke notes its support for the Commission’s current policy of not 

reforming or abrogating contracts that were negotiated prior to the time of any finding of 

market power. Duke reply comments at 8, n.12. 
Docket No. RM04-7-000 463 

with the Commission’s manner of resolving other claims of broad-based 

discrimination.961

Commission Determination

817. In order to protect customers from market power concerns, we will continue to 

apply mitigation to all sales in the balancing authority area in which a seller is found, 

or presumed, to have market power. However, as discussed below we will allow 

mitigated sellers to make market-based rate sales at the metered boundary962 between 

a mitigated balancing authority area and a balancing authority area in which the seller 

has market-based rate authority under certain circumstances. 

818. Commenters advocating allowing market-based rate sales in a mitigated 

market provided the power is intended for an unmitigated market (e.g., applying 

mitigation only to sales that sink in the mitigated market) have failed to adequately 

explain how customers in the mitigated market would be protected from the potential 

exercise of market power. In addition, commenters have failed to adequately address 

how the Commission could effectively monitor such sales to ensure that improper 

sales were not being made. Indeed, several commenters have noted the complex 

 961 Carolina Agencies at 23; Dalton Utilities reply comments at 7-9. 

962 North American Electric Reliability Corporation. Glossary of Terms Used in 

Reliability Standards at 2 (2007), available at 

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Glossary_02May07.pdf. 
Docket No. RM04-7-000 464 

administrative problems that would be associated with trying to monitor compliance 

with such a policy.963

819. Allowing market-based rate sales by a seller that has been found to have 

market power, or has so conceded, in the very market in which market power is a 

concern is inconsistent with the Commission’s responsibility under the FPA to ensure 

that rates are just and reasonable and not unduly discriminatory. While we generally 

agree that it is desirable to allow market-based rate sales into markets where the seller 

has not been found to have market power, we do not agree that it is reasonable to 

allow a mitigated seller to make market-based rate sales anywhere within a mitigated 

market. It is unrealistic to believe that sales made anywhere in a balancing authority 

area can be traced to ensure that no improper sales are taking place. Such an 

approach would also place customers and competitors at an unreasonable 

disadvantage because the mitigated seller has dominance in the very market in which 

it is making market-based rate sales. 

820. However, we do recognize that sales made at the metered boundary for export 

do lend themselves to being monitored for compliance, and the nature of these types 

of sales do not unduly disadvantage customers or competitors. Prohibiting marketbased rate sales at these metered boundaries of the balancing authority area could 

prevent or adversely impact cross border sales at these unique locations and reduce 

 963 For example, PNM/Tucson note that transmission tags alone are inadequate to 

monitor market transactions. PNM/Tucson at 14-15. 
Docket No. RM04-7-000 465 

market liquidity in markets where the seller does not possess market power. Buyers 

taking title to power at a metered boundary for delivery to serve load in a balancing 

authority area where the seller has market-based rate authority have competitive 

choices and therefore are not required to transact with the seller found to have market 

power within the mitigated balancing authority area(s). 

821. Accordingly, we will allow such sales to be made at market-based rates. 

Mitigated sellers making such sales must maintain for a period of five-years from the 

date of the sale all data and information related to the sale that demonstrates that the 

sale was made at the metered boundary between the mitigated balancing authority 

area and a balancing authority area in which the seller has market-based rate 

authority, that the sale is not intended to serve load in the seller’s mitigated market, 

and that no affiliate of the mitigated seller will sell the same power back into the 

mitigated seller’s mitigated market. 

822. Such an approach properly balances commenters’ concerns that when a buyer 

purchases power to serve load in markets where the mitigated seller lacks market 

power the buyer has access to competitive alternatives with the Commission’s 

obligation under the FPA to ensure that rates are just and reasonable. Further, we 

find that our approach in this regard does not place an unreasonable burden on the 

customer, mitigated seller, or competitors. We also emphasize that the mitigation we 

adopt herein is prospective only. In response to Dalton’s concern, we clarify that 
Docket No. RM04-7-000 466 

such mitigation does not modify, abrogate, or otherwise affect existing contractual 

agreements.964 

823. Further, we disagree with the Carolina Agencies’ contention that short of a 

“must-offer” provision unrestricted exports from a mitigated market increase the 

prices charged by other suppliers due to scarcity. Carolina Agencies’ argument 

would only apply when the market prices in the first-tier markets are higher than the 

seller’s cost-based rate in the mitigated market. This situation is not necessarily 

always the case and, therefore, the Carolina Agencies’ concern may be based on an 

unrealistic assumption. 

824. We disagree with MidAmerican and the Oregon Commission’s claim that if 

the Commission requires mitigated sellers to mitigate all their sales in the mitigated 

market this would encourage gaming, such as round-trip or ricochet transactions. 

While the Commission issued an order rescinding Market Behavior Rules 2 and 6,965

Order No. 670 finalized regulations prohibiting energy market manipulation pursuant 

to the Commission’s new Energy Policy Act of 2005 authority. The Commission 

emphasized in Order No. 670 that “the specific prohibitions of Market Behavior Rule 

 964 See South Carolina Electric and Gas Co., 114 FERC ¶ 61,143 at P 18 (2006) 

(accepting mitigation on a prospective basis; existing long-term agreements remain in 

effect until terminated pursuant to their terms); see also April 14 Order, 107 FERC ¶ 

61,018 at P 154; July 8 Order, 108 FERC ¶ 61,026 at P 145. 

965 Investigation of Terms and Conditions of Public Utility Market-Based Rate 

Authorizations, 114 FERC ¶ 61,165 (2006). 
Docket No. RM04-7-000 467 

2 (wash trades, transactions predicated on submitting false information, transactions 

creating and relieving artificial congestion, and collusion for the purpose of market 

manipulation), ... are examples of prohibited manipulation, all of which are 

manipulative or deceptive devices or contrivances, and are therefore prohibited 

activities under this Final Rule, subject to punitive and remedial action.”966 Such 

fraud and manipulative conduct therefore remains prohibited and subject to the 

Commission’s anti-manipulation and civil penalty authority. 

d. Proposed Tariff Language

Comments

825. Several commenters have proposed specific tariff language in the event the 

Commission allows market-based rate sales in the mitigated market or at the border. 

For example, PNM/Tucson would require a sale to “have a contractual point of 

delivery at or beyond the transmission interface of the mitigated control area 

(assuming that the point of delivery is not in another control area where the seller is 

also mitigated).”967 They would also require the seller’s market-based rate tariff to 

explicitly prohibit efforts to collude with a third party to sell to customers in the 

mitigated control area at market-based rates.968 

 966 Prohibition of Energy Market Manipulation, Order No. 670, 114 ¶ FERC 

61,047 at P 59 (2006). 

967 PNM/Tucson at 15. 

968 Id. 
Docket No. RM04-7-000 468 

826. PNM/Tucson point out that their proposal contains a significant concession. 

Under their proposed language, a sale by a mitigated seller at the generation bus in 

the mitigated control area must be made at mitigated rates. They believe this 

concession is fair if the Commission insists that market-based rate sales for mitigated 

sellers are based on contractual points of delivery at or beyond the transmission 

interface of the mitigated control area. In these companies’ view, such an approach 

would provide needed certainty through a bright line rule and limit factual disputes 

and investigations.969 

827. MidAmerican and Ameren also support using tariff or agreement language to 

ensure power sinks outside of the mitigated market.970 MidAmerican favors using 

tariff safeguards and confirmation/oversight procedures to mitigate a seller’s ability 

to exercise generation market power, prevent gaming, and protect wholesale 

customers in the mitigated region. MidAmerican submits that it has developed and 

filed market-based rate tariff provisions and verification and oversight procedures 

that can ensure that export transactions sink outside the mitigated seller’s control 

area.971 MidAmerican argues that its approach correctly focuses on whether the 

 969 Id. at 16-17; MidAmerican submits that its proposal would also provide the 

“bright-line” regulatory certainty sought by PNM/Tucson. MidAmerican reply 

comments at 16-18. 

970 MidAmerican at 28; Ameren at 19-20. 

971 Under MidAmerican’s proposed tariff revisions: (i) counterparties would be 

required to affirmatively confirm that the energy sold within MidAmerican’s control area 

 (continued...) 

 
Docket No. RM04-7-000 469 

mitigated seller could exercise market power over transactions that affect entities that 

purchase on behalf of, or for re-sale to, loads within the market subject to mitigation, 

rather than the geographical location where customers may take responsibility for 

transmitting the power to a final destination. Moreover, MidAmerican claims that its 

proposal would allow the market to work efficiently in areas where the mitigated 

seller’s ability to exercise market power is not an issue. MidAmerican supports a 

Commission technical conference to further explore this concept with interested 

parties.972

828. Several commenters further propose that mitigated sellers be required to add 

language to their market-based rate tariffs or to specific market-based rate contracts 

to restrict re-sales from sinking in the mitigated control area.973 FP&L argues that 

 

will not stay inside that control area; (ii) MidAmerican energy schedulers will review 

NERC tags associated with in-control area sales on a daily basis to ensure transactions 

indeed sink outside the mitigated control area; (iii) if a review of the NERC tags shows 

that a transaction will sink inside the mitigated control area, the sale will be renegotiated 

at cost-based rates; and (iv) if required by the Commission, MidAmerican would submit 

the NERC tag data to the appropriate market monitor. MidAmerican at 28-29. 

972 MidAmerican at 28-29. 

973 FP&L at 6 (proposing the following tariff language: “Purchasers are hereby on 

notice that the sink for any energy or capacity sale under this Tariff shall not be in the 

Seller’s control area.”); E.ON U.S. at 10 (proposing “a simple tariff commitment by 

sellers that power sold at a point of delivery within their mitigated control area will, to 

the best of their knowledge, sink elsewhere.”); Ameren at 20 (proposing that agreements 

governing market-based rate sales in mitigated markets explicitly state that the subject 

power will sink outside the mitigated region, and that the seller be required to report such 

sales in its EQR). 
Docket No. RM04-7-000 470 

requiring such language would reinforce the idea that re-sales into mitigated control 

areas are violations of a Commission-approved tariff that also, depending on the 

facts, might violate the Commission’s market manipulation regulations.974 

829. Another commenter agrees that restrictive language in the market-based rate 

tariff could prevent re-sales into the mitigated control area by helping to ensure that 

any power purchased at market-based rates within a mitigated control area is 

exclusively for export to serve loads beyond the mitigated market. Where the 

Commission is concerned that gaming could lead to the exercise of market power 

over wholesale customers in the home control area, this commenter suggests that the 

Commission reemphasize that efforts to loop power through an adjacent market area 

in order to raise prices to wholesale customers in mitigated areas above competitive 

levels is a violation of market-based rate tariffs. Further, this commenter submits that 

the Commission may require buyers to confirm that power purchased at market-based 

rates in a mitigated control area is for export, use NERC tag data and transmission 

scheduling information to verify when purchased power is being exported from the 

home control area, and require oversight by independent market monitors.975

 974 FP&L at 6. 

975 Dr. Pace at 20-21. 
Docket No. RM04-7-000 471 

Commission Determination

830. Consistent with our decision above, mitigated sellers choosing 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 will be required to commit and maintain sufficient documentation to 

demonstrate976 that: (1) legal title of the power sold transfers at the metered boundary 

between a mitigated balancing authority area and one in which the mitigated entity 

has market-based rate authorization; and (2) any power sold is not intended to serve 

load in the seller’s mitigated market and (3) no affiliate of the mitigated seller will 

sell the same power back into the mitigated seller’s mitigated market. To accomplish 

these requirements, mitigated sellers seeking to make market-based rate sales at the 

metered boundary between their mitigated balancing authority area and a balancing 

authority area in which the sellers have market-based rate authority must adopt the 

following tariff provision: 

Sales of energy and capacity are permissible under this tariff in all balancing 

authority areas where the Seller has been granted market-based rate authority. 

Sales of energy and capacity under this tariff are also permissible at the metered 

boundary between the Seller’s mitigated balancing authority area and a balancing 

authority area where the Seller has been granted market-based rate authority 

provided: (i) legal title of the power sold transfers at the metered boundary of the 

balancing authority area where the seller has market-based rate authority; (ii) any 

 976 Reliance solely on NERC tag data as documentation for such sales will likely 

be deemed insufficient as such an approach has not yet been shown to be either workable 

or effective. 
Docket No. RM04-7-000 472 

power sold hereunder is not intended to serve load in the seller’s mitigated market; 

and (iii) no affiliate of the mitigated seller will sell the same power back into the 

mitigated seller’s mitigated market. Seller must retain, for a period of five years 

from the date of the sale, all data and information related to the sale that 

demonstrates compliance with items (i), (ii) and (iii) above. 

 

831. This approach affords necessary protection from market power abuse for 

customers in the mitigated markets. Such language reminds all sellers that gaming 

resulting in re-sales of any sort by an affiliate of the mitigated seller into their 

mitigated balancing authority area(s) (i.e., by looping power through adjacent 

markets) are violations of a Commission-approved tariff that may also, depending on 

the facts, violate the Commission’s market manipulation regulations. Such violations 

may result in penalties being imposed under the market manipulation regulations 

and/or the revocation of a mitigated seller’s market-based authority in all markets. 

E. Implementation Process

Commission Proposal

832. In the NOPR, the Commission put forth several proposals to streamline the 

administration of the market-based rate program while maintaining a high degree of 

oversight. The Commission proposed to modify the practice of requiring an updated 

market power analysis to be submitted within three years of any order granting a 

seller market-based rate authority and every three years thereafter by, instead, putting 

in place a structured, systematic review based on a coherent and consistent set of 

data. First, the Commission proposed to establish two categories of sellers with 
Docket No. RM04-7-000 473 

market-based rate authorization. Sellers in the first category, Category 1,977 would 

not be required to file a regularly scheduled updated market power analysis. The 

Commission proposed instead to monitor any market power concerns for Category 1 

sellers through the change in status reporting requirement and through ongoing 

monitoring by the Commission’s Office of Enforcement. In this regard, the 

Commission noted that failure to timely file a change in status report would constitute 

a violation of the Commission’s regulations and the seller’s market-based rate tariff. 

833. Sellers in Category 2, consisting of all sellers that do not qualify for Category 

1, would be required to file regularly scheduled updated market power analyses in 

addition to change in status reports. The Commission proposed to codify this 

requirement in its regulations. Failure to timely file an updated market power 

analysis would constitute a violation of the Commission’s regulations and the seller’s 

market-based rate tariff. 

834. Second, to ensure greater consistency in the data used to evaluate Category 2 

sellers, the Commission proposed that the required updated market power analyses be 

filed for each seller’s relevant geographic market(s) on a schedule allowing 

 977 Category 1 sellers would include power marketers and power producers that 

own or control 500 MW or less of generating capacity in aggregate and that are not 

affiliated with a public utility with a franchised service territory. Category 1 sellers also 

must not own or control transmission facilities other than limited equipment necessary to 

connect individual generating facilities to the transmission grid (or must have been 

granted waiver of the requirements of Order No. 888 because the facilities are limited and 

discrete and do not constitute an integrated grid), and they must not present other vertical 

market power issues. NOPR at P 152. 
Docket No. RM04-7-000 474 

examination of the individual seller at the same time that the Commission examines 

other sellers in the relevant markets and contiguous markets within a region from 

which power could be imported. The Commission appended a proposed schedule for 

the regional review process, rotating by geographic region with three regions being 

reviewed per year. For corporate families that own or control generation in multiple 

control areas and different regions, the Commission proposed that the corporate 

family would be required to file an update for each region in which members of the 

corporate family sell power during the time period specified for that region. 

835. Finally, the Commission proposed to require that all updated market power 

analyses and all new applications for market-based rate authority include an appendix 

listing all generation assets owned or controlled by the corporate family by control 

area, listing the in-service date and nameplate and/or seasonal ratings by unit, and all 

electric transmission and natural gas intrastate pipelines and/or gas storage facilities 

owned or controlled by the corporate family and their location. 

1. Category 1 and 2 Sellers

Comments

a. Establishment of Category 1 and 2 Sellers

836. A variety of commenters fully support the Commission’s proposed 

categorization of sellers into two categories and the boundaries of those categories. 

ELCON comments that the Commission’s limited resources should be focused on the 
Docket No. RM04-7-000 475 

dominant players and not treat every seller as a potential threat. NRECA commends 

the Commission for its attempt to streamline the process.978 APPA/TAPS support the 

proposed categories but suggest that the Commission clarify that it retains the ability 

to determine that a Category 1 seller must still adhere to the triennial update 

requirements if, for example, it is dominant in a particular load pocket. Explaining 

that its generation and power marketing activities are only incidental to its mining 

operations, and that its market share will likely decline over time, Newmont states 

that filing an updated market analysis every three years would be an unnecessary 

burden to prepare and a waste of the Commission’s time to review. Newmont finds 

the 500 MW cutoff a clear, bright line that would be easy to administer. If the 

Commission determines it necessary to adjust the threshold, however, Newmont 

suggests retaining the 500 MW cutoff with a further requirement that no more than 

250-300 MW be located in any one control area. Alternatively, there could be some 

sliding scale delineation between Categories 1 and 2 based on the size of a control 

area, in terms of load, unaffiliated capacity, or both. 

837. Financial Companies and Morgan Stanley request that the Commission release 

a list of all sellers in each category and the region in which the Commission believes 

each seller belongs to help ensure that sellers have notice of their status and related 

 978 See also EPSA reply comments at 3, 13-14. 
Docket No. RM04-7-000 476 

filing obligations. These parties also suggest that the Commission hold a technical 

conference on commenters’ proposals about how to organize the categories. 

838. FirstEnergy opposes the concept of exempting Category 1 sellers from 

triennial reporting while continuing the requirement for Category 2 sellers. 

FirstEnergy states that there is no reason for the Commission to require any public 

utility authorized to sell at market-based rates to file an updated market power 

analysis. According to FirstEnergy, the showing made in the initial market-based rate 

proceeding and the change in status rules are adequate, and relieving Category 1 

sellers from filing without abolishing the requirement entirely would be unduly 

discriminatory. 

839. On the other hand, the California Commission believes that all sellers should 

have to continue filing updated market power analyses; it states that the assumption 

that Category 1 sellers do not need the same level of scrutiny as larger sellers is 

erroneous, and argues that the NOPR provides no legitimate justification for creating 

a disparity between Category 1 and 2 sellers. The California Commission continues 

by stating that reliance solely on market monitoring would not necessarily be 

effective in California. It notes that in markets utilizing LMP, there is a great 

potential for sellers to exert “local” market power, especially in load pockets. In such 

load pocket areas, it contends that there is no guarantee that a small seller could not 

have market power. Further, it states that a Category 1 seller could suddenly gain 

market power due to another seller’s withdrawal from the market and asserts that 

“given the number of markets and the Commission’s limited resources, it would seem 
Docket No. RM04-7-000 477 

an enormous task of monitoring without requiring regular updated market power 

analyses from all market participants.”979 

840. Similarly, NASUCA states that there is no basis in the record to assume that 

Category 1 sellers would lack market power at all times and offers examples of when 

Category 1 sellers could pose a problem.980 NASUCA also warns that there is no 

apparent limit on the total amount of exempt generation that could be owned by 

entities other than those affiliated with a franchised utility. Specifically, NASUCA 

argues that: 

[U]nder the [Category 1] definition and [change of status] notice obligations, a 

“Category 1” seller could qualify for exemption from triennial market power 

reviews even if its holding company affiliates – other power marketing and 

generation entities that also have “Category 1” status – collectively have a share of 

generation far larger than 500 MW, and even if the seller has a retail affiliate 

without a franchised service territory. Examples might include a group of 

“Category 1” peaker plant owners in a constrained area, each owned by a separate 

entity affiliated with the same holding company; owners of a fleet of small hydro 

facilities, each a separate entity within a holding company structure; or an 

assemblage of generation control [sic] by numerous power marketing subsidiaries, 

each of which controls less than 500 MW of generation.[981] 

 979 California Commission at 4. 

980 For example, NASUCA asserts that there appears to be a possibility that a 

seller with a fleet of newer power plants that were initially exempted from review would 

be totally exempt from subsequent review based on the size of the power plants. These 

sellers might at times have market power with respect to ancillary services. NASUCA 

further submits that changed circumstances, such as declining reserve margins, might 

create opportunities for seemingly small sellers to exercise market power. 

981 NASUCA at 12. See also NASUCA reply comments at 9-11 (stating that 

neither the 500 MW exemption, nor the expansion to a 1000 MW exemption, nor the 

elimination of a horizontal market power test, should be adopted). 
Docket No. RM04-7-000 478 

841. Thus, NASUCA argues that the regulations should be modified or clarified to 

prevent this scenario. If the Commission proceeds with its proposal, NASUCA states 

that the Commission should consider a much lower threshold, such as 75 MW. 

842. State AGs and Advocates state that exempting entities, no matter how small, 

would conflict with the concept that all sellers contribute in varying degrees to the 

existence of market power in a market.982

843. NASUCA and the California Commission argue that none of the proponents of 

an exempt category of sellers have shown how the exemption meets the 

Commission’s legal requirements.983 NASUCA expresses concern that the blanket 

exemption for Category 1 sellers from filing updated market power reviews is 

inconsistent with the justification the Commission has previously made to the courts 

in support of market-based rates, namely, that the Commission makes a discrete 

finding or determination as to each seller’s market power, and periodically reviews it. 

The California Commission similarly disputes that the exemption meets the 

underlying principle found in Lockyer. It states that the Ninth Circuit in that case 

noted that the Commission’s authority to grant market-based rates is rooted in the 

integral nature of the reporting requirements. The California Commission asserts that 

 982 State AGs and Advocates reply comments at 14. 

983 NASUCA reply comments at 9-11, California Commission reply comments at 

1-4. 
Docket No. RM04-7-000 479 

the proposed requirement for Category 1 sellers to make a filing only upon a change 

in status is inconsistent with the rationale laid out in Lockyer. It further contends that 

delegation of ongoing monitoring to the Commission’s Office of Enforcement is 

vague and contrary to the underlying principle found in Lockyer. According to the 

California Commission, the assumptions underlying the proposed Category 1 

exemption (that since Category 1 sellers are smaller in size they do not need to be 

subject to the same requirements and scrutiny as larger sellers of energy, and that 

“’Category 2 sellers are the larger sellers with more of a presence in the market and 

are more likely to fail one or more of the indicative screens or pass by a smaller 

margin than Category 1 sellers’”) are insufficient to justify a departure from the 

Lockyer rationale.984 

844. PPM refutes the California Commission’s arguments. First, PPM asserts that 

the California Commission is wrong in its generalization that a seller that controls 

less than 500 MW in a market that utilizes LMP could exert local market power. 

PPM argues that the existence of an LMP market does not increase the potential for a 

small generator or marketer to possess market power; LMP is intended to reduce the 

ability of a party to exercise local market power.985 Second, PPM states that the 

California Commission is wrong when it asserts that Lockyer requires the 

 984 California Commission reply comments at 3-4 (quoting NOPR at P 153). 

985 PPM reply comments at 1-3. 
Docket No. RM04-7-000 480 

Commission to require all sellers to file updated market power analyses. According 

to PPM, in Lockyer, the Court found that if the Commission is going to grant parties 

the authority to charge market-based rates, the Commission must continue to monitor 

and ensure that the rates charged are just and reasonable. PPM submits that creating 

a categorical exemption to reduce the burden on smaller generators and marketers 

does not mean that the Commission is eliminating its ability to effectively monitor 

the wholesale electric market. It states that the Commission retains the tools 

necessary to ensure that all rates are just and reasonable: all entities with marketbased rate authority must submit electric quarterly reports to the Commission 

regarding their transactions; all parties have the right to ask the Commission for relief 

under section 206 of the FPA if they believe that rates are improper or unjust; the 

Commission may take up an independent review of any markets which are displaying 

abnormal characteristics; and finally, the Commission may require certain parties to 

file updated market power analyses if the seller is found to have market power even if 

the seller meets the threshold for Category 1 exemption. 

b. Threshold for Category 1 Sellers and Other Proposed Modifications

845. While the majority of commenters support the concept of exempting smaller, 

Category 1 sellers from filing updated market power analyses, many seek 

clarification or modification of the proposal. A number of commenters propose a 

threshold other than ownership or control of 500 MW or less in aggregate. Suggested 
Docket No. RM04-7-000 481 

thresholds include: 500 MW or less of uncommitted capacity (therefore including 

only that which is available for sale into markets during peak periods);986 500 MW 

within a particular control area;987 500 MW within a geographic market;988 500 MW 

within a particular region;989 up to 1000 MW;990 less than 1 percent of the installed 

capacity in a regional market or 1000 MW in that regional market (whichever is 

higher);991 or some other formula.992 Several commenters urge the Commission to 

consider the size of a particular control area or geographic region or market and 

 986 See Ormet at 9. 

987 See, e.g., PPM at 3-4; AWEA at 3-4. 

988 See Constellation at 8-9 (noting that this would be consistent with the 

Commission’s indicative screen analysis and regional approach to updated market power 

analyses). 

989 EPSA at 36-37; AWEA at 3-4; Suez/Chevron at 5-10. 

990 See Morgan Stanley at 10-13; Financial Companies at 13-14; Financial 

Companies reply comments at 7-8. See also Mirant at 12 (recommending 1000 MW per 

geographic market if the Commission hopes to have a minimal impact on sellers’ 

compliance costs caused by eliminating the 18 CFR 35.27(a) exemption). 

991 EPSA at 36-37. 

992 Constellation at 9-11 (supports changing threshold from 500 MW to the greater 

of 500 MW or 2 percent of the total generation capacity in the relevant geographic 

market; where the geographic market is an RTO or ISO, change threshold to the greater 

of 1,000 MW or 2 percent of the total generation capacity in that market); Ameren at 21 

(supports exempting a company that owns or controls more than 500 MW but owns or 

controls less than 20 percent of the total uncommitted capacity in the relevant geographic 

market and also is not affiliated with an entity that owns transmission facilities in that 

market). 
Docket No. RM04-7-000 482 

whether the geographic market is served by an RTO/ISO,993 and to take into account 

the difference between thermal generating capacity and intermittent or nondispatchable generation for their ability to impact the competitiveness of a market.994

846. PPM argues that without certain modifications to the Commission’s definition 

of a Category 1 seller, which PPM believes is too narrowly defined, many generators 

and marketers may needlessly have to submit an updated market power analysis. 

According to PPM, the Commission should not eliminate the exemption for new 

generation (pursuant to 18 CFR 35.27(a)) without expanding the group of generators 

and marketers eligible for Category 1 status.995 Several commenters also urge the 

Commission to allow fact-specific requests for exemption from filing requirements 

for those sellers who otherwise would qualify as Category 2 sellers996 or other 

particular exemptions.997

 993 Drs. Broehm and Fox-Penner at 13; Constellation at 9; PPM at 3-4. 

994 AWEA at 3-4 (asserting that companies owning or controlling thermal 

generating capacity have a greater opportunity for impacting the competitiveness of a 

market than those that own or control non-dispatchable generation, such as wind power 

facilities, that rarely achieve production at nameplate capacity levels); PPM at 4 (same); 

Financial Companies reply comments at 8-9. 

995 PPM at 3-5. 

996 See Morgan Stanley; Financial Companies. 

997 See, e.g., Ormet at 7-11 (exemption for self use/supply, i.e., capacity used to 

self supply a corporate affiliate and presumptively unavailable for sale into markets); 

TXU at 4-5 (case-by-case determination of whether a seller’s affiliation with an entity 

that owns or controls Commission-jurisdictional transmission presents the possibility of 

vertical market power concerns). 
Docket No. RM04-7-000 483 

847. In addition, Constellation proposes specific modifications to the proposal. 

First, Constellation requests that the Commission change the affiliation standard in 

the definition of Category 1 sellers to be consistent with other definitions set forth in 

the NOPR. Because the proposed language would exclude from the definition of 

Category 1 sellers any affiliate of a public utility with a franchised service territory 

regardless of whether it has captive customers, Constellation suggests using the 

defined term “franchised public utility”998 instead of “public utility with a franchised 

service territory.” Constellation states that the exclusion should only apply to 

affiliates of public utilities with captive customers. Second, Constellation argues that 

a company should be considered to be a Category 1 seller so long as it is not affiliated 

with a “franchised public utility” in the same geographic region. It explains that, with 

this change, a company would qualify as a Category 1 seller in California despite the 

fact that it is affiliated with a franchised public utility in New England because any 

concerns about affiliate abuse would exist only in the New England market and not in 

California.999 Third, Constellation suggests that, if operational control over 

transmission facilities has been transferred to an RTO/ISO, then a seller’s affiliation 

 998 Proposed 18 CFR 35.36(a)(5) defines a franchised public utility as “a public 

utility with a franchised service obligation under state law and that has captive 

customers.” 

999 Similarly, Constellation contends that, if a seller and its affiliates own more 

than 500 MW of generation capacity in only one region and less in others, then the seller 

should be required to file updated market power analyses in only the region(s) where its 

affiliated generation exceeds the threshold. 
Docket No. RM04-7-000 484 

with the owner of such transmission facilities should not exclude the seller from 

qualifying as a Category 1 seller. Further, Constellation seeks clarification that the 

exclusions for owners of transmission facilities that are simply interconnection 

facilities, are under operational control of an RTO/ISO, or are subject to waiver of 

Order No. 888 and 889, will also apply to affiliates of those transmission owners. 

Commission Determination 

Adoption of Category 1/Category 2

848. We adopt the NOPR proposal to create a category of sellers that are exempt 

from the requirement to automatically submit updated market power analyses, with 

certain modifications. As discussed further below, this finding is fully consistent 

with our statutory obligation to ensure just and reasonable rates and with court 

decisions construing that obligation. Moreover, it will streamline the administration 

of the market-based rate program by focusing the Commission’s resources on sellers 

that have a significant presence in the market. It also is supported by the majority of 

commenters in this proceeding. 

849. The Commission agrees with Financial Companies and Morgan Stanley that 

sellers should have notice of their status and related filing obligations. However, we 

believe the criteria we adopt herein are sufficiently clear so that the vast majority of 

sellers can easily determine in which category they fall. Accordingly, the 

Commission will not initially compile and release a list of sellers in each category. 

Rather, we will require all sellers that believe they fall into Category 1 to make a 

filing with the Commission at the time that updated market power analyses for the 
Docket No. RM04-7-000 485 

seller’s relevant market would otherwise be due (based on the regional schedule for 

updated market power analyses adopted in this Final Rule). That filing should 

explain why the seller meets the Category 1 criteria1000 and should include a list of all 

generation assets (including nameplate or seasonal capacity amounts) owned or 

controlled by the seller and its affiliates grouped by balancing authority area.1001 The 

Commission will notice these filings and provide an opportunity for comment. The 

Commission will then act on the seller’s filing, either acknowledging that the seller 

falls within Category 1 or, if it finds that the seller does not qualify as a Category 1 

seller, directing the seller to file an updated market power analysis. Subsequently, all 

Category 1 sellers will not be required to file regularly scheduled updated market 

power analyses. 

850. With regard to sellers that fall into Category 2, these sellers will be required to 

file an updated market power analysis based on the schedule in Appendix D. In our 

 1000 These criteria, as modified in this Final Rule, include wholesale power 

marketers and wholesale power producers that own or control 500 MW or less of 

generation in aggregate per region; that do not own, operate or control transmission 

facilities other than limited equipment necessary to connect individual generating 

facilities to the transmission grid (or have been granted waiver of the requirements of 

Order No. 888); that are not affiliated with anyone that owns, operates or controls 

transmission facilities in the same region as the seller’s generation assets; that are not 

affiliated with a franchised public utility in the same region as the seller’s generation 

assets; and that do not raise other vertical market power issues. 

1001 In the section titled “Regional Review and Schedule” we discuss further how 

we implement this approach. 
Docket No. RM04-7-000 486 

orders acting on the updated market power analyses, the Commission will make a 

finding that the seller is a Category 2 seller, as appropriate. 

851. In addition, with regard to new applications for market-based rate authority, 

we also will make a finding regarding the category in which the seller falls. 

However, all sellers submitting initial applications for market-based rate authority 

must submit the indicative screens, or accept a presumption of market power in 

generation, and must submit a vertical market power analysis. 

852. We reject FirstEnergy’s argument that there should be no requirement for any 

seller to file an updated market power analysis. Competitiveness of markets is 

continuing to change and, therefore, we are reluctant to rely only on initial market 

power analyses, change in status filings, and section 206 complaints in all cases. The 

burden on Category 2 sellers is small compared to their market presence and 

activities, and is outweighed by the fact that submission of periodic updated market 

power analyses enhances Commission oversight and public confidence in the 

regulatory process. Thus, we will require the submittal of regularly scheduled 

updated market power analyses by those sellers that have more of a presence in the 

market and are more likely to either fail one or more of the indicative screens or pass 

by a smaller margin than those that will qualify as Category 1 sellers, or that may 

present circumstances that could pose vertical market power issues, i.e., Category 2 

sellers. Through regularly scheduled updated market power analyses for Category 2 

sellers, the Commission is better able to evaluate the ongoing reasonableness of those 

sellers’ charges and to provide for an ongoing assessment of their ability to exercise 
Docket No. RM04-7-000 487 

market power. In the absence of regularly scheduled updated market power analyses 

from the Category 2 sellers, it would be more difficult for the Commission to fulfill 

its statutory duty to ensure that market-based rates are just and reasonable and that 

market-based rate sellers continue to lack the potential to exercise market power so 

that market forces are indeed determining the price. 

853. Because Category 1 and 2 sellers occupy different postures in terms of their 

presence in the market, it is not unduly discriminatory to eliminate the requirement to 

file a regularly scheduled updated market power analysis for Category 1 sellers but 

not Category 2 sellers. Category 1 sellers have been carefully defined by the 

Commission to have attributes that are not likely to present market power concerns: 

ownership or control of relatively small amounts of generation capacity; no affiliation 

with an entity with a franchised service territory in the same region as the seller’s 

generation facility; little or no ownership or control of transmission facilities and no 

affiliation with an entity that owns or controls transmission in the same region as the 

seller’s generation facility; and no indication of an ability to exercise vertical market 

power. Further, based on a review of past Commission orders, we are aware of no 

entity that would have qualified as a Category 1 seller under this Final Rule but 

would nevertheless have failed our indicative screens necessitating a more thorough 

analysis. Thus, the Commission has provided a reasoned basis to distinguish 

Category 1 sellers from Category 2 sellers. Moreover, the EQR reporting 

requirements and change in status filings required for Category 2 market-based rate 

sellers will also apply to Category 1 sellers. This will ensure adequate oversight of 
Docket No. RM04-7-000 488 

Category 1 sellers, even without regularly scheduled updated market power analyses. 

Further, we will continue to reserve the right to require an updated market power 

analysis from any market-based rate seller at any time, including for those sellers that 

fall within Category 1. 

854. In this regard, we agree with PPM that the Commission retains the tools 

necessary to ensure that all rates are just and reasonable, including initial market 

power evaluations, and ongoing monitoring by the Commission. For example, as 

noted above, all sellers with market-based rates must file electronically with the 

Commission an EQR of transactions no later than 30 days after the end of the 

reporting quarter and must comply with the change in status reporting requirement. 

We note that the reporting requirement relied upon by the court in Lockyer is the 

transaction-specific data found in EQRs, which we continue to require of all sellers, 

and not updated market power analyses. Thus, exempting Category 1 sellers from 

routinely filing updated market power analyses does not run counter to Lockyer. 

855. With respect to EQR filings, the Commission enhanced and updated the posttransaction filing requirements from what they were during the period at issue in the 

Lockyer case, now requiring electronic reporting of, among other things:1002 (1) a 

 1002 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 

(May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (2002). Required data sets for contractual 

and transaction information are described in Attachments B and C of Order No. 2001. 

The EQR must be submitted to the Commission using the EQR Submission System 

Software, which may be downloaded from the Commission’s website at 

http://www.ferc.gov/docs-filing/eqr.asp. The exact dates for these reports are prescribed 

 (continued...) 

 
Docket No. RM04-7-000 489 

summary of the contractual terms and conditions in every effective service agreement 

for market-based power sales; and (2) transaction information for effective short-term 

(less than one year) and long-term (one year or greater) market-based power sales 

during the most recent calendar quarter. We also note that the Commission has 

revoked the market-based rate authority of sellers that have failed to comply with the 

EQR filing requirements.1003 Further, the Commission has utilized EQR data in 

determinations relating to market power. For example, the Commission relied in part 

on EQR data in reaching its determination that an “alternative” market power analysis 

submitted by Duke Power was unpersuasive.1004

856. With respect to notices of change in status, in a related rulemaking proceeding 

in early 2005, the Commission clarified and standardized market-based rate sellers’ 

reporting requirement for any change in status that departs from the characteristics 

the Commission relied on in initially authorizing sales at market-based rates. 1005 In 

Order No. 652, the Commission required that, as a condition of obtaining and 

 

in 18 CFR 35.10b. Failure to file an EQR (without an appropriate request for extension), 

or failure to report an agreement in an EQR, may result in forfeiture of market-based rate 

authority, requiring filing of a new application for market-based rate authority if the seller 

wishes to resume making sales at market-based rates. 

1003 See Electric Quarterly Reports, 115 FERC ¶ 61,073 (2006); Electric Quarterly 

Reports, 114 FERC ¶ 61,171 (2006); Electric Quarterly Reports, 69 FR 57679 (Sept. 27, 

2004); Electric Quarterly Reports, 105 FERC ¶ 61,219 (2003). 

1004 Duke Power, a Division of Duke Energy Corporation,111 FERC ¶ 61,506 at P 

48, 55 (2005). 

1005 Order No. 652 at P 47. 
Docket No. RM04-7-000 490 

retaining market-based rate authority, sellers must file notices of such changes no 

later than 30 days after the change in status occurs.1006 These requirements are 

codified in our regulations, and failure of a market-based rate seller to timely file a 

change in status report constitutes a tariff violation. If such a violation occurs, the 

Commission has the tools available to impose remedies, as necessary and appropriate, 

from the date on which the tariff violation occurred. Such remedies could include 

disgorgement of profits, civil penalties or other remedies the Commission finds 

appropriate based on the specific facts and circumstances. 

857. We note that any new market-based rate seller must conduct a horizontal 

market power analysis for our review. Furthermore, we reiterate that the Commission 

retains the ability to require an updated market power analysis from any seller, 

Category 1 or 2, at any time. 

858. We also reject those arguments made by the California Commission, 

NASUCA, and State AGs and Advocates that all sellers should continue to be 

required to file regularly scheduled updated market power analyses. For the reasons 

stated above, assertions that the Commission will be unable to monitor market-based 

rate sellers without requiring all sellers to file regularly scheduled updated market 

power analyses are unfounded. 

 1006 As discussed below in the Change in Status section, the Commission is 

modifying its regulations to provide that, in the case of power sales contracts with future 

delivery, such contracts are reportable 30 days after the physical delivery has begun. 
Docket No. RM04-7-000 491 

859. In response to the comments of NASUCA and Constellation, we make the 

following clarifications. We clarify that, subject to other conditions discussed below, 

Category 1 sellers include power marketers and power producers with 500 MW or 

less of generation capacity owned or controlled by the seller and its affiliates in 

aggregate per region. Our use of the term “region” is intended to be as delineated in 

the Regional Review and Schedule attached as Appendix D. 

860. We further clarify that a seller that owns, operates or controls, or is affiliated 

with an entity that owns, operates or controls, transmission facilities in the same 

region as the seller’s generation assets does not qualify as a Category 1 seller in that 

region. This standard applies regardless of whether the total generation capacity 

owned or controlled by the seller and its affiliates is below 500 MW in the region. 

861. Regarding Constellation’s point that a company should be considered 

Category 1 so long as it is not affiliated with a franchised public utility in the same 

region (and meets the other requirements for Category 1), we concur. Hence, a seller 

that is affiliated with a franchised public utility that is not in the same region in which 

the seller owns or controls generation assets may qualify as a Category 1 seller for 

that region if it meets the other Category 1 criteria. Likewise, a seller that does not 

own, operate or control, and is not affiliated with an entity that owns, operates or 

controls, transmission in the same region in which the seller owns or controls 

generation assets may qualify as a Category 1 seller for that region. 

862. We do not adopt Constellation’s proposal that we carve out an exemption for 

sellers affiliated with a franchised public utility without captive customers nor do we 
Docket No. RM04-7-000 492 

adopt the proposal to exempt those that are affiliated with transmission owners that 

have given operational control of their transmission facilities to RTOs/ISOs.1007 

Constellation has failed to adequately demonstrate that sellers affiliated with a 

franchised public utility without captive customers and those that are affiliated with 

transmission owners that have given operational control of their transmission 

facilities to RTOs/ISOs necessarily lack market power in generation. 

863. In addition, we will revise the definition of Category 1 sellers in the 

regulations to include those that own, operate or control only transmission facilities 

that are “limited equipment necessary to connect individual generating facilities to 

the transmission grid.” While the NOPR included this language in the preamble, 

conforming language was inadvertently excluded from the definition of Category 1 

sellers in § 35.36(a)(2) of the proposed regulations. 

Threshold for Category 1 

864. After considering all of the comments regarding the proposed cutoff between 

Categories 1 and 2, we believe that 500 MW or less of generating capacity per region 

is an appropriate threshold. We will use this value as a cutoff because, during our 15 

years of experience administering the market-based rate program, there have only 

rarely been allegations that sellers with capacity of 500 MW or less had market 

power, and when those claims have been raised the Commission’s review has either 

 1007 We do, however, replace the term “public utility with a franchised service 

territory” with the defined term “franchised public utility.” 
Docket No. RM04-7-000 493 

found no evidence of market power or found that the market power identified was 

adequately mitigated by Commission-enforced market power mitigation rules.1008 

While some commenters urge the Commission to adopt either a higher or lower 

threshold, the Commission believes that a 500 MW threshold is both a reasonable 

balance as well as conservative enough to ensure that those unlikely to possess 

market power will be granted market-based rate authority. Moreover, as Newmont 

asserts, 500 MW is a clear, bright line that will be easy to administer. 

865. In addition and in response to commenter requests, we clarify that the 500 

MW threshold is determined by adding all the generation capacity owned or 

controlled by the seller and its affiliates within the same region (as delineated in the 

Regional Review and Schedule attached as Appendix D). In keeping with our 

conservative approach with regard to which entities qualify for Category 1, we find 

that aggregate capacity in a given region best meets our goal of ensuring that we do 

not create regulatory barriers to small sellers seeking to compete in the market while 

maintaining an ample degree of monitoring and oversight that such sellers do not 

obtain market power. In this regard, we also clarify that although we will use 

aggregate capacity owned or controlled in a region to determine which sellers are 

required to file regularly scheduled updated market power analyses, we will continue 

 1008 Moreover, as noted above, the Commission’s indicative screens are set at 

conservative levels. 
Docket No. RM04-7-000 494 

to evaluate the balancing authority area in which the seller is located when 

performing our indicative screens, absent evidence to the contrary.1009

866. While we recognize the appeal of a test that takes into account the size of each 

geographic market, such as using a percentage of all capacity (as opposed to a stated 

MW) cutoff and the use of uncommitted capacity rather than installed capacity, these 

methodologies are inconsistent with a straightforward, conservative means of 

screening sellers and consequently would lead to regulatory uncertainty. As markets 

and market participants can fluctuate, a determination of the number of MWs 

constituting a particular percentage of capacity in a regional market would have to be 

constantly recalculated and the assumptions underlying a determination could lead to 

potential challenges. Such an approach would run counter to our intention to provide 

certainty to market participants and to streamline the administration of the program. 

867. The Commission rejects as unnecessary suggestions by AWEA and PPM that 

we take into account the differences among generation, including that classified as 

intermittent or non-dispatchable, when calculating the generation capacity of a seller. 

We believe that many sellers with wind and other non-thermal capacity will fall 

below the 500 MW threshold; those that do not may take advantage of simplifying 

 1009 As we have stated above, where a generator is interconnecting to a nonaffiliate owned or controlled transmission system, there is only one relevant market (i.e., 

the balancing authority area in which the generator is located).
Docket No. RM04-7-000 495 

assumptions and other means to minimize the burden of filing an updated market 

power analysis. 

868. With respect to several commenters’ desire for fact-specific exemptions for 

sellers who otherwise may qualify for Category 2, we note that the Commission will 

determine on a case-by-case basis the category status of each seller with marketbased rate authorization. In our attempt to keep the Category 1 criteria as simple and 

straightforward as possible, we may have swept under Category 2 particular sellers 

whose circumstances make it unlikely that they could ever exercise market power. 

As a result, we will entertain and evaluate individual requests for exemption from 

Category 2 and make a finding on the category status of each company. However, if 

a seller wishes to request exemption from Category 2, it must make a filing seeking 

such an exemption no later than 120 days before its next updated market power 

analysis is due. We also will consider any arguments from intervenors that a 

particular seller that contends that it qualifies for Category 1 status based on our 

definition should nevertheless be treated as a Category 2 seller and thus be required to 

continue filing updated market power analyses. 

2. Regional Review and Schedule

Commission Proposal

869. To ensure greater consistency in the data used to evaluate Category 2 sellers, 

the Commission proposed to require ongoing updated market power analyses to be 

filed for each seller’s relevant geographic market on a pre-determined schedule. 

Such a process would allow examination of the individual seller at the same time that 
Docket No. RM04-7-000 496 

the Commission examines other sellers in the relevant market and contiguous markets 

within a region from which power could be imported. The Commission appended to 

the NOPR a proposed schedule for the regional review process, rotating by 

geographic region with three regions being reviewed per year. For corporate families 

that own or control generation in multiple control areas and different regions, the 

Commission proposed that the corporate family would be required to file an update 

for each region in which members of the corporate family sell power during the time 

period specified for that region. 

Comments

870. Several commenters, including ELCON, APPA/TAPS, NRECA, 

Suez/Chevron, and Newmont, support the Commission’s proposal. ELCON states 

that the requirement that a seller file its updated market power analysis at the same 

time the Commission examines other sellers in the relevant market and region is an 

excellent idea because it provides a better picture to the Commission during its 

review. APPA/TAPS state that the regional approach will lead to data consistency 

and availability, and will allow the Commission to fulfill its obligations more 

completely. Newmont believes that the Commission’s proposal appropriately 

balances the need to effectively monitor and mitigate market power while avoiding 

unnecessary and unproductive regulatory requirements.1010 

 1010 Newmont at 1. 
Docket No. RM04-7-000 497 

871. Alternatively some commenters oppose the proposal entirely, or suggest 

modifications. Reliant states that the regional review and schedule would 

significantly increase the administrative burdens of compliance rather than streamline 

them. According to Reliant, companies that engage in business in multiple regions of 

the United States would have to file several times over the three year schedule instead 

of once as is required currently.1011 Morgan Stanley and Financial Companies state 

that the Commission should require Category 2 sellers to file only once every three 

years, either with the region where they have a franchised service territory or the 

region in which they own the greatest amount of generation. EEI and EPSA maintain 

that a regional review will pose a great burden on utilities operating in multiple 

markets and will lead to confusion over contradictory information.1012

872. State AGs and Advocates warn that the regional approach will result in a too 

infrequent analysis of each area. They and others state that, with the combined 

approach, each specific region will only be looked at completely every three years, 

which is less oversight than the Commission has currently.1013

 1011 Similarly, Allegheny, Mirant, FP&L, EEI, FirstEnergy, MidAmerican, TXU, 

Morgan Stanley, Financial Companies, and EPSA argue that large corporate families 

could find themselves in a perpetual triennial review that would place a substantial 

regulatory burden and expense on them. 

1012 EEI reply comments at 27-29, EPSA reply comments at 11-14. 

1013 See, e.g., State AGs and Advocates at 49-51, Reliant at 9-11, Mirant at 2-6, 

EPSA at 39-40, EEI reply comments at 27-29, EPSA reply comments at 11-14. 
Docket No. RM04-7-000 498 

873. FirstEnergy notes that the Commission has encouraged PJM and Midwest ISO 

to eliminate “seams” between their respective regions and comments that the 

proposal to schedule submittal of updated market power analyses for sellers in these 

two regions at different times is inconsistent with the reasons underlying adoption of 

common filing dates. Mirant states that the limited number of consultants that 

perform market power analyses use separate, proprietary databases and warns that the 

market data submitted on a regional basis will remain inconsistent. Further, Mirant 

asserts that there may be antitrust issues if a group of competing sellers jointly hires 

one consultant. 

874. NRECA replies that any increase in the burden on sellers does not outweigh 

the substantial benefits of greater data consistency and a complete picture of each 

region under review.1014 APPA/TAPS assert that the Commission should not 

sacrifice improvements to its program for the interests of a few companies and that 

any increased cost to companies associated with regional reviews is outweighed by 

the companies’ profits from market-based rate sales. They dismiss concerns 

regarding a scarcity of consultants, noting that the market should respond to an 

increase in demand for consulting services, and that “competition will force 

efficiency gains to be passed along to consultants’ clients.”1015 Further, with respect 

 1014 NRECA reply comments at 28-30. 

1015 APPA/TAPS reply comments at 20. 
Docket No. RM04-7-000 499 

to a group of sellers jointly hiring a consultant to produce a market analysis, they 

comment that antitrust counsel should be able to ensure joint representation does not 

result in improper information sharing.1016 

875. PNM/Tucson state that the updated market power analyses in a given region 

should be deliberately staggered so that utilities are able to build upon data sets 

already submitted in prior proceedings, instead of each having to construct its own, 

which would result in varying, competing data sets. 

876. Mirant and FP&L add that with all the entities filing concurrently it will be 

difficult for some, such as non-transmission owning entities, to acquire the necessary 

data (i.e., simultaneous import limit data). NRECA, Mirant and Powerex ask the 

Commission to have transmission-owning utilities file their updated market power 

analyses (or information necessary for others to perform preliminary screens) at a 

minimum 90 days prior to the regional due date; MidAmerican requests that the 

Commission require each transmission provider to post to its OASIS a simultaneous 

import study 60 days before the filing deadline that could be used by first-tier entities 

to develop their market power analyses. Similarly, Suez/Chevron suggests requiring 

RTOs and/or control area operators in each region to file certain information in 

advance of the filing deadline so that sellers can rely on uniform baseline data.1017 

 1016 Id. at 19-21. 

1017 The data Suez/Chevron refer to include the information indicated in proposed 

Appendix C, Pivotal Supplier Analysis at Rows E through J, O, P and Q and also 

 (continued...) 

 
Docket No. RM04-7-000 500 

EEI critiques the proposals for sharing of data prior to submission of triennial 

reviews, stating that this would increase the complexity of an already cumbersome 

process.1018 

877. APPA/TAPS state that data sharing by companies should be enhanced by 

regional reviews, not impaired, and that more robust data and opportunities to 

reconcile conflicting submissions with a regional review will lead to a better analysis 

by the Commission.1019

878. MidAmerican asserts that the Commission should allow more time between 

the end of the qualification period and the filing of market power analyses. It states 

that these analyses require Form 1 data that is not available until several months after 

the end of the calendar year and that control area loads as filed in Form 714 are 

frequently not available until the third quarter following the end of the calendar year, 

usually July. Additionally, it states that generation and load data from Forms EIA860 and EIA-861, respectively, are likewise not available until late in the following 

year. Accordingly, it suggests that market analyses should not be due until mid-

 

proposed Appendix C, Wholesale Market Share Analysis at Rows F through Q, and the 

accompanying workpapers. 

1018 EEI reply comments at 27-29. 

1019 APPA/TAPS reply comments at 19-21. 
Docket No. RM04-7-000 501 

October following the end of the qualification period, allowing roughly 90 days 

between the availability of Form 714 and the deadline for filing.1020

879. Many commenters also argue that the Commission should extend the time 

until the first regional reviews are due. Suggested beginning filing dates include: the 

first filing period for a region that is no earlier than a company’s next required 

updated analysis;1021 the first filing period that occurs no earlier than two years from 

the latest filed updated analysis;1022 the first filing period that is no earlier than one 

year from the latest filed updated analysis;1023 or 180 days after the Final Rule is 

published in the Federal Register.1024 Duke suggests that, rather than extending the 

first filing times, the Commission clarify that those entities due to file their next 

updates before the scheduled regional reviews are due can forgo making any interim 

filings. 

880. APPA/TAPS ask the Commission to extend the period for commenting on the 

updated market power analyses from the current 21-day comment period to 60 days, 

at a minimum. They state that because numerous sellers will file the updated market 

power analyses contemporaneously, intervenors should be given sufficient time to 

 1020 See MidAmerican at 33. 

1021 See Consumers at 2-4, Allegheny at 16-18. 

1022 See MidAmerican at 30-33. 

1023 See Constellation at 13. 

1024 See Allegheny at 16-18. 
Docket No. RM04-7-000 502 

make meaningful use of the expanded body of information and to prepare multiple 

pleadings dealing with various sellers in the region. They add that the additional time 

should improve the quality of the analyses that the Commission receives from 

intervenors. 

881. Finally, regarding the Commission’s proposal to require all updates (and all 

new applications) to include an appendix listing all generation assets owned or 

controlled by the corporate family, in-service dates and capacity ratings by unit, Duke 

agrees with the proposal that the appendix should also reflect all electric transmission 

and natural gas intrastate pipelines and/or gas storage facilities owned or controlled 

by the corporate family. It states that having such a standardized listing will be 

helpful both to the Commission and to other market participants.1025 Duke cautions, 

however, that including the location of transmission and gas pipeline facilities in the 

appendix could conflict with CEII requirements, and requests clarification that sellers 

will have discretion with locational descriptions. 

Commission Determination

882. The Commission adopts the NOPR proposal to conduct a regional review of 

updated market power analyses, with certain modifications. We agree with 

commenters such as APPA/TAPS that the regional approach will lead to data 

consistency and availability. In this regard, both the Commission and market 

 1025 Duke at 49. 
Docket No. RM04-7-000 503 

participants will benefit from greater data consistency that will result from regional 

examination of updated market power analyses and a methodical study of all sellers 

in the same region. This will give the Commission a more complete view of market 

forces in each region and the opportunity to reconcile conflicting submissions, 

enhancing our ability to ensure that sellers’ rates remain just and reasonable. 

883. Although some commenters express concern that a regional review approach 

will increase administrative burdens, particularly for sellers operating in multiple 

regions, we believe that the Commission’s proposal properly and fairly balances the 

need to effectively monitor and mitigate market power in wholesale markets with the 

desire to minimize any administrative burden associated with the filing and review of 

updated market power analyses. While we recognize that some sellers may have to 

file updates more frequently than they do currently, we have carefully balanced the 

interests of all involved, and we believe that regional reviews of updated market 

analyses is both needed and desirable and will enhance the Commission's ability to 

continue to ensure that sellers either lack market power or have adequately mitigated 

such market power. 

884. We note that sellers currently must prepare a market power analysis for all of 

their generation assets nationwide. Some sellers with assets in multiple regions have 

chosen to submit their individual updated market power analyses when each is due 

(every three years) rather than combining them into a single updated market power 

analysis. Others file one updated market power analysis for the entire corporate 

family, with individual analyses of the different markets in which their assets are 
Docket No. RM04-7-000 504 

located. Either way, the same analyses must be filed under the status quo and the 

approach adopted in this Final Rule. The timing may differ, but the increased burden 

is minimal.1026

885. Nevertheless, considering the comments received and upon further review of 

the Commission’s proposal, we believe that some of the proposed regions should be 

consolidated. Therefore, we will reduce the number of regions from the proposed 

nine to six. In Appendix D we identify the six regions (Northeast, Southeast, Central, 

Southwest Power Pool, Southwest, and Northwest), and will require Category 2 

sellers that own or control generation assets in each region to file an updated market 

power analysis for that region every three years based on a rotating schedule shown 

in the Appendix.1027 We believe that, with fewer and larger regions, some sellers will 

likely be present in fewer regions and administrative burdens for those sellers 

accordingly will be reduced. In addition, the decrease in the number of regions will 

also extend the time period between filings. In the NOPR, the Commission stated 

that three regions would be reviewed per year, with four months between each set of 

 1026 In this regard, we note that preparation of multiple market power analyses is 

likely less burdensome and less expensive than what would otherwise be required under 

cost-based regulation which can result in extended administrative litigation to determine 

the just and reasonable rate. 

1027 Concerning power marketers that may not own or control generation assets in 

any region, we will require the submission of a filing explaining why the seller meets the 

Category 1 criteria, as discussed above. Power marketers must submit such a filing with 

the first scheduled geographic region in which they make any sales. 
Docket No. RM04-7-000 505 

filings. Here we adopt review of two regions per year, with the filing periods six 

months apart. 

886. Regarding FirstEnergy’s argument that PJM and Midwest ISO should be 

placed in the same region, we continue to encourage PJM and the Midwest ISO to 

address "seams" issues. However, we find that placing them in different regions for 

the purpose of determining when an updated market power analysis is submitted 

should in no way affect or discourage efforts to address seams between these two 

regions. Other considerations (such as balancing RTO/ISO and non-RTO/ISO 

filings, and scheduling approximately the same number of filings each year) outweigh 

FirstEnergy's concerns. 

887. The Commission rejects the arguments by some commenters that the regional 

approach will result in too infrequent an analysis of each area. As a practical matter, 

currently sellers are required to file an updated market power analysis every three 

years. In the intervening years between updated market power analyses, most utilities 

either enjoy the 18 CFR 35.27(a) exemption from filing a generation market power 

analysis or rely on the previously filed updated market power analysis. The regional 

approach will provide the Commission with a snapshot of sellers across a larger area 

and will provide a more accurate view of simultaneous import capability into the 

relevant geographic markets under review. Accordingly, contrary to claims that the 

regional approach will result in less Commission oversight, the regional approach 

will enhance the Commission’s ability to analyze market power using better data with 

less opportunity for conflicting claims of ownership or control of generation assets. 
Docket No. RM04-7-000 506 

888. Regarding concerns about the scarcity of consulting firms, we note that our 

proposal will not necessarily increase the number of market power analyses to be 

performed (indeed, by exempting all Category 1 sellers from submitting updated 

market power analyses, the number may be decreased). We agree with APPA/TAPS 

that any shortage of consultants performing market power analyses should be 

temporary as firms adjust to a new schedule reflecting the regional review timetable 

and take precautions to prevent improper information sharing. 

889. We agree with commenters that transmission-owning entities should file their 

updated market power analyses in advance of others in each region. Thus, the 

Commission will modify the schedule proposed in the NOPR to better allow sellers to 

rely on the transmission-owning utilities’ information, and we will adopt a staggered 

filing approach for each region which will require different types of entities to file at 

different times. The transmission-owning utilities, which have the information 

necessary to perform SIL studies, will be required to file their updated market power 

analyses first. Six months later, all others in that region will be required to file their 

updated market power analyses.1028 

890. Staggering the time periods within which transmission-owning and nontransmission-owning utilities will be required to submit their updated market power 

 1028 If the Commission has not processed a particular SIL study before six months 

have passed and non-transmission owning entities must file their updated market power 

analyses, then those entities should rely on the filed SIL study. If the initial SIL study 

subsequently changes, the Commission will make conforming adjustments as needed. 
Docket No. RM04-7-000 507 

analyses will provide an opportunity for those non-transmission owning sellers that 

need simultaneous transmission import limits to perform the screens to rely on the 

SIL studies performed by the transmission-owning utilities rather than rely on a 

"proxy" for the import limits. 

891. Our experience is that sellers located in RTOs/ISOs typically do not need to 

rely on a SIL study in performing the screens, and transmission-owning utilities in 

RTOs/ISOs typically do not prepare or submit such studies. Accordingly, staggered 

filings for sellers in RTOs/ISOs may not be necessary for purposes of data 

availability. Nevertheless, we will retain the staggered filing deadlines for all regions 

for consistency and to avoid any confusion in this regard. If a particular seller that is 

located in an RTO/ISO finds that it needs import data in order to complete its market 

power analysis, we expect the RTO/ISO to assist such sellers if requested. 

892. In response to MidAmerican’s suggestion that the Commission allow adequate 

time between the date that all data is available and the date that a region’s analyses 

are due, we will schedule the updates to be filed in December (12 months after the 

study year), and June (18 months after the study year). We note that studies due in 

December and June may be filed anytime during the applicable month. Such a 

schedule will allow adequate time for the data to be available (at least 6 weeks after 

EIA Forms 860 and 861 become public) and the analyses to be completed. 

893. In response to commenters’ requests that the Commission extend the time until 

the first analyses are due, we will commence the schedule in December 2007. The 

Commission believes this will provide adequate notice and time to prepare the 
Docket No. RM04-7-000 508 

analyses. In addition, we clarify that sellers that otherwise would have been required 

to file an updated market power analysis before the effective date of this rule should 

submit their updated market power analyses in accordance with past orders directing 

them to do so. Starting with the effective date of this rule, sellers should submit their 

updated market power analyses in accordance with the schedule set forth in Appendix 

D. 

894. We also agree with the suggestion of APPA/TAPS to extend the period for 

intervenors to comment on the updates. We agree that extending the comment period 

will allow intervenors a better opportunity to review and comment on filings, 

especially considering the large number of filings that will be submitted at one time. 

For that reason, the Commission will establish a 60-day comment period for updated 

market power analyses. Further, we adopt the NOPR proposal to require that with 

each new application and updated market power analysis, the seller must list in an 

appendix, among other things, all affiliates that have market-based rate authority and 

identify any generation assets owned or controlled by the seller and any such affiliate. 

In addition, we extend this obligation to relevant change in status notifications.1029 

We believe that requiring the submission of such data will provide the Commission 

with more accurate and up-to-date information about each corporate family and will 

address some of our concerns regarding confusion that has occurred with respect to 

 1029 Relevant change in status notifications would include, for example, the 

addition of new facilities, but not a name change. 
Docket No. RM04-7-000 509 

corporate families and, in particular, what sellers are authorized to transact at marketbased rates in each corporate family. 

895. Accordingly, the appendix must list all generation assets owned (clearly 

identifying which affiliate owns which asset) or controlled (clearly identifying which 

affiliate controls which asset) by the corporate family by balancing authority area, 

and by geographic region, and provide the in-service date and nameplate and/or 

seasonal ratings by unit. As a general rule, any generation assets included in a 

seller’s or a seller’s affiliate’s market study should be listed in the asset appendix. 

We find that the in-service date and nameplate and/or seasonal ratings help identify 

and provide the Commission and market participants with critical market 

information. In addition, the appendix must reflect all electric transmission and 

natural gas intrastate pipelines and/or gas storage facilities owned or controlled by the 

corporate family and the location of such facilities. 

896. In response to Duke, we clarify that CEII data is more detailed than “simply 

[giving] the general location of the critical infrastructure.”1030 As the location of the 

facilities listed in the appendix need only include the balancing authority area and 

geographic region (see sample appendix attached as Appendix B) in which they are 

located, we do not anticipate that any CEII will be disclosed. 

 1030 18 CFR 388.113(c)(1)(iv). 
Docket No. RM04-7-000 510 

F. MBR Tariff

Commission Proposal

897. In the NOPR, the Commission proposed to adopt a market-based rate tariff of 

general applicability (MBR tariff), applicable to all sellers authorized to sell electric 

energy, capacity or ancillary services at wholesale at market-based rates, as a 

condition of market-based rate authority. The MBR tariff, as proposed, would 

require each seller to comply with the applicable provisions of the market-based rate 

regulations to be codified at 18 CFR Part 35, Subpart H. The Commission proposed 

that each seller would be required to list on the MBR tariff the docket numbers and 

case citations, where applicable, of any proceedings where the seller received 

authorization to make sales of energy between affiliates or where its market-based 

rate authority was otherwise restricted or limited. 

898. The Commission explained that not all of the provisions of the proposed 

regulations may be applicable to all sellers. For example, a seller may not wish to 

offer ancillary services under the tariff. The Commission sought comments regarding 

whether a placeholder should be reserved in the MBR tariff for the seller to indicate 

those parts of the regulations that are not applicable to it. 

899. The Commission stated that this streamlining effort is not intended to reduce 

the flexibility of sellers and customers in negotiating the terms of individual 

transactions. The Commission noted that sellers would continue to negotiate the 

terms and conditions of sales entered into under their MBR tariff, and the terms and 

conditions of those underlying agreements and the transaction data would be reflected 
Docket No. RM04-7-000 511 

in the quarterly EQRs. The Commission stated that if sellers wish to offer or require 

certain “generic” terms and conditions that in the past were contained in their marketbased rate tariff, they may place customers on notice of such requirements by 

including such information on a company website and include any related provisions 

in individual transaction agreements. The Commission explained its desire that the 

MBR tariff reflect, in a consistent manner, only those matters that are required to be 

on file.1031 

900. Further, rather than each entity having its own MBR tariff, which can result in 

dozens of tariffs for each corporate family with potentially conflicting provisions, the 

Commission proposed that each corporate family have only one tariff, with all 

affiliates with market-based rate authority separately identified in the tariff.1032 The 

Commission stated that this would reduce the administrative burden and confusion 

that occurs when there are multiple, and potentially conflicting, tariffs in a single 

corporate family, and would allow the Commission and customers to know what 

sellers are in each corporate family. 

1. Tariff of General Applicability

Comments

901. Several commenters do not support the adoption of a tariff of general 

applicability. Allegheny argues that “the Commission is without legal authority to 

 1031 NOPR at P 163. 

1032 Id. at P 164. 
Docket No. RM04-7-000 512 

impose a one-size-fits-all market-based rate tariff.”1033 It argues that the Commission 

has made no finding of undue discrimination and is not proposing to act under FPA § 

206, and asserts that administrative efficiency is an insufficient justification to impose 

a standardized tariff on market-based rate sellers. Similarly, FirstEnergy asserts that 

requiring a uniform MBR tariff would impose undue administrative burdens on 

sellers, as each would have to make a compliance filing modifying its currently 

effective tariff and would also have to expand its compliance program to confirm that 

its tariff was in conformance with the uniform tariff. 

902. Xcel states that the Commission has not made clear its basis for and expected 

benefit from a pro forma tariff. Xcel suggests that, if it is adopted, then the 

Commission should describe any limitations on a seller’s market-based rate authority, 

in addition to identifying any docket numbers where they were imposed.1034 

903. Similarly, Avista Corporation believes that all of the terms and conditions of a 

tariff should be included in one easily accessible place. Requiring that certain terms 

and conditions be posted on a company website, rather than the tariff, is bound to 

cause unnecessary confusion as to which terms and conditions apply, and will 

increase the burden on both the utilities to notify, and customers to remain apprised, 

 1033 Allegheny at 20. 

1034 Xcel at 17. 
Docket No. RM04-7-000 513 

of when those terms and conditions change.1035 Additionally, FirstEnergy states that 

a process by which a seller places customers on notice of such terms and conditions 

beyond the minimum by including such information on a company website, and 

including related provisions in individual transaction agreements, would be 

cumbersome at best, and would deprive sellers and customers of the benefit of having 

the “generic” terms and conditions in one document.1036

904. Commenters who responded to the question of whether a placeholder should 

be reserved in the tariff to indicate parts of the regulations that are not applicable to 

the seller, support the idea of a placeholder.1037

905. Mirant notes that the sample MBR tariff attached to the NOPR did not provide 

for specific RTO/ISO ancillary service products and states that it is unclear how the 

Commission would identify which seller under the corporate tariff is permitted to sell 

the specific ancillary services traded in each region. Mirant asks whether the 

Commission would require each seller of ancillary services to maintain an ancillary 

services tariff on file with the Commission. Mirant further notes that some sellers not 

located in an RTO/ISO have been granted authorization to sell ancillary services at 

market-based rates if they post those services on their websites and suggests that the 

 1035 Avista at 10-12 

1036 First Energy at 27-31. 

1037 Avista at 10; MidAmerican at 33 (suggesting that the placeholder could be 

included as an attachment to each seller’s tariff in order to preserve the generic nature of 

the tariff itself); Progress Energy at 19. 
Docket No. RM04-7-000 514 

requirement that sellers maintain such a website would have to be cross-referenced in 

the corporate tariff. 

906. EEI states that companies with operations in multiple markets may need to 

tailor their market-based rate tariffs to reflect the particular circumstances of each 

market. This will be true for RTO and ISO markets as well as non-RTO markets. In 

each of these cases, participants in the markets typically must agree to abide by 

specific market terms and conditions that may need to be reflected in the tariff. 

Therefore, EEI encourages the Commission to allow each company to file multiple 

tariffs, as may be necessary to reflect these market differences.1038

907. Regarding the timing of tariff implementation, MidAmerican comments that 

the Commission should apply the new tariff prospectively only to future transactions, 

and urges that existing tariffs should be unaffected until existing transactions expire. 

MidAmerican observes that if existing tariffs containing terms and conditions are 

replaced by the proposed generic tariff, then neither the new tariff nor the existing 

service agreements will reflect the terms and conditions of ongoing transactions. 

908. ELCON supports the proposed MBR tariff, believing that it will be more 

customer-friendly. APPA/TAPS agree, stating that a pro forma tariff will help by 

addressing variations in MBR tariffs that increase transaction costs by creating 

 1038 EEI at 49. 
Docket No. RM04-7-000 515 

potential confusion about applicable terms and conditions.1039 A number of 

commenters find some merit in the concept of the MBR tariff, but request 

clarifications or revisions.1040 Some of these entities comment that companies with 

operations in multiple markets may need to tailor their tariffs to reflect the particular 

circumstances of each market, and state that participants in organized markets 

typically must agree to abide by specific terms that may need to be reflected in their 

tariffs. 

909. Indianapolis P&L asserts that any restrictions on market-based rate authority 

should be in a tariff, rather than in Commission orders. It believes that “converting 

concepts (e.g., all sales in a control area will be mitigated) into precise contractworthy terms and conditions can be very difficult” and argues that the best way to 

prevent misunderstandings between parties is to have “precise, transparent and, 

publicly-available language in a tariff explaining the precise conditions on an entity’s 

market-based rate authority.”1041 Indianapolis P&L further warns that “having 

restrictions on an entity’s market-based rate authorization contained in a tariff only 

 1039 EEI counters APPA/TAPS, asserting that each seller’s MBR tariff in a given 

market is fully available to market participants, so there should be no confusion. EEI 

reply comments at 30-31. 

1040 FirstEnergy at 27-29; Constellation at 27-29; Progress Energy at 19-23. 

1041 Indianapolis P&L at 15. 
Docket No. RM04-7-000 516 

through cross-reference to a Commission order may run afoul of the FPA requirement 

that rates be ‘on file’ with the Commission.”1042

910. Constellation seeks clarification that a seller that has received waiver from the 

code of conduct need not report in its MBR tariff that the affiliate restrictions in 

proposed § 35.39 do not apply to it. Alternatively, Constellation suggests that the 

Commission allow sellers to list the appropriate docket numbers in which the 

Commission has granted waivers of the code of conduct or provide a place to indicate 

that the provisions are not applicable. Constellation notes that many market-based 

rate sellers have included provisions in their tariffs regarding reassignment of 

transmission capacity and sale of firm transmission rights, congestion contracts, or 

fixed transmission rights (as a group, “FTRs”), and requests that the Commission 

either provide for inclusion of such provisions in the MBR tariff or state affirmatively 

that they will not be required. 

Commission Determination

911. In the NOPR, the Commission explained that it was acting pursuant to sections 

205 and 206 of the FPA in proposing to amend its regulations to govern market-based 

rate authorizations for wholesale sales of electric energy, capacity and ancillary 

services by public utilities, “including modifying all existing market-based rate 

authorizations and tariffs so they will be expressly conditioned on or revised to reflect 

 1042 Id. 
Docket No. RM04-7-000 517 

certain new requirements proposed herein.”1043 Section 205 of the FPA requires that 

all rates for sales subject to our jurisdiction, and all rules and regulations pertaining to 

such rates, be just and reasonable. Section 206 of the FPA provides that, when the 

Commission finds that a rate or a rule, regulation or practice affecting a rate, is unjust 

or unreasonable, the Commission shall determine the just and reasonable rate, rule or 

regulation and order it so. 

912. Based on careful consideration of the comments received, the Commission 

agrees that complete uniformity of market-based rate tariffs is not necessary. 

However, pursuant to our authority under sections 205 and 206, we conclude that the 

lack of consistent tariff form and content has hampered our ability to manage the 

market-based rate program in an efficient manner and has introduced uncertainty for 

potential customers. We find that continuing to allow basic inconsistencies in the 

market-based rate tariffs on file with the Commission is unjust and unreasonable. 

Nevertheless, we find that we can achieve our goal without imposing a uniform tariff 

requirement on all sellers by, instead, requiring that all sellers revise their marketbased rate tariffs to contain certain standard provisions, as discussed below. 

913. We believe the approach we adopt here addresses the concerns of commenters 

that the Commission not impose a one-size-fits-all approach while, at the same time, 

presenting a uniform set of required provisions that will provide adequate certainty 

 1043 NOPR at P 1. 
Docket No. RM04-7-000 518 

and will be more customer friendly. In addition, we believe that allowing sellers to 

include seller specific terms and conditions in their market-based rate tariffs will offer 

a greater degree of transparency and serve customers by providing for the opportunity 

to have all terms and conditions identified and in one place. As Progress Energy 

asserts, “[g]reater consistency of tariffs within the industry . . . will not only reduce 

customer confusion, it also will reduce the administrative burden of those responsible 

for the implementation and administration of the tariff.”1044

914. Accordingly, in this Final Rule, we adopt two standard “required” provisions 

that each seller must include in its market-based rate tariff: a provision requiring 

compliance with the Commission’s regulations and a provision identifying any 

limitations and exemptions regarding the seller’s market-based rate authority. 

915. In particular, with regard to compliance with the Commission’s regulations, 

we will require each seller to include the following provision in its market-based rate 

tariff: 

Seller shall comply with the provisions of 18 CFR Part 35, Subpart H, as 

applicable, and with any conditions the Commission imposes in its orders 

concerning seller’s market-based rate authority, including orders in which 

the Commission authorizes seller to engage in affiliate sales under this 

tariff or otherwise restricts or limits the seller’s market-based rate authority. 

Failure to comply with the applicable provisions of 18 CFR Part 35, 

Subpart H, and with any orders of the Commission concerning seller’s 

market-based rate authority, will constitute a violation of this tariff. 

 1044 Progress Energy at 19-20. 
Docket No. RM04-7-000 519 

916. We also will require that the seller include a provision identifying all 

limitations on its market-based rate authority (including markets where the seller does 

not have market-based rate authority) and any exemptions from, or waivers of, or 

blanket authorizations under the Commission’s regulations that the seller has been 

granted (such as exemption from affiliate sales restrictions; waiver of the accounting 

regulations; blanket authority under Part 34 for the issuances of securities and 

liabilities, etc.), including cites to the relevant Commission orders. 

917. In addition to the required tariff provisions, we also will adopt a set of 

standard provisions (which we reference herein as “applicable provisions”) that must 

be included in a seller’s market-based rate tariff to the extent that they are applicable 

based on the services provided by the seller. For example, if the seller’s sales under 

its market-based rate tariff are subject to mitigation, it must include the standard 

provision governing mitigated sales. Similarly, if the seller makes sales of certain 

ancillary services in certain RTOs/ISOs, or if it makes sales of ancillary services as a 

third-party provider, it must include the standard ancillary services provisions, as 

applicable. 

918. Attached hereto as Appendix C is a listing of the standard required provisions 

and the standard applicable provisions. The Commission will post these provisions 

on its web site and will update them as appropriate. 

919. In addition, as discussed more fully below, we will permit sellers to list in their 

market-based rate tariffs additional seller-specific terms and conditions that go 

beyond the standard provisions set forth in Appendix C. 
Docket No. RM04-7-000 520 

920. As Constellation observes, the uniform MBR tariff proposed in the NOPR did 

not provide for sellers to offer reassignment of transmission capacity or FTRs. As 

revised in this Final Rule, Appendix C does not contain a standard provision for the 

reassignment of transmission capacity. The Commission believes that, although these 

items have historically been offered in the context of sales of electric energy and 

capacity, they are transmission-related rather than generation services. Accordingly, 

the Commission has made provision for reassignment of transmission capacity in the 

revised OATT, as discussed in Order No. 890.1045 Thus, we state affirmatively here 

that provisions concerning the reassignment or sale of transmission capacity or FTRs 

are not required to be included in a seller’s market-based rate tariff, nor is it 

appropriate to include transmission-related services in the seller’s market-based rate 

tariff. Sellers seeking to reassign transmission capacity should adhere to the 

provisions of Order No. 8901046 and should revise their market-based rate tariffs to 

remove provisions governing these services at the time they otherwise revise their 

tariffs to conform them to the standard provisions discussed herein. 

921. Regarding FTRs and, incidentally, virtual trading,1047 we note that 

Commission-approved market rules for RTOs/ISOs address resales of FTRs and 

 1045 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 814-816 & n.496. 

1046 Id. at P 816. 

1047 Virtual trading involves sales or purchases in an RTO/ISO day-ahead market 

that do not go to physical delivery. For example, virtual bidding allows entities that do 

 (continued...) 

 
Docket No. RM04-7-000 521 

virtual trading to ensure that no market power is exercised in such trades. In addition, 

sellers engaging in these activities sign a participation agreement with RTOs/ISOs 

which require them to abide by those market rules. Hence, the approval of the market 

rules in conjunction with approval of the generic participation agreement by the 

Commission constitutes authorization for public utilities to engage in the resale of 

FTRs and virtual transactions, and no separate authorization is required under the 

FPA. The Commission’s monitoring of the effectiveness of the market rules and 

oversight of participants engaging in FTR resales and virtual trading in the RTO/ISO 

markets provide sufficient protections against the exercise of market power. 

Nevertheless, if the Commission concludes in the future that a separate section 205 

authorization would better enable us to ensure that FTR resales or virtual trading do 

 

not serve load to make purchases in the day-ahead market. Such purchases are 

subsequently sold in the real-time spot market. Likewise, entities without physical 

generating assets can make power sales in the day-ahead market that are subsequently 

purchased in the real-time market. By making virtual energy sales or purchases in the 

day-ahead market and settling these positions in the real-time, any market participant can 

arbitrage price differences between the two markets. For example, a participant can 

make virtual purchases in the day-ahead if the prices are lower than it expects in the realtime market, and then sell the purchased energy back into the real-time market. The 

result of this transaction would be to raise the day-ahead price slightly due to additional 

demand and, thus, improve the convergence of the day-ahead and real-time energy prices 

due to additional supply in the real-time. Virtual trading is not limited to entities without 

assets. For example, generators or loads that prefer to transact at the real-time price may 

use virtual trading to accomplish this without having to under-schedule load or withhold 

generation from the day-ahead market by submitting matching virtual trades. 
Docket No. RM04-7-000 522 

not result in unjust and unreasonable wholesale rates, the Commission may change 

the filing requirements for engaging in these activities.1048 

922. To the extent that individual companies within a corporate family need or 

desire a tariff separate from their affiliates, the Commission will allow this, as 

discussed below. Although EEI asserts that participants in organized markets may 

need to meet the requirements of various organized markets, EEI offers no specific 

examples in this regard. Nevertheless, we believe that our action to replace the 

uniform MBR tariff proposed in the NOPR with standard provisions that we will 

require to be included in a seller’s market-based rate tariff and the allowance of seller 

specific terms and conditions in the market-based rate tariff should meet the needs of 

all sellers with market-based rate authority. 

923. We will require all market-based rate sellers to make section 206 compliance 

filings to modify their existing tariffs to include the standard required provisions set 

forth in Appendix C as well as any of the standard applicable provisions. These 

compliance filings are to be made by each seller the next time the seller proposes a 

tariff change, makes a change in status filing, or submits an updated market power 

 1048 To the extent that this position departs from our holding in California 

Independent System Operator, Inc., 89 FERC ¶ 61,153 at 61,435-36 (1999) (requiring, 

among other things, that all public utility resellers of FTRs file a rate schedule for 

authorization to make resales) we note that that analysis rested on Order No. 888’s filing 

requirements for resales of transmission capacity. As Order No. 890 has modified the 

filing requirements with respect to reassignments of transmission capacity (in addition to 

the reasons cited above) we find it appropriate not to require a separate rate schedule for 

FTRs or virtual trading at this time. 
Docket No. RM04-7-000 523 

analysis (or a demonstration that Category 1 status is appropriate) in accordance with 

the schedule in Appendix D. 

924. One of the required standard provisions (the compliance with Commission 

regulations provision) states that failure to comply with the applicable provisions of 

the regulations adopted in this Final Rule or with any Commission orders concerning 

a seller’s market-based rate authority will constitute a violation of the seller’s tariff. 

As provided in this Final Rule, the regulations at 18 CFR Part 35, Subpart H will 

become effective 60 days after publication of this Final Rule in the Federal Register. 

Accordingly, this provision will be considered part of each seller’s market-based rate 

tariff effective as of the effective date of this Final Rule. As noted above, all sellers 

will be required to amend their market-based rate tariffs to include the required 

standard provisions, as well as the required applicable provisions, either at the time 

that they file any other amendment to their current tariffs, when they report a change 

in status, or when they file their updated market power analysis, whichever occurs 

first. However, regardless of the date on which sellers make their compliance filing, 

the provision providing that failure to abide by the regulations will constitute a tariff 

violation will be considered part of each seller’s current market-based rate tariff as of 

60 days after the date of publication of this Final Rule in the Federal Register. 

2. Placement of Terms and Conditions

Comments

925. In the NOPR, the Commission observed that the purpose of a MBR tariff of 

general applicability is not to direct the terms and conditions of particular sales but to 
Docket No. RM04-7-000 524 

ensure that the tariff on file reflects in a consistent manner only those matters that are 

required to be on file, namely, the identity of the seller(s), the docket number(s) of the 

market-based rate authorization, the seller’s requirement to follow the conditions of 

market-based rate authorization contained in the proposed regulations, and that the 

rates, terms and conditions of any particular sale will be negotiated between the seller 

and individual purchasers. The Commission stated that sellers could offer other 

“generic” terms and conditions as information on a company website. 

926. In response, several commenters state that requiring companies to move 

generic terms and conditions to a company website, or to replicate them in individual 

agreements or rely on Commission orders, would be confusing and/or overly 

cumbersome.1049 Avista and FirstEnergy believe that all of the terms and conditions 

of a tariff should be in one easily accessible place; otherwise, sellers and customers 

would be deprived of the benefit of having them in one document. According to 

FirstEnergy, this “would be contrary to the goal of establishing a ‘customer-friendly 

tariff’ as contemplated in the NOPR.”1050 Further, FirstEnergy states that the fact that 

the Commission may not review individualized commercial terms included in tariffs 

does not make it unjust and unreasonable for sellers to include such terms in their 

tariffs; thus, there is no basis for the Commission to exercise its authority under FPA 

 1049 Avista at 10-12; Indianapolis P&L at 14-15; FirstEnergy at 27-31. 

1050 FirstEnergy at 29. 
Docket No. RM04-7-000 525 

§ 206 to require changes to existing market-based rate tariffs. However, Progress 

Energy agrees with the Commission that commercial terms and conditions for sales 

under the MBR tariff should not be filed for Commission review. 

Commission Determination

927. As discussed above, we find consistency of standard market-based rate tariff 

provisions to be essential, and we modify the proposal in the NOPR by adopting a set 

of standard tariff provisions that we will require each seller to include in its marketbased rate tariff, but we do not adopt the NOPR proposal that all sellers adopt the 

uniform MBR tariff of general applicability set forth in the NOPR. After careful 

consideration of the comments, we also will not adopt the NOPR proposal that sellers 

offer other generic terms and conditions as information on a company website. We 

agree with commenters as to the benefits to sellers and customers of having all terms 

and conditions relevant to a seller’s market-based rate power sales available in one 

document. Thus, we will permit sellers to list in their market-based rate tariffs 

additional terms and conditions that go beyond the standard provisions required in 

Appendix C (with the exception of transmission-related services, as discussed above), 

as modified in this Final Rule. As has been our practice in many instances, we will 

not evaluate the justness and reasonableness of such additional provisions, but will 

allow them to be included in the market-based rate tariff that is on file with the 

Commission. Our reasoning is that such additional provisions are presumptively just 

and reasonable. A seller granted market-based rate authority has been found not to 

have, or to have adequately mitigated, market power; thus, if a customer is not 
Docket No. RM04-7-000 526 

satisfied with the terms and conditions offered by a seller, the customer can choose to 

purchase from a different supplier. 

3. Single Corporate Tariff

Comments

928. ELCON supports the NOPR proposal that each corporate family have one 

tariff on file, stating that it will lead to better transparency regarding what each seller 

in a corporate family owns or controls. APPA/TAPS agree, commenting that a single 

corporate tariff addresses recurring problems with determining exactly who is 

affiliated with whom.1051 Sempra agrees in general that the single tariff structure 

should eliminate confusion that results when entities within the same corporate 

family have tariffs with terms that differ. 

929. However, a number of commenters raise potential implementation issues and 

believe that having all entities in a corporate family selling under the same tariff 

should be optional and not mandatory.1052 Several of these commenters state that the 

 1051 EEI disagrees, contending that, since companies already disclose affiliations in 

their individual market-based rate filings and are separately subject to the Commission’s 

affiliate transactions rules, any confusion about affiliations does not justify a single tariff 

requirement. EEI reply comments at 30-31. 

1052 See, e.g., EPSA at 41; Duke at 45-48; MidAmerican at 33-35; FirstEnergy at 

27-31; Constellation at 27-29; Progress Energy at 19-23; EEI at 49. Cogentrix also 

expresses reservations about requiring a single corporate tariff. See Cogentrix/Goldman 

at 6-8. 
Docket No. RM04-7-000 527 

Commission has not demonstrated the need for a single corporate tariff and believe 

that the added burden of implementation would outweigh any benefits.1053

930. Some of the problems with the single corporate tariff proposal identified by 

commenters include the following: 

· the proposal does not make sense for diversified energy companies with a variety 

of non-utility generator or power marketer affiliates because it would require increased 

regulatory and legal coordination among affiliates; 

· the burden of replacing multiple market-based rate tariffs with one umbrella tariff 

would be significant, requiring amendment and re-execution of many documents with 

many trading counterparties, as well as extensive changes to the existing quarterly 

reporting process; 

· a single tariff listing all affiliates could create confusion regarding which affiliates 

may be bound by certain executed service agreements, or which terms and conditions 

apply to certain affiliates; 

· confusion would result when trying to create a single tariff per corporate family 

when sellers can have multiple corporate families; listing the same seller on the MBR 

tariffs of multiple corporate groups would not improve transparency; and 

· given that some sellers’ upstream ownership can include multiple investors, 

passive investors, and limited partners, the proposal could impose a filing requirement on 

 1053 See, e.g., Mirant at 6-10; FirstEnergy at 27-31. 
Docket No. RM04-7-000 528 

entities that have only a passive role and may not otherwise be engaged in the energy 

business. 

931. Several commenters assert that, while they support the objective of 

simplifying tariff administration, the Commission has not considered the 

administrative and commercial ramifications of mandating one tariff per family. For 

instance, Duke cites the possibility that any seller under the corporate tariff could be 

sued for an affiliate’s alleged breach, and the complications of Company A selling 

Subsidiary X to Company B and the status of X’s sales under Company A’s tariff. 

Mirant questions how the sale of a subsidiary’s MBR tariff to a non-affiliate would be 

handled, given that the tariffs are assets that can be bought and sold. In a related 

comment, Ameren asks for which company or companies would the tariff be a 

jurisdictional facility for purposes of FPA § 203. EPSA and Sempra request 

clarification regarding how an enforcement action would be affected by the presence 

of other members of a corporate family on the same tariff, and Ameren seeks 

clarification on the effect of a revocation of market-based rate authority of only some 

companies in a corporate family. MidAmerican suggests that, since different 

affiliates within a corporate family may have authority to offer different services, a 

service schedule to the tariff should specify the products that each affiliate is 

authorized to offer and any restrictions or limitations on a seller’s market-based rate 

authorization. Morgan Stanley notes that, in many cases, the “parent” is not a 

jurisdictional entity or is a holding company, and recommends requiring each 

corporate family to designate a lead company that will submit its filing and those of 
Docket No. RM04-7-000 529 

its affiliates, rather than specifically appointing the “parent corporation” as the filing 

entity. Duke urges the Commission to consider what legal means would be required 

to ensure that the tariff is legally a separate and severable tariff for each member of a 

family. 

932. Further, commenters state that there are transitional issues that the 

Commission should consider, such as whether existing tariffs will be superseded or 

cancelled and all existing service agreements migrated to the joint tariff; which 

corporate entity would be required to file and maintain the MBR tariff; and the extent 

to which affiliates may have to file separate quarterly reports due to the fact that the 

responsible employees are not shared (e.g., regulated versus unregulated merchant 

employees). 

933. In reply comments, EPSA reiterates its opposition to a mandatory single 

corporate tariff, urging the Commission to abandon the proposal because it “poses 

major practical obstacles for corporate parents that own vastly differing 

affiliates.”1054 EPSA contends that the Commission’s premise for adopting the 

proposal, i.e., entities within a corporate family can have conflicting tariff provisions, 

is mooted by the adoption of a standardized tariff. In addition, EPSA echoes 

implementation concerns raised by other parties, in particular: (1) the situation where 

a seller is a member of two corporate families; and (2) increased regulatory burden 

 1054 EPSA reply comments at 3-4. 
Docket No. RM04-7-000 530 

from frequent tariff amendments each time ownership changes and corporate 

affiliations are terminated or created. 

934. Indianapolis P&L argues that affiliates should be permitted to maintain 

separate market-based rate tariffs for many of the reasons already cited. In addition, 

it contends that consolidation will increase the burden on many entities by requiring 

increased regulatory and legal coordination between affiliates. Whereas many 

utilities presently separate their utility and non-utility operations in part to comply 

with Commission regulations, Indianapolis P&L asserts that mandating a single tariff 

per corporate family would necessarily require utility and non-utility affiliates to 

operate in closer coordination. FirstEnergy agrees, stating that “[t]he Commission 

should not expect franchised public utilities with captive customers to market power 

totally independently of their affiliates where they are all required to sell power to 

wholesale purchasers under the same tariff.”1055

935. Finally, some commenters state that the Commission’s concerns can be 

satisfied through means other than a single tariff per corporate family. Duke 

recommends allowing affiliated utilities to operate with separate but uniform tariffs 

while posting on their corporate websites a centralized list of each of the affiliates’ 

market-based rate tariffs. Similarly, Progress Energy suggests requiring sellers to use 

 1055 FirstEnergy at 30. 
Docket No. RM04-7-000 531 

the standardized tariff but having them include a section identifying all affiliates with 

market-based rate authority and any restrictions on that authority. 

Commission Determination

936. We will modify the NOPR proposal and allow sellers to elect whether to 

transact under a single market-based rate tariff for an entire corporate family or under 

separate tariffs. The benefits that the Commission hoped to realize by requiring all 

corporate families to consolidate their operations under one tariff will be achievable 

by other means, namely, by having each individual seller revise its existing marketbased rate tariff to include the standard tariff provisions we require in this Final Rule 

and by maintaining up-to-date information on sellers’ affiliates through the 

submission of asset appendices.1056 

937. For the benefit of those sellers that choose a single corporate tariff, we clarify 

that each seller should continue to report its own transactions using the docket 

number under which it initially received market-based rate authority. 

 1056The asset appendix is discussed above in Implementation Process. 
Docket No. RM04-7-000 532 

G. Legal Authority

1. Whether Market-Based Rates Can Satisfy the Just and Reasonable 

Standard Under the FPA

Comments

938. A number of commenters challenge the Commission’s authority to adopt a 

market-based rate regime.1057 State AGs and Advocates contend that the courts have 

never actually reviewed the Commission’s market-based rate program and found that 

it satisfies the FPA. They contend that the Commission in the NOPR cited dictum in 

Louisiana Energy and Power Authority v. FERC,

1058 noting that the petitioner in that 

case did not challenge the Commission’s general policy of permitting market-based 

rates in the absence of market power. They further argue that the D.C. Circuit in 

Elizabethtown Gas Company v. FERC,

1059 relied on dictum in a prior gas case to the 

effect that, where markets are competitive, it is “rational” to assume that a seller will 

make “only a normal return on its investment.” State AGs and Advocates then 

criticize the D.C. Circuit’s opinion, arguing that “this sort of judicial economic 

theorizing does not constitute either the substantial evidence required to support 

orders of this Commission under the [FPA], or the ‘empirical proof’ required by the 

 1057 E.g., State AGs and Advocates at 3-13, 18-28, 38-40; NASUCA at 33-37. 

1058 141 F.3d 364, 365 (D.C. Cir. 1998) (LEPA). 

1059 10 F.3d 866, 870 (D.C. Cir. 1993) (Elizabethtown Gas). 
Docket No. RM04-7-000 533 

courts when an agency attempts to substitute competition for statutorily required 

regulation.”1060

939. NASUCA similarly questions the Commission’s reliance on Elizabethtown 

Gas as the legal foundation for its market-based rate regime. NASUCA suggests that 

the Supreme Court’s decision in MCI v. AT&T,

1061 casts considerable doubt on the 

vitality of Elizabethtown Gas and cases that follow its apparent endorsement of 

market-based rates that did not consider the statutory filing issues found crucial in 

MCI. NASUCA also notes that, in another case the Commission relied on, Mobil Oil 

Exploration v. United Distribution Co.

1062, the Supreme Court cited to FPC v. 

Texaco, where it held that just and reasonable rates cannot be determined solely by 

reference to market prices.1063

940. Some commenters argue that a finding that competitive markets exist is a 

prerequisite to relying upon market-based rate authority to satisfy the mandates of the 

FPA.1064 Industrial Customers contend that the Commission may rely on marketbased rate authority to produce just and reasonable rates if it finds that a competitive 

 1060 State AGs and Advocates at 8-9. 

1061 512 U.S. 218 (1994) (MCI). 

1062 498 U.S. 211 (1991). 

1063 417 U.S. 380, 397 (1974). 

1064 Industrial Customers at 3-12; NRECA at 6-10; State AGs and Advocates reply 

comments at 17-22. 
Docket No. RM04-7-000 534 

market exists and the seller lacks or has adequately mitigated market power. They 

submit that the duty to determine that a competitive market exists is separate and 

independent of the determination that a seller lacks, or has adequately mitigated, 

market power. 

State AGs and Advocates contend that the market-based rate program offers no way to 

monitor whether existing competition results in just and reasonable rates, nor a way to 

check rates if it does not.1065 

941. In reply, PNM/Tucson argues that the Commission need not entertain attacks 

on the existence of competitive power markets and the legality of market-based rates 

under the FPA, as they constitute collateral attacks on recent Commission decisions 

and the Lockyer opinion, and because a theoretical debate on the subject is beyond 

the scope of this rulemaking proceeding. PNM/Tucson asserts that those cases found 

that market-based rates are permissible by law and urges the Commission to reject 

any attacks on market-based rates generally.1066 

942. Financial Companies respond to State AGs and Advocates’ assertion that the 

Commission should suspend or revoke all market-based rates and return to cost-of-

 1065 State AGs and Advocates reply comments at 18-19, citing Farmers Union 

(finding reliance on existing competition, with no monitoring or mitigation, 

unacceptable). 

1066 PNM/Tucson reply comments at 3-4 (citing Lockyer and the underlying 

Commission orders, State of California, ex rel. Bill Lockyer v. British Columbia Power 

Exchange Corp., 99 FERC ¶ 61,247, order on reh’g, 100 FERC ¶ 61,295 (2002)). 
Docket No. RM04-7-000 535 

service ratemaking by commenting that the complaining parties mischaracterize the 

state of the wholesale market. Financial Companies enumerate the “myriad of 

approval, reporting and other obligations”1067 that constitute the Commission’s 

oversight and point out that ISOs and RTOs provide another layer of market 

monitoring and mitigation. They state that it is preferable to shape market power 

remedies addressing specific circumstances than to revoke market-based rate tariffs 

for all sellers. 

Commission Determination

943. The Commission rejects arguments that it has no authority to adopt marketbased rates or that the market-based rate program it is adopting in this rule does not 

comply with the FPA. The Supreme Court has held that “[f]ar from binding the 

Commission, the FPA’s just and reasonable requirement accords it broad ratemaking 

authority. . . . The Court has repeatedly held that the just and reasonable standard 

does not compel the Commission to use any single pricing formula in general. . . 

.”1068 It is settled law that market-based rates can satisfy the just and reasonable 

standard of the FPA, as most recently reaffirmed by the Ninth Circuit in Lockyer and 

 1067 Financial Companies reply comments at 10. 

1068 See Mobil Oil Exploration v. United Distribution Co., 498 U.S. 211, 224 

(1991) (Mobil Oil Exploration), citing FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 

(1944); FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian Basin Area 

Rate Cases, 390 U.S. 747, 776-77 (1968) (Permian); Texaco; Mobil Oil Corp. v. FPC, 

417 U.S. 283, 308 (1974). 
Docket No. RM04-7-000 536 

Snohomish,

1069 and the court in Lockyer expressly denied a “facial challenge to the 

market-based [rate] tariffs,” as discussed below. 

944. In the Lockyer court’s analysis of the Commission’s market-based rate 

authority, the Ninth Circuit cited the Supreme Court’s determination in Mobil Oil 

Exploration. It also noted that the use of market-based rate tariffs was first approved 

(by the courts) as to sellers of natural gas in Elizabethtown Gas, then as to wholesale 

sellers of electricity in LEPA. 

945. Commenters have also argued that the proposed rule impermissibly relies 

solely on the market to determine just and reasonable rates, as was the case in 

Texaco. We reject these arguments as well. 

946. In Texaco, the Supreme Court found that the Natural Gas Act (NGA) permits 

the indirect regulation of small-producer rates.1070 The Supreme Court explained that 

"[t]he Act directs that all producer rates be just and reasonable but it does not specify 

the means by which that regulatory prescription is to be attained. That every rate of 

every natural gas company must be just and reasonable does not require that the cost 

of each company be ascertained and its rates fixed with respect to its own costs."1071 

 1069 Public Utility District No. 1 of Snohomish County, Washington v. FERC, 471 

F.3d 1053 (9th Cir. 2006) (Snohomish). 

1070 Cases under the NGA and the FPA are typically read in pari materia. See, e.g., 

FPC v. Sierra Pacific Power Company, 350 U.S. 348, 353 (1956); Arkansas-Louisiana 

Gas Company v. Hall, 453 U.S. 571, 578 n.7 (1981). 

1071 417 U.S. at 387. 
Docket No. RM04-7-000 537 

The Supreme Court noted that it had sustained rate regulation based on setting area 

rates that were based on composite cost considerations, citing its decision in FPC v. 

Hope Natural Gas Co.1072 The Supreme Court further explained, with respect to the 

prior area rate cases, "we recognized that encouraging the exploration for and 

development of new sources of natural gas was one of the aims of the Act and one of 

the functions of the Commission. The performance of this role obviously involved 

the rate structure and implied a broad discretion for the Commission."1073 Quoting 

Permian Basin, the Supreme Court added that "[i]t follows that ratemaking agencies 

are not bound to the service of any single regulatory formula; they are permitted, 

unless their statutory authority otherwise plainly indicates, 'to make the pragmatic 

adjustments which may be called for by particular circumstances.’" 1074 

947. The Texaco Court further stated that "the prevailing price in the marketplace 

cannot be the final measure of 'just and reasonable' rates mandated by the Act."1075 

But, "[t]his does not mean that the market price of gas would never, in an individual 

 1072 320 U.S. at 602 ("Under the statutory standard of 'just and reasonable' it is the 

result reached not the method employed which is controlling."). 

1073 Id. at 388. 

1074 Id. at 389, citing Permian, 390 U.S. at 776-777. 

1075 Id.
Docket No. RM04-7-000 538 

case, coincide with just and reasonable rates or not be a relevant consideration in the 

setting of area rates."1076

948. In Elizabethtown Gas, a decision relying on Texaco, the D.C. Circuit 

addressed a Commission order approving a restructuring settlement under which 

Transcontinental Gas Pipeline Corporation (Transco) would no longer sell gas 

bundled with transportation, but would sell gas at the wellhead or pipeline receipt 

point, to be transported as the buyer sees fit. The sales would be market-based 

(negotiated) and the rates for transportation on Transco's system would be cost-ofservice based. In approving the settlement, the Commission had “determined that 

Transco's markets are sufficiently competitive to preclude the pipeline from 

exercising significant market power in its merchant function and to assure that gas 

prices are 'just and reasonable' within the meaning of the NGA section 4."1077 The 

Commission also "authorized Transco in advance 'to establish and to change' 

individually negotiated rates free of customer challenge under section 4 of the NGA; 

the 'only further regulatory action' possible under the settlement is the Commission's 

review of Transco's prices under section 5 of the Act, upon the Commission's own 

motion or upon the complaint of a customer that is not a party to the settlement." 1078

 1076 Id. at 399. 

1077 10 F.3d at 869. 

1078 Id.
Docket No. RM04-7-000 539 

949. In Elizabethtown Gas, the D.C. Circuit upheld the Commission's approval of 

market-based pricing, holding that “nothing in FPC v. Texaco precludes the FERC 

from relying upon market-based pricing.”1079 The D.C. Circuit explained that in 

Texaco, the Commission had failed to even mention the "just and reasonable" 

standard and appeared to apply only the "standard of the marketplace" in reviewing 

the reasonableness of the rate (which the Supreme Court had found to be 

unacceptable). Thus, the D.C. Circuit explained with approval, "the FERC has made 

it clear that it will exercise its section 5 authority (upon its own motion or upon that 

of a complainant) to assure that a market (i.e., negotiated) rate is just and 

reasonable."1080

950. The D.C. Circuit noted that the Commission had specifically found that 

Transco's markets are sufficiently competitive to preclude it from exercising 

significant market power. It further noted that the Commission had explained that 

Transco would be providing comparable transportation for all gas supplies and that 

"adequate divertible gas supplies exist" to assure that Transco would have to sell at 

competitive prices. Thus, the D.C. Circuit concluded that Transco would not be able 

to raise its price above the competitive level without losing substantial business. 

"Such market discipline provides strong reason to believe that Transco will be able to 

 1079 Id. at 870. 

1080 Id.
Docket No. RM04-7-000 540 

charge only a price that is ‘just and reasonable' within the meaning of section 4 of the 

NGA."1081

951. Likewise in LEPA, the D.C. Circuit affirmed the Commission's approval of an 

application by Central Louisiana Electric Company (CLECO) to sell electric energy 

at market-based rates. The D.C. Circuit found reasonable the Commission's 

conclusion that there are no market power considerations that should bar CLECO's 

application to sell at market-based rates. It also found reasonable the Commission's 

conclusion that even if CLECO had participated in oligopolistic behavior in the past, 

the Commission's new open access transmission rules had transformed the 

competitive environment. The D.C. Circuit noted that "competitors outside the 

current, alleged oligopoly will now be able to transmit power into CLECO's territory 

on nondiscriminatory terms." 1082 Thus, according to the D.C. Circuit, the 

Commission reasonably predicted that it was "unlikely that 'energy suppliers will 

decline to participate in the emerging competitive markets."' 1083 Finally, the D.C. 

Circuit viewed favorably the Commission's provision of a safeguard in the event that 

its predictions are wrong: 

FERC notes that should the Commission's sanguine 

predictions about market conduct turn out to be incorrect, 

 1081 Id. at 871. 

1082 141 F.3d at 370. 

1083 Id. (quoting Commission order). 
Docket No. RM04-7-000 541 

LEPA can file a new complaint for any abuses of market 

power that do occur. While this escape hatch might be 

insufficient if LEPA had shown a substantial likelihood that 

FERC's predictions would prove incorrect, it provides an 

appropriate safeguard against the uncertainties of FERC's 

prognostications where there has been no such showing.[1084] 

952. In the market-based rate program adopted in this rule and through other 

Commission actions, unlike the situation in Texaco, the Commission is not relying 

solely on the market, without adequate regulatory oversight, to set rates. Rather, it 

has adopted filing requirements (EQRs and change in status filings for all marketbased rate sellers, regularly scheduled updated market power analyses for all 

Category 2 market-based rate sellers, 1085), new market manipulation rules, and a 

significantly enhanced market oversight and enforcement division to help oversee 

potential market manipulation. In addition, for sellers in RTO/ISO organized 

 1084 Id. at 370-71 (footnotes and citations omitted). 

1085 In this Final Rule, the Commission creates two categories of sellers. Category 

1 sellers (wholesale power marketers and wholesale power producers that own or control 

500 MW or less of generation in aggregate per region; that do not own, operate or control 

transmission facilities other than limited equipment necessary to connect individual 

generation facilities to the transmission grid (or have been granted waiver of the 

requirements of Order No. 888); that are not affiliated with anyone that owns, operates or 

controls transmission facilities in the same region as the seller’s generation assets; that 

are not affiliated with a franchised public utility in the same region as the seller’s 

generation assets; and that do not raise other vertical market power issues) would not be 

required to file a regularly scheduled updated market power analysis, but would be 

subject to the change in status requirement. Category 2 sellers consist of all sellers that 

do not qualify as Category 1 sellers. 
Docket No. RM04-7-000 542 

markets, Commission-approved tariffs contain specific market rules designed to 

prevent or mitigate exercises of market power. 

953. In Lockyer, the Ninth Circuit cited with approval the Commission’s dual 

requirement of an ex ante finding of the absence of market power and sufficient postapproval reporting requirements and found that the Commission did not rely on 

market forces alone in approving market-based rate tariffs. The Ninth Circuit held 

that this dual requirement was “the crucial difference” between the Commission’s 

regulatory scheme and the FCC’s regulatory scheme, remanded in MCI, which had 

relied on market forces alone in approving market-based rate tariffs.1086 The Ninth 

Circuit thus held that “California’s facial challenge to market-based tariffs fails” and 

“agree[d] with FERC that both the Congressionally enacted statutory scheme, and the 

pertinent case law, indicate that market-based tariffs do not per se violate the 

FPA.”1087 The Ninth Circuit determined that initial grant of market-based rate 

authority, together with ongoing oversight and timely reconsideration of marketbased rate authorization under section 206 of the FPA, enables the Commission to 

meet its statutory duty to ensure that all rates are just and reasonable.1088 While the 

 1086 Id. at 1013. 

1087 Id. at 1013 & n.5; id. at 1014 (“The structure of the tariff complied with the 

FPA, so long as it was coupled with enforceable post-approval reporting that would 

enable FERC to determine whether the rates were ‘just and reasonable’ and whether 

market forces were truly determining the price.”). 

1088 See Snohomish, 471 F.3d at 1080 (in which the Ninth Circuit discusses its 

 (continued...) 

 
Docket No. RM04-7-000 543 

court in Lockyer found that the Commission’s market-based rate reporting 

requirements were not followed in that particular case, it did not find those reporting 

requirements invalid and, in fact, upheld the Commission’s market program as 

complying with the FPA. The market-based rate requirements and oversight adopted 

in this rule are more rigorous than those reviewed by the Lockyer court. 

954. Accordingly, the Commission rejects the position of commenters arguing that 

the Commission lacks authority to continue to permit market-based rates for 

wholesale sales of electricity. The courts have sustained the Commission’s finding 

that market-based rates are one method of setting just and reasonable rates under the 

FPA. As supplemented by this Final Rule, the Commission finds that the marketbased rate program complies with the statutory and judicial standards for acceptable 

market-based rates. We will retain our policy of granting market-based rate authority 

to sellers without market power under the terms and conditions set forth in this Final 

Rule and the Commission’s regulations. 

955. Further, we will retain our approach to determining whether a seller should 

receive authorization to charge market-based rates, as modified by the Final Rule, by 

analyzing seller-specific market power. The Commission has a long-established 

 

decision in Lockyer). In Snohomish, the Ninth Circuit explained, “As in Lockyer, we do 

not dispute that FERC may adopt a regulatory regime that differs from the historical costbased regime of the energy market, or that market-based rate authorization may be a 

tenable choice if sufficient safeguards are taken to provide for sufficient oversight.” Id.

at 1086. 
Docket No. RM04-7-000 544 

approach when a seller applies for market-based rate authority of focusing on whether 

the seller lacks market power.1089 This approach, combined with our filing 

requirements (EQRs, change of status filings, and regularly scheduled updated market 

power analyses for Category 2 sellers) and ongoing monitoring through our 

enforcement office and complaints filed pursuant to FPA section 206, allows us to 

ensure that market-based rates remain just and reasonable. Moreover, for sellers in 

RTO/ISO organized markets, the Commission has in place market rules to help 

mitigate the exercise of market power, price caps where appropriate, and RTO/ISO 

market monitors to help oversee market behavior and conditions. As explained in our 

earlier discussion, we believe that the market-based rate program fully complies with 

judicial precedent. 

Consistency of Market-based Rate Program with FPA Filing Requirements 

Comments

956. State AGs and Advocates contend that the Commission’s market-based rate 

program fails to comply with the FPA in several ways: (1) it ignores the FPA 

 1089 See, e.g., Heartland Energy Services, Inc., 68 FERC ¶ 61,223, at 62,060-61 

(1994); Louisville Gas and Electric Co., 62 FERC ¶ 61,016, at 61,143 n.16 (1993) (and 

the cases cited therein); Citizens Power & Light Corp., 48 FERC ¶ 61,210, at 61,776 & 

n.11 (1989); Pacific Gas and Electric Co. (Turlock), 42 FERC ¶ 61,406, at 62,194-98, 

order on reh’g, 43 FERC ¶ 61,403 (1988); Pacific Gas and Electric Co. (Modesto), 44 

FERC ¶ 61,010, at 61,048-49, order on reh’g, 45 FERC ¶ 61,061 (1988). See also, e.g., 

LEPA, 141 F.3d at 365; Consumers Energy Co., 367 F.3d 915 at 922-23 (D.C. Cir. 2004) 

(upholding Commission orders granting market-based rate authority, noting that the 

Commission’s longstanding approach is to assess whether applicants for market-based 

rate authority do not have, or have adequately mitigated, market power). 
Docket No. RM04-7-000 545 

mandate that all rates and contracts, as well as all changes in rates and contracts, must 

be filed in advance and made open to the public for prior review, and instead allows a 

seller to simply report rates after-the-fact or, in some cases, not at all; (2) it eliminates 

the statutory mandate that all rate increases must be noticed by filing 60 days in 

advance so that they can be reviewed and, if warranted, suspended for up to five 

months, set for hearing with the burden of proof on the seller, and made subject to 

refund pending the outcome of the hearing; (3) it provides no objective or 

independent standard for determining whether “competitive” market-based rates are 

in fact “just and reasonable;”1090 (4) it provides no standard for determining whether 

market rates are unduly preferential or discriminatory; and (5) it provides no way for 

consumers in most cases to know what the “just and reasonable” rate will be in 

advance. 1091 They also contend that the legal presumptions that follow from the 

Commission’s market power screens would unduly shift the burden of demonstrating 

the existence of market power to intervenors and away from the Commission. They 

argue that, until an appropriate methodology for predicting and checking market 

power is in place, the Commission must suspend its market-based rate regime and 

return to cost-of-service rates for all wholesale sales of electric power. 

 1090 State AGs and Advocates express doubt that the rate of return for power sold 

from a highly depreciated coal plant in an auction process at a market price equal to the 

marginal cost of a new, gas-fired plant could be within a zone of reasonableness. State 

AGs and Advocates at 25-26. 

1091 Id. at 19-20. 
Docket No. RM04-7-000 546 

957. NASUCA objects that the proposed rules would prohibit utilities from filing 

new wholesale energy contracts,1092 an apparent reference to the Commission’s 

policy, since the issuance of Order No. 2001,1093 that long-term affiliate sales 

contracts under a seller’s market-based rate tariff are not to be filed.1094 According to 

NASUCA, by not requiring sellers to file long-term market-based rate sales contracts, 

the Commission effectively precludes the public and others from objecting before the 

rates take effect. Additionally, NASUCA states that there is no statutory basis for a 

Commission rule directing sellers not to file their rates when the statute says exactly 

the opposite.1095 AARP similarly comments that the Commission’s policy of 

monitoring long-term market-based sales through quarterly reports is too little 

oversight too late to ensure that such rates are just and reasonable. AARP argues that 

the Commission should reconsider its policy on affiliate transactions and asserts that 

all affiliate contracts should be filed and reviewed under section 205 to comply with 

the express requirements under the FPA.1096

 1092 NASUCA at 32-33. 

1093 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 

(May 8, 2002), FERC Stats. & Regs., Regs. Preambles 2001-2005 ¶ 31,127 (2002). See

18 CFR 35.10b. 

1094 NASUCA at 27-29. 

1095 Id. at 28. 

1096 AARP at 12. 
Docket No. RM04-7-000 547 

958. NASUCA also argues that the proposed rule allows sellers with cost-based 

rates to declare their own rates without filing them, subject to Commission review 

when the sales are for less than one year. It contends that the burden of proof, under 

Farmers Union Central Exchange, Inc. v. FERC1097 and Texaco,

1098 is on the 

Commission to demonstrate empirical proof that consumers are provided the 

“complete, effective and permanent bond of protection from excessive rates” that the 

statute anticipates.1099

Commission Determination

959. We reject State AGs and Advocates’ arguments that the Commission’s 

market-based rate program fails to comply with the FPA. Contrary to State AGs and 

Advocates’ contention that the Commission’s market-based rate program “ignores the 

FPA mandate that all rates and contracts, as well as all changes in rates and contracts, 

must be filed in advance and made open to the public for prior review” and instead 

“allows sellers to simply ‘report’ rates after-the-fact, or in some cases, not at all,”1100

as the courts have found, the Commission’s market-based rate program does not 

 1097 734 F.2d 1486 (D.C. Cir. 1984), cert. denied sub nom. Williams Pipe Line 

Company v. Farmers Union Central Exchange, Inc., 469 U.S. 1034 (1984) (Farmers 

Union). 

1098 417 U.S. 380 (1974). 

1099 NASUCA cites Atlantic Ref. Co. v. Pub. Serv. Comm’n of State of N.Y., 360 

U.S. 378, 388 (1959). 

1100 State AGs and Advocates at 19. 
Docket No. RM04-7-000 548 

violate the FPA’s filing requirements. The FPA requires that every public utility file 

with the Commission “schedules showing all rates and charges for any transmission 

or sale subject to the jurisdiction of the Commission,”1101 but it explicitly leaves the 

timing and form of those filings to the Commission’s discretion. Public utilities must 

file “schedules showing all rates and charges” under “such rules and regulations as 

the Commission may prescribe,” and “within such time and in such form as the 

Commission may designate.”1102

960. We note that the courts have recognized the Commission’s discretion in 

establishing its procedures to carry out its statutory functions. For example, the Ninth 

Circuit, in denying a California Commission request to order the Commission to 

adopt different market-based rate tariff reporting requirements, observed: 

Congress specified that filings be made “within such time and with such 

form” and under “such rules and regulations as the Commission may 

prescribe.” 16 U.S.C. § 824d(c). Thus, so long as FERC has approved a 

tariff within the scope of its FPA authority, it has broad discretion to 

establish effective reporting requirements for administration of the 

tariff.[1103] 

 1101 16 U.S.C. 824d(c). 

1102 Id. 

1103 Lockyer, 383 F.3d at 1013. See also Wabash Valley Power Association v. 

FERC, 268 F.3d 1105, 1115 (citing with approval the Commission’s authority to fix just 

and reasonable rates under section 206 as a condition of its market-based rate 

authorization); Environmental Action v. FERC, 996 F.2d 401, 407-08 (D.C. Cir. 1993) 

(in which the D.C. Circuit recognized “the Commission’s determination to streamline its 

regulatory process to keep pace with advances in information technology. Ratemaking is 

a time-consuming process.”). 
Docket No. RM04-7-000 549 

961. The market-based rate tariff, with its appurtenant conditions and requirement 

for filing transaction-specific data in EQRs, is the filed rate. As the Commission has 

held, if every service agreement under a previously-granted market-based rate 

authorization had to be filed for prior approval, then the original market-based rate 

authorization would be a pointless exercise.1104

962. We also disagree with State AGs and Advocates’ argument that the marketbased rate program eliminates the statutory mandate that all rate increases be noticed 

by filing 60 days in advance and, if warranted, suspended for up to five months, set 

for hearing with the burden of proof on the seller, and made subject to refund pending 

the outcome of the hearing. The Commission has developed a thorough process to 

evaluate the sellers that it authorizes to enter into transactions at market-based rates. 

Under the market-based rate program, the rate change is initiated when a seller 

applies for authorization of market-based rate pricing. All applications are publicly 

noticed, entitling parties to challenge a seller’s claims. At that time, there is an 

opportunity for a hearing, with the burden of proof on the seller to show that it lacks, 

or has adequately mitigated, market power, and for the imposition of a refund 

obligation. In addition, if a seller is granted market-based rate authority, it must 

comply with post-approval reporting requirements, including the quarterly filing of 

 1104 GWF Energy LLC, 98 FERC ¶ 61,330, at 62,390 (2002). 
Docket No. RM04-7-000 550 

transaction-specific data in EQRs,1105 change of status filings for all sellers, and 

regularly-scheduled updated market power analyses for Category 2 sellers. 

963. In addition, we disagree with State AGs and Advocates’ arguments that the 

Commission failed to show how competitive market-based rates are just and 

reasonable and not unduly discriminatory or preferential. The standard for judging 

undue discrimination or preference remains what it has always been: disparate rates 

or service for similarly situated customers.1106 As the Commission has held in prior 

cases, and as the courts have upheld, rates that are established in a competitive market 

can be just, reasonable and not unduly discriminatory.1107 Rates do not have to be set 

by reference to an accounting cost of service to be just, reasonable and not unduly 

discriminatory. When the Commission determines that a seller lacks market power, it 

is therefore making a determination that the resulting rates will be established through 

competition, not the exercise of market power. Furthermore, the Commission’s 

market-based rate program includes many ongoing regulatory protections designed to 

 1105 The Ninth Circuit found the pre-EQR quarterly reporting requirements to be 

“integral to the [market-based rate] tariff” and that they, together with the Commission’s 

initial approval of market-based rate authority, comply with the FPA’s requirements. 

Lockyer, 383 F.3d at 1016. As discussed elsewhere in this Final Rule, through the EQRs, 

the Commission has enhanced and updated the post-transaction quarterly reporting filing 

requirements that were in place during the period at issue in Lockyer. 

1106 See, e.g., Southwestern Electric Cooperative, Inc. v. FERC, 347 F.3d 975, 981 

(D.C. Cir. 2003). 

1107 See, e.g., Lockyer, 383 F.3d at 1012-13; Tejas Power Corp. v. FERC, 980 F.2d 

998, 1004 (D.C. Cir. 1990). 
Docket No. RM04-7-000 551 

ensure that rates are just and reasonable and not unduly discriminatory or preferential. 

The filing and reporting requirements incorporated into the market-based rate 

program (EQRs, change in status filings, regularly-scheduled updated market power 

analyses) help the Commission to prevent, to discover and to remedy exercises of 

market power and unduly discriminatory rates. In addition, the adoption of pro forma

transmission tariff provisions that apply industry-wide ensures that potential 

customers are treated similarly in obtaining transmission access to energy providers. 

Moreover, Commission-approved RTOs and ISOs run real-time energy markets 

under Commission-approved tariffs.1108 These single price auction markets set 

clearing prices on economic dispatch principles, to which various safeguards have 

been added to protect against anomalous bidding. 

964. Thus, 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 should those steps be necessary. For example, based on its review of 

updated market power updates, 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 

 1108 In response to State AGs and Advocates’ argument about the rate of return for 

a seller receiving a market clearing price for power sold in an auction process, the issue 

does not concern whether a particular seller should have market-based rate authority, and 

it is more appropriately addressed in the context of an RTO/ISO proceeding rather than in 

this rulemaking proceeding. 
Docket No. RM04-7-000 552 

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. 

965. In the NOPR that preceded Order No. 2001, the Commission noted that it 

needed to make changes to keep abreast of developments in the industry, e.g., it had 

approved umbrella tariffs for market-based rates by public utilities and there had been 

a significant increase in the number of section 205 filings after the Commission’s 

open access initiatives in Order Nos. 888 and 889.1109 The Commission explained: 

 Under the Commission’s current filing requirements in 18 C.F.R. 

Part 35, individual service agreement filings associated with approved 

 1109 Open Access Same-Time Information System and Standards of Conduct, 

Order No. 889, 61 FR 21737 (1996), FERC Stats. & Regs., Regs. Preambles ¶ 31,037 

(1996), order on reh'g, Order No. 889-A, 62 FR 12484 (1997), FERC Stats. & Regs., 

Regs. Preambles ¶ 31,049 (1997), reh'g denied, Order No. 889-B, 81 FERC ¶ 61,253 

(1997), aff'd in part and rev'd in part sub nom Transmission Access Policy Study Group 

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S. 1 

(2002). 
Docket No. RM04-7-000 553 

tariffs require a significant amount of time, effort, and expense on the part 

of public utilities to prepare and serve on their customers and the 

Commission. These individual filings also require a significant amount of 

staff time and effort associated with docketing, noticing, loading the 

information onto RIMS, and other processing tasks. Further, the 

information contained in such filings that is most relevant to customers and 

the Commission could also be provided in an alternative, streamlined form, 

thus continuing to satisfy the requirements of FPA section 205(c), but in a 

more efficient manner. Accordingly, we propose to replace the filing of 

individual service agreements and Quarterly Transaction Reports with the 

filing of an electronic Index of Customers. This format will greatly 

increase the accessibility and usefulness of the relevant data, which will 

confer greater benefits to the public.[1110] 

966. The Commission implemented the revised filing requirements in Order No. 

2001. In so doing, it further explained that: 

The revised filing public utility requirements adopted in this Final Rule 

create a level playing field vis-à-vis the filing requirements applicable to 

traditional utilities and power marketers. While the data to be reported in 

the data sets reduces public utilities’ overall reporting burden as compared 

to existing requirements, it is hoped that the Electric Quarterly Reports’ 

more accessible format will make the information more useful to the public 

and the Commission will better fulfill the public utilities’ responsibility 

under FPA section 205(c) to have rates on file in a convenient form and 

place. The data should provide greater price transparency, promote 

 1110 Revised Public Utility Filing Requirements, Notice of Proposed Rulemaking, 

FERC Stats. & Regs., Proposed Regulations 1999-2003, ¶ 32,554 at 34,062 (2001). 
Docket No. RM04-7-000 554 

competition, enhance confidence in the fairness of markets, and provide a 

better means to detect and discourage discriminatory practices.[1111] 

967. Thus, we find that the multiple layers of filing and reporting requirements 

incorporated into the market-based rate program meet the filing requirements of the 

FPA and, in conjunction with our enhanced market oversight and enforcement 

functions within the Commission, as well as the ability of the public to file section 

206 complaints, provide adequate protection from excessive rates. Given our broad 

discretion to determine the procedures to carry out our statutory duties, our marketbased rate program fully complies with the requirements of the FPA.1112 

968. Although State AGs and Advocates also argue that the legal presumptions that 

follow from the Commission’s market power screens would unduly shift the burden 

of demonstrating the existence of market power to intervenors, the Commission 

previously addressed and rejected this argument. On rehearing of the April 14 Order, 

the Commission explained that nothing in that order shifts the burden of proof that 

section 205 imposes on the filing utility. Passing both screens or failing one merely 

 1111 Order No. 2001, FERC Stats. & Regs., Regs. Preambles 2001-2005 ¶ 31,127 

at P 31. 

1112 Moreover, the decision to eliminate the filing of market-based rate contracts 

was made almost five years ago in a generic rulemaking proceeding that was open to 

participation by all interested parties. Commenters’ failure to raise this concern in that 

proceeding precludes them from attacking the Commission’s well-settled practice here. 
Docket No. RM04-7-000 555 

establishes a rebuttable presumption. To challenge a seller who passes both screens, 

the intervenor need not conclusively prove that the seller possesses market power. 

Rather, the intervenor need only meet a burden of going forward with evidence that 

rebuts the results of the screens. At that point, the burden of going forward would 

revert back to the seller to prove that it lacks market power.1113 Ultimately, the 

burden of proof under section 205 belongs to the seller. 

969. With respect to NASUCA’s and AARP’s concern about long-term affiliate 

sales contracts not being filed, we note that since 2002, the Commission’s regulations 

have provided that long-term market-based rate power sales service agreements, with 

affiliates or otherwise, are not to be filed with the Commission.1114 Although 

commenters acknowledge that the Commission first considers in a separate 

proceeding whether to authorize affiliate transactions, they believe that the 

Commission should nevertheless review the resulting rates in a proceeding under 

FPA section 205 before they go into effect. 

970. NASUCA and AARP have not convinced us that this practice needs to be 

modified as a legal or policy matter. Our market-based rate program incorporates 

numerous protections against excessive rates, regardless of the identities of the parties 

to a transaction, and commenters do not provide any compelling reason why affiliate 

 1113 July 8 Order, 108 FERC ¶ 61,026 at P 29. 

1114 See 18 CFR 35.1(g) (“[A]ny market-based rate agreement pursuant to a tariff 

shall not be filed with the Commission”). 
Docket No. RM04-7-000 556 

transactions should be treated any differently. To the extent that a particular affiliate 

relationship presents issues of concern, they will be considered in the context of our 

determination whether to authorize any affiliate sales. Accordingly, we will continue 

to direct sellers not to file long-term market-based rate sales contracts, unless 

otherwise permitted by Commission rule or order. 

971. Regarding NASUCA’s assertion that our proposals would allow sellers with 

cost-based rates to declare their own rates without filing them, we emphasize that all 

mitigation proposals, whether based on the default cost-based rates or some other 

cost-based rates, must be filed with the Commission for review. As we make clear 

above in the Mitigation section of this Final Rule, any such filings are noticed, and 

interested parties are given an opportunity to intervene, comment on, or protest the 

submittal. 

972. 

2. Whether Existing Tariffs Must Be Found to Be Unjust and

Unreasonable, and Whether the Commission Must Establish a Refund 

Effective Date

Comments

973. NASUCA states that the Commission invokes sections 205 and 206 of the 

FPA as authority for the proposed action, including modifying all existing marketbased rate authorizations and tariffs so they will be expressly conditioned on or 

revised to reflect certain new requirements. NASUCA submits that any action taken 

under section 206 must be prefaced by a Commission finding that existing rates are 

unjust and unreasonable and the fixing of a refund effective date. It argues that the 
Docket No. RM04-7-000 557 

Commission has failed to make express findings necessary to support its proposal to 

modify all existing market-based rate tariffs under section 206 or to explain how it 

can modify the existing tariffs without finding that they are not just and reasonable 

and establishing a refund effective date.1115

Commission Determination

974. As discussed above in the MBR Tariff section, in requiring all sellers to revise 

their existing market-based rate tariffs to include certain standard provisions, the 

Final Rule finds that continuing to allow basic inconsistencies in the market-based 

rate tariffs on file with the Commission is unjust and unreasonable. Thus, 

NASUCA’s concern in that regard is addressed. 

975. We disagree with NASUCA that we must establish a refund effective date 

because we are establishing rules under section 206. Even if section 206 were read to 

require the establishment of a refund effective date in rulemakings initiated under 

section 206, rather than only in case-specific section 206 investigations initiated by 

complaints or sua sponte by the Commission,1116 we have broad discretion to adopt 

 1115 NASUCA at 32. 

1116 The Congressional intent of the Regulatory Fairness Act of 1988 (RFA), 

which added the refund effective date provision to section 206, was to expedite the 

resolution of complaint proceedings. Congress believed that, pre-RFA, public utilities 

had little incentive to settle meritorious section 206 complaints since any relief was 

prospective only, and the public utilities kept any revenues collected during the pendency 

of a section 206 proceeding. The purpose of the legislation was to “correct this problem 

by giving FERC the authority to order refunds, subject to certain limitations.” S.Rep. No. 

491, 100th Cong., 2d Sess. 3 (1988), reprinted in 1988 U.S.C.C.A.N. 2684, 2685. In so 

 (continued...) 

 
Docket No. RM04-7-000 558 

generic policy or make generic findings through either a rulemaking or adjudication, 

and we have discretion whether to order refunds.1117 This proceeding is not an 

adjudicatory investigation of public utilities’ existing market-based rate tariffs for 

which refunds will be required. Rather, we are modifying existing market-based rate 

tariffs prospectively only through this rulemaking.1118 Accordingly, the 

establishment of a refund effective date in this rulemaking would be meaningless. 

H. Miscellaneous

1. Waivers

Commission Proposal

976. The Commission has granted certain entities with market-based rate authority, 

such as power marketers and independent or affiliated power producers, waiver of the 

Commission’s Uniform System of Accounts (USofA) requirements, specifically 

waiver of Parts 41, 101, and 141 of the Commission’s regulations.1119 The 

 

doing, Congress left it to the Commission’s discretion to determine when the public 

interest would be served by requiring refunds under section 206, stating “Because the 

potential range of these situations cannot be fully anticipated, no attempt has been made 

to enumerate them here.” S.Rep. No. 491, 100th Cong., 2d Sess. 6, reprinted in 1988 

U.S.C.C.A.N. 2688. Nowhere in the Senate Report does Congress mention setting refund 

effective dates in rulemakings. 

1117 See, e.g., Lockyer, 383 F.3d at 1016. 

1118 E.g., Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985); SEC 

v. Chenery, 332 U.S. 194, 202-03, reh’g denied, 332 U.S. 747 (1947). 

1119 Part 41 pertains to adjustments of accounts and reports; Part 101 contains the 

Uniform System of Accounts for public utilities and licensees; Part 141 describes 

required forms and reports. 
Docket No. RM04-7-000 559 

Commission has also granted blanket approval under Part 34 of the Commission’s 

regulations for future issuances of securities and assumptions of liability where the 

entity seeking market-based rate authority, such as a power marketer or power 

producer, is not a franchised public utility. 

977. In the NOPR, the Commission noted that, as the development of competitive 

wholesale power markets continues, independent and affiliated power marketers and 

power producers are playing more significant roles in the electric power industry. In 

light of the evolving nature of the electric power industry, the Commission sought 

comment on the extent to which these entities with market-based rate authority 

should be required to follow the USofA; what financial information, if any, should be 

reported by these entities; how frequently it should be reported; and whether the Part 

34 blanket authorizations continue to be appropriate. 

978. The Commission noted that some sellers have had their market-based rate 

authority revoked, or have elected to relinquish their market-based rate authority after 

a presumption of market power, and have begun or resumed selling power at costbased rates. As discussed in the April 14 Order, any waivers previously granted in 

connection with those sellers’ market-based rate authority are no longer applicable. 

Thus, the Commission currently rescinds any accounting and reporting1120 waivers 

for mitigated sellers in the mitigated control area. Similarly, the Commission stated 

 

1120 See 18 CFR 41.10-41.12, 141.1, 141.2 and 141.400. 
Docket No. RM04-7-000 560 

in the April 14 Order that it would rescind any blanket authorizations under Part 34 

for the mitigated seller and its affiliates. In the NOPR, the Commission proposed 

that, in the case of any affiliates, this would entail rescission of blanket authorizations 

in all geographic areas, not just the mitigated control area. 

979. The Commission proposed in the NOPR that any repeal of previously granted 

waivers become effective 60 days from the date of an order repealing such waivers in 

order to provide the affected utility with time to make the necessary filings with the 

Commission and to allow for an orderly transition from selling under market-based 

rates to cost-based rates. The Commission sought comment on that proposal. The 

Commission also sought input regarding any difficulties sellers may have when 

transitioning to cost-based rates and whether a prior waiver of the accounting 

regulations would leave them without adequate data to come into conformance with 

the accounting rules. 

a. Accounting Waivers

Comments

980. The majority of commenters who comment on this topic urge the Commission 

to retain existing waivers of the accounting regulations.1121 They submit that the 

Commission’s accounting requirements are only relevant when the utility or marketer 

that is being regulated charges cost-based rates. EPSA states that where a market-

 1121 See, e.g., Ameren at 23-24; EPSA at 33-36; Constellation at 23-27; EEI at 49-

52; Morgan Stanley at 9-10; Ormet at 15-17; PPM at 6-7. 
Docket No. RM04-7-000 561 

based rate seller neither has cost-of-service rates nor captive customers from which to 

recover cost-of-service rates, requiring such entities to comply with the USofA would 

be burdensomely expensive and would serve no purpose. The commenters explain 

that there has been no change in the industry that warrants a departure from the 

Commission’s precedent. Commenters state that a change in policy would serve no 

public benefit, and the costs that such market-based rate sellers would have to incur 

in order to collect and report such data would substantially outweigh the benefit of 

collecting and reporting it. 

981. Financial Companies state that there is no reason for the Commission to run 

the risk of discouraging participation in the energy markets and chilling investment 

by requiring power marketers and power producers who currently lack market power 

to comply with the USofA absent concrete evidence that the wholesale power 

markets are being harmed by the Commission’s current practice of granting waivers 

or blanket authority.1122 

982. Absent special circumstances, Sempra supports the current waivers and 

explains that the electric quarterly transaction reports submitted pursuant to Order 

No. 20011123 provide detailed information regarding transactions entered into by 

 1122 Financial Companies at 18. 

1123 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 

(May 8, 2002), FERC Stats. & Regs. ¶ 31,127 (2002); reh’g denied, Order 2001-A, 100 

FERC ¶ 61,074 (2002); reconsideration and clarification denied, Order No. 2001-B, 100 

FERC ¶ 61,342 (2002); further order, Order No. 2001-C, 101 FERC ¶ 61,314 (2002). 
Docket No. RM04-7-000 562 

entities authorized to make market-based rate sales. Sempra also notes that the 

retention of these waivers for market-based rate entities is also consistent with the 

treatment of power marketers and exempt wholesale generators (EWGs) under the 

Public Utility Holding Company Act of 2005 and the Commission’s regulations 

promulgated thereunder.1124 

983. APPA/TAPS suggest that the Commission provide waivers to Category 1 

sellers, but not for Category 2 sellers.1125 In response to the Commission’s question 

about the orderly transition from market-based to cost-based rates and the role that 

waivers may play in making that transition more difficult, APPA/TAPS suggest that 

Category 2 sellers are more likely than Category 1 sellers to lose market-based rate 

authority and find themselves subject to cost-based rates; accordingly, not providing 

the waivers for Category 2 sellers should address these transition concerns. 

Commission Determination

984. We will continue the Commission’s historical practice of granting waiver of 

Parts 41, 101, and 141 of the Commission’s regulations to certain entities with 

market-based rate authority. We agree with EPSA that little purpose would be served 

to require compliance with accounting regulations for entities that do not sell at cost-

 1124 Sempra at 8-9, citing Public Utility Holding Company Act of 2005, Pub. L. 

No. 109-58 1261 et seq., 119 Stat. 594 (2005) (PUHCA 2005). 

1125 However, any such waivers should not exempt a holding company or service 

company from applicable reporting requirements under the Commission’s PUHCA 2005 

regulations. APPA/TAPS at 29-30. 
Docket No. RM04-7-000 563 

based rates and do not have captive customers. Such entities typically include power 

marketers and independent and affiliated power producers that are not franchised 

public utilities.1126 

985. We conclude that the costs of complying with the Commission’s USofA 

requirements and, specifically Parts 41, 101, and 141 of the Commission’s 

regulations, outweigh any incremental benefits of such compliance where the seller 

only transacts at market-based rates.1127 Further, the risk of discouraging 

participation in the energy markets and the potential chilling effect on investment 

caused by requiring power marketers and power producers, who do not otherwise 

have a cost-based rate on file with the Commission, to comply with the USofA 

outweigh the added oversight the Commission might gain in this regard. 

986. As we have done in the past, previously granted waivers of the accounting 

requirements will continue to be rescinded where a seller is found to have market 

power (or where the seller accepts a presumption of market power) and the seller 

 1126 Likewise, we will continue to grant waiver of Subparts B and C of Part 35 of 

the Commission’s regulations requiring the filing of cost-of-service information, except 

for 18 CFR 35.12(a), 35.13(b), 35.15 and 35.16. We note that this waiver would not be 

granted to an entity that makes sales at cost-based rates. 

1127 We have previously stated that Parts 41, 101 and 141 prescribe certain 

accounting and reporting requirements that focus on the assets that a utility owns, and 

waiver of these requirements is appropriate where the utility “will not own any such 

assets, its jurisdictional facilities will be only corporate and documentary, its costs will be 

determined by utilities that sell power to it, and its earnings will not be defined and 

regulated in terms of an authorized return on invested capital.” Citizens Power & Light 

Corp., 48 FERC ¶ 61,210 at 61,780 (1989). 
Docket No. RM04-7-000 564 

proposes cost-based rate mitigation or the Commission imposes cost-based rate 

mitigation. Although the Commission stated in the NOPR that it would also revoke 

the accounting waivers for any of the mitigated seller’s affiliates with market-based 

rates in the mitigated balancing authority area, we clarify that we will not require 

revocation of the accounting and reporting waivers for a power marketer affiliated 

with a mitigated seller where such power marketer has no assets, no cost-based rate 

on file, and its applicable tariff prohibits sales in the mitigated balancing authority 

area.1128 

987. With regard to APPA/TAPS’s suggestion that the Commission provide 

waivers to sellers that qualify for Category 1 and not to sellers that qualify for 

Category 2, we decline to adopt such an approach. While APPA/TAPS may be 

correct that Category 2 sellers are more likely than Category 1 sellers to possess 

market power, we do not grant such accounting waivers based on the size of the seller 

(which is, to a great extent, the critical factor in determining in which category the 

seller is placed). Rather, as discussed above, the waivers are granted on the basis of 

whether the seller is a franchised public utility or otherwise is selling at cost-based 

rates. 

988. Finally, we note that all sellers, irrespective of accounting or other waivers, 

must file EQRs regarding their transactions. In addition, we agree with APPA/TAPS 

 1128 See, e.g., APS Energy Services Company, Inc., 117 FERC ¶ 61,158 (2006). 
Docket No. RM04-7-000 565 

that any waivers in this rule do not exempt a holding company or service company 

from applicable reporting requirements under the Commission’s PUHCA 2005 

regulations. 

b. Timing

Comments

989. Regarding the proposal that rescission of accounting and reporting waivers 

become effective 60 days from the date of an order rescinding such waivers, several 

commenters state that 60 days may not be enough time for sellers who have their 

market-based rate authority revoked, or have elected to relinquish their market-based 

rate authority after a presumption of market power and have begun or resumed selling 

power at cost-based rates, to conform to the Commission’s accounting 

requirements.1129 

990. EEI supports providing such companies at least six months post revocation to 

comply with USofA recordkeeping requirements.1130 EEI states that the Commission 

should allow the companies to begin keeping records under the USofA starting at the 

beginning of the next calendar year, or the companies’ fiscal year, if different, and to 

 1129 See Ameren at 24; EEI at 48-49; Mirant at 15-16. 

1130 Mirant also supports providing six months to comply with the reporting 

requirements and states that, in addition, the Commission should grant extensions to that 

deadline based upon a demonstration that the entity is working in good faith to comply 

with the deadline but, due to factors beyond the entity’s control, the deadline needs to be 

extended. Mirant at16. 
Docket No. RM04-7-000 566 

report the information the following year.1131 EEI argues that to put USofA in place 

and begin complying with the Commission’s reporting requirements such as the 

annual FERC Form 1 and quarterly FERC Form No. 3-Q takes substantial company 

time and resources. EEI explains that companies must put the necessary accounts and 

reporting formats in place within their accounting systems. This involves substantial 

training of staff, modification of accounting software, testing to ensure proper 

internal controls under the Sarbanes Oxley Act of 2002,1132 and review by company 

management and internal and external auditors to ensure accuracy under the 

securities laws and the Sarbanes Oxley Act. EEI submits that these measures can be 

quite costly – in the millions of dollars for larger companies – and they take time to 

implement. 

991. Constellation supports the 60-day transition period as reasonable but seeks 

clarification that under this approach the entity would be required to (1) maintain its 

accounts in accordance with the Commission’s USofA only for periods beginning at 

the end of such transition period, and (2) obtain specific authorization for securities to 

be issued, or liabilities to be assumed, subsequent to the end of such transition 

period.1133

 1131 EEI at 48-49. 

1132 Sarbanes Oxley Act of 2002, Pub. L. No. 107-204, 116 Stat. 745. 

1133 Constellation at 33. See also PPL at 26-27 (supports proposal to keep waivers 

effective for 60 days from date of order revoking market-based rate authority).
Docket No. RM04-7-000 567 

Commission Determination

992. We adopt the NOPR proposal that rescission of waivers of Parts 41, 101 and 

141 of the Commission’s regulations granted in connection with a seller’s marketbased rate authority will become effective 60 days from the date of an order revoking 

such waivers. We believe that this strikes a reasonable balance between the need to 

have adequate financial information on file with the Commission and the desire to 

provide sellers adequate time to comply. 

993. In our consideration of the transition period for complying with the accounting 

and reporting requirements, the Commission finds that commenters have not 

sufficiently supported their request for a transition period of six months or more. 

EEI’s arguments with respect to the time and money required to train staff and 

modify and test accounting software do not outweigh the need for the Commission to 

obtain financial information with regard to mitigated sellers so that we can meet our 

obligation under the FPA to ensure that rates remain just and reasonable and not 

unduly discriminatory or preferential. We note that our experience has shown that a 

60 day transition period is sufficient time for a mitigated seller to comply with the 

accounting requirements.1134

 1134 See Entergy Services, Inc, 115 ¶ FERC 61,260 (2006) (revoking waivers and 

authorizations previously granted to certain Entergy Affiliates). Accounting systems 

were in place within 60 days from the effective date of the order rescinding the waivers 

and the company was granted an additional 30 day extension to file the upcoming 

quarterly report. See Entergy Services, Inc., Docket No. AC06-257-000 (Nov. 21, 2006) 

(unpublished letter order). 
Docket No. RM04-7-000 568 

994. In response to Constellation’s request for clarification, we clarify that a seller 

losing or relinquishing its market-based rate authority will be required to maintain its 

accounts in accordance with the Commission’s USofA1135 and will be subject to 

quarterly and annual reporting requirements (FERC Form Nos. 3-Q, 1, or 1-F)1136 as 

of the effective date of the rescission of such waivers, i.e., 60 days from the date of 

the order rescinding the waivers. In this regard, such sellers will be required to 

comply with our accounting regulations (Part 101) beginning with the effective date 

of the rescission of such waiver. For quarterly reporting in FERC Form No. 3-Q, the 

seller will be required to submit FERC Form No. 3-Q beginning with the quarter in 

which the rescission of the accounting and reporting waivers becomes effective.1137 

The seller will also be required to submit a FERC Form No. 1 or 1-F, as applicable, 

beginning in the year in which the rescission of the accounting and reporting waivers 

becomes effective.1138 For example, if the effective date of rescission occurs on May 

15, the seller must make the 3-Q filing for the second quarter (April-June) at its 

 1135 18 CFR Part 101. 

1136 See 18 CFR 141.1, 141.2, 141.400. 

1137 The first quarterly filing made by the seller will include information from the 

effective date of the rescission through the end of the calendar quarter. 

1138 The first annual filing of FERC Form No. 1 or 1-F will include information 

beginning with the effective date of the rescission through the end of the calendar year. 

Additionally, there is a requirement that goes along with these forms that requires the 

submission of a CPA Certification Statement (18 CFR 41.10 – 41.12). 
Docket No. RM04-7-000 569 

regularly scheduled time even though it has not previously filed a Form 1.1139 If a 

particular seller is unable to meet the applicable filing dates, it may petition the 

Commission for an extension. We will consider such requests on a case-by-case 

basis. 

c. Part 34 Waivers Blanket Authorizations

Comments

995. In response to the Commission’s inquiry regarding whether Part 34 blanket 

authorizations (pertaining to issuances of securities or assumptions of liabilities) 

continue to be appropriate, all commenters addressing the issue urge the Commission 

to retain its current policy.1140 They submit that Commission oversight of securities 

issuances and assumptions of liabilities is only relevant for franchised public utilities 

and that prior authorization under section 204 is not necessary for market-based rate 

sellers that do not intend to “’become a public service franchised providing electricity 

to consumers dependent upon [their] services.’’1141 Financial Companies state that 

there is no reason for the Commission to risk adversely affecting energy markets by 

 1139 In this example, the seller’s 3-Q for the second quarter must reflect our 

accounting regulations as of May 15, the effective date of rescission of such waivers. 

1140 See, e.g., Cogentrix at 3-6; PPL at 25-27; TXU at 5-7; AWEA at 4-5; Duke 

supplemental comments at 1-8; Powerex at 26-28. 

1141 See Cogentrix at 5, citing Citizens Energy Corp., 35 FERC ¶ 61,336 at 61,455 

(1986). Cogentrix notes that entities with such blanket authorizations do not provide the 

service that franchised utilities are obligated to offer to their captive customers and that 

FPA section 204 and 18 CFR Part 34 are intended to protect. 
Docket No. RM04-7-000 570 

requiring entities that currently lack market power to secure agency approval each 

time they want to issue securities or assume liabilities. 

996. With regard to the statement in the NOPR that the Commission will rescind 

blanket authorizations for the mitigated seller and its affiliates in all geographic areas, 

not just the mitigated control area, Duke strongly opposes rescission of blanket 

section 204 authorizations for all affiliates of the mitigated seller in all markets. 

Duke urges the Commission to limit such rescission only to those market-based rate 

sellers making sales to captive customers in areas where there is a finding of market 

power.

1142 Duke states that the purpose of section 204 is to ensure the financial 

viability of franchised public utilities. As a result, prior authorization is appropriate 

for independent and affiliated power marketers with market-based rate authority who 

do not intend to assume public service franchise obligations. 

997. Duke argues that the Commission has not explained how issuance of a security 

or assumption of a liability by an affiliated marketer or merchant generator could be 

contrary to the public interest merely because an affiliate is deemed to have market 

power in power sales markets in a particular geographic area. Duke asserts that there 

is no evidence presented in the NOPR that would support the presumed linkage 

between a determination of a seller’s market power in a particular geographic market 

 1142 Duke supplemental comments at 1-8. See also PPL at 26 (loss of any waiver 

should apply only to the seller or affiliates that make wholesale sales in the control area 

where market-based rate authority is lost, but not to affiliates that do not conduct business 

in that control area). 
Docket No. RM04-7-000 571 

and the ability of that seller’s affiliates to leverage such market power in other 

geographic markets through their issuances of securities or debt. Duke says that this 

is especially true in the case of entities such as the Duke affiliates, which have 

amended their tariffs to preclude market-based rate sales in the Duke Power control 

area, the only geographic market where the company was determined to have market 

power. Given that no market-based rate sales will be made by the affiliates in the 

only geographic area where there was even an issue of market power, Duke states 

that there is no possible nexus between securities issuances by these entities and 

protecting the franchised customers of Duke’s traditional utility affiliates. 

998. Duke concludes that the Commission should determine that blanket 

authorizations under section 204 for market-based rate sellers should not be affected 

by a finding that a utility affiliate can exercise market power in its control area or 

other geographic markets. In the alternative, Duke asks the Commission to determine 

that, in cases where sellers cannot sell power at market-based rates in the geographic 

market(s) where an affiliated traditional utility is found to have market power, there 

can be no anti-competitive effects or need to protect franchise customers, and thus 

affiliated sellers should be able to obtain (or retain) blanket section 204 

authorizations. 

Commission Determination

999. We will continue to grant blanket approval under Part 34 for future issuances 

of securities and assumptions of liability where the entity seeking market-based rate 

authority, such as a power marketer or power producer, is not a franchised public 
Docket No. RM04-7-000 572 

utility or does not otherwise provide requirements service at cost-based rates.1143 The 

Commission traditionally has granted blanket authorization for the issuance of 

securities and assumptions of liability to power sellers not subject to cost-based rate 

regulation, i.e., power sellers that have market-based rate authority.1144 As the 

Commission has explained in previous cases involving market-based rate authority in 

which the sellers sought blanket authorization of issuances of securities or 

assumptions of liability, the purpose of section 204 of the FPA, which Part 34 

implements, is to ensure the financial viability of public utilities obligated to serve 

consumers of electricity.1145 Accordingly, where the seller is not a franchised public 

utility providing electric service to customers under cost-based regulation and has 

market-based rate authority, the Commission’s practice is to grant the blanket 

authorization, subject to consideration of objections by an interested party. 

1000. We do not adopt the NOPR proposal concerning the rescission of blanket 

authorizations for affiliates of mitigated sellers. After careful consideration of the 

comments received, we will limit such rescission to the mitigated seller and its 

 1143 See, e.g., Golden Spread Electric Coop., Inc., 97 FERC ¶ 61,025 at 61,070 

(2001) (“While Golden Spread has been granted market-based rate authority, it also 

makes requirements sales under Commission-accepted, cost-based rates. Since Golden 

Spread sells power at cost-based rates and not solely at market-based rates, it fails to 

qualify for blanket approval to issue securities.”). 

1144 Merrill Lynch Commodities, Inc., 108 FERC ¶ 61,233 at P 16 (2004). 

1145 Id. (citing Citizens Energy Corp., 35 FERC ¶ 61,198 at p. 61,455 (1986); 

Howell Gas Management Co., 40 FERC ¶ 61,336 at p. 62,026 (1987). 
Docket No. RM04-7-000 573 

affiliates making sales within the mitigated balancing authority area. Our decision 

here takes into account Duke’s and PPL’s arguments against rescission of blanket 

authorization for all affiliates in all markets. We conclude that it is not necessary to 

rescind such blanket authorizations in the case of affiliates that make sales outside of 

the mitigated balancing authority area because the seller retains its market-based rate 

authority in unmitigated markets. We clarify that the effective date for rescinding 

blanket authorization under Part 34 will be commensurate with the date on which a 

mitigated seller begins to sell power at cost-based rates. Further, sellers losing their 

market-based rate authority must file with the Commission to obtain specific 

authorization for securities to be issued, or liabilities to be assumed, prior to the date 

the seller first sells at cost-based rates. 

2. Sellers Affiliated with a Foreign Utility

Commission Proposal

1001. Under existing policy, a seller affiliated with a foreign utility selling in the 

United States (and each of its affiliates) must not have, or must have mitigated, 

market power in generation and transmission and not control other barriers to entry. 

In addition, the Commission considers whether there is evidence of affiliate abuse or 

reciprocal dealing. However, for sellers affiliated with a foreign utility, the 

Commission has allowed a modified approach to the current four prongs. 

1002. With regard to generation market power, should any of the seller’s first-tier 

markets include a United States market, the seller performs the market power screens 

in that control area(s). With regard to transmission market power, the Commission 
Docket No. RM04-7-000 574 

requires the seller affiliated with a foreign utility seeking market-based rate authority 

to demonstrate that its transmission-owning affiliate offers non-discriminatory access 

to its transmission system that can be used by its competitors to reach United States 

markets. The Commission does not consider transmission and generation facilities 

that are located exclusively outside of the United States and that are not directly 

interconnected to the United States. However, the Commission would consider 

transmission facilities that are exclusively outside the United States but nevertheless 

interconnected to an affiliate’s transmission system that is directly interconnected to 

the United States. A seller affiliated with a foreign utility must inform the 

Commission of any potential barriers to entry that can be exercised by either it or its 

affiliates in the same manner as a seller located within the United States. Regarding 

affiliate abuse, the requirement that a power marketer with market-based rate 

authority file for approval under section 205 of the FPA before selling power to a 

utility affiliate does not apply to situations involving sales of power to a foreign 

utility outside of the Commission’s jurisdiction. 

1003. The Commission proposed in the NOPR to retain its current policy when 

reviewing the application for market-based rate authorization by a seller affiliated 

with a foreign utility, and sought comment regarding whether the current policy is 

adequate to grant market-based rate authorization to such sellers. No comments were 

submitted on the broad question of whether our current policy, in general, is 
Docket No. RM04-7-000 575 

adequate. However, Powerex and NL Hydro1146 raise specific issues that are 

addressed below. As discussed below, we conclude that our current approach needs 

no modification. Accordingly, we will adopt the NOPR proposal to retain our current 

policy when reviewing an application for market-based rate authority by a seller 

affiliated with a foreign utility. 

Comments

1004. Powerex notes that comparability for non-jurisdictional United States-based 

transmission providers ("unregulated transmitting utilities" under the FPA) is now 

defined by statute to mean service "at rates that are comparable to those that the 

unregulated transmitting utility charges itself" and "on terms and conditions that are 

comparable to those under which the unregulated transmitting utility provides 

transmission services to itself and that are not unduly discriminatory or 

preferential."1147 Powerex notes that, in the OATT Reform NOPR, the Commission 

proposed to apply the comparability requirement of FPA section 211A on a case-bycase basis, i.e., by complaint.1148 Powerex states that, under principles of national 

treatment as set out in the North American Free Trade Agreement (NAFTA), the 

Commission should impose no more stringent a burden on similarly non-

 1146 NL Hydro is a Crown Corporation owned by the Government of 

Newfoundland and Labrador. 

1147 16 U.S.C. 824j-1(b). 

1148 OATT NOPR at P 111. 
Docket No. RM04-7-000 576 

jurisdictional Canadian and Mexican transmission-owning utilities. For that reason, 

Powerex urges the Commission to clarify that it will presume that Canadian and 

Mexican transmitting utilities are providing comparable and not unduly 

discriminatory or preferential transmission service unless this presumption is 

otherwise rebutted by third party or Commission-instituted complaint.1149 

1005. NL Hydro urges the Commission to reject Powerex’s suggestion that the 

Commission no longer should require market-based rate sellers to affirmatively 

demonstrate that non-discriminatory access is offered on transmission facilities that 

they or their affiliates own, control, or operate outside of the United States. NL 

Hydro argues that the comparability standard of FPA section 211A does not govern 

the Commission’s market-based rate analysis of transmission market power.1150 It 

states that the Commission has not suggested, in either this proceeding or the OATT 

rulemaking, that the comparability standard in FPA section 211A should create a 

presumption that any market-based rate seller (domestic or affiliated with a foreign 

utility) should be presumed to have passed the transmission market power test.1151

1006. NL Hydro supports the Commission’s proposal to retain its existing 

requirements with respect to the mitigation of transmission market power when 

 1149 Powerex at 32.

1150 NL Hydro reply comments at 3. 

1151 Id. at 5. 
Docket No. RM04-7-000 577 

reviewing the market-based rate applications of sellers affiliated with a foreign utility. 

According to NL Hydro, these requirements establish a reasonable balance among 

important regulatory objectives by: (1) requiring non-discriminatory access to 

foreign transmission facilities for access to United States markets as a condition of 

market-based rate authority; (2) complying with the national treatment requirements 

of NAFTA; and (3) applying principles of comity to the jurisdiction of foreign 

regulatory authorities with direct regulatory jurisdiction over foreign transmission 

entities.1152 Accordingly, NL Hydro believes that the Commission should codify in 

its regulations the requirement that a market-based rate seller, or its affiliate, that 

owns, controls, or operates transmission facilities outside of the United States must 

demonstrate that non-discriminatory access is offered on those facilities so that 

competitors of the seller may reach United States markets. 

Commission Determination

1007. We will continue to require a seller seeking market-based rate authority that is 

a foreign utility or is affiliated with a foreign utility to affirmatively demonstrate that 

any owned or affiliated transmission is offered on a non-discriminatory basis that can 

be used by competitors of the seller or its affiliate to reach United States markets. 

Accordingly, we reject Powerex’s suggestion that the Commission should presume 

that foreign transmitting utilities are providing comparable and not unduly 

 1152 NL Hydro at 13. 
Docket No. RM04-7-000 578 

discriminatory or preferential transmission service unless this presumption is 

rebutted. The Commission did not propose to implement section 211A of the FPA in 

Order No. 890 and section 211A is not relevant to the Commission’s analysis for 

purposes of granting or denying market-based rate authority.1153

1008. We will codify in § 35.37(d) of the Commission’s regulations the requirement 

that a market-based rate seller affiliated with a foreign utility, or its affiliate, that 

owns, controls, or operates transmission facilities outside of the United States and is 

interconnected with the United States must demonstrate that comparable, nondiscriminatory access is offered on those facilities so that competitors of the seller 

may reach United States markets. 

3. Change in Status

Commission Proposal

1009. In early 2005, the Commission clarified and standardized market-based rate 

sellers’ reporting requirements for any change in status that departed from the 

characteristics the Commission relied on in initially authorizing sales at market-based 

rates. In Order No. 652,1154 the Commission required, as a condition of obtaining and 

retaining market-base rate authority, that sellers file notices of such changes no later 

than 30 days after the change in status occurs. In the NOPR, the Commission sought 

comment on a number of issues that the Commission identified in Order No. 652 as 

 1153 Order No. 890, FERC Stats. & Regs. ¶ 31,241 at P 192. 

1154 Order No. 652 at P 47. 
Docket No. RM04-7-000 579 

issues that could be pursued in this proceeding. The Commission solicited comment 

on whether ownership of any new inputs to electric power production, including fuel 

supplies, should be reportable. To the extent that any such information is deemed 

reportable, the Commission proposed to align this reporting requirement to reflect the 

consideration of other barriers to entry as part of the vertical market power analysis. 

1010. The Commission proposed, consistent with Order No. 652, not to require the 

reporting of transmission outages per se as a change in status. However, to the extent 

a transmission outage affects on a long-term basis whether the seller satisfies the 

Commission’s concerns regarding horizontal or vertical market power, a change of 

status filing would be required. The Commission sought comment on this proposal. 

The Commission declined in Order No. 652 to narrow or delineate the definition of 

control. The Commission concluded that it is not possible to predict every contractual 

agreement that could result in a change of control of an asset; however, the Commission 

indicated that to the extent that parties wish to propose specific definitions or 

clarifications to the Commission’s historical definition of control, they may do so in the 

course of the instant rulemaking.1155 

1011. As proposed in the NOPR (§ 35.43 of the proposed regulations), events that 

constitute a change in status include the following: first, ownership or control of 

generation capacity that results in net increases of 100 MW or more, or of 

 1155 Id. at P 47. 
Docket No. RM04-7-000 580 

transmission facilities, or of inputs to electric power production other than fuel 

supplies; or, second, affiliation with any entity not disclosed in an application for 

market-based rate authority that owns, operates, or controls generation or 

transmission facilities or inputs to electric power production, or affiliation with any 

entity that has a franchised service area.1156

The Commission invited comment generally on whether the Commission should expand 

the triggering events for a change in status filing beyond what was adopted in Order No. 

652. In Order No. 652, we concluded that the reporting obligation should extend only to 

changes in circumstances within the knowledge and control of the seller. 

a. Fuel Supplies

Comments 

1012. Some commenters in general support the idea that ownership of fuel supplies 

should not be a factor in the vertical market power analysis and should not trigger a 

requirement to file a notice of change in status.1157 APPA/TAPS support the 

reporting of the acquisition of the means of production or transportation of fuel but 

not the reporting of the acquisition of fuel itself. APPA/TAPS explain that 

acquisition or control over companies that produce or deliver fuel and acquisitions of, 

or affiliations (including through joint ventures) with, production or transportation 

 1156 NOPR at P 179-182. 

1157 APPA/TAPS at 90-91; EEI at 21; Constellation at 23. 
Docket No. RM04-7-000 581 

resources (including LNG facilities) are inputs into electric power production that can 

raise significant competitive concerns. APPA/TAPS submit that, unlike fuel, the 

means of production or transportation of fuel are not so readily obtainable from 

alternative sources.1158 They argue that while entry from new storage or 

transportation facilities/transporters is possible, such entry involves sufficient siting 

difficulties and capital requirements that it cannot be assumed to be timely, likely or 

sufficient to remove competitive concerns. 

1013. Constellation suggests that the Commission should clearly distinguish between 

fuel supplies (including the capacity to produce and process them) and physical 

facilities used to transport or distribute fuel supplies. Constellation believes that 

ownership of fuel supply does not contribute to market power because of the 

availability of alternative suppliers. Constellation states that, while ownership or 

control of physical facilities to transport or distribute fuel has the potential to 

contribute to market power in some cases, such potential generally is blunted by 

regulation or by the availability of substitutes. Constellation asserts that ownership of 

facilities for the production or processing of coal or other fuels should not be 

reportable because alternative sources of supply can substitute for the coal or other 

fuels that can be produced or processed by such facilities. Constellation states that in 

specific instances, if any intervenor believes that fuel supplies (or fuel production or 

 1158 APPA/TAPS at 90-91, citing San Diego Gas & Elec. Co., 83 FERC ¶ 61,199 

(1998) (gas/electric merger). 
Docket No. RM04-7-000 582 

processing facilities) are not available from alternative suppliers for delivery in the 

relevant geographic region, the party could provide appropriate information in an 

attempt to rebut a market-based rate seller’s statement that it cannot erect barriers to 

entry in relevant markets.1159

1014. Constellation believes that the purchase of natural gas transportation or storage 

on intrastate or interstate pipelines should not trigger any change in status reporting 

requirement. It states that these transactions do not involve ownership or control of 

physical facilities for the transportation or storage of natural gas. Moreover, because 

capacity is available from the natural gas transportation and storage providers 

themselves, and through capacity release programs from other customers of such 

providers, Constellation believes that the purchase of such capacity does not 

contribute to the seller’s vertical market power.1160 

Commission Determination

1015. The Commission will not expand the change in status reporting requirement to 

include the reporting of a change in ownership or control of natural gas and oil 

supplies, or affiliation with an entity that owns or controls such fuel supplies. 

However, we will require the reporting of a change in status with regard to the 

ownership or control of, or affiliation with, any entity not disclosed in the application 

 1159 Constellation at 24-25. 

1160 Id. at 25. 
Docket No. RM04-7-000 583 

for market-based rate authority that owns, or controls “inputs to electric power 

production,” where that term is defined as “intrastate natural gas transportation, 

intrastate natural gas storage or distribution facilities; sites for new generation 

capacity development; sources of coal supplies and the transportation of coal supplies 

such as barges and railcars.” The Commission adopts this approach to align the 

change in status reporting requirement to reflect the other barriers to entry part of the 

vertical market power analysis. 

1016. We will adopt the current change in status requirement with the following 

modifications.1161 We will delete the phrase “other than fuel supplies” from proposed 

§ 35.43(a)(1) (now § 35.42(a)(1)). We originally proposed that events that constitute 

a change in status include “[o]wnership or control of generation capacity that results 

in net increases of 100 MW or more, or transmission facilities or inputs to electric 

power production other than fuel supplies.” In light of the definition of “inputs to 

electric power production” that we adopt in this Final Rule, there is no longer a need 

in § 35.42(a)(1) for the phrase “other than fuel supplies.” As noted above in the 

discussion on vertical market power, in this Final Rule we modify the definition of 

“inputs to electric power production” to mean “intrastate natural gas transportation, 

intrastate natural gas storage or distribution facilities; sites for new generation 

capacity development; sources of coal supplies and the transportation of coal supplies 

 1161 Another change to 18 CFR 35.42 is described above in the implementation 

section. 
Docket No. RM04-7-000 584 

such as barges and railcars.” The definition of “inputs to electric power production” 

includes “sources of coal supplies,” and therefore, including the phrase “other than 

fuel supplies” would be inaccurate. However, we note that the ownership or control 

of certain other fuel supplies (i.e., gas and oil supplies) will not require a notice of 

change in status. 

1017. Next, we are modifying the change in status provisions to be consistent with 

the horizontal and vertical market power provisions which we are adopting. Section 

35.42, as adopted herein, differs from the NOPR proposal in that we will require 

change in status notifications for changes in ownership or control of inputs to electric 

power production. Additionally, change in status notifications will be required for 

changes in operation, in addition to ownership and control, of transmission facilities. 

Similarly, we will require a change in status notification for affiliation with any entity 

not disclosed in the application for market-based rate authority that owns or controls 

generation facilities or inputs to electric power production and any entity not 

disclosed in the application for market-based rate authority that owns, operates or 

controls transmission facilities. 

1018. In response to APPA/TAPS, we clarify that the Commission’s change in status 

requirements are intended to track the requirements embedded in the horizontal and 

vertical analysis as well as the affiliate abuse representations. As clarified in the 

other barriers to entry part of the vertical market power analysis described in this 

Final Rule, the Commission will not require an analysis or affirmative statement with 

regard to ownership or control of, or affiliation with, an entity that owns or controls 
Docket No. RM04-7-000 585 

natural gas and oil supplies, the interstate transportation of natural gas, or the 

transportation of oil. In contrast, we will require 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 (defined as “inputs to electric power production” in 

the regulations); however, we adopt a rebuttable presumption that sellers cannot erect 

barriers to entry with regard to inputs to electric power production. Thus, while a 

seller is required to describe in a change in status filing any ownership of, control of 

or affiliation with entities that own or control inputs to electric power production (just 

as it must do in an initial application for market-based rate authority and an updated 

market power analysis), we will rebuttably presume that such ownership, control or 

affiliation does not allow a seller to raise entry barriers. We will, however, allow 

intervenors to demonstrate otherwise. 

1019. Further, in response to Constellation, we note that we presently do not require 

the reporting of capacity contracted for, but for which control is not transferred, with 

regard to interstate or intrastate natural gas pipeline or storage capacity and we agree 

that there is no compelling reason to begin doing so. 
Docket No. RM04-7-000 586 

b. Transmission Outages

Comments

1020. Numerous commenters support the Commission’s current policy and proposal 

not to require the reporting of transmission outages per se as a change in status.1162 

1021. Some commenters support the proposal not to require the reporting of all 

transmission outages per se because they believe that requiring sellers to report all 

transmission outages as changes in status would prove an overwhelming 

administrative burden with no market benefits.1163 Indianapolis P&L states that this 

approach balances the need for the Commission to have updated information with the 

need for sellers to focus on their business, rather than administrative filings.1164 EEI 

supports the current policy that only long-term transmission outages that could affect 

the Commission’s analysis of vertical and horizontal market power should be 

reportable.1165

1022. APPA/TAPS state that at least some transmission outage information is (or 

should be) publicly available on OASIS sites, suggesting less of a need to impose a 

 1162 APPA/TAPS at 87-89; Indianapolis P&L at 15; EEI at 21; MidAmerican at 

35-36; and Powerex at 34. 

1163 MidAmerican at 36; Indianapolis P&L at 15; EEI at 21. 

1164 Indianapolis P&L at 15. 

1165 EEI at 21. 
Docket No. RM04-7-000 587 

separate reporting requirement for such outages.1166 However, APPA/TAPS urge that 

certain outages be reported to the Commission’s Office of Enforcement on a nonpublic basis and that the Commission reserve its authority to require change of status 

reports for other, significant outages.1167 We note, however, that APPA/TAPS fail to 

provide examples of the types of outages that they believe should be reportable. 

1023. APPA/TAPS also suggest that the Commission identify for specific marketbased rate sellers generation and transmission facilities that, if there is an extended or 

repeated outage, could produce significant transmission constraints or reductions in 

the amount of available generation in that seller’s market(s). They suggest that the 

Commission, in conjunction with an RTO/ISO market monitor (where one exists), 

could identify and designate in that seller’s market-based rate authorization the key 

transmission facilities and/or generation units that are likely to increase competitive 

concerns if they go out of service. Because of the increased potential for market 

power harm associated with the outage of these facilities, APPA/TAPS suggest that 

the Commission could require a market-based rate seller under the terms of its 

market-based rate authorization to report publicly as a change in status outages of 

these specified facilities.1168

 1166 APPA/TAPS at 88. 

1167 Id. at 87-88. 

1168 APPA/TAPS at 88-89. 
Docket No. RM04-7-000 588 

1024. Powerex believes that additional clarification is necessary to determine what 

the Commission means by "long-term outages" that may affect a seller's market 

power analysis. Powerex also requests that the Commission consider whether 

transmission outages on a non-jurisdictional or foreign affiliate's transmission system 

should be considered a change in status that is reportable under Order No. 652, given 

the limits of the Commission's jurisdictional interests. 

Commission Determination

1025. We adopt the NOPR proposal not to require the reporting of transmission 

outages per se as a change in status. We agree that the reporting of all transmission 

outages, including the most routine, would be an excessive burden on sellers with no 

apparent countervailing benefit. However, consistent with Order No. 652, we 

reiterate that to the extent a long-term transmission outage affects one or more of the 

factors of the Commission’s market-based rate analysis (e.g., if it reduces imports of 

capacity by competitors that, if reflected in the generation market power screens, 

would change the results of the screens from a “pass” to a “fail”), a change of status 

filing is required.1169 

1026. We reject APPA/TAPS’s suggestion that the Commission should require the 

automatic reporting of some transmission outages to the Office of Enforcement. 

 1169 In response to Powerex’s request for clarification on what the Commission 

means by “long-term outages” that may affect a seller’s market power analysis, we 

clarify that the Commission uses the term “long-term” to mean one year or longer. 
Docket No. RM04-7-000 589 

APPA/TAPS fails to adequately explain why we should assume certain transmission 

outages are, as a matter of routine, an enforcement matter to be investigated for 

wrongdoing. 

1027. We also reject APPA/TAPS’ suggestion that the Commission identify certain 

generation and transmission facilities that could produce significant transmission 

constraints or reductions in the amount of generation available in that market-based 

rate seller’s market(s). Public identification of such generation and transmission 

facilities could cause CEII and security concerns. In addition, outages that could 

affect a seller’s market-based rate analysis will change over time. The burden 

remains on the market-based rate seller to identify the outages that should be reported 

as a change in status. We also remind commenters that entities may file a complaint 

or call the Office of Enforcement hotline if they are concerned that an outage 

provides the opportunity for a seller to exercise market power. Regarding Powerex’s 

request that the Commission consider whether transmission outages on a nonjurisdictional or foreign affiliate's transmission system should be considered 

reportable under Order No. 652, given the limits of the Commission's jurisdictional 

interests, we clarify that, consistent with our change in status reporting requirement in 

general, to the extent that a transmission outage reflects a change in the 

characteristics that the Commission relied on (e.g., if it reduces imports of capacity 

by competitors that, if reflected in the generation market power screens for U.S. 

markets, would change the results of the screens from a “pass” to a “fail”), a change 

of status filing would be required. The change in status requirement is an important 
Docket No. RM04-7-000 590 

element of the Commission’s market power oversight. If a seller affiliated with a 

foreign utility wishes to retain market-based rate authority in the United States, such 

seller must comply with the notice of change in status requirements, including the 

reporting of transmission outages that may change the results of the screens from a 

“pass” to a “fail.” The Commission finds no reason to exempt a seller affiliated with 

a foreign utility from this requirement. 

c. Control 

Comments

1028. Several commenters note that increased precision in the Commission's 

definition of control would be particularly helpful to sellers, especially in light of the 

increased emphasis on reporting accuracy and completeness and the Commission’s 

general practice of accepting change in status filings in letter orders, without 

providing much detailed analysis or explanation as to whether the filings were 

required in the first place.1170 These commenters seek clarification that energy 

contracts that are not associated with a specific resource (do not specify a “source”) 

do not transfer control. EEI and SoCal Edison argue that such contracts or liquidated 

damages call option contracts do not transfer control because, at their core, they are 

financial transactions used to mitigate the buyer’s price risk.1171 According to 

 

 (continued...) 

 

1170 EEI at 21-22; SoCal Edison at 10-14; Williams at 1; and Powerex at 33. 

1171 EEI offers an example of a firm energy call option that, in response to a dayahead call by the buyer, gives the seller the option of delivering energy from its own 
Docket No. RM04-7-000 591 

commenters, the option holder does not actually control any particular capacity that 

might be used to meet the contract needs. The energy could come from the seller, 

from the market through the seller, or directly from the market to the buyer if the 

seller opts to pay liquidated damages. They submit that if such a contract were 

deemed to transfer “control,” execution of such routine contracts would trigger a 

change in status filing for each incremental 100 MW purchased thereby, which is 

most likely not what the Commission intended. 

1029. APPA/TAPS support a reporting obligation for all of the types of contractual 

arrangements that could confer control, as consistent with the discussion in the 

horizontal market power section of the NOPR. They argue that these arrangements 

could provide a market-based seller with the means to determine whether capacity is 

offered into a market and whether a competitor can or will enter a market. They state 

that these arrangements also create opportunities for sellers to coordinate their 

behavior with other competitors. If the contracts do not raise competitive concerns, 

the seller could explain the factors supporting that conclusion in its report.1172 

 

facilities or buying energy from the competitive market, with the obligation to pay 

liquidated damages equal to the difference in price between the pre-agreed price and the 

cost to the buyer of buying replacement power from another source for failure to deliver. 

EEI argues such contract should not be deemed to transfer “control” and therefore should 

not be reportable. 

1172 APPA/TAPS at 89. 
Docket No. RM04-7-000 592 

1030. SoCal Edison urges the Commission to consider whether, and to clarify how, 

the emerging, non-traditional capacity and electrical energy products that are 

routinely transacted in hybrid electricity markets today would fit within its 

construction of its test for control (“...affecting ability of the capacity to reach the 

relevant market”). It warns that buyers may be hesitant to routinely purchase 

products that require continual change in status filings.1173 

Commission Determination

1031. Pursuant to the change in status reporting requirement, a market-based rate 

seller is required to report a change in control to the extent the seller acquires a net 

100 MW or more generation capacity through contract. Our determination of what 

constitutes control is discussed above in the horizontal market power analysis section 

and we adopt that discussion for purposes of the change in status requirement. That 

is, the Commission concludes 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. If a seller has control over certain capacity 

such that the seller can affect the ability of the capacity to reach the relevant market, 

then that capacity should be attributed to the seller for purposes of complying with 

the change in status requirement. 

 1173 SoCal Edison at 14-16. 
Docket No. RM04-7-000 593 

1032. Further, as the Commission has previously clarified, sellers making a change 

in status filing to report an energy management agreement are required to make an 

affirmative statement in their filing as to whether the agreement at issue transfers 

control of any assets and whether the agreement results in any material effect on the 

conditions that the Commission relied upon for the grant of market-based rate 

authority. On some occasions, and at the Commission’s discretion, the Commission 

may request the seller to submit a copy of the agreement and provide supporting 

documentation.1174 

1033. We reiterate here that a seller making a change in status filing is required to 

state whether it has made a filing pursuant to section 203 of the FPA.1175 To the 

extent the seller has made a section 203 filing that it submits is being made out of an 

abundance of caution without conceding that the Commission has section 203 

jurisdiction, the seller will be required to incorporate this same assumption in its 

market-based rate change in status filing (e.g., if the seller assumes that it will control 

a jurisdictional facility in a section 203 filing, it should make that same assumption in 

its market-based rate change in status filing and, on that basis, inform the 

 1174 Calpine Energy Services, L.P., 113 FERC ¶ 61,158 at P 13 (2005) (Calpine). 

1175 16 U.S.C. 824b. 
Docket No. RM04-7-000 594 

Commission as to whether there is any material effect on its market-based rate 

authority).1176

d. Triggering Events

Comments 

1034. In the NOPR, the Commission invited comments on whether it should expand 

the triggering events for a change in status filing beyond ownership or control of 

facilities or inputs and affiliation with entities that own or control facilities or inputs 

or that have a franchised service territory, as set forth in Order No. 652. No 

commenters suggest additional triggering events, and several commenters oppose any 

general expansion of categories.1177 Several commenters specifically oppose any 

requirement to report actions taken by competitors or natural events as a change in 

status. They argue that, in many cases, the seller may be unaware of actions taken by 

a competitor, making compliance virtually impossible.1178

Commission Determination

1035. We will not expand the events that trigger a change in status filing. Further, 

we will not expand triggering events to include actions taken by a competitor (such as 

a decision to retire a generation unit or take transmission capacity out of service) or 

 1176 Calpine, 113 FERC ¶ 61,158 at P 14. 

1177 MidAmerican at 36; Powerex at 34. 

1178 MidAmerican at 36-37; Powerex at 34. 
Docket No. RM04-7-000 595 

natural events (such as hydro-year level, higher wind generation, or load disruptions 

due to adverse weather conditions) beyond those adopted in Order No. 652. As we 

describe above in the vertical market power analysis discussion, with regard to 

barriers to entry erected or controlled by other than the seller, we find that it is not 

reasonable to routinely require sellers to make a showing regarding potential barriers 

to entry that others might erect and that are beyond the seller’s control. However, we 

will entertain on a case-by-case basis claims that the existence of barriers to entry 

beyond the seller’s control may affect the seller’s ability to exercise market power. 

For similar reasons we will not expand the events that trigger a change in status filing 

to include actions taken by a competitor or natural events. However, we will 

entertain on a case-by-case basis claims that such actions may affect the seller’s 

ability to exercise market power. 

e. Timing of Reporting

Comments

1036. At present, the Commission requires the reporting of changes in status to be 

“filed no later than 30 days after the legal or effective date of the change in status, 

including a change in ownership or control, whichever is earlier.”1179 The proposed 

regulatory text maintains this requirement. 

 

 (continued...) 

 

1179 Order No. 652 at P 106. The Commission clarified that for power sales 

contracts, “it is irrelevant for the purposes of compliance with the reporting obligation if 

the effective date on which control is transferred occurs prior to the date on which the 

purchaser is contractually bound to commence physical delivery.” Order No. 652-A at P 
Docket No. RM04-7-000 596 

1037. CAISO supports the current requirement that entities with market-based rate 

authority must report changes of status no later than 30 days after the change has 

occurred. CAISO proposes that any change in status be reported not only to the 

Commission but also to the relevant market monitor where the facilities are located. 

CAISO states that this minimal additional burden on the supplier will ensure that 

RTO and ISO staff are operating with the latest possible information.1180

1038. SoCal Edison recommends that the Commission revise the change in status 

reporting requirement to focus upon the actual acquisition of the resources in question 

– for power sales contracts, the date of physical power delivery. SoCal Edison states 

that the Commission’s current policies make it virtually impossible for a seller to 

provide a meaningful evaluation of whether or not a forward contract with delivery 

months or years in the future creates a departure from the characteristics the 

Commission relied upon in granting market-based rate authority as much as three 

years previously. SoCal Edison notes that, as currently written, the policy requires 

reporting of procurement activities potentially years in advance of any power delivery 

because the effective date of the contract – usually the execution date – may 

 

31. 

1180 CAISO at 15. 
Docket No. RM04-7-000 597 

significantly precede the date of physical delivery – that is, the actual transfer of 

control over generation resources.1181 

Commission Determination

1039. We provide clarification regarding when a change in status filing should be 

filed. In Order No. 652, we determined that reports of changes in status must be filed 

no later than 30 days after the legal or effective date of the change in status, including 

a change in ownership or control, whichever is earlier.1182 However, it was not the 

Commission’s intention, as SoCal Edison notes, to require reporting of procurement 

activities potentially years in advance of any power delivery. We agree with SoCal 

Edison that the current policy may be unclear and may cause an entity to file a notice 

of change in status years in advance of the actual transaction, i.e., change in 

ownership or transfer of control. The Commission requires a meaningful evaluation 

of whether a change creates a departure from the characteristics the Commission 

relied upon in granting market-based rate authority. It would be difficult for the 

Commission to accurately evaluate whether or not, for example, a forward contract 

with delivery months or years in the future will affect the conditions the Commission 

relied upon for the market-based rate authorization. Accordingly, we will modify § 

35.42(b) (formerly § 35.43(b)) to provide that, in the case of power sales contracts 

 1181 SoCal Edison at 17-19. 

1182 Order No. 652 at 106. 
Docket No. RM04-7-000 598 

with future delivery, such contracts are reportable 30 days after the physical delivery 

has begun. 

1040. We reject CAISO’s proposal that any change in status also be reported to the 

relevant market monitor where the facilities are located. We find that informing the 

Commission of changes in status is sufficient. Change in status filings are noticed 

and therefore interested entities will have notice of any such filing. 

f. Sellers Affiliated with a Foreign Utility

1041. The change in status requirement is applicable to all market-based rate sellers 

regardless whether they are domestic or affiliated with a foreign utility. 

Comments

1042. Powerex notes that the Commission stated in the NOPR that it “does not 

consider transmission and generation facilities that are located exclusively out of the 

United States and that are not directly interconnected to the United States [but] would 

consider transmission facilities that are exclusively outside the United States but 

nevertheless interconnected to an affiliate’s transmission system that is directly 

interconnected to the United States.”1183 Powerex submits that the NOPR fails to 

clarify the Commission's proposed treatment of foreign-sited generation facilities 

interconnected to an affiliated transmission system that, in turn, is directly 

interconnected to the United States transmission grid. Powerex argues that, based on 

 1183 NOPR at P 175. 
Docket No. RM04-7-000 599 

the nature of the Commission's concerns with respect to facilities outside the United 

States, the details concerning such generation capacity should not be relevant to the 

Commission's determination in circumstances where the affiliated uncommitted 

capacity exceeds the transmission limits of the intertie(s) directly interconnecting the 

affiliated foreign transmission system to the United States grid. Powerex states that 

foreign sellers with foreign generating facilities can make that generation available to 

United States markets only to the extent that transmission capacity is available on the 

interties crossing the international boundaries. In such instances, Powerex argues that 

the seller's participation in United States jurisdictional markets is constrained by the 

total transfer capability (TTC) of the transmission system of the intertie (a 

measurement of the level of imports that can access a market from a particular 

location). Powerex asserts that those intertie limits represent the foreign seller's 

maximum uncommitted foreign capacity available to United States markets.1184 

Thus, according to Powerex, only changes in the TTC of the intertie itself should be 

considered a change in the circumstances upon which the original market-based rate 

authorization was based, for purposes of Order No. 652 filings.1185 

1043. Powerex also argues that complying with the change in status requirements of 

Order No. 652 would require foreign sellers to demand routine updates of potentially 

 1184 Powerex at 29-30. 

1185 Id. at 30. 
Docket No. RM04-7-000 600 

non-public information from their foreign generation-owning affiliates; it contends 

that Order No. 652 imposes a continuous updating requirement any time an affiliate 

acquires additional generation assets, re-rates an existing facility, or enters into thirdparty contracts that confer some degree of control.1186 Powerex states that in certain 

circumstances, release of information could be inconsistent with the standards and 

policies of the foreign utility regulatory agency regulating the foreign generation 

owner.1187 Powerex argues that concerns related to these types of frequently nonpublic changes to an affiliate’s generation profile are appropriately limited to United 

States assets located in United States markets. 

Commission Determination

1044. The Commission treats foreign-sited generation facilities interconnected to an 

affiliated transmission system that, in turn, is directly interconnected to the United 

States transmission grid in the same way that it treats the first-tier generation facilities 

of non-foreign sellers. For the purpose of determining total uncommitted capacity, 

the affiliates’ capacity is combined. 

1045. In response to Powerex, we agree that if the Commission’s grant of marketbased rate authority was based on the seller’s, including its affiliate’s, uncommitted 

capacity exceeding the transmission limits of the intertie(s) directly interconnecting 

 1186 Id. at 31. 

1187 Powerex at 31. 
Docket No. RM04-7-000 601 

the seller to the United States grid, only changes in the TTC of the intertie would be 

considered a change in status subject to a reporting requirement. 

1046. Further, if a foreign utility believes that release of specific information is 

inconsistent with the policies of a foreign utility regulatory agency, the foreign utility 

should specifically inform the Commission of this, and the Commission will take the 

matter under advisement when considering whether to grant a request for special 

treatment. 

4. Third-Party Providers of Ancillary Services

Commission Proposal

1047. In Order No. 888, the Commission required transmission providers to offer 

certain ancillary services at cost-based rates as part of their open access commitment 

but also contemplated that third parties (parties other than the transmission provider 

in a particular transaction) could provide certain ancillary services.1188 The 

Commission also left open the door for ancillary services to be provided on other than 

a cost-of-service basis. In Order No. 888, the Commission stated that it would 

entertain requests for market-based pricing related to ancillary services on a case-bycase basis if supported by analyses that demonstrate that the seller lacks market 

power in these discrete services.1189 

 1188 See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,720-21. 

1189 Id.; Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,237-38. 
Docket No. RM04-7-000 602 

1048. In Ocean Vista Power Generation, L.L.C.,1190 the Commission explained that, 

as a general matter, a study of ancillary service markets should address the nature and 

characteristics of each ancillary service, as well as the nature and characteristics of 

generation capable of supplying each service, and that the study should develop 

market shares for each service. In particular, the Commission stated that an 

individual seller’s market power analysis for ancillary services markets should: (1) 

define the relevant product market for each ancillary service; (2) identify the relevant 

geographic market, which could include all potential sellers of the product from 

whom the buyer could obtain the service, taking into account relevant factors which 

may include the other sellers' locations, the physical capability of the delivery system 

and the cost of such delivery, and important technical characteristics of the sellers' 

facilities; (3) establish market shares for all suppliers of the ancillary services in the 

relevant geographic markets; and (4) examine other barriers to entry. The 

Commission also noted that it would entertain alternative explanations and 

approaches. 

1049. The Commission adopted in Avista Corporation1191 a general policy stating 

that third-party ancillary service providers that could not perform a market power 

study would be allowed to sell ancillary services at market-based rates, but only in 

 1190 82 FERC ¶ 61,114 at 61,406-07 (Ocean Vista). 

1191 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 (1999) (Avista). 
Docket No. RM04-7-000 603 

conjunction with a requirement that such third parties establish an Internet-based 

OASIS-like site for providing information about and transacting ancillary services. 

The authorization in Avista extended only to the following four ancillary services: 

Regulation Service, Energy Imbalance Service, Spinning Reserves, and Supplemental 

Reserves. The Commission based its Avista policy on the expectation that, as entry 

into ancillary service markets occurs, prices will decrease from the level established 

by the transmission provider’s cost-based rate. Under these circumstances, customers 

will pay prices for ancillary services that are no higher than and will very likely be 

lower than the transmission provider’s cost-based rate. The Commission explained 

that the ancillary services customer is protected in part by the availability of the same 

ancillary services at cost-based rates from the transmission provider. The backstop of 

cost-based ancillary services from the transmission provider provides, in effect, a 

limit on the price at which customers are willing to buy ancillary services.1192

1050. To further monitor market entry, the Commission required third-party 

suppliers to file with the Commission one year after their Internet-based site was 

 1192 We note that the Commission has authorized several utilities to use market 

index pricing for energy imbalance service. See, e.g., PacifiCorp, 95 FERC ¶ 61,145 

(2001), order on reh’g, 95 FERC ¶ 61,467 (2001). In such a case, customers are 

protected by the transmission provider’s obligation to offer the service at rates the 

Commission determines are just and reasonable and consistent with our Avista policy. 
Docket No. RM04-7-000 604 

operational (and at least every three years thereafter) a report detailing their activities 

in the ancillary services market.1193 

1051. The Commission stated that that it would apply this policy only to sellers that 

are authorized to sell power and energy at market-based rates. In addition, the 

Commission stated that it would not apply this approach to sales of ancillary services 

by a third-party supplier in the following situations: (1) sales to an RTO or an ISO, 

i.e., where that entity has no ability to self-supply ancillary services but instead 

depends on third parties;1194 (2) to address affiliate abuse concerns, sales to a 

traditional, franchised public utility affiliated with the third-party supplier, or sales 

where the underlying transmission service is on the system of the public utility 

affiliated with the third-party supplier; and (3) sales to a public utility that is 

 1193 The Commission subsequently established an EQR requirement for all marketbased rate sellers. 

1194 With the formation of RTOs and ISOs, several RTOs/ISOs performed market 

analyses to demonstrate whether various ancillary services are competitive. The result 

has been as follows: California Independent System Operator: Regulation, Spinning 

Reserve, and Non-Spinning Reserve. ISO New England: Regulation and Frequency 

(Automatic Generation Control), Operating Reserve – Ten-Minute Spinning, Operating 

Reserve – Ten-Minute Non-Spinning, and Operating Reserve – Thirty Minute. New 

York Independent System Operator: Regulation and Frequency Response Service, 

Operating Reserve Service (including Spinning Reserve, 10-Minute Non-Synchronized 

Reserves and 30-Minute Reserves). PJM Independent System Operator: Regulation and 

Frequency Response, Energy Imbalance, Operating Reserve – Spinning, and Operating 

Reserve – Supplemental. Thus, in markets where the demonstration has been made, 

sellers are afforded the opportunity to sell at market-based rates subject to any other 

conditions in those markets. 
Docket No. RM04-7-000 605 

purchasing ancillary services to satisfy its own open access transmission tariff 

requirements to offer ancillary services to its own customers.1195 

1052. In the NOPR, the Commission proposed to retain the Avista policy but sought 

comment on whether to modify or revise that current approach and, if so, how. The 

Commission also sought comment on whether its current conditions, such as the 

requirement to establish an Internet-based site, continue to be necessary. 

a. Internet Postings and Reporting Requirements

Comments

1053. A number of commenters support modifications to the Commission’s current 

approach to third-party sales of ancillary services on the basis that they believe the 

current policy has not succeeded in engendering robust markets for ancillary services. 

Avista, Puget, Cogentrix and Powerex state that the existing Internet posting and 

reporting policy is unnecessary.1196 Avista and Puget note that the current EQR 

requirement, which did not exist when the Commission first adopted the Internet 

posting requirement, provides sufficient information for the Commission to monitor 

ancillary services markets for market power. They argue that abandoning the Internet 

posting and reporting conditions would contribute to the development of more robust 

reserves markets. Similarly, Cogentrix and Powerex maintain that those requirements 

 1195 Avista, 87 FERC at 61,883, n.12. 

1196 Avista at 7-8; Puget at 1, 4-8; Cogentrix at 8-10; Powerex at 35-38; Morgan 

Stanley at 11-12.
Docket No. RM04-7-000 606 

are burdensome and hard to implement, especially for independent sellers that are not 

transmission owners and do not have the responsibility to maintain an OASIS. 

Instead of safeguarding against possible abuses of market power, these commenters 

state that the posting and reporting requirements have probably hindered the 

development of robust markets for ancillary services. 

1054. Puget states that virtually all ancillary services outside of RTO/ISO markets 

are provided at cost-based rates by the host transmission provider. Puget states that it 

conducted a review of the reports filed in dockets in which the Commission has 

granted market-based rate authority to sell ancillary services under the Avista 

provisions, which revealed that only a handful of ancillary services sales have been 

made. Based on the small number of market-based ancillary services sales that Puget 

found in its review of existing dockets, it concludes that companies have determined 

that the potential commercial gains from entering this market do not justify the cost 

and risks associated with the special posting and reporting requirements. 

1055. Avista and Powerex state that, to the extent that the Commission is concerned 

about market power, purchasers of ancillary services are protected from the exercise 

of market power because they may purchase these services from the transmission 

provider at cost pursuant to the OATT. Powerex maintains that the Commission can 

monitor these transactions via the EQRs and can encourage purchasers to file 

complaints under FPA section 206 should they believe a seller has exercised market 

power when making such sales. 
Docket No. RM04-7-000 607 

1056. In contrast, APPA/TAPS urge the Commission not to relax standards for 

market-based pricing of ancillary services. They support continuation of the 

Commission’s current approach for pricing ancillary services, including the 

requirement for a cost-based backstop for ancillary services provided by a 

transmission provider. They argue that ancillary services markets remain very much 

dependent upon control area operation and are closely connected to the operations of 

the transmission system. APPA/TAPS state that locational reserves requirements 

limit the geographic scope of potential ancillary service suppliers, and that capacity 

on automatic generation control cannot easily sell regulation service in its home 

market today and switch to sales in an adjoining market tomorrow. Further, they 

state that customers cannot shop for such services. According to APPA/TAPS, 

limitations of transmission and technology counsel against adopting short-cuts for 

assessing the appropriateness of market-based pricing of ancillary services.1197

1057. Morgan Stanley supports efforts to establish market-based ancillary service 

markets both inside and outside of ISOs and RTOs. Morgan Stanley recommends 

that the Commission investigate what is necessary to establish local ancillary services 

markets on a nationwide basis. Morgan Stanley supports eliminating barriers to entry 

in the ancillary services market and states that to further this goal, the Commission 

should allow market participants to negotiate over-the-counter (OTC) ancillary 

 1197 APPA/TAPS at 91. 
Docket No. RM04-7-000 608 

services contracts outside of established ISOs and RTOs. Morgan Stanley mentions 

that this option should be open to all sellers with market-based rates and that the 

posting requirement should remain mandatory for mitigated entities. 

Commission Determination

1058. We will modify our current approach for third-party sellers of ancillary 

services at market-based rates as announced in Avista. We appreciate the concerns 

raised by a number of commenters that the posting and reporting requirements 

imposed in Avista may be hindering the development of ancillary services markets 

particularly by third-party providers. As noted above, some commenters have 

indicated that the costs and responsibilities associated with establishing and 

maintaining an internet-based site may outweigh the benefits that third party sellers 

could derive from the sale of the additional products. We conclude that our EQR 

filing requirement provides an adequate means to monitor ancillary services sales by 

third parties such that the posting and reporting requirements established in Avista are 

no longer necessary. Through their EQR filings, third party providers of ancillary 

services provide information regarding their ancillary services transactions for the 

quarter, including the ancillary service provided, the price, and the purchaser. As a 

result, we will no longer require third-party providers of ancillary services to 

establish and maintain an internet-based OASIS-like site for providing information 

about their ancillary services transactions. 

1059. In addition, we will no longer require third-party suppliers to file with the 

Commission one year after their internet-based site is operational (and at least every 
Docket No. RM04-7-000 609 

three years thereafter) a report detailing their activities in the ancillary services 

market. We note that the Commission retains the ability to require such a report by a 

third-party supplier of ancillary services at any time. 

1060. All sellers that seek authority to sell ancillary services at market-based rates 

pursuant to Avista1198 must make a filing with the Commission to request that 

authority and must include language in their market-based rate tariffs identifying the 

ancillary services that they offer.1199 

1061. Moreover, we will retain our current policy of not allowing sales of ancillary 

services by a third-party supplier in the following situations: (1) sales to an RTO or 

an ISO, i.e., where that entity has no ability to self-supply ancillary services but 

instead depends on third parties; (2) sales to a traditional, franchised public utility 

affiliated with the third-party supplier, or sales where the underlying transmission 

service is on the system of the public utility affiliated with the third-party supplier; 

and (3) sales to a public utility that is purchasing ancillary services to satisfy its own 

open access transmission tariff requirements to offer ancillary services to its own 

customers.1200 These standard applicable tariff provisions appear in Appendix C to 

 1198 As noted above, the Avista policy applies to the following four ancillary 

services: Regulation Service, Energy Imbalance Service, Spinning Reserves, and 

Supplemental Reserves. 

1199 Sellers that have been granted authority to provide third-party ancillary 

services need not reapply because their authority continues. 

1200 Avista, 87 FERC at 61,883, n. 12. 
Docket No. RM04-7-000 610 

this Final Rule. As we stated in Avista, we are open to considering requests for 

market-based rate authorization to make such sales on a case-by-case basis. 

1062. At this time, the Commission will not adopt Morgan Stanley’s 

recommendation to investigate what is necessary to establish local ancillary services 

markets on a nationwide basis. We believe that the elimination of certain reporting 

requirements for third party providers of ancillary services adopted herein will 

adequately balance the need to encourage the development of ancillary services 

markets and the Commission’s responsibility to provide oversight and protection 

from market power. We find Morgan Stanley’s suggestion that the Commission 

allow market participants to negotiate OTC ancillary services contracts outside of 

established RTO/ISO markets unsupported and lacking in detail.1201

b. Pricing for Ancillary Services in RTOs/ISOs 

Comments

1063. As noted above, the Commission stated in Order No. 888 that it would 

entertain requests for market-based pricing related to ancillary services on a case-bycase basis if supported by analyses which demonstrate that the seller lacks market 

 1201 Morgan Stanley’s comments provide an insufficient basis for us to determine 

whether such OTC ancillary services contracts would be jurisdictional. The Commission 

has previously stated that it is not concerned with management transactions (such as 

swaps, options, and futures contracts) designed to assist buyers and sellers of electricity 

in hedging against adverse price changes which are settled in cash and where parties do 

not take actual delivery of the electricity. Morgan Stanley Capital Group, Inc., 69 FERC 

¶ 61,175 (1994). 
Docket No. RM04-7-000 611 

power in these discrete services.1202 To date, the Commission has permitted marketbased rate pricing for certain ancillary services in a number of RTOs and ISOs.1203 

Although Ameren supports retaining the Commission’s current approach, Ameren 

urges the Commission to address what it describes as a critical market design flaw 

regarding pricing for ancillary services in RTO/ISO markets with Day 2 energy 

markets but no market for ancillary services, such as the Midwest ISO. Ameren 

explains that providing regulation service and spinning reserves in the Midwest ISO 

market at traditional cost-based rates is uneconomic at present because owners of 

ancillary services capacity generally find it more profitable to sell energy from the 

capacity at market-based rates rather than to offer the capacity as reserves at costbased rates. Ameren recommends that the Commission ensure that its approach to 

sales of ancillary services provides flexibility by allowing sellers for cost-based rates 

for regulation service and spinning reserves in the Midwest ISO footprint to propose 

a component for recovery of lost opportunity costs where such costs are shown to be 

legitimate and verifiable. Ameren submits that the Commission has recognized the 

 1202 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,656-57; Order No. 888-A, 

FERC Stats. & Regs. ¶ 31,048 at 30,230. 

1203 AES Redondo Beach, L.L.C., et al., 85 FERC ¶ 61,123 (1998), order on reh'g, 

87 FERC ¶ 61,208 (1999), order on reh'g and clarification, 90 FERC ¶ 61,036 (2000); 

New England Power Pool, 85 FERC ¶ 61,379 (1998), reh'g denied, 95 FERC ¶ 61,074 

(2001); Central Hudson Gas & Electric Corporation, et al., 86 FERC ¶ 61,062, order on 

reh'g, 88 FERC ¶ 61,138 (1999). 
Docket No. RM04-7-000 612 

need for opportunity cost recovery in other circumstances, and should consider an 

opportunity cost component in the future.1204

1064. CAISO states that it agrees with the Commission’s decision to distinguish 

sales within an RTO or ISO from those not within an RTO or ISO. 1205 It agrees that 

the Commission can rely on the market monitoring unit of the RTO or ISO to assess 

competitiveness in the RTO or ISO’s ancillary service markets.1206

1065. However, CAISO also notes that the size of the ancillary service market is 

subject to change based on system conditions and the need to meet applicable 

reliability criteria. It says that at times the CAISO may be able to procure ancillary 

services on a system-wide basis, whereas at other times factors such as the 

proportionate mix of hydro and thermal resources, transmission path operating 

transfer capability limits or deratings, forecasted path flows, anticipated load and 

weather conditions, and generator outages may require the CAISO to procure 

ancillary services on a zonal or even more location-specific basis. CAISO also states 

that because not every facility has the capability to provide every ancillary service, 

the market power analysis for the energy market does not automatically ensure that 

 1204 Ameren at 24-25, citing San Diego Gas & Elec. Co., 95 FERC ¶ 61,115 at 

61,363-64 & n.47 (2001). 

1205 CAISO at 16-18. 

1206 CAISO recommends that the Final Rule emphasize the importance of 

appropriate RTO or ISO market power mitigation tariff provisions for sales involving 

ancillary services. 
Docket No. RM04-7-000 613 

market power cannot be exercised with respect to sales of ancillary services. 

Accordingly, CAISO states that there may be the need for more targeted market 

power mitigation procedures specifically applicable to sales of ancillary services. 

1066. NYISO supports the Commission’s proposed approach to the extent it is 

predicated on all eligible sellers being able to benefit from the Commission’s 

authorization of the NYISO to purchase ancillary services for loads at market-based 

rates.1207 It states that all eligible sellers should receive the market-clearing prices 

for ancillary services that are supplied on a market basis and that the final regulations 

should not impose burdensome and duplicative market data requirements on a 

potential seller of ancillary services, either directly or through data demands to an 

ISO if the ISO has already received Commission authorization for market-based 

ancillary services. 

1067. APPA/TAPS urge caution for market-based pricing of ancillary services in 

RTO/ISO areas. Even if the Commission finds that conditions exist to permit marketbased pricing of some ancillary services in some RTO/ISO-administered markets, 

APPA/TAPS state that such pricing would not be appropriate where vertically 

integrated utilities are also control area operators, such as in Midwest ISO and SPP, 

 1207 NYISO at 10. 
Docket No. RM04-7-000 614 

because the locational, control-area dependent nature of ancillary services increases 

the risk that control area operators will have market power.1208

1068. Powerex recognizes that in some control areas, there are locational reserve 

requirements that can be met by a limited number of resources and therefore limit the 

geographic scope of potential suppliers.1209 Powerex believes, however, that this 

situation can be mitigated on a case-specific basis, and therefore that it should not be 

the basis for generally rejecting the benefits of competitive supply of ancillary 

services. Powerex believes that it is the combination of the Commission's existing 

regulatory framework and administrative barriers raised by transmission providers 

that has effectively stifled the incentives for third-party suppliers to participate in 

ancillary services markets.1210 In support, Powerex states that experience with the 

California organized markets demonstrates that a third-party provider can sell 

operating reserves and regulation service services to an adjoining market and that 

these services can be provided from resources located two markets and more than a 

thousand transmission miles away. 

 1208 APPA/TAPS at 92. 

1209 See, e.g., APPA/TAPS at 90-92.

1210 Powerex reply comments at 1-3. 
Docket No. RM04-7-000 615 

Commission Determination

1069. We will continue our current approach regarding market-based pricing for 

certain ancillary services in RTOs and ISOs. Where an RTO or ISO performs a 

market analysis demonstrating a lack of market power for certain ancillary services, 

the Commission has approved the sale of those ancillary services at market-based 

rates. As reflected in the NOPR, the Commission has approved the sale of certain 

ancillary services at market-based rates in CAISO, ISO New England, NYISO, and 

PJM. Moreover, the Commission considers on a case-by-case basis market power 

mitigation measures for sales involving ancillary services in these markets. 

1070. Ameren’s request that the Commission address what Ameren considers to be a 

critical market design flaw regarding pricing for ancillary services in the Midwest 

ISO is beyond the scope of this rulemaking proceeding. Ameren’s concerns are more 

appropriately addressed upon an appropriate record in the context of proceedings 

involving the Midwest ISO market. 

1071. With regard to APPA/TAPS’ concern that market-based pricing of ancillary 

services would not be appropriate where vertically integrated utilities are also 

balancing authority area operators, such as in Midwest ISO and SPP, we note that the 

Commission carefully analyzes ancillary service markets in ISOs and RTOs before 

authorizing market-based rate pricing, ensuring that protections, such as market 

monitors, are established to reduce the risk that market power can be exercised. 

APPA/TAPS has had the opportunity to intervene and participate in such 

proceedings, including in proceedings involving Midwest ISO and SPP. 
Docket No. RM04-7-000 616 

1072. The Commission also imposes mitigation where necessary. For example, the 

Commission in its PJM West/South Regulation Zone order permitted sellers that lack 

market power in PJM to submit market-based rate bids in the market for regulation 

service, while mitigating bids submitted by American Electric Power Company and 

Virginia Electric and Power Company, because PJM has not sufficiently 

demonstrated that they lack the potential to exercise market power in this market.1211 

5. Reactive Power and Real Power Losses

Commission Proposal

1073. In the NOPR, the Commission did not provide a proposal with regard to the 

treatment of reactive power and real power losses. However, several commenters 

submitted comments about these services. 

a. Reactive Power

Comments

1074. Cogentrix asks the Commission to reconsider the existing requirements for the 

sale of reactive power by independent generators. It notes that currently generators 

 1211 PJM Interconnection, L.L.C., 111 FERC ¶ 61,134 (2005) (PJM West/South 

Regulation Zone). Similarly, the Commission in New York Independent System 

Operator, Inc., 91 FERC ¶ 61,218 at 61,798-802(2000), suspended market-based pricing 

in the non-spinning reserve market for a temporary period. The Commission imposed 

bidding restrictions on 10 minute non-spinning operating reserves suppliers and a 

mandatory bid requirement which required that all available capacity held by eastern 

suppliers of 10 minute non-spinning reserves, and that is not subject to a bona fide outage 

or conflicting contractual obligation, be bid into the market. The Commission indicated 

that the mandatory bid requirement was necessary to protect against the physical 

withholding of capacity for the 10 minute non-spinning reserve market. 
Docket No. RM04-7-000 617 

can sell reactive power only upon the submission to the Commission of separate cost 

filings. Cogentrix submits that the requirement of cost justification of reactive power 

rates should be eliminated. Cogentrix states that this requirement is unnecessary 

because generators with market-based rate authority are found to lack market power 

and are subject to the EQR and change in status reporting requirements, which ensure 

that they continue to lack market power and, therefore, that they cannot dictate the 

pricing of reactive power services. Cogentrix submits that because reactive power is 

a service that purchasers require generators to provide, it should be left to the parties 

to negotiate the proper rate under the interconnection agreement or the power 

purchase agreement, without requiring the generator to submit additional cost 

filings.1212

Commission Determination

1075. We reject Cogentrix’s proposal that the Commission reconsider in this 

proceeding existing requirements for the sale of reactive power by independent 

generators and eliminate the requirement that generators submit separate cost filings 

supporting reactive power sales. Consistent with our precedent,1213 we will continue 

to analyze reactive power sales on a case-by-case basis. 

 1212 Cogentrix at 10. 

1213 See, e.g., Calpine Oneta Power,L.P, 119 FERC ¶ 61,177 (2007), and cases 

cited therein. 
Docket No. RM04-7-000 618 

b. Real Power Losses

Comments

1076. Powerex requests that the Commission explicitly permit sellers to offer thirdparty loss compensation services1214 on non-affiliated transmission systems under 

their general market-based rate authority.1215 Powerex states that it believes that third 

parties currently are making real power losses sales pursuant to their market-based 

rate authority.1216 Powerex believes that the provision of real power losses is no 

different than the provision of other energy. It notes that in some control areas, the 

provision of such services comes with other attendant duties such as acting as the 

scheduling party for the losses. 

 1214 Although Powerex does not directly define loss compensation energy, we 

interpret it to be equivalent to real power losses associated with all transmission service. 

The Commission’s pro forma OATT in Order No. 890, sections 15.7 and 28.5, refer to 

real power losses. For purposes of this Final Rule, we will refer to loss compensation 

service or energy as real power losses. 

1215 Powerex initial comments at 38-40. 

1216 Powerex cites to a filing in which Ameren stated its understanding that it “may 

sell the energy that will be used by customers that choose to self-supply energy to meet 

their transmission losses to such customers under its general market-based power sales 

authority. [Ameren] will merely be selling the power the customer will use to meet its 

losses and obligations and, from [Ameren’s] standpoint, this will be no different than any 

other power sale. Such sales are also consistent with the Commission’s decision to treat 

the provision of losses as a service that can be provided by multiple entities, rather than 

one that the transmission provider is uniquely situated to provide.” Powerex at 39, citing 

Letter Transmitting Compliance Filing, Ameren Energy Marketing Co., Docket No. 

ER01-1945, at n.3 (July 27, 2001). 
Docket No. RM04-7-000 619 

Commission Determination

1077. We agree with Powerex that the provision of real power losses is no different 

than the provision of other energy. We clarify that we permit sellers to offer thirdparty real power losses on non-affiliated transmission systems under their marketbased rate authority. 

V. Section-by-Section Analysis of Regulations 

1. Section 35.27 Authority of State Commissions

1078. In the NOPR, we explained that the first two paragraphs of this section were 

added by Order No. 888, while Order No. 652 later added subsection (c) to 

implement the change in status reporting requirement. The Commission proposed to 

move or delete subsections (a) and (c), leaving only (b), which clarifies that nothing 

in this part should be construed as preempting or affecting the authority of state 

commissions. The NOPR did not propose to revise the language of subsection (b) in 

any way, and proposed only to amend the heading from “Power Sales at MarketBased Rates” to “Authority of State Commissions.” NASUCA filed comments in 

support of “assuring that there will be no preemption of state prerogatives under the 

proposed new regulations . . ..”1217 

1079. We reiterate that the Commission is not proposing to add or revise this 

provision at this time. It remains unchanged from when the Commission adopted it 

 1217 NASUCA at 3-4. 
Docket No. RM04-7-000 620 

in Order No. 888. The fact that it is renumbered in this proceeding will not have any 

impact, positive or negative, on the prerogatives of state commissions. 

2. Section 35.36 Generally

1080. This section defines certain terms specific to Subpart H and explains the 

applicability of Subpart H. Some of these terms were put in place when the 

Commission codified certain market behavior rules in Order No. 674.1218 

1081. The NOPR proposed to define “Seller” in paragraph (a)(1) as a public utility 

with authority to, or seeking authority to, engage in sales for resale of electric energy 

at market-based rates in order to make clear that Subpart H deals exclusively with 

market-based rate power sales. NASUCA comments that the explanation for the 

definition of “Seller” does not mention any language in FPA section 205 regarding 

“market-based rates,” and further, that there is no reference to market-based rates in 

that section of the Act. Thus, NASUCA contends that “the reference in the definition 

of “seller” to “market-based rates under section 205 of the Federal Power Act” is a 

non sequitur, lacks support in the statutory language, and should be deleted.”1219 

1082. We do not agree that the limiting language should be deleted. We believe that 

it is essential that the regulations in subpart H apply only to the specific sales that we 

are regulating herein (i.e., market-based rates for wholesale sales of electric energy, 

 1218 Conditions for Public Utility Market-Based Rate Authorization Holders, Order 

No. 674, FERC Stats. & Regs. ¶ 31,208, 114 FERC ¶ 61,163 (2006). 

1219 NASUCA at 32. 
Docket No. RM04-7-000 621 

capacity and ancillary services by public utilities) and not to any sales made at costbased rates or under any other authority; the definition should make this scope clear. 

To the extent that NASUCA is challenging the Commission’s ability to authorize 

market-based rates at all, the Commission addresses NASUCA’s arguments in that 

regard in the legal authority section of this Final Rule. 

1083. In the NOPR, the Commission proposed definitions for Category 1 Sellers and 

Category 2 Sellers to assist in understanding the parameters of the updated market 

power analysis filing requirement. The definition of Category 1 Sellers is being 

clarified, consistent with the discussion above in Implementation Process. 

1084. Paragraph (a)(4) defines inputs to electric power production in order to 

simplify § 35.37(e) regarding other barriers to entry. The Final Rule revises the 

definition consistent with the discussion in the vertical market power section. 

1085. Paragraph (a)(5) indicates that where the term franchised public utility is used, 

it is meant to include only those public utilities with a franchised service obligation 

under state law. The Commission modifies the definition as proposed in the NOPR 

so that the term “franchised public utility” does not include only utilities with captive 

customers. Instead, throughout the final regulations, references to franchised public 

utilities with captive customers are explicitly identified, where applicable. 

1086. New paragraph (a)(6) provides a definition of captive customers, the genesis 

of which is discussed above in the Affiliate Abuse section. 

1087. Paragraph (a)(7) (which was proposed as § 35.36(a)(6) in the NOPR) provides 

a definition for market-regulated affiliated entities. 
Docket No. RM04-7-000 622 

1088. New paragraph (a)(8) provides a definition of market information. 

1089. Paragraph (b) is a basic description of the applicability of Subpart H. 

3. Section 35.37 Market power analysis required

1090. This section describes the market power analysis the Commission employs, as 

discussed in the preamble, and when sellers must file one. It is intended to identify 

the key aspects of the analysis. 

1091. The Final Rule adds paragraph (a)(2), which codifies the requirement 

mentioned in the NOPR for each seller to include an appendix identifying specified 

assets with each market power analysis filed. The paragraph also directs readers to 

Appendix B for a sample asset appendix. 

1092. New language in paragaphs (c)(2) and (c)(3) clarifies that both sellers and 

intervenors may file alternative evidence to support or rebut the indicative screens, 

and addresses the use of the Delivered Price Test and its role in the analysis of market 

power, respectively. Further, at paragraph (c)(4), the regulations codify the 

requirement that each seller use a standard format for the indicative screens, the use 

of which was proposed in the NOPR. 

1093. Paragraph (d) specifies the requirement that a seller with transmission facilities 

must have on file an Open Access Transmission Tariff. The Final Rule adds a 

description of how this requirement applies to sellers affiliated with foreign utilities. 

1094. Paragraph (e) describes the information that must be provided to demonstrate a 

lack of vertical market power. The text is revised in several respects reflecting the 

discussion in the section of the Final Rule on vertical market power. 
Docket No. RM04-7-000 623 

1095. The Final Rule adds a new paragraph (f) to address concerns that CEII claims 

in market-based rate filings have been overbroad. The subsection provides a process 

for intervenors to gain access to data for which the filer has claimed privileged 

treatment under 18 CFR 388.112. 

4. Section 35.38 Mitigation

1096. The regulatory text proposed in the NOPR did not propose specific changes to 

the current approach to mitigation, and intended to capture the Commission’s existing 

requirements. The Final Rule does not depart from this approach, and adopts the 

same regulatory text regarding mitigation as proposed in the NOPR, with the addition 

of a clarification that mitigation will apply only to the market or markets in which a 

seller is found, or presumed, to have market power.

5. Section 35.39 Affiliate restrictions

1097. This section governs affiliate transactions and affiliate relationships and 

establishes certain conditions that a seller must satisfy as a condition of its marketbased rate authority. New paragraph (a) explains that, as a condition of obtaining and 

retaining market-based rate authority, the provisions set forth in the entire section, 

including the restriction on affiliate sales of electric energy and the affiliate 

restrictions, must be satisfied on an ongoing basis. Paragraph (b) expressly prohibits 

sales between a franchised public utility with captive customers and any of its 

market-regulated power sales affiliates without first receiving authorization for the 

transaction under section 205 of the FPA. This paragraph requires that, where the 

Commission grants a seller authority to engage in affiliate sales under its MBR tariff, 
Docket No. RM04-7-000 624 

any and all such authorizations must be listed in the seller’s tariff. The language 

varies from that proposed in the NOPR to reflect changes to the definition of 

“franchised public utility.” 

1098. Paragraphs (c)-(f) contain provisions governing the relationship between a 

franchised public utility with captive customers and its market-regulated power sales 

affiliates (formerly, code of conduct). The provisions of these paragraphs apply to all 

franchised public utilities with captive customers. These paragraphs include 

provisions governing the separation of employees, the sharing of market information, 

sales of non-power goods or services, and power brokering. The language varies 

from that proposed in the NOPR to reflect changes to the definition of “franchised 

public utility” and a number of other changes discussed in greater detail in the 

affiliate abuse section of this Final Rule.

1099. As discussed above in Affiliate Abuse, the Commission is adding several 

provisions concerning separation of functions and information sharing to more 

closely model the Commission’s standards of conduct, as appropriate. In addition, 

the final regulations include a new paragraph (g) with a general prohibition on using 

anyone as a conduit to circumvent any of the affiliate restrictions, and a new 

paragraph (h) explaining that, if necessary, affiliate restrictions involving two or more 

franchised public utilities, one or more of whom has captive customers and one or 

more of whom does not, will be imposed on a case-by-case basis.

6. Section 35.40 Ancillary services

1100. This provision restricts sales of ancillary services to those specific geographic 
Docket No. RM04-7-000 625 

markets for which the Commission has authorized market-based rate sales of such 

services. In the Final Rule, we delete proposed paragraph (b), which reflected the 

Internet posting and reporting requirements found in Avista Corporation,

1220 and 

which we find are no longer necessary, as discussed above in the section on Ancillary 

Services. We also delete proposed subsection (c), which described limitations on 

sales of ancillary services by third-party providers; we believe that the standard 

applicable tariff provision, which will be available on the Commission’s website as it 

may be revised from time to time, will adequately apprise sellers of the current policy 

concerning third-party providers. 

7. Section 35.41 Market behavior rules

1101. In Order No. 674, the Commission rescinded two of its market behavior rules 

and codified the remainder in § 35.37 of new Subpart H. The NOPR proposed to 

move these market behavior rules, unchanged, from § 35.37 to § 35.41. NASUCA 

submitted a number of substantive comments on these provisions. Because we did 

not propose any revisions to these rules, and we are not revising them substantively in 

this Final Rule, NASUCA’s comments are beyond the scope of this proceeding. We 

are, however, taking this opportunity to make several minor corrections and stylistic 

edits to the market behavior rules. 

8. Section 35.42 Change in status reporting requirement

 1220 Avista Corporation, 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 

(1999). 
Docket No. RM04-7-000 626 

1102. This section incorporates the provision previously found at paragraph 

35.27(c), which was codified by Order No. 652. The final regulatory text clarifies 

distinctions between generation facilities and transmission facilities, and incorporates 

minor revisions as discussed above in the section on Changes in Status.

1103. The Final Rule adds paragraph (c), which codifies the requirement that each 

seller include an appendix identifying specified assets with each pertinent change in 

status notification filed. The paragraph also directs readers to Appendix B for a 

sample asset appendix.

9. Miscellaneous 

1104. The final regulations add the phrase “unless otherwise permitted by 

Commission rule or order” in several places throughout the regulations to make clear 

that these general provisions are not meant to override approvals granted in particular 

circumstances in other orders or rules. 

1105. In this Final Rule, the Commission has deleted proposed § 35.42, MBR Tariff, 

which required sellers to have on file the MBR tariff of general applicability. That 

requirement has been modified, as explained above in the section on the MBR tariff; 

accordingly the regulation will not be adopted. 

VI. Information Collection Statement

1106. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection and data retention requirements imposed by agency 
Docket No. RM04-7-000 627 

rules.1221 Upon approval of a collection of information and data retention, 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. As discussed herein, the Commission is amending its regulations to 

codify its requirements for obtaining and retaining market-based rate authorization, 

implementing a market-based rate tariff, and incorporating the change in status 

reporting requirement for sellers seeking market-based rate authority. 

Initial Market Power Analysis

1107. The Commission has previously required utilities seeking market-based rate 

authority to file a market power analysis with the Commission; the Commission now 

codifies that requirement in the Commission’s regulations. This Final Rule reflects 

the Commission’s existing practice developed over the years through individual cases 

and will not impose any additional burden, with the following exception. 

1108. Section 35.27(a) of the Commission’s regulations1222 currently provides that 

any public utility seeking market-based rate authority shall not be required to submit 

a generation market power analysis with respect to sales from capacity for which 

construction commenced on or after July 9, 1996. Under current procedures, if all the 

 1221 5 CFR 1320.11. 

1222 18 CFR 35.27(a). 
Docket No. RM04-7-000 628 

generation owned or controlled by an applicant for market-based rate authority and its 

affiliates in the relevant balancing authority area is post-July 9, 1996 generation, such 

seller is not required to submit a generation market power analysis. In this Final 

Rule, the Commission eliminates the express exemption provided in § 35.27(a). This 

change means that all new sellers seeking market-based rate authority on or after the 

effective date of the Final Rule issued in this proceeding, whether or not all of their 

and their affiliates’ generation was built or acquired after July 9, 1996, must provide a 

market power analysis of their generation to support their application for marketbased rate authority. 

1109. Because the Commission allows a seller to make simplifying assumptions, 

where appropriate, and therefore to submit a streamlined analysis, the Commission 

believes that any burden of document preparation occasioned by the elimination of § 

35.27(a) should be minimal. To the extent that there are greater costs for some 

sellers, the benefit of ensuring that markets do not become less competitive over time 

outweighs any additional costs. 

Updated Market Power Analyses

1110. To retain market-based rate authority, the Commission currently requires that 

sellers file an updated market power analysis every three years. In this Final Rule, 

the Commission codifies the requirement that certain sellers with market-based rate 

authority file an updated analysis with the Commission to retain that authority. 

However, Category 1 sellers will be relieved of their existing obligation to file 

regularly scheduled updated market power analyses, as explained in the 
Docket No. RM04-7-000 629 

Implementation Process section of this Final Rule. Instead, sellers that believe they 

fall into Category 1 will be required to submit a filing with the Commission at the 

time that updated market power analyses for the seller’s relevant market would 

otherwise be due (based on the regional schedule for updated market power analyses 

adopted in this Final Rule) explaining why the seller meets the Category 1 criteria, 

including a list of all generation assets (including nameplate or seasonal capacity 

amounts) owned or controlled by the seller and its affiliates grouped by balancing 

authority area. Once the Commission agrees that a seller meets the Category 1 

criteria, that seller will not have to file regularly scheduled updated market power 

analyses. Category 2 sellers will retain their existing obligation to file a regularly 

scheduled updated market power analysis. Thus, Category 2 sellers will not face a 

greater burden to provide the Commission with the information required for an 

updated market power analysis. 

1111. In addition, the elimination of § 35.27(a) also means that existing Category 2 

sellers filing updated market power analyses on or after the effective date of the Final 

Rule issued in this proceeding, whether or not all of their and their affiliates’ 

generation was built or acquired after July 9, 1996, must provide a market power 

analysis of their generation to support their continued market-based rate authority. 

1112. Mirant argues that, with the elimination of the § 35.27(a) exemption, its cost of 

compliance will increase because it will have to prepare four updated market power 

analyses, each costing $20,000 to prepare and file, for companies that would have 

qualified for the § 35.27(a) exemption. Mirant states that only one of its subsidiaries 
Docket No. RM04-7-000 630 

would qualify as a Category 1 seller and Mirant still would have to make four 

updated market power analysis filings. On the other hand, other commenters state 

that the benefits of eliminating the § 35.27(a) exemption outweigh any added 

burdens. 

1113. Because the Commission allows a seller to make simplifying assumptions and 

rely on previously filed analyses by other market participants, where appropriate, and 

therefore to submit a streamlined analysis, the Commission believes that any burden 

of document preparation occasioned by the elimination of § 35.27(a) should be 

minimal. To the extent that there are greater costs for some sellers, the benefit of 

ensuring that markets do not become less competitive over time outweighs any 

additional costs. 

Regional Review and Schedule

1114. In the NOPR, the Commission proposed to require each seller to file an 

updated market power analysis for its relevant geographic market(s) on a schedule 

that will allow examination of the individual seller at the same time the Commission 

examines other sellers in these relevant markets and contiguous markets within a 

region from which power could be imported. The regional reviews would rotate by 

geographic region. 

1115. Some commenters expressed concern that regional review would increase the 

burden associated with filing updated market power analyses. Reliant, for example, 

states that companies which engage in business in multiple regions of the United 

States would have to file several times over the three year schedule instead of once as 
Docket No. RM04-7-000 631 

is required currently.1223 Other commenters support the regional review proposal. 

For example, NRECA maintains that the proposed regional approach will not impose 

an undue compliance burden on sellers. It notes that the regional review approach 

will ensure greater consistency in the data used to evaluate Category 2 sellers, citing 

the Commission’s statement in the NOPR that the Commission “will have before it a 

complete picture of the uncommitted capacity and simultaneous import capability 

into the relevant geographic markets under review.”1224 NRECA states that any 

increase in the burden on sellers hardly outweighs these substantial benefits. NRECA 

submits that the Commission has proposed a reasonable procedure to better ensure 

that market-based rate authority is granted only in appropriate circumstances. When 

compared with the burden, cost and time required by a cost-of-service rate regime, 

NRECA asserts that the burden of complying with the regional review approach will 

be minimal. APPA/TAPS describe the regional review proposed in the NOPR as a 

sensible proposal to conduct updated market power analyses on a rotating, regional 

basis to improve the quality and quantity of the data relied upon for market-based rate 

determinations and to provide the Commission with a more comprehensive picture of 

competitive conditions in regional markets. They assert that the Commission should 

 1223 Similarly, Allegheny, Mirant, FP&L, EEI, FirstEnergy, MidAmerican, TXU, 

Morgan Stanley, Financial Companies, and EPSA argue that large corporate families 

could find themselves in a perpetual triennial review that would place a substantial 

regulatory burden and expense on them. 

1224 NRECA reply comments at 28, citing NOPR at P 154. 
Docket No. RM04-7-000 632 

not sacrifice improvements to its market-based rate program to the interests of a few 

companies and that any increased financial cost to companies associated with 

regional reviews is outweighed by the companies’ profits from market-based rate 

sales. 

1116. We believe that the Commission’s proposal properly and fairly balances the 

need to effectively, comprehensively, and accurately assess market power in 

wholesale markets with the desire to minimize any administrative burden associated 

with the filing and review of updated market power analyses. While we recognize 

that some sellers may file updates more frequently than currently, we have carefully 

balanced the interests of all involved, and we believe that regional reviews of updated 

market analyses will result in more accurate and complete data. This in turn will 

enhance the Commission's ability to continue to ensure that sellers either lack market 

power or have adequately mitigated such market power. 

1117. Further, in light of commenters’ concern with the regional review schedule, 

the Commission has modified the schedule as proposed in the NOPR. The NOPR 

proposed that regional reviews would rotate by geographic region with three regions 

reviewed per year. Some commenters expressed concerned that, because they 

operate in multiple regions, they would be required to file updated market power 

analyses every year rather than every three years. To address this concern, we are 

reducing the number of filings that sellers with generation in multiple regions will 

have to make by consolidating the regions and reducing the total number from nine to 

six. With fewer and larger regions, sellers will likely occupy fewer regions, 
Docket No. RM04-7-000 633 

necessitating fewer filings. 

Market-Based Rate Tariff

1118. The NOPR proposed a tariff of general applicability (MBR tariff), which 

would provide greater consistency and reduce confusion regarding tariffs. The 

Commission recognized that the requirement to file the specified MBR tariff might 

cause a minimal burden of document preparation and organization for existing 

market-based rate sellers, but stated that long-term benefits would be realized for 

market participants as well as the Commission. 

1119. In this Final Rule, we do not adopt the NOPR proposal to require all sellers to 

adopt a tariff of general applicability. Instead, we adopt a set of standard tariff 

provisions that we will require each seller to include in its market-based rate tariff. 

While we will require all market-based rate sellers to make compliance filings to 

modify their existing tariffs to reflect these standard provisions, these compliance 

filings are to be made by each seller the next time the seller proposes a tariff change, 

makes a change in status filing, or submits an updated market power analysis in 

accordance with the schedule in Appendix D, whichever occurs first. 

1120. In the NOPR, the Commission also proposed that all market-based rate sellers 

file one market-based rate tariff per corporate family. Many commenters expressed 

concern with this proposal. In light of these concerns, we are not requiring sellers to 

file one market-based rate tariff per corporate family. Instead, we will allow sellers 

to elect whether to transact under a single market-based rate tariff for an entire 

corporate family or under separate tariffs. 
Docket No. RM04-7-000 634 

General

1121. The Commission’s regulations in 18 CFR Part 35 specify those reporting 

requirements that must be followed in conjunction with the filing of rate schedules 

under the FPA. The information provided to the Commission under 18 CFR Part 35 

is identified for information collection and records retention purposes as FERC-516. 

Data collection FERC-516 applies to all reporting requirements covered in 18 CFR 

Part 35 including: electric rate schedule filings, market power analyses, tariff 

submissions, market-based rate analyses, and reporting requirements for changes in 

status for public utilities with market-based rate authority. 

1122. The Commission is submitting these reporting and records retention 

requirements to OMB for its review and approval under § 3507(d) of the Paperwork 

Reduction Act.1225 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. With the exceptions of estimates regarding sellers’ market-based rate 

tariffs, the number of market-based rate sellers, and the burden estimates for Category 

 1225 44 U.S.C. 3507(d). 
Docket No. RM04-7-000 635 

1 sellers, we will use the same estimates here as in the NOPR.1226 

1123. The number of respondents expected to file to revise market-based rate tariffs 

has increased from the estimate set forth in the NOPR, given our decision not to 

require one MBR tariff per corporate family. We expect some sellers will opt to 

submit a single corporate tariff, but we will estimate the total number to be filed to be 

approximately 1230, rather than 650 as reported in the NOPR. We will conform the 

number of responses to reflect this new estimate as well. However, we note that this 

number may be significantly less if sellers choose the option to file one market-based 

rate tariff per corporate family. Additionally, the Commission proposed in the NOPR 

that sellers file their MBR tariffs as directed in the rulemaking proceeding requiring 

the submission of electronic tariffs. However, in this Final Rule, we are requiring 

that sellers file their modified tariffs the next time sellers propose a tariff change, 

make a change in status filing, or submit an updated market power analysis. We have 

adjusted the number of responses to reflect this requirement. 

Burden Estimate: The Public Reporting and records retention burden for all four 

reporting requirements and the records retention requirement is as follows.1227

Title: Electric Rate Schedule Filings (FERC-516). 

Action: Revised Collection. 

 1226 We note that the number of market-based rate sellers has increased since 

issuance of the NOPR in May 2006. 

1227 These burden estimates apply only to this Final Rule and do not reflect upon 

all of FERC-516. 
Docket No. RM04-7-000 636 

OMB Control No: 1902-0096 

Data Collection No. of 

Respondents 

No. of 

Responses 

Hours Per 

Response 

Total Annual 

Hours 

Initial Market 

Power Analysis 

120 120 130 15,600 

Market-Based 

Rate Tariff 

1230 4101228 6 2460 

 Category 1 

Qualification 

Filings1229

630 2101230 151231 3150 

Updated 

Analyses 

Category 21232

600 2001233 250 50,000 

Totals 71,210 

 1228 We expect responses to be staggered over the course of three years. 

Accordingly, the number of respondents (1230) has been divided by three. 

1229 Category 1 sellers are power marketers and power producers that own or 

control 500 MW or less of generating capacity in aggregate and that are not affiliated 

with a public utility with a franchised service territory. In addition, Category 1 sellers 

must not own, operate or control transmission facilities, and must present no other 

vertical market power issues. There are approximately 630 Category 1 sellers. 

1230 To determine the number of responses, the number of respondents (630) has 

been divided by 3 because the Category 1 filings will be submitted to the Commission on 

a staggered basis over the course of a three-year period. After the first three years, the 

number of responses will be zero. 

1231 This estimate reflects the limited scope of the filing required by Category 1 

sellers, i.e., a filing explaining why the seller meets the Category 1 criteria and including 

a list of all generation assets owned or controlled by the seller and its affiliates grouped 

by balancing authority area. 

1232 Category 2 sellers are any sellers not in Category 1. 

1233 To determine the number of responses, the number of respondents (600) has 

been divided by 3 because the responses will be submitted to the Commission on a 

staggered basis over the course of a three year period. 
Docket No. RM04-7-000 637 

Total Annual hours for Collection: (Reporting + record retention, (if appropriate)=

71,210 hours. 

Information Collection Costs: The total annual cost for Initial Market Power Analyses is 

estimated to be $2,340,000. Total annual cost for market-based rate tariffs is projected to 

be $369,000 for the first year. Total annual cost for Category 1 Qualification Filings is 

projected to be $472,500.1234 Total annual cost for Updated Market Power Analyses 

Category 2 is projected to be $7,500,000. The hourly rate of $150 includes attorney fees, 

engineering consultation fees and administrative support. There are 2080 total work 

hours in a year. There are no filing fees associated with applications for market-based 

rate authority. 

Respondents (Market Power Analysis; MBR Tariff; Triennial Review): Businesses or 

other for profit.

Frequency of Responses

Market Power Analyses: Occasionally; consistent with current practice, a market power 

analysis must be filed for each utility seeking market-based rate authority. 

Market-Based Rate Tariffs: once, consistent with the requirement that all sellers file 

modifications to their existing tariffs in accordance with the provisions in Appendix C. 

 1234 We note that Category 1 sellers will only be required to file on a single 

occasion Category 1 qualification filings whereas Category 2 sellers will file updated 

market power analyses every three years. 
Docket No. RM04-7-000 638 

Updated market power analyses: Updated market power analysis filed every three years 

for Category 2 sellers seeking to retain market-based rate authority.

Necessity of the Information

Market Power Analyses: Consistent with current practice, the market power analysis 

helps inform the Commission as to whether an entity seeking market-based rate authority 

lacks market power, and whether sales by that entity will be just and reasonable. 

Market-Based Rate Tariff: Market-based rate tariffs with standard provisions will 

improve the efficiency of the Commission in its analysis and determination of marketbased rate authority. These will reduce document preparation time overall and provide 

utilities with the clearly defined expectations of the Commission. 

Updated Market Power Analyses: The updated market power analyses allow the 

Commission to monitor market-based rate authority to detect changes in market power or 

potential abuses of market power. The updated market power analysis permits the 

Commission to determine that continued market-based rate authority will still yield rates 

that are just and reasonable. 

Internal review: The Commission has conducted an internal review of the public 

reporting burden associated with the collection of information and assured itself, by 

means of internal review, that there is specific, objective support for this information 

burden estimate. Moreover, the Commission has reviewed the collections of information 

and has determined that these collections of information are necessary and conform to the 
Docket No. RM04-7-000 639 

Commission’s plans, as described in this order, for the collection, efficient management, 

and use of the required information.1235 

1124. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, N.E., 

Washington, D.C. 20426 [Attention: Michael Miller, Office of the Executive 

Director, Phone: (202) 502-8415, fax: (202) 273-0873, e-mail: 

michael.miller@ferc.gov or the Office of Information and Regulatory Affairs, Office 

of Management and Budget, Washington, D.C. 20503 [Attention: Desk Officer for 

the Federal Energy Regulatory Commission]. 

VII. Environmental Analysis

1125. 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.1236 The Commission concludes that neither an 

Environmental Assessment nor an Environmental Impact Statement is required for 

this Final Rule under § 380.4(a)(15) of the Commission’s regulations, which provides 

 1235 See 44 U.S.C. 3506(c). 

1236 Order No. 486, Regulations Implementing the National Environmental Policy 

Act, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986-1990 ¶ 30,783 

(1987). 
Docket No. RM04-7-000 640 

a categorical exemption for approval of actions under sections 205 and 206 of the 

FPA relating to electric rate filings.1237

VIII. Regulatory Flexibility Act

1126. The Regulatory Flexibility Act of 1980 (RFA)1238 generally requires a 

description and analysis of rules that will have significant economic impact on a 

substantial number of small entities.1239 The Final Rule will be applicable to all 

public utilities seeking and currently possessing market-based rate authority. The 

Commission finds that the regulations adopted here should not have a significant 

impact on small businesses. 

1127. The submission of a market power analysis is currently required of all entities 

seeking authority to sell at market-based rates, and the Final Rule does not expand 

which entities will be required to file these analyses. The Final Rule does not create a 

new reporting requirement. It does, however, expand the scope of the analysis that 

must be submitted for those entities that previously were exempted from preparing a 

 1237 18 CFR 380.4(a)(15). 

1238 5 U.S.C. 601-12. 

1239 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. 

15 U.S.C. 632. The Small Business Size Standards component of the North American 

Industry Classification System defines a small electric utility as one that, including its 

affiliates, is primarily engaged in the generation, transmission, and/or distribution of 

electric energy for sale and whose total electric output for the preceding fiscal year did 

not exceed 4 million MWh. 13 CFR 121.201 (section 22, Utilities, North American 

Industry Classification System, NAICS). 
Docket No. RM04-7-000 641 

generation market power analysis by virtue of 18 CFR 35.27(a). The Commission is 

concerned that the continued use of the § 35.27(a) exemption, in time, would 

encompass all market participants as all pre-July 9, 1996 generation is retired. 

Nevertheless, because the Commission allows a seller to make simplifying 

assumptions, where appropriate, and therefore to submit a streamlined analysis, the 

Commission believes that any additional burden imposed by the elimination of the § 

35.27(a) exemption will be minimal. 

1128. Standard tariff provisions will decrease document preparation by clearly 

defining the information sought by the Commission. 

1129. For certain sellers, the triennial review submissions that provide updated 

market power analyses are required for the retention of market-based rate authority. 

Category 2 utilities shall continue to submit this analysis, which poses no greater 

burden than that already in place. However, the regulations will result in fewer 

filings with the Commission after the next three years than currently required for 

qualified smaller (Category 1) utilities’ retention of market-based rate authority. 

Thus, the Final Rule will be less burdensome economically and reduce the frequency 

of document preparation for market-based rate authority retention for qualified 

smaller utilities. The Commission concludes that this Final Rule will not have a 

significant economic impact on a substantial number of small entities. 

IX. Document Availability

1130. 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 
Docket No. RM04-7-000 642 

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 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 20426. 

1131. 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. 

1132. User assistance is available for eLibrary and the Commission's website during 

normal business hours from FERC Online Support at (202) 502-6652 (toll-free at 1-

866-208-3676) or email at ferconlinesupport@ferc.gov, or the Public Reference 

Room at (202) 502-8371 Press 0, TTY (202) 502-8659. E-Mail the Public Reference 

Room at public.referenceroom@ferc.gov. 

X. Effective Date and Congressional Notification

1133. These regulations are effective [insert date 60 days from the date the rule is 

published in the FEDERAL REGISTER]. 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 to the General Accounting 

Office. 
Docket No. RM04-7-000 643 

List of subjects in 18 CFR Part 35 

Electric power rates, Electric utilities, Reporting and recordkeeping requirements. 

By the Commission. Commissioner Moeller dissenting in part with a 

 separate statement attached. 

( S E A L ) 

 

 Kimberly D. Bose, 

 Secretary. 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Market-based Rates for Wholesale Sales of 

Electric Energy, Capacity and Ancillary Services 

by Public Utilities Docket No. RM04-7-000 

 (Issued June 21, 2007) 

 

MOELLER, Commissioner, dissenting in part: 

I find persuasive the arguments raised by commenters1

 that a limited 

grandfathering provision for the “1996 exemption”2

 is warranted, to avoid modifying the 

understanding that certain generators relied upon to finance and construct new 

generation. It is my position that, with respect to sales from capacity for which 

construction commenced on or after July 9, 1996, but before the effective date of this 

Final Rule, any public utility that has authority to engage in market-based rate sales 

should not be required to demonstrate a lack of market power in generation consistent 

with the terms of the exemption. That is, any public utility that qualified and received a 

1996 exemption should retain its exemption from filing a generation market power 

analysis (now termed horizontal market power analysis). However, any increase in such 

capacity after the effective date of this Final Rule would terminate the exemption. 

As I have stated previously, I am interested in providing regulatory certainty, and 

promoting infrastructure investment and independent power production. A limited 

grandfathering of the 1996 exemption would, on one hand, allow entities to continue to 

preserve the bargain they received when they relied on the exemption and, on the other 

hand, support the majority’s reasons for revoking the exemption for all generators. 

 1

 Such commenters include EPSA, Mirant and Constellation. 

2

 18 C.F.R. 35.27(a) (2006), which states “Notwithstanding any other 

requirements, any public utility seeking authorization to engage in sales for resale of 

electric energy at market-based rates shall not be required to demonstrate any lack of 

market power in generation with respect to sales from capacity for which construction 

has commenced on or after July 9, 1996.” 
Docket No. RM04-7-000 2 

Also, my understanding is that very few entities would be eligible for this limited 

grandfathering; even without the grandfathering, they would probably be classified as 

“Category 1 sellers.”3

 Moreover, this exemption neither precludes any entity from 

presenting evidence to the Commission, nor disallows the Commission of its own accord, 

to investigate an allegation of market power abuse by an exempt generator. This should 

allay any fears that these smaller entities will be able to exercise generation market 

power.4

 _______________________ 

 Philip D. Moeller 

 Commissioner 

 3

 “The sellers that have taken advantage of the exemption will largely qualify as 

Category 1 sellers, and thus will be unaffected to the extent that they will not be required 

to file a regularly scheduled updated market power analysis.” Final Rule at P 321. 

4

 In defending our decision to create Category 1 sellers, the majority observes that 

no commenter has submitted compelling evidence that Category 1 sellers have 

unmitigated market power. Final Rule at P 334. 
 In consideration of the foregoing, the Commission amends part 35, Chapter I, Title 

18, Code of Federal Regulations, as follows: 

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

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

7352. 

2. In § 35.27, the title and the section are revised to read as follows: 

§ 35.27 Authority of State Commissions.

 Nothing in this part – 

 (a) Shall be construed as preempting or affecting any jurisdiction a state 

commission or other state authority may have under applicable state and federal law, or 

 (b) Limits the authority of a state commission in accordance with state and federal 

law to establish 

 (1) Competitive procedures for the acquisition of electric energy, including 

demand-side management, purchased at wholesale, or 

 (2) Non-discriminatory fees for the distribution of such electric energy to retail 

consumers for purposes established in accordance with state law. 

3. Subpart H is revised to read as follows: 

Subpart H – Wholesale Sales of Electric Energy, Capacity and Ancillary Services at 

Market-Based Rates 

Sec. 

35.36 Generally. 
Docket No. RM04-7-000 2 

35.37 Market power analysis required. 

35.38 Mitigation. 

35.39 Affiliate restrictions. 

35.40 Ancillary services. 

35.41 Market behavior rules. 

35.42 Change in status reporting requirement. 

Appendix A to Subpart H Standard Screen Format 

Appendix B to Subpart H Corporate Entities and Assets 

§ 35.36 Generally. 

(a) For purposes of this subpart: 

 (1) Seller means any person that has authorization to or seeks authorization to 

engage in sales for resale of electric energy, capacity or ancillary services at marketbased rates under section 205 of the Federal Power Act. 

 (2) Category 1 Sellers means wholesale power marketers and wholesale power 

producers that own or control 500 MW or less of generation in aggregate per region; that 

do not own, operate or control transmission facilities other than limited equipment 

necessary to connect individual generating facilities to the transmission grid (or have 

been granted waiver of the requirements of Order No. 888, FERC Stats. & Regs. ¶ 

31,036); that are not affiliated with anyone that owns, operates or controls transmission 

facilities in the same region as the seller’s generation assets; that are not affiliated with a 

franchised public utility in the same region as the seller’s generation assets; and that do 
Docket No. RM04-7-000 3 

not raise other vertical market power issues. 

 (3) Category 2 Sellers means any Sellers not in Category 1. 

 (4) Inputs to electric power production means intrastate natural gas transportation, 

intrastate natural gas storage or distribution facilities; sites for generation capacity 

development; sources of coal supplies and equipment for the transportation of coal 

supplies such as barges and rail cars. 

 (5) Franchised public utility means a public utility with a franchised service 

obligation under state law. 

 (6) Captive customers means any wholesale or retail electric energy customers 

served under cost-based regulation. 

(7) Market-regulated power sales affiliate means any power seller affiliate other 

than a franchised public utility, including a power marketer, exempt wholesale generator, 

qualifying facility or other power seller affiliate, whose power sales are regulated in 

whole or in part on a market-rate basis. 

(8) Market information means non-public information related to the electric 

energy and power business including, but not limited to, information regarding sales, cost 

of production, generator outages, generator heat rates, unconsummated transactions, or 

historical generator volumes. Market information includes information from either 

affiliates or non-affiliates.

 (b) The provisions of this subpart apply to all Sellers authorized, or seeking 

authorization, to make sales for resale of electric energy, capacity or ancillary services at 

market-based rates unless otherwise ordered by the Commission.
Docket No. RM04-7-000 4 

§ 35.37 Market power analysis required.

(a) (1) In addition to other requirements in subparts A and B, a Seller must submit 

a market power analysis in the following circumstances: when seeking market-based rate 

authority; for Category 2 Sellers, every three years, according to the schedule contained 

in Order No. ___, FERC Stats. & Regs. ¶ 31,___; or any other time the Commission 

directs a Seller to submit one. Failure to timely file an updated market power analysis 

will constitute a violation of Seller’s market-based rate tariff. 

 (2) When submitting a market power analysis, whether as part of an initial 

application or an update, a Seller must include an appendix of assets in the form provided 

in Appendix B of this subpart. 

 (b) A market power analysis must address whether a Seller has horizontal and 

vertical market power. 

 (c) (1) There will be a rebuttable presumption that a Seller lacks horizontal market 

power if it passes two indicative market power screens: a pivotal supplier analysis based 

on the annual peak demand of the relevant market, and a market share analysis applied on 

a seasonal basis. There will be a rebuttable presumption that a Seller possesses 

horizontal market power if it fails either screen. 

 (2) Sellers and intervenors may also file alternative evidence to support or rebut 

the results of the indicative screens. Sellers may file such evidence at the time they file 

their indicative screens. Intervenors may file such evidence in response to a Seller’s 

submissions. 

(3) If a Seller does not pass one or both screens, the Seller may rebut a 
Docket No. RM04-7-000 5 

presumption of horizontal market power by submitting a Delivered Price Test analysis. 

A Seller that does not rebut a presumption of horizontal market power or that concedes 

market power, is subject to mitigation, as described in § 35.38. 

 (4) When submitting a horizontal market power analysis, a Seller must use the 

form provided in Appendix A of this subpart and include all supporting materials 

referenced in the form. 

 (d) To demonstrate a lack of vertical market power, a Seller that owns, operates or 

controls transmission facilities, or whose affiliates own, operate or control transmission 

facilities, must have on file with the Commission an Open Access Transmission Tariff, as 

described in § 35.28; provided, however, that a Seller whose foreign affiliate(s) own, 

operate or control transmission facilities outside of the United States that can be used by 

competitors of the Seller to reach United States markets must demonstrate that such 

affiliate either has adopted and is implementing an Open Access Transmission Tariff as 

described in § 35.28, or otherwise offers comparable, non-discriminatory access to such 

transmission facilities. 

 (e) To demonstrate a lack of vertical market power in wholesale energy markets 

through the affiliation, ownership or control of inputs to electric power production, such 

as the transportation or distribution of the inputs to electric power production, a Seller 

must provide the following information: 

(1) 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; 
Docket No. RM04-7-000 6 

(2) Sites for generation capacity development; and 

(3) Sources of coal supplies and the transportation of coal supplies such as barges 

and rail cars. 

(4) A Seller must ensure that this information is included in the record of each 

new application for market-based rates and each updated market power analysis. In 

addition, a Seller is required to make an affirmative statement that it has not erected 

barriers to entry into the relevant market and will not erect barriers to entry into the 

relevant market. 

 (f) If the seller seeks to protect any portion of the application, or any attachment 

thereto, from public disclosure pursuant to § 388.112 of this chapter, the seller must 

include with its request for privileged treatment a proposed protective order under which 

the parties to the proceeding will be able to review any of the data, information, analysis 

or other documentation relied upon by the seller for which privileged treatment is sought. 

A seller must grant access to privileged data to any party that signs a protective order 

within 5 days from the date that the party executes the protective order. 

§ 35.38 Mitigation. 

 (a) A Seller that has been found to have market power in generation or that is 

presumed to have horizontal market power by virtue of failing or foregoing the horizontal 

market power screens, as described in § 35.37(c), may adopt the default mitigation 

detailed in paragraph (b) of this section or may propose mitigation tailored to its own 

particular circumstances to eliminate its ability to exercise market power. Mitigation will 

apply only to the market(s) in which the Seller is found, or presumed, to have market 
Docket No. RM04-7-000 7 

power. 

 (b) Default mitigation consists of three distinct products: 

(1) Sales of power of one week or less priced at the Seller’s incremental cost plus 

a 10 percent adder; 

(2) Sales of power of more than one week but less than one year priced at no 

higher than a cost-based ceiling reflecting the costs of the unit(s) expected to provide the 

service; and 

(3) New contracts filed for review under section 205 of the Federal Power Act for 

sales of power for one year or more priced at a rate not to exceed embedded cost of 

service. 

§ 35.39 Affiliate restrictions.

(a) General affiliate provisions. As a condition of obtaining and retaining marketbased rate authority, the conditions provided in this section, including the restriction on 

affiliate sales of electric energy and all other affiliate provisions, must be satisfied on an 

ongoing basis, unless otherwise authorized by Commission rule or order. Failure to 

satisfy these conditions will constitute a violation of the Seller’s market-based rate tariff. 

(b) Restriction on affiliate sales of electric energy. As a condition of obtaining 

and retaining market-based rate authority, no wholesale sale of electric energy may be 

made between a franchised public utility with captive customers and a market-regulated 

power sales affiliate without first receiving Commission authorization for the transaction 

under section 205 of the Federal Power Act. All authorizations to engage in affiliate 

wholesale sales of electric energy must be listed in a Seller’s market-based rate tariff. 
Docket No. RM04-7-000 8 

 (c) Separation of functions.

 (1) For the purpose of this paragraph, entities acting on behalf of and for the 

benefit of a franchised public utility with captive customers (such as entities controlling 

or marketing power from the electrical generation assets of the franchised public utility) 

are considered part of the franchised public utility. Entities acting on behalf of and for 

the benefit of the market-regulated power sales affiliates of a franchised public utility 

with captive customers are considered part of the market-regulated power sales affiliates. 

(2) (i) To the maximum extent practical, the employees of a market-regulated 

power sales affiliate must operate separately from the employees of any affiliated 

franchised public utility with captive customers. 

 (ii) Franchised public utilities with captive customers are permitted to share 

support employees, and field and maintenance employees with their market-regulated 

power sales affiliates. Franchised public utilities with captive customers are also 

permitted to share senior officers and boards of directors with their market-regulated 

power sales affiliates; provided, however, that the shared officers and boards of directors 

must not participate in directing, organizing or executing generation or market functions. 

(iii) Notwithstanding any other restrictions in this section, in emergency 

circumstances affecting system reliability, a market-regulated power sales affiliate and a 

franchised public utility with captive customers may take steps necessary to keep the bulk 

power system in operation. A franchised public utility with captive customers or the 

market-regulated power sales affiliate must report to the Commission and disclose to the 

public on its website, each emergency that resulted in any deviation from the restrictions 
Docket No. RM04-7-000 9 

of section 35.39, within 24 hours of such deviation. 

 (d) Information sharing.

 (1) Unless simultaneously disclosed to the public, market information may not be 

shared between a franchised public utility with captive customers and a market-regulated 

power sales affiliate if the sharing could be used to the detriment of captive customers. 

 (2) Permissibly shared support employees, field and maintenance employees and 

senior officers and board of directors under §§ 35.39(c)(2)(ii) may have access to 

information covered by the prohibition of § 35.39(d)(1), subject to the no-conduit 

provision in § 35.39(g). 

 (e) Non-power goods or services.

 (1) Unless otherwise permitted by Commission rule or order, sales of any nonpower goods or services by a franchised public utility with captive customers, to a 

market-regulated power sales affiliate must be at the higher of cost or market price. 

 (2) Unless otherwise permitted by Commission rule or order, sales of any nonpower goods or services by a market-regulated power sales affiliate to an affiliated 

franchised public utility with captive customers may not be at a price above market. 

 (f) Brokering of power.

 (1) Unless otherwise permitted by Commission rule or order, to the extent a 

market-regulated power sales affiliate seeks to broker power for an affiliated franchised 

public utility with captive customers: 

(i) The market-regulated power sales affiliate must offer the franchised public 

utility’s power first; 
Docket No. RM04-7-000 10 

(ii) The arrangement between the market-regulated power sales affiliate and the 

franchised public utility must be non-exclusive; and 

(iii) The market-regulated power sales affiliate may not accept any fees in 

conjunction with any brokering services it performs for an affiliated franchised public 

utility. 

 (2) Unless otherwise permitted by Commission rule or order, to the extent a 

franchised public utility with captive customers seeks to broker power for a marketregulated power sales affiliate: 

(i) The franchised public utility must charge the higher of its costs for the service 

or the market price for such services; 

(ii) The franchised public utility must market its own power first, and 

simultaneously make public (on the Internet) any market information shared with its 

affiliate during the brokering; and 

(iii) The franchised public utility must post on the Internet the actual brokering 

charges imposed. 

 (g) No conduit provision. A franchised public utility with captive customers and 

a market-regulated power sales affiliate are prohibited from using anyone, including asset 

managers, as a conduit to circumvent the affiliate restrictions in §§ 35.39(a) through (g). 

 (h) Franchised utilities without captive customers. If necessary, any affiliate 

restrictions regarding separation of functions, power sales or non-power goods and 

services transactions, or brokering involving two or more franchised public utilities, one 

or more of whom has captive customers and one or more of whom does not have captive 
Docket No. RM04-7-000 11 

customers, will be imposed on a case-by-case basis. 

§ 35.40 Ancillary services. 

 A Seller may make sales of ancillary services at market-based rates only if it has 

been authorized by the Commission and only in specific geographic markets as the 

Commission has authorized. 

§ 35.41 Market behavior rules. 

 (a) Unit operation. Where a Seller participates in a Commission-approved 

organized market, Seller must operate and schedule generating facilities, undertake 

maintenance, declare outages, and commit or otherwise bid supply in a manner that 

complies with the Commission-approved rules and regulations of the applicable market. 

A Seller is not required to bid or supply electric energy or other electricity products 

unless such requirement is a part of a separate Commission-approved tariff or is a 

requirement applicable to Seller through Seller’s participation in a Commission-approved 

organized market. 

 (b) Communications. A Seller must provide accurate and factual information 

and not submit false or misleading information, or omit material information, in any 

communication with the Commission, Commission-approved market monitors, 

Commission-approved regional transmission organizations, Commission-approved 

independent system operators, or jurisdictional transmission providers, unless Seller 

exercises due diligence to prevent such occurrences. 

 (c) Price reporting. To the extent a Seller engages in reporting of transactions 

to publishers of electric or natural gas price indices, Seller must provide accurate and 
Docket No. RM04-7-000 12 

factual information, and not knowingly submit false or misleading information or omit 

material information to any such publisher, by reporting its transactions in a manner 

consistent with the procedures set forth in the Policy Statement issued by the 

Commission in Docket No. PL03-3-000 and any clarifications thereto. Unless Seller has 

previously provided the Commission with a notification of its price reporting status, 

Seller must notify the Commission within 15 days of the effective date of this regulation 

or within 15 days of the date it begins making wholesale sales, whichever is earlier, 

whether it engages in such reporting of its transactions. Seller must update the 

notification within 15 days of any subsequent change in its transaction reporting status. 

In addition, Seller must adhere to such other standards and requirements for price 

reporting as the Commission may order. 

 (d) Records retention. A Seller must retain, for a period of five years, all data 

and information upon which it billed the prices it charged for the electric energy or 

electric energy products it sold pursuant to Seller’s market-based rate tariff, and the 

prices it reported for use in price indices. 

§ 35.42 Change in status reporting requirement.

 (a) As a condition of obtaining and retaining market-based rate authority, a Seller 

must timely report to the Commission any change in status that would reflect a departure 

from the characteristics the Commission relied upon in granting market-based rate 

authority. A change in status includes, but is not limited to, the following: 

 (1) Ownership or control of generation capacity that results in net increases of 100 

MW or more, or of inputs to electric power production, or ownership, operation or 
Docket No. RM04-7-000 13 

control of transmission facilities, or 

 (2) Affiliation with any entity not disclosed in the application for market-based 

rate authority that owns or controls generation facilities or inputs to electric power 

production, affiliation with any entity not disclosed in the application for market-based 

rate authority that owns, operates or controls transmission facilities, or affiliation with 

any entity that has a franchised service area. 

 (b) Any change in status subject to paragraph (a) of this section must be filed no 

later than 30 days after the change in status occurs. Power sales contracts with future 

delivery are reportable 30 days after the physical delivery has begun. Failure to timely 

file a change in status report constitutes a tariff violation. 

 (c) When submitting a change in status notification regarding a change that 

impacts the pertinent assets held by a Seller or its affiliates with market-based rate 

authorization, a Seller must include an appendix of assets in the form provided in 

Appendix B of this subpart. 
Docket No. RM04-7-000 14 

Appendix A 

Standard Screen Format 

(Data provided for Illustrative Purposes only) 

Part I -- Pivotal Supplier Analysis 

Row Generation MW Reference 

Seller and Affiliate Capacity 

A Installed Capacity 19,500 Workpaper 

B Long-Term Firm Purchases 500 Workpaper 

C Long-Term Firm Sales -1,000 Workpaper 

D Imported Power 0 Workpaper 

Non-Affiliate Capacity 

E Installed Capacity 8,000 Workpaper 

F Long-Term Firm Purchases 500 Workpaper 

G Long-Term Firm Sales -2,500 Workpaper 

H Imported Power 3,500 Workpaper 

 

I Balancing Authority Area Reserve Requirement -2,160 Workpaper 

J Amount of Line I Attributable to Seller, if any -2,160 Workpaper 

 

K Total Uncommitted Supply (SUM A,B,C,D,E,F,G,I) 9,840 

 

Load 

L Balancing Authority Area Annual Peak Load 18,000 Workpaper 

M Average Daily Peak Native Load in Peak Month -16,500 Workpaper 

N Amount of Line M Attributable to Seller, if any -16,500 Workpaper 

 

O Wholesale Load (SUM L,M) 1,500 

 

P Net Uncommitted Supply (K-O) 8,340 

 

Q Seller's Uncommitted Capacity (SUM A,B,C,D,J,N) 340 

 

Result of Pivotal Supplier Screen (Pass if Line Q < Line P) PASS 

 (Fail if Line Q > Line P) 

 
Docket No. RM04-7-000 15 

Part II – Market Share Analysis (Data provided for Illustrative Purposes only)Row Q1 Q2 Q3 Q4 

(MW) (MW) (MW) (MW) 

Seller and Affiliate Capacity

A Installed Capacity 19,500 19,500 19,500 19,500 B Long-Term Firm Purchases 500 500 500 500 C Long-Term Firm Sales -1,000 -1,000 -1,000 -1,000 D Seasonal Average Planned Outages -4,000 -3,000 -800 -3,500 E Imported Power 0 0 0 0 

Capcacity Deductions 

F Average Peak Native Load in the Season -11,500 -10,000 -12,500 -11,500 G Amount of Line F Attributable to Seller, if any -11,500 -10,000 -12,500 -11,500 H Amount of Line F Attributable to Others, if any 0 0 0 0 I Balancing Authority Area Reserve Requirement -1,500 -1,320 -1,560 -1,500 J Amount of Line I Attributable to Seller, if any -1,500 -1,320 -1,560 -1,500 K Amount of Line I Attributable to Others, if any 0 0 0 0 

Non-Affiliate Capacity 

L Installed Capacity 8,000 8,000 8,000 8,000 M Long-Term Firm Purchases 500 500 500 500 N Long-Term Firm Sales -2,500 -2,500 -2,500 -2,500 O Local Seasonal Average Planned Outages -800 -200 -300 -400 P Uncommitted Capacity Imports 5,000 4,500 3,500 4,000 

Supply Calculation 

Q Total Competing Supply (SUM L,M,N,O,P,H,K) 10,200 10,300 9,200 9,600 R Seller's Uncommitted Capacity (SUM A,B,C,D,E,G,J) 2,000 4,680 4,140 2,500 S Total Seasonal Uncommitted Capacity (SUM Q,R) 12,200 14,980 13,340 12,100 T Seller's Market Share (R/S) 16.39% 31.24% 31.03% 20.66%  Results (Pass if < 20%) PASS FAIL FAIL FAIL  (Fail if ≥ 20)
Docket No. RM04-7-000 16 

Appendix B 

This is an example of the required appendix listing the filing entity and all its energy affiliates and their 

which should be submitted with all market-based rate filings. 

Market-Based Rate Authority and Generation Assets 

Location 

Filing Entity and 

its Energy 

Affiliates 

Docket # 

where MBR 

authority 

was 

granted 

Generation 

Name 

Owned 

By 

Controlled 

By 

Date 

Control 

Transferred 

Balancing 

Authority 

Area 

Geographic Region (per 

Appendix 

D) 

In

ABC Corp. ER05-23X- 000 ABC falls plant #1 ABC Corp. ABC Corp. NA* 

ABC 

balancing 

authority 

area 

Central 8/

xyz Inc. ER94-79XX- 000 NA NA NA NA NA NA 

RST LLC ER01-2XX5- 000 Green CoGen WWW Corp RST LLC 5/23/2005 New York ISO Northeast 12

Sample Co. ER03- XX45-000 Sample Co. 3 Sample Co. YYY Corp 2/1/1982 

Sample 

Co. 

balancing 

authority 

Southwest 5/

*if an entity has no assets or the field is not applicable please indicate so by inputting (NA). 
Docket No. RM04-7-000 17 

Electric Transmission Assets and/or Natural Gas Intrastate Pipelines and/or Gas Storage Facili

Location 

Filing Entity and 

its Energy 

Affiliates 

Asset Name 

and Use 

Owned 

By 

Controlled 

By 

Date 

Control 

Transferred Balancing Authority Area 

Geographic Region (per 

Appendix 

D) 

ABC Corp. 

CBA Line, 

used to 

interconnect 

Green Cogen 

to New York 

ISO 

transmission 

system 

ABC 

Corp. ABC Corp. NA* New York ISO Northeast 

Etc. LP 

Nowhere 

Pipeline, used 

to connect 

Storage LLC’s 

- Longway 

Pipeline to 

ABC falls plant 

#1 

Etc. LP Etc. LP NA ABC balancing authority area Central 

*if the field is not applicable please indicate so by inputting (NA). 
Docket No. RM04-7-000 18

Note: The following appendices will not be published in the Code of Federal 

Regulations. 

Appendix C

Required Provisions of the Market-Based Rate Tariff 

Compliance with Commission Regulations

Seller shall comply with the provisions of 18 CFR Part 35, Subpart H, as applicable, and 

with any conditions the Commission imposes in its orders concerning seller’s marketbased rate authority, including orders in which the Commission authorizes seller to 

engage in affiliate sales under this tariff or otherwise restricts or limits the seller’s 

market-based rate authority. Failure to comply with the applicable provisions of 18 CFR 

Part 35, Subpart H, and with any orders of the Commission concerning seller’s marketbased rate authority, will constitute a violation of this tariff. 

Limitations and Exemptions Regarding Market-Based Rate Authority

[Seller should list all limitations (including markets where seller does not have 

market-based rate authority) on its market-based rate authority and any 

exemptions from or waivers granted of Commission regulations and include 

relevant cites to Commission orders]. 

Include All Of The Following Provisions That Are Applicable

Mitigated Sales
Docket No. RM04-7-000 19 

Sales of energy and capacity are permissible under this tariff in all balancing authority 

areas where the Seller has been granted market-based rate authority. Sales of energy and 

capacity under this tariff are also permissible at the metered boundary between the 

Seller’s mitigated balancing authority area and a balancing authority area where the 

Seller has been granted market-based rate authority provided: (i) legal title of the power 

sold transfers at the metered boundary of the balancing authority area; (ii) any power sold 

hereunder is not intended to serve load in the seller’s mitigated market; and (iii) no 

affiliate of the mitigated seller will sell the same power back into the mitigated seller’s 

mitigated market. Seller must retain, for a period of five years from the date of the sale, 

all data and information related to the sale that demonstrates compliance with items (i), 

(ii) and (iii) above. 

Ancillary Services

 RTO/ISO Specific – Include All Services the Seller Is Offering

PJM: Seller offers regulation and frequency response service, energy imbalance service, 

and operating reserve service (which includes spinning, 10-minute, and 30-minute 

reserves) for sale into the market administered by PJM Interconnection, L.L.C. ("PJM") 

and, where the PJM Open Access Transmission Tariff permits, the self-supply of these 

services to purchasers for a bilateral sale that is used to satisfy the ancillary services 

requirements of the PJM Office of Interconnection. 
Docket No. RM04-7-000 20 

New York: Seller offers regulation and frequency response service, and operating 

reserve service (which include 10-minute non-synchronous, 30-minute operating 

reserves, 10-minute spinning reserves, and 10-minute non-spinning reserves) for sale to 

purchasers in the market administered by the New York Independent System Operator, 

Inc. 

New England: Seller offers regulation and frequency response service (automatic 

generator control), operating reserve service (which includes 10-minute spinning reserve, 

10-minute non-spinning reserve, and 30-minute operating reserve service) to purchasers 

within the markets administered by the ISO New England, Inc. 

California: Seller offers regulation service, spinning reserve service, and non-spinning 

reserve service to the California Independent System Operator Corporation ("CAISO") 

and to others that are self-supplying ancillary services to the CAISO. 

 Third Party Provider

Third-party ancillary services [include all of the following that the seller is offering: 

Regulation Service, Energy Imbalance Service, Spinning Reserves, and Supplemental 

Reserves]. Sales will not include the following: (1) sales to an RTO or an ISO, i.e., 

where that entity has no ability to self-supply ancillary services but instead depends on 

third parties; (2) sales to a traditional, franchised public utility affiliated with the third-
Docket No. RM04-7-000 21 

party supplier, or sales where the underlying transmission service is on the system of the 

public utility affiliated with the third-party supplier; and (3) sales to a public utility that is 

purchasing ancillary services to satisfy its own open access transmission tariff 

requirements to offer ancillary services to its own customers. 
Docket No. RM04-7-000 22 

Appendix D

Regions and Schedule for Regional Market Power Update Process

The six regions are combinations of NERC regions; RTOs and ISOs and are depicted in 

the map that follows. 

Map of Geographic Regions 

[ ] Northeast (ISO-NE, NYISO, PJM) 

[ ] Southeast (NERC Regions SERC and FRCC (not including PJM or Midwest ISO)) 

[ ] Central (Midwest ISO, NERC Region MRO) 
Docket No. RM04-7-000 23 

[ ] Southwest Power Pool (NERC region SPP) 

[ ] Southwest (California, NERC region WECC-AZNMSNV) 

[ ] Northwest (NERC Regions WECC-NWPP and WECC-RMPA) 

Regional Market Power Update Schedule

Study 

Period 

Filing Period 

(Anytime between) Entities Required to File 

2006 December 1-30, 2007 

Northeast 

Transmission 

Operators 

2006 June 1-30, 2008 

Southeast 

Transmission 

Operators 

All others in Northeast that 

did not file in December 

including all power marketers 

that sold in the Northeast. 

2006 December 1-30, 2008 

All others in Southeast that 

did not file in June including 

all power marketers that sold 

in the Southeast and have not 

already been found to be 

Category 1 sellers. 

2007 December 1-30, 2008 

Central 

Transmission 

Operators 

2007 June 1-30, 2009 SPP Transmission 

Operators 

All others in Central that did 

not file in December 

including all power marketers 

that sold in the Central and 

have not already been found 

to be Category 1 sellers. 

2007 December 1-30, 2009 

All others in SPP that did not 

file in June including all 

power marketers that sold in 

SPP and have not already 
Docket No. RM04-7-000 24 

been found to be Category 1 

sellers. 

2008 December 1-30, 2009 

Southwest 

Transmission 

Operators 

2008 June 1-30, 2010 

Northwest 

Transmission 

Operators 

All others in Southwest that 

did not file in December 

including all power marketers 

that sold in the Southwest and 

have not already been found 

to be Category 1 sellers. 

2008 December 1-30, 2010 

All others in Northwest that 

did not file in June including 

all power marketers that sold 

in the Northwest and have not 

already been found to be 

Category 1 sellers. 

2009 December 1-30, 2010 

Northeast 

Transmission 

Operators 

All Category 1 sellers should be identified by the Commission prior to the 

subsequent filing periods. Only Category 2 sellers will continue to file updated 

market power analyses according to the repeating schedule below. 

2009 June 1-30, 2011 

Southeast 

Transmission 

Operators 

Others in Northeast that did 

not file in December and have 

not been found to be 

Category 1 sellers. 

2009 December 1-30, 2011 

Others in Southeast that did 

not file in June and have not 

been found to be Category 1 

sellers. 

2010 December 1-30, 2011 

Central 

Transmission 

Operators 

2010 June 1-30, 2012 SPP Transmission 

Operators 

Others in Central that did not 

file in December and have not 

been found to be Category 1 

sellers. 

2010 December 1-30, 2012 Others in SPP that did not file 

in June and have not been 
Docket No. RM04-7-000 25 

found to be Category 1 

sellers. 

2011 December 1-30, 2012 

Southwest 

Transmission 

Operators 

2011 June 1-30, 2013 

Northwest 

Transmission 

Operators 

Others in Southwest that did 

not file in December and have 

not been found to be 

Category 1 sellers. 

2011 December 1-30, 2013 

Others in Northwest that did 

not file in June and have not 

been found to be Category 1 

sellers. 

This review cycle will be repeated in subsequent years. 
Docket No. RM04-7-000 26 

 Appendix E 

List of Commenters and Acronyms

Allegheny Energy Supply Co. and Allegheny Power - Allegheny Energy Companies

Alliance for Cooperative Energy Services Power Marketing LLC - Alliance Power 

 Marketing 

Ameren Services Co., Inc. - Ameren 

AARP - AARP

American Public Power Association/Transmission Access Policy Study Group – 

 APPA/TPAS

American Wind Energy Association - AWEA

Avista Corp. - Avista

Board of Water, Light and Sinking Fund Commissioners of the City of Dalton, Georgia – 

 Dalton Utilities

California Electricity Oversight Board - California Board

California Independent System Operator Corp. - CAISO

California Public Utilities Commission - California Commission 

Coalition of Midwest Transmission Customers, PJM Industrial Customer Coalition, 

 NEPOOL Industrial Customer Coalition, Industrial Energy Users of Ohio, Southeast 

 Electricity Consumers Association, Southwest Industrial Customer Coalition – 

 Industrial Customers

Cogentrix Energy, Inc. and Goldman Sachs Group - Cogentrix/Goldman

Constellation Energy Group, Inc. - Constellation

Consumers Energy Co. - Consumers

Dominion Resources Services, Inc. - Dominion

Duke Energy Corp. - Duke

Duquesne Power, LLC; Duquesne Light Company; Duquesne Keystone, LLC; Duquesne 

 Conemaugh, LLC; and Monmouth Energy, Inc. - Duquesne Companies 

E.ON U.S. LLC - E.ON U.S. 

Edison Electric Institute - EEI

ElectriCities of North Carolina, Inc. and Piedmont Municipal Power Agency – Carolina 

 Agencies 

Electricity Consumers Resource Council - ELCON

El Paso E&P Co. L.P. - El Paso E&P

Electric Power Supply Association - EPSA

Entergy Services, Inc. - Entergy

FirstEnergy Service Co. - FirstEnergy

Florida Power & Light Company and FPL Energy, LLC - FP&L

Indianapolis Power & Light Co. - Indianapolis P&L

ISO New England Inc. - ISO-NE
Docket No. RM04-7-000 27 

Joe Pace, PhD. - Dr. Pace

Mark B. Lively - Mr. Lively 

Merrill Lynch Commodities Inc., J.P. Morgan Ventures Energy Corp. and Bear Energy – 

 Financial Companies

MidAmerican Energy Co. and PacifiCorp - MidAmerican

Midwest Energy, Inc. – Midwest Energy

Mirant Corp. - Mirant

Montana Consumer Counsel - Montana Counsel

Morgan Stanley Capital Group Inc. - Morgan Stanley

National Association of State Utility Consumer Advocates - NASUCA

National Rural Electric Cooperative Association - NRECA

New Jersey Board of Public Utilities - New Jersey Board 

New Mexico Office of Attorney General, Colorado Office of Consumer Counsel, Utah 

 Committee of Consumer Services, Public Citizen, Public Utility Law Project of New 

 York, Rhode Island Office of Attorney General, and Rhode Island Division of Public 

 Utilities and Carriers - State AGs and Advocates

New York Independent System Operator, Inc. - NYISO

New York State Public Service Commission - New York Commission

Newfoundland and Labrador Hydro - NL Hydro

Newmont Mining Corp. - Newmont

NiSource Inc. - NiSource

NRG Energy, Inc. - NRG

Oregon Public Utilities Commission - Oregon Commission

Ormet Power Marketing - Ormet

Pacific Gas & Electric Co. - PG&E 

Piedmont Municipal Power Agency and ElectriCities of North Carolina – Carolina 

 Agencies 

Pinnacle West Companies - Pinnacle

Powerex Corp. - Powerex

PPL Companies - PPL

PPM Energy, Inc. - PPM

Progress Energy, Inc. - Progress Energy 

Public Service Electric and Gas Company, PSEG Power LLC and PSEG Energy 

 Resources & Trade LLC - PSEG Companies 

Public Service Co. of New Mexico/Tuscon Electric Power Company - PNM/Tuscon

Public Works Commission for the City of Fayetteville, North Carolina - Fayetteville

Puget Sound Energy, Inc. - Puget

Reliant Energy, Inc. – Reliant 

Richard Blumenthal, Attorney General for the State of Connecticut and the People of the 

 State of Illinois, by and through the Illinois Attorney General, Lisa Madigan – 

 Attorneys General of Connecticut and Illinois 
Docket No. RM04-7-000 28 

Romkaew Broehm, PhD. and Peter Fox-Penner - Drs. Broehm and Fox-Penner

Sempra Energy - Sempra

Southern California Edison Co. - SoCal Edison

Southern Company Services, Inc. - Southern

Southwest Industrial Customer Coalition - Southwest Coalition

Suez Energy North America, Inc. and Chevron USA Inc. - Suez/Chevron

Towns of Black Creek, NC; Dallas, NC; Forest City, NC; Lucama, NC; Sharpsburg, NC; 

 Stantonsburg, NC; and Waynesville, NC - NC Towns

Transmission Dependent Utility Systems - TDU Systems

TXU Portfolio Management Co. LP - TXU Wholesale

Westar Energy, Inc. and Kansas Gas and Electric Co. - Westar

Williams Power Co., Inc. - Williams

Wisconsin Electric Power Co. - Wisconsin Electric

Xcel Energy Services Inc. - Xcel