UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

(Docket No. RM04-7-000) 

Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary 

Services by Public Utilities 

(May 19, 2006) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking. 

SUMMARY: The Federal Energy Regulatory Commission (Commission) is proposing 

to amend 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 proposing to codify and, in certain respects, revise 

its current standards for market-based rates for sales of electric energy, capacity, and 

ancillary services. The Commission is proposing to retain several of the core elements of 

its current standards for granting market-based rates. However, we propose certain 

revisions to these standards and seek comment on other issues. The Commission also 

proposes to streamline certain aspects of its filing requirements to reduce the 

administrative burdens on applicants, customers and the Commission. 

DATES: Comments are due [insert date 60 days after publication in the FEDERAL 

REGISTER]. Reply comments are due [insert 30 days after comment date]. 
Docket No. RM04-7-000 - 2 - 

Comments should be double spaced and include an executive summary. 

ADDRESSES: You may submit comments, identified by Docket No. RM04-7-000, by 

one of the following methods: 

• Agency Web Site: http://www.ferc.gov. Follow the instructions for submitting 

comments via the eFiling link found in the Comment Procedures Section of the 

preamble. 

• Mail: Commenters unable to file comments electronically must mail or hand 

deliver an original and 14 copies of their comments to: Federal Energy 

Regulatory Commission, Office of the Secretary, 888 First Street N.E., 

Washington, D.C., 20426. Please refer to the Comment Procedures Section of the 

preamble for additional information on how to file paper comments. 

FOR FURTHER INFORMATION CONTACT: 

Kelly A. Perl (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6421 

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 

NOTICE OF PROPOSED RULEMAKING 

Paragraph Numbers

I. Introduction .................................................................................................................... 1.

II. Background .................................................................................................................. 2.

III. Discussion.................................................................................................................. 18.

A. Horizontal Market Power ....................................................................................... 18.

1. Current Policy...................................................................................................... 18.

2. Proposal ............................................................................................................... 39.

B. Vertical Market Power............................................................................................ 84.

1. Current Policy...................................................................................................... 85.

2. Proposal ............................................................................................................... 89.

C. Affiliate Abuse........................................................................................................ 96.

1. Power Sales Restrictions ..................................................................................... 98.

2. Market-Based Rate Code of Conduct For Affiliate Transactions Involving Power 

Sales and Brokering, Non-Power Goods and Services and Information Sharing.. 120.

D. Mitigation ............................................................................................................. 133.

1. Current Policy.................................................................................................... 133.

2. Proposal ............................................................................................................. 138.

E. Implementation Process ....................................................................................... 150.

1. Current Practice ................................................................................................ 150.

2. Proposal ............................................................................................................. 151.

F. Market-Based Rate Tariff (MBR Tariff)............................................................... 160.

G. Miscellaneous Issues ............................................................................................ 167.

1. Waivers.............................................................................................................. 167.

2. Foreign Sellers................................................................................................... 172.

3. Change in Status ................................................................................................ 179.

4. Third-Party Providers of Ancillary Services .................................................... 186.

H. Proposed Revisions To Regulations..................................................................... 196.

1. Section 35.27 [Currently] Power Sales at Market-Based Rates....................... 196.

2. Section 35.36 Generally ................................................................................... 199.
Docket No. RM04-7-000 - 2 - 

3. Section 35.37 Market Power Analysis Required.............................................. 202.

4. Section 35.38 Mitigation .................................................................................. 204.

5. Section 35.39 Affiliate Provisions.................................................................... 205.

6. Section 35.40 Ancillary Services ..................................................................... 207.

7. Section 35.41 Market Behavior Rules.............................................................. 208.

8. Section 35.42 Market-Based Rate Tariff ......................................................... 209.

9. Section 35.43 Change in Status Reporting Requirement ................................. 210.

IV. Information Collection Statement ........................................................................... 211.

V. Environmental Analysis ........................................................................................... 218.

VI. Regulatory Flexibility Act Analysis........................................................................ 219.

VII. Comment Procedures ............................................................................................. 223.

VIII. Document Availability ......................................................................................... 226.
 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Nora Mead Brownell, and Suedeen G. Kelly. 

Market-Based Rates for Wholesale Sales of Electric 

Energy, Capacity and Ancillary Services by Public 

Utilities 

Docket No. RM04-7-000 

NOTICE OF PROPOSED RULEMAKING 

(May 19, 2006) 

I. Introduction

1. Pursuant to sections 205 and 206 of the Federal Power Act (FPA),1

 the 

Commission is proposing to amend its regulations to revise Subpart H to Part 35 of Title 

18 of the Code of Federal 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 authorizations and tariffs so they will be 

expressly conditioned on or revised to reflect certain new requirements proposed herein. 

The major components of this Notice of Proposed Rulemaking (NOPR) are summarized 

in the next section. 

 1

 16 U.S.C. § 824d, 824e (2000). 
Docket No. RM04-7-000 - 2 - 

II. Background 

2. In 1988, the Commission began considering proposals for market-based pricing of 

wholesale power sales. The Commission acted on market-based rate proposals filed by 

various wholesale suppliers on a case-by-case basis. Over the years, the Commission 

developed a four-prong analysis used to assess whether a seller should be granted marketbased 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. 

3. The courts have reviewed the Commission’s market-based rate program and found 

that it satisfies the FPA. The FPA requires that all rates demanded by public utilities for 

the sale of electric energy at wholesale be found “just and reasonable.”2

 The United 

States Supreme Court has explained that the just and reasonable standard “does not 

compel the Commission to use any single pricing formula.”3

 The United States Court of 

Appeals for the D.C. Circuit has long held that “when there is a competitive market the 

[Commission] may rely upon market-based prices in lieu of cost-of-service regulation to 

 2

 Louisiana Energy and Power v. FERC, 141 F.3d 364, 365 (D.C. Cir. 1998) 

(citing 16 U.S.C. § 824d(a)) (Louisiana Energy). 

3

 Mobil Oil Exploration v. United Distribution Co., 498 US 211, 224 (1991). 
Docket No. RM04-7-000 - 3 - 

assure a ‘just and reasonable’ result.”4

 The Commission’s authorization of market-based 

rates has been found to satisfy the just and reasonable standard of the FPA.5

4. The Commission initiated the instant rulemaking proceeding in April 2004 to 

consider “the adequacy of the current four-prong 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. The comments from these technical conferences are considered in 

this NOPR.7

5. On April 14, 2004, the Commission issued an order modifying the then-existing 

generation market power analysis and its policy governing market power mitigation, on 

an interim basis.8

 The April 14 Order adopted a policy that would provide sellers a 

 4

 Elizabethtown Gas Company v. FERC, 10 F.3d 866, 870 (D.C. Cir. 1993) 

(Elizabethtown Gas), (citing Tejas Power Corp. v. FERC, 908 F.2d 998, 1004 (D.C. Cir. 

1990)). 

5

 See Louisiana Energy; Elizabethtown Gas; Consumers Energy Company v. 

FERC, 367 F.3d 915, 923 (D.C. Cir. 2004). 

6

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

(initiating rulemaking proceeding). 

7

 A summary of the comments submitted in this proceeding is attached as 

Appendix E. A list of the commenters is included in Appendix D. 

8

 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 - 4 - 

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. 

6. On July 8, 2004, the Commission acted on 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. The Commission clarified, among 

other things, the types of data on which sellers and intervenors may rely, and that 

adjustments may be allowed in certain circumstances. The Commission also clarified 

that mitigation would be imposed in all markets where a seller is found to have 

generation market power. 

7. The Commission believes it is now appropriate to revise and codify the standards 

for market-based rates for wholesale sales of electric energy, capacity and ancillary 

services. Refining and codifying effective standards for market-based rates will help 

customers by ensuring that they are protected from the exercise of market power. It will 

also provide greater certainty to sellers seeking market-based rate authority. 

8. The regulations proposed herein would adopt in most respects the Commission’s 

current standards for granting market-based rates. We believe these standards have, with 

the exceptions noted below, allowed the Commission to distinguish between applicants 

that have market power and those that do not. For example, the current interim 
Docket No. RM04-7-000 - 5 - 

horizontal (generation) market power screens9

 have allowed the Commission to identify a 

number of smaller applicants that do not have generation market power. The 

Commission authorized these applicants to obtain or retain market-based rate authority, 

which benefits customers by encouraging new entry and by providing them with the 

greater flexibility in product offerings that market-based rate approval conveys. The 

current screens also have allowed the Commission to more accurately identify instances 

where certain larger sellers may possess market power. If an applicant fails our screens, 

this does not, however, constitute a definitive finding of market power. Rather, our 

current standards allow any applicant that fails these screens to demonstrate that it lacks 

market power in generation using the delivered price test (DPT).10 The DPT has 

provided appropriate flexibility in allowing the Commission to consider the differing 

factual situations of particular sellers, such as those that have a responsibility for serving 

native load customers. The Commission proposes to continue to apply the DPT in such a 

flexible manner. 

 9

 As discussed below, the Commission proposes to henceforth refer to the 

generation market power analysis as the horizontal market power analysis. 

10 See April 14 Order at P 106 (“The [DPT] defines the relevant market by 

identifying potential suppliers based on market prices, input costs, and transmission 

availability, and calculates each suppliers’ economic capacity and available economic 

capacity for each season/load condition. The results of the [DPT] can be used for pivotal 

supplier, market share and market concentration analyses.”). 
Docket No. RM04-7-000 - 6 - 

9. In cases where the applicant has failed the DPT, or has otherwise chosen to adopt 

default cost-based mitigation or to propose other cost-based mitigation (e.g., cost-based 

rates) or tailored mitigation, our current policies protect customers by ensuring that 

applicants with market power in a given area have that market power mitigated. We 

recognize, however, that there has been uncertainty regarding the rate methodologies to 

use in developing cost-based market power mitigation and the effectiveness of the 

existing cost-based mitigation. We therefore seek comment in this rulemaking on several 

issues relating to cost-based market power mitigation, including: (i) whether there should 

be a standard methodology for determining cost-based ceiling rates and the appropriate 

methodology for sales of less than one week; (ii) whether selective discounting should be 

allowed for sellers that have been found to have market power, or that accept a 

presumption of market power, and are offering power under cost-based rates; and 

(iii) whether a mitigated seller that seeks to sell excess power generated within a 

mitigated market should be required to first offer its available capacity at cost-based rates 

to customers within the mitigated market. 

10. We also propose certain modifications to the horizontal (generation) market power 

screens to reflect our experience in applying them and the comments received in this 

proceeding. First, the Commission proposes to modify the treatment of newlyconstructed generation to avoid a situation in which all generation becomes exempt from 

our market power analyses as new generation is constructed and older (pre-1996) 

generation is retired. Second, although we propose to retain the default relevant 
Docket No. RM04-7-000 - 7 - 

geographic market (control area), we provide guidance as to the factors the Commission 

will consider in evaluating whether, in a particular case, to adopt an expanded geographic 

market instead of relying on the default geographic market. Third, we propose to change 

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 to 

clarify that native load can only include load attributable to native load customers as that 

term is defined insection 33.3(d)(4)(i) of the Commission’s regulations..11 Fourth, we 

propose to allow applicants the option of using seasonal capacity instead of nameplate 

capacity,12 and to retain the snapshot in time approach for the screens but to allow 

“known and measurable” changes (sometimes referred to as foreseeable and reasonably 

certain at the time of filing) for the DPT. 

11. With regard to vertical market power and, in particular, transmission market 

power, the Commission proposes to continue the current policy under which an open 

access transmission tariff (OATT) is deemed to mitigate a seller’s transmission market 

power.13 However, in recognition of the fact that OATT violations may nonetheless 

 11 18 CFR § 33.3(d)(4)(i) (2005). 

12 Nameplate capacity is the full-load continuous rating of a generator, prime 

mover, or other electric power production equipment under specific conditions as 

designated by the manufacturer. Installed generator nameplate rating is usually indicated 

on a nameplate physically attached to the generator. 

13 See Promoting Wholesale Competition Through Open Access Nondiscriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by 

(continued) 
Docket No. RM04-7-000 - 8 - 

occur, we propose that violation(s) of the OATT may be cause to revoke market-based 

rate authority in addition to any other applicable remedies, such as civil penalties. We 

also note that concerns regarding the adequacy of the current OATT will be addressed in 

Docket No. RM05-25-000, Preventing Undue Discrimination and Preference in 

Transmission Service. We are today issuing a Notice of Proposed Rulemaking to reform 

the OATT in that docket. 

12. With regard to vertical market power and, in particular, other barriers to entry, we 

propose to continue our current approach but provide clarification of what types of 

factors we would examine and we propose to combine the other barriers to entry analysis 

with the rest of our vertical market power analysis. 

13. With regard to affiliate abuse, the Commission proposes to discontinue referring to 

affiliate abuse as a separate “prong” of our analysis and instead proposes to codify in our 

regulations an explicit requirement that any seller with market-based rate authority must 

 

Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21,540 (May 10, 1996), 

FERC Stats. & Regs., Regulations Preambles January 1991-June 1996 ¶ 31,036 (1996), 

order on reh'g, Order No. 888-A, 62 FR 12,274 (March 14, 1997), 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 relevant 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 - 9 - 

comply with the affiliate sales restrictions and other affiliate provisions.14 The 

Commission proposes to address 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 proposes to retain its policy 

that sales of power between a franchised public utility and any of its non-regulated power 

sales affiliates15 must be pre-approved by the Commission. To demonstrate that an 

affiliate sale is just, reasonable and not unduly discriminatory, an applicant has several 

options, including pricing that sale at a market index that meets certain standards, 

conducting an auction that reflects certain guidelines, or otherwise meeting the standards 

 14 In the case of non-exempt wholesale generator (EWG) public utilities, for 

matters arising under Part II of the FPA, the term “affiliate” is defined as that term is used 

in section 358.3(b) and (c) (formerly section 161.2) of the Commission’s regulations. 

Section 358.3(b) defines “affiliate” as “another person which controls, is controlled by, or 

is under common control with, such person.” Section 358.3(c) states that “control 

(including the terms ‘controlling,’ ‘controlled by,’ and ‘under common control with’) . . . 

includes, but is not limited to, the possession, directly or indirectly and whether acting 

alone or in conjunction with others, of the authority to direct or cause the direction of the 

management or policies of a company. A voting interest of 10 percent or more creates a 

rebuttable presumption of control.” The term “affiliate” in the case of EWG public 

utilities is defined as “any company, 5 percent or more of the outstanding voting 

securities of which are owned, controlled or held with power to vote, directly or 

indirectly, by such company.” See 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, 096 (2006). (To be codified 

at 18 CFR section 366.1 (2006).) 

15 By “non-regulated” power sales affiliate, the Commission is referring to nontraditional power sellers including a power marketer, EWG, qualifying facilities (QFs), or 

other power seller affiliate, whose power sales are not regulated on a cost basis under the 

FPA. 
Docket No. RM04-7-000 - 10 - 

set forth in Edgar.

16 An affiliate sale that has not been pre-approved under these 

standards will constitute a tariff violation. In addition, we reaffirm that the Commission 

currently requires that sales made under market-based rate tariffs, including those made 

to affiliates, must be reported in an Electric Quarterly Report (EQR). With regard to 

affiliate transactions under a market-based rate tariff, we reaffirm that we either grant or 

deny authorization to make affiliate sales. To the extent that we authorize an affiliate 

transaction, we reaffirm that, consistent with the Commission’s regulations,17 any such 

agreement shall not be filed with the Commission. 

14. We also propose certain reforms to streamline the administration of the marketbased rate program. As discussed more fully below, in an effort to streamline and 

simplify the market-based rate program in general, while maintaining a high degree of 

oversight, the Commission proposes several changes and clarifications. Significant areas 

of modification involve the three-year updated market power analysis (triennial review or 

updated market power analysis) that all sellers with market-based rate authority are 

required to file, and the development of a market-based rate tariff of general applicability. 

15. With regard to updated market power analyses, the Commission’s current general 

practice is to require an updated market power analysis to be submitted within three years 

 16 Boston Edison Company Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 

(1991) (Edgar) (Describing types of evidence that can be used to demonstrate lack of 

affiliate abuse.) 

17 See 18 CFR § 35.1(g) (2005). 
Docket No. RM04-7-000 - 11 - 

from the date of the Commission order granting the seller market-based rate authority or 

accepting the previous triennial review. The Commission proposes to modify that 

general practice and put in place a structured, systematic review to assist the Commission 

in analyzing sellers in markets based on a coherent and consistent set of data. In 

particular, the Commission proposes to modify the requirements for filing updated 

market power analyses in two ways. First, the Commission proposes to establish two 

categories of sellers with market-based rate authorization. The first category, Category 1 

(approximately 550 sellers), would consist of 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 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 such facilities 

are limited and discrete and do not constitute an integrated grid18) and must present no 

other vertical market power issues. Category 1 sellers would not be required to file a 

regularly scheduled triennial review. The Commission would monitor any market power 

 18 See, e.g., Black Creek Hydro, Inc., 77 FERC ¶ 61,232 (1996). 
Docket No. RM04-7-000 - 12 - 

concerns for these sellers through the change in status reporting requirement,19 and 

through ongoing monitoring by the Commission’s Office of Enforcement. 

16. The second category, Category 2 (approximately 600 sellers), would include all 

sellers that do not qualify for Category 1. Category 2 sellers, in addition to the change in 

status reports, would be required to file regularly scheduled triennial reviews.20 To 

ensure greater consistency in the data used to evaluate Category 2 sellers, the 

Commission proposes to require each Category 2 seller to file updated market power 

analyses for its relevant geographic markets (default and any proposed alternative 

markets) on a schedule that will allow examination of the individual seller at the same 

time that the Commission examines other sellers in these relevant markets and contiguous 

markets within a region from which power could be imported. The Commission would 

continue to make findings on an individual seller basis, but would have before it a 

complete picture of the uncommitted capacity and simultaneous import capability into the 

relevant geographic markets under review. 

17. A second significant change is our proposal to adopt a market-based rate tariff of 

general applicability (MBR tariff), applicable to all sellers authorized to sell electric 

 19 See 18 CFR § 35.27(c) (2005) (reporting requirement for any change reflecting 

a departure from the characteristics the Commission relied upon in granting market-based 

rate authority). Failure to timely file a change in status report would constitute a tariff 

violation. 

20 Failure to timely file a triennial review would constitute a tariff violation. 
Docket No. RM04-7-000 - 13 - 

energy, capacity or ancillary services at wholesale at market-based rates. Further, the 

Commission proposes that, rather than each entity having its own MBR tariff, which can 

result in dozens of tariffs for each corporate family with potentially conflicting 

provisions, each corporate family would have only one tariff, with all affiliates with 

market-based rate authority separately identified in the tariff. This will reduce the 

administrative burden and confusion that occurs when there are multiple, and potentially 

conflicting, tariffs in a single corporate family. Our intent to streamline the terms of an 

MBR tariff is not to reduce the flexibility of sellers and customers in negotiating the 

terms of individual transactions. Rather, this flexibility will continue to exist. The 

purpose of a tariff of general applicability that requires the seller to comply with the 

applicable provisions of the market-based rate regulations is simply to codify, on a 

consistent basis, the basic requirements of market-based rate authorization. 

III. Discussion

A. Horizontal Market Power

1. Current Policy

a. Test for Generation Market Power 

18. In the April 14 Order, the Commission adopted two indicative screens for 

assessing generation market power that provide a rebuttable presumption of whether 

market power exists for a utility applying to obtain or retain market-based rate authority. 

Sellers that do not pass the initial screens are, among other things, allowed to provide 

additional evidence for Commission consideration. Such an approach allows the 
Docket No. RM04-7-000 - 14 - 

Commission to concentrate its efforts on sellers that may possess generation market 

power while screening out those sellers that do not pose such concerns. 

19. The Commission uses two indicative screens for assessing whether a particular 

seller raises any generation market power concerns, each with its own specific focus and 

attributes: a pivotal supplier analysis based on uncommitted capacity at the time of the 

market’s annual peak demand; and a market share analysis of uncommitted capacity 

applied on a seasonal basis. If a seller passes both screens, there is a rebuttable 

presumption that the seller does not possess market power in generation. However, the 

Commission allows intervenors to present evidence to rebut the presumption. On the 

other hand, if a seller fails either screen, this creates a rebuttable presumption that market 

power exists in generation.21 In this instance, the seller may: (1) file a more robust 

market power study, the DPT;22 (2) file a mitigation proposal tailored to its particular 

circumstances that would eliminate the ability to exercise market power; or (3) inform the 

Commission that it will either adopt the default cost-based rates discussed in the April 14 

Order or propose other cost-based rates and submit cost support for such rates. Before 

 21 In such a case, the Commission will institute a section 206 proceeding and such 

a seller’s rates prospectively will be made subject to refund until a final determination of 

market power is made or the seller accepts a presumption of market power and so 

mitigates. April 14 Order, 107 FERC ¶ 61,018 at n. 10. 

22 The only additional market power study allowed is the DPT. However, the 

Commission allows such sellers to present evidence, based on historical wholesale sales 

data, in support of a contention that, notwithstanding the results of the two indicative 

screens, they do not possess market power. 
Docket No. RM04-7-000 - 15 - 

the Commission considers the DPT, the seller must be found to have failed one (or both) 

of the two indicative screens or so concede.23 Accordingly, the DPT is considered as an 

alternative study to support the grant or continuation of market-based rate authority. In 

all cases, the seller or intervenors may present evidence such as historical wholesale sales 

data to support their opinion of whether the seller does or does not possess market power. 

20. Section 35.27(a) of the Commission’s regulations states that “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.”24 

Sellers meeting the criteria of section 35.27(a) of our regulations, as clarified in LG&E 

Capital,

25 may provide evidence demonstrating that they satisfy this section of our 

regulations rather than submit a generation market power analysis. However, if a seller 

sites generation in an area where it or its affiliates own or control other generation assets, 

the seller must provide an analysis regarding whether its new capacity (i.e., post-July 9, 

1996), when added to existing capacity, raises generation market power concerns. 

 23 April 14 Order, 107 FERC ¶ 61,018 at P 37. 

24 18 CFR 35.27(a) (2005).

25 LG&E Capital Trimble County LLC, 98 FERC ¶ 61,261 (2002) (LG&E 

Capital). 
Docket No. RM04-7-000 - 16 - 

21. Alternatively, a seller may forego submitting a generation market power analysis 

and accept a presumption of market power and go directly to mitigation by proposing 

case-specific mitigation that eliminates the ability to exercise market power, or agreeing 

to the default rates discussed below. Under such circumstances there will be a 

presumption of market power in all of the default relevant markets. 

22. If a seller’s proposed mitigation26 does not eliminate its ability to exercise market 

power, then the seller may not charge market-based rates in the geographic area(s) where 

market power is found, and the seller is subject to cost-based default rates or other costbased rates that the seller proposes and the Commission approves. The Commission’s 

default rates are as follows: (1) sales of power of one week or less must 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 must 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 must be priced at a rate not to exceed the embedded 

cost of service, and the contract must be filed with the Commission for review. Mitigated 

 26 Proposals for alternative mitigation in these circumstances could include costbased rates or other mitigation that the Commission may deem appropriate. For example, 

an applicant could propose to transfer operational control of enough generation to a third 

party such that the applicant would satisfy our generation market power concerns. 
Docket No. RM04-7-000 - 17 - 

sellers must first receive Commission approval for each long-term power sale prior to 

transacting.27

b. Additional Requirement for Transmission Owners

23. In addition, 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., 110 FERC 

¶ 61,127 (2005). 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 transmission-providing 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 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 

 27 The Commission notes here that, to the extent a party believes market power is 

being exerted in the course of negotiating a long-term purchase, such party may file a 

complaint pursuant to section 206 of the FPA. 
Docket No. RM04-7-000 - 18 - 

assumptions used historically by the transmission provider in approximating its control 

area import capability. 

24. A seller may provide a streamlined application to show that it passes the indicative 

screens. Thus, with respect to simultaneous import capability, if a seller can show that it 

passes the screens for each relevant geographic market without considering imports, no 

such simultaneous import analysis needs to be provided. Further, the Commission 

recognizes that certain sellers will not have the ability to perform a simultaneous import 

capability study. Accordingly, if a seller demonstrates that it is unable to perform a 

simultaneous import capability study for the control area in which it is located, the seller 

may propose to use a proxy amount for transmission limits. Such proposals are 

considered on a case-by-case basis. 

c. Relevant Geographic Markets

25. The default relevant geographic markets under both screens are first, the control 

area market where the seller is physically located, and second, the markets directly 

interconnected to the seller’s control area market (first-tier control area markets).28 In 

this default analysis, the Commission considers only those supplies that are located in the 

market being considered (relevant market) and those in first-tier markets to the relevant 

 28 For applications by sellers with no physical generation assets (such as power 

marketers) and that are affiliated with generation asset owning utilities, the Commission 

evaluates the affiliate generation owner’s market power when evaluating whether to grant 

market-based rate authority for the power marketer. 
Docket No. RM04-7-000 - 19 - 

market. Sellers located in and a member of regional transmission organizations 

(RTO)/independent system operators (ISO)29 that perform functions such as single 

central commitment and dispatch with a single energy market and Commission-approved 

market monitoring and mitigation may consider the geographic region under the control 

of the RTO/ISO as the default relevant geographic market for purposes of completing 

their analyses.30 Currently, these markets are operated by PJM Interconnection, LLC 

(PJM), ISO New England, Inc. (ISO-NE), New York Independent System Operator, Inc. 

(NYISO), Midwest Independent Transmission System Operator (Midwest ISO) and 

California Independent System Operator Corporation (CAISO). For sellers whose assets 

are physically located geographically within the RTO/ISO boundaries, there is only one 

default relevant market for those assets, and that is the RTO/ISO in which they are 

located and are a member. Likewise, where a generator is interconnecting to a nonaffiliate owned transmission system, there is only one relevant market, the control area in 

which the generator is located. 

 29 We note that the membership status described is such that the seller that owns 

transmission facilities other than limited equipment necessary to connect individual 

generating facilities to the transmission grid has turned over operational control of those 

transmission assets to the RTO/ISO. 

30 LG&E Energy Marketing, Inc., 111 FERC ¶ 61,153 (2005) (noting that where 

applicants are members of the Midwest ISO and their control area is within the Midwest 

ISO geographic footprint, the default relevant geographic market for the generation 

market power analyses is the Midwest ISO). 
Docket No. RM04-7-000 - 20 - 

26. The Commission allows 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. For example, sellers or 

intervenors can present evidence that the relevant market is broader (or more limited) 

than a particular control area. However, applicants presenting evidence that the relevant 

market is larger or smaller than the default relevant market must first complete the 

screens based on the default market as discussed above. To the extent some other 

geographic market is studied, the proponent of using that alternative market must adhere 

to including all monitored lines/constraints and critical contingencies that were 

historically applied during the seasonal peaks in assessing available transmission for nonaffiliate transmission customers (i.e., consistent with Open Access Same-Time 

Information System (OASIS)). Sellers and intervenors may also provide evidence that, 

because of internal transmission limitations (e.g., load pockets), the relevant market is 

smaller than the control area. 

d. Performance of the Indicative Screens

27. Both the pivotal supplier analysis and the market share analysis recognize utilities’ 

obligations to serve native load. Because utilities generally use the same generating units 

to make off-system wholesale sales and to serve native load, and because the amount of 

generation needed to serve native load can vary from hour to hour, some reasonable 

proxy is needed to represent the amount of generation that is needed to serve native load. 

Accordingly, the pivotal supplier analysis, for both sellers and competing suppliers, uses 
Docket No. RM04-7-000 - 21 - 

the average of the daily native load peaks during the month in which the annual peak 

demand day occurs as a proxy for native load obligation. The market share analysis for 

both sellers and competing suppliers uses the native load obligation on the minimum 

peak demand day for a given season. 

28. In the pivotal supplier screen, a market participant’s uncommitted capacity is 

determined by adding the total nameplate capacity of generation owned or controlled 

through contract and firm purchases, less operating reserves, native load commitments 

and long-term firm sales. To calculate the net uncommitted supply available to compete 

at wholesale, the wholesale load proxy (annual peak load less the native load proxy 

discussed above) is deducted from total uncommitted capacity in the market.31 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. 

29. In the market share analysis, uncommitted capacity is defined similarly to the 

pivotal supplier screen, with the additional deduction for planned outages that were done 

in accordance with good utility practice. Under the market share analysis, a seller that 

has less than a 20 percent market share in the relevant market for all seasons is 

 31 April 14 Order, 107 FERC ¶ 61,018 at P 99. 
Docket No. RM04-7-000 - 22 - 

considered to satisfy the market share analysis.32 A seller with a market share of 20 

percent or more in the relevant market for any season has a rebuttable presumption of 

market power but can present historical evidence to show that the seller satisfies the 

Commission’s generation market power concerns.33 

30. In addition, any seller, regardless of size, has the option of making simplifying 

assumptions in its analysis where appropriate. In performing all screens, sellers are 

required to prepare them as designed,34 and must use the most recently available 

unadjusted 12 months’ historical data as a snapshot in time.35 Sellers filing abbreviated 

studies may request waiver of the full data requirements. 

 32 The 20 percent threshold is consistent with section 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.” 

33 The other evidence the Commission will consider is historical sales and/or 

access to transmission to move supplies within, out of, and into a control area market. 

34 Sellers presenting evidence that the relevant market is larger or smaller than the 

default relevant market (i.e., control area) must first complete the screens based on the 

default relevant geographic market. 

35 The Commission clarified on rehearing that it will allow adjustments necessary 

to perform the screens if the seller fully justifies the need for and methodology used for 

the adjustment and files all workpapers supporting the adjustments and documenting the 

source data used. July 8 Order, 108 FERC ¶ 61,026 at P 119. 
Docket No. RM04-7-000 - 23 - 

e. The Delivered Price Test (DPT) 

31. 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 Commission’s DPT.36 The DPT is used to 

analyze the effect on competition for transfers of jurisdictional facilities in section 203 

proceedings,37 using the framework described in Appendix A of the Merger Policy 

Statement as revised in Order No. 642.38 The DPT is an established test that has been 

used routinely to analyze market power in the merger context for many years, and it has 

been affirmed by the courts.39

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

market prices, input costs, and transmission availability, and calculates each supplier’s 

 36 April 14 Order, 107 FERC ¶ 61,018 at P 105-12. 

37 16 U.S.C. 824b (2000). 

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

Act: Policy Statement, Order No. 592, 61 F. R. 68595 (1996), FERC Stats. & Regs., 

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

denied, Order No. 592-A, 62 F. R. 33341 (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 F. R. 70984 (2000), FERC Stats. & Regs., 

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

No. 642-A, 66 F. R. 16121 (2001), 94 FERC ¶ 61,289 (2001). 

39 See, e.g., Wabash Valley Power Associates, Inc. v. FERC, 268 F. 3d 1105 (D.C. 

Cir. 2001).
Docket No. RM04-7-000 - 24 - 

economic capacity and available economic capacity for each season/load period.40 The 

results of the DPT are used for pivotal supplier, market share and market concentration 

analyses. Using the economic capacity for each supplier, sellers are required to provide 

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

measures with the more robust output from the DPT allows sellers to present a more 

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

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

season/load periods, sellers are required to compare the load in the relevant market to the 

amount of competing supply. 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 for the relevant period. The analysis using available economic capacity to 

account for sellers’ and competing suppliers’ native load commitments is also required. 

34. Each supplier’s market share is calculated based on economic capacity, the DPT’s 

analog to installed capacity. The market shares for each season/load period reflect the 

costs of the seller’s and competing suppliers’ generation, thus giving a more complete 

picture of the seller’s ability to exercise market power in a given market. 

 40 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 - 25 - 

35. Sellers preparing a DPT also must calculate the market concentration using the 

Hirschman-Herfindahl Index (HHI) based on market shares.41 For the DPT, a showing of 

an HHI less than 2,500 in the relevant market for all season/load periods for sellers that 

have also shown that they are not pivotal and do not possess more than a 20 percent 

market share in any of the season/load periods would constitute a showing of a lack of 

market power, absent compelling contrary evidence. We will, however, consider all 

relevant facts and circumstances in reviewing a DPT, (including native load obligations), 

and we will balance the record evidence in determining whether or not the seller has 

generation market power. Thus, even sellers that exceed the foregoing thresholds may 

receive market-based rates under appropriate circumstances.42 

36. Sellers and intervenors may present evidence such as historical wholesale sales 

data, which can be used to calculate market shares and market concentration and to refute 

or support the results of the DPT. The Commission encourages sellers to present the 

most complete analysis of competitive conditions in the market as the data allow. In this 

regard, the Commission allows the introduction of such evidence beyond the most recent 

12 months. The use of unadjusted historical sales and transmission data will provide an 

 41 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. 

42 See, e.g., Kansas City Power & Light Co., 113 FERC ¶ 61,074 at P 30-35 

(2005) (Kansas City); Acadia Power Partners, LLC, 113 FERC ¶ 61,073 at P 40-45 

(2005) (Acadia). 
Docket No. RM04-7-000 - 26 - 

accurate depiction of actual market activity. Therefore, the Commission requires sellers 

submitting historical sales and transmission data as evidence to submit the actual data. 

37. The FPA requires that all rates charged by public utilities for the transmission or 

sale for resale of electric energy be just and reasonable.43 Thus, where a market-based 

rate seller is found to have market power in generation (e.g., after reviewing a seller’s 

DPT), it is incumbent upon the Commission to either reject such rates or to ensure that 

adequate mitigation measures are in place to ensure that the rates are just and reasonable. 

The Commission provides default cost-based rates to ensure that wholesale rates are just 

and reasonable. If a seller does not pass the generation market power screens, or 

foregoes the screens entirely, the Commission sets the just and reasonable rate at the 

default cost-based rate unless it approves different mitigation based on case-specific 

circumstances. 

38. For sellers that have a presumption of market power in generation (e.g. those 

failing one or both of the indicative screens), the Commission will institute a section 206 

proceeding and the seller’s rates will prospectively be made subject to refund.44 For 

sellers already charging market-based rates, market-based rates will not be revoked and 

 43 16 U.S.C. 824d(a) (2000). 

44 The refund floor would be the default cost-based rates or, if applicable, any 

case-specific cost-based rates proposed by the seller and accepted by the Commission. 

Accordingly, the seller has certainty as to its potential refund obligation, if any. April 14 

Order, 107 FERC ¶ 61,018 at n. 143. 
Docket No. RM04-7-000 - 27 - 

cost-based rates will not be imposed until the Commission issues an order making a 

definitive finding that the seller has market power in generation (typically, after the 

Commission has ruled on a DPT analysis) or, where the seller accepts a presumption of 

market power, an order is issued addressing whether default cost-based rates or casespecific cost-based rates are to be applied. The Commission will revoke the marketbased rate authority in all geographic markets where a seller is found to have market 

power in generation.45 

2. Proposal

39. The Commission adopted the indicative generation market power screens in the 

April 14 Order for interim purposes, and instituted the instant rulemaking proceeding to, 

among other things, review these screens and, as a whole, the horizontal market power 

portion of the Commission’s four-prong analysis. The Commission has gained 

considerable experience with the analysis since the April 14 Order and believes that in 

general the current screens work well to identify the subset of sellers that require 

additional review. Therefore, we propose to continue to use the screens adopted in the 

April 14 Order as well as the overall approach to analyzing generation market power set 

forth in the April 14 Order, including the procedural options available to sellers and the 

use of the DPT. However, commenters have raised some valid concerns and, 

 45 The seller has the option of withdrawing its market-based rate request in whole 

or in part. 
Docket No. RM04-7-000 - 28 - 

accordingly, the Commission proposes certain modifications to the screens as adopted in 

the April 14 Order, such as adjustments to the native load proxy. Furthermore, while 

reaffirming the screens, we propose that henceforth these screens should be referred to as 

our horizontal market power analysis. In particular, our horizontal analysis will include, 

as discussed in the April 14 Order, the two indicative screens and the DPT as necessary. 

a. Indicative Screens and DPT Criteria

40. Because the indicative screens are intended only to identify the sellers that require 

further review, we propose to retain the 20 percent threshold for the wholesale market 

share screen. The screens are indicative, not definitive. Indeed, pursuant to the 

horizontal market power analysis where an applicant is seeking to obtain or retain 

market-based rate authority, 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. 

Instead, where a seller fails one of the indicative screens, a section 206 proceeding is 

instituted to more closely examine a seller’s potential for exercising horizontal market 

power and does not mean a definitive finding has been made. Failure to pass either of the 

indicative screens creates a rebuttable presumption of market power. A seller that fails 

the initial screens is given 60 days from the date of issuance of an order finding a screen 

failure to: (1) file a DPT analysis; (2) file a mitigation proposal tailored to its particular 

circumstances that would eliminate the ability to exercise market power; or (3) inform the 
Docket No. RM04-7-000 - 29 - 

Commission that it will adopt the default cost-based rates or propose other cost-based 

rates and submit cost support for such rates.46

41. Some commenters argue that the 20 percent threshold is too low; others argue that 

it is too high. The Commission believes that the 20 percent threshold strikes the right 

balance in seeking to avoid both “false negatives” and “false positives” and proposes to 

continue using 20 percent. Because the presumption of horizontal market power 

established by the failure of the wholesale market share screen is rebuttable, coupled with 

the adjustment to the native load proxy discussed below, sellers should be assured that 

the 20 percent threshold is not unnecessarily stringent. 

42. We also propose 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. 

The pivotal supplier analysis examines the seller’s market power during the annual peak. 

The hours near that point in time are the most likely times that a seller will be a pivotal 

supplier. 

43. Similarly, for the DPT analysis, we propose to retain our current threshold 

including 2,500 for HHIs, as well as our current practice of weighing all the relevant 

factors in the analysis, in determining whether a seller does or does not have horizontal 

market power. We propose to continue to do so on a case-by-case basis, weighing such 

factors as available economic capacity, economic capacity, HHIs, and other historical 

 46 April 14 Order, 107 FERC ¶ 61,018 at P 208. 
Docket No. RM04-7-000 - 30 - 

wholesale sales data. The thresholds are well-established and appropriate, allowing the 

Commission to make a reasoned determination after reviewing all the evidence in the 

record. The DPT does not function like the initial screens in that the failure of either the 

economic capacity or available economic capacity analyses does not result in an 

automatic failure as a whole.47 

b. Native Load 

44. To reduce the number of “false positives” in the wholesale market share screen, 

however, we propose to adjust the native load proxy. Many commenters have noted that 

the current native load proxy for the market share screen is too limited and results in too 

much uncommitted capacity attributable to the seller. The Commission stated in the 

April 14 Order that by using the two screens together, the Commission is able to measure 

market power both at peak and off-peak times, and the ability to exercise market power 

both unilaterally and in coordinated interaction with other sellers. In the April 14 Order, 

the Commission adopted the native load proxy for the wholesale market share screen in 

order to balance the concerns of market participants. We now believe that the current 

proxy used in the market share screen may be too conservative. Accordingly, the 

Commission proposes to change the allowance for the native load deduction under the 

market share 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 

 47 Kansas City, 113 FERC ¶ 61,074 at P 30; Acadia, 113 FERC ¶ 61,073 at P 40. 
Docket No. RM04-7-000 - 31 - 

the market share screen consistent with the deduction allowed under the pivotal supplier 

screen. We propose to retain a season-by-season analysis. For example, the proxy for 

summer would be the average native load peak for June, July and August. The pivotal 

supplier screen’s native load proxy would remain unchanged from its current proxy of the 

average of the daily native load peaks during the month in which the annual peak day 

load occurs. We seek comments on our proposal. 

45. We believe there has been some inconsistency in the way in which sellers have 

reflected native load in performing both the screens and the DPT analysis. For this 

reason, we also propose to clarify that for the horizontal market power analysis, native 

load can only include load attributable to native load customers as defined in section 

33.3(d)(4)(i) of the Commission’s regulations,48 as it may be revised from time to time. 

We seek comments on this proposal. 

c. Control and Commitment of Generation 

46. The Commission stated 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 

 48 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 - 32 - 

capacity to the buyer.49 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 tied to a specific generating unit and do 

not convey operational control of the generation.50 

47. The Commission has stated that contracts can confer the same rights of control of 

generation or transmission facilities as ownership of those facilities.51 In short, 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 

 49 July 8 Order, 108 FERC ¶ 61,026 at P 65. 

50 Id. at P 66. 

51 Citizens Power and Light Corp., 48 FERC ¶ 61,210 at 61,777 (1989) (Citizens 

Power). 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 Plasma Power, L.L.C., 

102 FERC ¶ 61,265 at P 33-36 (2003) (D.E. Shaw) (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 Plant Management, Ltd., 109 FERC ¶ 61,315 

at P 15 (2004) (R.W. Beck) (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). 
Docket No. RM04-7-000 - 33 - 

performing the generation market power screens.52 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.53 

48. In recent years, some owners have turned to third parties to manage the day-to-day 

activities of running and dispatching plants and/or selling output. Such third-party 

contractors, often referred to as energy managers and/or asset managers, can be 

responsible for multiple facilities through multiple energy management agreements. 

These management agreements may, directly or indirectly, transfer control of the 

capacity. The Commission is concerned that there may be instances where, in effect, 

control of capacity has changed hands, but this capacity has not been attributed to the 

correct seller for purposes of calculating our market screens. 

49. 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.54 Likewise, in providing guidance regarding events 

 52 July 8 Order, 108 FERC ¶ 61,026 at P 65. 

53 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 January 2001-December 2005 ¶ 31,175 at P 47, order on 

reh’g, Order No. 652-A, 111 FERC ¶ 61,413 (2005). 

54 D.E. Shaw, 102 FERC ¶ 61,265 at P 33-36; R.W. Beck, 109 FERC ¶ 61,315 at P 

15. 
Docket No. RM04-7-000 - 34 - 

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.55 Although 

this analysis is inherently fact-dependent to some degree, the Commission is interested in 

providing greater certainty and clarity in this area, which should increase the uniformity 

in reporting capacity and reduce the possibility of tariff violations. The Commission 

therefore seeks comment on whether it should make certain generic findings, or create 

certain generic presumptions, regarding the indicia of control. Specifically, the 

Commission seeks comment on whether any of the following functions should merit a 

finding or presumption of control and, if so, on what basis: directing outages, fuel 

procurement, plant operations, energy and capacity sales, and/or credit and liquidity 

decisions. Alternatively, rather than focusing on these discrete items, should the 

Commission establish a presumption of control for any entity that has some discretion 

over the output of the plant(s) that it manages? Would such an approach promote greater 

certainty and better align the test with the ultimate goal of attributing plant capacity to 

those who control its output? If the Commission adopted such a presumption, how 

should it address instances where discretion over plant output may be shared between 

more than one party? We also propose to clarify that, in the event we adopt any such 

 55 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 47. 
Docket No. RM04-7-000 - 35 - 

presumptions, the Commission would nonetheless allow individual sellers to rebut the 

presumption on the basis of their particular facts and circumstances. 

50. The Commission also proposes to clarify that an entity (such as an asset manager 

or other such 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 (e.g., the entity must provide a horizontal and 

vertical market power analysis and include in its horizontal analysis all assets it owns or 

controls in the relevant market). If such an entity controls an asset from which 

jurisdictional power sales are being made and such entity does not have a rate on file, it is 

violating section 205 of the FPA.56 We wish to emphasize, however, that our intent is not 

to limit or stifle the provision of energy management services. These services can 

provide benefits to customers and the marketplace. Rather, our intent is to provide 

greater certainty and clarity as to when such arrangements confer control so that the 

capacity being controlled is properly reported and the entity assuming such control has 

received the necessary authorizations under the FPA for providing jurisdictional services. 

d. Relevant Geographic Market

51. The Commission proposes to continue to use its current approach with regard to 

the relevant geographic market. The default relevant geographic market is the control 

 56 18 U.S.C. § 824d (c) (2000). 
Docket No. RM04-7-000 - 36 - 

area where the seller is physically located and 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 proposes to continue to 

designate the RTO/ISO in which a seller is located and is a member as the default 

relevant geographic market for RTO/ISOs with sufficient market structure and a single 

energy market, and not require sellers to consider, as part of the relevant market, markets 

first-tier to the RTO/ISO in which the seller is located and is a member.57 We believe 

that designating a default relevant geographic market provides sellers and intervenors a 

measure of certainty regarding the relevant market. We note that the default market 

seems to be acceptable to most sellers as there have been relatively few sellers who have 

proposed to expand or contract the default relevant geographic market. 

52. We note that the North American Electric Reliability Council (NERC) no longer 

uses the designation of control area since it approved the “NERC Reliability Functional 

Model” on February 10, 2004. We seek 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 if so, in what way should it be specified and how readily 

available is the relevant data. 

 57 April 14 Order, 107 FERC ¶ 61,018 at P 187. 
Docket No. RM04-7-000 - 37 - 

53. The Commission proposes to continue to provide flexibility by allowing sellers 

and intervenors to present evidence that the market is smaller or larger than the default 

market. To that end, we propose to provide guidance regarding the demonstration that a 

relevant geographic market is larger than a default geographic market by identifying the 

types of factors the Commission will consider in evaluating whether to adopt an 

expanded geographic market in a particular case instead of relying on the default 

geographic market (generally, the control area). 

54. Reaching beyond the default market in which an entity is located can mean 

addressing additional physical and other challenges than when trading within that market. 

When assessing an expanded geographic market pursuant to the horizontal analysis, the 

Commission 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. Any proposal to use an expanded 

market (i.e., a market other than the default geographic 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. In this regard, we propose to require that a demonstration be made 

based on historical data. In addition, we would require that a sensitivity analysis be 

performed analyzing under what circumstance(s) transmission constraints would bind. 
Docket No. RM04-7-000 - 38 - 

55. The Commission also considers whether there is other evidence that would 

support the existence of an expanded market. In deciding whether customers may be 

considered as part of an expanded geographic market, the Commission will also consider 

evidence that they can access the resources outside of the default geographic market on 

similar terms and conditions as those inside the default geographic market. 

56. Such evidence submitted to show that the applicant’s customers have access to 

resources outside of their control area at terms and conditions similar to those at which 

they can access resources inside the control 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 control 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 control areas; 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. 

57. In determining whether two or more control areas are a single market the 

Commission would weigh, on a case-by-case basis, all the factors presented. As 
Docket No. RM04-7-000 - 39 - 

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 factors will be considered and as a 

whole will indicate whether there exists a single market. 

58. We seek comment on our proposed guidance and, in particular, whether there are 

other factors the Commission should consider when assessing a proposed expanded 

market. Are there any factor(s) that should be given more weight or are essential in 

determining the scope of the market (e.g., are there any factors that, if not satisfactorily 

addressed, would preclude the need to consider any other factors)? Should the 

Commission apply the same criteria when determining whether the geographic market is 

smaller than the default geographic market? 

59. In addition, as discussed previously, the Commission proposes to designate the 

RTO/ISO in which the seller is located and is a member as the default relevant 

geographic market for RTO/ISOs with sufficient market structure and a single energy 

market. We believe the added protections provided in structured markets with market 

monitoring, market power mitigation and transparency generally result in a market where 

attempts to exercise market power would be sufficiently mitigated. 

60. In the April 14 Order, the Commission identified PJM, ISO-NE, NYISO, and 

CAISO as meeting the criteria for being considered a single market for purposes of 
Docket No. RM04-7-000 - 40 - 

performing the generation market power screens.58 The Commission also stated that, 

applicants can incorporate the mitigation they are subject to in ISO/RTO markets as part 

of their market power analysis. For example, if a market power study showed that an 

applicant had local market power, the applicant could point to RTO mitigation rules as 

evidence that this market power has been adequately mitigated. In a later order, 59 the 

Commission found that the Midwest ISO also met the criteria for being considered a 

single market for purposes of performing the generation market power screens. 

61. However, our experience with corporate mergers and acquisitions indicates that 

these same RTOs 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.60 Therefore, the Commission seeks 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 geographic market for the horizontal market power 

analysis. In particular, should the Commission continue its approach of considering the 

entire geographic region as the default relevant market? Should the Commission 

 58 Id. at 187. 

59 Alliant Energy Corporate Services, Inc., 109 FERC ¶ 61,289 at P 31 (2004). 

60 Examples of these submarkets include ISO-NE’s Southwest Connecticut, 

NYISO’s East of Central East (Zones F through K), PJM-East (roughly New Jersey, 

Southeastern Pennsylvania and the Delmarva Peninsula), Midwest ISO excluding 

Wisconsin-Upper Michigan (WUMS), and CAISO’s SP15. 
Docket No. RM04-7-000 - 41 - 

consider the entire geographic region for purposes of the indicative screens but consider 

RTO/ISO submarkets for purposes of the DPT. In addition, should the Commission 

adopt general criteria to define submarkets? If so, what criteria should the Commission 

adopt? 

62. Lastly, if the Commission determines that an RTO/ISO submarket is the 

appropriate default geographic region in a particular case and an applicant is found to 

have market power within that submarket, should the Commission consider mitigation in 

addition to existing RTO market monitoring and mitigation? 

e. Use of Historical Data 

63. We propose to retain the “snapshot in time” approach for the screens, i.e., sellers 

must use the most recently available unadjusted 12 months’ historical data.61 Historical 

data are more objective, readily available, and less subject to manipulation than future 

projections; therefore, the Commission will continue to preclude adjustments to historical 

data with regard to the indicative screens, with the following exception. We propose to 

continue to permit sellers to make adjustments to data that are necessary to perform the 

screens provided that the applicant fully justifies the need for the adjustments, justifies 

the methodology used, provides all workpapers in support, and documents the source 

data. For example, an adjustment could be allowed where needed data is available only 

 61 In accordance with the proposed filing schedule discussed below, data for the 

indicative screens must track the calendar year previous to the year designated for filing. 
Docket No. RM04-7-000 - 42 - 

for a region that is not identical to the seller’s control area in order to put it in a form that 

can be used in the analysis as designed.62

64. However, we propose in the DPT analysis to allow applicants and intervenors to 

account for changes in the market that are known and measurable at the time of filing.63 

This proposal mirrors the Commission’s approach in connection with its merger analysis. 

In Order No. 642, we stated that we intend to consider current and reasonably foreseeable 

regional developments as part of our merger analysis. In the Merger Policy Statement, 

we adopted the U.S. Department of Justice / Federal Trade Commission Horizontal 

Merger Guidelines64 as the analytical framework for analyzing the effect on competition. 

Those guidelines “address the issue of changing market conditions by stating that ‘[t]he 

Agency will consider reasonably predictable effects of recent or ongoing changes in 

market conditions in interpreting market concentration and market share data.’”65 

Examples of known and measurable changes in the market that would be allowed include 

new long-term contracts, expiration of long-term contracts, planned and imminent plant 

deactivations/retirements, and planned and imminent plant additions, regardless of 

 62 July 8 Order, 108 FERC ¶ 61,026 at P 119. 

63 See 18 CFR § 35.13(a) (2005). 

64 U.S. Department of Justice and Federal Trade Commission, Horizontal Merger 

Guidelines (1997) (DOJ/FTC Guidelines). 

65 Oklahoma Gas and Electric Company and NRG McClain LLC, 105 FERC 

¶ 61,297 (2003) (OG&E), citing the DOJ/FTC Guidelines, § 1.521. 
Docket No. RM04-7-000 - 43 - 

ownership. Sellers who elect to adjust historical data to reflect known and measurable 

changes would be required to perform the analysis using the most recent historical data 

and then provide a sensitivity analysis including adjustments for all known and 

measurable changes in the market and not just those advantageous to the seller.66 

Applicants and intervenors proposing known and measurable changes to be considered in 

the DPT analysis will bear the burden of proof for their adjustments to historical data. 

We seek comments 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, we seek comments on exactly what types of changes should be allowed and 

under what circumstances.67

f. Reporting Format

65. As suggested by a commenter, we propose to require all sellers to submit the 

results of their indicative screen analysis in a uniform format to the maximum extent 

 66 See Western Resources, Inc., 65 FERC ¶ 61,106 (1993).

67 For example, in OG&E, the Commission accepted one change as known and 

measurable and rejected another. Specifically, the Commission found that the expiration 

of a long-term power sales contract within a year was a known and measurable change 

and should be part of the base case analysis (105 FERC ¶ 61,297 at P 33). In the same 

order, the Commission found that an upgrade of a transmission facility that was identified 

by the Southwest Power Pool as a persistent limiting facility, but was not under 

construction or even in the planning stage, was not “a foreseeable and reasonably certain 

change in the market” and therefore should not be part of the base case analysis (id. at P 

32). 
Docket No. RM04-7-000 - 44 - 

practicable. This format will promote consistency and will aid the Commission in the 

decision-making process. Sellers must cross reference the inputs with the data and 

workpapers they otherwise submit including those in accordance with Appendix G of the 

April 14 Order. Use of a uniform format for reporting results is not intended to limit 

other workpapers the seller may wish to submit. The format we propose to adopt can be 

found in Appendix C. We seek comments on this proposal. 

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

Commission’s Regulations)

66. Section 35.27(a) of the Commission’s regulations 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.[68] 

67. The Commission clarified in the April 14 Order that some sellers with capacity 

built after July 9, 1996 (section 35.27(a) exemption) may avoid submitting a horizontal 

market power analysis if they meet the requirements of section 35.27(a) of the 

Commission’s regulations. The Commission stated that, as it indicated in Order No. 888, 

it will consider whether a seller citing section 35.27(a) nevertheless possesses horizontal 

market power if specific evidence is presented by an intervenor, and a seller still must 

study whether its new capacity, when added to existing capacity, raises horizontal market 

 68 18 CFR 35.27(a) (2005). 
Docket No. RM04-7-000 - 45 - 

power concerns.69 As the Commission stated in Order No. 888, the evaluation of marketbased rates for existing capacity will include consideration of new capacity.70 

68. 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 applicant is not required to provide a horizontal market power 

analysis because of the exemption under section 35.27(a).71

69. Although we remain committed to encouraging new entry of generation, we are 

concerned that the continued use of the section 35.27(a) exemption may become too 

broad. Over time, this exemption would encompass all market participants as all 

pre-July 9, 1996 generation is retired. For this reason, some commenters suggest that the 

Commission should eliminate the exemption altogether.72

70. We agree with these commenters that our current practice will have unintended 

adverse consequences over time and therefore should be reformed. Accordingly, we 

propose to eliminate the express exemption provided in section 35.27(a), but to do so in a 

manner that will not act as a disincentive for the construction of new generation. As 

 69 April 14 Order, 107 FERC ¶ 61,018 at P 115, 116. 

70 Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,657. 

71 April 14 Order, 107 FERC ¶ 61,018 at P 38. 

72 American Public Power Association (APPA) Comments (March 15, 2005) at P 

35. 
Docket No. RM04-7-000 - 46 - 

explained further below, this change will not affect many sellers, given that they already 

are required to include all new capacity when submitting a market analysis for their pre1996 generation. Further, our proposal will assure that all generation is treated on an 

equal footing, such that market participants with similar market shares in the same 

geographic market are not treated differently based solely on the vintage of their assets. 

71. Under this proposal, the 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 and their affiliates’ generation was built 

after July 9, 1996, must provide a horizontal market power analysis of their generation. 

Because the Commission allows an applicant to make simplifying assumptions, where 

appropriate, and therefore to submit a streamlined analysis, the Commission believes that 

any additional burden imposed by the proposed elimination of the section 35.27(a) 

exemption will be minimal.73

 73 April 14 Order, 107 FERC ¶ 61,018 at P 117. In the April 14 Order, the 

Commission explained that appropriate simplifying assumptions are those assumptions 

that do not affect the underlying methodology utilized by the generation market power 

screens. For example, if an applicant passes our generation market power screens by 

only considering the control area market’s host utility as a competitor, the Commission 

foresees no benefit from completing a study to include other competitors. Similarly, if an 

applicant would pass the screens without considering competing supplies from adjacent 

control areas, the applicant need not include such imports in its studies. With regard to a 

new generator, such an applicant may base its horizontal market power analysis on the 

most recently approved study for the control area in which it is located.
Docket No. RM04-7-000 - 47 - 

72. Further, with 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. 

However, as discussed above, because the Commission allows for a streamlined analysis, 

including simplifying assumptions, where appropriate, any additional burden imposed by 

the proposed elimination of the section 35.27(a) exemption will be minimal. In addition, 

the Commission anticipates that those entities that otherwise would have relied on the 

exemption will, in most cases, qualify as Category 1 sellers and thus no longer be 

required to file triennial reviews. 

73. By proposing to eliminate the express exemption set forth in section 35.27(a), we 

are not proposing to require sellers with market-based rate authority to submit a new 

horizontal market power analysis (i.e., perform the generation market power screens) 

each time that they add a new generating unit. Rather, a seller with market-based rate 

authority would be required to file a "change in status" report under Order No. 652

notifying the Commission of the acquisition of additional generation,74 the same 

requirement that exists today. Such sellers are not required to file a market power 

 74 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 68. The threshold of 

additional generation that triggers the reporting requirement is a net increase of 100 MW 

or more. See Order No. 652-A, 111 FERC ¶ 61,413 at P 24-25. 
Docket No. RM04-7-000 - 48 - 

analysis of their generation with their change in status filing, nor do we propose they 

should.75

74. Thus, our proposal to eliminate section 35.27(a) should not impose significant 

additional burdens on new generation or otherwise deter new entry. We seek comments 

on this proposal. 

h. Nameplate Capacity

75. Based on our experience, we propose to allow sellers the option of using seasonal 

capacity instead of nameplate capacity as currently required. The seller must be 

consistent in its choice and use one or the other measure of capacity ratings throughout 

the analysis. The use of seasonal capacity ratings we believe more accurately reflects the 

seasonal real power capability andis not inconsistent with industry standards, and 

therefore it may be more convenient for sellers to acquire and compile the associated 

data. In addition, we do not think the use of such ratings will materially impact results. 

We seek comment on this proposal, including comment as to whether this information is 

publicly available to all market participants. 

i. Transmission Imports

76. We propose to continue our use of limiting capacity that can be imported into a 

relevant market to the results of a simultaneous transmission import capability study, and 

 75 Further, in the event the seller acquires existing generation, it may also need to 

seek approval therefor consistent with the provisions of section 203 of the FPA as 

amended. 16 U.S.C. 824b (2000). Energy Policy Act of 2005 §§ 261 et seq., Pub. L. No. 

109-58, 199 Stat. 594 (2005) (EPAct 2005). 
Docket No. RM04-7-000 - 49 - 

to reaffirm several aspects of the requirements regarding how to properly construct a 

simultaneous transmission import capability study for use in the indicative screens and 

the DPT. 

77. The simultaneous transmission import capability study is intended to provide a 

reasonable simulation of historical conditions. In particular, the simultaneous 

transmission import capability study is not the theoretical maximum import capability or 

a best import case scenario. It is a benchmark of 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). The analysis should 

not deviate from OASIS practice during each historical seasonal peak. Appendix E of the 

April 14 Order states that the power flow cases should represent the transmission 

provider’s tariff provisions and all firm/network reservations held by seller/affiliate 

resources during the most recent seasonal peaks. We propose to reaffirm that “all” means 

both short- and long-term firm/network reservations. 

78. In addition to the power flow cases, as noted in Appendix E of the April 14 Order, 

the seller must supply supporting documentation, and this documentation should include 

the operational practices historically used, reliability margins, and all firm/network 

reservations held by the seller or its affiliates that are modeled in the cases. The 

simultaneous transmission import capability study must reasonably reflect the 

transmission provider’s OASIS practices and the techniques used must have been 
Docket No. RM04-7-000 - 50 - 

historically available to customers. We propose to continue to use the instructions set 

forth in the April 14 Order. 

79. Further, the April 14 Order required simultaneous transmission import capability 

studies to include firm point-to-point and network transmission reservations. 

Firm/network reservations should be subtracted from the simultaneous transmission 

import capability if they are not historically modeled in the power flow case. In all cases, 

sellers are required to provide documentation of the firm/network reservations. 

80. We expect control area operators with market-based rate authority to provide 

simultaneous transmission import capability studies in a timely manner, consistent with 

the methodology described in the April 14 Order, for their control area and directly 

interconnected first-tier control areas in response to requests by sellers seeking marketbased rate authority.76 This includes all the required data, documentation and workpapers 

to support the study. 

81. We also propose to reaffirm certain aspects of an approximation explained in 

Appendix E of the April 14 Order. The April 14 Order allows directly interconnected 

first-tier control areas (to the market being studied) to be considered when conducting the 

study. However, it does not allow control areas that are second-tier to the control area 

being studied to be considered. 

 76 July 8 Order, 108 FERC ¶ 61,026 at P 124. 
Docket No. RM04-7-000 - 51 - 

82. We propose to specify how the calculation of a seller’s pro rata share of 

simultaneous transmission import capability should be performed. When studying its 

first-tier control area, the seller should allocate imports (after taking into account firm 

reservations by attributing them to the holders of the reservations including those 

applicable to the seller) pro rata between the seller and its competitors based on 

uncommitted capacity. We seek comments on this proposal. 

j. Procedural Issues

83. The Commission notes that Order No. 66277 issued June 21, 2005, addressed 

concerns that CEII claims in market-based rate filings are overbroad. In response to 

commenters’ concerns that intervenors should have sufficient time to respond to marketbased rate filings for which CEII is claimed, 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. The Commission encouraged the parties in cases in which 

CEII is filed to promptly negotiate a protective order in the proceeding governing access 

to the CEII, or privately negotiate for the submitter to provide the data to interested 

parties pursuant to an appropriate non-disclosure agreement. The Commission seeks 

comments on whether CEII designations remain a concern since issuance of that rule. 

 77 Critical Energy Infrastructure Information, Order No. 662, 70 FR 37031 

(June 28, 2005), FERC Stats. & Regs. ¶ 31,189 (June 21, 2005). 
Docket No. RM04-7-000 - 52 - 

The Commission also seeks 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. If the Commission were to establish a longer 

period for submitting comments in these cases, what would be an appropriate comment 

period? 

B. Vertical Market Power

84. The Commission historically has considered transmission market power and other 

barriers to entry as two separate parts of the four-prong market-based rate analysis. 

However, as discussed below, the examination of a seller’s ability to engage in 

transmission market power and a seller’s ability to exclude competitors from the market 

by erecting other barriers to entry through the control of inputs to electric power 

production both involve the evaluation of potential vertical market power. On this basis, 

in this NOPR the Commission proposes to reformulate its market-based rate analysis to 

consider issues relating to transmission market power and other barriers to entry under 

the heading “vertical market power.” This proposal is intended primarily to alter the way 

in which we characterize these issues, rather than changing the fundamental nature of the 

analyses that we perform. 

1. Current Policy

a. Transmission

85. To the extent that a market-based rate seller, or any of its affiliates, owns, 

operates, or controls transmission facilities, the Commission has required the seller to 
Docket No. RM04-7-000 - 53 - 

have an OATT on file before granting market-based rate authorization. The OATT was 

implemented in 1996 when the Commission issued Order No. 888 to remedy undue 

discrimination or preference in access to the monopoly owned transmission grid. Having 

a Commission approved-OATT on file satisfies the Commission’s concerns with regard 

to transmission market power. In addressing our transmission market power concerns, a 

seller, including its affiliates, that does not own, operate or control transmission facilities 

should make an affirmative statement that neither it, nor any of its affiliates, owns, 

operates or controls any transmission facilities.78 

86. The Commission issued a Notice of Inquiry in Preventing Undue Discrimination 

and Preference in Transmission Services,

79 that seeks to explore whether, and if so, 

which, reforms are necessary to the Order No. 888 pro forma OATT and to the individual 

public utility OATTs, given the current state of the electric industry, the complaints of 

customers regarding remaining undue discrimination, and the apparent uncertainties and 

inconsistent application concerning various tariff provisions that have arisen since 

implementation of Order No. 888. The Commission is issuing a notice of proposed 

rulemaking in that proceeding concurrently with this NOPR. 

 78 See, e.g., Citizens Power, 48 FERC ¶ 61,210. 

79 See Preventing Undue Discrimination and Preference in Transmission Service, 

70 FR 55796 (Sept. 23,2005), FERC Stats. & Regs., Regulations Preambles January 

2001-December 2005 ¶ 35,553 (2005) (OATT Reform Rulemaking). 
Docket No. RM04-7-000 - 54 - 

b. Other Barriers to Entry

87. Although the principal barriers to entry can be raised through the ownership or 

control of transmission facilities, the Commission also evaluates barriers to entry other 

than transmission (other barriers to entry). In the early 1990s, the Commission 

considered whether a seller or its affiliates could erect other barriers to entry through 

ownership or control of sites for new capacity development, key inputs to generation, or 

the transportation of key inputs to generation.80 The Commission has also considered 

other barriers to entry, such as: control of major engineering and consulting firms,81

control of fuel supplies, ownership or control of equipment,82 and the control of 

transportation or distribution of fuel supplies in the relevant markets.83 

 80 See Doswell Limited Partnership, 50 FERC ¶ 61,251 at 61,758 (1990) 

(Doswell); Commonwealth Atlantic Limited Partnership, 51 FERC ¶ 61,368 at 62,244-45 

(1990) (Commonwealth Atlantic), cited in Entergy Services, Inc., 58 FERC ¶ 61,234 at 

n.85 (1992) (Entergy MBR I).

81 See Wallkill Generating Company, L.P. (Wallkill), 56 FERC ¶ 61,067 (1991). 

82 See Louisville Gas and Electric Company, 62 FERC ¶ 61,016 at 61,147 (1993) 

(LG&E); Entergy MBR I, 58 FERC at 61,759; Pacific Gas and Electric Company, 

53 FERC ¶ 61,145 at 61,505 (1990). 

83 In Enron Power Marketing, Inc., 65 FERC ¶ 61,305 at 62,405 (1993), order on 

clarification and reh’g, 66 FERC ¶ 61,244 (1994), the Commission determined that a 

power marketer may be affiliated with an interstate natural gas pipeline because, under 

the Commission's requirements, such pipelines must offer open-access services on a nondiscriminatory basis. See also Vantus Energy Corporation, 73 FERC ¶ 61,099 at 61,316 

(1995). In Idaho Power Company, 110 FERC ¶ 61,219 at 61,816 (2005), the 

Commission considered a utility’s ownership and control of rail cars to transport coal in 

its evaluation of the other barriers to entry prong and held that there are many other 

companies from which rail cars may be leased, and that the total number of cars that the 

(continued) 
Docket No. RM04-7-000 - 55 - 

88. In particular, the Commission considered such things as a power producer’s 

ownership of building sites and its affiliation with or ownership of interstate natural gas 

pipelines, engineering and construction firms, or local natural gas distribution systems. 

For example, in Wallkill, the Commission determined that affiliation with a major 

engineering and construction firm could not be used to erect barriers to entry because 

there were a large number of such firms operating on a national basis. Further, in LG&E, 

the Commission found that although LG&E did not own facilities used to transport 

natural gas, its affiliate owned gas lines and gas storage facilities. In light of this, the 

Commission stated that should LG&E or any of its affiliates deny, delay, or require 

unreasonable terms, conditions, or rates for gas services to a potential electric competitor, 

the electric competitor could file a complaint with the Commission. The Commission has 

made similar findings in subsequent cases where a seller or its affiliates own or control 

any natural gas intrastate facilities or distribution facilities, stating that should such seller 

or any of its affiliates deny, delay, or require unreasonable terms, conditions, or rates for 

fuel or services to a potential electric competitor in bulk power markets, then the 

competitor may file a complaint with the Commission that could result in the suspension 

of the seller’s authority to sell power at market-based rates. The Commission has stated 

it will treat such denials, delays, or requirement of unreasonable terms, conditions or rates 

 

utility could be considered to control (less than 200) was insignificant relative to the total 

number of such cars. 
Docket No. RM04-7-000 - 56 - 

for gas service in the same manner as complaints by an electric competitor that an entity 

has refused to transmit electricity.84

2. Proposal

89. As discussed above, the Commission proposes to replace its 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, we propose that issues relating to 

whether the seller and its affiliates lack 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. 

90. Regarding transmission issues, the current policy is that having a Commissionapproved OATT on file is sufficient to mitigate transmission market power. However, 

the Commission has also recognized that Order No. 888 did not eliminate all potential to 

engage in undue discrimination and preference in the provision of transmission service.85 

 84 LG&E, 62 FERC ¶ 61,016 at 61,148. 

85 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). 
Docket No. RM04-7-000 - 57 - 

For this and other reasons, the Commission has initiated a Notice of Inquiry to address 

potential reforms to the current OATT.86 We believe that any concerns regarding the 

adequacy of the OATT should be addressed in that proceeding. We therefore will 

propose to continue to find that a Commission-approved OATT, as modified as a result 

of the OATT Reform Rulemaking, will adequately mitigate transmission market power. 

91. Nevertheless, the finding that an OATT adequately mitigates transmission market 

power rests on the assumption that individual applicants 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 another remedy the Commission may deem appropriate, such as 

disgorgement of profits or civil penalties.87 There may be OATT violations in 

circumstances that, after applying the factors in the Enforcement Policy Statement, merit 

revocation or limitation of market-based rate authority. 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 specific facts relating to the OATT 

violation and the entity’s market-based rate authority. The Commission proposes that, if 

it determines, as a result of a significant OATT violation, that the market-based rate 

 86 See Preventing Undue Discrimination and Preference in Transmission Service, 

70 FR 55796 (Sept. 23, 2005), FERC Stats. & Regs., Proposed Regulations ¶ 35,553 

(2005) (OATT Reform Rulemaking). A notice of proposed rulemaking is being issued in 

that proceeding concurrently with this NOPR. 

87 See, e.g., The Washington Water Power Company, 83 FERC ¶ 61,282 (1998). 
Docket No. RM04-7-000 - 58 - 

authority of a transmission provider will be revoked within a particular market, each 

affiliate of the transmission provider that possesses market-based rate authority will have 

it revoked in that market on the effective date of revocation of the transmission provider’s 

market-based rate authority. We remind sellers that they must abide by the provisions of 

the OATT if they do not want an adverse impact on their ability to charge market-based 

rates. 

92. The Commission also proposes to continue considering a seller’s ability to erect 

other barriers to entry, but to do so as part of the vertical market power analysis. We 

propose that, in order for a seller to demonstrate that it satisfies our vertical market power 

concerns, with respect to other barriers to entry, it must demonstrate that it and its 

affiliates cannot erect other barriers to entry. In this regard, we propose 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 and distribution of inputs to electric 

power production; and control of sites for new capacity development in the relevant 

market. We also propose to require sellers to make an affirmative statement that they 

have not erected barriers to entry into the relevant market and that they cannot do so. 

93. In addition, the Commission proposes 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 seeks comments on this 

proposal. The Commission proposes that the analysis continue to include the 
Docket No. RM04-7-000 - 59 - 

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. The Commission also clarifies that applicants need not address interstate 

transportation of natural gas supplies because such transportation is regulated by this 

Commission.88 Our open access regulations adequately prevent sellers from withholding 

interstate pipeline capacity. Interstate pipelines are required to sell available capacity at 

the approved maximum rates. In addition, interstate pipeline capacity held by firm 

shippers that is not utilized or released is available from the pipeline on an interruptible 

basis. As to the commodity, Congress has found the natural gas market competitive.89

94. Several commenters have suggested that a transmission planning and expansion 

process can ameliorate vertical market power. The Commission is seeking comments on 

the issues of transmission planning and expansion in the notice of proposed rulemaking 

in the OATT Reform Rulemaking that is being issued concurrently with this NOPR. We 

 88 Pipeline Service Obligations and Revisions to Regulations Governing SelfImplementing 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). 

89 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). 
Docket No. RM04-7-000 - 60 - 

seek comment on whether these planning and expansion efforts under the OATT Reform 

Rulemaking will address commenters’ concerns here. 

95. The Commission seeks comment on whether 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. We also seek comment on 

whether the exercise of buyer’s market power by the transmission provider should be 

considered a potential barrier to entry and, if so, what criteria the Commission should use 

to evaluate evidence that is presented. 

C. Affiliate Abuse

96. The fourth prong of the Commission’s current market-based rate analysis 

examines whether there is evidence involving the seller or its affiliates that relates to 

affiliate abuse or reciprocal dealing.90 As the Commission has explained, “[t]he 

Commission’s concern with the potential for affiliate abuse is that a utility with a 

monopoly franchise may have an economic incentive to exercise market power through 

its affiliate dealings.”91 The Commission stated that potential abuses include such 

 90 See Commonwealth Atlantic Limited Partnership, 51 FERC ¶ 61,368 at 62,245 

(1990) (discussing potential for reciprocal dealing if a buyer agrees to pay more for 

power from a seller in return for that seller (or its affiliates) paying more for power from 

the buyer (or its affiliates)). 

91 Edgar, 55 FERC ¶ 61,382 at 62,167 n.56. See also TECO Power Services 

Corp. and Tampa Electric Co., 52 FERC ¶ 61,191 at 61,697 n.41 (1990) (“The 

Commission has determined that self-dealing may arise in transactions between affiliates 

(continued) 
Docket No. RM04-7-000 - 61 - 

practices as affiliates selling products to a utility with a franchised service territory 

(franchised public utility) at excessive prices, or a franchised public utility providing 

inputs to an affiliate at preferentially low prices. Both of these practices are examples of 

market power that is exercised to the disadvantage of captive customers. The 

Commission also has explained that there may be a potential for affiliate abuse through 

means such as the pricing of non-power goods and services or the sharing of market 

information. 

97. The Commission in the past has used two means to ensure that affiliate abuse does 

not occur: restrictions on sales between a franchised public utility and its affiliates, and 

requiring a code of conduct that governs the relationship between franchised public 

utilities and their affiliates. 

1. Power Sales Restrictions

a. Current Policy

98. The Commission currently prohibits power sales at market-based rates between a 

franchised public utility and its affiliates without first receiving authorization of the 

transaction under section 205 of the FPA.92 In order to be granted market-based rate 

authorization, a franchised public utility and all of its affiliates must include such a 

 

because affiliates have incentives to offer terms to one another which are more favorable 

than those available to other market participants.”). 

92 Aquila, Inc., 101 FERC ¶ 61,331 (2002). 
Docket No. RM04-7-000 - 62 - 

prohibition in their market-based rate tariffs unless the Commission has otherwise 

authorized the seller to transact with its affiliates. 

99. The Commission has stated its concern that a franchised public utility and an 

affiliate may be able to transact in ways that transfer benefits from the captive customers 

of the franchised public utility to the affiliate and its shareholders.93 Where a franchised 

public utility makes a power sale to an affiliate, the Commission is concerned that such a 

sale could be made at a rate that is too low, in effect, transferring the difference between 

the market price and the lower rate from captive customers to the “non-regulated” 

affiliated entity. Where an entity makes power sales to an affiliated franchised public 

utility, the concern is that such sales not be made at a rate that is too high, which would 

give an undue profit to the affiliated entity at the expense of the franchised public utility’s 

captive customers. The Commission has found that a transaction between two nontraditional utility affiliates (such as power marketers, EWGs, or QFs) does not raise the 

same concern about cross subsidization because neither has a franchised service territory 

and therefore has no captive customers. As the Commission has explained, no matter 

how sales are conducted between non-traditional affiliates, profits or losses ultimately 

affect only the shareholders.94

 93 See, e.g., Heartland Energy Services Inc., 68 FERC ¶ 61,223 at 62,062 (1994) 

(Heartland). 

94 FirstEnergy Generation Corporation, 94 FERC ¶ 61,177 (2001); USGen Power 

Services, L.P., 73 FERC ¶ 61,302 at 61,846 (1995). 
Docket No. RM04-7-000 - 63 - 

100. In determining whether to allow power sales affiliate transactions, the 

Commission, over time, has adopted several methods, all of which have focused on 

ensuring that captive customers are adequately protected against affiliate abuse. We 

discuss these below. 

101. In Edgar, the Commission described 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. 95 The Commission stated that when an entity presents evidence regarding a 

competitive solicitation, the Commission requires assurance that: (1) a competitive 

solicitation process was designed and implemented without undue preference for an 

affiliate; (2) the analysis of bids did not favor affiliates, particularly with respect to nonprice factors; and (3) the affiliate was selected based on some reasonable combination of 

price and non-price factors.96

 95 Edgar, 55 FERC ¶ 61,382 at 62,168-69. 

96 Id. at 62,168. A seller with market-based rate authority would not necessarily 

be required to make a separate affirmative showing of no market power in order to fulfill 

the Edgar standards and receive authority to engage in an affiliate transaction. 
Docket No. RM04-7-000 - 64 - 

102. In subsequent cases, the Commission expanded on the competitive solicitation 

prong of Edgar and has stated that it must evaluate the bidding process and determine 

that, based on the evidence, a proposed power sale between affiliates is the result of 

direct head-to-head competition.97 

103. The Commission has provided guidelines as to how the Commission will evaluate 

whether a competitive solicitation process satisfies the Edgar criteria. The underlying 

principle when evaluating a competitive solicitation process under the Edgar criteria is 

that no affiliate should receive undue preference during any stage of the process. 

104. In Allegheny, the Commission stated that the following four guidelines will help 

the Commission determine if a competitive solicitation process satisfies that underlying 

principle: it is transparent; products are well defined; bids are evaluated comparably with 

no advantage to affiliates; and it is designed and evaluated by an independent entity. 98

The Allegheny guidelines serve as one example of evidence that a competitive 

solicitation has resulted in just and reasonable rates; they do not constitute the only way 

 97 See, e.g., Rockland Electric Company, 102 FERC ¶ 61,097 (2003); Connecticut 

Light & Power Company and Western Massachusetts Electric Company, 90 FERC 

¶ 61,195 at 61,633-34 (2000); Aquila Energy Marketing Corp., 87 FERC ¶ 61,217 at 

61,857-58 (1999); MEP Pleasant Hill, LLC, 88 FERC ¶ 61,027 at 61,059-60 (1999); 

Edgar, 55 FERC ¶ 61,382 at 62,167-69. 

98 See, e.g., Allegheny Energy Supply Company, LLC, 108 FERC ¶ 61,082 (2004) 

(Allegheny); Rockland Electric Company, 102 FERC ¶ 61,097 (2003); Conectiv Energy 

Supply, Inc., 91 FERC ¶ 61,076 (2000). 
Docket No. RM04-7-000 - 65 - 

in which an applicant could demonstrate that a competitive solicitation was not unduly 

discriminatory. 

105. The Commission has granted blanket authorization to make power sales to 

affiliates pursuant to a market-based rate tariff subject to certain conditions. For this 

blanket authorization, the Commission has required that sales of power by a franchised 

public utility to an affiliate be made at a rate no lower than the rate charged to nonaffiliates; the utility offering to sell power to an affiliate must make the same offer, at the 

same time, to non-affiliated entities; and the utility must post simultaneously the actual 

price charged to its affiliate for all transactions.99 These provisions were originally 

included as part of Detroit Edison’s cost-based rate tariff in response to a request by 

Detroit Edison to sell power to its affiliated power marketer at negotiated rates subject to 

a cost-based price cap. However, the Commission’s practice has been to allow such a 

provision in other sellers’ market-based rate tariffs. Utilities that request this blanket 

authorization have been required to include those conditions in their market-based rate 

tariffs.100 

106. The Commission also has authorized sales when a “non-regulated” affiliate seeks 

to sell power to an affiliated franchised public utility where sufficient pricing safeguards 

 99 Detroit Edison Co., 80 FERC ¶ 61,348 at 62,198 (1997). 

100 See, e.g., Alliant Services Company, 85 FERC ¶ 61,344 at 62,335 (1998); 

Tucson Electric Power Company, 82 FERC ¶ 61,141 at 61,525 (1998). 
Docket No. RM04-7-000 - 66 - 

were in place to ensure that there was no room for manipulation.101 In Advanced 

Resources, the Commission found adequate a plan where the power marketer sold energy 

to its affiliated franchised public utility at the lowest price paid by the franchised public 

utility to a non-affiliate under certain standard supplier agreements. Specifically, the 

Commission granted authorization because the price in these standard supplier 

agreements was equal to the average price of power sold to the franchised public utility 

through the PJM power exchange. Because the price of the franchised public utility’s 

purchases from the power marketer was set equal to the price of the franchised public 

utility’s purchases from PJM, the Commission concluded there was no room for 

manipulation. 

107. The Commission also has allowed sales between affiliates pursuant to a marketbased rate tariff without imposing any price or transaction conditions where there were 

no captive wholesale or retail customers or where captive customers were adequately 

protected from affiliate abuse.102 In these cases, the Commission found that captive 

 101 See, e.g., GPU Advanced Resources, Inc., 81 FERC ¶ 61,335 (1997) 

(Advanced Resources); FirstEnergy Trading & Power Marketing, Inc., 84 FERC ¶ 61,214 

at 62,037-38, reh’g denied, 85 FERC ¶ 61, 311 (1998) (rejecting tariffs without prejudice 

to the applicants submitting alternative proposals that delineate the nature of the 

transactions to be undertaken and demonstrate that any proposed safeguards mitigate the 

potential for affiliate abuse). 

102 See, e.g., Consumers Energy Company, 94 FERC ¶ 61,180 (2001) (finding 

there are adequate safeguards including Consumer Energy disallowing revenues for sales 

to CMS Marketing to be factored into any rate calculations for wholesale customers, 

existence of retail rate freeze, and phase in of retail choice); FirstEnergy Corp., 94 FERC 

(continued) 
Docket No. RM04-7-000 - 67 - 

customers were protected through fixed rate contracts, retail rate freezes, retail access, 

and an inability for the captive ratepayer to be harmed through fuel adjustment clauses. 

The Commission also has found that tying the price of an affiliate transaction to an 

established, relevant market price or index mitigates affiliate abuse concerns.103 

b. Proposal 

108. We remain concerned about the potential adverse impact that affiliate power sales 

transactions may have on captive customers104 and propose to continue our policy of 

reviewing affiliate transactions under section 205 of the FPA. Although we have 

traditionally identified affiliate abuse as the fourth prong of our test for market-based rate 

 

¶ 61,182 at 61,630 (2001) (finding of adequate safeguards based on FirstEnergy’s 

commitment to hold wholesale customers harmless from changes in cost, a retail rate 

freeze in Ohio, and caps on retail rates in Pennsylvania); Exelon Generation Company, 

L.L.C., 93 FERC ¶ 61,140 at 61,425 (2000), reh'g denied, 95 FERC ¶ 61,309 (2001) 

(finding there are adequate safeguards including retail access, rate freezes, rate caps, and 

other mechanisms).

103 Brownsville Power I, L.L.C., 111 FERC ¶ 61,398 at P 10 (2005) (Brownsville); 

See also FirstEnergy Trading Servs., Inc., 88 FERC ¶ 61,067 at 61,156 (1999) 

(FirstEnergy Trading); Union Light, Heat, and Power Co., 110 FERC ¶ 61,212 at P16 

(2005) (affirming that use of Midwest ISO Day 2 market prices meets the Edgar test and 

mitigates concerns regarding transactions between affiliates); Idaho Power Company, 

95 FERC ¶ 61,147 (2001) (accepting use of the Dow Jones Mid-Columbia Index and the 

Dow Jones Palo Verde Index for affiliate sales); Pinnacle West Capital Corporation, 

91 FERC ¶ 61,290 (2000) (allowing use of the lesser of the Palo Verde Index and system 

incremental cost as a cap on the price for sales between affiliates); DPL Energy, Inc., 

90 FERC ¶ 61,200 (2000) (affirming that use of the "into Cinergy" index price as a price 

cap for its power sales to Dayton P&L mitigates affiliate abuse concerns); Ameren

Services Company, 86 FERC 61,212 (1999) (accepting use of “into Cinergy” for sales 

between affiliates).

104 See Edgar, 55 FERC ¶ 61,382 at 62,167. 
Docket No. RM04-7-000 - 68 - 

authority, in practice this prong is not only evaluated at the time an application is filed, 

but rather is satisified on an ongoing basis through the requirement that sellers obtain 

prior approval, under the foregoing standards, for affiliate power sales. To reflect and 

codify this practice, we propose to discontinue referring to affiliate abuse as a separate 

"prong" of our analysis and instead we propose to codify in our regulations at 18 C.F.R 

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 

provisions. 105 Thus, we will address 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. However, we note that a seller 

seeking to obtain or retain market-based rate authority will continue to be obligated to 

provide a detailed description of its corporate structure so that we can be assured that our 

standards are being applied correctly. In particular, applicants with franchised service 

territories will be required to make a showing regarding whether they serve customers 

 105 With regard to reciprocal dealing, we believe that any concerns as to a seller’s 

ability to engage in reciprocal dealing are addressed by the affiliate abuse provisions we 

propose to include in the Commission’s regulations as well as the Commission’s final 

rule prohibiting energy market manipulation. See Prohibition of Energy Market 

Manipulation, Order No. 670, 71 FR 4244 (January 26, 2006), FERC Stats. & Regs. 

¶ 31,202 (2006), order on reh’g, Order No. 670-A, 114 FERC ¶ 61,300 (2006). 
Docket No. RM04-7-000 - 69 - 

and to identify all non-regulated power sales affiliates, such as affiliated marketers and 

generators.106 

109. Consistent with the foregoing, we propose to amend the Commission’s regulations 

to include a provision expressly prohibiting power sales between a franchised public 

utility and any of its non-regulated affiliates without first receiving authorization of the 

transaction under section 205 of the FPA. Further, we propose that, as a condition of 

receiving market-based rate authority, sellers must adopt the MBR tariff (included as 

Appendix A to this NOPR) which includes a provision requiring the seller to comply 

with, among other things, the affiliate provisions in the regulations. We note that failure 

to satisfy the conditions set forth in the affiliate provisions will constitute a tariff 

violation. We seek comments on this proposal. 

110. Sellers seeking authorization to engage in affiliate transactions will continue to be 

obligated to provide evidence to support a determination as to whether there are captive 

customers that would trigger the application of our standards for affiliate power sales.107 

If the Commission finds, based on the evidence provided by the seller, that the seller has 

no captive customers, the affiliate provisions in the regulations would not apply. 

 106 In this regard, the Commission protects captive customers by ensuring that 

wholesale rates are just and reasonable. 

107 Sellers that have already received authorization to make sales to affiliates 

would retain that authorization unless the Commission institutes a section 206 

investigation to examine whether the seller’s current circumstances continue to satisfy 

our affiliate abuse concerns and subsequently revokes such authorization. 
Docket No. RM04-7-000 - 70 - 

However, if the record does not support a finding of no captive customers, the seller must 

abide by all affiliate restrictions contained in the regulations in order to obtain and retain 

market-based rate authority. In the Commission’s Final Rule on transactions subject to 

section 203, the Commission defined the term “captive customers” to mean “any 

wholesale or retail electric energy customers served under cost-based regulation.”108 We 

seek comment on whether the same definition should be used for purposes of this rule. 

111. We propose to continue our past approach for determining what types of affiliate 

transactions are permissible and the criteria that should be used to make those decisions. 

When affiliates participate in a competitive solicitation process, application of the 

Allegheny criteria would constitute safe harbor criteria that the affiliate abuse condition is 

satisfied in a transaction between a franchised public utility and its affiliate. The 

Commission will consider competitive solicitations, on a case-by-case basis. However, 

we emphasize that using a competitive solicitation is not the only way an affiliate 

transaction can address our concerns that the transaction does not pose affiliate abuse 

concerns. 

112. In Edgar, two alternatives to competitive solicitation evidence were found to be 

acceptable evidence of a market price. These alternatives included prices non-affiliates 

 108 Transactions Subject to FPA section 203, Order No. 669-A, 71 FR 28422 

(May 16, 2006), FERC Stats. & Regs. ¶ 31,097 (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, 096 (2006). 
Docket No. RM04-7-000 - 71 - 

are willing to pay for similar service and benchmark evidence. However, Edgar also 

noted the difficulty of finding such truly comparable alternative evidence.109 This 

difficulty in finding adequate comparable evidence increases the likelihood that 

applications submitted with such evidence could raise issues of material fact and thus 

could be set for hearing. 

113. We continue 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 (i.e., is a 

relevant index).110 The Commission has stated its belief that the added protections in 

structured markets with central commitment and dispatch and market monitoring and 

mitigation (such as RTOs/ISOs) generally result in a market where prices are 

transparent.111 

114. Although the Commission has found in the past that certain non-RTO price indices 

are acceptable indicators of market prices, we recognize that price indices at thinly traded 

points can be subject to manipulation and are otherwise not good measures of market 

 109 See Edgar, 55 FERC ¶ 61,382 at 62,169. 

110 Brownsville, 111 FERC ¶ 61,398 at P10. See also Portland General Elec. Co., 

96 FERC ¶ 61,093 at 61,378 (2001); FirstEnergy Trading, 88 FERC ¶ 61,067 at 61,156 

(1999). 

111 April 14 Order, 107 FERC ¶ 61,018 at P 189. 
Docket No. RM04-7-000 - 72 - 

prices, as discussed in the Price Index Policy Statement112 and November 19 Price Index 

Order.113 Accordingly, we propose to 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.114 The requirements include the 

criteria found in the Price Index Policy Statement, including but not limited to115

reporting of prices by those not involved in trading, and a process for resolving reporting 

errors, as well as those specific to jurisdictional tariffs: (1) providing the volume and 

number of transaction data on which the index value is based (or clearly indicating when 

no such data is available); (2) confirming that the Commission can have access to 

relevant data in the event of an investigation of possible false price reporting or 

manipulation; and (3) establishing minimum criteria to determine whether there is 

adequate liquidity for daily, weekly, and monthly electricity indices. 

 112 Policy Statement On Natural Gas And Electric Price Indices 104 FERC 

¶ 61,121 (2003) (Price Index Policy Statement). 

113 Order Regarding Future Monitoring Of Voluntary Price Formation, Use Of 

Price Indices In Jurisdictional Tariffs, And Closing Certain Tariff Docket 109 FERC 

¶ 61, 184 (2004) (November 19 Price Index Order). 

114 November 19 Price Index Order, 109 FERC ¶ 61,184 at P 40-69. 

115 Price Index Policy Statement, 104 FERC ¶ 61,121 at P 34. 
Docket No. RM04-7-000 - 73 - 

115. The Commission seeks comment on whether evidence other than competitive 

solicitations, RTO price or non-RTO price indices, or benchmarks described above, 

should be accepted in an application for authority to engage in affiliate power sales. 

116. With regard to merging companies the Commission has stated that for the 

purposes of affiliate abuse, merging companies will be considered affiliates under the 

market-based rate tariff while their merger is pending.116 We seek comments regarding at 

what point the Commission should consider two non-affiliates as merging partners: the 

date the merger is announced, the date the section 203 application is filed with the 

Commission, or another time? The Commission proposes to use the date a merger is 

announced as the triggering event, but we seek comment on this issue. 

117. The Commission also proposes that entities that engage in energy/asset 

management of generation on behalf of a franchised public utility be treated as affiliates 

of that franchised public utility in a manner similar to that of non-regulated affiliates and 

be subject to the affiliate provisions we propose herein. The Commission also proposes 

that entities that engage in energy/asset management of generation on behalf of non- 

 116 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 - 74 - 

regulated affiliates of a franchised public utility be treated in a similar manner as the nonregulated affiliates. We seek comment on this proposal. 

118. The Commission currently requires that sales made under market-based rate 

tariffs, including those made to affiliates, be reported in an EQR.117 The Commission 

affirms that its role with regard to market-based rates, and specifically affiliate 

transactions, will be to either grant or deny authorization to make affiliate sales. 

Additionally, the Commission reiterates that, once authorized, all such sales should be 

reported in an EQR. 

119. Although, at one time, the Commission’s policy was to require certain marketbased rate sellers to file their long-term market-based rate power sales service agreements 

with the Commission,118 since the issuance of Order No. 2001, the Commission’s policy 

has been to require that such agreements not be filed with the Commission. 

Notwithstanding this policy, the Commission on occasion may have accepted long-term 

service agreements for filing. At this time, the Commissionreaffirms that long-term 

affiliate sales contracts under the seller’s market-based rate tariff that are authorized by 

 117 Revised Public Utility Filing Requirements, Order No. 2001, 67 FR 31043 

(May 8, 2002), FERC Stats. & Regs., Regulations Preambles January 2001-December 

2005 ¶ 31,127 (2002). 

118 See Southern Company Services, Inc., 99 FERC ¶ 61,103 (2002). 
Docket No. RM04-7-000 - 75 - 

the Commission shall not be filed with the Commission.119 However, the seller must 

make a section 205 filing with the Commission to obtain authorization to engage in an 

affiliate transaction, and may not engage in such transaction without first receiving such 

authorization. 

2. Market-Based Rate Code of Conduct For Affiliate Transactions 

Involving Power Sales and Brokering, Non-Power Goods and 

Services and Information Sharing

a. Current Policy

120. The Commission requires affiliates of franchised public utilities that request 

market-based rate authority to submit a market-based rate code of conduct to govern the 

relationship between the franchised public utility and its affiliates. Historically, the 

purpose of the market-based rate code of conduct120 has been to safeguard against 

 119 18 CFR § 35.1(g) (2005) (“[A]ny market-based rate agreement pursuant to a 

tariff shall not be filed with the Commission”). 

120 The market-based rate code of conduct has at times been confused with the 

Commission’s Standards of Conduct. The electric Standards of Conduct, originally 

issued in Order No. 889 et seq., were established to govern the relationship between a 

public utility’s transmission function and its wholesale merchant function (including 

affiliated power marketers) to ensure that all transmission customers have equal access to 

transmission information. See Open Access Same-Time Information System and 

Standards of Conduct, Order No. 889, 61 FR 21,737 (1996), FERC Stats. & Regs., 

Regulations Preambles July 1996-December 2000 ¶ 31,035 (1996), order on reh'g, Order 

No. 889-A, 62 FR 12,484 (1997), FERC Stats. & Regs., Regulations Preambles July 

1996-December 2000 ¶ 31,049 (1997), reh'g denied, Order No. 889-B, 81 FERC ¶ 61,253 

(1997), order on reh'g, Order No. 889-C, 82 FERC ¶ 61,046 (1998), aff'd in relevant part 

sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 

2000). The Standards of Conduct were recently updated by the Commission. See

Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 69134 

(continued) 
Docket No. RM04-7-000 - 76 - 

affiliate abuse by protecting against the possible diversion of benefits or profits from 

franchised public utilities (i.e., traditional public utilities with captive ratepayers) to an 

affiliated entity for the benefit of shareholders. Just as the Commission has expressed 

concern about the potential for affiliate abuse in connection with power sales between 

affiliates, it also has recognized that there may be a potential for affiliate abuse through 

other means, such as the pricing of non-power goods and services or the sharing of 

market information between affiliates.121 The market-based rate code of conduct was 

designed to address these concerns. The Commission has waived the market-based rate 

code of conduct requirement in cases where there are no captive customers, and thus no 

potential for affiliate abuse, or where the Commission finds that such customers are 

adequately protected against affiliate abuse.122 In such cases, however, the Commission 

 

(Dec. 11, 2003), III FERC Stats. & Regs., Regulations Preambles January 2001-

December 2005 ¶ 31,155 (Nov. 25, 2003), order on reh’g, Order No. 2004-A, 69 FR 

23,562, (Apr. 29, 2004), III FERC Stats. & Regs., Regulations Preambles January 2001-

December 2005 ¶ 31,161 (April 16, 2004), order on reh’g, Order No. 2004-B, 69 FR 

48,371 (Aug. 10, 2004), III FERC Stats. & Regs., Regulations Preambles January 2001-

December 2005 ¶ 31,166 (Aug. 2, 2004), order on reh’g, Order No. 2004-C, 70 FR 284 

(Jan 4., 2005), III FERC Stats. & Regs., Regulations Preambles January 2001-December 

2005 ¶ 31,172 (Dec. 21, 2004), order on reh'g, Order No. 2004-D, 110 FERC ¶ 61,320 

(March 23, 2005), appeal docketed sub nom., Natural Gas Fuel Supply Corp. v. FERC, 

No. 04-1183 (D.C. Circuit).

121 See, e.g., Potomac Electric Power Company, 93 FERC ¶ 61,240 at 61,782 

(2000); Heartland, 68 FERC ¶ 61,223 at 62,062-63. 

122 See, e.g., CMS Marketing, Services and Trading Co., 95 FERC ¶ 61,308 at 

62,051 (2001) (granting request for cancellation of code of conduct where wholesale 

contracts, as amended, “cannot be used as a vehicle for cross-subsidization of affiliate 

(continued) 
Docket No. RM04-7-000 - 77 - 

directed the utilities to notify the Commission should they obtain captive customers in the 

future and expressly reserved the right to reimpose the market-based rate code of conduct 

requirement. In the Order No. 2004 Standards of Conduct rulemaking proceeding, the 

Commission solicited comment on whether to reform the market-based rate code of 

conduct but determined that such reform should take place in a separate proceeding.123 

121. The market-based rate code of conduct requirements have evolved through 

market-based rate orders.124 Beginning with orders issued in 1999, the Commission 

informed sellers that if an applicant submitted a market-based rate code of conduct that 

was inconsistent with the market-based rate code of conduct attached to those orders, the 

 

power sales or sales of non-power goods and services”); Alcoa, Inc., 88 FERC ¶ 61,045 

at 61,119 (1999) (waiving code of conduct requirement where there were no captive 

customers); Green Power Partners 1 LLC, 88 FERC ¶ 61,005 at 61,010-11 (1999) 

(waiving code of conduct requirement where there are no captive wholesale customers 

and retail customers may choose alternative power suppliers under retail access program). 

123 Order No. 2004, at 30,853. The following entities submitted comments in the 

Standards of Conduct rulemaking proceeding in Docket No. RM01-10-000 relating to 

the concept of codifying the code of conduct: Cinergy (codification not needed); Entergy 

(if codified, the code of conduct should reflect established codes); NEPOOL Industrial 

Customer Coalition (codification needed); LG&E Energy Corporation (separate code of 

conduct policy issues should be treated in a separate rulemaking); PanCanadian Energy 

Services, Inc. (codification unnecessary). 

124 Seminal early Commission decisions discussing the purposes of the code of 

conduct requirements include Heartland and LG&E Power Marketing, Inc., 68 FERC 

¶ 61,247 at 62,121-24 (1994). 
Docket No. RM04-7-000 - 78 - 

Commission would reject it and designate the attachment as the applicable code.125 The 

Commission’s market-based rate code of conduct provisions state: 

STATEMENT OF POLICY AND CODE OF CONDUCT 

WITH RESPECT TO THE RELATIONSHIP BETWEEN 

[POWER MARKETER/ POWER PRODUCER] AND [PUBLIC 

UTILITY] 

Marketing of Power 

1. To the maximum extent practical, the employees of [Power 

Marketer/Power Producer] will operate separately from the employees of 

[Public Utility]. 

 2. All market information shared between [Public Utility] and [Power 

Marketer/Power Producer] will be disclosed simultaneously to the public. 

This includes all market information, including but not limited to, any 

communication concerning power or transmission business, present or 

future, positive or negative, concrete or potential. Shared employees in a 

support role are not bound by this provision, but they may not serve as an 

improper conduit of information to non-support personnel. 

3. Sales of any non-power goods or services by [Public Utility], 

including sales made through its affiliated EWGs or QFs, to [Power 

Marketer/Power Producer] will be at the higher of cost or market price. 

4. Sales of any non-power goods or services by the [Power Marketer/ 

Power Producer] to [Public Utility] will not be at a price above market. 

Brokering of Power 

To the extent [Power Marketer/Power Producer] seeks to broker power for 

[Public Utility]: 

 125 See, e.g., Northeast Utilities Service Company, 87 FERC ¶ 61,063 (1999) 

(requiring market-based rate applicants to submit codes of conduct consistent with an 

attached code of conduct and imposing the attached code in the event of inconsistency). 
Docket No. RM04-7-000 - 79 - 

5. [Power Marketer/Power Producer] will offer [Public Utility's] power 

first. 

6. The arrangement between [Power Marketer/Power Producer] and 

[Public Utility] is non-exclusive. 

7. [Power Marketer/Power Producer] will not accept any fees in 

conjunction with any Brokering services it performs for [Public Utility]. 

122. The Commission has also accepted the inclusion of an additional provision to 

govern brokering activities where a franchised public utility brokers for one of its 

affiliates.126

123. Numerous significant changes have taken place in the electric industry relevant 

to the market-based rate code of conduct requirement since the Commission approved the 

first market-based rate codes of conduct in the mid-1990s. The Commission has required 

open access transmission service in Order No. 888; there has been an increase in the 

number of power marketers and power producers authorized to transact under marketbased rates, as well as an increased market for available transmission capacity, an 

increased number of power transactions, and new and different uses for the transmission 

 126 See MEP Investments, LLC, 87 FERC ¶ 61,209 at 61,828 (1999) (“CP&L has 

taken the brokering rules established by the Commission for the opposite situation (when 

the marketer is brokering for the utility), and modified them to apply to its situation. 

Specifically, instead of the no-fee rule when a marketer brokers for its affiliate, for 

brokering service CP&L provides to Monroe, CP&L will charge Monroe the higher of 

CP&L’s costs for that service or the market rate for such services. CP&L will also market 

its own power first, simultaneously make public any information shared with Monroe 

during brokering, and post on its Internet site the actual brokering changes imposed. This 

addition to CP&L’s code of conduct is accepted.”). 
Docket No. RM04-7-000 - 80 - 

grid.127 The Commission has found that the nature of electric market participants is also 

changing, with the rise of power marketers and generation facilities that are affiliated 

with traditional regulated entities, as well as unaffiliated entities.128

124. There also has been an increased range of activities engaged in by asset or energy 

managers.129 Although asset managers can provide valuable services and thereby benefit 

consumers and the marketplace, such relationships also could result in transactions 

harmful to captive customers. We note that, as the consequence of one Commission 

investigation, there was a settlement agreement pursuant to which a company’s marketbased rate codes of conduct were revised to expand (a) the range of affiliates to which 

 127 Standards of Conduct for Transmission Providers, Order No. 2004, 68 FR 

69134, FERC Stats. & Regs., ¶ 31,155, Regulations Preambles January 2001- December 

2005. 

128 Id. As of April 1, 2006, approximately 1170 entities have market-based rate 

authority granted by the Commission. They include approximately 390 independent 

power marketers, 70 traditional utilities with market-based rate authority, 100 affiliated 

power marketers, 400 affiliated power producers, 180 independent power producers and 

30 financial institutions. 

129 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.) 
Docket No. RM04-7-000 - 81 - 

they applied and (b) the regulation of conduct between affiliates, including the asset 

manager.130

125. While the Commission has required that entities comply with the provisions of the 

market-based rate code of conduct, the market-based rate code of conduct has not been 

codified in the Commission’s regulations. Further, some applicants for market-based rate 

authority have requested and received variations from the market-based rate code of 

conduct. Such variations, while reasonable in individual circumstances, may over time 

become inconsistent with the Commission’s goals of protecting captive customers and 

fostering transparent and consistent regulation of the market. Likewise, some corporate 

families have filed several different market-based rate codes of conduct for their affiliates 

while others have filed only one or have received a waiver of the market-based rate code 

of conduct requirement. 

 130 In 2003, as part of a Settlement Agreement with the Commission, Cleco Corp. 

agreed to an expansion of its codes of conduct governing relations between its various 

affiliates that Enforcement staff alleged had participated in power sales and related 

conduct in violation of the Standards of Conduct and Cleco’s previous codes of conduct. 

Cleco Corp., 104 FERC ¶ 61,125 (2003). Pursuant to the terms of the resulting 

settlement agreement, Cleco submitted revised codes that governed information sharing 

and independent functioning between Cleco’s three exempt wholesale generators (with 

market-based rate authority), its power marketer that in essence acted as an asset manager 

for the three, and its captive ratepayer utility, rather than merely code provisions 

governing relations between, on the one hand, the captive ratepayer utility, and, on the 

other, the marketing and generation affiliates. 
Docket No. RM04-7-000 - 82 - 

126. An example of inconsistent market-based rate codes of conduct was revealed in 

Commission staff’s audit of Progress Energy, Inc. In that proceeding, there were eight 

different codes with differing provisions for different Progress affiliates.131 

b. Proposal

127. The Commission continues to believe that a code of conduct is necessary to 

protect captive customers from the potential for affiliate abuse. Further, in light of the 

repeal of the Public Utility Holding Company Act of 1935 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, it is important that the Commission have in 

place restrictions to preclude transferring captive customer benefits to stockholders 

through a company’s “non-regulated” power sales business. We therefore believe 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 between power sales affiliates.

128. We also believe that greater uniformity and consistency in the codes of conduct is 

appropriate. With the experience gained over the years in approving various codes of 

conduct, including our standard code of conduct, we are proposing to adopt a uniform 

 131 See Florida Power Corp., 111 FERC ¶ 61,243 (2005), attached staff Audit 

Report at 6. 
Docket No. RM04-7-000 - 83 - 

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. We therefore propose to codify such 

affiliate provisions in section 35.39(b)-(e) of our regulations and to require that, as a 

condition of receiving market-based rate authority, sellers comply with these provisions. 

Failure to satisfy the conditions set forth in the affiliate provisions will constitute a tariff 

violation. This uniformity will help ensure that captive customers are protected and that 

affiliate provisions are applied and administered in an even-handed manner in harmony 

with legitimate current industry practices. We seek comment on this proposal and on 

whether the specific affiliate provisions proposed in this NOPR are sufficient to protect 

captive customers. In particular, what changes, if any, should the Commission adopt? 

Additionally, as previously noted, we seek comment on the definition of “captive 

customer.”

129. The proposed provisions are the same as those in the standard code of conduct that 

exists today with the following exceptions. First, the proposed regulations use the term 

“non-regulated” affiliates instead of power marketer/power producer to make it clear that 

the provisions apply to the relationship between a franchised public utility and any of its 

affiliates that are not regulated under cost-based regulation. This includes affiliate power 

marketers and affiliate power producers, such as EWGs and QFs. 

130. Second, in the case of companies that are acting on behalf of and for the benefit of 

franchised public utilities with captive customers, the proposed affiliate provisions treat 
Docket No. RM04-7-000 - 84 - 

such companies, for purposes of the affiliate provisions, as the franchised public utility. 

For example, if a company has been created to manage generation assets for the 

franchised public utility, such entity is subject to the same information sharing provision 

as the franchised public utility with regard to information shared with non-regulated 

affiliates, such as power marketers and power producers. 

131. 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. For example, asset 

managers of a non-regulated affiliate’s generation assets are treated as the non-regulated 

affiliate with regard to, for example, the information sharing provision. We seek 

comment on this proposal.

132. The Commission invites comments proposing other additions, substitutions, or 

eliminations to the proposed affiliate provisions. 

D. Mitigation

1. Current Policy

133. The Commission began accepting applications for market-based power sales in the 

late 1980s as a means to provide greater flexibility to transactions in emerging 

competitive wholesale power markets. The analysis for horizontal market power at that 

time was the "hub and spoke" methodology, and under that methodology most sellers 

received market-based rate approval. If, however, a seller failed the hub and spoke 

analysis for a particular market, as a general matter, no specific mitigation was imposed. 
Docket No. RM04-7-000 - 85 - 

Rather, the seller could continue to sell power under existing cost-based rate schedules on 

file with the Commission in that area. 

134. The Commission began providing greater flexibility in setting cost-based rates for 

coordination sales during this period as well. Historically, utilities had set the rate for 

coordination sales on a "split the savings" formula132 or on the incremental cost of the 

units participating in the sale (plus an adder). In the late 1980s, however, the 

Commission began to approve a variety of "up to" rates under which the applicant could 

charge a rate that was anywhere between a "floor" of incremental cost and a "ceiling" of 

variable energy costs plus an embedded cost demand charge. Examples of this more 

flexible approach were the Western Systems Power Pool, Inc. agreement, under which all 

sellers in the Western Interconnect could transact under a common ceiling rate. The 

Commission also provided significant flexibility to individual sellers, such as by allowing 

them to cap rates at the cost of the most recently installed unit, even if that unit was a 

high-cost baseload unit. 

135. This more flexible approach to wholesale power sales continued largely 

unchanged until 2001 when the Commission adopted the supply margin assessment 

 132 A seller’s incremental cost (the out-of-pocket cost of producing an additional 

MW) is compared with a buyer’s decremental cost (the cost of not producing the last 

MW). The average of the incremental and decremental cost is the “split the savings” 

rate. 
Docket No. RM04-7-000 - 86 - 

(SMA) test.133 The SMA sought to strengthen the horizontal market power test in several 

significant ways, such as considering transmission capability to limit the amount of 

competitive supplies that could get into the relevant market. Although not imposing a 

cost-based rate for longer term transactions, the SMA developed a “must offer” 

requirement and a “split the savings” formula in the event that a seller failed the 

generation market power test, which was the traditional cost-based ratemaking model 

used for spot market energy sales. 

136. In the April 14 and July 8 Orders, the Commission replaced the SMA test with two 

indicative screens for assessing horizontal market power, the pivotal supplier screen and 

the wholesale market share screen, and modified the Commission’s approach to costbased mitigation. 

137. In the April 14 Order, the Commission adopted default mitigation tailored to three 

distinct products: (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 will be priced at an embedded cost “up-to” rate reflecting the costs of 

the unit(s) expected to provide the service; and (3) sales of power for one year or more 

will be priced at an embedded cost of service basis and each such contract will be filed 

with the Commission for review and approved prior to the commencement of service. 

The Commission determined that sellers that are found to have market power (i.e., after 

 133 See AEP Power Marketing, Inc., 97 FERC ¶ 61,219 (2001) (SMA Order). 
Docket No. RM04-7-000 - 87 - 

the Commission has ruled on the DPT analysis), or that accept a presumption of market 

power, may either accept the Commission’s default cost-based mitigation measures or 

propose their own case-specific measures tailored to their particular circumstances that 

eliminate their ability to exercise market power, including adopting existing cost-based 

rates, but did not provide guidance as to which departures from the default mitigation 

would be approved.134 

2. Proposal

138. We seek comment on whether the default mitigation set forth in the April 14 Order 

is appropriate as currently structured. In particular, certain recurring issues have arisen in 

implementing the cost-based mitigation and we seek comment on these issues. 

Specifically, we seek comment, as discussed further below, on four issues of recurring 

significance: (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. 

a. Cost-Based Rate Methodology

139. We first seek comment on issues associated with the rate methodology for 

designing cost-based mitigation. There are two principal issues concerning rate 

methodology that have arisen in implementing the April 14 Order. The first relates to the 

requirement that sales of less than one week be made at incremental cost plus 10 percent. 

 134 April 14 Order, 107 FERC ¶ 61,018 at P 147, 148 & n.142, 150 & n.144. 
Docket No. RM04-7-000 - 88 - 

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 less than one week. We 

seek comment on whether to continue to apply a default rate for sales of less than one 

week that is tied to incremental cost plus 10 percent. Are there problems associated with 

using “up to” rates for shorter-term sales and, if so, what are they? Does the current 

approach provide utilities a disincentive to offer their power to wholesale customers in 

their local control area for short-term sales? Would an “up to” rate adequately mitigate 

market power for such sales? 

140. The second rate methodology issue relates to the design of an "up to" cost-based 

rate. In the past, the Commission has allowed significant flexibility in designing “up to” 

rates. Is that flexibility still warranted? For example, there are often disputes over which 

units are “most likely to participate” or “could participate” in coordination sales. Should 

the Commission continue to allow utilities flexibility in selecting the particular units that 

form the basis of the “up to” rate? If not, what units should an “up to” rate be based 

upon, and how should that rate be calculated? Should the Commission prescribe a 

standard methodology that would allow an applicant to avoid a hearing on rate 

methodology? Would a methodology that is based on average costs (both variable and 

embedded) allow an applicant to avoid a hearing because it eliminates the seller’s 

discretion in designating particular units as “likely to participate”? Are there other 

approaches that would accomplish a similar objective? 
Docket No. RM04-7-000 - 89 - 

141. In the April 14 and July 8 Orders, the Commission stated that sellers that are found 

to have market power (i.e., after the Commission has ruled on a DPT analysis) or that 

accept a presumption of market power can either accept the Commission’s default costbased mitigation measures or propose alternative methods of mitigation. With regard to 

alternative methods of mitigation, should the Commission 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? Would the use of such agreements as a mitigation 

measure satisfy the just and reasonable standard of the FPA? 

142. Finally, the Commission notes that if a mitigated seller is returning to existing 

cost-based rates, the Commission would have the obligation to consider whether those 

rates are sufficient for that purpose, and would have the authority to institute a 

proceeding under FPA section 206 to investigate their justness and reasonableness. 

b. Discounting

143. A seller that has authorization to sell under an “up to” cost-based rate has an 

incentive to discount its sales price when the market price in the seller’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 customers. 

144. The primary issue in this area is whether a seller can “selectively” discount, i.e., 

offer different prices to different purchasers of the same product during the same time 
Docket No. RM04-7-000 - 90 - 

period. We seek 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 we do allow selective discounting, what 

mechanisms (reporting or otherwise), if any, are necessary to protect against undue 

discrimination? By contrast, if we do not allow selective discounting, should we require 

the utility to post discounts to ensure that they are available to all similarly situated 

customers? 

c. Protecting Mitigated Markets

145. Under our current policy, if a seller loses market-based rate authority in its home 

control area, any sales in that control area must be pursuant to cost-based rates; 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 its available power to purchasers 

outside that control area if, for example, market prices outside its control area exceed the 

cost-based caps. Wholesale customers have argued that default cost-based mitigation of 

this kind is of little value if a mitigated seller can simply market its excess capacity at 

market-based rates in other control areas.135 To address this concern, commenters have 

suggested that the Commission either revoke a mitigated seller’s market-based rate 

authority in all control areas or impose some type of mitigation that protects wholesale 

 135 See, e.g., Carolina Power and Light Company, 113 FERC ¶ 61,130 at P 16 & 

n.21 (2005). 
Docket No. RM04-7-000 - 91 - 

customers in those areas where a seller has been found to have market power or has 

accepted the presumption of market power. 

146. The Commission seeks comment on whether its current policy is appropriate and, 

if not, what further restrictions are necessary. In particular, we seek comment on the 

following: 

a. Is it 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? Does this represent undue discrimination or 

otherwise constitute "withholding" in the home control area that is 

inconsistent with the FPA's mandate that rates be just, reasonable and 

not unduly discriminatory? Or, does this reflect economically efficient 

behavior and encourage necessary trading within and across regions, 

particularly in peak periods when marginal prices rise above average 

embedded costs? 

b. Should the Commission 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, 

should the must offer requirement 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 profiting? For example, should there be an annual open 
Docket No. RM04-7-000 - 92 - 

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 is 

free to sell the remaining capacity at market-based rates where it has 

authority to do so? If we adopt such a must offer requirement, what 

rules should there be to define "available" capacity to avoid case-by-case 

disputes over this issue? 

c. As an alternative, should the Commission find that any seller that has 

lost market-based rate authority in its home control area should not be 

able to sell power at market-based rates in adjacent (first tier) control 

areas? Would this be appropriate mitigation and easier to implement 

than a must offer requirement? Or, would such mitigation unnecessarily 

discourage trading and flexibility in markets for which the seller has 

been found not to have market power? 

d. Sales that Sink in Unmitigated Markets 

147. The Commission has stated that its role is to assure customers that sellers who are 

authorized to sell at market-based rates do not have market power or have adequately 

mitigated the potential exercise of market power.136 Further, the Commission’s recent 

orders accepting mitigation proposals are clear that the mitigation is to apply to sales in 

 136 July 8 Order, 108 FERC ¶ 61,026 at P 146. 
Docket No. RM04-7-000 - 93 - 

the geographic market where an applicant is found (or presumed) to have market power 

(mitigated market), not only sales to end users in the control area.137 In order to put in 

place adequate mitigation that eliminates the ability to exercise market power and ensure 

that rates are just and reasonable,138 all market-based rate sales in a mitigated market 

where an applicant is found or presumed to have the ability to exercise market power 

must be subject to mitigation approved by the Commission. 

148. 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.139 However, in MidAmerican Energy Company,

140 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 those buyers that 

serve end-use customers in the mitigated market. Limiting mitigation in this manner 

would improperly allow market-based rate sales within the mitigated market to entities 

that do not serve end-use customers in the mitigated market. Such a limitation would not 

 137 See Oklahoma Gas and Electric Company and OGW Energy Resources, Inc.,

114 FERC ¶ 61,297 (2006), reh’g pending; Carolina Power and Light Company, 

114 FERC ¶ 61,294 (2006) (CP&L); Duke Energy Trading and Marketing, L.L.C., 

114 FERC ¶ 61,056 (2006). 

138 See April 14 Order at P 144, 147. 

139 The Commission has recently clarified that mitigation applies to all sales in a 

mitigated market. See, e.g., CP&L, 114 FERC ¶ 61,294 at P 9 (2006). 

140 114 FERC ¶ 61,280 (2006), reh’g pending (MidAmerican). 
Docket No. RM04-7-000 - 94 - 

mitigate the seller’s ability to attempt to exercise market power over sales in the 

mitigated market and is inconsistent with our direction in the April 14 and July 8 Orders. 

For example, 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 applicant has been found to have market 

power. In particular, arguments were made that an applicant 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 

we restrict mitigated applicants to selling power only to buyers serving end-use 

customers, 141 and has since rejected tariff language that proposes to do so.142

149. The Commission seeks comment on whether it should modify or revise its current 

policy and, if so, how. In particular, we seek comment on the following: 

a. Should the Commission allow market-based rate sales by a mitigated 

seller within a mitigated market if those sales do not “sink” in that 

control area? If so, under what circumstances should the Commission 

allow such sales and how would the Commission ensure that such sales 

do indeed “sink” in an unmitigated control area? How does the 

Commission distinguish possible permissible sales to the border of the 

 141 See July 8 Order, 108 FERC ¶ 61,026 at P 134. 

142 See, e.g., MidAmerican, 114 FERC ¶ 61,280 at P 33. 
Docket No. RM04-7-000 - 95 - 

restricted control area from sales that are not permitted within the 

restricted control area? 

b. Under such a policy, what opportunities, if any, are presented to “game” 

the mitigation? If it is determined that a mitigated seller’s sales in fact 

do not “sink” outside the restricted control area, what penalties should 

the Commission consider? 

c. If the Commission retains its current policy of prohibiting all marketbased rate sales by a mitigated seller in a mitigated market what effect, 

if any, does such a policy have on existing contractual arrangements? 

With regard to existing transmission rights a buyer may have in a 

mitigated market, how easily could existing market-based rate 

agreements between that buyer and the mitigated seller be amended to 

provide for delivery of power in an unmitigated market under the same 

economic terms as exists today? 

E. Implementation Process 

1. Current Practice 

150. The Commission’s current practice is a case-by-case analysis of new applications 

for market-based rate authorization as well as updated market power analyses. In 

addition, to date the Commission has allowed sellers to propose their own individualized 

tariffs. 
Docket No. RM04-7-000 - 96 - 

2. Proposal

151. The Commission proposes to put in place a structured, systematic review to assist 

the Commission in analyzing sellers based on a coherent and consistent set of data for 

relevant geographic markets. In addition, some corporate families have many 

subsidiaries with market-based rate authorization, each with its own separate tariff. This 

has led to confusion, inconsistencies between the tariffs of a single corporate family, and 

difficulty in coordinating changes to the tariffs. To remedy these concerns, the 

Commission proposes to streamline the administrative process associated with the filing 

and review of market-based rate updated market power analyses and to consolidate 

market-based rate authorizations into a single tariff. 

152. The Commission proposes to continue to require sellers to submit updated market 

power analyses for all relevant geographic markets (default or proposed alternative 

markets, as discussed previously) in which they own or control generation. However, the 

Commission proposes to modify this filing requirement in two ways. First, the 

Commission proposes to establish two categories of sellers with market-based rate 

authorization. The first category (Category 1) 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. In addition, 

Category 1 sellers 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 such 
Docket No. RM04-7-000 - 97 - 

facilities are limited and discrete and do not constitute an integrated grid143), and must 

present no other vertical market power issues. Rather than requiring Category 1 sellers to 

file a regularly scheduled triennial review, the Commission would monitor any market 

power concerns through the change in status reporting requirement and through ongoing 

monitoring by the Commission’s Office of Enforcement.144 All sellers with market-based 

rate authority are required to make a filing with the Commission regarding any change in 

status that reflects a departure from the characteristics that the Commission relied upon in 

granting market-based rate authority. Failure to timely file a change in status report 

would constitute a violation of the Commission’s regulations and the seller’s MBR 

tariff.145 A seller would be subject to disgorgement of profits and/or civil penalties from 

the date on which the tariff violation occurred. Such seller may also be subject to 

suspension or revocation of its authority to sell at market-based rates (or other 

appropriate non-monetary remedies). In addition, the Commission would retain the right 

to initiate a section 206 proceeding if circumstances warranted. A seller that no longer 

satisfies the Category 1 criteria would be required to submit a change in status 

notification and would be subject to the updated market power analysis filing required of 

Category 2 sellers. 

 143 See, e.g., Black Creek Hydro, Inc., 77 FERC ¶ 61,232 (1996). 

144 Order No. 652, FERC Stats. & Regs., ¶ 31,175. 

145 Id. at P 113. 
Docket No. RM04-7-000 - 98 - 

153. The second category (Category 2) would include all sellers that do not qualify for 

Category 1. Category 2 sellers, in addition to the requirement to file change in status 

reports, would be required to file regularly scheduled triennial reviews. Category 2 

sellers are the larger sellers with 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 

Category 1 sellers. 

154. To ensure greater consistency in the data used to evaluate Category 2 sellers, the 

Commission proposes to require each seller to file updated market power analyses for its 

relevant geographic markets (default and any proposed alternative markets) 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.146 The regional reviews would rotate by 

geographic region with three regions reviewed per year. Appendix B provides a schedule 

for the proposed regional review process. The Commission proposes to continue to make 

findings on an individual seller basis, but will have before it a complete picture of the 

uncommitted capacity and simultaneous import capability into the relevant geographic 

markets under review. 

 146 Sellers would be deemed to be assigned to a region based on the control area in 

which they own or control generation. Nine regions will be examined using the regions 

specified in the 2004 State of the Markets Report, excluding ERCOT, as shown in the 

map attached as part of Appendix B. Those regions are: Northwest, California, 

Southwest, Midwest, SPP, Southeast, PJM, New York, and New England. 
Docket No. RM04-7-000 - 99 - 

155. The Commission proposes to codify in its regulations the obligation for Category 

2 sellers to timely file a triennial review. As a result, failure to timely file a triennial 

review would constitute a violation of the Commission’s regulations and the seller’s 

MBR tariff and could result in disgorgement of profits and/or civil penalties from the date 

on which the seller violated its tariff. 147 A seller may also be subject to suspension or 

revocation of its authority to sell at market-based rates (or other appropriate nonmonetary remedies). If a seller files a timely triennial review, its market-based rate 

authority would continue unless the Commission institutes a section 206 proceeding 

because the seller fails one of the indicative screens and the Commission subsequently 

makes a definitive finding of market power and revokes its market-based authority, or the 

seller accepts the presumption of market power and adopts the default cost-based 

mitigation or proposes other cost-based mitigation or tailored mitigation. 

156. Some corporate families own or control generation in multiple control areas and 

different regions. For example, a corporate family may own generation facilities on the 

east coast as well as in California. In this instance, the corporate family would be 

required to file a current triennial review for each region in which members of the 

corporate family sell power during the time period specified for that region. To the 

 147 Currently, the requirement to file triennial reviews is contained in our orders, 

but not in the tariffs or in our regulations. 
Docket No. RM04-7-000 - 100 - 

extent a new subsidiary is formed and a new request for market-based rate authority is 

submitted, triennial reviews will be due at the regularly scheduled time for review of the 

markets in the region in which the new applicant owns or controls generation. We seek 

comment on this proposal. 

157. In addition, the Commission proposes to require that all triennial review filings 

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 and listing 

the in-service date and nameplate and/or seasonal ratings by unit. 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 and the location of such facilities. 

158. Triennial reviews should reflect the most recently available historical data from 

the calendar year prior to the year of filing. 

159. We seek comments on the proposal to adopt these filing requirements.

F. Market-Based Rate Tariff (MBR Tariff)

160. Historically the Commission has not required the filing of a market-based rate 

tariff of general applicability. However, many sellers have submitted one or more 

umbrella market-based rate tariffs that set forth the conditions of market-based rate 

approval and the general terms applicable to all transactions, with individual transactions 

being negotiated through service agreements, letter confirmations, or other 

documentation that sets forth the rates and any individualized terms and conditions. This 

general practice has afforded flexibility to sellers as markets and the industry evolved and 
Docket No. RM04-7-000 - 101 - 

as new products and services were sold under market-based rate tariffs. However, this 

flexible approach has sometimes resulted in inconsistency in the tariffs filed within the 

same corporate family, which can create confusion for customers and compliance 

problems, and it also has resulted in inconsistencies in memorializing the conditions of 

market-based rate approval in such tariffs. 

161. As part of our effort to streamline and simplify the market-based rate program in 

general, while at the same time maintaining a high degree of transparency and oversight, 

we propose to adopt a market-based rate tariff of general applicability that all sellers 

authorized to sell wholesale electric power at market-based rates will be required to file 

as a condition of market-based rate authority.148 The MBR tariff would require the seller 

to comply with the applicable provisions of the market-based rate regulations which this 

NOPR proposes to codify in 18 CFR Part 35, Subpart H. These provisions reflect the 

Commission’s two decades of experience with market-based rate power sales and should 

serve to reduce the burden on customers of managing multiple tariffs. In addition, the 

seller would be required to list on the MBR tariff the docket numbers and case citations, 

where applicable, of the proceedings, if any, in which the seller received Commission 

authorization to make sales of energy between affiliates or where its market-based rate 

authority was otherwise restricted or limited. A copy of the proposed MBR tariff is 

attached as Appendix A. 

 148 Order No. 614 guidelines for designating rate schedules must be observed. 
Docket No. RM04-7-000 - 102 - 

162. 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 seeks comments on 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 that seller. 

163. In proposing the adoption of the MBR tariff, our purpose is not to direct the terms 

and conditions of a particular power sale or to otherwise reduce the flexibility afforded to 

market-based rate sellers in fashioning the terms of individual transactions. Rather, 

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 in the quarterly EQRs. Further, if sellers wish to offer 

or require certain “generic” terms and conditions that in the past were contained in their 

market-based 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. Our purpose in requiring a MBR tariff of general 

applicability is to ensure that the MBR tariff on file with the Commission for each seller 

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 our proposed regulations, and that the rates, terms and conditions of any 

particular sale will be negotiated between the seller and individual purchasers. We do not 
Docket No. RM04-7-000 - 103 - 

believe any useful purpose is served in having on file the commercial terms preferred by 

particular applicants, given that the purpose of market-based rate authorization is to 

provide flexibility in such terms and conditions. Furthermore, our standards for approval 

of market-based rates do not include a review of such individualized commercial terms 

and thus, such submissions are unnecessary. 

164. Further, the Commission proposes that, rather than each entity having its own 

MBR tariff, which can result in dozens of tariffs for each corporate family with 

conflicting provisions, each corporate family has only one tariff on file, with all affiliates 

with market-based rate authority separately identified in the tariff. This will allow for 

better transparency with regard to what sellers each corporate family has, and a more 

customer-friendly tariff. The requirement to have a single MBR tariff does not mean that 

all members of a corporate family would be counterparties on every sale under the tariff; 

rather, individual transactions would continue to be consummated with individual sellers 

within the corporate family, as they are today. 

165. We seek comments on this proposal. 

166. Regarding the specifics of filing the MBR tariffs, we note that the Commission has 

initiated a rulemaking proceeding to require the filing of electronic tariffs.149 We propose 

 149 See Electronic Tariff Filings, Notice of Proposed Rulemaking, 69 FR 43929 

(July 23, 2004), FERC Stats. & Regs., Proposed Regulations ¶ 32,575 (July 8, 2004). 
Docket No. RM04-7-000 - 104 - 

that the timing of filing and format for the MBR tariffs be consistent with the 

requirements of the final rule issued in that proceeding. 

G. Miscellaneous Issues

1. Waivers

167. Certain entities with market-based rate authority have typically been granted 

waiver of the Commission’s Uniform System of Accounts, and thus have not been 

subject to specified accounting rules. For instance, Parts 41, 101, and 141 of the 

Commission’s regulations prescribe certain informational requirements that focus on the 

assets that a public utility owns.150 For market-based rate applications, the Commission 

has taken the position that, because a power marketer does not own any electric power 

generation or transmission facilities, its jurisdictional facilities would be only corporate 

and documentary, its costs would be determined by utilities that sell power to it, and its 

earnings would not be defined and regulated in terms of an authorized return on invested 

capital; accordingly, the Commission has granted waivers to power marketers of the 

requirements of these Parts. The Commission also has granted other market-based rate 

sellers, such as independent or affiliated power producers, waiver of the requirements of 

these Parts. 

168. The Commission has also granted power marketers’ and others’ requests for 

blanket approval under Part 34 of the Commission’s regulations for all future issuances 

 150 Part 41 pertains to adjustments of accounts and reports; Part 101 contains the 

Uniform System of Accounts; Part 141 describes required forms and reports. 
Docket No. RM04-7-000 - 105 - 

of securities and assumptions of liability, assuming that no party objects to such treatment 

during a notice period which the Commission provides.151 The purpose of section 204 of 

the FPA, which Part 34 implements, is to ensure the financial viability of public utilities 

obligated to serve electric consumers. The Commission has granted 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 public service franchise providing electricity to consumers dependent upon its 

service.152 

169. 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 seeks comment on the extent to which these 

entities should be required to follow the Uniform System of Accounts, what financial 

information, if any, should be reported by these entities, and how frequently it should be 

reported, and whether the Part 34 blanket authorizations continue to be appropriate. 

 151 We note that the Commission’s jurisdiction over issuances of securities and 

assumptions of liabilities under section 204 of the FPA applies only to entities that are 

public utilities as defined in the FPA and only where the public utilities’ security issues 

are not regulated by a State commission (see FPA section 204(f)). 

152 See, e.g., St. Joe Minerals Corp., 21 FERC ¶ 61,323 (1982); Cliffs Electric 

Service Company, 32 FERC ¶ 61,372 (1985); Citizens Energy Corp., 35 FERC ¶ 61,198 

(1986); Howell Gas Management Company, 40 FERC ¶ 61,336 (1987); and Nevada SunPeak Limited Partnership, 86 FERC ¶ 61,243 (1999). 
Docket No. RM04-7-000 - 106 - 

170. The Commission announced in the April 14 Order that, where an applicant is 

found to have market power (or where the applicant accepts a presumption of market 

power), the applicant will be required to adopt some form of cost-based rates or other 

mitigation the applicant proposes and the Commission accepts. Under these 

circumstances, the Commission found that it is essential that appropriate accounting 

records be maintained consistent with the Commission’s regulations. Accordingly, the 

Commission indicated it will no longer waive the otherwise applicable accounting 

regulations (e.g. Parts 41, 101, and 141 of the Commission’s regulations).153 Thus, the 

Commission would revoke the accounting waivers for a mitigated seller, and for any of 

its affiliates with market-based rates in the mitigated control area. Further, the 

Commission stated that it will not grant blanket approval for issuances of securities or 

assumptions of liability pursuant to Part 34 of the Commission’s regulation for the 

mitigated seller and its affiliates.154 In the case of any affiliates, this would entail 

rescission of these blanket authorizations in all geographic areas, not just the mitigated 

control area. 

171. We note 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 cost-based rates. Consistent with the 

 153 April 14 Order, 107 FERC ¶ 61,018 at P 150. 

154 Id. 
Docket No. RM04-7-000 - 107 - 

April 14 Order, any waivers previously granted in connection with those sellers’ marketbased rate authority are no longer applicable. We propose that such revocation of 

waivers become effective 60 days from the date of an order revoking such waivers in 

order to provide the affected utility with time to make the necessary filings with the 

Commission and allow for an orderly transition from selling under market-based rates to 

cost-based rates. We seek comment in this regard. The Commission seeks 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. 

2. Foreign Sellers

172. Under existing policy, a foreign entity 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 

foreign sellers, the Commission allows a modified approach to the four prongs. 

173. With regard to generation market power, should a foreign seller or any of its 

affiliates own or control any generation in the United States, or should one of its first-tier 

markets include a United States market, it should perform the market power screens in 

the appropriate control area(s). 

174. With regard to transmission market power, the Commission requires a foreign 

seller seeking market-based rate authority to demonstrate that its transmission-owning 
Docket No. RM04-7-000 - 108 - 

affiliate offers non-discriminatory access to its transmission system that can be used by 

competitors of the foreign seller to reach United States markets.155 However, if foreign 

transmission facilities meet the criteria for waiver of Order No. 888, such a 

demonstration would not be required.156

175. For purposes of market-based rate authorization, 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.157

176. Regarding other potential barriers to entry, a foreign seller should 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. 

177. Finally, regarding affiliate abuse, the Commission typically requires a power 

marketer with market-based rate authorization to file for approval under section 205 of 

the FPA before selling power to or purchasing power from any utility affiliate. However, 

 155 See TransAlta Enterprises Corp., 75 FERC ¶ 61,268 at 61,875 (1996), and 

Energy Alliance Partnership, 73 FERC ¶ 61,019 at 61,030-31 (1995) (Energy Alliance). 

156 Canadian Niagara Power Company, 87 FERC ¶ 61,070 (1999). 

157 Fortis Ontario, Inc. and Fortis US Energy Corp., 115 FERC ¶ 61,110 (2006). 
Docket No. RM04-7-000 - 109 - 

this general requirement does not apply to situations involving sales of power to or from 

a foreign utility outside of the Commission’s jurisdiction.158

178. The Commission proposes to retain its current policy when reviewing a foreign 

seller’s application for market-based rate authorization consistent with our overall 

approach discussed herein. The Commission seeks comments regarding whether this 

current policy is adequate to grant market-based rate authorization to such sellers. 

3. Change in Status

179. In early 2005, the Commission clarified and standardized market-based rate 

sellers’ reporting requirement 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. 652,159 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. The rule provided that a change in status 

includes, but is not limited to: (i) ownership or control of generation or transmission 

facilities or inputs to electric power production other than fuel supplies, or (ii) affiliation 

with any entity not disclosed in the application for market-based rate authority that owns 

or controls generation or transmission facilities or inputs to electric power production, or 

 158 Energy Alliance, 73 FERC ¶ 61,019 at 61,031; TransAlta, 75 FERC ¶ 61,268 at 

61,876. 

159 Order No. 652 at P 47.
Docket No. RM04-7-000 - 110 - 

affiliation with any entity that has a franchised service area.160 A seller’s experiencing 

one of these changes would trigger the notification requirement.161

180. The Commission has provided further guidance on change in status filings in 

several cases. In Calpine Energy Services, L.P.,162 the Commission clarified that sellers 

making a change in status filing to report an energy management agreement are required 

to make an affirmative statement regarding whether the agreement transfers control of 

any assets and whether it results in any material effect on the conditions the Commission 

relied on when granting market-based rates. The Commission also clarified 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 Federal Power Act. To the 

extent the seller has made a section 203 filing that it submits is being made 

out of an abundance of caution and thus has voluntarily consented to the 

Commission’s 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 marketbased rate change in status filing and, on that basis, inform the Commission 

as to whether there is any material effect on its market-based rate 

authority).[163] 

 160 See 18 CFR 35.27(c) (2005). 

161 If a seller ceases to do business, or, in the event of its dissolution, such seller 

should file a notice of cancellation of its rate schedule. 

162 113 FERC ¶ 61,158 at P 13 (2005). 

163 Id. at P 14 (footnotes omitted). 
Docket No. RM04-7-000 - 111 - 

181. In addition, market-based rate sellers must report as a change in status each 

cumulative increase in generation of 100 MW or more that has occurred since the most 

recent notice of change in status filed by that seller (i.e., multiple increases in generation 

that individually do not exceed the 100 MW threshold must all be reported once the 

aggregate amount of such increases reaches 100 MW or more).164 The Commission 

reserves the right to require additional information, including an updated market power 

analysis, if necessary to determine the effect of an entity’s change in status on its marketbased rate authority.165

182. In Order No. 652, the Commission identified a number of issues that could be 

pursued in the instant rulemaking proceeding. The Commission had proposed in that 

rulemaking proceeding to include fuel supplies as an input to electric power production 

the acquisition of which would be a reportable change in status. However, in the final 

rule, the Commission determined that this issue would be more appropriately raised in the 

instant rulemaking proceeding, and stated that the Commission would provide 

 164 See Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 68. The reporting 

requirement is triggered only by net, rather than gross, increases in generation capacity of 

100 MW or more. For example, capacity decreases associated with changes in 

generation capacity or expiration of capacity under long-term purchase contracts should 

be netted against generation capacity increases to determine whether the 100 MW 

materiality threshold has been reached. The Commission has adopted a netting approach 

in determining whether the materiality threshold has been reached, subject to the 

cumulative 100 MW threshold. See Order No. 652-A, 111 FERC ¶ 61,413 at P 24-25. 

165 Order No. 652 at P 95. 
Docket No. RM04-7-000 - 112 - 

opportunity for interested persons to propose modifications to the existing approach in 

this proceeding.166 Accordingly, the Commission solicits comments 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 proposes to align this reporting requirement to reflect the consideration of 

other barriers to entry as part of the vertical market power analysis, and commenters 

should refer to the discussion of other barriers to entry herein where the Commission 

proposes to clarify what constitutes an input to electric power production as part of the 

Commission’s review of vertical market power. 

183. In Order No. 652, the Commission clarified that the reporting of transmission 

outages per se as a change in status was not required. However, to the extent a 

transmission outage affects, on a long-term basis (e.g., an extended outage of a circuit or 

substation), whether the seller satisfies the Commission’s concerns regarding horizontal 

or vertical market power (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 would be required. The Commission 

also stated that it would consider this matter further in the context of this rulemaking in 

the transmission market power part of the market power analysis.167 We propose, 

 166 Id. at P 58. 

167 Id. at P 75. 
Docket No. RM04-7-000 - 113 - 

consistent with Order No. 652, not to require the reporting of transmission outages per se 

as a change in status. We seek comment on this proposal. 

184. The Commission declined in Order No. 652 to narrow or delineate the definition 

of control. The Commission noted that, historically, if a seller has control over certain 

capacity such that it 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. Further, the capacity associated with contracts that confer 

operational control of a facility to an entity other than the owner must be assigned to the 

entity exercising control over that facility. 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.168 As discussed above, 

the horizontal market power section herein seeks comment on a number of issues 

concerning control and commitment of generation. 

185. In Order No. 652 we did not expand the triggering events for a change in status 

filing to include actions taken by a competitor (such as a decision to retire a generation 

unit or take transmission capacity out of service) or natural events (such as hydro-year 

level, higher wind generation, or load disruptions due to adverse weather conditions). In 

 168 Id. at P 47. 
Docket No. RM04-7-000 - 114 - 

Order No. 652, we concluded that the reporting obligation should extend only to changes 

in circumstances within the knowledge and control of the seller. However, in Order No. 

652, we stated that interested persons could pursue in the instant rulemaking whether the 

Commission should expand the triggering events for a change in status filing. 

Accordingly, we invite comments generally on whether the Commission should expand 

the triggering events 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 adopted in Order No. 652. 

4. Third-Party Providers of Ancillary Services 

186. 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) would also provide ancillary services.169 The Commission also left open the 

door that ancillary services could be provided on other than a cost-of-service basis. In 

Order No. 888, Commission stated that it would entertain requests for market-based 

pricing related to ancillary services on a case-by-case basis if supported by analyses that 

demonstrate that the seller lacks market power in these discrete services.170 In Ocean 

 169 See Order No. 888, FERC Stats. & Regs. ¶ 31,036 at 31,720-21. 

170 Id.; Order No. 888-A, FERC Stats. & Regs. ¶ 31,048 at 30,237-38. 
Docket No. RM04-7-000 - 115 - 

Vista Power Generation, L.L.C. (Ocean Vista),171 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. The Commission also noted that it would entertain alternative 

explanations and approaches. 

187. In Ocean Vista, the Commission also offered more detailed guidance for what a 

market power study for ancillary services markets should include: (1) defining a relevant 

product market for each ancillary service, which should include the applicant's product, 

together with other products that, from the buyer's perspective, are good substitutes; 

(2) identifying the relevant geographic market, which could include all potential suppliers 

of the product from whom the buyer could obtain the service, taking into account relevant 

factors which may include the other suppliers' locations, the physical capability of the 

delivery system and the cost of such delivery, and important technical characteristics of 

the suppliers' facilities; (3) establishing market shares for all suppliers of the ancillary 

services in the relevant geographic markets; and (4) examining other barriers to entry. 

188. The guidance offered by the Commission in Order No. 888 and Ocean Vista was 

designed for two purposes: to ensure that sellers of ancillary services do not exercise 

 171 82 FERC ¶ 61,114 at 61,406-07. 
Docket No. RM04-7-000 - 116 - 

market power and to further the goal of promoting competition in ancillary service 

markets. 

189. However, in Avista Corporation,172 the Commission stated that there remained two 

problems hindering the development of ancillary service markets. First, access to critical 

data may preclude many potential sellers of ancillary services from performing reliable 

market analyses. Second, without an alternative means of regulating ancillary service 

rates at an early stage in the development of competitive wholesale power markets, the 

Commission may not be able to encourage sufficient market entry of third-party 

providers of ancillary services. 

190. Accordingly, the Commission adopted a policy wherein third-party ancillary 

service providers that cannot perform a market power study would be allowed to sell 

ancillary services at market-based rates, but only in conjunction with a requirement that 

such third parties establish an Internet-based OASIS-like site for providing information 

about and transacting ancillary services. 

191. In this regard, the Commission stated that it will apply this policy only to 

applicants who are authorized to sell power and energy at market-based rates. In 

addition, the Commission stated that it will not apply this approach to sales of ancillary 

services by a third-party supplier in the following situations: (1) the approach will not 

apply to sales to a regional transmission organization (RTO) or an independent system 

 172 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 (1999) (Avista). 
Docket No. RM04-7-000 - 117 - 

operator (ISO), i.e., where that entity has no ability to self-supply ancillary services but 

instead depends on third parties (the Commission stated that its experience to date 

indicates that the data problems associated with market analysis involving sales to an 

ISO, for example, should not be insurmountable and an appropriate showing of a lack of 

market power can be made);173 (2) to address affiliate abuse concerns, the approach will 

not apply to sales to a traditional, franchised public utility affiliated with the third-party 

supplier, or to sales where the underlying transmission service is on the system of the 

public utility affiliated with the third-party supplier; and (3) the approach will not apply 

to sales to a public utility who is purchasing ancillary services to satisfy its own open 

access transmission tariff requirements to offer ancillary services to its own customers 

(the Commission indicated that it is open, however, to considering requests for marketbased rates in such circumstances on a case-by-case basis).174

 173 With the formation of RTOs and ISOs, several RTO/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. 

174 Avista, 87 FERC at 61,883 n. 12. 
Docket No. RM04-7-000 - 118 - 

192. The Commission based its policy as announced in Avista 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.175 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. The Commission 

stated that it believes that this protection, in conjunction with the Internet-based site 

requirement, will provide an appropriate and effective safeguard against potential 

anticompetitive behavior. 

193. The information contained in the Internet-based site would include service 

availability, prices, and requests granted and denied. To further monitor development of 

market entry, the Commission required third-party suppliers to file with the Commission 

 175 The Commission stated that it is cognizant of, but will address separately and at 

the appropriate time, situations in which it becomes apparent that, due to changes in 

ancillary services markets, competitive prices would be higher than the transmission 

provider's cost-based rate, were it not for the transmission provider's obligation to meet 

all demand for ancillary services at such a rate. 
Docket No. RM04-7-000 - 119 - 

one year after their Internet-based site is operational (and at least every three years 

thereafter176) a report detailing their activities in the ancillary services market. 

194. In particular, the Commission stated that: 

[i]f the applicant cannot perform a study showing that it lacks market power 

in the provision of ancillary services, it may receive flexible rates provided 

it safeguards against potential anticompetitive behavior by establishing an 

Internet-based site for providing information regarding, and conducting, 

ancillary services transactions. The site would include postings of offers of 

services available and their offering prices and would provide customers 

with the ability to request services and make bids for these services. The 

site would also contain information about accepted and denied requests and 

the reasons for denial. The site should conform to the applicable OASIS 

Standards and Communications Protocols (Version 1.3).[177] 

195. We propose to retain our current approach in this regard. We seek comment on 

whether we should modify or revise our current approach and, if so, how. Also, we seek 

comment on whether our current conditions such as the requirement to establish an 

Internet-based site continue to be necessary. 

 176 The Commission reserves the right to require that such a report be filed at any 

time. 

177 Avista, 87 FERC at 61,884. We note that section 37.6(d)(5) of the 

Commission’s regulations states: “Any entity offering an ancillary service shall have the 

right to post the offering of that service on the OATT if the service is one required to be 

offered by the Transmission Provider under the pro-forma tariff prescribed by part 35 of 

this chapter. Any entity may also post any other interconnected operations service 

voluntarily offered by the Transmission Provider. Postings by customers and third 

parties must be on the same page, and in the same format, as posting of the Transmission 

Provider.” 
Docket No. RM04-7-000 - 120 - 

H. Proposed Revisions To Regulations

1. Section 35.27 [Currently] Power Sales at Market-Based Rates

196. Subsections (a) and (b) of this section were added by Order No. 888 in order to 

implement the post-1996 exemption for new generation and to clarify the authority of 

state commissions respectively. Order No. 652 later added subsection (c) to implement 

the change in status reporting requirement. 

197. This NOPR proposes to eliminate the post-1996 exemption, and thus the proposed 

regulatory text deletes subsection (a). Subsection (c) is proposed to move to subpart H 

section 35.43, and thus the proposed text deletes section 35.27(c). This leaves only 

current subsection (b) in 35.27. The proposed regulatory text does not revise the 

language in any way and merely renumbers current subsection (b) to reflect the absence 

of the other subsections. 

198. With the changes proposed herein, the current section heading, “Power Sales at 

Market-Based Rates,” will no longer be pertinent. The Commission proposes to amend 

the heading to “Authority of State Commissions” to reflect the content of the remaining 

provision. 

2. Section 35.36 Generally

199. This section is proposed to define certain terms specific to Subpart H and to 
Docket No. RM04-7-000 - 121 - 

explain the applicability of Subpart H.178 Some of these terms were put in place recently 

when the Commission codified certain market behavior rules in Order No. 674.179 

Subsection (a)(1) explains that “seller” refers to a public utility with authority to, or 

seeking authority to, engage in sales for resale of electric energy, capacity or ancillary 

services at market-based rates to make clear that Subpart H deals exclusively with 

market-based rate power and ancillary services sales. The proposed regulations define 

Category 1 sellers and Category 2 sellers to assist in understanding the parameters of the 

updated market power analysis requirement. Subsection (a)(4) defines inputs to electric 

power production in order to simplify section 35.37(e) regarding other barriers to entry. 

Subsection (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 territory that have 

captive customers. Last, subsection (a)(6) provides a definition for non-regulated 

affiliated entities, which appears in several places in the proposed regulations. 

200. Subsection (b) is intended to leave room for certain provisions that do not apply to 

a particular seller should the Commission make a finding, for instance, that a franchised 

public utility has no captive customers and hence section 35.39(b) is not applicable. 

 178 We note that we also proposed to change the title of Subpart H from 

‘Wholesale Sales of Electricity at Market-Based Rates’ to ‘Wholesale Sales of Electric 

Energy, Capacity and Ancillary Services at Market-Based Rates’. 

179 Conditions for Public Utility Market-Based Rate Authorization Holders, Order 

No. 764, FERC Stats. & Regs. ¶ 31,208, 114 FERC ¶ 61,163 (2006). 
Docket No. RM04-7-000 - 122 - 

201. We solicit comments on whether further or different language than that proposed 

here should be incorporated in our regulations. 

3. Section 35.37 Market Power Analysis Required

202. 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 without providing too much detail. The Commission is 

cognizant that the finer points of the market power analysis change over time as 

individual orders consider new facts and as precedent shifts to follow the evolution of the 

power industry; the proposed regulations should not be so detailed as to require revision 

from time to time to follow these changes. 

203. We solicit comments on the scope of the language that should be incorporated in 

the regulations.

4. Section 35.38 Mitigation

204. The NOPR raises questions concerning the current approach and seeks comments 

regarding any changes the Commission should adopt. In addition, we propose to 

characterize the informal term “up to” cost-based rates as “priced at no higher than a 

cost-based ceiling reflecting the cost of the units expected to provide service.” We seek 

comments on whether further or different language than that proposed here should be 

incorporated in our regulations.
Docket No. RM04-7-000 - 123 - 

5. Section 35.39 Affiliate Provisions

205. This section governs affiliate transactions and affiliate relationships and 

establishes affiliate conditions that a seller must satisfy as a condition of its market-based 

rate authority. Subsection (a) includes a provision expressly prohibiting sales between a 

franchised public utility and any of its non-regulated power sales affiliates without first 

receiving authorization of the transaction under section 205 of the FPA. This subsection 

requires that, where the Commission grants a seller authority to engage in affiliate sales 

under its MBR tariff, any and all such authorizations must be listed in the seller’s tariff. 

We seek comments on the proposal to include this provision in the Commission’s 

regulations. 

206. Subsections (b)-(e) contain the market-based rate code of conduct provisions 

governing the relationship between a franchised public utility and its non-regulated 

power sales and power brokering affiliates. The provisions of this subsection apply to all 

franchised public utilities with captive customers. This subsection includes provisions 

governing the separation of employees, the sharing of market information, sales of nonpower goods or services, and power brokering. It proposes that, for purposes of applying 

the provisions of this section, entities acting on behalf of and for the benefit of a 

franchised public utility (such as service companies and entities managing the generation 

assets of the franchised public utility) are considered to be part of the franchised public 

utility, and entities acting on behalf of and for the benefit of a non-regulated affiliate of a 

franchised public utility (such as affiliated power marketers and power producers and 
Docket No. RM04-7-000 - 124 - 

entities managing the generation assets of the affiliated power marketers and producers) 

are considered to be part of the non-regulated affiliates. This section is an integral part of 

the Commission’s conditions regarding affiliate abuse where captive customers are 

concerned. We seek comments on the proposal to include the affiliate provisions in the 

regulations. 

6. Section 35.40 Ancillary Services

207. This provision restricts sales of ancillary services to those specific geographic 

markets for which the Commission has authorized market-based rate sales of such. In 

addition, this section lays out the limitations on third-party ancillary services sales 

provided in Avista Corporation.

180

7. Section 35.41 Market Behavior Rules

208. Recently, the Commission rescinded two of its market behavior rules and codified 

the remainder in section 35.37 of new Subpart H. Also, in a Final Rule issued 

concurrently with this NOPR the Commission is revising the record retention period from 

three years to five years. In this NOPR, we propose to move these market behavior rules, 

unchanged, from section 35.37 to section 35.41. 

 180 Avista Corporation, 87 FERC ¶ 61,223, order on reh’g, 89 FERC ¶ 61,136 

(1999). 
Docket No. RM04-7-000 - 125 - 

8. Section 35.42 Market-Based Rate Tariff 

209. This proposed provision imposes the requirement that each seller (or its corporate 

parent) have on file with the Commission the market-based rate tariff that is appended 

hereto at Appendix A.

9. Section 35.43 Change in Status Reporting Requirement

210. This section incorporates the provision currently found at subsection 35.27(c), 

which was codified by Order No. 652. No modifications to the existing language are 

proposed. We seek comment on whether any changes are warranted. 

IV. Information Collection Statement

211. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection and data retention requirements imposed by agency 

rules.181 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 proposes 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. 

 181 5 CFR § 1320.11 (2005). 
Docket No. RM04-7-000 - 126 - 

212. The Commission has previously required utilities seeking market-based rate 

authority to file a market power analysis with the Commission; the Commission now 

proposes to codify that requirement in the Commission’s regulations. This proposal 

reflects the Commission’s existing practice and will not impose any additional burden, 

with the following exception. 

213. Section 35.27(a) of the Commission’s regulations 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 

generation owned or controlled by an applicant for market-based rate authority and its 

affiliates in the relevant control area is post-July 9, 1996 generation, such applicant is not 

required to submit a generation market power analysis. In this NOPR, the Commission 

proposes to eliminate the express exemption provided in section 35.27(a). This proposal 

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 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 market-based rate 

authority. Because the Commission allows an applicant to make simplifying 

assumptions, where appropriate, and therefore to submit a streamlined analysis, any 

burden of document preparation occasioned by the proposed elimination of section 

35.27(a) should be minimal. Moreover, any burden of document preparation caused by 
Docket No. RM04-7-000 - 127 - 

the proposed elimination of section 35.27(a) should apply for the most part only with 

regard to generation market power analyses required to support an initial application for 

market-based rate authority. 

214. The second filing requirement proposed in this NOPR is that all market-based rate 

sellers file one market-based rate tariff per corporate family. The MBR tariff proposed 

by the Commission is appended to this NOPR. The proposed tariff, coupled with the 

proposed regulations, will simplify the content of MBR tariffs filed with the Commission 

and decrease the burden of document preparation by providing a clearly defined 

statement of the information sought by the Commission. Utilities will only be required to 

fill in the company-specific information, which lessens the burden of drafting 

documentation. A tariff of general applicability will also give the Commission 

consistency on review and clarity regarding the connections between parent and affiliate 

utilities in its analysis. Although the requirement to file the specified MBR tariff may 

cause a minimal burden of document preparation and organization for existing marketbased rate sellers, long-term benefits will be realized for utilities as well as the 

Commission. 

215. To retain market-based rate authority, the Commission currently requires that 

sellers file a triennial review. In this NOPR, the Commission proposes to codify the 

requirement that certain sellers with market-based rate authority file a triennial review 

with the Commission to retain that authority. However, the Commission proposes that 

certain smaller utilities, Category 1 sellers, be relieved of their existing duty to file the 
Docket No. RM04-7-000 - 128 - 

triennial review. Thus, larger sellers will not face a greater burden to provide the 

Commission with the information required for a triennial review, and the burden of 

supplying the updated analysis may be eliminated for certain smaller entities seeking to 

retain market-based rate authority. 

216. 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 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, triennial reviews, 

and reporting requirements for changes in status for public utilities with market-based 

rate authority. 

217. The Commission is submitting these reporting and records retention requirements 

to OMB for its review and approval under section 3507(d) of the Paperwork Reduction 

Act.182 Comments are solicited 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. 

 182 44 U.S.C. § 3507(d) (2000). 
Docket No. RM04-7-000 - 129 - 

Burden Estimate: The Public Reporting and records retention burden for all four 

proposed reporting requirements and the records retention requirement is as follows.183

Title: Electric Rate Schedule Filings (FERC-516). 

Action: Revised Collection. 

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 

650184 217 6 3,900 

Triennial 

Review 

Category 1185

0 0 0 0 

Triennial 

Review 

600 200187 250 50,000 

 183 These burden estimates apply only to this NOPR and do not reflect upon all of 

FERC-516. 

184 The number of respondents for market-based rate tariffs is expected to be 650. 

The figure 217 represents 650 respondents, per year, over the course of 3 years. Also, the 

650 figure takes into account that parent companies will file for their affiliates. 

185 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 or control transmission facilities, and must present no other vertical market 

power issues. The zero in this section represents that Category 1 Sellers are not 

responsible for filing triennial updates. 
Docket No. RM04-7-000 - 130 - 

Category 2186

Totals 

Total Annual hours for Collection: (Reporting + record retention, (if appropriate)= 

hours. 

Information Collection Costs: The total annual cost for Initial Market Power Analysis is 

estimated to be $2,340,000. Total annual cost for market-based rate tariffs is projected to 

be $195,300. Total annual cost for Triennial Reviews 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. 

 186 Category 2 Sellers are any sellers not in Category 1. 

187 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 - 131 - 

MBR Tariff: A MBR tariff for each corporate family with all current sellers to be filed 

with the Commission after the final rule is effective. In the future, a MBR tariff will be 

filed occasionally by each utility newly seeking market-based rate authority. 

Triennial Review: Updated market power analysis filed every three years for Category 2 

sellers seeking to retain market-based rate authority.188

Necessity of the Information 

Market Power Analyses: Consistent with current practices, the market power analysis 

aids the Commission in determining whether an entity seeking market-based rate 

authority lacks market power and permits a determination that sales by that entity will be 

just and reasonable. 

MBR Tariff: A market-based rate tariff filed for each corporate family, with all affiliates 

with market-based rate authority separately identified in the tariff, would improve the 

efficiency of the Commission in its analysis and determination of market-based rate 

authority. The MBR Tariff would allow the Commission to have a clear definition of the 

relationships between parent and affiliate utilities in assessing market-based rate authority 

and/or the investigation thereof. This will allow for better transparency with regard to 

what sellers each corporate family has, and a more customer friendly tariff. A tariff of 

 188 Certain smaller entities (Category 1 sellers) are proposed to be exempted from 

this requirement. 
Docket No. RM04-7-000 - 132 - 

general applicability will also reduce document preparation time overall and provide 

utilities with the clearly defined expectations of the Commission. 

Triennial Review: The triennial review allows 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 

proposed by this NOPR and has determined that these collections of information are 

necessary and conform to the Commission’s plans, as described in this order, for the 

collection, efficient management, and use of the required information.189 

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. Comments on the requirements 

of the proposed rule may also be sent to the Office of Information and Regulatory 

 189 See 44 U.S.C. § 3506(c) (2004). 
Docket No. RM04-7-000 - 133 - 

Affairs, Office of Management and Budget, Washington, D.C. 20503 [Attention: Desk 

Officer for the Federal Energy Regulatory Commission]. 

V. Environmental Analysis

218. 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.190 The Commission has categorically excluded certain 

actions from this requirement as not having a significant effect on the human 

environment.191 The actions proposed here fall within the categorical exclusions in the 

Commission’s regulations for rules that are clarifying, corrective, or procedural, or do not 

substantially change the effect of legislation or regulations being amended.192 In 

addition, the proposed rule is categorically excluded as an electric rate filing submitted by 

a public utility under sections 205 and 206 of the FPA.193 As explained above, this 

proposed rule addressing the issue of electric rate filings submitted by public utilities for 

market-based rate authority is clarifying in nature. Accordingly, no environmental 

assessment is necessary and none has been prepared in this NOPR. 

 190 Regulations Implementing the National Environmental Policy Act, Order No. 

486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations Preambles July 

1996-December 2000 ¶ 30,783 (1987). 

191 18 CFR § 380.4 (2005). 

192 See 18 CFR § 380.4(a)(2)(ii). 

193 See 18 CFR § 380.4(a)(15). 
Docket No. RM04-7-000 - 134 - 

VI. Regulatory Flexibility Act Analysis

219. The Regulatory Flexibility Act of 1980 (RFA)194 generally requires a description 

and analysis of rules that will have significant economic impact on a substantial number 

of small entities.195 The proposed rule will be applicable to all public utilities seeking 

and currently possessing market-based rate authority. The Commission finds that the 

regulations proposed here should not have a significant impact on small businesses. 

220. The submission of a market power analysis is currently required of all entities 

seeking authority to sell at market-based rates, and the proposed rule does not alter which 

entities will be required to file these analyses. The proposed rule does not create a new 

reporting requirement. It does, however, propose to expand the scope of the analysis that 

must be submitted for those entities that previously were exempted from preparing a 

generation market power analysis by virtue of 18 CFR 35.27(a). The Commission is 

concerned that the continued use of the section 35.27(a) exemption, in time, would 

encompass all market participants as all pre-July 9, 1996 generation is retired. 

 194 5 U.S.C. §§ 601-12 (2000). 

195 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 (2000). 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 (2004) (section 22, 

Utilities, North American Industry Classification System, NAICS). 
Docket No. RM04-7-000 - 135 - 

Nevertheless, because the Commission allows an applicant to make simplifying 

assumptions, where appropriate, and therefore to submit a streamlined analysis, the 

Commission believes that any additional burden imposed by the proposed elimination of 

the section 35.27(a) exemption will be minimal. Thus, public utilities are currently 

prepared to submit market power analyses and this requirement does not pose a greater 

burden. 

221. The proposed rule requires that each corporate family have on file one MBR tariff 

of general applicability, with all affiliates with market-based rate authority separately 

identified in the tariff. Although this may initially increase the burden of document 

preparation and organization for parent utilities, long-term benefits will be realized that 

reduce burdens on utilities and the Commission. A tariff of general applicability will 

decrease document preparation by providing a clearly defined statement of the 

information sought by the Commission. Moreover, a single tariff for each corporate 

family will reduce the filing burden on utilities. Small entities affiliated with a parent 

utility need not prepare a separate tariff; rather, they will merely add their company name 

to their parent utility’s tariff. Thus, the burden is decreased. 

222. 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 proposed regulations would result in fewer filings with the Commission 

than currently required for qualified smaller utilities’ (Category 1) retention of market-
Docket No. RM04-7-000 - 136 - 

based rate authority. Those who do have to file are able to use short cuts described above 

(i.e., simplifying assumptions). Thus, the proposed rule would be less burdensome 

economically and reduce the frequency of document preparation for market-based rate 

authority retention for qualified smaller utilities. 

VII. Comment Procedures

223. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due [insert date _60__ 

days from publication in the FEDERAL REGISTER]. Reply comments are due 

[insert date 30 days after comment date]. Comments and reply comments must refer 

to Docket No. RM04-7-000, and must include the commenter's name, the organization 

they represent, if applicable, and their address in their comments. Comments and reply 

comments may be filed either in electronic or paper format. 

224. Comments and reply comments may be filed electronically via the eFiling link on 

the Commission's web site at http://www.ferc.gov. The Commission accepts most 

standard word processing formats and commenters may attach additional files with 

supporting information in certain other file formats. Documents created electronically 

using word processing software should be filed in the native application or print-to-PDF 

format and not in a scanned format. This will enhance document retrieval for both the 

Commission and the public. Attachments that exist only in paper form may be scanned. 

Commenters filing electronically should not make a paper filing. Service of rulemaking 
Docket No. RM04-7-000 - 137 - 

comments is not required. Commenters that are not able to file comments and reply 

comments electronically must send an original and 14 copies of their comments to: 

Federal Energy Regulatory Commission, Office of the Secretary, 888 First Street, N.E., 

Washington, D.C., 20426. 

225. All comments and reply comments will be placed in the Commission's public files 

and may be viewed, printed, or downloaded remotely as described in the Document 

Availability section below. Commenters on this proposal are not required to serve copies 

of their comments and reply comments on other commenters. 

VIII. Document Availability

226. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’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. 

227. From the Commission's Home Page on the Internet, this information is available in 

the Commission’s document management system, 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. 

228. User assistance is available for eLibrary and the Commission's website during 
Docket No. RM04-7-000 - 138 - 

normal business hours. For assistance, please contact FERC Online Support at 1-866-

208-3676 (toll free) or (202)502-8222 (e-mail at FERCOnlineSupport@FERC.gov), or 

the Public Reference Room at (202) 502-8371, TTY (202)502-8659 (e-mail at 

public.referenceroom@ferc.gov ). 

List of subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements. 

 By direction of the Commission. 

 Magalie R. Salas, 

 Secretary. 
Docket No. RM04-7-000 - 139 - 

 In consideration of the foregoing, the Commission proposes to amend 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. Section 35.27 is revised 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. 

35.37 Market power analysis required. 

35.38 Mitigation. 

35.39 Affiliate restrictions. 

35.40 Ancillary services. 
Docket No. RM04-7-000 - 140 - 

35.41 Market behavior rules. 

35.42 Market-based rate tariff. 

35.43 Change in status reporting requirement. 

§ 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 at market-based 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; that do not own or control 

transmission facilities (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 or 

controls transmission facilities; that are not affiliated with a public utility with a 

franchised service territory; and that do 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 sites for development of generation, 

fuel inputs such as coal facilities, and the transportation or distribution of inputs to 

electric power production such as gas storage, intrastate gas transportation and 

distribution systems, and rail cars/barges for the transportation of coal. 

 (5) Franchised public utility means a public utility with a franchised service 

obligation under state law and that has captive customers. 

 (6) Non-regulated power sales affiliate means any non-traditional power seller 
Docket No. RM04-7-000 - 141 - 

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. 

 (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. 

§ 35.37 Market power analysis required.

(a) 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. 

 (b) A market power analysis must address whether a Seller has horizontal and 

vertical market power. 

 (c) There will be a rebuttable presumption that a Seller lacks horizontal market 

power if it passes two indicative market power screens: first, a pivotal supplier analysis 

based on the annual peak demand of the relevant market and; second, 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. A Seller that has horizontal 

market power, or that has not rebutted a presumption of horizontal market power, is 
Docket No. RM04-7-000 - 142 - 

subject to mitigation, as described in § 35.38. 

 (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. 

 (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: a description of its affiliation, ownership or 

control of inputs to electric power production; a description of its ownership or control of 

intra-state transportation or distribution of inputs to electric power production; a 

description of its ownership or control of any sites for new generation capacity 

development; and a statement that it cannot erect barriers to entry in the relevant markets. 

§ 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. 

 (b) Default mitigation consists of three distinct products: (i) sales of power of one 
Docket No. RM04-7-000 - 143 - 

week or less priced at the Seller’s incremental cost plus a 10 percent adder; (ii) 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 (iii) 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) 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 public utility Seller with a franchised service territory and a nonregulated power sales affiliate without first receiving Commission authorization for the 

transaction under section 205 of the Federal Power Act. Failure to satisfy this condition 

will constitute a violation of the Seller’s market-based rate tariff. All authorizations to 

engage in affiliate wholesale sales of electricity must be listed in a Seller’s market-based 

rate tariff. 

 (b) Separation of functions.

 (1) For the purpose of this subsection, entities acting on behalf of and for the 

benefit of a franchised public utility (such as entities managing 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 a franchised public utility’s nonregulated power sales affiliates are considered part of the non-regulated affiliated entities. 

(2) To the maximum extent practical, the employees of a non-regulated power 
Docket No. RM04-7-000 - 144 - 

sales affiliate will operate separately from the employees of any affiliated franchised 

public utility. 

 (c) Information sharing.

 All market information shared between a franchised public utility and a nonregulated power sales affiliate will be disclosed simultaneously to 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. Shared employees 

in a support role are not bound by this provision, but they may not serve as a conduit of 

information to non-support personnel. 

 (d) Non-power goods or services.

 (1) Sales of any non-power goods or services by a franchised public utility, 

including sales made to or through its affiliated exempt wholesale generators or 

qualifying facilities, to a non-regulated power sales affiliate will be at the higher of cost 

or market price. 

 (2) Sales of any non-power goods or services by a non-regulated power sales 

affiliate to an affiliated franchised public utility will not be at a price above market. 

 (e) Other.

 (1) To the extent a non-regulated power sales affiliate seeks to broker power for 

an affiliated franchised public utility: 
Docket No. RM04-7-000 - 145 - 

(a) the non-regulated power sales affiliate must offer the franchised public utility’s 

power first; 

(b) the arrangement between the non-regulated power sales affiliate and the 

franchised public utility must be non-exclusive; and 

(c) the non-regulated power sales affiliate may not accept any fees in conjunction 

with any brokering services it performs for an affiliated franchised public utility. 

 (2) To the extent a franchised public utility seeks to broker power for a nonregulated power sales affiliate: 

(a) the franchised public utility will be required to charge the higher of its costs for the 

service or the market rate for such services; 

(b) the franchised public utility will be required to market its own power first, and 

simultaneously make public (on an electronic bulletin board and/or the Internet) any 

market information shared with its affiliate during the brokering; and 

(c) the franchised public utility will post on an electronic bulletin board and/or the 

Internet the actual brokering charges imposed. 

§ 35.40 Ancillary services.

 (a) If a Seller seeks authority to make sales of ancillary services at market-based 

rates, it may offer such services provided the service has been authorized by the 

Commission and only in specific geographic markets as the Commission has authorized. 

 (b) If a Seller is authorized by the Commission to make sales of ancillary services 
Docket No. RM04-7-000 - 146 - 

at market-based rates as a third-party ancillary services provider: 

 (1) Seller shall establish an Internet-based site for providing information 

regarding ancillary services transactions including, prior to making transactions, postings 

of offers of services available and offering prices; procedures under which all customers 

would request service and make bids; postings of the actual transaction prices after the 

transactions are consummated; and accepted and denied requests and the reasons for 

denial. The site should conform to the applicable OASIS Standards and Communications 

Protocols. 

 (c) Seller is not authorized to make sales of ancillary services at market-based 

rates as a third-party ancillary services provider: 

 (1) To a regional transmission organization or an independent system operator 

(other than those ancillary services that are subject to § 35.40(a)) that has no ability to 

self-supply ancillary services but instead depends on third parties; 

 (2) When the underlying transmission service is on the transmission system of a 

transmission provider with whom the Seller is affiliated; or 

 (3) To a public utility who is purchasing ancillary services to satisfy its own Open 

Access Transmission Tariff requirements to offer ancillary services to its own 

transmission customers, unless Seller(s) receives separate authorization by the 

Commission. 

§ 35.41 Market Behavior Rules.
Docket No. RM04-7-000 - 147 - 

 (a) Unit operation. Where a Seller participates in a Commission-approved 

organized market, Seller will 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 power 

market. 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. Seller will 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 Seller engages in reporting of transactions to 

publishers of electric or natural gas price indices, Seller shall provide accurate and 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 shall notify the 
Docket No. RM04-7-000 - 148 - 

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 shall adhere to 

such other standards and requirements for price reporting as the Commission may order. 

 (d) Records retention. Seller shall 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 Market-based rate tariff.

(a) In addition to other requirements in subpart A, every public utility that is 

authorized to sell electric energy at market-based rates pursuant to section 205 of the 

Federal Power Act must have on file with the Commission a tariff of general 

applicability. Such tariff must be the market-based rate tariff contained in Order No. 

___, FERC Stats. & Regs. ¶ 31,___ (Final Rule on Market-Based Rates for Wholesale 

Sales of Electricity by Public Utilities). 

(b) The market-based rate tariff contained in Order No. ___, FERC Stats. & Regs. 

¶ 31,___, must be filed by Sellers who have been granted market-based rate authority 

prior to the issuance of Order No. ______, in accordance with Order No. _____, FERC 

Stats. & Regs. ¶ 31, ___ (Final Rule on Electronic Tariff Filing). A market-based rate 

tariff must be filed by a Seller who is initially seeking market-based rates at the time it 
Docket No. RM04-7-000 - 149 - 

applies for market-based rate authorization. 

 (c) Each corporate family will file a single market-based rate tariff, with all 

affiliates with market-based rate authority separately identified in the tariff. 

§ 35.43 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 transmission facilities or inputs to electric power production other than 

fuel supplies, or 

 (2) Affiliation with any entity not disclosed in the 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. 

 (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. Failure to timely file a change in 

status report constitutes a tariff violation. 
Docket No. RM04-7-000 - 150 - 

Appendix A

Proposed Market-Based Rate Tariff

Market-Based Rate Tariff 

Seller(s) Under This Tariff: Docket No. Authorizing Market-Based Rates: 

ABC, Inc. Docket No. ERXX-XXX-XXX 

XYZ, LLC Docket No. ERXX-XXX-XXX 

Etc. etc. 

1. Availability: Electric energy, capacity and ancillary services are available under 

this tariff for wholesale sales to purchasers with whom seller has contracted. Not all 

services may be available from all sellers listed. 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. 

2. Applicability: This tariff is applicable to all wholesale sales of electric energy, 

capacity and ancillary services by seller. 

3. Rates: All sales shall be made at rates established by agreement between the 

purchaser and seller. 

4. Other Terms and Conditions: All other terms and conditions not listed herein shall 

be established by agreement between the purchaser and seller. 

5. Effective Date: This Rate Schedule is effective on the date of compliance with the 

final rule on Electronic Tariff Filings, Order No. ___, FERC Stats. & Regs. ¶ 31,___. 
Docket No. RM04-7-000 - 151 - 

Market-Based Rate 

Tariff 

Appendix A 

Docket No. Approving Affiliate Sales

Docket No. ERXX-XXX-XXX 

Docket No. ERXX-XXX-XXX 

Etc. 

 Check if Not Applicable 

 

Docket No. Imposing Restrictions on Market-Based Rate Authority

Docket No. ERXX-XXX-XXX 

Docket No. ERXX-XXX-XXX 

Etc. 

 Check if Not Applicable 
Docket No. RM04-7-000 - 152 - 

 Appendix B 

Schedule for Regional Triennial Review Process 

All Category 2 sellers that own or control generation in the California, Northwest, 

Southwest, Midwest, SPP, Southeast, PJM, New York, and New England regions during 

the period specified below (Qualification Period) will file updated market power 

analyses within the filing period specified in the following schedule. Triennial Reviews 

should reflect the most recently available historical data from the calendar year prior to 

the year of filing. The regions are depicted in the map that follows. (Source: Federal 

Energy Regulatory Commission, 2004 State of the Markets Report, staff report prepared 

by the Office of Market Oversight & Investigations, June 2005.) 

Region Qualification Period Filing Period 

PJM 2006 April 1-30, 2007 

New York 2006 July 1-30, 2007 

New England 2006 October 1-30, 2007 

Midwest 2007 April 1-30, 2008 

SPP 2007 July 1-30, 2008 

Southeast 2007 October 1-30, 2008 

California 2008 April 1-30, 2009 

Northwest 2008 July 1-30, 2009 

Southwest 2008 October 1-30, 2009 

PJM 2009 April 1-30, 2010 

New York 2009 July 1-30, 2010 

New England 2009 October 1-30, 2010 

Midwest 2010 April 1-30, 2011 

SPP 2010 July 1-30, 2011 

Southeast 2010 October 1-30, 2011 

California 2011 April 1-30, 2012 
Docket No. RM04-7-000 - 153 - 

Northwest 2011 July 1-30, 2012 

Southwest 2011 October 1-30, 2012 

This review cycle will be repeated in subsequent years. 
Docket No. RM04-7-000 - 154 - 

Appendix C 

Standard Screens Format 

AMOUNTS LISTED ARE FOR ILLUSTRATIVE PURPOSES ONLY 

Pivotal Supplier Analysis 

Supply: Row (MW) Reference 

Applicant's Installed Capacity A 19,500 Workpaper 1 

Applicant’s Long-Term Firm Purchases B 500 Workpaper 6 

Applicant's Long-Term Firm Sales C (1,000) Workpaper 2 

Applicant’s Imports (Limited by Simultaneous Import Capability) D 0 Workpaper 5 

Non-Affiliate Local Installed Capacity E 8,000 Workpaper 1 

Non-Affiliate Long-Term Firm Purchases F 500 Workpaper 6 

Non-Affiliate Long-Term Firm Sales G (2,500) Workpaper 2 

Non-Affiliate Uncommitted Capacity Imports H 

 (Limited by Simultaneous Import Capability) I 3,500 Workpaper 5 

Control Area Reserve Requirement J (2,160) Workpaper 3 

Amount of Line J Attributable to Applicant, if any K (2,160) Workpaper 3 

 L 

 Total Uncommitted Supply (SUM A,B,C,D,E,F,G,I,J,Q) M 9,840 

 N 

Load: O 

Control Area Annual Peak Load P 18,000 Workpaper 4 

Average Daily Peak Native Load in Peak Month Q (16,500) Workpaper 4 

Amount of Line Q Attributable to Applicant, if any R (16,500) Workpaper 4 

S 

 Wholesale Load (-SUM P,Q) T (1,500) 

 U 

 Net Uncommitted Supply (SUM M,T) V 8,340 

 W 

 Applicant's Uncommitted Capacity (SUM A,B,C,K,R) X 340 

 
Docket No. RM04-7-000 - 155 - 

 PASS 
Docket No. RM04-7-000 - 156 - 

AMOUNTS FOR ILLUSTRATIVE PURPOSES ONLY 

Wholesale Market Share Analysis:

 Row Q1 Q2 Q3 Q4 Reference 

 (MW) (MW) (MW) (MW) 

Applicant's Installed Capacity A 19,500 19,500 19,500 19,500 Workpaper 1 

Applicant’s Long-Term Firm Purchases B 500 500 500 500 Workpaper 6 

Applicant's Long-Term Firm Sales C (1,000) (1,000) (1,000) (1,000) Workpaper 2 

Applicant’s Seasonal Average Planned Outages D (4,000) (3,000) (800) (3,500) Workpaper 7 

Applicant’s Imports (Limited by Simultaneous Import Capability) E 0 0 0 0 Workpaper 5 

Average Peak Native Load in the Season F (11,500) (10,000) (12,500) (11,500) Workpaper 8 

Amount of Line F Attributable to Applicant, if any G (11,500) (10,000) (12,500) (11,500) Workpaper 8 

Amount of Line F Attributable to Others, if any H (0) (0) (0) (0) Workpaper 8 

Control Area Reserve Requirement I (1,500) (1,320) (1,560) (1,500) Workpaper 3 

Amount of Line I Attributable to Applicant, if any J (1,500) (1,320) (1,560) (1,500) Workpaper 3 

Amount of Line I Attributable to Others, if any K (0) (0) (0) (0) Workpaper 8 

Non-Affiliate Local Installed Capacity L 8,000 8,000 8,000 8,000 Workpaper 1 

Non-Affiliate Long-Term Firm Purchases M 500 500 500 500 Workpaper 6 

Non-Affiliate Long-Term Firm Sales N (2,500) (2,500) (2,500) (2,500) Workpaper 2 

Non-Affiliate Local Seasonal Average Planned Outages O (800) (200) (300) (400) Workpaper 7 

Non-Affiliate Uncommitted Capacity Imports P 

 (Limited by Simultaneous Import Capability) Q 5,000 4,500 3,500 4,000 Workpaper 5 

 R 

 Total Competing Supply (SUM L,M,N,O,Q,H,K) S 10,200 10,300 9,200 9,600 

 Applicant's Uncommitted Capacity (SUM A,B,C,D,E,G,J) T 2,000 4,680 4,140 2,500 

 Total Seasonal Uncommitted Capacity (SUM S,T) U 12,200 14,980 13,340 12,100 

 V 

 Applicant's Market Share (T/U) W 16.39% 31.24% 31.03% 20.66% 

 PASS FAIL FAIL FAIL 

 
Docket No. RM04-7-000 - 157 - 

Appendix D 

Commenters

Allen Freifeld (Mr. Freifeld) 

Ameren Corporation (Ameren) 

American Electric Power (AEP) 

Alliance Energy Corporate Services, Inc. (Alliance) 

Allegheny Energy, Inc. (Allegheny) 

American Antitrust Institute (American Antitrust) 

American Forest & Paper Association (Forest & Paper) 

American Public Power Association (APPA) 

Analysis Group Inc. (Analysis Group) 

Andrew N. Kleit (Kleit) 

Arizona Public Service Company (APS) 

Bates White, LLC (Bates White) 

Benjamin Hobbs (Dr. Hobbs) 

Bonneville Power Administration (BPA) 

Boston Pacific Company (Boston Pacific) 

California Electricity Oversight Board (California Board) 

California Public Utilities Commission (California Commission) 

Calpine Corporation (Calpine) 

Cinergy Services, Inc. (Cinergy) 

Cogeneration Association of California, Energy Producers and 

Users Coalition, Nevada Independent Energy Coalition, 

March Point Cogeneration and Sumas Energy (CoGen) 
Docket No. RM04-7-000 - 158 - 

Consolidated Edison Company of New York, Inc. (ConEd) 

Constellation Energy Group Inc. (Constellation) 

Consumers Energy Company (Consumers) 

David DeRamus (Dr. DeRamus) 

David S. Portnoy (Mr. Portnoy) 

Duke Energy Corporation (Duke) 

East Texas Cooperatives (East Texas Coop) 

EEI and Alliance of Energy Suppliers (EEI) 

ELCON 

Electric Power Supply Association (EPSA) 

Entergy Services, Inc. (Entergy) 

Federal Trade Commission (FTC) 

FirstEnergy Service Company (FirstEnergy) 

Harquahala Generating Company, LLCC (Harquahala) 

Harvey Reiter (Reiter) 

Independent Energy Producers 

Industrial Consumers (ELCON, AISI, ACC and AF&PA) (Industrial Consumers) 

Industrial Energy Users – Ohio (IEU- Ohio) 

Intergen Service, Inc. (Intergen) 

James B. Bushnell (Dr. Bushnell) 

Joint Consumer Advocates (Advocates) 

John Hilke (Dr. Hilke) 

Julia Frayer (Dr. Frayer) 
Docket No. RM04-7-000 - 159 - 

Kansas City Power & Light Company (Kansas City Power) 

Keyspan-Ravenswood LLC (Keyspan-Ravenswood) 

Lafayette Utilities Systems (Lafayette) 

Louisiana Public Service Commission (Louisiana Commission) 

Maryland Public Service Commission (Maryland Commission) 

Mayflower LP (Mayflower) 

MidAmerican Energy Company (MidAmerican) 

Midwest Municipal Transmission Group (Midwest Municipal Transmission) 

Midwest Stand-Alone Transmission Companies (Midwest Stand-Alone Transmission) 

Montana Consumer Counsel (Montana Counsel) 

Montana Public Service Commission (Montana Commission) 

Morgan Stanley Capital Group, Inc. (Morgan Stanley) 

National Association of Regulatory Utility Commissioners (NARUC) 

National Grid USA (National Grid) 

NRECA 

NRG Energy, Inc. (NRG) 

Pace Global Energy Services, LLC (Pace Global) 

PacifiCorp (PacifiCorp) 

PJM Industrial Customer Coalition (PJM Industrial Consumers) 

Power Systems Engineering, Inc. (Power Systems) 

Powerex Corp. (Powerex) 

Progress Energy, Inc. (Progress Energy) 

Public Utilities Commission of Ohio (Ohio Commission) 
Docket No. RM04-7-000 - 160 - 

Puget Sound Energy (Puget) 

Robert Garvin (Mr. Garvin) 

Schwab Capital Markets, L.P. (Schwab) 

Southern Company Services, Inc. (Southern) 

Susan F. Tierney and Paul J. Hibbard (Tierney & Hibbard) 

The PSEG Companies (PSEG) 

Tractebel Energy Marketing, Inc. (Tractebel) 

Transmission Access Policy Study Group (TAPS) 

Transmission Dependent Utility Systems (TDU Systems) 

Utility Economic Engineers (Economic Engineers) 

Virginia State Corporation Commission (Virginia Commission) 

Wisconsin Electric Power Company (Wisconsin Electric) 

Wisconsin Public Service Commission (Wisconsin Commission) 

Xcel Energy Services Inc. (Xcel) 
Docket No. RM04-7-000 - 161 - 

Appendix E 

Summary of Comments 

1. Horizontal Market Power

The Commission convened two technical conferences on June 9, 2004 and January 27, 

2005, to consider whether, and to what extent, the Commission should modify the interim 

generation market power screens and the appropriate mitigation for those sellers found to 

have generation market power. Among the specific issues that the Commission 

considered was the application of the generation market power screens, including the 20 

percent threshold, the application of the DPT or other alternatives for measuring 

generation market power, extending the market power screens to cover capacity and 

generation based ancillary services and retention of the section 35.27 (a) exemption 

of generation units built after July 9, 1996 from the requirement to demonstrate a lack of 

generation market power. The technical conference also considered issues regarding 

regional geographic markets and other mitigation the Commission should consider. 

1. After the technical conferences, the Commission invited all interested parties to 

submit comments. Many parties submitted comments. 

a. Indicative Screens

(i) Relevant Market
Docket No. RM04-7-000 - 162 - 

2. Many investor-owned utilities (IOUs) oppose the Commission’s use of control 

areas as the default geographic market outside of RTO/ISOs.196 IOUs state that the 

Commission should detail the technical criteria and data needed that will be used to judge 

whether the screens can be based on a regional market.197 Virginia Commission states 

that the Commission should analyze the actual physical characteristics of a transmission 

system, including any transmission constraints, when determining the relevant 

geographic market, and that sellers should not be able to use the RTO/ISO footprint as 

the default relevant geographic market.198 BPA suggests that sellers should be permitted 

to include specific references and quantitative estimates of any capacity limitations that 

result from operational constraints which would further limit marketing discretion and the 

seller’s potential to exercise market power.199 

(ii) Native Load

3. Ohio Commission states that the screens should take into account the level of 

market concentration and the other obligations that the seller must meet, such as the 

 196 Cinergy Comments (March 14, 2005) at 9-10; PacifiCorp Comments (March 

14, 2005) at 2; and Puget Comments (March 14, 2005) at 1-5. 

197 Puget Comments (March 14, 2005) at 2, 3, 8. 

198 Virginia Commission Comments (June 30, 2004) at 3; see also APPA 

Comments (June 30, 2004) at 23 and Forest & Paper Comments (June 30, 2004) at 9. 

199 BPA Comments (June 30, 2004) at 4. 
Docket No. RM04-7-000 - 163 - 

native load obligations and any provider of last resort obligations.200 Louisiana 

Commission states that generation that primarily serves retail load should be excluded 

from the analysis, and AEP states that the screens are flawed because they do not 

consider the seller’s own load and many firm transmission service reservations as well as 

the amount of non-seller load required to serve the market.201

4. APPA and others present an opposing view. APPA states that the screens should 

not use uncommitted capacity, and that alternatively the Commission should narrow 

deductions of capacity and load that are in the wholesale market and require the 

submission of contracts to support the legitimacy of such deductions.202 Bates White 

agrees that native load should not be excluded and that to do so is inconsistent with the 

analysis in section 203 proceedings.203 Montana Counsel states that generation suppliers 

should not be able to deduct capacity reserved for other utilities’ native load.204 Some 

commenters note that there is no way to perfectly account for native load, so only supply 

that has not been excluded from the analysis as native load should be allowed to be sold 

 200 Ohio Commission Comments (June 30, 2004) at 3-4; see also Cinergy 

Comments (March 14, 2005) at 17. 

201 Louisiana Commission Comments (June 30, 2004) at 2; AEP Comments (June 

30, 2004) at 15. 

202 APPA Comments (June 30, 2004) at 22; see also Intergen Comments (July 1, 

2004) at 4. 

203 Bates White Comments (June 30, 2004) at 3-4. 

204 Montana Counsel Comments at 4. 
Docket No. RM04-7-000 - 164 - 

at market-based rates.205 Other ideas included allowing sellers to deduct the minimum 

load overall, not just the minimum peak day load.206

(iii) Screen Modifications

5. Independent power producers and transmission dependent utilities (IPPs/TDUs) 

and Industrial Consumers expressed general support for the current screens. NRECA 

argues that the pivotal supplier screen is ineffective and should be revised particularly 

with regard to the native load and operating reserve deductions.207 NRECA states that the 

market share screen does a better job of identifying potential market power than the 

pivotal supplier, but that the 20 percent threshold is too high.208 AEP argues that 

unreasonably high levels of supply are necessary for vertically-integrated utilities to have 

less than 20 percent market share, and Southern states that the threshold is very low.209

6. TAPS and American Antitrust argue that the screens should consider prices, not 

just supply and demand.210 Dr. Julia Frayer argues that the Commission should add 

 205 APPA Comments (June 30, 2004) at 22. 

206 Id. at 25. 

207 NRECA Comments (March 14, 2005) at 4. 

208 NRECA Comments (March 14, 2005) at 5; NRECA Comments (June 30, 2004) 

at 14. 

209 AEP Comments (June 30, 2004) at 12; Southern Comments (June 30, 2004) at 

8. 

210 TAPS Comments (June 10, 2004) at 12-13; American Antitrust Comments 

(March 14, 2005) at 9. 
Docket No. RM04-7-000 - 165 - 

context to the pivotal supplier screen by defining the market conditions or considering the 

pivotal supplier screen over multiple years, including any expected changes in supply and 

demand.211 American Antitrust states that the pivotal supplier screen should not be used 

as it does not accurately capture the potential for a seller to exercise market power.212 

APPA states that the pivotal supplier screen should be based on monthly peaks instead of 

just a single annual peak month, the wholesale market share screen should be based on 

the minimum load and not the minimum peak load, the HHI concentration measure 

should be incorporated in the market share screens, the DPT threshold should be reduced 

to 1,800, and/or the market share threshold should be reduced to 15 percent.213 EEI states 

that the native load proxy in the market share screen overstates the generation capacity 

available to the applicant for wholesale market sales and that instead of using the lowest 

seasonal daily peak demand to represent the supplier’s native load obligation, alternative 

native load proxies should be considered.214

7. Dr. James B. Bushnell and American Antitrust comment that false positives may 

occur because the screens do not appropriately account for supply contracts and retail 

obligations, and that the market share screen needs to be altered if it is retained, adjusting 

 211 Dr. Frayer Statement (January 27, 2005). 

212 American Antitrust Comments (March 14, 2005) at 6-7. 

213 APPA Comments (June 30, 2004) at 23. 

214 EEI Comments (March 14, 2005) at 7-8. 
Docket No. RM04-7-000 - 166 - 

the threshold levels to consider market concentration in unconcentrated, moderately 

concentrated, and highly concentrated markets as set forth in the horizontal merger 

guidelines.215 Some state regulators state that the Commission should eliminate the 

prohibition on the use of forward-looking data.216 Some commenters note that the 

Commission should look into administering the screens on a regional basis.217

 (iv) Alternative Analysis

8. IOUs state that the Commission should adopt a regional approach to its 

assessment thereby promoting efficiency and consistency of data collection and analysis 

among the sellers.218 PacifiCorp suggests that a permanent replacement for the interim 

screens should include a clearly defined regional market or markets for the West.219 EEI 

proposes a contestable load analysis220 under which a seller failing either of the indicative 

screens would be given the opportunity to file at the time of the application to 

 215 Dr. Bushnell Comments (March 14, 2005) at 3; American Antitrust Comments 

(March 14, 2005) at 8. 

216 See, e.g., California Board Comments (March 14, 2005) at 5. 

217 EEI Comments (March 14, 2005) at 29-31; APPA and TAPS Comments 

(June 13, 2005) at 4. 

218 PacifiCorp Comments (June 30, 2004) at 4-5. 

219 PacifiCorp Comments (March 14, 2005) at 5. 

220 The contestable load analysis focuses on the historical relationship between the 

wholesale loads that were actually seeking supply alternatives (contestable loads) and the 

resources other than those of the control area operator that were available to serve those 

loads.
Docket No. RM04-7-000 - 167 - 

demonstrate that the seller does not have generation market power.221 FTC argues that 

the contestable load analysis is not economically sound, suffers from substantial defects 

and should not be relied upon to assess horizontal market power, stating that it fails to 

consider price, contractual and legal restrictions, transmission discrimination and 

transmission constraints.222 Some commenters223 are opposed to a contestable load 

analysis because it is so loosely prescribed that it would almost surely result in noncomparable, inconsistent results in the hands of different sellers, that it would most likely 

understate sellers’ market power and eliminate from the screens any means of measuring 

the potential for coordinated behavior.224 APPA suggests adding an HHI/concentration 

screen, using different metrics to measure collusion risks, requiring the seller to conduct 

the pivotal supplier screen on a monthly basis, and lowering the HHI component of the 

DPT from 2,500 to 1,800.225 

9. Several state regulators support the use of simulation models as a tool for 

detecting collusion among several market participants or inaccurate uncommitted 

 221 EEI Comments (March 14, 2005) at 15. 

222 FTC Comments (January 18, 2006) at 1-11. 

223 APPA Comments (March 14, 2005) at 2; American Antitrust Comments 

(March 14, 2005). 

224 NRECA Comments (March 14, 2005) at 5.

225 APPA Comments (March 16, 2005) at 3. 
Docket No. RM04-7-000 - 168 - 

capacity calculations.226 IOUs state that the Commission should not rely on market 

simulation models. APPA argues that simulation models may have a role, but the 

Commission should not make any such model its sole assessment tool.227 Dr. Bushnell 

states that the Commission should consider the use of an oligopoly simulation model, 

which would use a residual demand curve to test the market power of a given firm, which 

can be very useful in detecting potential market power with data requirements no more 

extensive than what is required for the screens.228 Dr. Frayer argues that the Commission 

should also consider pricing behavior in its analysis, use a residual demand analysis, that 

the DPT should be refined to describe the market concentration of the capacity that would 

be price-setting, and should consider the hypothetical monopolist or “SSNIP” test.229 

 b. Procedural Issues

10. APPA and NRECA state that the Commission should allow intervenors more time 

to review and analyze the information and screen results provided by sellers and more 

time to submit rebuttal evidence such as their own DPT.230 They suggest that the 

Commission allow 60 days for comments on the market screen analyses and the DPT and 

 226 See, e.g., California Commission Comments (March 14, 2005) at 4. 

227 APPA Comments (June 30, 2004) at 18. 

228 Dr. Bushnell Comments (June 30, 2004) at 3. 

229 Dr. Frayer Comments (January 27, 2005) at 8-10. 

230 APPA Comments (March 14, 2005) at 22. 
Docket No. RM04-7-000 - 169 - 

add that the Commission should require the regular reporting of generation and 

transmission data needed to perform the screens.231 Tractebel states that sellers should be 

required to submit filings in standard formats so that the filings are easily comparable.232 

APPA states that too much data is designated as Critical Energy Information 

Infrastructure (CEII).233 PacifiCorp argues that the Commission should allow each 

affiliate to pass or fail the screens on its own, without being aggregated with the other 

affiliates.234

11. Intergen states that the burden should be on sellers to prove that there is some 

compelling reason, such as reliability, to permit the seller to hold market-based rate 

authority or to provide appropriate remedial action to address any problems that may 

arise.235 Forest & Paper expresses concern about false negatives produced by the 

indicative screens, and states that the rebuttable presumption improperly shifts the burden 

of proof from the seller to intervenors who may lack access to confidential data and the 

necessary resources to conduct elaborate and detailed market power studies. 236 

 231 NRECA Comments (June 30, 2004) at 6. 

232 Tractebel Comments (January 26, 2005) at 3. 

233 APPA and TAPS Comments (March 16, 2005) at 3. 

234 PacifiCorp Comments (June 30, 2004) at 5. 

235 Intergen Comments (July 1, 2004) at 2.

236 Forest & Paper Comments (June 30, 2004) at 5, 7-8. 
Docket No. RM04-7-000 - 170 - 

 2. Vertical Market Power (Transmission and Other Barriers to Entry)

12. The Commission at the June 9, 2004 and December 7, 2004 technical conferences 

considered the issue of whether the Commission’s pro forma OATT adequately mitigates 

transmission market power, as well as other proposals to identify and mitigate 

transmission market power. Specifically, the Commission examined the definition of 

transmission market power, how transmission market power could be used to foreclose 

competition, impact consumer and power supplier interests, how to differentiate between 

the exercise of transmission market power and legitimate reliability-driven denial of 

access, and other methods to screen for transmission market power and mitigate or 

eliminate transmission market power. The technical conference also addressed issues 

related to what other barriers to entry the Commission should consider in evaluating 

applications for market-based rate authority. Specifically, the conference discussed the 

effect that the lack of competition in fuel or other inputs could have on possible entry into 

the generation business, possible monopolization of future generating sites, and potential 

financial constraints such as competitors’ creditworthiness or access to capital, that the 

Commission should consider in evaluating applications for market-based rate authority. 

After the technical conference, the Commission requested written comments from all 

interested parties. 

 a. Transmission

13. Several IOUs, including Duke, Southern, and FirstEnergy, assert that the OATT 

and various other rules are sufficient to mitigate transmission market power and that the 
Docket No. RM04-7-000 - 171 - 

Commission should continue to rely on these unless there is substantial evidence that 

suggests widespread non-compliance/systemic violation of these standards.237 

MidAmerican asserts that if transmission limitations are restricting access to competitive 

supplies, this will be reflected in the Commission’s current market power screens.238 In 

addition, Cinergy suggests that the Commission retain the presumption that transmissionowning sellers do not possess transmission market power if the seller has an OATT on 

file or the seller’s transmission is under the control of an ISO or RTO.239 Cinergy also 

states that if some form of discrimination occurs in violation of the terms of open access 

transmission service, this is best addressed in the context of the OATT.240

14. Conversely, several other commenters state that the OATT is not sufficient to 

mitigate transmission market power and offer suggestions to help alleviate transmission 

market power, including the following: 

a. Promoting best available transmission practices 

b. Independent regional structures 

c. Transmission planning and expansion and a reduction in congestion 

d. Continuing to develop capacity markets 

 237 See, e.g., Southern Comments (January, 1, 2005) at 12; Duke Comments 

(January 1, 2005) at 2; FirstEnergy Comments (January 21, 2005) at 6. 

238 MidAmerican Comments (January 21, 2005) at 13. 

239 Cinergy Comments (March 14, 2005) at 18. 

240 Id. at 18-19. 
Docket No. RM04-7-000 - 172 - 

e. Requiring transmission owners to plan and construct the system as required by 

the OATT’s requirements 

f. Requiring transmission owners to interconnect with others 

g. Clarifying rollover rights 

h. Tying the grant of market-based rate authority to the willingness of the 

transmission owner to make upgrades and jointly plan with network customers.241

15. Similarly, several commenters identify the following transmission-related issues 

as barriers to entry:242

a. Transmission constraints 

b. Transmission service denials 

c. Interconnection and transmission discrimination 

d. Transmission planning and expansion 

e. Withholding transmission capacity through thermal loading calculations and 

operational practices. 

f. Monopsony power 

g. Customer foreclosure, which prevents the customer from being able to reach 

additional sources of power 

h. Allocation of all firm transmission rights to the incumbent IOUs 

 241 See, e.g., EPSA Comments (January 21, 2005) at 8-10; Mayflower Comments 

(January 21, 2005) at 12; TAPS and Midwest Municipal Transmission Written Statement 

(December 7, 2004) at 9; Transcript, December 7, 2004 at 28 (Boston Pacific); Transcript 

December 7, 2004 at 25 (NRECA); TAPS Comments (January 21, 2005) at 3. 

242 Transcript, June 9, 2004 at 62-63 (Dr. Hilke); Transcript, June 9, 2004 at 180 

(Calpine); Transcript, December 7, 2004 at 14-18 (TAPS and Midwest Municipal 

Transmission); Transcript, June 9, 2004 at 108-114 (EPSA); Transcript, June 9, 2004 at 

89 (Boston Pacific). 
Docket No. RM04-7-000 - 173 - 

16. Calpine and PSEG state that the Commission may wish to consider applying a 

presumption that if a seller requests market-based rate authority and is not a member of 

an RTO or an ISO, it is has transmission market power.243 Calpine asserts that the mere 

existence of an OATT is not sufficient to ensure that a vertically integrated utility cannot 

exercise transmission market power but that ceding control of transmission functions to 

an ISO or RTO or having its transmission market power mitigated by having its OASIS 

administered by an independent entity mitigates its transmission market power.244 

17. EEI states that effective wholesale competition needs a robust and reliable 

transmission infrastructure245 and further that fair and open access to transmission in nonRTO markets can be achieved through state and Commission efforts, such as independent 

transmission administrators, or transmission companies, and market monitors.246 Dr. 

John Hilke (Dr. Hilke) similarly suggests that the Commission use membership in an 

approved and fully operating RTO or ISO as its initial transmission market power screen 

in evaluating market-based rate applications.247 National Grid encourages the 

Commission to continue to expand its ongoing efforts to promote independent 

 243 Calpine Comments (June 30, 2004) at 7; PSEG Comments (June 30, 2004) at 8. 

244 Id. at 3, 8. 

245 EEI Comments (January 21, 2005) at 7. 

246 Id. at 5. 

247 Transcript, December 7, 2004 at 10 (Dr. Hilke). 
Docket No. RM04-7-000 - 174 - 

transmission.248 The California Commission also supports the establishment of an 

independent market monitor in all transmission markets and further states that proposed 

transmission upgrades for potential discrimination in the siting of new or additional 

facilities should be examined. East Texas Coop states that where transmission market 

power exists, market-based rate authority must be revoked unless the utility turns its 

planning functions over to an independent entity.249 PacifiCorp suggests that any 

additional measures the Commission imposes to mitigate transmission market power 

must apply to all transmission owners, not just those seeking market-based rate 

authority.250

18. Midwest Stand-Alone Transmission and Midwest Municipal Transmission state 

that structural solutions, such as the formation of stand-alone transmission companies 

and/or joint transmission systems, should be encouraged.251 East Texas Coop agrees that 

stand-alone transmission companies are a promising structural remedy.252

 248 National Grid Comments (June 30, 2004) at 4. 

249 East Texas Coop Comments (January 21, 2005) at 7. 

250 PacifiCorp Comments (January 21, 2005) at 2, 8. 

251 Midwest Stand-Alone Transmission Comments (January 21, 2005) at 9; 

Midwest Municipal Transmission Comments (December 7, 2004) at 10; Midwest StandAlone Transmission Written Statement (December 13, 2004) at 4. 

252 East Texas Coop Comments (January 21, 2005) at 15. 
Docket No. RM04-7-000 - 175 - 

19. APPA argues there should be better enforcement of the Network Integration 

Transmission Service portion of the OATT, as well as increased diversification of 

ownership of the transmission system, and that market-based rate authorizations of such 

dominant transmission providers should be conditioned upon their participation in an 

inclusive regional transmission planning process.253

20. FirstEnergy, EEI, and Joint Consumer Advocates state that there is a need for the 

construction of new transmission facilities and that the Commission should focus on 

ways to encourage investment in new energy infrastructure as a way of easing 

congestion, perhaps through an RTO.254 National Grid advises the Commission to 

consider the expansion of the capability of the transmission grid as the best long-term 

solution to uncompetitive market conditions in generation.255

21. Xcel argues that the OATT should be modified to clarify and facilitate joint 

planning activities.256 Dr. Benjamin Hobbs states that to address the challenges of 

transmission planning in wholesale power market environments, a transmission benefits 

methodology can be developed, such as the California ISO’s Transmission Economic 

 253 APPA Comments (January 21, 2005) at 2; APPA Written Statement 

(December 7, 2004) at 3, 7. 

254 FirstEnergy Comments (January 21, 2005) at 9; EEI Presentation (December 8, 

2004) at 5; Joint Consumer Advocates Comments (January 21, 2005) at 5. 

255 National Grid Comments (June 30, 2004) at 3. 

256 Xcel Comments (January 21, 2005) at 7. 
Docket No. RM04-7-000 - 176 - 

Assessment Methodology, which is a set of economic and risk analysis procedures that 

attempt to respond to the requirements of the new planning environment by explicitly 

quantifying the market power mitigation benefits of reinforcements.257 APPA states that 

the Commission should encourage transmission providers to offer their network 

customers the opportunity to jointly own transmission facilities.258 NRECA states that 

the Commission should develop transmission market power screens and consider making 

incremental changes to the OATT to better mitigate transmission market power.259 

22. TDU Systems state that the OATT has been insufficient to mitigate the exercise 

of transmission market power and state that addressing the problem of transmission 

constraints is critical to a long-term structural solution to wholesale electricity market 

power problems.260

23. Midwest Municipal Transmission also comments that the Commission should 

further deny market-based rate authority to transmission owners that have not remedied 

congestion.261 TAPS further asserts that where there is a lack of available transmission 

 257 Dr. Hobbs Presentation (December 7, 2004) at 1. 

258 APPA Comments (January 1, 2005) at 2. 

259 NRECA Comments (January 21, 2005) at 4. 

260 TDUs Comments (June 30, 2004) at 10-12. 

261 Midwest Municipal Transmission Comments (December 7, 2004) at 11. 
Docket No. RM04-7-000 - 177 - 

capacity (ATC), market-based rates should not be allowed.262 Mayflower argues that a 

monopoly provider has market power and should be given the opportunity to rebut the 

presumption of market power by showing they have successfully implemented or 

emulated competitive markets.263

 b. Other Barriers to Entry

24. Most commenters favor continued examination of other barriers to entry as part of 

market-based rate authorization, although some also recommend various modifications to 

the scope of the analysis and methods for assessment.264 EEI comments that the 

Commission has rightly focused on the ability of a seller to erect barriers, but that there is 

little evidence that barriers to entry are a major problem.265 EPSA asserts that barriers to 

entry can have a large impact on the competitiveness of a market but that this is an area 

of the Commission's analysis that has not been well-litigated or well-explained and where 

the industry needs more guidance as to what it takes to satisfy this prong of the 

Commission's four-prong analysis.266 APPA argues that the Commission’s other barriers 

 262 TAPS Comments (January 21, 2005) at 2. 

263 Mayflower Comments (January 21, 2005) at 7, 8. 

264 One commenter recommends consolidating and subsuming the existing four 

prongs into analyses focused on vertical and horizontal market power. American 

Antitrust Transcript (June 9-10, 2004) at 160. 

265 Transcript, June 9-10, 2004 at 51 (EEI). 

266 Transcript, June 9-10, 2004 at 117-118 (EPSA). 
Docket No. RM04-7-000 - 178 - 

to entry analysis is inappropriately restricted to barriers the seller can create and that 

granting the privilege of market-based rate authority should depend upon evaluating the 

existing entry barriers regardless of who created them. 267 TAPS argues that state-created 

legal barriers are an effective barrier to entry, citing restrictions governing the 

municipalities to which the Florida Municipal Power Agency (FMPA) can sell and in 

which time period, which TAPS states also has the effect of preventing FMPA from 

being an “anchor tenant” for merchant generation.268 

25. Some commenters suggest that the Commission consider other barriers to entry 

that have not been previously considered. Bates White and American Antitrust propose 

that the Commission consider monopsony power as a barrier to entry. They state that a 

dominant buyer in a market can exercise monopsony power by refusing to buy from 

rivals; a rival will not enter the market if there is no demand for its output.269 Mr. David 

S. Portnoy suggests that counterparty credit terms for transactions can serve as a barrier 

to entry because sellers with lower credit quality may only be able to sell in short-term 

markets because of credit demands from counterparties, which are not uniform.270 Also, 

 267 Transcript, June 9-10, 2004 at 137 (TAPS); Transcript, June 9-10, 2004 at 34 

(APPA). 

268 Id. 

269 Transcript, June 9-10, 2004 at 9 (Bates White); Transcript, June 9-10, 2004 at 

162 (American Antitrust). 

270 David S. Portnoy Comments (January 21, 2005) at 3-4. 
Docket No. RM04-7-000 - 179 - 

Mayflower notes that the requirement that some IPPs post credit as a condition of 

transacting raises barriers to entry concerns.271 

26. Several commenters offer recommendations for the assessment criteria for the 

other barriers to entry prong as it relates to defining the relevant market for a market 

power analysis. American Antitrust encourages the Commission to consider the 

guidelines approach employed by the DOJ/FTC 1992 Merger Guidelines,272 which 

considers market share, ease of entry, and countervailing efficiencies. It submits that 

adopting more consistent guidelines would ease controversy over control area versus load 

pocket versus regional market analysis tension by introducing correct metrics for 

assessing participation in the market including time differentiated products and defining 

product markets.273 EPSA states that to the extent that the native load exemption is 

included in the generation market power analysis, the opportunities for erecting barriers 

to entry are heightened.274 

27. Others propose ways to detect when a barrier to entry has been raised and ways to 

initially screen for other barriers to entry. Calpine proposes that to detect whether a 

 271 Mayflower LP Comments (January 21, 2005) at 37. 

272 US Department of Justice and Federal Trade Commission, Horizontal Merger 

Guidelines, 57 FR 41,552 (1992), revised, 4 Trade Reg. Rep. (CCH) ¶ 13,104 (April 8, 

1997). 

273 Transcript, June 9-10, 2004 at 166-167 (American Antitrust). 

274 Transcript, June 9-10, 2004 at 118 (EPSA). 
Docket No. RM04-7-000 - 180 - 

utility’s access to the best generating sites constitutes an improper barrier to entry, the 

Commission can evaluate whether the utility provided a site to an affiliate at terms and 

conditions that are significantly different or cheaper than what one would expect them to 

provide to third parties.275 More broadly, Dr. Hilke states that ISO/RTO membership and 

compliance with generation connection standards should be part of the initial screen for 

barriers to entry.276

3. Affiliate Abuse

 a. Sales Restrictions

28. In connection with the January 27 and 28, 2005 technical conference, the 

Commission asked whether its current regulations and enforcement are adequate to 

address affiliate abuse and whether there are other factors the Commission should 

consider when granting market-based rate authority. Among other things, the 

Commission asked what the focus of the its affiliate abuse policies should be (protecting 

competition in the wholesale market; wholesale captive customers only; or wholesale and 

retail captive customers); whether the Edgar criteria are effective in mitigating and 

preventing affiliate abuse; and whether competitive solicitations are a feasible and 

reasonable means to ensure a level playing field. 

 275 Transcript December 7, 2004 at 182 (Calpine). 

276 Transcript, December 7, 2004 at 12 (Dr. Hilke). 
Docket No. RM04-7-000 - 181 - 

29. Some members of the industry, including Harquahala, the California Commission, 

and PacifiCorp suggest that a competitive solicitation process is an effective and reliable 

way to ensure there is no affiliate preference in the market.277 Several IOUs assert that 

the Commission’s existing affiliate abuse protection standards, including the Edgar

standard, are sufficient to prevent affiliate abuse.278 Harquahala moreover argues that all 

transactions, whether cost-based or market-based, should be held to the Edgar standard. 

Conversely, EEI, National Grid, and the Wisconsin Commission express general 

opposition towards the Commission requiring competitive solicitations and state that the 

Commission should consider state-approved alternatives to competitive solicitations and 

should continue to allow other approaches such as state or regional resource planning that 

involves public and merchant suppliers’ participation.279

30. The FTC and the Maryland Commission assert that an independent market 

monitor or evaluator is imperative to a competitive environment.280 Similarly, several 

commenters state that separate independent review by a regional or local monitor on an 

 277 See, e.g., Harquahala Comments (January 21, 2005) at 2-3; California 

Commission Comments (March 14, 2005) at 3-4; PacifiCorp Comments (June 30, 2004) 

at 12. 

278 See, e.g., Southern Comments (March 14, 2005) at 7-10; Constellation 

Comments (March 14, 2005) at 23-25. 

279 See, e.g., EEI Comments (March 15, 2005) at 7-8; National Grid Comments 

(June 30, 2004) at 6-7; Transcript, January 28, 2005 at 14-16 (Wisconsin Commission). 

280 See, e.g., FTC Comments (July 16, 2004) at 15; Transcript, January 28, 2005 at 

136-137 (Maryland Commission). 
Docket No. RM04-7-000 - 182 - 

ongoing basis would yield the best results, and that it is the best way to ensure that a 

market participant is not exercising market power or engaging in affiliate abuse.281 The 

FTC recognizes that the Commission likely will adopt a number of policies regarding 

protection against affiliate abuse and the role of an independent monitor. Accordingly it 

argues that the Commission may want to include compliance with any newly adopted 

policies regarding affiliate abuse as a prerequisite to passing the affiliate abuse screen. It 

further asserts that a utility with a record of violations of any of these policies should 

again bear the burden of proof that it passes the affiliate abuse prong. 282

31. Dr. DeRamus asserts that the Commission has embarked down the right road in 

its approach to analyzing generation market power by setting up indicative screens that 

are used to simply establish a "rebuttable presumption" of market power, or lack thereof. 

He states that it is a procedural device that appropriately balances the competing demands 

for accuracy and expediency and ultimately suggests that the Commission follow a 

similar "rebuttable presumption" approach with respect to affiliate abuse .

283 EEI, 

however, opposes the creation of a rebuttable presumption of affiliate abuse if a seller is 

vertically integrated with ownership and control of transmission, there is no fully 

functioning RTO, there is significant lower-cost capacity from competing generators 

 281 See, e.g., Transcript, January 28, 2005 at 122-123 (Independent Energy 

Producers); Montana Commission Comments (March 14, 2005) at 3. 

282 FTC Comments (July 16, 2004) at 15. 

283 Transcript, January 28, 2005 at 23-24, 26, 29, and 31 (Dr. DeRamus). 
Docket No. RM04-7-000 - 183 - 

within the seller’s control area, the seller continues to dispatch higher cost generation, 

and intervenors have complained.284 

32. National Grid, EEI, and the Wisconsin Commission suggest that the state should 

have primary jurisdiction over affiliate abuse.285 PacifiCorp similarly states that the 

Commission should review an affiliate transaction under the Edgar standard only when 

the applicable state commission declines to review the transaction or lacks the 

jurisdiction to do so.286 Southern asserts that the Commission should not interfere with 

state jurisdiction over resource adequacy. Southern further argues that issuing resource 

adequacy guidelines on a federal level would also be improper because it would likely 

fail to take into account significant regional differences and particular retail needs.287 

Several industry regulators also believe that the Commission should focus on protecting 

captive wholesale customers instead of retail customers. 

33. APPA and TAPS assert that competitive markets will aid the Commission in 

addressing affiliate abuse/self-dealing concerns because a consumer can readily choose a 

 284 See, e.g., EEI Comments (March 15, 2005) at 9. 

285 See, e.g., National Grid Comments (June 30, 2004) at 6-7; EEI Comments 

(June 30, 2004) at 12, 25, and 27-31;and Transcript, January 28, 2005 at 14 and 16 

(Robert Garvin). 

286 PacifiCorp Comments (June 30, 2004) at 12. 

287 Southern Comments (March 14, 2005) at 15-16. 
Docket No. RM04-7-000 - 184 - 

supplier other than the one engaged in abusive behavior if the market is competitive.288 

PJM Industrial Consumers however argue that affiliate abuse can exist even within a 

competitive marketplace. They give examples of what they contend constitutes abuse 

occurring even where each participant’s ability to sell to its affiliate is based on the fact 

that the price is tied to a relevant locational marginal price and they stress that the 

Commission should not just assume these prices are just and reasonable.289 Ameren 

asserts that if the Commission were to adopt policies that place affiliates at a competitive 

disadvantage relative to non-affiliated entities, it would harm the consumers and 

competition.290 Southern and EEI state that a utility’s purchasing and dispatch activities 

are unrelated to affiliate abuse considerations and, in fact, they are unrelated to the 

Commission’s market-based rate analysis because these activities involve a utility’s 

purchases, not its sales.291

34. Many similar comments and arguments were received in Docket No. PL04-6-000, 

which addressed solicitation processes for public utilities. 

 b. Market-Based Rate Code of Conduct

 288 APPA and TAPS Comments (June 30, 2004) at 20-21. 

289 PJM Industrial Consumers Comments (January 21, 2005) at 25-27. 

290 Transcript, January 28, 2005 at 8-10 (Ameren). 

291 See, e.g., Southern Comments (March 14, 2005) at 17-20; EEI Comments 

(March 15, 2005) at 10. 
Docket No. RM04-7-000 - 185 - 

35. In connection with the January 27 and 28, 2005 technical conference, the 

Commission asked, among other things, whether the code of conduct aids in preventing 

affiliate abuse, whether past waivers of the code of conduct have led to instances of 

affiliate abuse, and whether the code of conduct should contain additional provisions. 

Steve Corneli described the code of conduct as important in aligning market participants’ 

interests with competitive results.292 Dr. DeRamus urged that an applicant should not be 

able to "define away" the problem of affiliate abuse by implicitly or explicitly restricting 

its code of conduct293 and called for a “searching inquiry” by the Commission to assess 

whether an applicant's specific code of conduct within the context of the applicant's 

business structure and practices will be effective in preventing affiliate abuse. Allen 

Freifeld said that exemptions from codes of conduct granted by the Commission on the 

basis of a retail rate freeze being in place at the time of the application may be harmful to 

the long-term development of markets.294 EPSA notes that the existence of a corporate 

code of conduct is insufficient and does not eradicate the possibility of affiliate abuse.295 

Mr. Frame notes that when safeguards for customers, such as retail choice and rate 

 292 Transcript, January 28, 2005 at 151 (Corneli). Similarly, Mr. Alan Kelly’s 

comments noted the importance of the code of conduct in ensuring that affiliated 

generators or marketers do not receive preferential access to transmission information. 

Transcript, January 28, 2005 at 6 (Alan Kelley). 

293 Transcript, January 28, 2005 at 23-24 (Dr. DeRamus). 

294 Transcript, January 28, 2005 at 148-49 (Allen Freifeld). 

295 EPSA Comments (March 14, 2005) at 10. 
Docket No. RM04-7-000 - 186 - 

freezes of wholesale customer protection, are in place “the need for a code of conduct or 

strict prohibition of utility-affiliate interaction becomes superfluous.”296

 5. Mitigation

36. The Commission examined issues relating to mitigation as part of the June 9, 

2004 and January 27-28, 2005 technical conferences held in this proceeding. Among the 

issues discussed at the technical conferences were whether the current mitigation for 

horizontal market power was sufficient and what other methods the Commission could 

employ to mitigate horizontal market power. The technical conference also considered 

ways to mitigate vertical market power, among other things. 

37. APPA and TAPS urge the Commission to stand firm and not to retreat from its 

findings regarding the need for the cost-based remedy, note that the mere existence of an 

RTO does not eliminate the need for cost-based rates, and argue that the Commission 

should mitigate the market and not the individual seller.297 Calpine states that the 

Commission should not allow those who fail the screens to propose their own mitigation 

measures, and Forest & Paper suggests that the Commission take a more definitive and 

comprehensive approach in prescribing mitigation measures when sellers fail the screens 

 296 Rodney Frame Comments (March 14, 2005) at 10. 

297 APPA Comments (June 30, 2004) at 16-17. 
Docket No. RM04-7-000 - 187 - 

and DPT.298 Xcel agrees with the appropriateness of establishing caps based on nearby 

markets where it can be demonstrated that the seller does not have market power, 

supports the limitation of mitigation only to wholesale customers that are load-serving 

entities in the relevant market, and opposes the suggestion of imposing an obligation to 

serve.299 EEI argues that the price mitigation should emulate competitive markets and 

not regulated markets and that such price mitigation would avoid the economic 

distortions that would be created by cost-based mitigation. 300 Morgan Stanley argues 

that the Commission should require sellers to adopt integrated remedies that address all 

potential channels through which the seller could exercise market power and that the 

Commission should not allow sellers to adopt the Commission’s default rate except as a 

last resort, since default rates do not address more subtle reasons for, or opportunities to 

exercise, market power.301

6. Implementation Process

38. PacifiCorp urges the Commission to adopt a regional approach to its assessment 

of generation market power. PacifiCorp’s regional approach would identify regional 

 298 Calpine Comments (June 30, 2004) at 11; Forest & Paper Comments (June 30, 

2004) at 14. 

299 Xcel Comments (March 14, 2005) at 2-3. 

300 EEI Comments (March 14, 2005) at 18-19. 

301 Morgan Stanley Comments (March 14, 2005) at 9-10. 
Docket No. RM04-7-000 - 188 - 

markets and evaluate the potential for market power within such regional markets. It 

states that such a regional approach would promote efficiency and consistency of data 

collection and analysis among the applicants.302 While EEI supports retention of the 

control area as the default market, it states that it would support a regional approach 

option for suppliers voluntarily to submit a consolidated application covering a given 

market. According to EEI, the primary potential advantage of using a regional market 

approach would be the cost savings resulting from certifying an entire regional market at 

one time versus continuing the certification process on an individual supplier basis.303 

APPA and TAPS suggest that the Commission synchronize consideration of renewals for 

a specified geographic region, such as a regional reliability council. Among the benefits 

they cite for requiring applicants to simultaneously produce data for the region are 

improved quality and availability of data and development of a more complete picture of 

the market in which the applicants compete. They suggest that further streamlining could 

come from consolidation of reauthorizations of affiliated sellers. APPA and TAPS note 

that a regional approach does not relieve the Commission of its obligations to make a 

fact-based inquiry regarding a specific seller’s potential to exercise market power. 304

 302 PacifiCorp Comments (June 30, 2004) at 4-5. 

303 EEI Comments (March 14, 2005) at 24, 29-31. 

304 APPA and TAPS Comments (March 14, 2005) at 40-42.