123 FERC ¶ 61,055 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

[Docket No. RM04-7-001; Order No. 697-A] 

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

Services by Public Utilities 

(Issued April 21, 2008) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Order on Rehearing and Clarification. 

SUMMARY: In this order on rehearing, the Commission affirms its basic determinations 

in Order No. 697, and grants rehearing and clarification regarding certain revisions to its 

regulations and to the standards for obtaining and retaining market-based rate authority 

for sales of energy, capacity and ancillary services to ensure that such sales are just and 

reasonable. The Commission also clarifies several aspects of the implementation process 

adopted in Order No. 697. 

EFFECTIVE DATE: This rule will become effective [Insert_Date 30 days after 

publication in the FEDERAL REGISTER]

FOR FURTHER INFORMATION CONTACT: 

Debra A. Dalton (Technical Information) 

Office of Energy Market Regulation 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, D.C. 20426 

(202) 502-6253 
Docket No. RM04-7-001 - 2 - 

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
TABLE OF CONTENTS

Paragraph Numbers

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

II. Discussion.................................................................................................................... 16.

A. Horizontal Market Power....................................................................................... 16.

1. Whether to Retain the Indicative Screens........................................................... 16.

2. Indicative Market Share Screen Threshold Levels ............................................ 31.

3. DPT Criteria........................................................................................................ 42.

4. Other Products and Models ................................................................................ 52.

5. Native Load Deduction....................................................................................... 60.

6. Relevant Geographic Market.............................................................................. 68.

7. Use of Historical Data ...................................................................................... 116.

8. Transmission Imports ....................................................................................... 132.

9. Further Guidance Regarding Control and Commitment of Capacity............... 147.

B. Vertical Market Power ........................................................................................ 151.

1. OATT Violations and Market-Based Rate Revocation.................................... 151.

2. Treatment of FTRs............................................................................................ 163.

3. Other Barriers to Entry ..................................................................................... 166.

C. Affiliate Abuse ..................................................................................................... 181.

1. General Affiliate Terms & Conditions ............................................................. 182.

2. Power Sales Restrictions .................................................................................. 223.

3. Market-Based Rate Affiliate Restrictions......................................................... 233.

D. Mitigation............................................................................................................. 260.

1. Cost-Based Rate Methodology......................................................................... 260.

2. Protecting Markets With Mitigated Sellers ...................................................... 294.

E. Implementation Process........................................................................................ 341.

1. Category 1 and 2 Sellers................................................................................... 343.

2. Regional Review and Schedule ........................................................................ 363.

3. Clarifications on Implementation Process........................................................ 373.

4. Market-Based Rate Tariff Clarifications .......................................................... 383.

F. Legal Authority..................................................................................................... 395.

1. Whether Market-Based Rates Can Satisfy the Just and Reasonable Standard 

Under the FPA ....................................................................................................... 395.

2. Consistency of Market-Based Rate Program with FPA Filing Requirements . 435.

3. Whether Existing Tariffs Must Be Found To Be Unjust and Unreasonable, and 

Whether the Commission Must Establish a Refund Effective Date...................... 497.

G. Miscellaneous....................................................................................................... 501.

1. Change in Status ............................................................................................... 501.

2. Third Party Providers of Ancillary Services..................................................... 516.
Docket No. RM04-7-001 ii 

3. Requesting Market-Based Rate Authority for QFs .......................................... 524.

H. Clarifications of the Commission’s Regulations ................................................. 528.

III. Information Collection Statement ........................................................................... 535.

IV. Document Availability ............................................................................................ 536.

V. Effective Date .......................................................................................................... 539.

Regulatory Text 

Appendix A to Subpart H: Standard Screen Format 

Appendix C to Order No. 697-A: Revised Tariff language 

Appendix D to Order No. 697-A: Revised Regional Review Schedule 

Appendix E to Order No. 697-A: Petitioner Acronyms 
123 FERC ¶ 61,055 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Suedeen G. Kelly, Marc Spitzer, 

 Philip D. Moeller, and Jon Wellinghoff.

Market-Based Rates for 

Wholesale Sales of Electric 

Energy, Capacity and Ancillary 

Services by Public Utilities 

Docket No. RM04-7-001 

ORDER NO. 697-A 

ORDER ON REHEARING AND CLARIFICATION 

(Issued April 21 2008) 

I. Introduction

1. On June 21, 2007, the Federal Energy Regulatory Commission (Commission) 

issued Order No. 697,1

 codifying and, in certain respects, revising its standards for 

obtaining and retaining market-based rates for public utilities. In order to accomplish 

this, as well as streamline the administration of the market-based rate program, the 

Commission modified its regulations at 18 CFR part 35, subpart H, governing marketbased rate authorization. The Commission explained that there are three major aspects of 

its market-based regulatory regime: (1) market power analyses of sellers and associated 

conditions and filing requirements; (2) market rules imposed on sellers that participate in 

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

Ancillary Services by Public Utilities, Order No. 697, 72 Fed. Reg. 39,904 (Jul. 20, 

2007), FERC Stats. & Regs. ¶ 31,252 (2007) (Final Rule). 
Docket No. RM04-7-001 -2- 

Regional Transmission Organization (RTO) and Independent System Operator (ISO) 

organized markets; and (3) ongoing oversight and enforcement activities. The Final Rule 

focused on the first of the three features to ensure that market-based rates charged by 

public utilities are just and reasonable. Order No. 697 became effective on September 

18, 2007. 

2. On December 14, 2007, the Commission issued an order clarifying four aspects of 

Order No. 697.2

 Specifically, that order addressed: (1) the effective date for compliance 

with the requirements of Order No. 697; (2) which entities are required to file updated 

market power analyses for the Commission’s regional review; (3) the data required for 

the horizontal market power analyses; and (4) what constitute “seller-specific terms and 

conditions” that sellers may list in their market-based rate tariffs in addition to the 

standard provisions listed in Appendix C to Order No. 697. The Commission also 

extended the deadline for sellers to file the first set of regional triennial studies that were 

directed in Order No. 697 from December 2007 to 30 days after the date of issuance of 

the Clarification Order. 

3. In this order, the Commission responds to a number of requests for rehearing and 

clarification of Order No. 697. In most respects, the Commission reaffirms its 

determinations made in Order No. 697 and denies rehearing of these issues. With respect 

to several issues, however, the Commission grants rehearing or provides clarification. 

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

Ancillary Services by Public Utilities, 121 FERC ¶ 61,260 (2007) (Clarification Order). 
Docket No. RM04-7-001 -3- 

4. For example, the Commission affirms in large part the determinations made in 

Order No. 697 concerning the horizontal market power analysis, including the use of the 

20 percent threshold for the indicative wholesale market share screen and the Delivered 

Price Test (DPT), the use of a 2,500 Hirschman-Herfindahl Index (HHI) threshold for the 

DPT analysis, and the use of the average peak native load as the native load proxy for the 

indicative wholesale market share screen and DPT analysis. The Commission also 

affirms its decision to use a balancing authority area or the RTO/ISO region as the default 

relevant geographic market. Similarly, the Commission affirms the decision that, where 

the Commission has made a specific finding that there is a submarket within an 

RTO/ISO, that submarket should be considered the default relevant geographic market. 

However, the Commission grants rehearing concerning the finding that Northern PSEG is 

a submarket within PJM. On reconsideration, we conclude that we erred in relying on a 

finding of a submarket in a particular proceeding that was subsequently vacated on 

procedural grounds. 

5. In response to requests for clarification concerning existing mitigation in 

RTO/ISOs, the Commission adopts a rebuttable presumption that the existing 

Commission-approved RTO/ISO mitigation is sufficient to address market power 

concerns in the RTO/ISO market, including mitigation applicable to RTO/ISO 

submarkets. However, intervenors may challenge that presumption. Depending on the 

nature of the evidence submitted by an intervenor, the Commission will consider whether 

to institute a separate section 206 proceeding to investigate whether the existing 

RTO/ISO mitigation continues to be just and reasonable. 
Docket No. RM04-7-001 -4- 

6. While the Commission affirms its determination to continue the use of historical 

data and a “snapshot in time approach,” the Commission will consider sensitivity studies, 

on a case-by-case basis, that present clear and compelling evidence that certain changes 

in a market should be taken into account as part of the market power analysis in a 

particular case. 

7. With regard to simultaneous transmission import limit (SIL) studies, the 

Commission clarifies that the use of simultaneous total transfer capability (TTC) in the 

SIL study must properly account for all firm transmission reservations, transmission 

reliability margin, and capacity benefit margin. 

8. The Commission affirms its determinations concerning the vertical market power 

analysis and clarifies that sellers are not required to report on financial transmission 

rights as part of the vertical market power analysis. 

9. The Commission codifies in the regulations at 18 CFR 35.36 a definition of 

“affiliate” for purposes of Order No. 697 based on the definition adopted in the Affiliate 

Transactions Final Rule.3

 In addition, the Commission reiterates in this order a number 

of clarifications that it made in the Affiliate Transactions Final Rule regarding the term 

“captive customers,” the purpose of the definition, and its focus on “cost-based 

regulation.” Among other things, the Commission notes that if a state regulatory authority 

in a retail choice state does not believe that retail customers are sufficiently protected and 

 3 Cross-Subsidization Restrictions on Affiliate Transaction, Order No. 707, 73 FR 

11013 (Feb. 29, 2008), FERC Stats. & Regs. ¶ 31,264 (Feb. 21, 2008) (Affiliate 

Transactions Final Rule). 
Docket No. RM04-7-001 -5- 

that our affiliate restrictions should apply to the local franchised public utility, it may ask 

the Commission to deem its retail customers to be captive customers for purposes of 

applying the affiliate restrictions. 

10. The Commission clarifies that the new affiliate restriction regulations promulgated 

in Order No. 697 supersede codes of conduct approved by the Commission prior to the 

effective date of Order No. 697. The Commission also provides a number of 

clarifications concerning employees who are not subject to the independent functioning 

requirement. Further, the Commission grants rehearing regarding the adoption of a twoway information sharing restriction in 18 CFR 35.39(d), finding, among other things, that 

a one-way information sharing restriction adequately protects captive customers. 

11. The Commission for the most part affirms its determinations concerning 

mitigation, including retaining the Commission’s default mitigation and declining to 

impose a generic “must offer” requirement. The Commission clarifies that it has not prejudged the types of specific situations in which it might impose a “must offer” 

requirement on a particular seller. In response to rehearing requests concerning the 

Commission’s mitigation of long-term transactions based on the result of a failure of a 

short-term indicative screen, the Commission is modifying its policy with respect to 

mitigation of long-term transactions (one year or more in duration). In this regard, the 

Commission will allow a mitigated seller to demonstrate on a case-by-case basis that it 

does not have market power with respect to a specific long-term contract. 

12. Concerning the tariff provision adopted in the Final Rule for mitigated sellers that 

want to make market-based rate sales at the metered boundary between a balancing 
Docket No. RM04-7-001 -6- 

authority area in which the seller was found, or presumed, to have market power and a 

balancing authority area in which the seller has market-based rate authority, after 

considering comments raised regarding the difficulty of determining and documenting 

whether the power sold is intended to serve load in the balancing authority area in which 

the seller has market power, the Commission is revising the tariff language to eliminate 

the intent element. 

13. The Commission affirms, among other things, its determination in Order No. 697 

to create a category of market-based rate sellers (Category 1 sellers) that are not required 

to automatically submit updated market power analyses, as well as its decision to adopt a 

regional filing process for updated market power analyses. In response to concerns raised 

regarding the potential for Category 1 sellers to exercise market power in load pockets or 

other transmission-constrained areas, we explain that we are modifying our approach. To 

the extent that a Commission-identified submarket is under analysis (relevant submarket), 

if the Commission determines based on analysis of indicative screens filed by other 

sellers that there may be potential market power concerns with respect to any Category 1 

sellers in the relevant submarket, the Commission will, if appropriate, require an updated 

market power analysis to be filed by such Category 1 sellers and allow other parties to 

comment. In this regard, the Commission would be exercising its right to require an 

updated market power analysis at anytime. 

14. The Commission also provides clarifications regarding other aspects of the Final 

Rule, including addressing questions that have arisen concerning the implementation 
Docket No. RM04-7-001 -7- 

process adopted in Order No. 697 and providing clarifications concerning the change in 

status reporting requirement. 

15. Finally, the Commission rejects as without merit arguments raised by petitioners 

challenging the Commission’s authority to adopt market-based rates and alleging that the 

market-based rate program fails to comply with the requirements of the FPA. 

II. Discussion

A. Horizontal Market Power

1. Whether to Retain the Indicative Screens

Final Rule

16. In Order No. 697, the Commission adopted, with some modifications, two 

indicative market power screens (the uncommitted market share screen and the 

uncommitted pivotal supplier screen) to determine whether sellers may have market 

power and should be further examined. The Commission explained that sellers that fail 

either screen would rebuttably be presumed to have market power, but they would have 

an opportunity to present evidence (through the submission of a Delivered Price Test 

(DPT) analysis) demonstrating they do not have market power. The Commission 

concluded that, although some sellers disagree with the use of two screens or find flaws 

in them, the conservative approach of using two screens together would allow the 

Commission to more readily identify potential market power by measuring market power 

at both peak and off-peak times and both unilaterally and in coordinated interaction with 

other sellers. The Commission explained that a conservative approach at the indicative 

screen stage of the proceeding is warranted because, if a seller passes both of the 
Docket No. RM04-7-001 -8- 

indicative screens, there is a rebuttable presumption that it does not possess horizontal 

market power.4

 In conclusion, the approach represented an appropriate balance between 

the need to protect against market power and the desire not to place unnecessary filing 

burdens on utilities.5

 

17. The wholesale market share screen measures for each of the four seasons whether 

a seller has a dominant position in the market based on the number of megawatts of 

uncommitted capacity owned or controlled by the seller as compared to the uncommitted 

capacity of the entire relevant market. When calculating uncommitted capacity, a seller 

adds the total nameplate or seasonal capacity of generation owned or controlled through 

contract plus long-term firm purchases and deducts operating reserves, native load 

commitments, and long-term firm sales.6

 4

 Order No. 697 at P 62. 

5 Id. P 33, 35. 

6

 Order No. 697 states that 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. 

Order No. 697 at P 38. Order No. 697 further states that uncommitted capacity from a 

seller’s remote generation (generation located in an adjoining balancing authority area) 

should be included in the seller’s total uncommitted capacity amounts. Id. However, one 

of the standard screen formats included at Appendix A to Order No. 697 does not capture 

these details. Part I – Pivotal Suppler Analysis, inadvertently does not include Row H 

(imported power) and Row M (average daily Peak Native Load in Peak month, a proxy 

for native load commitment) in calculating Row K (total uncommitted supply). We thus 

correct this error in the Revised Appendix A to include the missing variables of the 

equation. 
Docket No. RM04-7-001 -9- 

18. The pivotal supplier analysis evaluates the potential of a seller to exercise market 

power based on uncommitted capacity at the time of the relevant market’s annual peak 

demand, focusing on the seller’s ability to exercise market power unilaterally. It 

examines whether the market demand can be met absent the seller during peak times; a 

seller is determined to be pivotal if demand cannot be met without some contribution of 

supply by the seller or its affiliates. For purposes of identifying the wholesale market, the 

Commission explained that the “proxy for the wholesale load is the annual peak load 

(needle peak) less the proxy for native load obligation (i.e., the average of the daily native 

load peaks during the month in which the annual peak load day occurs).”7

19. The Commission chose not to adopt suggestions to alter the indicative screens in 

order to incorporate a contestable load analysis, as proposed by some commenters. Such 

an analysis would consider the amount of excess market supply available to serve the 

amount of wholesale demand seeking supply at a particular moment in time.8

 The 

Commission reasoned that such an analysis is essentially a variant on the pivotal supplier 

screen with differences in the calculation of wholesale load and the test thresholds since it 

addresses whether suppliers other than the seller can meet the demand in the relevant 

market. The Commission concluded that incorporating such an analysis would not 

improve its ability to establish a presumption of whether a seller has market power, and 

 7 Id. P 41. 

8 See id. P 49. Generally, advocates of the contestable load analysis believe that, 

if available non-applicant supply is at least twice the contestable load, that is sufficient to 

make a finding that the market is competitive. 
Docket No. RM04-7-001 -10- 

“without the market share indicative screen, the Commission would have insufficient 

information because there would be no analysis of a seller’s size relative to the other 

sellers in the market, and no information on the seller’s market power during off-peak 

periods.”9

 Additionally, the Commission noted that the contestable load analysis fails to 

consider the relative price of the competing supplies and thus whether the available nonapplicant supply is competitively priced and, hence, in the market.10

Requests for Rehearing

20. On rehearing, Southern contends that the Final Rule violates the requirement in 

FPA section 206 that the Commission bears the burden of proof in section 206 

proceedings and that the Commission’s determinations be based on substantial 

evidence.11 According to Southern, this shifting of the burden of proof occurs through 

the use of indicative screens that Southern submits are inherently flawed and which, if 

failed, result in a presumption of market power that must be rebutted by sellers. Southern 

states that once a screen failure occurs and a presumption of market power arises, a seller 

only has two options: either accept a determination that it has market power and adopt 

 9 Id. P 66. 

10 Order No. 697 also dealt with the following issues, about which rehearing has 

not been sought: control and commitment of generation resources; elimination of former 

18 CFR 35.27, which had exempted newly-constructed generation from the horizontal 

market power analysis; reporting format for the indicative screens; nameplate capacity; 

and several procedural issues. 

11 Southern Rehearing Request at 7-8 (citing 16 U.S.C. 824e(a); FPC v. Sierra 

Pacific Power Co., 350 U.S. 348 at 353 (1956) (Sierra); Public Service Commission of 

New York v. FERC, 642 F.2d 1335, 1345 (D.C. Cir. 1980); Public Service Co. of New 

Mexico, 115 FERC ¶ 61,090, at P 33 (2006)). 
Docket No. RM04-7-001 -11- 

cost-based rate mitigation measures, or provide the Commission with a DPT analysis.12 

Southern concludes that by applying the indicative screens codified in the Final Rule, the 

Commission will effectively shift to sellers the evidentiary burden in a section 206 

proceeding.13 Southern argues that the screens are inherently flawed in their ability to 

definitively assess market power when none is actually present, noting that the Final Rule 

acknowledges that the screens are conservative in nature and may result in false positives 

indicating market power.14 Southern argues that because of their conservative nature and 

propensity to result in false positives, such screens cannot properly provide a basis for 

shifting the burden of proof to sellers, and are incapable of providing substantial evidence 

of market power. 

21. To remedy this, Southern argues that the Commission should reconsider its 

determination in the Final Rule that a failure of an indicative screen results in a 

presumption of market power. Instead, the Commission should determine that the 

indicative screens are only intended to identify sellers that appear to raise no horizontal 

market power concerns and thus can be considered for market-based rate authority 

without the necessity of further analysis. In other words, passing the screens should raise 

 12 Id. at 7 (citing Order No. 697 at P 63). 

13 Id. at 8. 

14 Id. (citing Order No. 697 at P 62, 71, 74, 89). Further, Southern asserts that 

only in instances of high market share should a prima facie case of market power be 

established, which would shift the burden of proof. Id. at 10 & n.10 (citing U.S. v. 

Syufy, 903 F.2d 659, 664 (9th Cir. 1990); Hunt-Wesson Foods, Inc. v. Ragu Foods, Inc., 

627 F.2d 919, 924 (9th Cir. 1980), cert. denied, 450 U.S. 921 (1981)). 
Docket No. RM04-7-001 -12- 

a favorable presumption that a seller does not have market power, and a seller would 

never be “presumed” to have generation market power.15 

22. Southern further argues that the Final Rule’s market share screen and its 

application of the DPT are arbitrary and capricious, not supported by substantial 

evidence, without a rational basis, and contrary to established legal precedent.16 

Specifically, Southern contends that the market share screen and the DPT improperly fail 

to account for the size of the wholesale market demand that could be served by the 

uncommitted capacity in the relevant region.17 Southern argues that wholesale market 

demand should be considered in the market share screen and the DPT because market 

power concerns only exist if a seller has the power to raise prices above competitive 

levels or exclude competition in the relevant market for a not insubstantial amount of 

time.18 According to Southern, even the Department of Justice (DOJ) merger analysis, 

on which the Final Rule relies, would take the wholesale market into account when 

 15 Id. at 11. 

16 Id. at 20 (citing 5 U.S.C. 706(2)(A) and (E) (2000); Union Pac. Fuels, Inc. v. 

FERC, 129 F.3d 157, 161 (D.C. Cir. 1997) (holding that review of Commission orders is 

made under the arbitrary and capricious standard of the Administrative Procedure Act); 

Sithe Independence Power Partners v. FERC, 165 F.3d 944 (D.C. Cir. 1999)(stating that 

the Commission must be able to demonstrate that it has “made a reasoned decision based 

upon substantial evidence in the record” and the “path of [its] reasoning” must be clear) 

(quoting Town of Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992)). 

17 Id. at 3-4 (citing United States v. Grinnell Corp., 384 U.S. 563, 571 (1966); 

MetroNet Services Corp. v. U.S. West Communications, 329 F.3d 986 (9th Cir. 2003); 

United States v. Dentsply International, Inc., 399 F.3d 181, 187 (3rd Cir. 2005)). 

18 Id. at 12-13. 
Docket No. RM04-7-001 -13- 

determining an entity’s “market share.”19 Southern comments that in the Final Rule the 

Commission appeared to give four reasons why it was unwilling to consider market 

demand (i.e., contestable load), and contends that these reasons provide an insufficient 

basis for rejecting a contestable load analysis.20 Southern believes that the weight of the 

evidence clearly demonstrates that to be legitimate indicators of market power, the 

market share screen and DPT should take the relevant wholesale demand into account. 

Commission Determination

23. We disagree with Southern’s contention that the Final Rule violates the 

requirement in the FPA that the Commission bears the burden of proof in section 206 

proceedings. We also disagree with Southern’s view that failure of the indicative 

screen(s) does not provide a sufficient basis to establish a rebuttable presumption of 

market power. 

24. As a general matter, we agree that the burden of proof in a section 206 proceeding 

is on the Commission where the Commission institutes the proceeding on its own motion. 

However, we find Southern’s argument that the burden of proof in a section 206 

proceeding is unlawfully shifted to entities that fail one of the indicative screens to be 

without merit. As an initial matter, the burden of going forward is on the Commission in 

the first instance, and ultimately, when the Commission institutes a proceeding under 

section 206 of the FPA. In the Final Rule, the Commission has established through 

 19 Id. at 13. 

20 Id. at 15 and Frame affidavit at ¶ 25, referring to Order No. 697 at P 66-67. 
Docket No. RM04-7-001 -14- 

rulemaking a generic test to support its burden of going forward: a seller’s failure of one 

of the indicative screens establishes a rebuttable presumption of market power. The 

burden of going forward then shifts to the seller once such a proceeding is initiated to 

rebut the presumption of market power. Once the seller submits additional evidence to 

rebut the presumption of market power, the Commission must determine, based on 

substantial evidence in the record, whether the seller has market power. Thus, the 

ultimate burden of proof under FPA section 206 remains with the Commission.21 On this 

basis, the Commission is not unlawfully shifting the burden of proof to the seller that fails 

one of the screens. 

 21 See AEP Power Marketing, Inc., 108 FERC ¶ 61,026, at P 30 (2004) (July 8 

Order) (“Failure of a screen establishes a rebuttable presumption of market power, which 

satisfies the Commission’s initial burden of going forward in such proceedings. The 

burden of going forward will then be upon the applicant once such a proceeding is 

initiated.”); see id. P 29 (stating that passing both screens or failing one merely 

establishes a rebuttable presumption, and explaining that in the case of an intervenor in a 

section 205 proceeding that seeks to prove that the applicant possesses market power, 

“the intervenor need only meet a ‘burden of going forward’ with evidence that rebuts the 

results of the screens. At that point, the burden of going forward would revert back to the 

applicant to prove that it lacks market power.”) (citing Pennzoil Co. v. FERC, 645 F.2d 

360, 392 (5th Cir. 1981), cert. denied, 454 U.S. 1142 (1982); accord Transcontinental 

Gas Pipe Line Corp., Opinion No. 135, 17 FERC ¶ 61,232, at 61,450 (1981) (“The 

presumption ... is the same as that which arises from a prima facie case: it imposes on 

the party against whom it is directed the burden of going forward with substantial 

evidence to rebut or meet the presumption, but does not shift the burden of persuasion.”); 

Generic Determination of Rate of Return on Common Equity for Electric Utilities, Order 

No. 389-A, 29 FERC ¶ 61,223, at 61,458 (1984) (concluding that rebuttable presumption 

that a rate of return based on a benchmark is just and reasonable does not shift ultimate 

burden of proof imposed by Federal Power Act)); see also Southern Companies Energy 

Marketing, Inc., 111 FERC ¶ 61,144, at P 24 (2005) (stating that a “screen failure 

satisfies the Commission’s burden of going forward and shifts to the applicant the burden 

of presenting evidence rebutting the presumption of market power”), order dismissing 

reh’g as moot, 119 FERC ¶ 61,300 (2007). 
Docket No. RM04-7-001 -15- 

25. Moreover, in Order No. 697, the Commission addressed an argument by Southern 

that failure of the screens does not provide a sufficient basis to establish a rebuttable 

presumption of market power, and Southern has failed on rehearing to convince us that a 

seller should never be presumed to have generation market power. In particular, the 

Commission explained that the indicative screens are intended to identify the sellers that 

raise no horizontal market power concerns and can otherwise be considered for marketbased rate authority. Sellers failing one or both of the indicative screens, on the other 

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

which a more robust analysis is required. The Commission explained that the 

uncommitted pivotal supplier screen focuses on the ability to exercise market power 

unilaterally. Failure of this screen indicates that some or all of the seller’s generation 

must run to meet peak load. The uncommitted market share analysis indicates whether a 

supplier has a dominant position in the market. Failure of the uncommitted market share 

screen may indicate that the seller has unilateral market power and may also indicate the 

presence of the ability to facilitate coordinated interaction with other sellers. It is on this 

basis that the Commission finds that a rebuttable presumption of market power is 

warranted when a seller fails one or both of the indicative screens. The screens 

themselves represent the first piece of evidence that the potential for market power exists 

since failure of one or both of the screens indicates that the seller may be a pivotal 

supplier in the market or has a high enough market share of uncommitted capacity to 
Docket No. RM04-7-001 -16- 

raise horizontal market power concerns.22 In addition, we note that although we find that 

failure of an indicative screen is a sufficient basis to establish a presumption of market 

power, the Commission allows such a seller to continue to sell under market-based rate 

authority until a definitive finding is made, albeit with rates subject to refund to protect 

customers. 

26. We disagree with Southern’s argument that the indicative screens have a 

propensity to result in false positive indications of market power, do not provide 

substantial evidence of market power and, therefore, cannot provide a basis for shifting 

the evidentiary burden to sellers. As we explained in Order No. 697, the indicative 

screens are intended to screen out those sellers that raise no horizontal market power 

concerns and can otherwise be considered for market-based rate authority from those 

sellers that raise concerns but may not necessarily possess horizontal market power.23 

While we recognize that the conservative nature of the screens may result in some false 

positives, a conservative approach at the indicative screen stage is warranted because if a 

seller passes both of the indicative screens, there is a rebuttable presumption that it does 

not possess horizontal market power. Thus, we must weigh the risk of false positives and 

any resulting repercussions on a seller (e.g., section 206 proceeding, rate subject to 

refund, temporary regulatory uncertainty) against the costs of adopting a less 

 22 See Order No. 697 at P 65.

23 Id. P 62. 
Docket No. RM04-7-001 -17- 

conservative screen or eliminating the market share indicative screen.24 In particular, if 

the screens result in a false positive indication of market power, the seller has the 

opportunity to rebut the presumption of market power while it continues to have marketbased rate authority. However, if we were to adopt a less conservative screen, that could 

result in a false negative, i.e., a false indication of no market power and customers would 

not be adequately protected. Accordingly, if the Commission were to adopt Southern’s 

approach we are concerned that false negatives would become a reality and the 

Commission would not be able to fulfill its FPA section 205 and 206 mandate to ensure 

just, reasonable and not unduly discriminatory rates. On this basis, we believe that 

evidence of an indicative screen failure is sufficient to establish a rebuttable presumption 

of market power, in which case the seller will then have the opportunity to rebut that 

presumption of market power. 

27. Additionally, in response to Southern’s concerns regarding the conservative nature 

of the indicative screens, Order No. 697 changed the native load proxy under the market 

share indicative screen from the minimum native load peak demand for the season to the 

average of the daily native load peak demands for the season, making the native load 

proxy for the market share indicative screen consistent with the native load proxy under 

the pivotal supplier screen.25 A native load proxy based on the average of peak load 

conditions is more representative, and thus more accurate, than a proxy based on 

 24 Id. P 71. 

25 Id. P 135. 
Docket No. RM04-7-001 -18- 

minimum peak load conditions. Basing the native load proxy on the average of the peaks 

will make the screens more accurate in eliminating sellers without market power while 

focusing on ones that may have market power.26 Thus, the updated native load proxy 

will reduce the likelihood that false positive indications of market power will occur. 

28. Accordingly, we affirm our determination in the Final Rule that a failure of an 

indicative screen results in a presumption of market power, and reject Southern’s 

proposal that a seller never be “presumed” to have horizontal market power as a result of 

an indicative screen failure.27 

29. The Commission also disagrees with Southern’s assertion that the market share 

screen and the DPT analysis do not account for the size of wholesale market demand, and 

are therefore arbitrary and capricious.28 While Southern may disagree with our approach 

to considering wholesale market demand, both the market share screen and the DPT 

consider wholesale market demand by considering uncommitted capacity. Uncommitted 

capacity considers wholesale market demand by reducing the seller’s available capacity 

by the amount of capacity committed to serve demand. In addition, in both the initial 

screen and the DPT, the Commission requires a pivotal supplier analysis, which looks at 

whether there is sufficient competing supply to serve wholesale demand. 

 26 Id. P 137. 

27 Southern Rehearing Request at 11. 

28 We further address Southern’s arguments with regard to the DPT analysis 

below. 
Docket No. RM04-7-001 -19- 

30. In addition, we disagree with Southern that our choice of how to account for the 

wholesale market demand has resulted in the market share screen and the DPT being 

arbitrary and capricious. The development of the market share screen and the DPT 

resulted from lengthy public proceedings at which varying perspectives and arguments 

were taken into account. Over the years, and in light of the Commission’s FPA 

responsibilities, the Commission has carefully considered various points of view in an 

open transparent dialogue with the electric industry and has based its determinations on 

sound regulatory principles. In particular, the market share screen provides a 

straightforward economically sound and accepted method to identify those sellers that 

have the potential to exercise market power.29 The uncommitted pivotal supplier screen 

measures the ability of the firm to dominate the market at peak periods. Further, the 

market share screen indicates whether a supplier may have a dominant position in the 

market and measures the ability of a seller to affect coordinated interaction with other 

sellers that could be accomplished during both peak and off-peak times. The market 

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

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

 29 See In the Matter of Merger Policy Under the Federal Power Act, May 7, 1996 

Comments of the U.S. Department of Justice, Docket No. RM96-6-000 (providing 

comments on the Commission’s standards for determining whether a proposed merger is 

in the public interest, recommending that the Commission apply a market share screen to 

identify quickly those mergers that are unlikely to raise competitive issues and 

concluding that the Horizontal Merger Guidelines provide “sound competitive analysis”); 

see also U.S. Department of Justice and the Federal Trade Commission, Horizontal 

Merger Guidelines, section 2.0, reprinted at 4 Trade Reg. Rep. (CCH) ¶13,104 (Issued 

April 2, 1992, Revised April 8, 1998).
Docket No. RM04-7-001 -20- 

is uncommitted after accounting for its obligations to serve native load. It also provides a 

snapshot of these market shares in each season of the year.30 Thus, the indicative screens 

measure a seller’s market power at both peak and off-peak times and therefore indirectly 

measure market power potential during periods of both relatively high and low demand.31 

With regard to Southern’s argument that in the Final Rule the Commission appeared to 

give four reasons why it was unwilling to consider market demand (i.e., contestable 

load), and Southern’s contention that these reasons provide an insufficient basis for 

rejecting a contestable load analysis, we reaffirm our determination that the contestable 

load analysis is flawed and essentially a variant on the pivotal supplier screen.32 Like the 

pivotal supplier screen, the contestable load analysis addresses whether suppliers other 

than the seller can meet the demand in the relevant market. Thus, incorporating such an 

analysis would not improve our ability to establish a presumption of whether a seller 

possesses market power and would add little useful information.33 

2. Indicative Market Share Screen Threshold Levels 

Final Rule

31. Order No. 697 retained the 20 percent threshold for the wholesale market share 

screen (i.e., with a market share of less than 20 percent, the seller passes the screen). The 

 30 Order No. 697 at P 65. 

31 Id. 

32 Id. P 66. 

33 Id. 
Docket No. RM04-7-001 -21- 

Commission reasoned that a relatively conservative threshold for passing the market 

share screen was appropriate, explaining that the screens are indicative of market power, 

not definitive. Responding to arguments that the Commission should use a 35 percent 

threshold as a presumption of market power because the U.S. Department of Justice 

(DOJ) merger guidelines state that only firms with 35 percent of more market share have 

market power, the Commission explained: 

in a market comprised of five equal-sized firms with 20 percent market 

shares, the HHI is 2,000, which is above the DOJ/FTC HHI threshold of 

1,800 for a highly concentrated market, and in markets for commodities 

with low demand price-responsiveness like electricity, market power is 

more likely to be present at lower market shares than in markets with high 

demand elasticity.[34] 

32. The Commission continued that, when arguing that a 20 percent threshold for the 

market share screen is too low, commenters ignored that the indicative screens are based 

on uncommitted capacity, not total capacity; as a result, a substantial amount of seller 

capacity may not be counted in measures of market share. The Commission, therefore, 

concluded that the 20 percent threshold strikes the right balance in seeking to avoid both 

false negative and false positive results.35

Requests for Rehearing

33. Southern asserts that the Final Rule arbitrarily utilizes a 20 percent market share 

 34 Id. P 89. 

35 Id. P 91. 
Docket No. RM04-7-001 -22- 

threshold to establish a presumption of market power.36 Further, Southern argues that the 

20 percent threshold is contrary to legal precedent holding that a higher market share is 

required to warrant market power concerns.37 

34. Southern argues that, contrary to the Commission’s assertions, the 1984 Merger 

Guidelines do not support the 20 percent figure used in the market share screen. First, it 

states that while the particular sentence cited by the Commission from section 4.134 of 

the 1984 guidelines does actually contain the words “market share of 20 percent,” it does 

not support the application of a 20 percent threshold under the market share screen when 

considered in proper context, since other portions of the 1984 Merger Guidelines indicate 

that the DOJ’s definition of “market share” in the context of merger evaluation is 

different from the Commission’s definition of “market share” under its market share 

screen.38 Second, Southern argues that according to the very sentence cited in the Final 

Rule from the 1984 Merger Guidelines, the 20 percent “market share” threshold refers 

only to the market share of the acquired firm in the overall context of a proposed merger 

 36 Southern Rehearing Request at 4 (citing DOJ 1984 Merger Guidelines, Section 

2.4; Edison Mission Energy, Inc. v. FERC, 394 F.3d 964, 968 (D.C. Cir. 2005) (stating 

that the Commission must “articulate a satisfactory explanation for its action including a 

‘rational connection between the facts found and the choice made.’”) (quoting Motor 

Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983)). 

37 Id. 

38 The Final Rule cited section 4.134, stating “[t]he 20 percent threshold is 

consistent with § 4.134 of the U.S. Department of Justice 1984 Merger Guidelines issued 

June 14, 1984, reprinted in Trade Reg. Rep. P 13,103 (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.’” Order No. 697 at n.21. 
Docket No. RM04-7-001 -23- 

of multiple firms. It does not refer to the market share of the merged firm postacquisition, nor does it even refer to the market share of the acquiring firm. Third, 

Southern argues that the Commission’s reliance on the 20 percent threshold in section 

4.134 of DOJ’s 1984 Merger Guidelines is misplaced because that provision is outdated -

- it is not included in DOJ’s current horizontal merger guidelines. In this regard, the 1984 

Merger Guidelines were used to evaluate both vertical and horizontal mergers. The 

newer versions of DOJ’s horizontal merger guidelines subsequently adopted in 1992 and 

1997 do not carry forward section 4.134’s 20 percent market share threshold. Thus, the 

market share of a single firm does not automatically translate into a high HHI as the 

Commission suggests.39 

35. Southern also argues on rehearing that section 2 of the Sherman Antitrust Act, 

which prohibits not only actual monopolization but also attempted monopolization and 

conspiracy to monopolize, has spawned a well-established body of law to address the 

type of market concerns that the Commission attempts to address in the Final Rule. 

Southern contends that the Commission’s 20 percent threshold falls short when measured 

against the jurisprudence interpreting section 2 of the Sherman Act and that a more 

relevant threshold in a non-merger context would arguably be closer to 90 percent than 

20 percent.40 Whether the Commission’s concern arises out of the unilateral ability of a 

 39 Id. at 16-19. 

40 Id. at 20 (citing Hiland Dairy v. Kroger, 402 F.2d 968, 976 (8th Cir. 1968) 

(rejecting 60 or 33 percent market share); Robinson v. Magovern, 521 F. Supp. 842, 887 

(W.D. Pa. 1981)). 
Docket No. RM04-7-001 -24- 

utility to exert market power or the ability of two or more utilities to act concertedly in a 

way that restrains trade, Southern argues that jurisprudence interpreting the Sherman Act 

more appropriately addresses those concerns than does merger analysis. Aside from the 

authorities supporting a rule of law that less than at least a 50 percent market share should 

be insufficient to suggest market power, Southern argues that many cases and 

commentators may be cited for the proposition that the Commission’s 20 percent 

threshold is misguided and lacks a rational basis; relatively low market shares should, as 

a matter of law, preclude findings of market power.41 Southern adds that the courts have 

not only consistently held that market shares in the 20 percent range are insufficient to 

support a finding of actual monopoly power under section 2 of the Sherman Act, but also 

have found little difficulty in determining that such market share is not enough to sustain 

even a claim of attempted monopolization under section 2.42 

36. NASUCA argues on rehearing that in calculating market share when screening for 

horizontal market power, the Commission should not subtract capacity needed for longterm contracts as “committed” if the contracts are indexed or linked to spot market prices. 

 41 Id. at 22-23 (citing Cargill, Inc. v. Monfort of Colorado, Inc., 479 U.S. 104, 

119 n.15 (1986) (noting that 20.4 percent market share is probably insufficient to sustain 

predatory pricing, and citing authorities indicating that 60 percent or more would be 

necessary); Bailey v. Allgas, Inc., 284 F.3d 1237, 1250 (11th Cir. 2002); Yoder Bros., 

Inc. v. California-Florida Plant Corp., 537 F.2d 1347, 1368 (5th Cir. 1976) (stating that a 

20 percent market share was insufficient as a matter of law to prove market power)). 

42 Id. at 24 (citing H.L. Hayden Co. of New York, Inc., v. Siemens Medical 

Systems, Inc., 879 F.2d 1005, 1017 (2nd Cir. 1989); Nifty Foods Corp. v. Great Atl. & 

Pac. Tea Co., 614 F.2d 832, 841 (2nd Cir. 1980) (one-third market share not enough); 

U.S. v. ALCOA, 148 F.2d 416, 424 (2nd Cir. 1945). 
Docket No. RM04-7-001 -25- 

NASUCA asserts that a seller with a market share of capacity greater than 20 percent can 

reduce it, and pass a market power screen it would otherwise fail, by “committing” 

portions of its capacity. NASUCA states that it requested in its NOPR comments that the 

Commission clarify that it will not consider capacity dedicated to meeting long-term 

contract sales of energy to be “committed” – and thus disregarded from market share – if 

the price of energy in the long-term contracts is indexed or linked to spot market prices. 

NASUCA contends that it identified relevant research in support of its request in citing a 

model that withdraws the capacity committed under the long-term contracts from the 

short-run market.43 NASUCA states that the Commission overlooked NASUCA’s 

request, and therefore requests that the Commission grant its requested clarification 

because research indicates that long-term contracts linked to spot market prices do not 

reduce, and may exacerbate, the ability of a seller to raise spot market prices above 

competitive levels.44 In the alternative, NASUCA seeks further proceedings to examine 

the exercise of market power by sellers who pass market screens due to their contractual 

commitment to make long-term energy sales at rates indexed to spot market prices. 

Commission Determination

37. We affirm our determination to retain the 20 percent threshold for the indicative 

wholesale market share screen. Use of the 20 percent market share threshold is 

 43 NASUCA Rehearing Request at 8 (citing Chloe Lo Coq. Index Contracts and 

Spot Market Competition, University of California Energy Institute, Center for the Study 

of Energy Markets, June 2006, p. 15, available at 

http://www.ucei.berkeley.edu/ThirdTierButtons/PDFButton_Off.jpg). 
Docket No. RM04-7-001 -26- 

appropriate since the screen is indicative, not dispositive. Southern's arguments suggest 

that the 20 percent is dispositive, but it is not. If a seller fails the indicative screens, it can 

submit a full DPT analysis in which a range of factors are considered, including market 

shares, HHIs (market concentration) and other factors affecting the relevant markets. A 

20 percent market share is not even considered dispositive at that stage; rather, we have 

approved market-based rates in several cases where a supplier had a market share 

exceeding 20 percent.45 In addition, we note that the cases cited by Southern, where 

much higher market shares were allowed, involve markets other than electricity.46 

Electricity markets possess unique characteristics including, but not limited to, inelastic 

demand and the need to balance the entire transmission grid in real-time. Economic 

 44 Id. (citing Order No. 697 at P 82-93). 

45 PPL Montana, LLC, 115 FERC ¶ 61,204, at P 41 (2006), order denying reh’g, 

120 FERC ¶ 61,096 (2007); Kansas City Power and Light Co., 113 FERC ¶ 61,074, at 

P 26, 30 (2005); PacifiCorp, 115 FERC ¶ 61,349, at P 29, 32 (2006); Tampa Electric Co., 

117 FERC ¶ 61,311, at P 26-27 (2006). 

46 Hiland Dairy v. Kroger, 402 F.2d 968 (8th Cir. 1968) (concerning a claim of 

monopolization in the milk and dairy business); Robinson v. Magovern, 521 F. Supp. 842 

(W.D. Pa. 1981) (addressing an antitrust action against a hospital); Cargill, Inc. v. 

Monfort of Colorado, Inc., 479 U.S. 104 (1986) (concerning a merger in the beef packing 

industry); Bailey v. Allgas, Inc., 284 F.3d 1237 (11th Cir. 2002) (addressing an antitrust 

action arising from a price war between liquid propane gas competitors); Yoder Bros., 

Inc. v. California-Florida Plant Corp., 537 F.2d 1347 (5th Cir. 1976) (addressing antitrust 

claims arising from infringement of plant patents); H.L. Hayden Co. of New York, Inc., 

v. Siemens Medical Systems, Inc., 879 F.2d 1005 (2nd Cir. 1989) (addressing antitrust 

claims relating to distribution of dental x-ray equipment); Nifty Foods Corp. v. Great Atl. 

& Pac. Tea Co., 614 F.2d 832 (2nd Cir. 1980) (concerning an antitrust suit arising from 

the substitution of a supplier of frozen waffles); U.S. v. ALCOA, 148 F.2d 416 (2nd Cir. 

1945) (concerning claims of monopolization of interstate and foreign commerce in the 

manufacture and sale of aluminum). 
Docket No. RM04-7-001 -27- 

theory and empirical estimates of the short-run elasticities of electricity demand suggest 

that these unique conditions allow sellers in wholesale electricity markets to exercise 

market power using a much more limited withholding of supply than industries listed in 

the cases cited by Southern.47 Thus, the use of a conservative threshold such as a 20 

percent market share is warranted, particularly for an indicative screen. 

38. Southern asserts that the Final Rule’s reliance on the 1984 Merger Guidelines for 

use of the “20 percent market share” is incorrect. Section 4.134 of the 1984 Merger 

Guidelines states: 

Entry through the acquisition of a relatively small firm in the market may 

have a competitive effect comparable to new entry. Small firms frequently 

play peripheral roles in collusive interactions, and the particular advantages 

of the acquiring firm may convert a fringe firm into a significant factor in 

the market. The Department is unlikely to challenge a potential competition 

merger when the acquired firm has a market share of five percent or less. 

Other things being equal, the Department is increasingly likely to challenge 

a merger as the market share of the acquired firm increases above the 

threshold. The Department is likely to challenge any merger satisfying the 

other conditions in which the acquired firm has a market share of 20 

percent of [sic] more.[48] 

39. Upon further review, the context discussed in this quote differs from the issue 

before us, and provides little guidance here. In the market-based rate context, we focus 

 47 Energy Information Administration, “Assumptions to the Annual Energy 

Outlook 2006,” Report #: DOE/EIA-0554 (2006); James A. Espey & Molly Espey, 

“Turning on the Lights: A Meta-analysis of Residential Electricity Demand Elasticities,” 

JOURNAL OF AGRICULTURAL AND APPLIED ECONOMICS, 36:1, at 65-81 (April 2004). 

48 U.S. Department of Justice Non-Horizontal Merger Guidelines sec. 4.134, 

originally issued June 14, 1984, as part of the U.S. Department of Justice Merger 

Guidelines, reprinted in Trade Reg. Rep. ¶ 13,103 (CCH 1988) (footnote omitted). 
Docket No. RM04-7-001 -28- 

on whether the applicant has a 20 percent market share as a conservative measure 

because of the electricity market's characteristics including inelastic demand and the need 

to balance the entire transmission grid in real-time.49 However, the Non-Horizontal 

Merger Guidelines provide that a firm with a 20 percent share is unlikely to be a “fringe” 

firm and an insignificant factor in the market. This is the same reason that we use the 20 

percent threshold in our indicative screen: firms with a 20 percent market share would be 

unlikely to hold a dominant position in the market.50 

40. We also reject Southern’s argument that the Commission’s 20 percent threshold 

falls short when measured against the jurisprudence interpreting section 2 of the Sherman 

Act.51 Economic theory suggests that it may be possible, given the unique conditions in 

electricity markets, for sellers to exercise market power, using a much more limited 

withholding of supply, than industries listed in the cases relied upon by Southern.52

 49 A seller who has less than a 20 percent market share in a season will be 

considered to satisfy the market share analysis. AEP Power Marketing, Inc., 107 FERC 

¶ 61,018, at P 102 (April 14 Order), order on reh’g, 108 FERC ¶ 61,026 (2004) (July 8 

Order). 

50 See id. P 104. 

51 Southern Rehearing Request at 22-23. 

52 See supra n.46. 
Docket No. RM04-7-001 -29- 

Moreover, in contrast to the cases cited, the Commission uses 20 percent as an indicative

screen, not as a dispositive factor in determining whether market power exists. We have, 

as indicated, approved market-based rates for firms with market shares in excess of 20 

percent. 

41. We reject NASUCA’s request that the Commission require sellers to treat capacity 

that is committed to long-term contracts that are indexed or linked to spot market prices 

as uncommitted capacity in calculating market share when screening for horizontal 

market power. As support, NASUCA cites a model that withdraws the capacity 

committed under the long-term contracts from the short-run market, and then concludes 

that the now reduced capacity traded in the spot market lowers the incentives for rival 

firms to deviate from any collusive behavior by reducing the number of firms in the 

market and their available capacity.53 Therefore, the model cited by NASUCA subtracts 

capacity committed under long-term contracts from the capacity available in the short-run 

market, just as we do in our analysis. Similarly, the Commission believes that once 

capacity is committed long-term, regardless of how that capacity is priced (e.g., whether 

linked to spot prices or not), the ability of the firm to use that capacity to exercise market 

power in the spot market is severely limited or non-existent. The ability to collude will 

 53 “If collective action is necessary for the exercise of market power, as the 

number of firms necessary to control a given percentage of total supply decreases, the 

difficulties and costs of reaching and enforcing an understanding with respect to the 

control of that supply might be reduced.” U.S. Department of Justice and the Federal 

Trade Commission, Horizontal Merger Guidelines, section 2.0, reprinted at 4 Trade Reg. 

Rep. (CCH) ¶ 13,104 (Issued April 2, 1992, Revised April 8, 1998). 
Docket No. RM04-7-001 -30- 

be determined by the remaining uncommitted capacity in the spot market, not the 

capacity that is already committed under long-term contracts. Therefore, we conclude 

that it is appropriate to subtract capacity committed under long-term contracts when 

calculating a seller’s uncommitted capacity for purposes of performing the indicative 

screens. 

3. DPT Criteria

Final Rule

42. In Order No. 697, the Commission announced that it would continue to use the 

DPT to make a definitive determination of whether a seller has market power and that it 

would continue to weigh both available economic capacity and economic capacity when 

analyzing market shares and Hirschman-Herfindahl Indices (HHI).54 The Commission 

chose to retain the HHI threshold of 2,500 for passing the DPT, and to retain the 20 

percent market share threshold. Responding to arguments that if a 2,500 HHI threshold is 

retained, it should be used with a 15 percent market share because these are the criteria of 

the oil pipeline test from which the 2,500 HHI was derived, the Commission noted that it 

“had not seen cases where the HHI was over 2,500 and the seller’s market share was 

between 15 and 20 percent, which would be the type of situation about which 

[commenters] are concerned.”55 

Requests for Rehearing

 54 Order No. 697 at P 13, 104, 106. 

55 Id. P 113. 
Docket No. RM04-7-001 -31- 

43. Montana Counsel argues that the Commission should clarify that capacity 

committed to a competitor’s native load or otherwise unavailable on a firm basis should 

not be considered available to compete with the applicant’s generation, and as such 

should not be included as available capacity in the DPT analysis. Montana Counsel 

states that in its order on PPL Montana’s request for renewal of market-based rate 

authority, the Commission stated that it was “not inconsistent with how DPTs have 

historically been conducted” for PPL Montana to include as available competing 

generation capacity that was committed elsewhere.56 Montana Counsel contends that this 

is inappropriate insofar as generation committed to serve another utility’s native load 

cannot be available to compete with the applicant’s generation on a firm basis. Montana 

Counsel states that while it appears that Order No. 697 remedies this mistake in stating 

that total supply is determined by adding the total amount of uncommitted capacity 

located in the relevant market (including capacity owned by the seller and competing 

suppliers) with that of uncommitted supplies that can be imported (limited by 

simultaneous transmission import capability) into the relevant market from the first-tier 

markets, the Commission does not explicitly change the Commission’s prior policy. 57 

Accordingly, Montana Counsel requests clarification that the Commission will not allow 

 56 Montana Counsel Rehearing Request at 9 (citing PPL Montana, LLC, 

115 FERC ¶ 61,204, at P 49 (2006)). 

57 Id. at 10 (citing Order No. 697 at P 37-38). 
Docket No. RM04-7-001 -32- 

applicants to count as available economic capacity generation that is in fact committed; if 

necessary and in the alternative, Montana Counsel requests rehearing of this issue. 

44. TDU Systems argue on rehearing that the Final Rule fails to explain how the 

adoption of a 2,500 HHI threshold is rationally related to the Commission’s objective of 

precluding market-based rates in highly concentrated markets.58 They assert that the 

Commission should lower the HHI threshold to 1,800 as the appropriate threshold for 

treating a market as highly concentrated, and that the Commission’s refusal to do so in 

the Final Rule was arbitrary and capricious. TDU Systems state that, since the 

Commission set out in the Final Rule “to provide ‘a rigorous up-front analysis of whether 

market-based rates should be granted,’ it is somewhat puzzling as to why the 

Commission believes that the case for any change in the status quo must be 

‘compelling.’”59

45. TDU Systems note that 1,800 is the level which the Commission uses in its merger 

regulations and contends that the Commission placed too much reliance on the 1994 DOJ 

 58 TDU Systems state that “The Final Rule fails to explain how the adoption of an 

1,800 Herfindahl-Hirschman Index (‘HHI’) threshold is rationally related to its objective 

of precluding market-based rates in highly concentrated markets. TDU Systems 

Rehearing Request at 2 (citing Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto Ins. 

Co., 463 U.S. 29, 42-43 (1983); Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315, 1319 

(D.C. Cir. 2004)). However, the Final Rule retained 2,500 as the appropriate threshold 

for passing the HHI component of the DPT. 

59 Id. at 12-13 (citing Order No. 697 at P 2). 
Docket No. RM04-7-001 -33- 

recommendations60 as to market rates in the very different oil pipeline market for arriving 

at the 2,500 HHI threshold. TDU Systems state that electric utilities do not face the same 

competition from other modes of transportation and demand elasticity as do oil pipelines. 

They state that these factors support their argument for a lower HHI.61 If the 

Commission does not adopt the 1,800 level consistent with effective competition, TDU 

Systems contend that it should reduce the market-share threshold to 15 percent.62 

46. TDU Systems argue that they made a strong case for reducing the triggering HHI 

level to 1,800 in their NOPR comments, and that the Commission appears not to have 

considered it carefully. They assert that if a market is regarded as “highly concentrated,” 

the DOJ guidelines indicate that even modest increases in concentration will likely raise 

significant competitive concerns. They contend that, in such a market, other agencies 

presume that an HHI increase of 100 or more is likely to create or enhance market power. 

They conclude that, regardless of what the Commission ordered in the April 14 Order, 

there is no good reason at this time to regard a market with a 2,000 HHI as not highly 

concentrated.63

 60 April 14 Order, 107 FERC ¶ 61,018, at P 110 & n.96 (citing Comments of the 

U.S. Dept. of Justice, Docket No. RM94-1-000 (Jan. 18, 1994)). 

61 TDU Systems Rehearing Request at 14. 

62 Id. at 6-7 (citing DOJ Comments, Docket No. RM94-1-000 (Jan. 18, 1994), at 

13).

63 Id. at 13. 
Docket No. RM04-7-001 -34- 

47. Southern argues that for the same reasons that the market share screen should take 

into account the overall size of the wholesale market and include a contestable load 

analysis, the DPT should take into account the overall size of the wholesale market, or 

should be replaced by a contestable load analysis.64

Commission Determination

48. In response to the Montana Counsel’s request, we clarify that capacity committed 

to a competitor’s native load or otherwise unavailable on a long-term firm basis, will not 

be considered available to compete with the seller’s generation, and as such will not be 

included as available economic capacity in the DPT analysis. We also note that Montana 

Counsel misrepresents our findings in the PPL Montana proceeding. In that proceeding, 

it was not argued that the capacity in question was committed elsewhere. Rather, the 

Commission addressed the argument that capacity “may” be committed. PPL Companies 

rebutted that argument by explaining that the buyers at issue did not have long-term firm 

transmission available to export the energy in question from the NorthWestern control 

area, and that because the buyers could elect to leave this capacity in the NorthWestern 

control area, the capacity in question should not be excluded from the available economic 

capacity in the NorthWestern control area. The Commission noted that PPL Companies’ 

treatment of this capacity is not inconsistent with how DPTs have historically been 

conducted. 

 64 Southern Rehearing Request at 3-4, 11-16 and Frame Affidavit at ¶ 5, 21-22. 
Docket No. RM04-7-001 -35- 

49. The Commission rejects TDU Systems’ proposal to reduce the HHI threshold 

level to 1,800. The Commission will continue to use a 2,500 HHI and a 20 percent 

market share as the thresholds for the DPT analysis. The Commission believes that the 

market share/HHI thresholds of 20 percent and 2,500, respectively, enable the 

Commission to identify dominant firms in highly concentrated markets, rather than firms 

with market shares above 20 percent that operate in less concentrated markets (e.g., HHIs 

less than 2,500), resulting in fewer false positives.65 Further, the Commission will 

continue to examine each DPT analysis on a case-by-case basis, weighing other factors, 

besides market share and HHIs, such as historical sales and transmission data.66 Thus, 

we will retain 2,500 as the appropriate threshold for passing the HHI component of the 

DPT.67 Notwithstanding TDU Systems’ argument that the Final Rule fails to explain 

how the adoption of a 2,500 HHI threshold is rationally related to the Commission’s 

objective of precluding market-based rates in highly concentrated markets, the 

Commission has explained why 2,500 is the appropriate threshold, and we reject TDU 

Systems’ contention that the Commission did not carefully consider arguments for 

reducing the threshold to 1,800. At less than 2,500 HHI in the relevant market for all 

season/load conditions, there is little likelihood of coordinated interaction among 

 65 As explained in Order No. 697 at P 100, lowering the HHI threshold to 1,800 

will cause more false positives and direct capital away from the generation sector. 

66 Order No. 697 at P 96. 

67 Id. P 113; April 14 Order, 107 FERC ¶ 61,018, at P 111. 
Docket No. RM04-7-001 -36- 

suppliers in a market.68 TDU Systems argue that the DOJ Merger Guidelines use an 

1,800 HHI, but fail to note that the focus of the Guidelines is on increases in market 

concentration produced by a merger. For example, an existing market could have an HHI 

of 2,400 and the DOJ would take no action if the acquired firm was very small. It is 

therefore not the 1,800 HHI figure, standing alone, that merits scrutiny by the DOJ, but 

rather the relative increase in concentration that could cause the DOJ to investigate 

further. We therefore do not believe that our approach conflicts in any way with the DOJ 

merger guidelines. We also reaffirm our determination not to adopt TDU Systems’ 

suggestion to lower the market share threshold to 15 percent from 20 percent. As we 

explained, we believe that the 20 percent threshold strikes the right balance in seeking to 

avoid both false negatives and false positives.69 

50. With regard to Southern’s argument that the DPT should take into account the 

overall size of the wholesale market or be replaced by a contestable load analysis, the 

Commission reaffirms its determination that the contestable load analysis is essentially a 

variant on the pivotal supplier screen, and therefore redundant. As a variant of the 

pivotal supplier screen, the contestable load analysis has differences in the calculation of 

wholesale load and the test thresholds. Like the pivotal supplier screen, it addresses 

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

 68 April 14 Order, 107 FERC ¶ 61,018 at P 111. 

69 Order No. 697 at P 113; July 8 Order, 108 FERC ¶ 61,026 at P 95-97; NOPR at 

P 41. 
Docket No. RM04-7-001 -37- 

Incorporating such an analysis would not improve our ability to establish a presumption 

of whether a seller possesses market power and would add little useful information.70 In 

addition, because the indicative screens measure a seller’s market power at both peak and 

off-peak times, they therefore measure market power potential during periods of both 

high and low demand, and this concern need not be addressed in the DPT.71 

51. We also reject Southern’s argument that the DPT should be replaced by the 

contestable load analysis. First, unlike the DPT, the contestable load analysis fails to 

consider relative prices of competing suppliers.72 Second, contrary to Southern’s claim, 

the DPT does consider wholesale load because it analyzes ten different seasons/load 

periods and the Available Economic Capacity (AEC) analysis deducts the native load 

commitments of all suppliers, which includes wholesale commitments. 

4. Other Products and Models

Final Rule

52. Regarding relevant product markets, the Commission stated in the Final Rule: 

[w]e will not generically alter the indicative screens or the DPT to allow 

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

commenters suggest. As the Commission has stated in the past, absent 

entry barriers, long-term capacity markets are inherently competitive 

because new market entrants can build alternative generating supply. There 

is no reason to generically require that the horizontal analysis consider 

those products that are affected by entry barriers. Instead, we will consider 

 70 Order No. 697 at P 66. 

71 Id. P 65-66. 

72 Id. P 67. 
Docket No. RM04-7-001 -38- 

intervenors’ arguments in this regard on a case-by-case basis.[73] 

53. The Commission also rejected suggestions by some commenters that it adopt 

behavioral modeling, such as game theory, in addition to or in place of the indicative 

screens and the DPT. The Commission explained that, although game theory has been 

used in laboratory experiments and in theoretical studies where the number of players and 

choices available to players are limited, it is not a practical approach given the volume of 

analyses the Commission must perform. The Commission noted that a large number of 

choices are available in market power analyses and many of those are unobservable, and 

concluded that data gathering and analysis burden imposed on sellers and the 

Commission if it were to adopt behavior modeling would be overly burdensome and 

impractical.74

Requests for Rehearing

54. NASUCA argues that the Commission must investigate whether sellers are able to 

raise electricity auction market rates to higher non-competitive levels, without collusion, 

through strategic bidding and gaming behavior in Commission-approved auction 

markets.75 NASUCA states that experience, mathematical game theory analysis, judicial 

decisions, and laboratory simulations indicate that market participants who pass market 

power screens nonetheless may be able to elevate prices in Commission-approved 

 73 Id. P 122. 

74 Id. P 124. 

75 NASUCA Rehearing Request at 5. 
Docket No. RM04-7-001 -39- 

auction markets through non-collusive strategic bidding, withholding, and gaming 

tactics.76 NASUCA states that the Commission’s market power screens are based on a 

static analysis of single sellers’ market shares, stating that less than a 20 percent share of 

the relevant market capacity is sufficient and less than the supply margin on the annual 

peak day satisfies the “supply margin assessment.” NASUCA concludes that neither of 

these tools addresses the problem identified in the research that sellers in these 

specialized markets repeatedly communicate through their bidding behavior.77 

55. NASUCA states that, to its knowledge, the Commission has never publicly 

discussed mathematical game theory analysis in depth in its orders, has not investigated 

the problem, and has held no technical conference or workshop to invite researchers to 

present their findings regarding gameability of the wholesale electricity markets.78 

NASUCA argues that strategic market behavior analysis is needed to assess whether 

current market designs allow participants, without overt collusion, to elevate market 

prices to unreasonable and non competitive levels. The purpose of such analysis would 

be to take corrective action to prevent gaming behavior, by revising market designs or 

rules. NASUCA asserts that the Commission misunderstood NASUCA’s request in 

finding that consideration and analysis of such behavior would be burdensome.79 

 76 Id. at 2. 

77 Id. at 6. 

78 Id. at 7 (citing Order No. 697 at P 121, 124). 

79 Id. at 7 (citing Order No. 697 at P 124). 
Docket No. RM04-7-001 -40- 

56. NASUCA argues that the “primary purpose” of the FPA and the Commission is 

protection of utility consumers. NASUCA states that, in order to achieve confidence that 

rates set in Commission-sanctioned markets are reasonable, the Commission must 

investigate strategic bidding and market gaming by market participants.80 NASUCA 

therefore requests that, at a minimum, the Commission commence a proceeding to 

investigate this and begin it by inviting researchers who have identified strategic auction 

market gaming as a problem in auction markets of the type used for the sale of electricity 

to present their research at a public technical conference. 

57. APPA/TAPS argue that, in addition to the existing indicative screens, the 

Commission should require that the market share screen be submitted using only firm 

transmission capacity.81 In this regard, APPA/TAPS state that applicants should be 

required to “submit a ‘firm transmission Market Share Screen’ where the SIL 

[simultaneous transmission import limit] study reflects only firm transmission 

capacity.”82 According to APPA/TAPS, running the market share screen using only firm 

transmission in the SIL study would provide evidence about who could realistically 

compete to sell long-term, firm products. Further, APPA/TAPS argue that the pivotal 

supplier screen is not well adapted to examining market conditions for long-term 

 80 Id. (citing Electrical Dist. No. 1 v. FERC, 774 F.2d 490, 492-93 (D.C. Cir. 

1984)). 

81 APPA/TAPS Rehearing Request at 13. 

82 Id. 
Docket No. RM04-7-001 -41- 

products, and that the firm transmission market share screen could be performed to 

provide better insight into the market for long-term products. APPA/TAPS assert that to 

understand what long-term generation capacity may be available and backed by firm 

transmission service, the market share screen should be run using an SIL study of firm 

transmission capacity only, preferably using available transfer capability (ATC) for the 

upcoming annual period, but at a minimum, run without capacity benefit margin (CBM) 

modeled as available, even on a non-firm basis.83 APPA/TAPS also argue that the 

Commission should require sellers to calculate the simultaneous available import 

capability of their systems using the firm ATC values that transmission customers are 

given, and use those results to prepare one of the iterations of the market share screen.84

Commission Determination

58. We have considered the strategic bidding literature and various theoretical models 

which demonstrate that market participants who pass market power screens nonetheless 

may be able to elevate prices in Commission-approved auction markets through “noncollusive strategic bidding, withholding, and gaming tactics.” However, the Commission 

does not think it is necessary to investigate the possibility of whether sellers or market 

participants are able to engage in strategic bidding, withholding and gaming tactics to 

elevate prices in auction markets in order to determine whether to grant market-based rate 

authority. First, these theoretical or gaming models require consideration of numerous 

 83 Id. at 16. 

84 Id. at 17. 
Docket No. RM04-7-001 -42- 

assumptions and hypothetical future behavior that may quickly become invalid because 

of the changing behavior of market participants, changes in the market or changes in 

other factors, e.g., supply or demand. Accordingly, the Commission is concerned that 

they would not be reliable tools in helping assess whether a seller has market power. 

Second, the type of behavior described by NASUCA may be prohibited by the 

Commission’s Anti-Manipulation Rule at section 1c.2 of the Commission’s regulations.85 

Violations of the Anti-Manipulation Rule include behavior constituting a fraud that had 

the purpose of impairing, obstructing, or defeating a well-functioning market.

86 The 

Commission’s Office of Enforcement monitors activity in the electric markets and 

conducts investigations to determine whether market participants are violating the AntiManipulation Rule. To the extent that NASUCA or any other entity has specific 

allegations of market manipulation, that entity should contact the Commission’s 

Enforcement Hotline or the Division of Investigations of the Office of Enforcement. 

Finally, as the Commission stated in Order No. 697, for practical considerations the data 

gathering and analysis burden imposed on sellers and the Commission to consider all the 

hypothetical types of behavior would be overly burdensome and impractical.87 

 85 Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 

(Jan. 26, 2006), FERC Stats. & Regs. ¶ 31,202 (2006), reh’g denied, 114 FERC ¶ 61,300 

(2006). 

86 Order No. 670, FERC Stats. & Regs. ¶ 31,202 at P 50-53. 

87 Order No. 697 at P 124. 
Docket No. RM04-7-001 -43- 

59. With regard to APPA/TAPS’ argument that the existing indicative screens should 

be altered so that sellers are required to “submit a ‘firm transmission Market Share 

Screen’ where the SIL study reflects only firm transmission capacity” in order to examine 

market conditions for long-term products, we reiterate that the indicative screens are 

intended to identify sellers that raise no horizontal market power concerns in short-term 

markets, and we decline to allow different product analyses for short-term or long-term 

power. We address the issue of the analysis of the competitiveness of long-term markets 

in the section of this order addressing mitigation. Thus, we reject APPA/TAPS’ 

argument that sellers should be required to submit a firm transmission market share 

screen where the SIL study reflects only firm transmission capacity. 

5. Native Load Deduction

Final Rule

60. In Order No. 697, the Commission modified the native load proxy for the market 

share screen from the minimum peak day in the season to the average peak native load, 

averaged across all days in the season, making the native load proxy for the market share 

indicative screen consistent with the native load proxy under the pivotal supplier 

indicative screen. The Commission found that using the existing native load proxy did 

not provide an accurate picture of the conditions throughout the season. The Commission 

explained that a native load proxy based on the average of peak load conditions is more 

representative, and thus more accurate, than a proxy based on extreme (minimum) peak 

load conditions, and further, that basing the native load proxy on the average of the peaks 
Docket No. RM04-7-001 -44- 

is more accurate by eliminating sellers without market power while focusing on ones that 

may have market power. 

61. In addition, the Commission clarified that native load can only include load 

attributable to native load customers based on the definition of native load in section 

33.3(d)(4)(i) of the Commission’s regulations and gave sellers the option of using 

seasonal capacity instead of nameplate capacity. 

Requests for Rehearing

62. TDU Systems assert on rehearing that the Commission’s failure to explain how its 

modification of the native load proxy in the wholesale market share screen is rationally 

related to the objective of accurately detecting the market power of electric utilities in 

their home control areas is arbitrary and capricious.88 

63. TDU Systems argue that the Commission should maintain the existing native load 

proxy for use in the wholesale market share screen89 because the Commission does not 

provide a reasoned analysis and supporting evidence for increasing the native load proxy 

for the market share indicative screen from the minimum daily native load peak demand 

for the season to the average daily native load peak demand for the season.90

 88 TDU Systems Rehearing Request at 3 (citing Motor Vehicle Mfrs. Ass’n v. 

State Farm Mut. Auto Ins. Co., 463 U.S. 29, 42-43 (1983); Pac. Gas & Elec. Co. v. 

FERC, 373 F.3d 1315, 1319 (D.C. Cir. 2004)). 

89 Id. at 7. 

90 Id. at 8, 18. 
Docket No. RM04-7-001 -45- 

64. TDU Systems point out the Commission’s explanation that the virtue of having the 

two indicative screens is that they each measure different market conditions,91 and assert 

that, to achieve that purpose, they should use different proxies for native load obligations. 

TDU Systems conclude that the Commission should revise the market share screen to use 

the minimum native load during the season as the proxy.92 

Commission Determination

65. In response to TDU Systems’ assertion that changing the native load proxy is 

arbitrary and capricious and may not accurately detect the market power of electric 

utilities in their home balancing authority areas, we acknowledge that increasing the 

native load proxy may have the effect of reducing the market share for traditional utilities 

and could result in fewer failures of the market share screen.93 However, as we explained 

in Order No. 697, the native load proxy adopted in Order No. 697 more accurately 

describes the conditions faced by sellers across seasons rather than simply at the most 

extreme peak load conditions.94 For instance, using the minimum peak day in the native 

 91 April 14 Order, 107 FERC ¶ 61,018 at P 90 (2004). 

92 TDU Systems Rehearing Request at 20. 

93 We note that use of the average daily native load peak demand for the season is 

also applicable to first-tier competitors. Thus, while a traditional utility applicant will 

have a lower amount of uncommitted capacity than it would have had using a native load 

proxy based on the minimum daily native load peak demand for the season, so too will 

traditional utility sellers in first-tier markets. Accordingly, although the traditional utility 

applicant’s uncommitted capacity is reduced, so too is the relative size of the market 

considering imports from first-tier markets. All else being equal, the market shares of the 

traditional utility applicant may not change much if at all. 

94 Order No. 697 at P 137. 
Docket No. RM04-7-001 -46- 

load proxy only measures sellers’ available capacity on a single day, and does not reflect 

the more general conditions faced by sellers throughout the season. Because changing 

the native load deduction will lead to a more accurate measure of uncommitted capacity 

for load-serving entities, there will be a more accurate measure of the conditions faced by 

competing suppliers. Thus, the native load proxy is more accurate in detecting the 

market power of electric utilities in their home balancing authority areas. 

66. We reject TDU Systems’ argument that because the pivotal supplier and market 

share screens measure different market conditions they should therefore use different 

native load proxies. We disagree and find that is not appropriate to use different native 

load proxies for the different screens. Although the screens themselves use inherently 

different methodologies, the native load does not vary depending on which screen is 

used. Accordingly, we find that use of the average peak native load as the native load 

proxy for both screens provides an accurate picture of the conditions throughout the 

season. 

67. We also clarify the definition of native load as it is used in the DPT analysis. With 

regard to the statement in the Final Rule that under the DPT, a seller “will be considered 

pivotal if the sum of the competing suppliers’ economic capacity is less than the load 

level (plus a reserve requirement that is no higher than State and Regional Reliability 

Council operating requirements for reliability) for the relevant period”95 we clarify that 

the analysis should also be performed using available economic capacity to account for 

 95 Id. P 108. 
Docket No. RM04-7-001 -47- 

sellers’ and competing suppliers’ native load commitments. We further clarify that 

native load in the relevant market (sellers’ and competing suppliers’) should be 

subtracted from the total load in each season/load period, and that the native load 

subtracted should be the average of the hourly native load for each season load 

condition.96 

6. Relevant Geographic Market

Final Rule

68. In Order No. 697, the Commission adopted its existing approach with respect to 

the default relevant geographic market, with some modifications. The Commission 

announced that it would continue to use a seller’s balancing authority area97 or the 

RTO/ISO market,98 as applicable, as the default relevant geographic market, explaining 

that the use of defined default geographic markets provides the industry with as much 

certainty as possible while also providing parties the right to challenge the default 

geographic market definition and submit pertinent evidence.99 

69. With respect to traditional (non-RTO/ISO) markets, the Commission adopted a 

rebuttable presumption that the seller’s default relevant geographic market under both 

 96 See id. P 150 (citing 18 CFR 33.3(d)(4)(i)). 

97 Previously, the Commission had used the term “control area,” but in the Final 

Rule it replaced that term with “balancing authority area” with regard to relevant 

geographic markets. 

98 An RTO/ISO must have a sufficient market structure and a single energy market 

with Commission-approved market monitoring and mitigation. 

99 Order No. 697 at P 235. 
Docket No. RM04-7-001 -48- 

indicative screens would be the balancing authority area where the seller is physically 

located, and each of its neighboring first-tier balancing authority areas.100 

70. With respect to RTO/ISO markets, the Commission stated that sellers located in 

and members of the RTO/ISO may consider the geographic region under the control of 

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

horizontal analyses, unless the Commission has already found the existence of a 

submarket. Where the Commission makes a specific finding that there is a submarket 

within an RTO/ISO, that submarket becomes the default relevant geographic market for 

sellers located within the submarket for purposes of the market power analysis (both 

indicative screens and DPT). In the Final Rule, the Commission concluded that sellers 

located in these RTO/ISO submarkets should not use the entire RTO/ISO footprints as 

their relevant geographic markets. The Commission explained that this policy is 

consistent with how it has treated such submarkets in the context of mergers; the Final 

Rule cited several cases to support this proposition, including Exelon Corp.,

101 where the 

Commission found that PJM-East and Northern PSEG are sub-markets within PJM 

Interconnection (PJM). 

71. The Commission stated that it would continue to allow sellers and intervenors to 

present evidence on a case-by-case basis to show that some other geographic market 

 100 Id. P 231-32. 

101 112 FERC ¶ 61,011, reh’g denied, 113 FERC ¶ 61,299 (2005) (Exelon). The 

Commission noted that Exelon later terminated the merger. Order No. 697 at P 236 and 

n.220. 
Docket No. RM04-7-001 -49- 

should be considered as the relevant market in a particular case. To the extent that the 

Commission finds that a submarket exists within an RTO/ISO, intervenors or sellers can 

provide evidence to the contrary; thus, a submarket, like the other default geographic 

markets, is a rebuttable default geographic market.102 The Commission explained that it 

will also consider arguments that a seller operates in an RTO/ISO submarket even if the 

Commission has not previously found that a submarket exists. Likewise, sellers and 

intervenors also may present evidence that the relevant market is broader than a particular 

balancing authority area or RTO/ISO footprint or submarket. 

72. The Commission stated that sellers may incorporate the mitigation they are subject 

to in RTO/ISO markets or submarkets with Commission-approved market monitoring 

and mitigation as part of their market power analysis.103 By way of example, if a market 

power analysis indicates that a seller may have market power, the seller may point to the 

RTO/ISO mitigation rules as evidence that its market power has been adequately 

mitigated. The same is true for submarkets; for instance, New York City will be treated 

as a separate default market for market-based rate study purposes, and its existing In-City 

mitigation will be used to assess whether any concerns over market power are already 

mitigated.104 

Requests for Rehearing 

 102 Id. P 238. 

103 Id. P 241. 

104 Id. P 242. 
Docket No. RM04-7-001 -50- 

73. TDU Systems and NRECA object to the Commission’s determination to use a 

balancing authority area or RTO/ISO region as a default relevant geographic market; they 

believe that a seller should always have the burden of defining the appropriate geographic 

market or submarket and that the Commission cannot lawfully place the burden on 

customers or intervenors to show that the “default” market is not the relevant geographic 

market.105 Thus, NRECA argues that the Commission’s determination to use the 

applicant public utility’s balancing authority area or the RTO/ISO region as the default 

relevant geographic market is arbitrary, capricious, contrary to law, in excess of statutory 

authority, and not supported by substantial evidence.106 Further, according to NRECA, 

the Final Rule did not adequately respond to NRECA’s argument that default geographic 

markets should not be used because the Commission cannot place the burden on 

intervenors to demonstrate that the default market is not the relevant geographic market, 

and failed to satisfactorily explain the Commission’s action “‘including a rational 

connection between the facts found and the choice made.’”107 

 105 TDU Systems Rehearing Request at 15; NRECA Rehearing Request at 18. 

106 NRECA Rehearing Request at 2-3 (citing Secretary of Labor v. Keystone Coal 

Mining Corp., 151 F.3d 1096, 1100 (D.C. Cir. 1998) (Keystone); 5 U.S.C. 556(d); 

5 U.S.C. 706(2)(A), (C), (E); 16 U.S.C. 824d(e); 16 U.S.C. 825l(b); Preventing Undue 

Discrimination and Preference in Transmission Service, Order No. 890, 72 FR 12265 

(March 15, 2007), FERC Stats. & Regs. ¶ 31,241, at P 901-1094 (2007), order on reh’g 

and clarification, Order No. 890-A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. & Regs. 

¶ 31,261 (2007)). 

107 Id. at 20 (quoting Pac. Gas & Elec. Co. v. FERC, 373 F.3d 1315, 1319 (D.C. 

Cir. 2004)). 
Docket No. RM04-7-001 -51- 

74. TDU Systems state that, although the Commission has attempted to create a 

“balanced approach,” it is arbitrary and capricious to grant market-based rate authority 

based on the inaccurate assumption that in most cases, the Commission will rely on 

RTO/ISO regions as default geographic markets. TDU Systems cite Keystone for the 

proposition that evidentiary presumptions are only permissible in the presence of a 

connection between proven and inferred facts, and asserts that, “[e]ven with the 

submarkets the Commission identifies in the Final Rule (at P 246), the exceptions to the 

rule are still far too numerous to declare that the proposal can pass the ‘so probable that it 

is sensible’ test.”108 It argues that public utility sellers should have an affirmative 

obligation, meeting the strict standard for burden shifting, to identify the relevant 

geographic market and justify the market used in their horizontal market power analyses. 

Using the wrong default geographic markets prevents the Commission from accurately 

assessing the public utility’s market power and thus contravenes the statutory 

prerequisites. 

75. NRECA and TDU Systems claim that the use of RTO/ISO regions and balancing 

authority areas as default relevant markets in many cases will not produce valid screen 

results because they do not take into account well-known binding transmission 

constraints and load pockets, such as those the Commission has found in the New York 

Independent System Operator (NYISO) and the ISO New England (ISO-NE) 

 108 TDU Systems Rehearing Request at 15. 
Docket No. RM04-7-001 -52- 

submarkets.109 They assert that the Commission should eliminate the use of the seller’s 

balancing authority area or RTO/ISO region as the relevant market and instead require an 

applicant to identify the relevant geographic market based on actual data including grid 

topology and existing transmission constraints.110 

76. In contrast to the arguments raised on rehearing by NRECA and TDU Systems, 

PSEG and Reliant find fault with the Commission’s ruling that the larger RTO/ISO 

region will not be used as the default geographic market for market-based rate sellers 

located in RTO/ISO areas where the Commission has found submarkets to exist. PSEG 

claims that the ruling departs from many years of Commission policy utilizing the 

RTO/ISO as the default relevant geographic market and is inconsistent with the 

Commission’s confidence in the impact of RTO/ISO market monitoring and 

mitigation.111 PSEG asserts that this major change in policy is not supported by 

substantial evidence, is not a product of reasoned decision making,112 and claims that “it 

 109 NRECA Rehearing Request at 19 (“Given that the Commission was able to 

find submarkets in relatively compact and contiguous regions such as [NYISO] and [ISONE], then the notion of using far-flung RTO/ISO regions such as the Midwest ISO and 

SPP as default markets is untenable”); TDU Systems Rehearing Request at 15. 

110NRECA Rehearing Request at 20; TDU Systems Rehearing Request at 16. 

111 PSEG Rehearing Request at 2-3 (quoting Order No. 697 at P 290 (“We believe 

that a single market with Commission-approved market monitoring and mitigation and 

transparent prices provides added protection against a seller’s ability to exercise market 

power ....”)). 

112 Id. at 6 (citing Moraine Pipeline Co. v. FERC, 906 F.2d 5, 9 (D.C. Cir. 1990) 

(reasoned decision making requires that the Commission must not just acknowledge 

arguments made, but must “respond to [such] arguments and . . . articulate its decision 

(continued...) 
Docket No. RM04-7-001 -53- 

is difficult to discern the legal or factual basis for the change.”113 Regarding the 

Commission’s explanation that the consideration of submarkets is consistent with the 

Commission’s merger analysis, PSEG states that “simply because the Commission 

needed to examine submarket impacts in the context of an individual merger proceeding 

does not make that submarket appropriate as a default geographic market to be applied 

going forward on a generic basis for all sellers in that submarket.”114 PSEG argues that 

the focus of the market power analysis is substantively different in the two types of 

proceedings, and that the public was not on notice that the Commission might rely on 

findings from a merger proceeding to create a generic rule applicable to all parties located 

in the same area, thus constituting “retroactive rulemaking.” Moreover, PSEG contends 

that by basing a generic determination of submarkets on prior merger filings rather than 

after a systematic review of market power in a region, the Commission adopts a policy 

that discriminates against some market participants because a market-based rate seller 

can be located in an RTO/ISO sub-region that has greater instances of transmission 

 

based on evidence in the record”); Motor Vehicles Mfrs. Ass’n. v. State Farm Mutual 

Auto. Ins. Co., 463 U.S. 29, 43, 48, 57 (1983); Williams Natural Gas Co. v. FERC, 

90 F.3d 531, 533 (D.C. Cir. 1996) (To be upheld, the Commission’s order must be 

“supported by substantial evidence and reached by reasoned decision-making — that is, a 

process demonstrating the connection between the facts found and the choice made.”)). 

113 Id. PSEG also cites Missouri Public Service Commission v. FERC, 234 F.3d 

36, 40 (D.C. Cir. 2000) (when “the Commission balances competing interests in arriving 

at its decision, it must explain on the record the policies which guide it.”). 

114 Id. at 6-7. See also Reliant Rehearing Request at 5-6, warning that sellers may 

have no choice but to intervene and potentially litigate in additional proceedings where 

the Commission may possibly make a finding that identifies a new submarket. 
Docket No. RM04-7-001 -54- 

constraints than any of the submarkets specifically identified in Order No. 697, but will 

still be able to proceed with a market-based rate application using the RTO/ISO as the 

default relevant geographic market.115 PSEG asserts that a fairer approach would be to 

review potential submarkets comprehensively as part of the regional review process that 

will be conducted according to the schedule provided in Appendix D of the Final Rule.116 

77. Reliant states that the record does not support the use of submarkets in indicative 

screens, noting that one commenter advocated use of a submarket when applying the 

DPT but that no commenters suggested that the indicative screens should be performed 

utilizing a submarket. Reliant argues that when a submarket is used within an RTO/ISO 

in indicative screens, the applicable default market used will be smaller than the full 

market within which a seller participates. Reliant claims that this is inconsistent with the 

design and intent of the indicative screens because identification of a submarket is 

unpredictable, and because a submarket identified in another potentially unrelated 

proceeding may be used.117

78. PSEG argues further that the Commission ignored record evidence proving the 

lack of technical and policy merit in creating submarkets when performing market power 

analyses submitted by the three RTO/ISOs that commented on the issue; and it claims 

that California ISO (CAISO), ISO-NE, and NYISO agree that there is no technical and 

 115 Id. at 8. 

116 Id. at 9. 

117 Reliant Rehearing Request at 5-6. 
Docket No. RM04-7-001 -55- 

structural need for the examination of RTO/ISO submarkets.118 According to PSEG, the 

Commission’s failure to meaningfully consider that evidence and to respond to it was 

arbitrary and capricious and not reasoned decisionmaking.119 

79. PSEG contends that submarkets are inappropriate as default relevant geographic 

markets because they are largely a product of transmission constraints that periodically 

create short-term price differences between neighboring geographic areas. Such 

differences, it states, are not static and can be altered over the long term by transmission 

reinforcements, new generation entry, and changes in load.120 It concludes that the 

unpredictable nature of those forces makes submarkets unreliable for assessing market 

power, and believes that the Commission should have retained the RTO/ISO as the 

default relevant geographic market so long as the RTO/ISO has market monitoring and 

mitigation programs in place in conjunction with a regional transmission expansion 

planning program. 

 118 PSEG Rehearing Request at 4-6 (citing NYISO NOPR comments at 3-4; ISONE NOPR comments at 4 and 6; and CAISO NOPR comments at 13). 

119 Id. at 6 (citing Moraine Pipeline Co. v. FERC, 906 F.2d 5, 9 (D.C. Cir. 1990) 

(holding that the Commission must not just acknowledge arguments made but must 

respond to such arguments)). 

120 Reliant Rehearing Request at 7-8; PSEG Rehearing Request at 9-10. Reliant 

limits its objections to the use of submarkets in indicative screens. 
Docket No. RM04-7-001 -56- 

80. With specific reference to the Commission’s generic finding of submarkets in 

Eastern PJM and Northern PSEG, PSEG alleges that the Commission erred in relying on 

a prior ruling in the Exelon-PSEG merger proceeding,121 which merger was subsequently 

terminated. According to PSEG, the Commission cannot rely on the Exelon-PSEG 

merger proceeding because that analysis was dependent on the assumption that Exelon 

and PSEG would merge; the termination of the merger changed key assumptions that 

were material to the market power analysis examining what changes to competitive 

conditions would occur as a consequence of the merger. 

Commission Determination

81. We affirm our decision to use a balancing authority area or RTO/ISO region as a 

default relevant geographic market. In Order No. 697, the Commission fully explained 

the basis for using default geographic markets. The Commission explained that the use 

of defined default geographic markets provides sellers and intervenors a measure of 

certainty regarding the relevant market while also providing parties the right to challenge 

the default geographic market definition and submit pertinent evidence of an alternative 

geographic market based on actual data. 

82. As discussed more fully below, we reject NRECA’s and TDU Systems’ argument 

that the Commission’s determination to use the applicant public utility’s balancing 

authority area or the RTO/ISO region as the default relevant geographic market is 

 121 PSEG Rehearing Request at 10, referring to Exelon Corp., 112 FERC ¶ 61,011, 

order on reh’g, 113 FERC ¶ 61,299 (2005). 
Docket No. RM04-7-001 -57- 

arbitrary, capricious, contrary to law, in excess of statutory authority, and not supported 

by substantial evidence. In Order No. 697 the Commission carefully considered and 

balanced various arguments on both sides of the issue concerning whether it is 

appropriate to use default geographic markets for purposes of the horizontal analysis. 

83. Our use of the applicant public utility’s balancing authority area or the RTO/ISO 

region as the default relevant geographic market is supported by the evidence. In 

particular, with regard to traditional (non-RTO/ISO) markets, the Commission adopted as 

the default geographic market first the balancing authority area where the seller is 

physically located and, second, the markets directly interconnected to the seller’s 

balancing authority area (first-tier balancing authority area markets). Our decision to use 

the balancing authority area or the RTO/ISO region as the default geographic market 

closely tracks our guidance provided in Order No. 697 on what constitutes a market.122 

Our experience has indicated that typically there are frequently recurring physical 

impediments to trade between balancing authority areas that would prevent competing 

supplies from first-tier markets from reaching wholesale customers.123 Thus, our 

decision to consider balancing authority areas as the default geographic market is neither 

arbitrary nor capricious but, rather, firmly embedded in the characteristics of our 

jurisdictional markets. 

 122 Order No. 697 at P 231-232. 

123 Id. P 268. 
Docket No. RM04-7-001 -58- 

84. In addition, with regard to public policy considerations and regulatory certainty, 

the Commission explained in Order No. 697 that using balancing authority areas allows 

the Commission and the public to rely on publicly available data provided for balancing 

authority areas that are relevant to the market-based rate analysis.124 Further, it is the 

interconnection and coordination between balancing authority areas that provides a 

foundation for the Commission to analyze transmission limitations and other transfers of 

energy and provides reasonable measures of the relevant geographic market under typical 

circumstances.125 

85. With regard to RTO/ISO markets, the Commission's approach has been well 

considered and consistent with our approach described above regarding traditional 

markets. After weighing all the facts, including our experience regulating these markets, 

the Commission concluded that the geographic region under the control of the RTO/ISO 

 124 Id. P 233. 

125 Id. P 251. Similar to a control area, a balancing authority area is physically 

defined with metered boundaries that we refer to as the balancing authority area. Every 

generator, transmission facility, and end-use customer must be in a balancing authority 

area. The responsibilities of a balancing authority include the following: (1) match, at all 

times, the power output of the generators within the balancing authority area and capacity 

and energy purchased from or sold to entities outside the balancing authority area, with 

the load within the balancing authority area in compliance with the Reliability Standards; 

(2) maintain scheduled interchange and control the impact of interchange ramping rates 

with other balancing authority areas, in compliance with Reliability Standards; (3) have 

available sufficient generating capacity, and Demand Side Management to maintain 

Contingency Reserves in compliance with Reliability Standards; and (4) have available 

sufficient generating capacity, Demand Side Management, and frequency response to 

maintain Regulating Reserves and Operating Reserves in compliance with Reliability 

Standards. Id. (citing Approved Reliability Standards. 

http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp). 
Docket No. RM04-7-001 -59- 

is the appropriate market absent evidence to the contrary. Thus, as a starting point and 

consistent with our guidance on what constitutes a market, the Commission has made a 

finding that the geographic region under the control of the RTO/ISO is appropriate for 

use as the default geographic market. In addition, where the Commission has made a 

specific finding that there is a submarket within an RTO/ISO, the Commission explained 

that the submarket should be considered as the default relevant geographic market. Thus, 

our decision to consider the geographic region under the control of the RTO/ISO as the 

default geographic market, unless the Commission makes a specific finding of the 

existence of a submarket, is neither arbitrary nor capricious, but similarly embedded in 

the characteristics of our jurisdictional markets. 

86. With regard to TDU Systems’ and NRECA’s assertion that a seller should always 

have the burden of defining the appropriate geographic market or submarket and that the 

Commission cannot lawfully place the burden on customers or intervenors to show that 

the “default” market is not the relevant geographic market, we disagree. As stated above, 

after careful consideration and based on the facts before us, the Commission has made 

findings regarding these geographic markets. We reject TDU Systems’ and NRECA’s 

argument that under Keystone, the Commission may not grant market-based rate 

authority based on the assumption that, in most cases, the Commission will rely on 

RTO/ISO regions as default geographic markets because such a presumption shifts the 

burden of establishing the relevant geographic market from the seller to intervenors. In 

Keystone, the court found that an evidentiary presumption is only permissible if there is 
Docket No. RM04-7-001 -60- 

“a sound and rational connection between the proved and inferred facts.”126 Contrary to 

TDU Systems’ and NRECA’s argument that there is no evidence to support use of 

RTO/ISO regions as default geographic markets, and, as explained in the Final Rule, the 

RTO/ISO regions have historically been used as default geographic markets.127 As 

explained in the Final Rule and prior orders, we have used RTO/ISO regions as the 

default market for many reasons, including the central commitment and dispatch in most 

RTOs/ISOs, the elimination of trade barriers within those regions (e.g., pancaked rates), 

common market mitigation and other factors.128 On rehearing, TDU Systems and 

 126 Keystone, 151 F.3d 1096 at 1100. 

127 See April 14 Order at P 41, 187 (stating that when performing the generation 

market power analysis, applicants located in RTOs/ISOs with sufficient market structure 

may consider the geographic region under the control of the RTO/ISO as the relevant 

default geographic region for purposes of completing their analyses, and comparing the 

practice to the Commission’s earlier approach under the hub and spoke analysis). 

128 See, e.g., April 14 Order at P 187-191; July 8 Order at P 177; Mystic I, LLC, 

111 FERC ¶ 61,378, at P 14-19 (2005) (rejecting challenge to the use of ISO-NE market 

as the relevant geographic market on the basis that local market power mitigation is in 

place: “[W]ithout specific evidence to the contrary, we are satisfied that ISO-NE has 

Commission-approved tariff provisions in place to address instances where transmission 

constraints would otherwise allow generators to exercise local market power and that 

these rules and procedures will apply in the NEMA/Boston zone within ISO-NE.”); 

Wisconsin Electric Power Co., 110 FERC ¶ 61,340, at P 19-20, reh’g denied, 111 FERC 

¶ 61,361, at P 13-15 (2005) (rejecting challenge to use of Midwest ISO market as the 

relevant geographic market on basis that local market power mitigation measures exist: 

“The tighter thresholds in NCAs such as WUMS in the Midwest ISO, and the resulting 

tighter mitigation of bids, are local market power mitigation measures” and should 

adequately address specific concerns regarding the possibility that Wisconsin Electric can 

exercise market power in the WUMS region). Accord AEP Power Marketing, Inc., 

109 FERC ¶ 61,276 (2004), reh’g denied, 112 FERC ¶ 61,320, at P 23-25 (2005), aff’d, 

Industrial Energy Users-Ohio v. FERC, No. 05-1435 (D.C. Cir. Feb. 16, 2007) (use of 

PJM footprint as relevant geographic market; noting existence of Commission-approved 

(continued...) 
Docket No. RM04-7-001 -61- 

NRECA have presented no empirical evidence demonstrating that RTO/ISO regions 

should not be used as default geographic markets, or that the use of RTO/ISO regions as 

default geographic markets is inadequate or insufficient for the typical situation. 

87. We agree with NRECA and TDU Systems that we should take into account 

binding transmission constraints and load pockets in both RTO/ISO regions and 

balancing authority areas and Order 697 does so. Based on our findings on binding 

transmission constraints, the Commission has identified six submarkets in NYISO, PJM, 

and ISO-NE, as described in Order No. 697.129 Where the Commission has made a 

specific finding that there is a submarket within an RTO/ISO or within any other market, 

the market-based rate analysis (both the indicative screens and the DPT) should consider 

that submarket as the default relevant geographic market.130 We note that NRECA and 

TDU Systems’ argument that the use of RTO/ISO regions and balancing authority areas 

as the default relevant market in many cases will not produce valid screen results because 

this use does not take into account “well-known binding transmission constraints and 

 

market monitoring and mitigation). See also Midwest Independent Transmission System 

Operator, Inc., 109 FERC ¶ 61,157, at P 463 (2004) (noting that the Midwest ISO-wide 

market will not be considered as the default geographic market until such time as the 

Midwest ISO becomes a single market and performs functions such as single central 

commitment and dispatch with Commission-approved market monitoring and 

mitigation). 

129 Id. P 236. 

130 Id. 
Docket No. RM04-7-001 -62- 

load pockets” is overly simplistic. The Commission has provided in Order No. 697131

guidance as to the record information needed to make a determination that an alternative 

geographic market is appropriate (e.g., expanded market, submarket). The Commission 

will, and has,132 carefully considered record evidence regarding geographic markets. In 

particular, “well-known” is an arbitrary term and does not meet the type of evidence 

needed for the Commission to base a determination. Accordingly, we will continue to 

use a seller’s balancing authority area or the RTO/ISO market, as applicable, as the 

default relevant geographic market, unless the Commission makes a specific finding of 

the existence of a submarket. 

88. We disagree with PSEG’s statement that, “simply because the Commission needed 

to examine submarket impacts in the context of an individual merger proceeding does not 

make that submarket appropriate as a default geographic market to be applied going 

forward on a generic basis for all sellers in that submarket.” As discussed above, our 

determination of what constitutes a geographic market is not dependent upon whether the 

type of proposal before us is in the context of a market-based rate or merger proceeding. 

Rather, we base our determination on facts relating to a particular region and the 

guidelines we have provided regarding what constitutes a geographic market. Whether in 

a merger proceeding, RTO proceeding, or market-based rate proceeding the fundamental 

 131 Id. P 267-278. 

132 See Pinnacle West Capital Corp., 122 FERC ¶ 61,035 (2008). 
Docket No. RM04-7-001 -63- 

characteristics of a market does not change nor should we ignore our findings because 

administratively they were made in a different proceeding. 

89. With regard to PSEG’s argument that the public was not on notice that the 

Commission might rely on findings from a merger proceeding that could apply in 

subsequent market-based rate proceedings, we reiterate that, to the extent that the 

Commission finds that a submarket exists within an RTO/ISO, intervenors or sellers can 

provide evidence to the contrary (i.e., the submarket, like our other default geographic 

markets, is rebuttable).133 Moreover, in the NOPR in this proceeding, the Commission 

explained that its experience with corporate mergers and acquisitions indicates that the 

RTO/ISOs that the Commission has identified as meeting the criteria for being 

considered a single market for purposes of performing the generation market power 

screens have, at times, been divided into smaller submarkets for study purposes because 

frequently binding transmission constraints prevent some potential suppliers from selling 

into the destination market. Therefore, the Commission sought comment on its approach 

under the market-based rate program of considering the entire geographic region under 

control of the RTO/ISO, with a sufficient market structure and a single energy market, as 

the default relevant market. Further, the NOPR asked whether the Commission should 

continue its approach of considering the entire geographic region as the default market 

for purposes of the indicative screens but consider RTO/ISO submarkets for purposes of 

 133 Order No. 697 at P 238. 
Docket No. RM04-7-001 -64- 

the DPT.134 Thus, contrary to PSEG’s argument, since the issuance of the NOPR in May 

2006, the public has been on notice that the Commission might rely on findings from a 

merger proceeding that could apply in determining RTO/ISO submarkets that may be 

used in market-based rate proceedings. 

90. However, we will grant PSEG’s request for rehearing regarding the Commission’s 

determination in the Final Rule that because the Commission made a prior finding in the 

Exelon-PSEG merger proceeding that Northern PSEG is a separate market in PJM, 

sellers in PJM should use that submarket as the default geographic market for their 

market-based rate analysis. After the parties in that case terminated the merger, the U.S. 

Court of Appeals for the D.C. Circuit vacated the Commission’s orders on procedural 

grounds. In light of the ultimate disposition of Exelon/PSEG merger proceeding, on 

reconsideration, we conclude that we erred in relying on a prior finding of submarkets 

that was made in that proceeding.135

91. With regard to PJM East, however, we note that in proceedings other than the 

Exelon/PSEG merger, the Commission also treated PJM-East as a market within PJM.136 

Accordingly, we reaffirm our finding in the Final Rule that because the Commission 

 134 NOPR at P 61; Order No. 697 at P 215. 

135 Exelon Corp., 112 FERC ¶ 61,011, reh’g denied, 113 FERC ¶ 61,299 (2005), 

vacated, PPL Electric Utilities Corp. V. FERC, No. 06-1009 (D.C. Cir. Dec. 21, 2006). 

136 See, e.g., El Paso Energy Corporation, 92 FERC ¶ 61,076 (2000), Energy East 

Corporation, 96 FERC ¶ 61,322 (2001), Potomac Electric Power Company, 96 FERC 

¶ 61,323 (2001). 
Docket No. RM04-7-001 -65- 

already has found that PJM-East constitutes a separate market in PJM, sellers located in 

PJM should use PJM-East as the default geographic market. 

92. We reject PSEG’s argument that the Commission's policy discriminates against 

some market participants. In particular, PSEG contends that a market-based rate seller 

can be located in an RTO/ISO sub-region that has greater instances of transmission 

constraints than any of the submarkets specified in the Final Rule, but will be able to 

proceed with a market-based rate application using the RTO/ISO as the default relevant 

market. As the Commission has stated, default geographic markets are adequate and 

sufficient for the typical situation, and by defining default geographic markets, we 

provide the industry as much certainty as possible while also providing affected parties 

the right to challenge the default geographic market definition and provide evidence in 

that regard.137 Thus, in the example posited by PSEG, if there is evidence that indicates 

high instances of transmission constraints within an RTO that has not been previously 

found to constitute a submarket, intervenors have the opportunity to present that evidence 

to the Commission. Accordingly, because all market participants have the opportunity to 

challenge the default geographic market definition, this policy does not discriminate 

against some market participants. Rather, the Commission's policy in this regard 

recognizes the findings the Commission has already made and Order No. 697 provides 

guidance to parties that wish to challenge the default geographic markets. 

 137 Id. P 234. 
Docket No. RM04-7-001 -66- 

93. With regard to PSEG’s claims that the Commission failed to consider evidence 

submitted by CAISO, ISO-NE, and NYISO that there is no technical and structural need 

for the examination of RTO/ISO submarkets, we find that where the Commission has 

made a specific finding that there is a submarket within an RTO/ISO, the market-based 

rate analysis should reflect the facts and consider that submarket as the default relevant 

geographic market. To do otherwise would be inconsistent with our findings of a 

submarket in the first instance. In particular, the Commission has consistently stated that 

the Commission-approved market monitoring and mitigation provides added protection 

against a seller’s ability to exercise market power, but cannot replace the generation 

market power analysis.138 While we consider carefully comments by interveners, this 

Commission will also consider all the facts before us before making a finding. 

94. In addition, while PSEG is correct that transmission constraints can be temporary, 

as noted above, all of the submarkets that the Commission has identified result from 

frequently binding transmission constraints during historical seasonal peaks examined; 

these particular constraints have not tended to be temporary in nature. Evidence with 

respect to whether a transmission constraint is temporary or is frequently binding will be 

considered in determining whether a submarket exists. To the extent that some existing 

constraints may be alleviated by construction of new transmission facilities, parties may 

bring these situations to our attention for further consideration. 

 138 See Order No. 697 at P 290. 
Docket No. RM04-7-001 -67- 

95. Without a correctly defined submarket, sellers with market power in the RTO/ISO 

market may not be identified, and their market power mitigated in both the real-time and 

day-ahead markets. While we acknowledge PSEG’s claim that the Commission’s 

determination on RTO/ISO submarkets departs from Commission policy utilizing the 

RTO/ISO as the default relevant geographic market, we disagree with PSEG’s claim that 

this is inconsistent with Commission confidence in the impact of RTO/ISO market 

monitoring and mitigation. The purpose of this rulemaking proceeding has been to 

consider and evaluate the Commission’s current market-based rate policy and to make 

adjustments to this approach, as warranted. Thus, we have carefully considered the facts 

before us, including our historical approach, and found it reasonable that where the 

Commission has made a specific finding that there is a submarket within an RTO/ISO, 

the market-based rate analysis should reflect those facts and consider that submarket as 

the default relevant geographic market because to do otherwise would be inconsistent 

with our findings of a submarket in the first instance. In addition, the Commission has 

been in the process of developing and improving policies that best protect customers and 

promote market competition in a manner that accounts for the changing nature of 

developing electricity markets. We will not depart from this basic approach. 

96. Moreover, PSEG overstates the difference between our prior policy and the policy 

adopted in Order No. 697. Prior to Order No. 697, the Commission did not identify 

submarkets within an RTO/ISO as default geographic markets, but one of the principal 

reasons for this policy was the ability to rely on Commission-approved mitigation in 

submarkets within RTOs/ISOs to mitigate any localized market power. Although Order 
Docket No. RM04-7-001 -68- 

No. 697 changed our approach to geographic market definition as it relates to 

submarkets, applicants may propose to continue to rely on Commission-approved 

mitigation in these submarkets as adequate to address any market concerns. 

RTO/ISO Exemption

Final Rule

97. Prior to the April 14 Order, the Commission exempted sellers located in markets 

with Commission-approved market monitoring and mitigation from providing generation 

market power analyses stating that such sellers will be governed by the specific 

thresholds and mitigation provisions approved for the particular markets.139 In the 

April 14 Order, the Commission determined that it would no longer exempt these sellers, 

on the basis that requiring sellers located in such markets to submit screen analyses 

provided an additional check on the potential for market power. In Order No. 697, the 

Commission declined the request by commenters that it reinstate the pre-April 14 Order 

exemption for sellers located in markets with Commission-approved market monitoring 

and mitigation from providing generation market power analyses. Instead, the 

Commission indicated that it would continue to require generation market power analyses 

from all sellers, including those in RTO/ISO markets. The Commission noted that while 

a single market with Commission-approved market monitoring and mitigation and 

 139 See AEP Power Marketing, Inc., 97 FERC ¶ 61,219 (2001). 
Docket No. RM04-7-001 -69- 

transparent prices provides added protection against a seller’s ability to exercise market 

power, it cannot replace the generation market power analysis.140 

Requests for Rehearing

98. Reliant and PSEG argue that the Commission should reconsider its decision not to 

exempt sellers located in markets with Commission-approved market monitoring and 

mitigation from submitting horizontal market power analyses. Reliant contends that the 

Commission did not explain what value a separate horizontal market power analysis 

would have, given that market monitoring by an independent market monitor consistent 

with Commission-approved rules and mitigation already identifies and mitigates market 

power. According to Reliant, market monitoring and mitigation provides a better picture 

of market power issues in RTO/ISO markets as compared to an individual seller’s 

separate horizontal market power analysis which considers only market power at a fixed 

moment in time and also provides relief from the costs and burdens of producing a 

horizontal market power analysis.141 In the alternative, if the Commission declines to 

reinstate the exemption, Reliant asserts that the Commission should clarify that 

Commission-approved mitigation rules presumptively mitigate a seller’s market power 

and, in addition, the Commission should reconsider its decision to utilize previously 

identified RTO/ISO submarkets as the relevant geographic market for the indicative 

screens. 

 140 Id. P 290. 

141 Reliant Rehearing Request at 2-3. 
Docket No. RM04-7-001 -70- 

99. Reliant opines that a fundamental purpose and objective of market monitoring and 

mitigation is to detect actual, and the potential for, market power and to safeguard against 

it so as to ensure that no seller in the market can dominate the market, manipulate price, 

or otherwise act to stifle competition.142 Accordingly, Reliant argues that a presumption 

that a seller’s market power is adequately mitigated where Commission-approved market 

monitoring and mitigation rules are in effect is entirely appropriate, unless an intervenor 

can demonstrate why Commission-approved mitigation is insufficient in a particular case. 

According to Reliant, it is not appropriate to add the administrative burden of applying 

indicative screens if the Commission believes that market monitoring and mitigation is 

generally working.143 

100. PSEG asserts that the Commission erred in failing to create a presumption that, 

even when the Commission has found submarkets to exist, no further analysis of the 

submarkets is required so long as a robust RTO/ISO market monitoring and mitigation 

scheme is in place. According to PSEG, a demonstration of a lack of market power in 

submarkets should only be required if there is reason to question whether such local 

 142 Id. at 3 (citing Market Monitoring Units in Regional Transmission 

Organizations and Independent System Operators, 111 FERC ¶ 61,267, at P 1 (2005) 

(market monitoring units perform an important role in enhancing competitiveness of 

RTO/ISO markets by, among other things, monitoring organized wholesale markets to 

identify potential anticompetitive behavior by market participants and providing 

comprehensive market analysis critical for informed policy decision making); April 14 

Order, 107 FERC ¶ 61,018 at P 186, 190 (recognizing the pro-competitive benefits of 

RTO/ISO markets with market monitoring and mitigation)). 

143 Id. at 7.
Docket No. RM04-7-001 -71- 

market power is being addressed. RTO/ISO markets with Commission-approved market 

monitoring and mitigation programs in place should have a presumption that analysis of 

potential submarkets is not required. PSEG states that, to the extent other market 

participants believe otherwise, the burden should fall on them to show that an analysis of 

these submarkets was in fact required.144 

101. To further support its position, PSEG notes that none of the three RTO/ISOs that 

filed comments on the NOPR saw any reason for applying mitigation outside of their 

existing programs. PSEG states that not accepting the efficacy of the RTO/ISO 

mitigation for purposes of the market-based rate assessment potentially undermines the 

authority and role of the RTO/ISOs.145 PSEG suggests that the Advanced Notice of 

Proposed Rulemaking on organized markets would be a preferable way for the 

Commission to fine-tune the market monitoring and mitigation functions of such 

organizations on a prospective basis.146

102. Similarly, EEI requests that the Commission clarify that “mitigated sellers in 

RTOs and ISOs may rely on Commission-approved market monitoring and mitigation for 

sales within the RTOs and ISOs without each seller having to demonstrate that such 

mitigation suffices in place of the default mitigation, unless a complainant demonstrates 

 144 PSEG Rehearing Request at 11-12. 

145 Id. 

146 Id. at 12 (citing Wholesale Competition in Regions with Organized Electric 

Markets, Advanced Notice of Proposed Rulemaking, 72 FR 36276 (July 2, 2007), FERC 

(continued...) 
Docket No. RM04-7-001 -72- 

that the RTO and ISO monitoring and mitigation does not suffice as to a particular 

seller.”147 EEI is concerned that the Commission may unnecessarily burden sellers in the 

organized markets with having to demonstrate in each individual proceeding that the 

RTO/ISO mitigation measures suffice as an alternative to Order No. 697’s default 

mitigation. 

103. NRG believes that Order No. 697 creates ambiguity regarding how the 

Commission’s default market power mitigation regime will interact with existing 

mitigation regimes that have been approved in organized RTO/ISO markets. NRG 

asserts that this ambiguity will discourage suppliers from building new generation in 

constrained areas. Thus, NRG seeks clarification, and, alternatively, rehearing, on two 

points. First, NRG asks that the Commission clarify that it will rebuttably presume that 

existing RTO/ISO regimes adequately mitigate market power for any sellers located in an 

RTO/ISO market that fail to pass indicative screens and a DPT analysis.148 Second, in 

the event that a seller’s market power is found not to be adequately mitigated, the 

Commission should clarify that the seller is allowed to propose its own tailored 

mitigation measures not necessarily based on embedded costs.149

 

Stats. & Regs. ¶ 32,617 (2007) (considering potential reforms to attributes of organized 

markets, including market monitoring). 

147 EEI Rehearing Request at 4-5.

148 NRG Rehearing Request at 2.

149 Id. at 3. 
Docket No. RM04-7-001 -73- 

104. On the first point, NRG explains that the Final Rule does not explicitly state that 

RTO/ISO monitoring and mitigation protocols will provide sufficient mitigation for any 

market power presumed if a seller fails the screens. NRG asserts that any generation 

market power a seller might possess has already been mitigated by those protocols. Thus, 

such sellers should not automatically be treated the same way as other mitigated sellers 

and subjected to default mitigation. However, NRG contends that the Final Rule leaves 

in question whether existing RTO/ISO mitigation regimes or the conflicting mitigation 

regime adopted in the Final Rule will govern in future seller-specific cases. NRG warns 

that this regulatory uncertainty will put new investment at risk, an outcome that should be 

avoided given the great efforts made to put in place alternatives to RMR contracts.150 In 

addition, NRG claims that the ambiguity threatens to harm state-sanctioned competitive 

procurement programs, which typically require binding bids which cannot be conditioned 

on obtaining subsequent Commission approval.151

105. Regarding the second requested clarification, NRG notes that in several places in 

the Final Rule, the Commission states that it will retain existing cost-based default 

mitigation rates, but is unclear whether alternative, tailored mitigation rates must be costbased. NRG seeks clarification that the apparent limitation to cost-based alternatives was 

inadvertent. In addition, NRG states that “the Commission should make clear that in 

 150 Id. at 7 (citing Devon Power LLC, 115 FERC ¶ 61,340 (2006) (concerning the 

New England FCM settlement) and PJM Interconnection, L.L.C., 117 FERC ¶ 61,331 

(2006) (concerning the PJM RPM settlement)). 

151 Id. at 10-12.
Docket No. RM04-7-001 -74- 

reviewing alternative mitigation measures proposed by merchant generators in RTOs, it 

will consider whether the proposed measures will support and attract necessary 

investment on reasonable terms, and recover the supplier’s cost of capital.”152

106. NYISO states that it is unclear whether the Commission intended to adopt a 

default mitigation measure that would be inconsistent with its previously approved 

market design and mitigation measures for the NYISO’s bid-based, uniform clearingprice auction markets.153 In particular, NYISO argues that there is no evidentiary or 

policy basis that would justify the imposition of default mitigation in the form of a 

revenue cap, rather than a bid cap, in Commission-approved Locational Based Marginal 

Price markets like NYISO.154 

107. NYISO argues that the imposition of default market power mitigation in the form 

of revenue caps rather than bid caps would be incompatible with the principles 

underlying uniform clearing price auctions. NYISO ensures that the market clearing 

 152 Id. at 16.

153 NYISO Rehearing Request at 4 (citing New York Independent System 

Operator, Inc., 89 FERC ¶ 61,196 (1999), order on compliance and reh’g, 90 FERC 

¶ 61,317, clarified, 91 FERC ¶ 61,154 (2000) (orders addressing the NYISO’s proposed 

Market Mitigation Measures); New York Independent System Operator, Inc., et al., 

99 FERC ¶ 61,246 (2002) (order on the NYISO’s comprehensive mitigation measures 

filing); Midwest Independent Transmission System Operator, Inc., 108 FERC ¶ 61,163, 

at P 257, order on reh’g, 109 FERC ¶ 61,157 (2004) (“We find that the conduct and 

impact approach with its associated thresholds is an appropriate approach to mitigation in 

the Midwest ISO’s market. The conduct and impact approach allows for a lighter handed 

approach to mitigation, in which the market is allowed to function as is, except when 

problems are detected.”)). 

154 Id. at 7. 
Docket No. RM04-7-001 -75- 

price will either be a competitive price or it will be a mitigated price.155 Thus, NYISO 

requests clarification that cost-based mitigation will limit a mitigated entity’s permissible 

maximum bid, but not constrain the mitigated entity from receiving the market clearing 

price if it is not the marginal seller. Additionally, NYISO argues that if the 

Commission’s default cost-based mitigation is interpreted to impose a revenue cap as 

well as a bid cap, the NYISO states that it will face significant administrative burdens if 

revenue caps are imposed rather than bid caps.156

108. APPA/TAPS, on the other hand, believe that the Commission should clarify that a 

seller relying on RTO/ISO mitigation to remedy its market power must demonstrate those 

measures’ effectiveness. APPA/TAPS note that the Final Rule indicates sellers can 

incorporate existing RTO/ISO mitigation as part of their market power analyses, but asks 

for clarification that an applicant must make a specific showing that those mitigation 

measures in fact address the specific concerns in the market-based rate analysis. 

APPA/TAPS assert that the scope of RTO/ISO mitigation is much narrower than the 

default, cost-based mitigation the Commission prescribes; it notes that the Commission 

has stated that RTO/ISO mitigation and the market-based rate analysis are different and 

that “‘pieces of one should not automatically be used as precedent for the other.’”157 

 155 Id. at 2, 3, 5. 

156 Id. at 7. 

157 APPA/TAPS Rehearing Request at 24 (citing Midwest Independent 

Transmission System Operator, Inc., 109 FERC ¶ 61,157, at P 242 (2004), order on

reh’g, 111 FERC ¶ 61,043 (2005)). 
Docket No. RM04-7-001 -76- 

APPA/TAPS state that RTO/ISO mitigation measures apply only to spot markets and 

day-ahead and/or real time, but do not apply to weekly, monthly or long-term 

transactions, including those negotiated on a bilateral basis, and that RTO/ISO mitigation 

is often far less protective than the Commission’s cost-based default of incremental cost 

plus 10 percent. APPA/TAPS explain that they are not asking the Commission to make a 

generic finding that all RTO/ISO mitigation is insufficient to mitigate sellers’ generation 

market power, but that they seek a ruling that the burden of proof that the RTO/ISO 

mitigation adequately addresses the seller’s market power falls on the seller, rather than 

intervenors. If the Commission does not make that clarification, APPA/TAPS state that it 

should clarify that it will allow intervenors to challenge such claims and will give 

meaningful consideration to those challenges.158

Commission Determination

109. The Commission denies the requests of PSEG and Reliant to reconsider its 

decision to require sellers located in markets with Commission-approved market 

monitoring and mitigation to submit horizontal market power analyses. As we explained 

in Order No. 697, while the Commission-approved market monitoring and mitigation in 

RTO/ISO markets provides protection against a seller’s ability to exercise market power, 

it cannot replace the horizontal market power analyses which provide the Commission 

and the industry with critical information regarding the potential market power of sellers 

in the market. 

 158 Id. at 26-27. 
Docket No. RM04-7-001 -77- 

110. We conclude that the dual protections of individual market power analyses and 

mitigation rules of the RTO/ISOs provide the Commission with better ability to discern 

and protect against potential market power. While, as discussed below, mitigation rules 

for the individual RTO/ISOs in most cases should be sufficient to guard against the 

exercises of market power, we are not comfortable at this time with dispensing of the 

requirement for sellers in RTO/ISOs to provide us with horizontal market power 

analyses. Any administrative burden of submitting such analyses is outweighed by the 

additional information gleaned with respect to a specific seller’s market power. 

111. APPA/TAPS request that the Commission clarify on rehearing that a seller relying 

on RTO/ISO mitigation to mitigate its market power must demonstrate the effectiveness 

of those measures. A number of other petitioners, on the other hand, request that the 

Commission clarify that it will rebuttably presume that existing RTO/ISO regimes 

adequately mitigate market power for any sellers located in an RTO/ISO market that fail 

the indicative screens and the DPT analysis. In response to these requests, to the extent a 

seller seeking to obtain or retain market-based rate authority is relying on existing 

Commission-approved RTO/ISO market monitoring and mitigation, we adopt a 

rebuttable presumption that the existing mitigation is sufficient to address any market 

power concerns. However, intervenors may challenge the effectiveness of that 

mitigation. We agree with PSEG that the challenging party should have the burden of 

proof to demonstrate that existing RTO/ISO mitigation is not sufficient. Thus, because 

existing RTO/ISO mitigation has been found to be just and reasonable by the 

Commission in the context of a proceeding specific to a particular RTO/ISO and 
Docket No. RM04-7-001 -78- 

involving all of its stakeholders, we believe it appropriate and clarify herein that there is a 

rebuttable presumption that such RTO/ISO mitigation is adequate to mitigate market 

power in the RTO/ISO market, including Commission-approved mitigation applicable to 

RTO/ISO submarkets such as In-City New York. To the extent that a party wishes to 

challenge that presumption, the challenging party will have the burden of proof. 

112. In response to EEI, to the extent the Commission has considered a challenge to 

existing mitigation and has found it to be adequate, any additional challenges must 

demonstrate a change in circumstances rather than just rearguing issues on which the 

Commission has already ruled. 

113. A number of petitioners raise issues regarding the types of mitigation that the 

Commission might impose on mitigated sellers in RTOs/ISOs. NRG requests that, in the 

event a seller’s market power is found not to be adequately mitigated, the Commission 

should clarify that the seller may propose tailored mitigation measures that are not 

necessarily based on embedded costs. NYISO states that it is unclear whether the 

Commission intended to adopt a default mitigation measure for any sellers located in an 

RTO/ISO market that fail to pass the indicative screens and the DPT analysis and seeks 

clarification that cost-based mitigation will only limit a mitigated entity’s permissible 

maximum bid, but will not constrain the mitigated entity from receiving the market 

clearing price if it is not the marginal seller. 

114. In response to these issues raised regarding the types of mitigation that the 

Commission might impose on mitigated sellers in RTO/ISO, the Commission will, 

depending on the nature of the evidence submitted by an intervenor, consider whether to 
Docket No. RM04-7-001 -79- 

institute a separate section 206 proceeding that would be open to all interested entities to 

investigate whether the existing RTO/ISO mitigation continues to be just and reasonable 

and, if not, how such mitigation should be revised. Any intervenor in such a section 206 

proceeding may present evidence on the adequacy of the existing mitigation. If 

appropriate, the Commission will consider modifying that mitigation on an RTO/ISOwide basis, rather than on a seller-specific basis, because RTO/ISO mitigation is designed 

to mitigate market power generally. In other words, if existing mitigation is found to be 

inadequate for a particular seller, then it is likely to be insufficient for all similarly 

situated sellers. We note that in reviewing alternative mitigation measures in the context 

of RTOs, the Commission will consider whether the proposed mitigation measures will 

adequately deter the exercise of market power, are consistent with the RTO/ISO's market 

design and will support and attract necessary investment on reasonable terms, and 

recover the suppliers’ cost of capital. With regard to NYISO’s request, as discussed 

above, with regard to sellers located in an RTO/ISO market that fail to pass the indicative 

screens and the DPT analysis, we will not impose default cost-based rate mitigation 

(which is used in non-RTO/ISO markets) in addition to RTO/ISO mitigation. Rather, we 

adopt a rebuttable presumption that the existing mitigation is sufficient to address any 

market power concerns. 

115. With regard to APPA/TAPS’ assertion that the scope of RTO/ISO mitigation is 

much narrower than the default cost-based rate mitigation and its argument that RTO/ISO 

mitigation provides less protection than the Commission’s default mitigation of 

incremental cost plus 10 percent, we understand that RTO/ISO mitigation measures apply 
Docket No. RM04-7-001 -80- 

to day-ahead and/or real-time markets, and we reiterate that RTO/ISO mitigation is 

determined to be just and reasonable when it is approved by the Commission.159 We 

review and approve mitigation rules in RTO/ISO markets on the basis of the specific 

facts and circumstances prevailing in such markets. Thus, customers and other interested 

parties are fully able, in the context of those proceedings, to comment on whether the 

mitigation rules are sufficiently strong to deter the exercise of market power. In addition, 

pursuant to the Final Rule, customers or other affected parties may argue, in the context 

of a specific market-based rate application or triennial review, that changed 

circumstances have rendered such mitigation no longer just, reasonable and not unduly 

discriminatory. 

7. Use of Historical Data

Final Rule

116. The Commission held in the Final Rule that it would retain the “snapshot in time” 

approach for the indicative screens and the DPT, so that sellers will be required to use 

actual historical data for the previous calendar year in their market power analyses. After 

careful consideration of the comments received, the Commission chose not to adopt the 

NOPR proposal that the DPT analysis allow sellers and intervenors to account for 

 159 APPA/TAPS rely on Midwest Independent Transmission System Operator, 

Inc., 109 FERC ¶ 61,157, at P 242 (2004), order on reh’g, 111 FERC ¶ 61,043 (2005) 

(Midwest ISO) in arguing that RTO mitigation and the market-based rate analysis are 

different. We recognize that in Midwest ISO the Commission stated that its marketbased rate analysis and mitigation in the Midwest ISO differ, and, as stated above, we 

reiterate that RTO mitigation is determined to be just and reasonable when it is approved 

by the Commission.
Docket No. RM04-7-001 -81- 

changes in the market that are known and measurable at the time of filing. Instead, the 

Commission decided to retain its existing practice that sellers are required to use 

unadjusted historical data in the preparation of a DPT for a market-based rate analysis 

and clarified that it would require the use of the actual historical data for the previous 

calendar year. 

117. The Commission distinguished this treatment from the approach in the 

Commission’s merger analysis, which requires applicants and intervenors to account for 

changes in the market that are known and measurable at the time of filing. The 

Commission found that the purpose of using the DPT in market-based rate proceedings is 

different from that in a merger analysis. Whereas a merger analysis is forward-looking 

and it is difficult and costly to undo a merger, the market-based rate analysis is a 

“snapshot in time” approach where the Commission’s focus is on whether the seller 

passes the indicative screens and the DPT based on unadjusted historical data. The 

Commission considered that its grant of market-based rate authority is conditioned on, 

among other things, the seller’s obligation to inform the Commission of any change in 

status from the circumstances the Commission relied on in granting it market-based rate 

authority on an ongoing basis. Thus, the change in status reporting requirement allows 

the Commission to evaluate changes when they actually happen rather than relying on 

projections, making it unnecessary and redundant for the Commission to allow sellers to 

account for known and measurable changes in the DPT. 

Requests for Rehearing
Docket No. RM04-7-001 -82- 

118. Montana Counsel argues that the Commission erred in refusing to allow 

adjustments to the DPT analysis to account for known and measurable future changes, 

such as contracts for the sale of capacity belonging to the seller that will expire during the 

term of its market-based rate authority. Montana Counsel asserts that by refusing to 

consider known and measurable changes, the Commission is intentionally allowing the 

DPT analysis to be conducted based on data and assumptions that are known not to be 

representative of reality.160 Montana Counsel argues that it is inherently irrational, 

arbitrary, and capricious to allow companies whose generation market power is being 

analyzed to deduct the generation that is being tested from its supply on grounds that the 

generation is committed, as the Commission does when the contracts for power from that 

generation are expiring. Montana Counsel states that such a market power test is 

inherently flawed, and that this flawed test has concrete results, with negative impacts for 

consumers. Montana Counsel cites the Commission’s May 2006 renewal of PPL 

Montana’s market-based rate authority, in spite of the fact that the main utility in 

Montana, NorthWestern Energy, must buy from PPL Montana to serve its load, as an 

example of the negative impact that the market power test can have on consumers.161 

 160 Montana Counsel Rehearing Request at 7. 

161 Id. at 7-8 (citing PPL Montana, LLC, 115 FERC ¶ 61,204 (2006) (PPL 

Montana)). Montana Counsel includes its request for rehearing of PPL Montana, filed 

June 16, 2006 in Docket No. EL05-124, et al., as Attachment A to its request for 

rehearing of Order No. 697. Id. at 8. The Montana Counsel’s rehearing request in the 

PPL Montana proceeding asserts that the Commission’s decision to renew the marketbased rate authority of the PPL Montana Companies is error insofar as it is contrary to 

record evidence and the requirements of the Federal Power Act. The Commission denied 

(continued...) 
Docket No. RM04-7-001 -83- 

119. Montana Counsel notes that the Final Rule distinguishes the market-based rate 

process from the Commission’s merger analysis by saying that while mergers are difficult 

to undo, sellers with market-based rate authority must file change in status reports, 

allowing the Commission to evaluate changes when they happen. Montana Counsel 

argues that the Commission misses the point that if the change in status is caused by the 

expiration of a long-term contract for the sale of capacity, then by the time the change in 

status report is submitted, the seller may have already re-sold the capacity at a price 

reflecting the seller’s underlying market power.162 

120. Montana Counsel contends that the refusal to consider known and measurable 

changes is especially inappropriate in light of the fact that the Commission considers 

mitigation proposed by the seller.163 Montana Counsel argues that, if the Commission 

will consider an applicant’s “‘propos[al] to transfer operational control of enough 

generation to a third party such that the applicant would satisfy [the Commission’s] 

generation market power concerns’” it should also consider whether an applicant’s 

available capacity will increase during the market-based rate authorization period when 

contracts expire.164 

 

Montana Counsel’s request for rehearing in PLL Montana LLC, 120 FERC ¶ 61,096 

(2007). 

162 Id. at 8-9. 

163 Id. at 9 (citing Order No. 697 at P 25, 63 n.46). 

164 Id. 
Docket No. RM04-7-001 -84- 

121. NRECA similarly asserts that the Final Rule’s failure to require applicants and 

allow intervenors to incorporate known and measurable changes to historical data in the 

indicative screens and the DPT in favor of a rigid “snapshot” analysis of historical data is 

arbitrary, capricious, contrary to law, and in excess of statutory authority.165 NRECA 

argues that, if the Commission knows a change will take place, it would be arbitrary and 

capricious to grant market-based rate authority based on an assumption that the change 

will not take place.166 Long-term contracts will expire on a known schedule, and the 

seller should not be allowed to assume that the capacity will remain committed to the 

buyer. According to NRECA, the Commission cannot, consistent with the FPA, ignore 

that pending change in circumstances. At a minimum, intervenors should have the 

opportunity to demonstrate the applicant’s market power using data reflecting conditions 

after the contracts expire.167 

122. NRECA states that the Commission’s reliance on change in status filings as the 

means to report the expiration of a long-term contract is illogical and does not constitute 

reasoned decision making.168 NRECA believes that absent a full market power analysis, 

 165 NRECA Rehearing Request at 3, 21 (citing Cal. ex rel. Lockyer v. FERC, 

383 F.3d 1006 (9th Cir. 2004) (Lockyer); 5 U.S.C. 706(2)(A), (C)). 

166 Id. at 21 (citing Mo. Pub. Serv. Comm’n v. FERC, 337 F.3d 1066, 1075 (D.C. 

Cir. 2003) (“Reliance on facts that an agency knows are false at the time it relies on them 

is the essence of arbitrary and capricious decision making.”)). 

167 Id. at 22. 

168 Id. (citing Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43; Pac. Gas & Elec. Co. v. 

FERC, 373 F.3d at 1319). 
Docket No. RM04-7-001 -85- 

it is impossible to adequately determine the effect of the change. NRECA submits that 

the triennial review will often come too late to protect customers.169 

123. TDU Systems also argue that the Commission should require applicants’ marketpower analyses to reflect imminent changes which are known and measurable. They 

agree that historical data are more objective, but object that when they are not 

representative of market conditions that will exist during the three-year period of marketbased rate authority, considering imminent changes is legally required.170 For soon-toexpire long-term contracts, TDU Systems assert that the seller should not be permitted to 

assume that the capacity will remain committed to the buyer. The burden should not be 

shifted to the intervenors to propose the adjustment; rather, an applicant should be 

required to include it as part of the analysis.171

Commission Determination

124. We will continue the use of historical data for both the indicative screens and the 

DPT in market-based rate cases. We reject several petitioners’ requests that the 

Commission require sellers to reflect imminent changes that are known and measurable, 

and therefore we deny rehearing on this issue. Regarding the Commission’s reliance 

upon historical rather than projected data in analyzing market power studies, and its 

 169 Id. at 23 (citing Lockyer, 383 F.3d at 1014-15. See also TDU Systems 

Rehearing Request at 17. 

170 TDU Systems Rehearing Request at 7, 16 (citing Mo. Pub. Serv. Comm’n v. 

FERC, 337 F.3d 1066, 1075 (D.C. Cir. 2003)). 

171 Id. at 17. 
Docket No. RM04-7-001 -86- 

determination not to require sellers to reflect changes that are known and measurable, the 

Commission’s practice for many years has been to use a “snapshot in time approach” 

based on the most recently available historical data at the time of filing, i.e., to rely upon 

studies based on unadjusted historical data. We continue to allow intervenors to submit 

sensitivity analyses including projected data, but we reject the proposal that applicants 

include adjustments to historical data as part of the required analyses. 

125. There are several reasons why this approach benefits customers and is otherwise in 

the public interest. First, as we explained in the Final Rule, historical data are more 

objective, readily available, and less subject to manipulation by applicants than future 

projections.172 If the Commission were to allow applicants to submit studies based on 

their future projections or that reflect “imminent changes,” then sellers would be able to 

selectively “cherry pick” those changes that benefited the seller in obtaining marketbased rate authorization while ignoring other equally likely future changes that would 

undermine the seller’s chances for obtaining such authorization. Second, this approach 

benefits customers, state commissions and other affected intervenors because it requires 

the use of a consistent methodology that can be replicated by intervenors, rather than 

allowing sellers to submit customized market power studies that, due to myriad selective 

adjustments, are difficult to analyze and can hide the presence of market power. Third, it 

is important to note that the “snapshot in time” approach does not preclude the 

Commission from considering future changes in market conditions; rather, the 

 172 Order No. 697 at P 299. 
Docket No. RM04-7-001 -87- 

Commission’s grant of market-based rate authority is conditioned, among other things, 

on the seller’s obligation to inform the Commission of any change in status from the 

circumstances the Commission relied upon in granting it market-based rate authority. 

Accordingly, the market-based rate change in status reporting requirement allows the 

Commission to evaluate changes when they actually happen rather than relying on 

projections, making it unnecessary and redundant for the Commission to allow sellers to 

account for predicted changes in the DPT for market-based rate purposes. 

126. Furthermore, accounting for “imminent changes” would be excessively 

burdensome with regard to expiring contracts because, for an accurate representation, a 

review of all expiring contracts and all contracts being negotiated inside all balancing 

authority areas in the relevant market and the seller’s first-tier markets might be 

necessary. In addition, because the definition of “imminent” is a matter of interpretation 

and may change depending on the circumstances, it would produce regulatory 

uncertainty. Furthermore, future changes are not necessarily known and measurable. For 

example, a long-term contract may be expiring in a year, but until it expires, it often can 

be renewed for the same term(s). Therefore, an analysis that assumes that the long-term 

capacity of that contract was uncommitted would not always be correct, and therefore 

could overstate the seller’s market power. When a change does occur the Commission 

has a method to evaluate the new situation through its requirement that sellers with 

market-based rate authority report changes in status and what effect, if any, such a change 

has on the grant of market-based rate authority. In any event, the Commission may 
Docket No. RM04-7-001 -88- 

require a full market power analysis at any time including as a result of a seller’s change 

in status filing. 

127. With regard to Montana Counsel’s argument that the Commission should allow 

evidence of known and measurable changes rather than a strict adherence to historical 

data because if a change in status is caused by the expiration of a long-term contract for 

the sale of capacity, then by the time a seller’s change in status filing is submitted, a 

seller may have already re-sold the capacity at a price reflecting the seller’s underlying 

market power, we recognize that a seller’s change in status filing would not be filed until 

after a long-term contract expires. However, there are countervailing reasons why the 

Commission believes that the use of historical data is appropriate and reaffirms its 

practice of using a “snapshot in time approach.”173 As explained above, the Commission 

adopted this approach because historical data are more objective, readily available, and 

less subject to manipulation by sellers than future projections. We reiterate our concern 

that if the Commission were to require sellers to submit studies or change in status filings 

based on their future projections such as “imminent changes,” then sellers would be able 

to selectively “cherry pick” those changes that benefited the seller in retaining marketbased rate authorization while ignoring other equally likely future changes that would 

undermine the seller’s chances for obtaining or retaining market-based rate authorization. 

Similarly, intervenors could introduce only those imminent changes that result in higher 

 173 For the reasons stated above, we also reject NRECA’s argument that the 

triennial review and the change in status filing will come too late. 
Docket No. RM04-7-001 -89- 

market shares for a seller, thus artificially increasing the seller’s market shares. In 

addition, requiring a seller to submit market power analyses that reflect future or 

“imminent changes” such as the future expiration of a long-term contract would be 

excessively burdensome because, for an accurate representation, review of all expiring 

contracts, and all contracts being negotiated inside the relevant market and the seller’s 

home balancing authority area and its first-tier markets may be necessary. Otherwise, the 

seller’s analysis might be incomplete and produce invalid results. 

128. In addition, as explained above, future changes are not necessarily known and 

measurable since a long-term contract may be expiring in a year, but until it expires, it 

often can be renewed for the same term. Likewise, the Commission does not allow the 

seller to deduct capacity that it is currently negotiating to sell to third parties. To do so 

would allow the seller to argue that it has an “imminent” sale and the Commission should 

consider that capacity to be committed, resulting in lowering the seller’s market shares. 

The danger in this circumstance is, like the expiring contract that could be extended, the 

sale may not actually occur and the seller could appear to have rebutted the presumption 

of market power when in fact, based on actual data, it has market power. Therefore, an 

analysis that assumes that the long-term capacity associated with an expiring contract is 

uncommitted would not always be correct. In addition, because the definition of 

“imminent” is a matter of interpretation and may change depending on the circumstances, 

it would produce regulatory uncertainty. For all of these reasons, our determination to 

rely on unadjusted historical data in the indicative screens and the DPT analysis is based 

on reasoned decision making. 
Docket No. RM04-7-001 -90- 

129. Notwithstanding our policy requiring the use of historical data and a “snapshot in 

time approach,” in previous cases we nevertheless have addressed evidence presented by 

intervenors who sought to demonstrate that upon expiration of a long-term contract, a 

seller would be able to exercise market power.174 Indeed, in cases where this issue has 

arisen, the Commission considered the impact of the expiring long-term contract on the 

seller’s market power and concluded that even when adjustments were made to the 

available economic capacity measure to account for expiring contracts, the seller did not 

fail the indicative screens.175 

130. While we continue to believe that the “snapshot in time approach” is appropriate, 

and will continue to require the use of historical data in the market power analysis, we 

nevertheless will consider, on a case-by-case basis, clear and compelling evidence 

presented by sellers and intervenors that seek to demonstrate that certain changes in the 

market, such as the expiration of a long-term contract, should be taken into account as 

part of the market power analysis in a particular case. Entities who seek to make this 

demonstration must present clear and compelling evidence in support of their argument. 

The Commission will address any countervailing factors that affect whether the seller 

will have the ability to exercise market power. Such countervailing factors could include, 

but are not limited to, any competitor that similarly has expiring long-term contracts and 

 174 PPL Montana, LLC, 115 FERC ¶ 61,204, at P 46 (2006), order denying reh’g, 

120 FERC ¶ 61,096, at P 52-54 (2007); Boralex Livermore Falls LP, 122 FERC ¶ 61,033, 

at P 43 (2008). 

175 Id. 
Docket No. RM04-7-001 -91- 

any other factors that might impact the market power analysis such as plant retirements, 

transmission access, and generation upgrades. In this regard, we remind entities that they 

must perform the market power screens as designed but may also provide a sensitivity 

analysis consistent with the discussion above. 

131. We reject Montana Counsel’s argument that, if the Commission considers a 

seller’s proposal to transfer operational control of enough generation to a third party as 

part of its proposed mitigation so that the seller would satisfy the Commission’s 

horizontal market power concerns, then the Commission should also consider imminent 

changes that would increase a seller’s market shares. Consideration of a proposal to 

transfer operational control of generation as part of a seller’s proposed mitigation, unlike 

consideration of imminent changes as part of a seller’s market power analysis, does not 

run the risk that a seller’s market power may be hidden. Moreover, the act of transferring 

control may be enough to reduce the seller’s market shares sufficiently to address market 

power concerns. 

8. Transmission Imports

Final Rule

132. In Order No. 697, the Commission adopted the proposal to continue to measure 

limits on the amount of capacity that can be imported into a relevant market based on the 

results of a simultaneous transmission import limit (SIL) study.176 Thus, a seller that 

owns transmission will be required to conduct simultaneous transmission import 

 176 Order No. 697 at P 354. 
Docket No. RM04-7-001 -92- 

capability studies for its home balancing authority area and each of its directlyinterconnected first-tier balancing authority areas consistent with the requirements set 

forth in the April 14 Order, as clarified in Pinnacle West Capital Corp.

177 The 

Commission commented that “the SIL study is ‘intended to provide a reasonable 

simulation of historical conditions’ and is not ‘a theoretical maximum import capability 

or best import case scenario.’”178 To determine the amount of transfer capability under 

the SIL study, the Commission stated that historical operating conditions and practices of 

the applicable transmission provider should be used and the analysis should reasonably 

reflect the transmission provider’s OASIS operating practices. The Commission will also 

continue to allow sensitivity studies, but the sensitivity studies must be filed in addition 

to, not in lieu of, an SIL study.179

133. In response to a commenter’s suggestion, the Commission stated it would allow 

the use of simultaneous total transfer capability (TTC) values, provided that these TTCs 

are the values that are used in operating the transmission system and posting availability 

on OASIS. In addition, the Commission stated that “[s]ellers submitting simultaneous 

TTC values must provide evidence that these values account for simultaneity, account for 

all internal transmission limitations, account for all external transmission limitations 

 177 110 FERC ¶ 61,127 (2005). 

178 Order No. 697 at P 354 (internal citations omitted). 

179 Id. P 355. 
Docket No. RM04-7-001 -93- 

existing in first-tier areas, account for all transmission reliability margins, and are used in 

operating the transmission system and posting availability on OASIS.”180

134. The Commission also agreed with several commenters that short-term firm 

reservations can be unpredictable, driven by real-time system conditions, and do not 

necessarily indicate that the associated transmission capacity is not available for 

competing supplies. Thus, the Commission concluded that, in calculating simultaneous 

transmission import limits, short-term reservations of 28 days or less in effect during the 

study periods need not be accounted for.181

135. The Commission stated that when actual OASIS practices conflict with the 

instructions in Appendix E of the April 14 Order, sellers should follow OASIS practices 

and must provide documentation of these practices.182 The Commission further stated 

that the SIL is a benchmark of historical conditions, including peak load, and that if 

additional supplies could be imported above a market’s study year peak load, the 

Commission will consider a sensitivity study that is submitted in addition to the required 

SIL study and supported by record evidence.183

 180 Id. P 364. 

181 Id. P 368. 

182 Id. P 356. 

183 Id. P 361. 
Docket No. RM04-7-001 -94- 

136. The Commission adopted the requirement for use of the SIL study as a basis for 

transmission access for both the indicative screens and the DPT analysis.184 The 

Commission stated that this requirement assures that all factors important in determining 

transmission access to the seller’s market are taken into account.185

Requests for Rehearing

137. APPA/TAPS request clarification that the use of simultaneous TTC in the SIL 

study must properly account for all firm transmission reservations, transmission 

reliability margin, and capacity benefit margin.186 First, APPA/TAPS assert that the 

Commission should state that clarifications provided in the Final Rule regarding firm 

reservations apply to any use of simultaneous TTC.187 APPA/TAPS argue that 

transmission reserved by a third party should not be double-counted via pro-rata 

allocation of unused transmission capacity.188 Second, APPA/TAPS read the Final 

Rule’s mention of the need for simultaneous TTC to “account for all transmission 

reliability margins” 189 as affirming that TRM set-asides should not be included in 

 184 Id. P 384. 

185 Id. P 386. 

186 APPA/TAPS Rehearing Request at 28-29 (citing Order No. 697 at P 364, 369; 

July 8 Order, 108 FERC ¶ 61,026). 

187 Id. at 28 (citing Order No. 697 at P 369). 

188 Id. 

189 Order No. 697 at P 364. 
Docket No. RM04-7-001 -95- 

transmission capability, consistent with the July 8 Order.190 Third, APPA/TAPS ask the 

Commission to affirm that it will apply to simultaneous TTC its prior findings in the July 

8 Order that CBM set asides should be reflected in transmission capability as non-firm 

capability unless they are used for reliability during seasonal peaks, in which case they 

should not be treated as part of import capability.191 APPA/TAPS point out that 

transmission providers do not make CBM available on a firm basis, and when it is used 

for reliability, it should not be deemed available at all to competing suppliers.192

138. Southern states that the Final Rule concludes that short-term reservations of more 

than 28 days are to be “accounted for” in the simultaneous study, which suggests that 

they should be deducted from the resulting import values. Southern submits that this 

treatment, if intended by the Commission, is inappropriate and thus should be 

reconsidered.193 Instead, Southern argues that such reservations should be assigned to the 

entity “that actually controls that generation capacity on a long-term basis and who, by 

virtue of that long-term control, might actually receive extra financial benefits if the 

exercise of market power in wholesale electricity markets caused wholesale prices to 

rise.”194 Southern argues that there is a conflict between the section on Control and 

 190 APPA/TAPS Rehearing Request at 28-29. 

191 Id. at 29. 

192 Id. 

193 Southern Rehearing Request at 32. 

194 Id. at 32-33 (quoting Frame Affidavit at ¶ 20). 
Docket No. RM04-7-001 -96- 

Commitment, where the Commission concludes “that the determination of control is 

appropriately based on a review of the totality of circumstances on a fact-specific 

basis,”195 and the SIL section that effectively assigns to applicants any short-term 

purchases that they make between one month and one year in duration so long as those 

purchases are covered with firm transmission reservations.196 

139. Southern argues that the Commission’s “after-the-fact” examination of short-term 

transmission reservations to see how many were more than 28 days in duration and who 

made those reservations is arbitrary and capricious decision-making. Southern also 

contends that the Final Rule is ambiguous and internally inconsistent when the 

Commission states that short-term firm transmission reservations longer than 28 days 

must be accounted for in the simultaneous import capability study.197 The Final Rule 

also provides that applicants do not need to account for short-term reservations of one 

month or less. However, according to Southern, the Commission then arbitrarily states 

that since the shortest month of the year has only 28 days (in non-leap years), 

reservations longer than 28 days must be accounted for in a simultaneous import 

capability study. Thus, the Final Rule is internally inconsistent with regard to what 

constitutes a month, and the Commission selected the length of a month that is contrary 

 195 Order No. 697 at P 174. 

196 Southern Rehearing Request, Frame Affidavit at ¶ 19. 

197 Id. at 33. 
Docket No. RM04-7-001 -97- 

to the evidence and is thus arbitrary and capricious.198 According to Southern, the 

Commission should grant rehearing and make clear that applicants are not required to 

address short-term firm transmission reservations in their simultaneous import capability 

studies.199

140. Southern states that although Appendix E required the use of generation scaling 

for calculating simultaneous import limit, the Final Rule allowed sellers to use another 

methodology when their actual OASIS practice conflicts with the instructions in 

Appendix E. Based on this clarification, Southern states that Southern is to use the same 

load shift methodology that it has historically used in calculating transfer capability for 

OASIS posting instead of the Appendix E mandated generation scaling. Southern states 

that in order to simulate a power transfer under the load shift methodology to determine 

simultaneous import capability into the Southern Companies’ balancing authority area for 

seasonal peak conditions, load in the power flow case is initially set to the seasonal peak 

load level and served by a comparable amount of generation in accordance with the 

engineering principle that for each control area, generation must equal load plus losses 

plus interchange. According to Southern, in order to perform transfer analysis using the 

 198 Id. at 34 (citing General Chemical Corp., 817 F.2d at 857 (reversing an order 

that was internally inconsistent); East Texas Electric Co-op v. FERC, 218 F.3d 750, 754 

(D.C. Cir. 2000); McElroy Elecs. Corp. v. FCC, 990 F.2d 1351, 1358 (D.C. Cir. 1993); 

Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43 (finding that agency rule would be arbitrary 

and capricious if the explanation runs counter to the evidence before the agency); FPL v. 

Lorion, 470 U.S. 729, 744 (1985)). 

199 Id. at 34-35. 
Docket No. RM04-7-001 -98- 

load shift methodology, load is uniformly increased in the Southern Companies balancing 

authority area, while load is simultaneously decreased in first-tier control areas to 

simulate the appropriate transfer of power between the areas. Southern states that this 

commonly used methodology has the effect of increasing loads during the transfer to 

levels that, by definition, exceed the seasonal peak load represented in the power flow 

case.200 Southern requests clarification that, for purposes of performing transfer analysis 

under the load shift methodology, transmission providers may allow the load shift 

methodology to effect load levels that are higher than the historical peak load levels as 

the means of simulating transfers. Otherwise, Southern contends that the Final Rule will 

contain inherently conflicting provisions that, on the one hand direct the use of historical 

practices related to load shift transfer analyses, but at the same time forbid the 

methodological process whereby the load shift approach simulates the power flows under 

study.201

141. Southern agrees that a simultaneous import capability study conducted in 

accordance with Appendix E or historical practice for seasonal peaks may be appropriate 

for the indicative screens. Further, the same study approach used for the screens may be 

appropriate for use in a DPT. However, Southern states that there is no legal or policy 

justification for seeking a more complete analysis of competitive conditions on the 

generation side, while not permitting a comparable effort pertaining to transmission. 

 200 Id. at 31. 

201 Id. 
Docket No. RM04-7-001 -99- 

Southern argues that to treat these issues differently could potentially lead to serious 

distortions of the competitive analysis. Therefore, Southern requests that the 

Commission clarify that the Final Rule does not foreclose an applicant from presenting a 

more thorough simultaneous import capability study based upon historical conditions as 

part of a DPT study. Of course, any such presentation would have to be considered on a 

case-specific basis and it would have to be consistent with the fundamental 

determinations of Appendix E related to simultaneous feasibility, historical practices and 

the like.202 

Commission Determination

142. In response to the comments from APPA/TAPS, we clarify that the use of 

simultaneous TTC in the SIL study must properly account for all firm transmission 

reservations, transmission reliability margin, and capacity benefit margin. We agree that 

the clarifications provided in the Final Rule regarding firm reservations apply to all 

simultaneous transmission import limit studies, including those that use simultaneous 

TTC.203 We agree that transmission reserved by a third party should not be doublecounted, such as by assuming it is available a second time to other competitors via prorata allocation of unused transmission capacity.204 We affirm that the Final Rule’s 

mention of the need for simultaneous TTC to “account for all transmission reliability 

 202 Id. at 35. 

203 Order No. 697 at P 369. 

204 APPA/TAPS Rehearing Request at 28. 
Docket No. RM04-7-001 -100- 

margins”205 means that TRM set-asides should not be included in transmission capability, 

consistent with the July 8 Order.206 We also affirm that our prior findings in the July 8 

Order that capacity benefit margin set asides should be reflected in transmission 

capability as non-firm capability unless they are used for reliability during seasonal 

peaks, in which case they should not be treated as part of import capability, also apply to 

studies that use simultaneous TTC.207 APPA/TAPS has correctly interpreted the Final 

Rule in these respects. 

143. Southern argues that there is inconsistency between the proposed treatment of 

short-term transmission reservations and the Control and Commitment section of Order 

No. 697. We disagree. In the Control and Commitment section, we refer to the control 

of a generation asset, including the ability to dispatch the generation asset. In the SIL 

section, we refer to a firm transmission reservation. These are different. The objective of 

the SIL calculation is to determine the amount of transmission imports available to bring 

in supply from first-tier areas.208 An applicant’s firm transmission reservations represent 

 205 Order No. 697 at P 364. 

206 APPA/TAPS Rehearing Request at 28-29. 

207 Id. at 29. 

208 The Commission recognizes that there may be confusion concerning the use of 

a pro rata allocation of generation capacity when performing a simultaneous 

transmission import limit (SIL) study and the requirement that, when performing the 

indicative screens, “[a]ny simultaneous transmission import capability should first be 

allocated to the seller’s uncommitted remote generation. Any remaining simultaneous 

transmission import capability would then be allocated to any uncommitted competing 

supplies.” See Order No. 697 at P 38. 

(continued...) 
Docket No. RM04-7-001 -101- 

transmission that is not available to competing suppliers. Applicants who believe that 

their firm transmission reservations should be treated as available to import competing 

supply may present evidence that the Commission will consider on a case-by-case basis. 

144. In response to Southern’s comments regarding short-term transmission 

reservations, we clarify that for the reasons described in Order No. 697,209 applicants are 

not required to address short-term firm reservations in the market power screens. 

Currently, the Commission’s EQR Data Dictionary defines monthly as more than 168 

consecutive hours up to one month, and seasonal as greater than one month and less than 

 

With regard to performing a SIL study, pro-rata allocation is used to assign shares 

to two “groups” of uncommitted generation capacity in the aggregated first-tier market. 

The seller must first calculate the sum of its owned and affiliated uncommitted generation 

capacity, then it must sum all other sellers’ uncommitted generation capacity. The seller 

then divides these two numbers to compute a ratio of the seller’s (and affiliated) 

uncommitted generation capacity to all other sellers’ uncommitted generation which 

determines the “share” that each seller is allocated to import into the study area. In other 

words, when performing the SIL study, any uncommitted generation capacity in the 

aggregate first-tier market is allocated pro rata for the purpose of determining the value of 

the SIL. 

With regard to performing the indicative screen analyses, all of the seller’s and its 

affiliated uncommitted generation capacity in first-tier markets (remote capacity) should 

be allocated to the seller’s total uncommitted capacity in the relevant market (study 

area), up to the SIL limit. Any remaining simultaneous transmission import capability is 

then allocated to any uncommitted competing generation. 

For example, if the SIL limit is 200 MW, the seller and its affiliates’ uncommitted 

generation capacity in first-tier markets is 150 MW, and competing uncommitted 

generation capacity in first-tier markets is 350 MW, then to properly perform the 

indicative screens the seller’s uncommitted generation capacity in the relevant market is 

increased by 150 MW and competing supply in the relevant market is increased by 50 

MW. 

209 Order No. 697 at P 368. 
Docket No. RM04-7-001 -102- 

365 consecutive days.210 Twenty-eight days fits within the definition of a month, and is a 

reasonable limit to separate short-term reservations from long-term reservations for 

purposes of the generation market power screens. Since the market power screens are 

conducted for four seasonal periods, and they are designed to model historical conditions 

during the four seasonal peak periods, the screens must account for transmission 

reservations typical for each season. It is not practical to require applicants to provide 

data on every transmission reservation, yet we cannot ignore the impact of transmission 

reservations on the potential for market power. Requiring applicants to account for 

reservations greater than one month in duration strikes a balance between allowing the 

screens to reasonably model historical conditions without requiring unreasonable 

amounts of information from applicants. Therefore, we will require applicants to allocate 

their seasonal and longer transmission reservations to themselves from the calculated 

SIL, where seasonal reservations are greater than one month and less than 365 

consecutive days in duration, as defined in the Commission’s EQR Data Dictionary. 

145. We grant the clarification Southern seeks in part. We would allow sellers to use 

load shift methodology to calculate simultaneous import limit while scaling their load 

beyond the historical peak load, provided they submit adequate support and justification 

for the scaling factor used in their load shift methodology and how the resulting SIL 

number compares had the company used a generation shift methodology. 

 210 Order Adopting Electric Quarterly Report Data Dictionary, Order No. 2001-G, 

72 FR 56735 (Oct. 4, 2007), 120 FERC ¶ 61,270, at P 35 (2007). 
Docket No. RM04-7-001 -103- 

146. In response to Southern’s request for clarification regarding whether applicants 

may present more thorough simultaneous import capability studies based upon historical 

conditions as part of a DPT study, we clarify that, as we stated in the Final Rule, 

applicants may submit additional sensitivity studies, including a more thorough import 

study as part of the DPT. We reaffirm, however, that any such sensitivity studies must be 

filed in addition to, and not in lieu of, an SIL study.211

9. Further Guidance Regarding Control and Commitment of 

Capacity

147. In Order No. 697, the Commission concluded that the determination of control is 

appropriately based on a review of the totality of circumstances on a fact-specific basis. 

We explained that no single factor or factors necessarily results in control. We further 

explained that the electric industry remains a dynamic, developing industry, and no 

bright-line standard will encompass all relevant factors and possibilities that may occur 

now or in the future. If a seller has control over certain capacity such that the seller can 

affect the ability of the capacity to reach the relevant market, then that capacity should be 

attributed to the seller when performing the generation market power screens.212 

148. We determined that the circumstances or combination of circumstances that 

convey control vary depending on the attributes of the contract, the market and the 

market participants. Therefore, we concluded that it would be inappropriate to make a 

generic finding or generic presumption of control, but rather that it is appropriate to 

 211 Id. P 355. 
Docket No. RM04-7-001 -104- 

continue making our determinations of control on a fact-specific basis. We explained, 

however, that we continue our historical approach of relying on a set of principles or 

guidelines to determine what constitutes control. Thus, we stated that we continue to 

consider the totality of circumstances and attach the presumption of control when an 

entity can affect the ability of capacity to reach the market. We explained that our 

guiding principle is that an entity controls the facilities when it controls the decisionmaking over sales of electric energy, including discretion as to how and when power 

generated by these facilities will be sold.213 

149. We declined to adopt commenters’ suggestions that we require all relevant 

contracts to be filed for review and determination by the Commission as to which entity 

controls a particular asset (e.g., with an initial application, updated market power 

analysis, or change in status filing). While we noted that under section 205 of the FPA, 

the Commission may require any contracts that affect or relate to jurisdictional rates or 

services to be filed, we explained that the Commission uses a rule of reason with respect 

to the scope of contracts that must be filed and does not require as a matter of routine that 

all such contracts be submitted to the Commission for review. Our historical practice has 

been to place on the filing party the burden of determining which entity controls an asset. 

Therefore, we required a seller to make an affirmative statement as to whether a 

contractual arrangement transfers control and to identify the party or parties it believes 

 212 Order No. 697 at P 174. 

213 Id. P 175. 
Docket No. RM04-7-001 -105- 

control the generation facility, but explained that the Commission retains the right at the 

Commission’s discretion to request the seller to submit a copy of the underlying 

agreement(s) and any relevant supporting documentation. 

150. Given the increased level of investment in the electric utility industry as a result of 

the Energy Policy Act of 2005 (EPAct 2005)214 and our implementing rules and 

regulations, we find it necessary to provide further guidance with respect to the 

representations that a seller should make regarding which entity controls a particular 

asset. An increasing number of investors are acquiring interests in assets that may be 

relevant to a seller’s market-based rate authority. As we explained in Order No. 697, we 

will continue to place on the filing party the burden of determining which entity controls 

an asset. We will rely on the seller’s representations regarding control, absent 

extenuating circumstances. Therefore, to provide further guidance to the industry, we 

reiterate that the seller, in advising the Commission of its determinations of control, 

should specifically state whether a contractual arrangement transfers control and should 

identify the party or parties it believes control(s) the generation facility. In doing so, the 

seller should make its representation in light of our discussion in Order No. 697 and cite 

to that order as the basis for which it has made its determination. 

B. Vertical Market Power 

1. OATT Violations and Market-Based Rate Revocation

Final Rule

 214 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005). 
Docket No. RM04-7-001 -106- 

151. In the Final Rule, the Commission stated it will revoke an entity’s market-based 

rate authority in response to an OATT violation upon a finding of a nexus between the 

specific facts relating to the OATT violation and the entity’s market-based rate authority, 

and reiterated that an OATT violation may subject the seller to other remedies the 

Commission may deem appropriate, such as disgorgement of profits or civil penalties.215 

The finding that an OATT adequately mitigates transmission market power rests on the 

assumption that individual entities comply with the OATT and that there may be OATT 

violations in circumstances that, after applying the factors in the Enforcement Policy 

Statement,216 merit revocation or limitation of market-based rate authority. The Final 

Rule found, however, that it is inappropriate to revoke a seller’s market-based rate 

authority for an OATT violation unless there is a nexus between the specific facts relating 

to the OATT violation and the seller’s market-based rate authority. The Commission 

declined to adopt a rebuttable presumption that any OATT violation has the requisite 

nexus to support revocation of market-based rate authority, explaining that there is a wide 

range of types of OATT violations, including ones that may be inadvertent and others 

that are neither intended to affect, nor in fact affect, the market-based rate sales of the 

transmission provider or its affiliates.217

 215 Order No. 697 at P 417. 

216 Enforcement of Statutes, Orders, Rules and Regulations, 113 FERC ¶ 61,068 

(2005) (Enforcement Policy Statement). 

217 Order No. 697 at P 417. 
Docket No. RM04-7-001 -107- 

152. The Commission stated that determining what constitutes a sufficient factual 

nexus is best left to a case-by-case consideration, explaining that the wide range of 

positions among commenters on how to define a sufficient factual nexus itself suggested 

that this finding is best made after review of a specific factual situation. Some 

commenters had asserted that a finding of a “material” violation of the OATT would be 

sufficient. The Commission disagreed. While a seller’s inconsequential OATT violation 

would not serve as a basis for revoking that entity’s market-based rate authority, the 

Commission stated that revocation is warranted only when an OATT violation has 

occurred and the violation had a nexus to the market-based rate authority of the violator 

or its affiliates.218 The Commission also clarified that it will allow intervenors on a caseby-case basis to file evidence if they believe they have been denied transmission access in 

violation of the OATT.219

153. The Commission emphasized in the Final Rule that it has discretion to fashion 

remedies for OATT violations that relate to the violator’s market-based rate authority in 

instances in which the Commission does not find sufficient justification for revocation of 

that authority. For example, in appropriate circumstances, the Commission may modify 

or add additional conditions to the violator’s market-based rate authority or impose other 

requirements to help ensure that the violator does not commit future, similar misconduct. 

The Commission also explained that it will consider whether to impose sanctions such as 

 218 Id. P 418. 

219 Id. P 421. 
Docket No. RM04-7-001 -108- 

assessment of civil penalties for particularly serious OATT violations in addition to 

revocation of the violator’s market-based rate authority.220

Requests for Rehearing

154. NRECA and TDU Systems argue that the Final Rule’s determination that the 

Commission will not revoke the market-based rate authority of a public utility or its 

affiliates upon the utility’s violation of its OATT unless there is a “nexus” between the 

“specific facts” of the violation and the violator’s market-based rate authority is arbitrary, 

capricious, contrary to law, and in excess of statutory authority. NRECA also argues 

that the Final Rule does not provide clear guidance as to what would constitute a 

sufficient nexus.221 

155. TDU Systems state that the Commission must clarify the circumstances in which it 

will find that there is a sufficient nexus between a transmission provider’s OATT 

violations and the revocation of market-based rate authorization of the provider or its 

affiliates, and reconsider its decision to determine what constitutes a sufficient factual 

nexus on a case-by-case basis.222 TDU Systems state that, apart from trivial violations, 

which could be screened out by the kind of materiality filter suggested by 

APPA/TAPS,223 the Commission has not explained why material OATT violations 

 220 Id. P 419. 

221 NRECA Rehearing Request at 28 (citing Order No. 697 at P 418). 

222 TDU Systems Rehearing Request at 8, 20. 

223 Id. at 21 (citing APPA/TAPS Initial Comments at 81). 
Docket No. RM04-7-001 -109- 

should not create at least a presumption that market-based rate authorization is 

inappropriate.224 TDU Systems state that, because having an OATT on file and being 

bound by its terms are necessary to mitigating the public utility’s vertical market power, 

there is logical reason to be concerned that a violation may have undermined a premise 

for the authorization. TDU Systems therefore assert that an OATT violation should 

automatically trigger a Commission proceeding in which the violator has the burden of 

justifying its continued market-based rate authority.225 Furthermore, TDU Systems state 

that shifting the burden to the transmission provider could encourage transmission 

providers to be in full compliance with coordinated and open regional planning.226

156. TDU Systems also argue that the Commission needs to address further the content 

of the “nexus” requirement. They contend that transmission-owning public utilities 

might read Order No. 697 to allow for revocation of their market-based rate authority 

only when it would be arbitrary and capricious for the Commission not to do so.227 TDU 

Systems contend that the Commission has offered no clue to understanding why it may 

be relevant whether the alleged violator has committed an OATT violation in order to 

further a specific sale under its own market-based rate tariff or that of an affiliate. TDU 

Systems conclude that if such a connection is indeed critical, there would appear to be a 

 224 Id. at 8, 21. 

225 Id. at 21. 

226 Id. at 8. 

227 Id. at 22. 
Docket No. RM04-7-001 -110- 

substantial danger of deflecting attention from the characteristics of a transmission 

provider’s conduct, i.e., whether it is anticompetitive or reflects the exercise of market 

power.228

157. These petitioners claim that the Commission’s position appears to place the 

burden of proof on customers, competitors, or the Commission to demonstrate the nexus, 

rather than requiring the violator to demonstrate the lack of any such nexus.229 

158. NRECA asserts that when a public utility violates its OATT, one of the 

preconditions to the grant of market-based rate authority is violated. It argues that, under 

the FPA, the seller, not customers, must bear the burden of proof that its continuing sales 

under its market-based rate tariff remain at just and reasonable levels.230 NRECA 

therefore contends that there should be a presumption that there is a “nexus” between the 

OATT violation and the seller’s market-based rate authority.231 NRECA states that the 

burden, consistent with the FPA, should be on the seller to rebut this presumption; 

however, it suggests that the Commission could evaluate the seller’s showing, and if the 

 228 Id.

229 NRECA Rehearing Request at 3, 27-29; TDU Systems Rehearing Request at 

3-4, 20. 

230 NRECA Rehearing Request at 28 (citing Lockyer, 383 F.3d at 1014-15; 

16 U.S.C. 824d(e)). 

231 Id. at 29. 
Docket No. RM04-7-001 -111- 

issue is in doubt, set the matter for investigation or hearing and order a temporary 

suspension of market-based rate authority until the matter is resolved.232

Commission Determination

159. The Commission denies rehearing of the decision to require a factual nexus 

between a substantial OATT violation and the entity’s market-based rate authority to 

justify revocation of that authority. As the Commission explained in Order No. 697, the 

“nexus condition” is required in order to ensure that our actions are not arbitrary or 

capricious or based on an inadequate factual record. We disagree with NRECA and TDU 

Systems that any material OATT violation should necessarily justify revocation of the 

entity’s market-based rate authority since the violation may have no relation to the 

market-based rate authority. In such circumstances, the Commission will consider such 

other remedies as may be appropriate. We also decline to provide specific examples of 

what would constitute a sufficient nexus between an entity’s market-based rate authority 

and an OATT violation because the factual circumstances involved in a claimed violation 

will be unique to the company and, therefore, any list would be incomplete. This is 

especially true in light of continually developing markets. We continue to believe that 

the determination of what would be a sufficient factual nexus between an OATT 

violation and revocation of the violator’s market-based rate authority is best left to caseby-case consideration. 

 232 Id.
Docket No. RM04-7-001 -112- 

160. With regard to the transmission provider’s planning obligations in particular, 

violations of the planning-related requirements of the pro forma OATT may or may not 

have a sufficient factual nexus with the transmission provider’s market-based rate 

authority. A case-by-case analysis will be necessary to determine if the violation justifies 

revocation of the transmission provider’s market-based rate authority. We agree with 

TDU Systems that OATT violations by a transmission provider that may not be explicitly 

connected with its market-based rate authorization may nonetheless promote conditions 

in which the violator could gain an advantage in future transactions. However, we note 

that this is an example of why a case-by-case determination is needed so that the 

Commission can consider the violation, the seller’s market-based rate authority, and 

market conditions in determining what remedy, if any, best suits the situation. Therefore, 

we will apply the mechanisms adopted in Order No. 890 to aid us in determining on a 

case-by-case basis if a particular violation puts that company at an advantage vis-à-vis its 

market-based rate authority.233 

161. We disagree with TDU Systems and NRECA that the Commission inappropriately 

shifted the burden of proof regarding whether there is a nexus. We anticipate that the 

Commission’s consideration of a seller’s OATT violation and whether or not there is a 

nexus with its market-based rate authority would normally arise as part of a Commissioninitiated enforcement proceeding. In enforcement proceedings, the Commission has 

considerable discretion in how to fashion an appropriate remedy and the burden of 

 233 See Order No. 890-A, FERC Stats. & Regs. ¶ 31,261 at P 1037.
Docket No. RM04-7-001 -113- 

justifying any remedial actions taken against a violator, including revocation of marketbased rate authority and determining what remedies are required to ensure that any future 

sales, market-based rate or otherwise, are at just and reasonable rates. Moreover, even if 

the issue arose in publicly noticed proceedings (such as a section 206 or 306 complaint), 

the Commission would exercise its remedial discretion based on the facts presented and 

accordingly bear the burden of justifying any remedy imposed on the transmission 

provider for a violation of its OATT. Whether or not a violation justifies revocation of 

the seller’s market-based rate authority will depend on the facts and circumstances 

involved in each case; therefore, it would not be appropriate to adopt a presumption of 

that nexus, as requested by petitioners. The Commission will make a determination 

based on the facts of each particular case as to whether or not an OATT violation has a 

nexus to the seller’s market-based rate authority. In sum, the Commission’s action in 

Order No. 697 does not shift the burden of proving a nexus to customers and competitors. 

162. Contrary to TDU Systems’ assertion, Order No. 697 does not limit the 

Commission to revoking a seller’s market-based rate authority only in circumstances 

where it would be arbitrary and capricious not to do so. If an OATT violation occurs, the 

Commission will investigate whether or not the facts surrounding the violation have a 

nexus to the seller’s market-based rate authority. It would not be just and reasonable for 

the Commission to revoke a seller’s market-based rate authority if in fact the violation 

had no bearing on the seller’s market-based rate position. The way to make such a 

determination is based on an adequate factual record and that is what would be 

established in such a proceeding before making any determinations. 
Docket No. RM04-7-001 -114- 

2. Treatment of FTRs

Final Rule

163. In the Final Rule, the Commission stated that provisions concerning the 

reassignment or sale of transmission capacity or firm transmission rights, congestion 

contracts, or fixed transmission rights (as a group, FTRs) are not required to be included 

in a seller’s market-based rate tariff, nor is it appropriate to include transmission-related 

services in a seller’s market-based rate tariff.234 The Commission explained that 

Commission-approved market rules for RTO/ISOs address resales of FTRs and virtual 

trading to ensure that no market power is exercised in such trades. In addition, sellers 

engaging in these activities sign a participation agreement with RTO/ISOs which require 

them to abide by those market rules. Hence, the approval of the market rules in 

conjunction with approval of the generic participation agreement by the Commission 

constitutes authorization for public utilities to engage in the resale of FTRs and virtual 

transactions, and no separate authorization is required under the FPA. 

Requests for Rehearing

164. Morgan Stanley states that, when assessing whether a potential market-based rate 

seller has market power, the Commission has focused on ownership and control of 

physical transmission (except for that which is necessary to interconnect generation to the 

transmission grid).235 Morgan Stanley requests that the Commission clarify whether a 

 234 Order No. 697 at P 920. 

235 Morgan Stanley Rehearing Request at 1-2 (citing Iowa Power Partners, 

81 FERC ¶ 61,058, at 61,281 (1997)). 
Docket No. RM04-7-001 -115- 

seller is required to include and report the acquisition of financial transmission rights 

when assessing whether it has vertical market power. Morgan Stanley states that the 

Commission declined to adopt such a requirement as part of Order No. 652 governing 

changes in status.236 However, Morgan Stanley asserts that “Commission staff and others 

have taken inconsistent positions on whether the failure to disclose the acquisition of 

financial transmission rights constitutes a violation of a seller’s market-based rate 

tariff.”237 

Commission Determination

165. The Commission clarifies herein that sellers are not required to report on financial 

transmission rights as part of the vertical market power assessment. Thus, failure to 

disclose the acquisition of financial transmission rights in an application for market-based 

rate authority, a three-year update or a change in status filing does not constitute a 

violation of a seller’s market-based rate tariff. While ownership of financial transmission 

rights could affect a seller’s incentive to exercise market power, we find that there are 

adequate mechanisms and protections in place to minimize a seller’s ability to do so (e.g., 

market monitoring and mitigation in RTO/ISOs; the requirement that a seller must abide 

by its OATT and any violation thereof could constitute a violation of a seller’s market-

 236 Reporting Requirement for Changes in Status for Public Utilities with MarketBased Rate Authority, Order No. 652, 70 FR 8253 (Feb. 18, 2005), FERC Stats. & Regs. 

¶ 31,175, order on reh’g, 111 FERC ¶ 61,413 (2005). 

237 Morgan Stanley Rehearing Request at 2. (citing Enron Power Marketing, 

119 FERC ¶ 63,013 (2007) (discussing Enron’s use of FTRs to exercise market power 

and its failure to report its FTRs to the Commission)). 
Docket No. RM04-7-001 -116- 

based rate tariff; the Commission’s enforcement proceedings). Moreover, the 

Commission does not analyze physical rights that a seller has to transmission service 

when analyzing vertical market power, and the Commission will treat financial rights in 

an equal manner. Physical and financial rights to transmission service do not enable the 

customer to control transmission capacity in a way that withholds the capacity from the 

market. To the extent there is an issue with potential market manipulation by a seller, the 

Commission would address this through an Office of Enforcement proceeding. 

3. Other Barriers to Entry

Final Rule

166. The Final Rule adopted the NOPR proposal to consider a seller’s ability to erect 

other barriers to entry as part of the vertical market power analysis, but modified the 

requirements when addressing other barriers to entry. It also provided clarification 

regarding the information that a seller must provide with respect to other barriers to entry 

(including which inputs to electric power production the Commission will consider as 

other barriers to entry) and modified the proposed regulatory text in that regard.238

167. In the Final Rule, the Commission drew a distinction between two categories of 

inputs to electric power production: one consisting of natural gas supply, interstate 

natural gas transportation (which includes interstate natural gas storage), oil supply, and 

oil transportation; and another consisting of intrastate natural gas transportation, intrastate 

natural gas storage or distribution facilities, sites for generation capacity development, 

 238 Order No. 697 at P 440. 
Docket No. RM04-7-001 -117- 

and sources of coal supplies and the transportation of coal supplies such as barges and 

rail cars.239 

168. With regard to the first category, the Commission removed the inputs from the 

vertical market power analysis. Thus, the Final Rule did not require a description of or 

affirmative statement with regard to ownership or control of, or affiliation with an entity 

that owns or controls, natural gas and oil supply, including interstate natural gas 

transportation and oil transportation.240 The Commission explained that prices for 

wellhead sales of natural gas were decontrolled by Congress,241 and that the Commission 

has granted other sellers blanket authority to make such sales at market rates. In the case 

of transportation of natural gas, the Commission noted that pipelines operate pursuant to 

the open and non-discriminatory requirements of Part 284 of the Commission’s 

regulations;242 these regulations mandate that all available pipeline capacity be posted on 

 239 Id. P 441. 

240 Id. P 442. 

241 INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002); Natural Gas Decontrol Act of 

1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., at 6 (1989). 

242 Order No. 697 at P 443 (citing Pipeline Service Obligations and Revisions to 

Regulations Governing Self-Implementing Transportation; and Regulation of Natural Gas 

Pipelines After Partial Wellhead Decontrol, Order No. 636, 57 FR 13267 (Apr. 16, 1992), 

FERC Stats. & Regs., Regulations Preambles January 1991-June 1996 ¶ 30,939 (Apr. 8, 

1992); Regulation of Short-Term Natural Gas Transportation Services and Regulation of 

Interstate Natural Gas Transportation Services, Order No. 637, FERC Stats. & Regs., 

Regulations Preambles July 1996 - December 2000 ¶ 31,091 (Feb. 9, 2000); clarified, 

Order No. 637-A, FERC Stats. & Regs., Regulations Preambles July 1996 - December 

2000) ¶ 31,099 (May 19, 2000); reh’g denied, Order No. 637-B, 92 FERC ¶ 61,062 

(2000); aff’d in part and remanded in part sub nom.).
Docket No. RM04-7-001 -118- 

the pipelines’ website, and that available capacity cannot be withheld from a shipper 

willing to pay the maximum approved tariff rate. The Commission noted that, to the 

extent intervenors are concerned about a seller’s market power from ownership or control 

of interstate natural gas transportation, this would be actionable first in a complaint 

proceeding under section 5 of the Natural Gas Act before turning to market-based rate 

consequences, if any.243

169. Similarly, the Commission noted that oil pipelines are common carriers under the 

Interstate Commerce Act, specifically under section 1(4), that they are required to 

provide transportation service “upon reasonable request therefore,” and that Congress has 

not chosen to regulate sales of oil. 244 

170. With regard to the second category of inputs to electric power production, the 

Commission adopted a rebuttable presumption that sellers cannot erect barriers to entry 

with regard to the ownership or control of, or affiliation with any entity that owns or 

controls, those inputs.245 The Commission noted that, to date, it has not found such 

ownership, control or affiliation to be a potential barrier to entry warranting further 

analysis in the context of market-based rate proceedings. However, unlike the first 

category of inputs, the Commission does not have sufficient evidence to remove these 

 243 Order No. 697 at P 445. 

244 Id. P 444 (quoting 49 App. U.S.C. 1(4)).

245 Id. P 446. The Commission modified the definition of “inputs to electric power 

production” in 18 CFR 35.36(a)(4) to reflect this clarification. 
Docket No. RM04-7-001 -119- 

inputs from the analysis entirely. Accordingly, the Commission stated that it will 

rebuttably presume that ownership or control of, or affiliation with an entity that owns or 

controls, any of the second category of inputs does not allow a seller to raise entry 

barriers, but intervenors will be allowed to demonstrate otherwise. The Final Rule noted 

that this rebuttable presumption only applies if the seller describes and attests to these 

inputs to electric power production in its market power analysis, as discussed below.246

171. The Commission required a seller to provide a description of its ownership or 

control of, or affiliation with an entity that owns or controls, any of the second category 

of inputs. The Final Rule required sellers to provide this description and to make an 

affirmative statement, with some modifications to the affirmative statement from what 

was proposed in the NOPR. Instead of requiring sellers to make an affirmative statement 

that they have not erected barriers to entry into the relevant market, the Final Rule 

required sellers to make an affirmative statement that they have not erected barriers to 

entry into the relevant market and will not erect barriers to entry into the relevant market. 

The Final Rule clarified that the obligation in this regard applies both to the seller and its 

affiliates, but is limited to the geographic market(s) in which the seller is located. 247

172. Therefore, the Final Rule modified the proposed regulations to require a seller to 

provide a description of its ownership or control of, or affiliation with an entity that owns 

or controls these types of assets, to ensure that this information is included in the record 

 246 Id. P 446. 

247 Id. P 447. 
Docket No. RM04-7-001 -120- 

of each market-based rate proceeding. In addition, the Commission required sellers to 

make an affirmative statement that they have not erected barriers to entry into the 

relevant market and will not erect barriers to entry into the relevant market.248 

173. The Commission also modified the change in status reporting requirement in 

§ 35.42 of the Commission’s regulations to be consistent with the other barriers to entry 

part of the vertical market power analysis as adopted in the Final Rule. 

Requests for Rehearing

174. Southern notes that the Final Rule modified the change in status regulations 

adopted by the Commission in Order No. 652. Specifically, Southern states that the 

Commission modified the definition of inputs to electric power production to mean 

“‘intrastate natural gas transportation, intrastate natural gas storage or distribution 

facilities; sites for new generation capacity development; sources of coal supplies and the 

transportation of coal supplies such as barges and railcars,’” 249 and comments that under 

the change in status reporting regulations, sellers would be required to notify the 

Commission of any changes to such inputs. Southern requests clarification of what is 

meant by the phrase “sources of coal supplies and the transportation of coal supplies such 

as barges and railcars” in the context of the definition of “inputs to electric power 

production.” Because such inputs to electric power production are considered in the 

 248 Id. P 448. 

249 Southern Rehearing Request at 41 (citing Order No. 697 at P 1016). 
Docket No. RM04-7-001 -121- 

Commission’s vertical market power analysis,250 Southern believes that the 

Commission’s intention is for this phrase to mean physical coal sources (i.e., coal mines) 

and ownership or control over who may access transportation of coal via barges and 

railcar trains (e.g., control of a train system, a railcar manufacturing or supply company, 

or a barge production or supply company), rather than merely entering into a coal supply 

contract with a coal vendor. Southern argues that if a change in status filing were 

required every time a large utility entered into a coal purchase agreement, purchased or 

leased a single railcar or barge, or engaged in other such routine activities, which 

Southern asserts are a necessary and inherent part of keeping power plants operating so 

that they can reliably serve a utility’s customers, the Commission could find itself 

inundated with submissions. Accordingly, Southern requests that the Commission clarify 

that the phrase “inputs to electric power production” is intended to encompass physical 

coal sources and ownership of control over who may access transportation of coal via 

barges and railcar trains. 

175. APPA/TAPS request that the Commission clarify that intervenors may introduce 

evidence that control and/or ownership of interstate natural gas supply, transportation or 

storage, as well as oil supply and transportation, creates entry barriers.251 APPA/TAPS 

request clarification that the Final Rule’s stated case-by-case consideration of other entry 

 250 Id. at 41 (citing Order No. 697 at P 446). 

251 APPA/TAPS Rehearing Request at 29-30 (citing Order No. 697 at P 441-49; 

United States v. Enova Corp., 107 F. Supp. 2d 10 (D.D.C. 2000)). 
Docket No. RM04-7-001 -122- 

barriers will include evidence that a seller’s or its affiliate’s ownership or control of the 

first category of entry barriers will be considered.252 According to APPA/TAPS, if, as 

the Commission believes, markets in the first category are competitive, intervenors will 

rarely raise concerns about them in specific cases, which means there is no basis to reject 

this requested clarification on grounds that allowing intervenors to raise entry concerns 

will be unduly burdensome for applicants or the Commission. APPA/TAPS contend that 

if there are concerns about these entry barriers, the Commission provides no justification 

for requiring an intervenor to undertake the time and expense of a “‘complaint 

proceeding under section 5 of the Natural Gas Act before turning to market-based rate 

consequences.’”253 Further, APPA/TAPS state that by allowing intervenor evidence 

regarding market issues surrounding the first category of inputs, the market-based rate 

program “‘will allow unique or newly developed barriers to entry to be brought before 

the Commission.’”254 

Commission Determination

176. We agree with Southern that it was not the Commission’s intent for the term 

“inputs to electric power production” to encompass every instance of a seller entering 

into a coal supply contract with a coal vendor in the ordinary course of business. The 

Commission clarifies that Order No. 697 encompasses physical coal sources and 

 252 Id. at 30. 

253 Id. (quoting Order No. 697 at P 445). 

254 Id. (quoting Order No. 697 at P 449). 
Docket No. RM04-7-001 -123- 

ownership of or control over who may access transportation of coal via barges and railcar 

trains. Thus, the Commission will revise its definition of “inputs to electric power 

production” in § 35.36(a)(4) as follows: “intrastate natural gas transportation, intrastate 

natural gas storage or distribution facilities; sites for new generation capacity 

development; physical coal supply sources and ownership of or control over who may 

access transportation of coal supplies.” 

177. The Commission denies APPA/TAPS’ request that the Commission clarify that 

intervenors may introduce evidence that control and/or ownership of interstate natural gas 

supply, transportation or storage, as well as oil supply and transportation, creates entry 

barriers. As explained above and in Order No. 697, prices for wellhead sales were 

decontrolled by Congress,255 and the Commission has granted other sellers blanket 

authority to make such sales at market rates. In the case of transportation of natural gas, 

pipelines operate pursuant to the open and non-discriminatory requirements of Part 284 

of the Commission’s regulations;256 these regulations require that all available pipeline 

capacity be posted on the pipelines’ website, and that available capacity cannot be 

withheld from a shipper willing to pay the maximum approved tariff rate. Similarly, the 

Final Rule noted that oil pipelines are common carriers under the Interstate Commerce 

Act, specifically under section 1(4), that they are required to provide transportation 

 255 INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002); Natural Gas Decontrol Act of 

1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess., at 6 (1989). 

256 Order No. 697 at P 443 (and cases cited therein). 
Docket No. RM04-7-001 -124- 

service “upon reasonable request therefore,” and that Congress has not chosen to regulate 

sales of oil. 257

178. As stated in the Final Rule, to the extent intervenors are concerned about a seller’s 

market power from ownership or control of interstate natural gas transportation, this 

would be actionable first in a complaint proceeding under section 5 of the Natural Gas 

Act before turning to any market-based rate consequences. 

179. The Commission found in Order No. 697 and we reiterate here that there is no 

need to address these inputs to electric power production as potential barriers to entry in 

the context of the market-based rate program. In light of the precedent described above, 

we conclude that sellers cannot erect barriers to entry with regard to such inputs. 

180. Regarding APPA/TAPS’ assertion that the Commission provides no justification 

for requiring an intervenor to file a complaint proceeding under section 5 of the Natural 

Gas Act when a concern arises regarding interstate natural gas transportation, as 

explained in Order No. 697, natural gas pipelines operate pursuant to the open and nondiscriminatory requirements of Part 284 of the Commission’s regulations. On this basis, 

the appropriate forum for addressing a concern that may arise regarding interstate natural 

gas transportation would initially be a proceeding under the Natural Gas Act, not the 

FPA. Thus, a market-based rate proceeding would not be the proper forum for such a 

complaint. The place to challenge a particular seller’s potential market power in 

 257 Id. P 444 (quoting 49 App. U.S.C. 1(4)).
Docket No. RM04-7-001 -125- 

interstate natural gas transportation markets is in a complaint proceeding under section 5 

of the Natural Gas Act. 

C. Affiliate Abuse

181. In Order No. 697, the Commission determined that affiliate abuse should no 

longer be considered a separate “prong” of the market-based rate analysis, and instead 

codified the affiliate requirements and restrictions as an explicit requirement in section 

35.39 of the Commission’s regulations. The affiliate requirements and restrictions must 

be satisfied on an ongoing basis as a condition of obtaining and retaining market-based 

rate authority.258 The regulations expressly prohibit power sales between a franchised 

public utility with captive customers and any market-regulated power sales affiliate, 

without first receiving Commission authorization for the transaction under section 205 

of the FPA. The regulations also include the requirements formerly known as the 

market-based rate “code of conduct,” as revised in Order No. 697. 

1. General Affiliate Terms & Conditions

a. Affiliate Definition

182. As an initial matter, we clarify that the term “affiliate” for purposes of Order No. 

697 and the affiliate restrictions adopted in § 35.39 of our regulations is defined as that 

 

(continued...) 

258 A seller seeking market-based rate authority must provide information 

regarding its affiliates and its corporate structure or upstream ownership. To the extent 

that a seller’s owners are themselves owned by others, the seller seeking to obtain or 

retain market-based rate authority must identify those upstream owners. Sellers must 

trace upstream ownership until all upstream owners are identified. Sellers must also 

identify all affiliates. Finally, an entity seeking market-based rate authority must describe 

the business activities of its owners, stating whether they are in any way involved in the 
Docket No. RM04-7-001 -126- 

term is used in the regulations adopted in the Affiliate Transactions Final Rule. In the 

Affiliate Transactions Final Rule, the Commission considered the use of the term 

affiliate in the context of the Affiliate Transactions NOPR, the Commission’s Standards 

of Conduct for Transmission Providers, and other precedent.259 The Commission also 

reviewed the affiliate definitions contained in both the Public Utility Holding Company 

Act of 1935 (PUHCA 1935)260 and the Public Utility Holding Company Act of 2005 

(PUHCA 2005)261. After taking into account these differing definitions of affiliate, and 

recognizing the need to provide greater clarity and consistency in our rules, the 

Commission explained that it believes it is important to try to adopt a more consistent 

definition in its various rules and also one that is sufficiently broad to allow us to 

adequately protect customers.262 On this basis, the definition of affiliate as adopted in 

the Affiliate Transactions Final Rule explicitly incorporates the PUHCA 1935 definition 

of affiliate for EWGs (rather than incorporate it by reference as previously has been 

done).263 The definition also adopts a parallel definition of affiliate for non-EWGs, but 

 

energy industry. 

259 See, e.g., Morgan Stanley Capital Group, Inc., 72 FERC ¶ 61,082, at 61,436-37 

(1995) (Morgan Stanley). 

260 15 U.S.C. 79a et seq. 

261 EPAct 2005 at 1261 et seq. 

262 For example, we adopt this definition of affiliate for purposes of section 203 of 

the FPA in the Affiliate Transactions Final Rule. 

263 We note that in EPAct 2005 section 1277(b)(2), Congress enacted a 

conforming amendment which amended FPA section 214 to refer to the section 2(a) 

(continued...) 
Docket No. RM04-7-001 -127- 

with adjustments to reflect the previously-used 10 percent voting interest threshold for 

non-EWGs and to eliminate certain language not applicable or necessary in the context 

of the FPA. 

183. In light of the Commission’s goal to have a more consistent definition of affiliate 

for purposes of both EWGs and non-EWGs to the extent possible, as well as to 

strengthen the Commission’s ability to ensure that customers are protected, we clarify 

that, for purposes of Order No. 697, we will define “affiliate” as that term is used in the 

Affiliate Transactions Final Rule, codified in § 35.43(a)(1) of the Commission’s 

regulations. Accordingly, as discussed herein, we will codify the definition of affiliate 

in our market-based rate regulations at § 35.36. 

b. Definition of Market-Regulated Power Sales Affiliate

Final Rule

184. The Commission explained in Order No. 697 that the market-based rate affiliate 

restrictions codified in § 35.39 govern the relationship between a franchised public 

 

(continued...) 

PUHCA 2005 definition of “affiliate” rather than the section 2(a) PUHCA 1935 

definition of “affiliate.” Our Affiliate Transactions Final Rule did not recognize this 

conforming amendment. However, the conforming amendment is ambiguous. There is 

no section 2(a) in PUHCA 2005 and, inexplicably, the text of PUHCA 2005 retained only 

a portion of the full PUHCA 1935 definition of “affiliate;” although it retained the 

PUHCA 1935 threshold of five percent, it dropped much of the statutory text, thus 

leaving a potential gap in the scope of entities that could be considered affiliates. It is 

unclear whether this was a drafting oversight, but we do not believe Congress intended to 

preclude the Commission, in adopting regulations preventing cross-subsidization, undue 

preferences or the exercise of market power from using an “affiliate” definition that 

provides greater customer protection with respect to EWG transactions. Our Affiliate 

Transactions Final Rule and this rule thus use the 1935 statutory text framework for 

EWGs. We adopt the definition of affiliate promulgated in the Affiliate Transactions 
Docket No. RM04-7-001 -128- 

utility with captive customers and its market-regulated power sales affiliates.264 The 

affiliate restrictions codified in the regulations include a provision expressly prohibiting 

power sales between a franchised public utility with captive customers and a marketregulated power sales affiliate without first receiving Commission authorization.265 The 

Commission defined market-regulated power sales affiliate to mean “any power seller 

affiliate other than a franchised public utility, including a power seller affiliate, whose 

power sales are regulated in whole or in part at market-based rates.”266 

Requests for Rehearing

185. Occidental states that, in its current form, Order No. 697 could be interpreted to 

permit franchised public utilities to require their captive customers to subsidize their 

market-based rate activities, so long as their regulated and market-based rate activities 

were combined in a single entity.267 To prevent that result, Occidental requests that the 

Commission explicitly require that the functional attributes, rather than the arbitrary 

structure of a utility, be considered in determining compliance with the rule’s affiliate 

abuse provisions.268 Occidental states that the Commission should focus on potential 

 

Final Rule with a modification to reflect the approach discussed herein. 

264 Id. at P 549. 

265 Id. at P 467. 

266 Id. at P 490. 

267 Occidental Rehearing Request at 2. 

268 Id.
Docket No. RM04-7-001 -129- 

market-based rate seller conduct rather than on artificial structural distinctions selected 

by the seller. 269

186. Specifically, Occidental argues that, because Order No. 697 focuses solely on 

conduct between a utility and a legally separate affiliate, it would allow a utility to 

benefit its market-based rate activities at the expense of its captive regulated customers 

simply by collapsing its regulated and market-based rates sales activities into a single 

entity that, while not technically an affiliate of the utility, could attempt to engage in the 

abuses that Order No. 697 seeks to prevent.270 Occidental asserts that the Commission 

can focus on potential market-based rate seller conduct, rather than on artificial 

structural distinctions selected by the seller, by clarifying that it will not focus solely on 

the narrow definitions of franchised public utility, captive customer, and marketregulated power sales affiliate, but instead will use a functional test that broadly applies 

the concept embodied in the rule to seller conduct. 

187. Occidental states that the Commission should either clarify that the affiliate abuse 

requirements of the rule apply equally to market-regulated functions performed within a 

franchised public utility, or revise the definition of market-regulated power sales affiliate 

to achieve that same result.271 In the alternative, Occidental states the Commission 

should grant rehearing and modify “market-regulated power sales affiliate” to “market-

 269 Id. at 5. 

270 Id. at 4. 

271 Id. at 8. 
Docket No. RM04-7-001 -130- 

regulated power sales function” which would necessitate removing the provision stating 

that such an entity is not a franchised public utility.272 

Commission Determination

188. We deny Occidental’s request for rehearing and clarification. As we explained in 

Order No. 697, we “are concerned that there exists the potential for a franchised public 

utility with captive customers to interact with a market-regulated power sales affiliate in 

ways that transfer benefits to the affiliates and its stockholders to the detriment of the 

captive customers.”273 Accordingly, we have adopted in our regulations affiliate 

restrictions intended to guard against such behavior. 

189. If an entity decides to encompass its marketing function within the franchised 

public utility’s corporate structure, then there is no longer any affiliate entity to trigger 

the concerns of affiliate abuse that the market-based rate affiliate restrictions are 

designed to address. For example, one of our primary concerns in adopting affiliate 

restrictions is to prevent a franchised utility from making below-market sales to its 

merchant affiliate and to prevent the merchant affiliate from making above-market sales 

to its franchised utility affiliate. 

In particular, Occidental’s argument rests on the premise that the franchised public utility 

that encompasses its marketing function within the franchised public utility corporate 

structure could benefit its market-based rate activities at the expense of its captive 

 272 Id.

273 Order No. 697 at P 513. 
Docket No. RM04-7-001 -131- 

customers. Occidental appears to be suggesting that revenues from the franchised public 

utility’s off-system sales at market-based rates would be funneled to the utility’s 

shareholders rather than credited to the utility’s customers. However, such a scenario is 

at odds with Commission precedent requiring that off-system sales be reflected through 

allocation or revenue credits in the rates of the utility’s customers.274

190. Additionally, state commissions have oversight authority for franchised public 

utilities with captive customers that make retail sales. Therefore, the states should be 

able to ensure that a franchised public utility with captive customers does not attempt any 

“internal” cross-subsidization to the detriment of captive customers. Generally, states 

similarly require revenue crediting to the utility’s retail customers. 

191. Thus, we will deny Occidental’s request for rehearing and clarification and retain 

the current requirements for the affiliate restrictions. We will also retain the current 

definition of market-regulated power sales affiliate under Order No. 697. 

c. Definition of Captive Customers

Final Rule

192. As adopted in Order No. 697, 18 CFR 35.36(a)(6) defines captive customer as 

“any wholesale or retail electric energy customers served under cost-based 

 274 See, e.g., Public Service Co. of New Mexico, Opinion No. 146, 20 FERC 

¶ 61,290 at 61,546-48 (crediting revenue from intersystem opportunity sales to native 

load customers), reh’g denied, 21 FERC ¶ 61,334 (1982); Golden Spread Electric 

Cooperative, Inc., Opinion No. 501, 123 FERC ¶ 61,047 at P 94-98 (crediting revenue 

from intersystem opportunity sales to native load customers) (2008); Boston Edison Co., 

Opinion No. 53, 8 FERC ¶ 61,077 at 61,283 (allocating costs to firm services where the 

revenue crediting methodology may result in over-allocation of costs to the customers 

(continued...) 
Docket No. RM04-7-001 -132- 

regulation.”275 The Commission clarified that the definition of captive customers did 

not include those customers who have retail choice, i.e., the ability to select a retail 

supplier based on the rates, terms, and conditions of service offered. Rather, retail 

customers who have no ability to choose an electric energy supplier are considered 

captive because they must purchase from the local utility pursuant to cost-based rates set 

by a state or local regulatory authority; that is, they are served under cost-based 

regulation. 

193. The Commission further explained in Order No. 697 that retail customers who 

choose to be served under cost-based rates, even though they have the ability to choose 

one retail supplier over another, are not considered to be under “cost-based regulation” 

and therefore are not captive under the definition. 

194. While much of the discussion in Order No. 697 focused on retail customers, the 

Commission stated “regarding wholesale customers, sellers should continue to explain 

why, if they have wholesale customers, those customers are not captive.”276

195. The Commission also declined to include transmission customers in the definition 

of captive customers for purposes of market-based rates for public utilities. The 

Commission stated that the open access policies in Order No. 890 protect transmission 

customers from the exercise of vertical market power. 

 

whose rates were at issue), reh'g denied, Opinion No. 53-A, 9 FERC ¶ 61,002 (1979). 

275 Order No. 697 at P 478 (to be codified at 18 CFR 35.36(a)(6)). 

276 Order No. 697 at P 480. 
Docket No. RM04-7-001 -133- 

Requests for Rehearing

196. Occidental argues that, just as with retail customers that have retail choice, 

wholesale customers with alternatives should also not be deemed to be “captive 

customers.”277 Occidental argues that wholesale customers, whether buying under costbased or market-based rates, have alternatives and are therefore not captive. Occidental 

states that a wholesale seller does not have any obligation to sell to any buyer, nor is a 

wholesale buyer obligated to buy from any particular seller. Occidental argues that the 

Commission’s conclusion that retail customers with retail choice “are not served under 

cost-based regulation, since that term indicates a regulatory regime in which retail 

choice is not available” dictates that a wholesale cost-based customer cannot be captive 

because choice is, by definition, available.278 Accordingly, Occidental requests that the 

Commission remove wholesale customers from the definition of captive customers. 

Commission Determination

197. With regard to Occidental’s request for rehearing concerning whether wholesale 

customers should be included in the definition of “captive customers,” we note that 

Occidental raised the same argument in its comments in the Affiliate Transactions 

rulemaking. In the course of responding to Occidental’s concerns in that proceeding, the 

Commission provided a number of clarifications regarding the term “captive 

 277 Occidental Rehearing Request at 9. 

278 Id. 
Docket No. RM04-7-001 -134- 

customers,” the purpose of the definition, and its focus on “cost-based regulation” that 

we reiterate here. 

198. The Commission explained that its fundamental goal in categorizing certain 

customers as “captive” is to protect customers served by franchised public utilities from 

inappropriately subsidizing the market-regulated or non-utility affiliates279 of the 

franchised public utility or otherwise being financially harmed as a result of affiliate 

transactions and activities. In other words, we are concerned about the potential for the 

inappropriate transfer of benefits from such customers to the shareholders of the 

franchised public utility or its holding company.280 Where customers are served under 

market-based regulation as opposed to cost-based regulation, it is presumed that the 

seller has no market power over a customer and that the customer has a choice of 

 279 We note that the affiliate restrictions adopted in Order No. 697 apply to power 

sales and non-power goods and services transactions between franchised public utilities 

with captive customers and their market-regulated power sales affiliates, whereas the 

Affiliate Restrictions Final Rule applies to franchised public utilities with captive 

customers and their market-regulated power sales affiliates as well as their non-utility 

affiliates. Accordingly, the discussion herein is limited to market-regulated power sales 

affiliates. 

280 For example, if a market-regulated seller sells power to its affiliated franchised 

public utility at an above market price, the customers of the franchised public utility pay 

more than they need to for power and the affiliate makes a higher profit for the holding 

company’s shareholders. Similarly, if a franchised public utility sells temporarily excess 

fuel to its market-regulated power seller affiliate at a price below its cost, the customers 

of the franchised utility end up subsidizing the affiliate’s operating costs, to the benefit of 

shareholders and the detriment of the customers of the franchised utility. In other 

contexts, an extreme example would be a holding company that siphons funds from a 

franchised public utility to support its failing market-regulated power sales affiliate 

company; again, this results in financial benefit to shareholders at the expense of 

customers. 
Docket No. RM04-7-001 -135- 

suppliers; thus, there is less opportunity for a customer to involuntarily be in a situation 

in which its rates subsidize or support another entity. 

199. Under a regime of cost-based regulation, however, we cannot make these same 

assumptions. If a franchised public utility is selling at a wholesale cost-based rate under 

the FPA, the franchised utility seller may be in the position of potentially trying to flow 

through its cost-based rates costs that should instead be borne by its affiliates, i.e., 

potentially subsidizing the “non-regulated” activities of its market-regulated power sales 

affiliates to the detriment of the franchised public utility’s customer(s). As the 

Commission stated in the Affiliate Transactions Final Rule, while there is some merit to 

Occidental’s assertion that wholesale customers, by definition, have alternatives and that 

there is no obligation for a wholesale customer to sell to any buyer, nor for a buyer to 

buy from any particular seller, for the customer protection reasons stated above, we 

believe it is important to err on the side of a broad definition of captive customers. On 

this basis, we deny Occidental’s request for rehearing that the Commission change its 

existing analysis and generically exclude wholesale customers from the definition of 

captive customers. 

200. Nevertheless, as the Commission noted in the Affiliate Transactions Final Rule, 

although we are erring on the side of a broad definition of captive customers, we 

recognize that there may well be circumstances in which customers fall within our 

definition, even though there are sufficient protections in place to protect such customers 

against any risk of harm from transactions between the franchised public utility and its 

affiliates. For example, it is possible that wholesale customers with fixed rate contracts 
Docket No. RM04-7-001 -136- 

would be adequately protected and that the affiliate restrictions should not apply to 

utilities whose customers all have fixed rate contracts with no fuel adjustment clause.281 

The Commission explained that it is not prepared at this time to generically exclude such 

customers from the definition of captive customers but instead will allow franchised 

public utilities, on a case-by-case basis, to argue that the affiliate restrictions should not 

apply. This will allow the Commission to closely examine the facts related to each 

franchised public utility. There may be circumstances other than fixed rate contracts in 

which we may be willing to find that the affiliate restrictions do not apply, but a public 

utility will need to demonstrate that there is no opportunity for wholesale customers of 

the franchised public utility to be harmed as a result of affiliate transactions. 

201. We note that in Order No. 697, we stated that “regarding wholesale customers, 

sellers should continue to explain why, if they have wholesale customers, those 

customers are not captive.”282 Consistent with the foregoing discussion, we will modify 

that statement. If sellers have wholesale customers, instead of explaining why those 

customers are not captive, the sellers should explain why those customers are adequately 

protected against affiliate abuse. 

 281 The Commission would need to be assured that all wholesale customers of a 

franchised public utility have adequate fixed rate contracts, not just a sub-set of the 

customers. Further, because such contracts may have different expiration dates, the 

Commission might need to place temporal conditions on such a waiver. 

282 Order No. 697 at P 480. 
Docket No. RM04-7-001 -137- 

202. We also will revise the definition of captive customers to be consistent with the 

definition adopted in the Affiliate Transactions Final Rule. In that Final Rule, the 

Commission modified the definition of captive customers to make explicit what was 

only implicit in its earlier rules – that the definition is intended to apply to customers 

served by a franchised public utility under cost-based regulation. Accordingly, we will 

revise the definition of captive customers in 18 CFR 35.36(a)(6) to mean “any 

wholesale or retail electric energy customers served by a franchised public utility under 

cost-based regulation.” 

203. Additionally, as the Commission recently stated in the Affiliate Transactions Final 

Rule, if a state regulatory authority in a retail choice state does not believe that retail 

customers are sufficiently protected and that our affiliate restrictions should apply to the 

local franchised public utility, it may file a petition for declaratory order to deem its 

retail customers to be captive customers for purposes of applying the affiliate 

restrictions.283 A state regulatory authority may also raise such an argument as part of 

its comments in a market-based rate proceeding. 

d. Electric Cooperatives

Final Rule

204. The Commission declined to subject to the affiliate restrictions and regulations in 

§ 35.39 electric cooperatives that may otherwise be subject to the Commission’s 

jurisdiction. In Order No. 697, the Commission reasoned that “affiliate abuse takes 

 283 Affiliate Transactions Final Rule at P 45. 
Docket No. RM04-7-001 -138- 

place when the affiliated public utility and the affiliated power marketer transact in ways 

that result in a transfer of benefits from the affiliated public utility (and its ratepayers) to 

the affiliated power marketer (and its shareholders).”284 The Commission explained 

that, where a cooperative is involved, the cooperative’s members are both the ratepayers 

and the shareholders. Therefore, there is no potential danger of shifting the benefits 

from the ratepayers to the shareholders.285 

Requests for Rehearing

205. El Paso E&P argues that the Commission’s concerns regarding affiliate 

transactions should apply equally to sales by jurisdictional public utility cooperatives to 

their affiliated members,286 and that the Commission cannot abdicate its obligation to 

protect captive customers. According to El Paso E&P, the fact that a cooperative is 

comprised of its member distribution cooperatives could actually facilitate the exercise 

of market power, because a cooperative, through its member board, has an incentive to 

charge as much as it can to captive customers in order to subsidize the rates paid by its 

residential and commercial customers.287 

 284 Order No. 697 at P 526 (citing Heartland Energy Services, Inc., 68 FERC 

¶ 61,223, at 62,062 (1994)). 

285 Order No. 697 at P 526 (citing Old Dominion Electric Cooperative, 81 FERC 

¶ 61,044, at 61,236 (1997)). 

286 El Paso E&P Rehearing Request at 8 (citing Illonova Power Marketing, Inc., 

88 FERC ¶ 61,189 (1999); First Energy Trading & Power Marketing, Inc., 84 FERC 

¶ 61,214 (1998)).

287 Id. at 6, 12. 
Docket No. RM04-7-001 -139- 

206. El Paso E&P contends that the Commission abdicated its responsibility under the 

FPA to protect captive customers by claiming lack of jurisdiction over the 

cooperatives.288 El Paso E&P explains that no Commission precedent addresses the 

situation where sales at market-based rates are ultimately made to captive customers of 

the distribution cooperatives. El Paso E&P points out that, unlike other cases, a 

generation and transmission cooperative seller’s affiliate distribution cooperatives are 

not the ultimate consumers of the power.289 Therefore, El Paso E&P maintains, they do 

intend to pass on potential excessive purchased power costs to captive customers. 

207. For example, El Paso E&P argues that the fact that Deseret and Moon Lake may 

receive above-market rates from El Paso E&P will not necessarily result in profit to 

either entity. Rather, the collection of such monopoly rents could be used by either 

Deseret or Moon Lake to subsidize the costs paid by other ratepayers in their members' 

franchised service territories. Even if it did result in profits to either Deseret or Moon 

Lake, El Paso E&P asserts that there is no assurance that El Paso E&P would receive 

any share of such profits since it is not a member of Deseret’s board and has no say in 

what Deseret charges to its members. Because it also is not a member of Moon Lake’s 

board, El Paso E&P argues it has no ability to vote on whether any profits that may be 

earned by Deseret, and may be credited to Moon Lake, are actually paid back to it.290 

 288 Id. at 6. 

289 Id. at 11. 

290 Id. at 12-13. 
Docket No. RM04-7-001 -140- 

208. El Paso E&P also argues that the Commission erred in justifying its failure to 

protect captive ratepayers of cooperatives on the ground that El Paso E&P’s concern is 

really about discrimination in the allocation of benefits and burdens among retail 

ratepayers, which is a state law issue. El Paso E&P argues that this cannot be squared 

with the protection that the Commission provides in Order No. 697 for captive 

ratepayers of non-cooperative sellers.291 El Paso E&P takes the position that, if the 

Commission permits cooperatives to charge market-based rates, then the Commission is 

obligated to ensure that all captive customers are protected from any abuse or excessive 

rates resulting from those market-based rates.292

209. Moreover, El Paso E&P argues that the Commission has not explained how state 

commissions could deny pass-through of market-based rates by distribution cooperatives 

to their retail customers when the rates have been approved by the Commission.293 It 

asserts that the cases cited by the Commission are not on point. Specifically, the 

exception to federal pre-emption discussed in Nantahala Power and Light Co. v. 

Thornburg294 relates to the quantity purchased, not the price paid. El Paso E&P 

 291 Id. at 14. 

292 Id. at 8. 

293 Id. at 7, 15 (citing Arkansas Power & Light Co. v. Missouri Public Service 

Commission, 829 F.2d 1444, 1452-53 (8th Cir. 1987)) (Arkansas P&L) (holding that the 

ordinary state-law process of suspension and investigation of retail rates is not preempted 

by the FPA ,and there is no language in the FPA to indicate that Commission orders on 

wholesale rates require an immediate pass-through of those wholesale rates).

294 476 U.S. 953 (1986). Mississippi Power & Light Co. v. Mississippi ex rel. 

Moore, 487 U.S.354 (1958) (holding that state commissions must treat Commission-

(continued...) 
Docket No. RM04-7-001 -141- 

contends that this exception is not applicable to cooperatives because their cooperative 

structure requires the distribution cooperative members to purchase their power from 

their generation and transmission cooperative.295 

Commission Determination

210. We deny El Paso E&P’s request for rehearing. El Paso E&P has not raised any 

new arguments on rehearing, and it has not persuaded us to reverse our finding from 

Order No. 697 that electric cooperatives are not subject to the Commission’s affiliate 

restrictions codified in § 35.39. 

211. The Commission explained in Order No. 697 that, even if an electric cooperative 

is not exempt from public utility regulation by the FPA under section 201(f), the 

Commission previously determined that transactions of an electric cooperative with its 

members do not present dangers of affiliate abuse through self-dealing.296 Where a 

cooperative is involved and the cooperative’s members are both the ratepayers and the 

 

approved costs for wholesale power as reasonably incurred operating expenses for the 

purposes of setting retail rates, but state commissions are precluded from setting retail 

rates that would “trap” the costs a seller was mandated to pay under a Commission order, 

or from undertaking a prudence review for the purpose of deciding whether to approve 

such retail rates.); Central Vermont Public Service Corporation, 84 FERC ¶ 61,194 

(1998)) (holding that state commissions are preempted by federal law from reviewing the 

prudence of power purchases, if, as a result of wholesale power supply allocation directed 

by the Commission, the purchaser has no legal choice but to make a particular purchase 

and to permit such a review would interfere with the Commission’s plenary authority 

over interstate wholesale rates).

295 Id.

296 Order No. 697 at P 526 (citing Heartland Energy Services, Inc., 68 FERC 

¶ 61,223, at 62,062 (1994)). 
Docket No. RM04-7-001 -142- 

shareholders, any profits earned by the cooperative will inure to the benefit of the 

cooperative’s ratepayers. As such, no potential danger exists of shifting benefits from 

the ratepayers to the shareholders. Deseret is not a for-profit entity with an incentive to 

maximize its rates for the benefit of its shareholders; rather, its ratepayers and 

shareholders are the same entities. Similarly, Moon Lake is not a power marketer 

concerned only with passing its costs through to its ratepayers for the benefit of its 

shareholders. Rather, Moon Lake is responsible to its members, including El Paso E&P, 

which is entitled to vote in Moon Lake’s Board elections and is entitled to the same 

single vote held by each residential and commercial ratepayer of Moon Lake.297

212. Moreover, if Deseret charges Moon Lake higher rates than Deseret charges its 

other five member cooperatives, it may be engaging in discrimination, which is barred 

by sections 205 and 206 of the FPA. As we explained in Order No. 697, El Paso E&P’s 

concern is not one that can be addressed through affiliate restrictions in market-based 

rates, but is rather more of a concern of discrimination in the allocation of benefits and 

burdens among retail ratepayers.298

213. Therefore, we deny El Paso E&P’s request for rehearing and reaffirm our finding 

that electric cooperatives are not subject to the affiliate restrictions codified in § 35.39 

because there is no danger of affiliate abuse through self-dealing. 

 297 See El Paso E&P Rehearing Request at 13, n.7. 

298 Order No. 697 at P 527. 
Docket No. RM04-7-001 -143- 

e. Public Utility Holding Company Act of 2005 as a 

“Commission Rule or Order” Permitting At-Cost Pricing

Final Rule

214. Order No. 697 requires that sales of any non-power goods or services by a marketregulated power sales affiliate to an affiliated franchised public utility with captive 

customers will not be at a price above market, unless otherwise permitted by 

Commission rule or order.299 The Commission also adopted the proposal to require that 

sales of non-power goods or services by a franchised public utility with captive 

customers to a market-regulated power sales affiliate be at the higher of cost or market 

price, unless otherwise authorized by the Commission. The Commission explained that 

these requirements will protect captive customers against affiliate abuse by ensuring that 

the utility with captive customers does not recover too little for goods and services 

provided to a market-regulated power sales affiliate and that the franchised public utility 

with captive customers does not pay too much for goods and services provided by a 

market-regulated power sales affiliate.300 

Requests for Rehearing

215. EEI states that the Final Rule requires market-regulated affiliates to sell nonpower goods and services to utilities with captive customers at or below market prices, 

unless otherwise authorized by the Commission. It seeks rehearing of the Final Rule as 

 299 Id. at P 597; 18 CFR 35.39(e). 

300 Id. 
Docket No. RM04-7-001 -144- 

that requirement may apply to centralized service companies.301 Specifically, EEI notes 

that in Order No. 667, the Commission issued a final rule implementing the Public 

Utility Holding Company Act of 2005, with a rebuttable presumption that centralized 

service companies may use “at cost” pricing for services to affiliate utilities, unless 

complainants demonstrate that the at-cost pricing exceeds the market price.302 EEI 

requests that the Commission clarify that Order No. 667 constitutes a “Commission rule 

or order” generally authorizing use of at-cost pricing by centralized service companies to 

utility affiliates under Order No. 697, absent complainant evidence that such pricing 

exceeds the market price.303 

Commission Determination

216. We will grant EEI’s request and clarify that Order No. 667 constitutes a 

Commission rule or order generally authorizing the use of at-cost pricing by a 

centralized service company to utility affiliates absent any demonstration that at-cost 

pricing exceeds the market price. 

217. In Order No. 667, the Commission allowed centralized service companies to sell 

non-power goods and services to affiliated franchised utilities using an “at cost” 

 301 EEI Rehearing Request at 2. 

302 Repeal of the Public Utility Holding Company Act of 1935 and Enactment of 

the Public Utility Holding Company Act of 2005, Order No. 667, FERC Stats. & Regs. 

¶ 31,197, at P 169 (2005), order on reh’g, Order No. 667-A, FERC Stats. & Regs. 

¶ 31,213, order on reh’g, Order No. 667-B, FERC Stats. & Regs. ¶ 31,224 (2006), order 

on reh’g, Order No. 667-C, 118 FERC ¶ 61,133 (2007).

303 EEI Rehearing Request at 4, 7-8. 
Docket No. RM04-7-001 -145- 

standard, stating that “there is a rebuttable presumption that such ‘at-cost’ sales for nonpower goods and services between a centralized service company and its affiliates are 

reasonable.”304 The Commission made clear that the rebuttable presumption for “atcost” sales for non-power goods and services only applies to sales by a centralized 

service company to its affiliates. Sales of non-power goods and services made by 

market regulated or unregulated affiliates other than centralized service companies to 

their franchised utility affiliates are subject to the Commission’s “no higher than 

market” standard.305 The Commission also explained that while it will apply a 

rebuttable presumption that costs incurred under “at-cost” pricing for services provided 

by centralized service companies are reasonable, the Commission will entertain 

complaints that “at-cost” pricing for such services exceeds the market price.306

218. Given the Commission’s reasoning set forth in Order No. 667 and Order No. 667-

A, we clarify that, for centralized service companies, as defined in Order No. 667 and § 

366.5 of the Commission’s regulations, Order No. 667 constitutes a “Commission rule or 

order” generally authorizing use of at-cost pricing by centralized service companies to 

their franchised public utilities with captive customers, absent complainant evidence that 

such at-cost pricing exceeds the market price. 

 304 Order No. 667-A, FERC Stats. & Regs. ¶ 31,213 at P 38.

305 Id.

306 Order No. 667, FERC Stats. & Regs. ¶ 31,197 at P 169. 
Docket No. RM04-7-001 -146- 

f. Sales of Non-Power Goods and Services

Final Rule

219. In Order No. 697, the Commission held that sales of non-power goods or services 

by a franchised public utility with captive customers to a market-regulated power sales 

affiliate are to be at the higher of cost or market price, unless otherwise authorized by the 

Commission. The Commission also codified the requirement that sales of any non-power 

goods or services by a market-regulated power sales affiliate to an affiliated franchised 

public utility with captive customers will not be at a price above market, unless otherwise 

authorized by the Commission.307

Requests for Rehearing

220. FP&L seeks limited clarification or, in the alternative, reconsideration of Order 

No. 697 on the issue of pricing of non-power goods and services provided for affiliates 

by either franchised public utilities or their market-regulated power sales affiliates when 

those services are comparable to shared services provided by a centralized service 

company. 

221. FP&L requests clarification that when a franchised public utility provides its 

market-regulated power sales affiliates with non-power goods or services, or a marketregulated power sales affiliate provides its affiliated franchised public utility with nonpower goods and services, and those services are comparable to those provided by a 

centralized service company, then those non-power goods and services may be provided 

 307 Order No. 697 at P 597 (to be codified at 18 CFR 35.39(e)). 
Docket No. RM04-7-001 -147- 

at fully-loaded cost as a reasonable proxy for market price.308 FP&L also requests that 

the Commission clarify that the grandfathering provision in the Affiliate Transactions 

Final Rule (which provides that the pricing rules adopted therein are prospective only) 

also applies with respect to the requirements of Order No. 697 where existing interaffiliate transactions involving non-power goods and services are comparable to those 

provided by a centralized service company. 

Commission Determination

222. Issues similar to those raised here by FP&L also have been raised on rehearing of 

the Affiliate Transactions Final Rule, which applies the same standards for the pricing of 

non-power goods and services as Order No. 697. To ensure consistency in our approach 

to pricing of non-power goods and services between both rulemaking proceedings, the 

Commission will address FP&L’s arguments concerning Order No. 697 in a 

supplemental order.309

2. Power Sales Restrictions

a. Sales Between Two Affiliates Requiring Prior 

Commission Approval

 308 FP&L March 24, 2008 Request for Clarification at 4. 

309 The Commission need not address all issues raised in a proceeding at one time. 

See Mobil Oil Exploration & Producing Southeast, Inc. v. United Distribution 

Companies, 498 U.S. 211 (1991) (holding that an agency enjoys broad discretion in 

determining procedurally how best to handle related yet discrete issues). See also

Colorado Office of Consumer Counsel v. FERC, 490 U.S. 954 (D.C. Cir. 2007) (holding 

that the Commission need not revisit all elements of a tariff upon finding one aspect to be 

unjust and unreasonable). 
Docket No. RM04-7-001 -148- 

Final Rule

223. In paragraph 467 of the Final Rule, the Commission stated that it was adopting in 

the regulations a provision expressly prohibiting power sales between a franchised 

public utility with captive customers and any market-regulated power sales affiliates 

without first receiving Commission authorization for the transaction under section 205 

of the FPA.310 

224. The Commission further noted (in paragraph 492) that while it has historically 

placed affiliate restrictions only on the relationship between a franchised public utility 

with captive customers and any affiliated market-regulated power sales affiliate, the 

Commission believes there may be circumstances in which it also would be appropriate 

to impose similar restrictions on the relationship of two affiliated franchised public 

utilities where one of the affiliates has captive customers and one does not. The 

Commission said it would not generically impose the affiliate restrictions on such 

relationships but will evaluate whether to impose the affiliate restrictions in such 

situations on a case-by-case basis.311 

Requests for Rehearing

225. Ameren argues that paragraphs 467 and 492 of Order No. 697, taken together, 

provide that power sales between two affiliated franchised public utilities – one with 

captive customers and one without – are not prohibited, do not require prior 

 310 Order No. 697 at P 467. 

311 Id. P 492. 
Docket No. RM04-7-001 -149- 

authorization under section 205 of the FPA, and are not generally subject to the affiliate 

restrictions. Instead, the Commission said that it will consider applying the restrictions 

on a case-by-case basis.312 Given that position, Ameren is confused by § 35.39(h) of the 

new regulations, which provides: 

If necessary, any affiliate restrictions regarding separation of functions, 

power sales or non-power goods and services transactions, or brokering 

involving two or more franchised public utilities, one or more of whom has 

captive customers and one or more of whom does not have captive 

customers, will be imposed on a case-by-case basis. [313] 

226. Ameren states this provision is meaningless if prior authorization of such 

transactions is not required. With regard to the Commission’s statement that it will 

consider applying the affiliate restrictions on a case-by-case basis, Ameren states that 

the Commission fails to explain how it will conduct such an analysis of the need to 

apply the restriction or when such an obligation to abide by this particular restriction 

would arise. 

227. Ameren states that the Commission should do one of three things. Because the 

Commission itself noted that commenters did not show a potential for affiliate abuse in 

such a situation, the Commission could clarify, consistent with precedent, that prior 

authorization of power sales between affiliated franchised public utilities is not required 

and therefore § 35.39(h) will be deleted. Alternatively, the Commission could clarify 

that, absent a specific finding imposed prospectively under sections 205 or 206 of the 

 312 Ameren Rehearing Request at 5. 

313 Emphasis added. 
Docket No. RM04-7-001 -150- 

FPA, a utility has no obligation to seek prior authorization of power sales between 

affiliated franchised public utilities. Conversely, Ameren maintains that, if the 

Commission intends that public utilities seek pre-approval of such transactions, then it 

should clearly state that intention. Without such clarification, Ameren asserts that 

franchised public utilities face an uncertain regulatory regime when transacting with 

another franchised public utility.314 

Commission Determination

228. In response to Ameren’s request, we clarify that when a franchised public utility 

receives section 205 authority to sell at market-based rates, it does not have to obtain a 

separate section 205 authority for power sales to another franchised public utility, as 

would be the case if it wanted to make power sales to a non-franchised, marketregulated power sales affiliate. Thus, an additional authorization is not required for 

power sales between two affiliated franchised public utilities, one with captive 

customers and one without captive customers. We clarify that, when we said we would 

evaluate these situations on a case-by-case basis, we meant that the Commission, on its 

own motion or in response to a complaint, may decide to examine the circumstances of 

any power sales between two such affiliated franchised public utilities, where one has 

captive customers and the other does not. Any determination based on such an 

examination would be prospective only. 

 314 Id. at 6. 
Docket No. RM04-7-001 -151- 

b. Affiliate Restrictions’ Applicability to Franchised Public 

Utilities and Commission Jurisdictional MarketRegulated Power Sales Affiliates

Final Rule

229. The Commission explained in Order No. 697 that the market-based rate affiliate 

restrictions codified in § 35.39 govern the relationship between a franchised public 

utility with captive customers and its market-regulated power sales affiliates. This 

ensures that captive customers are protected from any potential for harm as a result of 

affiliate dealings. 

Requests for Rehearing

230. FP&L states that it remains unclear whether the restrictions are intended to cover 

non-franchised power marketers whose sales are not subject to Commission jurisdiction 

– for example power marketers selling exclusively into the Electric Reliability Counsel 

of Texas (ERCOT). 315 FP&L requests that the Commission clarify that the affiliate 

restrictions apply only to the relations between franchised public utilities with captive 

customers and their Commission-jurisdictional market-regulated power sales affiliates, 

and do not apply to affiliates engaged in power sales exclusively within ERCOT.316 

FP&L states that, given the magnitude of an expansion of the affiliate restrictions to 

cover non-Commission-jurisdictional power marketers, and the absence of any explicit 

 315 FP&L Rehearing Request at 11. 

316 Id. at 10, 12. 
Docket No. RM04-7-001 -152- 

discussion in either the proposed rule or the Final Rule in this proceeding, FP&L does 

not believe the Commission intends such an expansion.317 

Commission Determination

231. We grant in part FP&L’s request for clarification. The Commission’s marketbased rate regulations, including the affiliate restrictions, do not apply to entities that are 

not considered public utilities under FPA section 201(e), which would include entities 

engaged in power sales exclusively within ERCOT. 

232. The Commission’s market-based rate regulations apply to any public utility with 

market-based rates. If a franchised public utility with market-based rates sells to an 

affiliate company in ERCOT (which would be a non-public utility), the affiliate 

restrictions would apply to the franchised public utility’s dealings with the affiliate. It 

could not sell to or purchase from the ERCOT affiliate unless consistent with our 

regulations. The affiliate restrictions would not apply to the ERCOT affiliate’s dealings 

with the other non-public utility affiliates since the ERCOT affiliate is not a public utility. 

3. Market-Based Rate Affiliate Restrictions

233. In codifying the affiliate restrictions in the regulations, the Commission 

established certain restrictions that govern the separation of functions, sharing of market 

information, sales of non-power goods or services, and power brokering to govern the 

relationship between franchised public utilities with captive customers and their marketregulated affiliates. As a condition of receiving and retaining market-based rate 

 317 Id. at 12. 
Docket No. RM04-7-001 -153- 

authority, the Commission required sellers to comply with these affiliate restrictions 

unless otherwise permitted by Commission rule or order.318

a. Two-Way Information Sharing Restriction

Final Rule

234. The Commission adopted a two-way information sharing restriction in § 35.39(d) 

prohibiting a franchised public utility with captive customers from sharing information 

with a market-regulated power sales affiliate, and vice-versa.319 

Requests for Rehearing

235. Southern argues the Commission erred in Order No. 697 by adopting a two-way 

information restriction (§ 35.39(d)) that prevents a franchised public utility from 

receiving information from its market-regulated power sales affiliate. Southern claims 

that the Commission failed to demonstrate that communications from a market-regulated 

power sales affiliate to a franchised public utility would harm captive customers and that 

the existing one-way communication restriction currently in many Commission-accepted 

codes of conduct is insufficient. 

236. Southern states that the Commission provided one example of how information 

shared with a franchised public utility by its market-regulated affiliate might harm 

captive customers. Specifically, the Commission stated that in an RFP situation where 

 318 Order No. 697 at P 549. To the extent that the Commission did not impose a 

code of conduct requirement on a seller as a condition of market-based rate authority 

because the seller had demonstrated that it did not have captive customers, that waiver 

remains in effect provided that the seller still does not have captive customers. 

319 Id. P 583. 
Docket No. RM04-7-001 -154- 

both a franchised public utility and its market-regulated affiliate are considering whether 

to submit a bid and the market-regulated affiliate is allowed to share its price and 

quantity information, the franchised public utility could possibly use the information for 

the benefit of its stockholders at the expense of its captive customers. However, 

Southern submits that § 35.39(d) is written much broader than is necessary to address 

this concern, and could serve to unnecessarily prevent a franchised public utility from 

receiving operational information under Commission-approved generation pooling 

arrangements. Southern argues that the Commission has not suggested much less 

demonstrated that a franchised public utility’s knowledge of the status of its marketregulated affiliate’s units could advantage the market-regulated affiliate at the expense 

of the franchise public utility’s captive customers. Accordingly, Southern alleges Order 

No. 697 is without a rational basis in this regard and unsupported by substantial 

evidence.320 

237. Southern believes that the two-way restriction would actually harm captive 

customers by impairing the pooling arrangement, thereby denying them the traditional 

benefits of integration and coordinated operations and by triggering costs and 

 320 Southern Rehearing Request at 6 (citing Motor Vehicles Mfrs. Ass’n., 463 U.S. 

at 43 (1983) (stating that the agency must articulate a “rational connection between the 

facts found and the choice made”); Burlington Truck Lines v. U.S., 371 U.S. 156, 168 

(1962); Western Union v FCC, 856 F.2d 315, 318 (D.C. Cir. 1988) (stating that an 

agency must demonstrate a “rational connection between the facts found and the choice 

made”)). 
Docket No. RM04-7-001 -155- 

inefficiencies that far outweigh any conceivable benefit. Accordingly, Southern requests 

that the Commission reconsider the two-way information sharing restriction. 

238. Moreover, according to Southern, the Commission failed to recognize the 

implementation burden that will be imposed by the two-way restriction. Southern 

submits that the Commission has grossly underestimated the expense and effort that will 

be required for utilities to implement the two-way restriction.321 Based on its actual 

experience, Southern believes that compliance with the two-way restriction will be very 

costly to utilities and require a substantial amount of time to complete, potentially in 

excess of six months (a much longer period than is allowed by an effective date of 60 

days after the Final Rule’s publication in the Federal Register).322 While some utilities 

may be able to complete their implementation of the two-way restriction within this 

period, Southern argues it is more likely that most utilities will need more time to ensure 

compliance. Thus, to the extent the Commission maintains the two-way restriction, 

Southern requests that the Commission allow utilities and their market-regulated power 

sales affiliates sufficient time to implement the two-way restriction.323

239. To the extent the Commission maintains the restriction, in any form, Southern 

requests that the Commission clarify the scope of § 35.39(d) and limit the types of 

information that are restricted to be consistent with the above-described example set 

 321 Id. at 37. 

322 Order No. 697 at P 1133. 

323 Southern Rehearing Request at 36, 39. 
Docket No. RM04-7-001 -156- 

forth in Order No. 697. 324 Southern states that, at a minimum, the Commission should 

provide an exception for information provided to franchised public utilities by their 

market-regulated affiliate pursuant to participation in Commission-approved pooling 

arrangements. Finally, and to the extent the Commission retains any two-way 

restrictions, it should allow franchised public utilities and their market-regulated power 

sales affiliates sufficient time to assess their organizations and technology infrastructures 

and implement the measures necessary to ensure compliance.325 

Commission Determination

240. After consideration of Southern’s arguments, we will grant Southern’s request for 

rehearing on this issue. 

241. As previously explained, the purpose of the affiliate restrictions is to ensure that 

captive customers of a franchised public utility are adequately protected from any harm 

that may arise from affiliate dealings. In an attempt to provide regulatory certainty, and 

upon further review, we find that the one-way information sharing restriction, which 

prohibits a franchised public utility with captive customers from sharing market 

information with a market-regulated power sales affiliate, adequately protects captive 

customers. We have not been presented with any specific examples how captive 

customers have been harmed by a market-regulated power sales affiliate sharing market 

information with its franchised public utility with captive customers. We also note that 

 324 Id. at 39. 

325 Id. at 40-41. 
Docket No. RM04-7-001 -157- 

adopting a one-way information sharing restriction is consistent with the Commission’s 

approach in the Standards of Conduct. 

242. While we are granting Southern’s request for rehearing on this issue, we remind 

sellers that the information sharing provision, like all affiliate restrictions, is subject to 

the no-conduit rule. The no-conduit rule allows permissibly-shared employees to 

receive market information so long as they are not conduits for sharing that information 

with employees that are not permissibly shared. Additionally, we remind all marketbased rate sellers that the FPA prohibits any seller from providing an undue preference 

to an affiliate or any other seller.326

b. Affiliate Restrictions’ Precedence Over Pre-Existing 

Codes of Conduct

Final Rule

243. As stated above, the Commission expressly stated in Order No. 697 that the 

regulations at 18 CFR Part 35, Subpart H, including the affiliate restrictions, will 

become effective 60 days after publication of Order No. 697 in the Federal Register.

327 

Order No. 697 became effective on September 18, 2007. 

Requests for Rehearing

244. Ameren asserts that a reasonable interpretation of Order No. 697 is that sellers 

with market-based rate authority are to follow the affiliate restrictions in § 35.39 upon 

the effective date of the regulation, but states nothing is said regarding the potential for 

 326 See 16 USC 824d (2001). 

327 Id. at P 924. 
Docket No. RM04-7-001 -158- 

conflicts between the new regulations and existing affiliate restrictions/codes of conduct 

and how such conflicts will be resolved. Ameren states that the Commission apparently 

intended the new regulations to supersede the existing affiliate restrictions/codes of 

conduct, but asserts that clarification is needed. Thus, in order to avoid uncertainty and 

increase transparency, Ameren asks the Commission to clarify whether the new 

regulations take precedence over the affiliate restrictions/codes of conduct currently on 

file upon the effective date of the new regulations.328 

Commission Determination

245. The Commission clarifies that the new affiliate restriction regulations promulgated 

in Order No. 697 and codified in § 35.39 supersede the codes of conduct approved by 

the Commission prior to Order No. 697’s effective date.329 The affiliate restrictions in § 

35.39 now govern the relationship between a franchised public utility with captive 

customers and its market-regulated power sales affiliates. In the event of a conflict 

between a seller’s previously approved code of conduct and the new affiliate restriction 

regulations, the regulations supersede a previously approved code of conduct. For 

example, if a seller’s previous code of conduct prohibited information sharing of any 

market information, public or non-public, because the definition of market information 

 328 Ameren Rehearing Request at 7. 

329 Clarification Order, 121 FERC ¶ 61,260 at P 5. 
Docket No. RM04-7-001 -159- 

in the regulations does not prohibit the disclosure of publicly available information, a 

seller may share public market information under the new affiliate restrictions.330 

246. Nevertheless, where the Commission had imposed in a Commission order in a 

particular case specific limitations that are more restrictive than those codified in § 

35.39, such limitations would continue to be in effect. We also clarify that, while all 

sellers with market-based rate authority must abide by the affiliate restrictions as set 

forth in § 35.39 of the Commission’s regulations, if a seller wishes to impose a more 

restrictive limitation than currently exists in the affiliate restrictions, such seller may 

propose additional tariff provisions for the Commission to review in a filing under FPA 

section 205. 

c. Treatment of “Field & Maintenance” Employees and 

Shared Operation and Maintenance Staff in Affiliate 

Restrictions

Final Rule

247. In the Final Rule, the Commission codified in its regulations the requirement that, 

to the maximum extent practical, the employees of a market-regulated power sales 

affiliate must operate separately from the employees of any affiliated franchised public 

utility with captive customers (independent functioning requirement). The Commission 

adopted an exception to the independent functioning requirement that permits a 

franchised public utility with captive customers and its market-regulated power sales 

affiliates to share senior officers and members of the board of directors, support 

 330 See id. P 592. 
Docket No. RM04-7-001 -160- 

employees, and field and maintenance employees that perform purely manual, technical, 

or mechanical duties and do not have planning or direct operational responsibilities.331

Requests for Rehearing

248. FP&L states that certain of these changes and refinements to the affiliate 

restrictions (formerly code of conduct) appear subject to interpretation, and certain 

interpretations may be more restrictive than intended.332 Specifically, FP&L states the 

Commission should clarify that “field and maintenance employees” include technical 

and engineering personnel engaged in generation-related activities, provided that such 

employees do not themselves: (1) buy or sell energy; (2) make economic dispatch 

decisions; (3) determine (as opposed to implement) outage schedules; or (4) engage in 

power marketing activities.333 FP&L states that sharing such employees does not 

diminish or jeopardize the requirement of separation of functions “to the maximum 

extent practical,” and is “unlikely to harm captive customers.”334 

249. Additionally, FP&L urges that the Commission clarify that “field and maintenance 

employees” include non-commercial technical and engineering personnel involved in 

nuclear plant operations.335 FP&L notes that, in the context of nuclear plant operations, 

 331 Id. P 561-63, 565; 18 CFR 35.39(c)(2)(ii). 

332 FP&L Rehearing Request at 2, 4. 

333 Id. at 3, 6-7. 

334 Id. at 6. 

335 Id. at 7. 
Docket No. RM04-7-001 -161- 

adherence to Nuclear Regulatory Commission (NRC) requirements and safe operations 

in general often are facilitated by the creation of a broad knowledge pool using all of a 

company’s personnel with expertise in nuclear operations.336 

250. EEI notes that Order No. 697 allows franchised public utilities with captive 

customers and their market-regulated power sales affiliates to share field and 

maintenance employees and their supervisors, but that it conditions this allowance on 

the employees and supervisors not exercising “control” over generation facilities.337 If 

interpreted broadly, EEI argues this condition could eliminate the ability to share such 

staff that work on generation facilities, because operation and maintenance of generation 

facilities necessarily involve the ability to curtail or stop operation of the facilities. EEI 

requests that the Commission clarify that companies may share such employees and 

supervisors even if the employees and supervisors have the authority to curtail or stop 

the operation of generation facilities as part of their operation and maintenance 

functions, so long as the employees are not involved in decisions regarding the 

marketing or sale of electricity from the facilities.338 

Commission Determination

251. We grant FP&L’s request for clarification that “field and maintenance employees” 

includes technical and engineering personnel engaged in generation-related activities, 

 336 Id.

337 EEI Rehearing Request at 5 (citing Order No. 697 at P 565). 

338 EEI Rehearing Request at 3-4 and 5-6. 
Docket No. RM04-7-001 -162- 

provided that such employees do not themselves: (1) buy or sell energy; (2) make 

economic dispatch decisions; (3) determine (as opposed to implement) outage schedules; 

or (4) engage in power marketing activities. 

252. We have no evidence that such field and maintenance employees have engaged in 

behavior that would adversely affect captive customers. Additionally, we note that such 

field and maintenance employees are still subject to the no-conduit rule. Based on the 

evidence before us, the existing regulations and the overarching purpose of the affiliate 

restrictions, we find that excepting field and maintenance employees from the 

independent functioning requirement, provided such employees do not engage in 

prohibited actions as outlined above, is consistent with the affiliate restrictions. This 

clarification also is applicable to FP&L’s request regarding shared employees involved 

in nuclear plant operations.339

253. In response to EEI’s request for clarification, although Order No. 697 states that 

operational employees may not be shared, the Commission clarifies that companies may 

share employees and supervisors who have the authority to curtail or stop the operation 

of generation facilities solely for operational reasons. However, shared employees may 

not be involved in decisions regarding the marketing or sale of electricity from the 

facilities, may not make economic dispatch decisions, and may not determine the timing 

 339 Order No. 697 permits the sharing of information to enable nuclear power 

plants to comply with the requirements of the NRC as described in the NRC’s 

February 1, 2006 Generic Letter 2006-002, Grid Reliability and the Impact on Plant Risk 

and the Operability of Offsite Power. Order No. 697 at P 581. 
Docket No. RM04-7-001 -163- 

of scheduled outages for facilities. The Commission did not create the exception for 

permissibly-shared field and maintenance employees to enable those employees to 

confer a benefit on a franchised power utility’s market regulated power sales affiliate to 

the detriment of captive customers. Thus, to ensure that captive customers are not 

harmed, shared field and maintenance employees may not make economic dispatch 

decisions or determine when scheduled maintenance outages (as opposed to emergency 

forced outages) will occur. 

d. Risk Management Employees Under the No-Conduit Rule

Final Rule

254. With regard to the independent functioning requirement in the affiliate restrictions, 

the Commission adopted a “no-conduit rule” that prohibits a franchised public utility 

with captive customers and a market-regulated power sales affiliate from using anyone, 

including asset managers, as a conduit to circumvent the affiliate restrictions.340 

Otherwise, Order No. 697 did not specifically address the sharing of risk management 

employees. 

Requests for Rehearing

255. FP&L requests that the Commission clarify that, subject to the no-conduit rule, 

risk management employees may permissibly be shared under the affiliate 

restrictions.341 FP&L states that, while it does not believe Order No. 697 establishes a 

 340 Order No. 697 (to be codified at 18 CFR 35.39(g)). 

341 FP&L Rehearing Request at 8. 
Docket No. RM04-7-001 -164- 

prohibition against shared risk management employees, in the absence of an explicit 

reference to risk management in § 35.39(c)(2)(ii), Order No. 697 has created 

confusion.342 

Commission Determination

256. We find that risk management personnel do not fall within the scope of the 

independent functioning rule, so long as they are acting in their roles as risk 

management personnel rather than as marketing function employees, as defined in the 

standards of conduct. Of course, such risk management employees remain subject to the 

no-conduit rule and may not pass market information to marketing function 

employees.343

e. Definition of “Market Information”

Final Rule

257. In Order No. 697, the Commission adopted a definition of market information: 

“non-public information related to the electric energy and power business including, but 

not limited to, information regarding sales, cost of production, generator outages, 

generator heat rates, unconsummated transactions, or historical generator volumes.”344 

The Commission explained that market information includes information that, if shared 

 342 Id. at 10. 

343 See Standards of Conduct for Transmission Providers, Notice of Proposed 

Rulemaking, 73 FR 16,228 (March, 27, 2008), FERC Stats. & Regs. ¶ 32,630 (March 21, 

2008) (Standards of Conduct NOPR). 

344 Order No. 697 at P 591 (to be codified at 18 CFR 35.36(a)(8)). 
Docket No. RM04-7-001 -165- 

between a franchised public utility and a market-regulated affiliate, could result in a 

detriment to the franchised public utility’s captive customers.345

Requests for Rehearing

258. Ameren argues that, in introducing its new definition of “market information,” for 

purposes of the restrictions on affiliates sharing information, the Commission incorrectly 

quotes from its 1996 order in UtiliCorp United, Inc.346 Specifically, Ameren alleges that 

the Commission recited the list of types of data from UtiliCorp, but added “past” to the 

litany. According to Ameren, this “misquote” sets the stage for the new definition to 

include past information, such as “historical generator volumes” and “past sales and 

purchase activities.” Ameren requests rehearing of this expansion of the definition of 

the term “market information” to include past information. In addition, Ameren states 

that the Commission does not explain how past information, such as historical generator 

volumes, could be used to the detriment of the franchised public utility’s captive 

customers.347 

Commission Determination

259. The Commission denies Ameren’s request for rehearing. The Commission is 

intentionally including past market information in the information disclosure 

prohibitions because there are instances in which the sharing of historical (or past) 

 345 Id. P 593. 

346 75 FERC ¶ 61,168 (1996) (UtiliCorp). 

347 Ameren Rehearing Request at 8. 
Docket No. RM04-7-001 -166- 

market information between a franchised public utility with captive customers and a 

market-regulated power sales affiliate can potentially harm captive customers. For 

example, if a market-regulated power sales utility had knowledge of its affiliated 

franchised public utility’s prior costs of purchasing power, it could use this information 

to outbid a competitor in a request for proposals to supply power to the franchised public 

utility. We note, however, that the restriction on sharing market information, whether 

past, present, or future, does not apply to information that is publicly available.348

D. Mitigation

1. Cost-Based Rate Methodology

a. Selecting the Particular Units that Form the Basis of the 

“Up To” Rate 

Final Rule

260. Where a seller adopts the default cost-based mid-term rate or otherwise proposes a 

cost-based rate designed on the unit or units expected to run, the Final Rule continues to 

allow the seller flexibility in proposing the particular units that form the basis of the “up 

to” rate. The Commission determines whether such proposals are just and reasonable on 

a case-by-case basis. The Final Rule also reiterated that any seller proposing an 

alternative mitigation methodology carries the burden of justifying its proposal.349

 348 Order No. 697 at P 592. To use an example cited by Ameren, once past sales 

information is filed with the Commission in an EQR, such information would not be 

covered by the information disclosure prohibition. 

349 Id. P 649. 
Docket No. RM04-7-001 -167- 

Requests for Rehearing 

261. TDU Systems and NRECA suggest that allowing sellers to choose the unit or units 

expected to run can affect the “up to” default rate for mid-term sales, and also skew the 

default incremental cost rate for short-term sales.350 TDU Systems351 and NRECA352

claim that the Final Rule failed to adopt measures to ensure that the mitigated rates of 

large public utilities reflect their actual cost of service. TDU Systems and NRECA 

submit that the Commission should adopt more stringent controls over sellers’ discretion 

in establishing cost-based rates for mid-term sales in markets where a seller has been 

found, or is presumed, to have market power.353 NRECA reiterates a proposal made in 

its comments to the NOPR that, for mid-term sales, the Commission should enforce a 

matching or consistency principle: the same generating units should be used as the basis 

for the fixed and variable costs in determining the default embedded-cost rate.354 

NRECA asserts that a matching or consistency principle would help to ensure that a 

mitigated seller cannot mix high-fixed-cost units with high-variable-cost units to 

 350 NRECA Rehearing Request at 25; TDU Systems Rehearing Request at 9. 

351 TDU Systems Rehearing Request at 4 (citing K N Energy, Inc. v. FERC, 

968 F.2d 1295, 1303 (D.C. Cir. 1991)). 

352 NRECA Rehearing Request at 3 (citing N. States Power Co. v. FERC, 30 F.3d 

177, 181-82 (D.C. Cir. 1994); 5 U.S.C. 706(2)(A), (C)). 

353 TDU Systems Rehearing Request at 4 (citing American Mining Congress v. 

EPA, 907 F.2d 1179, 1187 (D.C. Cir. 1990)). 

354 Id. at 27 (citing N. States Power Co. v. FERC, 30 F.3d 177, 181-82 (D.C. Cir. 

1994)); see also TDU Systems Rehearing Request at 26-27. 
Docket No. RM04-7-001 -168- 

artificially inflate the embedded-cost rate. At the same time, NRECA adds that if a seller 

can show that a portfolio of generating units is likely to be used to provide service, then 

the seller might be permitted to use a weighted average of the fixed and variable costs of 

the portfolio. 

262. NRECA also proposes that the Commission require public utilities, in addition to 

justifying their mitigated rates prior to the rate becoming effective, to also file ex post

quarterly reports of the actual sales and the actual incremental or embedded costs 

incurred in making sales for terms of one year or less. Such mitigated cost-based rate 

sales, NRECA reasons, would be subject to a cost-based formula rate, and thus subject to 

refund. In NRECA’s view, providing for a case-by-case review of proposed cost-based 

rates prior to implementation of the rates does not address concerns that arise after the 

mitigated cost-based rates become effective.355 

263. NRECA contends that it is inconsistent with the FPA356 to place the burden on 

customers to file a complaint pursuant to section 206357 in order to ensure that the 

mitigated rates are just and reasonable in the first instance. Moreover, NRECA claims 

 355 Id. at 25-26. 

356 Id. at 26 (citing Mun. Light Bds. v. FPC, 450 F.2d 1341, 1348 (D.C. Cir. 

1971)). 

357 Id. (citing 16 U.S.C. 824e). 
Docket No. RM04-7-001 -169- 

that because any rate relief would be prospective from the date of the complaint,358 this 

would allow unjust and unreasonable rates to be charged until a complaint is filed.359 

Commission Determination

264. On the issue of selecting the particular units that form the basis of the “up to” rate 

for mitigated mid-term sales, we will continue to apply our current methodology. TDU 

Systems and NRECA are concerned that the Final Rule failed to adopt measures to 

ensure that proposed mitigated rates for sales of less than one year reflect the mitigated 

sellers’ actual cost of service. These entities assert that imposing a matching or 

consistency principle on mitigated sellers’ proposed cost-based rate methodologies would 

help to prevent mitigated sellers from mixing high fixed-cost units with high variablecost units that could artificially inflate the mitigated seller’s embedded cost rate. We find 

that the Commission’s current methodology allows mitigated sellers reasonable 

discretion to propose units to use in determining a cost-based rate while at the same time 

requiring any such proposal to be cost-justified and approved by the Commission. This 

balancing of a seller’s right under the FPA to propose rates with the obligation to costjustify such rates to the Commission provides the Commission adequate oversight to 

ensure that rates remain just and reasonable, and to prevent the mitigated seller from 

artificially inflating its cost-based rates. Once a seller files proposed rates, they are 

noticed for comment, and interested parties may file requests to intervene and comments. 

 358 Id. (citing 16 U.S.C. 824e(b)). 

359 Id. at 27 (citing Arkla v. Hall, 453 U.S. 571, 582 (1981)). 
Docket No. RM04-7-001 -170- 

If there are issues of material fact as to the proposed rates, such issues may be set for 

hearing. The Commission reviews the mitigated seller’s proposed rates, including a 

stacking analysis to determine the seller’s generation unit(s) likely to provide the 

service.360 In addition, the Commission analyzes the cost-justifications for the proposed 

rates to determine if the proposed rates meet the just and reasonable standard. As such, 

while a mitigated seller has the discretion to propose its choice of units, the 

Commission’s process of reviewing the rate resulting from a seller’s proposal ensures 

that such sellers do not have “excessive leeway” in proposing a cost-based rate, despite 

NRECA’s claim to the contrary. 

265. NRECA argues that placing the burden on customers to file a section 206 

complaint to ensure mitigated rates are just and reasonable in the first instance is 

inconsistent with the FPA. Rather than placing a burden on customers to ensure just and 

reasonable rates, the Commission first requires the mitigated seller to cost-justify any 

proposed cost-based rates. To wit, the mitigated seller may propose cost-based rates for 

 360 A stacking analysis is performed in order to determine the fixed costs 

associated with the generating units likely to participate in off-system sales, where the 

related energy is priced based on incremental costs. The first portion of the analysis is 

the stacking of the generating units where data is recorded from each unit in the order of 

increasing Fuel O&M cost per kWh (lowest to highest). Power for off-system sales will 

only be provided after the utility has met its firm native load. The analysis assumes that 

the native load approximates the company’s annual peak (in other words, any unit needed 

to serve the utility’s minimum annual peak will not be available for off-system sales). 

The next part of the analysis is to determine which units will participate in the off-system 

sale. This part of the analysis can be a judgmental process. First, one eliminates those 

units that are uneconomical to make the sale. Next, one selects those units that are 

(1) usually stacked just above the peak and (2) have fuel costs that are economical to 

make the off-system sale. 
Docket No. RM04-7-001 -171- 

Commission review; however, the seller does not have authorization to charge such rates 

until the Commission acts on the seller’s proposal. Thus, the Commission’s process does 

ensure that a mitigated seller’s rates are just and reasonable in the first instance. To the 

extent that a mitigated seller’s cost of providing the service decreases, the Commission’s 

long-standing practice is to consider claims of over-recovery in complaint proceedings.361 

Moreover, beyond proposing its matching principle, NRECA has failed to explain how 

adding this requirement would improve our current mitigation methodology. NRECA 

also provides no justification for treating mitigated sellers using a cost-based rate 

differently than any other cost-based rate sellers. 

266. NRECA also complains that without a reporting procedure for mid-term sales 

requiring ex-post filings of quarterly reports of actual sales and costs incurred, the 

Commission cannot ensure that the default cost-based rates for mitigated mid-term sales 

reflect the actual cost of service and are just and reasonable.362 However, as the 

Commission determined in Order No. 697, when a mitigated seller proposes cost-based 

mitigation, such an entity is obligated to comply with the Commission’s accounting and 

 361 Allegheny Power System Operating Cos., 111 FERC ¶ 61,308, at P 46 (2005) 

(“if a concern arises regarding over-recovery of transmission costs, such parties are free 

to seek relief by filing a complaint ... pursuant to section 206 of the FPA.”); Michigan 

Wolverine Power Supply Coop., Inc., 99 FERC ¶ 61,326 (2002). 

362 We note that while public utilities are required to file electric quarterly reports 

detailing transaction information, including price, for all market-based and cost-based 

power sales, such reports do not contain ex-post details of individual cost components. 
Docket No. RM04-7-001 -172- 

reporting regulations, found in Parts 41, 101 and 141363 of the Commission’s 

regulations.364 As the Commission explained, these requirements are imposed in order to 

maintain adequate financial information with regard to mitigated sellers so that the 

Commission can exercise its duties and responsibilities under the FPA to ensure that rates 

remain just and reasonable and not unduly discriminatory or preferential.365 The 

Commission and customers and competitors can rely on these financial forms to evaluate 

the adequacy of existing cost-based rates.366 The Commission expects that customers’ 

access to this data will allow them to demonstrate if rates have become unjust and 

unreasonable.367

 363 Part 41 pertains to adjustments of accounts and reports; Part 101 contains the 

Uniform System of Accounts for public utilities and licensees; Part 141 describes 

required forms and reports. Section 301(a) of the FPA authorizes the Commission to 

prescribe rules and regulations concerning accounts, records and memoranda as 

necessary or appropriate for the purposes of administering the FPA. 

364 Order No. 697 at P 986, 992. 

365 Id. P 993 

366 See, e.g., Quarterly Financial Reporting and Revisions to the Annual Reports, 

Order No. 646, FERC Stats. & Regs. ¶ 31,158, at P 16-17, order on reh’g, Order No. 646-

A, FERC Stats. & Regs. ¶ 31,163 (2004). 

367 See Houlton Water Company, 55 FERC ¶ 61,037 (1991) (dismissing complaint 

where customers failed to present prima facie case of excessive rates and noting that they 

had access to utility’s Form No. 1 data, among other data, and could prepare cost study 

on that basis). 
Docket No. RM04-7-001 -173- 

b. Sales of One Year or Greater

Final Rule 

267. The Final Rule retained the existing default mitigation policy for sales of one year 

or more (long-term). Specifically, the Commission determined that it will continue to 

require mitigated sellers to price long-term sales on an embedded cost of service basis 

and to file each such contract with the Commission for review and approval prior to the 

commencement of service.368 We note that our mitigation in this regard is prospective 

and does not impact any existing long-term contracts. 

268. Furthermore, the Final Rule retained the existing generation market power 

analyses (renamed to be a horizontal market power analysis) with minor changes and 

dismissed the request that the Commission consider different product analyses for shortand long-term products.369 Instead, the Final Rule retained the existing mitigation where 

a failure to rebut the presumption of short-term market power results in the mitigation of 

both a seller’s short-term and long-term sales. 

Requests for Rehearing

269. Long-Term Sellers (LT Sellers),370 Ameren, Southern, EEI, and OG&E take 

positions, in whole or in part, that the Commission erred in the Final Rule by adopting a 

 368 Id. P 659 (citing April 14 Order, 107 FERC ¶ 61,018 at P 151, 155). 

369 Id. P 122. 

370 LT Sellers include Public Service Company of New Mexico, Duke Energy 

Corporation, E.ON U.S., Progress Energy, Inc. (filing on behalf of its subsidiaries), 

Oklahoma Gas and Electric Company, PacifiCorp, Tucson Electric Power Company, 

Arizona Public Service Company, and Pinnacle West Marketing & Trading Co., LLC. 
Docket No. RM04-7-001 -174- 

policy that (1) generically mitigates long-term transactions based on a finding of market 

power under the Commission’s horizontal market power analyses which focuses on 

short-term markets; (2) fails to recognize that absent entry barriers, long-term capacity 

markets are inherently competitive; and (3) does not account for previously recognized 

distinctions between short-term and long-term transactions.371 Some assert that 

mitigation of long-term transactions is inconsistent with the Commission's finding in 

Order No. 697 that long-term markets are presumptively competitive, could reduce 

competition and raise prices in long-term markets, and have the effect of discouraging 

long-term transactions and investment, which the Commission has encouraged.372 They 

seek clarification and/or rehearing of this policy. 

270. They put forth the following arguments and rationale in support of their requests, 

and offer specific options for the Commission to consider in terms of relief. Southern 

states that, according to the Final Rule, the indicative screens are only “snapshots in 

time,” utilize only short-term data inputs focusing only on existing capacity holdings and 

consider only historical energy markets; thus, they cannot provide any reasonable 

information regarding supply and demand conditions in future markets. Southern and 

OG&E argue that the Commission should abandon the indicative screens and the DPT as 

 371 Southern Rehearing Request at 26 (citing Wholesale Competition in Regions

with Organized Electric Markets, Advance Notice of Proposed Rulemaking, FERC Stats. 

& Regs. ¶ 32,617, at P 85 (2007), and Energy Policy Act of 2005, Pub. L. No. 109-58, 

119 Stat. 594 (2005), sec. 1253). 

372 Ameren Rehearing Request at 9; LT Sellers Rehearing Request at 3, 10. See 

also EEI Rehearing Request at 11; OG&E Rehearing Request at 11. 
Docket No. RM04-7-001 -175- 

bases for mitigation measures in long-term markets and that a more appropriate analysis 

for determining whether market power exists in long-term markets is whether potential 

suppliers are barred from entering the market.373 LT Sellers, Southern, and EEI argue 

that the analysis of long-run market power should consider vertical market power.374 EEI 

offers that, absent barriers to entry and vertical market power, buyers in long-term 

markets have competitive alternatives, including the option to build new generation or to 

enter long-term transactions for third parties to do so, that will preclude sellers from 

exercising market power. EEI requests that the Commission clarify that it will consider 

the ability of a seller to exercise vertical market power or to erect other barriers to entry, 

rather than horizontal market power, in determining whether sellers may enter long-term 

transactions at market-based rates.375 

271. In terms of specific ways the Commission may address the issue of long-run 

market power, LT Sellers ask the Commission to find that the Final Rule allows sellers 

who fail one or both indicative screens to file a separate tariff for long-term capacity and 

energy sales at market-based rates, and that such a tariff would be accepted if that seller 

satisfies the Commission’s vertical market power analysis, which addresses the relevant 

issues regarding long-term sales: transmission market power and barriers to entry.376 

 373 Southern Rehearing Request at 27-28; OG&E Rehearing Request at 10. 

374 LT Sellers Rehearing Request at 10; Southern Rehearing Request at 28; and 

EEI Rehearing Request at 5, 10-11. 

375 EEI Rehearing Request at 10-11. See also Ameren Rehearing Request at 10. 

376 Id. at 21. 
Docket No. RM04-7-001 -176- 

According to LT Sellers, such tariffs could be limited by their terms to contracts of 

sufficient duration and that begin sufficiently far into the future to ensure that selfbuilding or new construction by others is a viable option and, thus, that the threat of new 

entry disciplines the prices under the contracts subject to the tariff.377 

272. LT Sellers recognize that there will be circumstances in which a tariff for longterm sales at market-based rates may not be appropriate for a particular seller. Therefore, 

LT Sellers contend that the Commission should establish several safe harbors for factual 

circumstances in which the Commission can take comfort in the lack of long-term market 

power such that a seller can file stand-alone long-term contracts with the Commission 

under a rebuttable presumption that the contract rate is just and reasonable.378 For 

example, LT Sellers suggest that a safe harbor would be appropriate where a seller 

demonstrates that its buyer conducted an Allegheny-type request for proposals, or where 

it conducted an informal procurement and provides sufficient evidence that the contract 

was not the result of any market power. 

273. Southern, Ameren, OG&E, and EEI similarly request that the Commission clarify 

that even if a seller’s blanket market-based rate authority is revoked, the seller may still 

seek Commission approval of long term market-based rate contracts on an individual 

 377 Id. at 10-11. 

378 LT Sellers Rehearing Request at 11, 24-27. 
Docket No. RM04-7-001 -177- 

basis.379 Southern argues that this clarification is necessary and appropriate because the 

absence of blanket authorization to make market-based rate sales should not preclude a 

seller from entering into long-term, market-based rate transactions with individual buyers 

over whom the seller does not have market power. Southern also requests that the 

Commission clarify the standards that it would utilize in determining whether to approve 

individual long-term market-based rate contracts on a case-by-case basis. In this regard, 

Southern submits that for each such long-term transaction filed with the Commission for 

approval, there would be no presumption that the seller has market power over the 

applicable buyer. Instead, there would be a separate evaluation process that would 

consider the specific circumstances applicable to each particular transaction and buyer.380 

According to Southern, the Commission should consider establishing other exceptions to 

allow sellers without blanket market-based rate authority to transact on a long-term basis, 

and the Commission should undertake to identify the types of circumstances where 

market power concerns generally are not present, irrespective of whether a seller 

ultimately passes the Final Rule’s criteria for blanket authority.381

274. Several petitioners take a contrary view. APPA/TAPS and Montana Counsel, in 

whole or in part, are concerned that the Commission’s statement about the inherent 

 379 Southern Rehearing Request at 29-30; Ameren Rehearing Request at 10; 

OG&E Rehearing Request at 11. 

380 Southern Rehearing Request at 29. 

381 Id. at 30. 
Docket No. RM04-7-001 -178- 

competitiveness of long-term markets may invite public utilities to seek to avoid any 

examination of market power in long-term markets, even on a case-specific basis.382 

275. While Montana Counsel agrees that “[t]he markets for short-term energy 

purchases and long-term firm capacity supplies are undeniably distinct,” it states that the 

Commission should not assume that there can be no market power for long-term firm 

capacity supplies; instead, it should require market-based rate applicants to demonstrate 

that they do not possess market power in the long-term market.383 In particular, Montana 

Counsel argues that the Commission seems to assume that barriers to entry are the 

exception rather than the rule, and that generation will usually be built to counteract longterm market power. Montana Counsel argues that the Commission’s reliance on an 

academic hypothesis for its statement that “[a]s the Commission has stated in the past, 

absent entry barriers, long-term capacity markets are inherently competitive because new 

market entrants can build alternative generating supply” in support of a major policy is 

unsupported, arbitrary and capricious. Montana Counsel offers that at least one recent 

analysis of barriers to entry in generation markets weighs against the Commission’s 

assumption.384 

 382 APPA/TAPS Rehearing Request at 12-13. 

383 Id. at 7. 

384 Montana Counsel Rehearing Request at 4-5 (citing John M. Kelly, Power 

Plants Don’t Fly – and Other Non-Artificial Barriers to Competition in Wholesale Power 

Markets, 26th USAEE/IAEE North American Conference Plenary Session, (Sept. 25, 

2006)). 
Docket No. RM04-7-001 -179- 

276. Montana Counsel states that the presence in a market of a seller with market 

power can itself be a barrier to entry, especially if the market is isolated by transmission 

constraints; for example, any new entrant would face the risk of predatory pricing by the 

incumbent seller, and transmission constraints would prevent the newly-built generation 

from being “moved” to a more hospitable market. Montana Counsel states that if the 

Commission grants market-based rate authority to a seller based on a presumption that 

new generation can enter the market and that seller in fact has market power, it will be 

allowing unjust and unreasonable rates.385 

277. APPA/TAPS also challenge the Commission’s statement regarding the 

competitiveness of long-term markets, arguing that an examination of the evidence shows 

a lack of factual support for this conclusion.386 In addition, they assert that the scope of 

RTO/ISO mitigation is much narrower than the default, cost-based mitigation the 

Commission prescribes; they note that the Commission has stated that RTO/ISO 

 385 Montana Counsel Rehearing Request at 5 (citing FPA sections 205-206; Gulf 

States Utils. Co. v. FPC, 411 U.S. 747 (1973)). 

386 APPA/TAPS Rehearing Request at 6 (citing AEP Power Marketing, Inc., 

107 FERC ¶ 61,018 at P 155 (2004) (April 14 Order). APPA/TAPS also cites a study 

that concluded that investment was not occurring in high-priced LMP areas, which in 

theory should attract new entry. The study concluded “that the LMP price signals are 

overwhelmed by other factors in these areas, such as structural barriers to entry, 

competing economic incentives, and the lack of a clear mechanism for assuring return on 

investment in certain types of projects.” Synapse Energy Economics, Inc., LMP 

Electricity Markets: Market Operations, Market Power, and Value for Consumers, 

Executive Summary (Feb. 5, 2007) available at 

http://www.appanet.org/files/PDFs/SynapseLMPElectricityMarket 

ExecSumm013107.pdf (emphasis added by APPA/TAPS). 
Docket No. RM04-7-001 -180- 

mitigation and the market-based rate analysis are different and that “‘pieces of one should 

not automatically be used as precedent for the other.’”387 APPA/TAPS state that 

RTO/ISO mitigation measures apply only to spot markets and day-ahead and/or realtime, but do not apply to weekly, monthly or long-term transactions, including those 

negotiated on a bilateral basis, and that RTO/ISO mitigation is often far less protective 

than the Commission’s default cost-based rates. 

278. Montana Counsel states that the Commission should consider evidence on the 

subject of barriers to entry in generation markets in this rulemaking, and in individual 

proceedings it should require sellers seeking market-based rate authority to present data 

on current generation markets from which the Commission can develop a factual record 

on which it can base a reasoned decision.388 Montana Counsel argues that the burden of 

demonstrating the existence of barriers to entry should not be on intervenors; rather the 

burden should be on the seller seeking the privilege of market-based rate authority to 

demonstrate the absence of barriers to entry, i.e., the existence of a competitive market 

for long-term power supply. 

Commission Determination

279. As discussed below, we will grant rehearing in part and modify our policy 

regarding the mitigation of long-term sales. The Commission has long held that long-

 387 APPA/TAPS Rehearing Request at 24 (citing Midwest Independent 

Transmission System Operator, Inc., 109 FERC ¶ 61,157, at P 242 (2004), order on 

reh’g, 111 FERC ¶ 61,043 (2005). 

388 Id. at 5 (citing 5 U.S.C. 706(2); Motor Vehicle Mfrs. Ass’n v. State Farm Mut.

(continued...) 
Docket No. RM04-7-001 -181- 

term markets may be presumed to be competitive, absent barriers to entry, and has taken 

actions within its authority to eliminate barriers to entry.389 Even if a seller is found to 

have market power in the short-term, that market power can be mitigated or eliminated 

by the meaningful opportunity for other sellers to enter the market in order to compete 

with the seller and drive down prices.390 Given adequate time, notice, and the absence of 

entry barriers, proposals for new infrastructure will emerge in response to price signals. 

Sellers and buyers will have an opportunity to plan and respond, as their needs dictate. 

Whether there is a meaningful opportunity for entry and when that opportunity is 

expected to occur may vary depending on such factors as the type or size of resource 

 

Auto. Ins. Co., 463 U.S. 29 (1983)). 

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

Public Utilities and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), 

FERC Stats. & Regs. ¶ 31,036, order on reh’g, Order No. 888-A, FERC Stats. & Regs. 

¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, 

Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission 

Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New 

York v. FERC, 535 U.S. 1 (2002); Standardization of Generator Interconnection 

Agreements and Procedures, Order No. 2003, FERC Stats. & Regs. ¶ 31,146 (2003) order 

on reh’g, Order No. 2003-A, FERC Stats. & Regs. ¶31,160, order on reh’g, Order No. 

2003-B, FERC Stats. & Regs. ¶ 31,171 (2004), order on reh’g, Order No. 2003-C, FERC 

Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom. Nat’l Ass’n of Regulatory Util. Comm’rs 

v. FERC, 475 F.3d 1277 (D.C. Cir. 2007); Regulation of Natural Gas Pipelines after 

Partial Wellhead Decontrol, Order No. 436, FERC Stats. & Regs. ¶ 30,665 (1985); 

Preventing Undue Discrimination and Preference in Transmission Service, Order No. 

890, 72 Fed. Reg. 12,266 (Mar. 15, 2007), FERC Stats. & Regs. ¶ 31,241, order on reh’g, 

Order No. 890-A, 73 Fed. Reg. 2984 (Jan. 16, 2008), FERC Stats. & Regs. ¶ 31,261 

(2007). 

390 See, e.g., W. Kip Viscusi, et al., Economics of Regulation and Antitrust 153-

55, (MIT Press 2000) (1992). 
Docket No. RM04-7-001 -182- 

needed (e.g., system, peaking), whether multiple resources are needed (e.g., transmission 

and generation), and siting and permitting considerations. 

280. In this regard, we agree with some of the concerns raised by petitioners and will 

allow sellers to demonstrate on a case-by-case basis that they do not have market power 

with respect to long-term contracts. We have considered the arguments raised by LT 

Sellers, Ameren, Southern, EEI and OG&E that the Commission erred in the Final Rule 

by adopting a policy that in all circumstances mitigates long-term sales based on a 

finding of market power under the Commission’s horizontal market power analyses. We 

agree that the indicative screens and the DPT only examine the presence of market power 

in the short-term; the Final Rule did not alter the indicative screens or the DPT to allow 

different product analyses for short-term or long-term power. In response to Southern’s 

assertion that the short-term analyses cannot provide any reasonable information 

regarding supply and demand conditions in future markets, we find that historical data, 

while perhaps an imperfect fit with regard to analyzing market power in forward markets 

and not to be relied on solely, does provide some indication as to the seller’s ability to 

exercise market power. This notwithstanding, we believe that there is merit to 

petitioners’ claims regarding the differences between long- and short-term markets, and 

the potential impact of the Final Rule on long-term contracting. As such, we grant 

clarifications and rehearing as discussed herein. Our decision to do so ensures just and 

reasonable rates while not impeding long-term contracting. To this end, and as discussed 

below, we are not, as Montana Counsel argues, simply relying on an unsupported 

hypothesis that entry will occur and discipline these markets to ensure just and reasonable 
Docket No. RM04-7-001 -183- 

rates. Rather, we will assess the facts and record presented with each individual section 

205 application. 

281. Accordingly, we grant rehearing in part and provide that any seller who fails the 

Commission’s market-based rate test or surrenders market-based rate authority (referred 

to herein as “mitigated sellers”) may file with the Commission under FPA section 205, on 

a case-by-case basis, a request for contract-specific market-based rates based on a 

demonstration that the seller does not have market power with respect to the specific 

long-term contract being filed. The Commission will not in this rulemaking promulgate 

tariffs of general applicability or provide generic safe harbors for long-term sales. As 

petitioners note, the market-based rate program focuses on short-term markets. The 

record before us is not sufficient to justify a generic market-based rate tariff for long-term 

sales or to create a “safe harbor” for such transactions. 

282. Therefore, on a case-by-case basis, the mitigated seller must show that a buyer 

under a long-term contract has viable alternatives including the entry of an appropriate 

amount of third-party newly-constructed resources during the relevant future period as an 

alternative to purchasing under the contract at issue. In order to make the relevant 

showing, the seller would have to show that its proposed contract is of a sufficiently long 

duration and provides for service to commence sufficiently far into the future, such that 

other sellers had a reasonable opportunity to enter the market; and that a buyer had other 

viable, comparable alternatives, which could include self-build options and third-party 

new construction. This builds upon the LT Sellers’ proposal (albeit in the context of a 

tariff) that such contracts “could be limited by their terms to contracts of sufficient 
Docket No. RM04-7-001 -184- 

duration and that begin sufficiently far into the future to ensure that self-building or new 

construction by others is a viable option and, thus, that the threat of new entry disciplines 

the prices under the contracts subject to the tariff.”391 At this time we are not imposing 

any specific requirements on the evidence that the mitigated sellers must submit with 

their application. Nevertheless, we observe that mitigated sellers who identify a specific 

buyer for a proposed contract will be better able to provide the Commission with an 

understanding of the viable and comparable alternatives that the particular buyer may 

have. 

283. The fact that the Commission will review all of these contracts under section 205 

of the FPA and provide notice and opportunity for comment addresses Montana 

Counsel’s concern that the Commission would rely on an academic hypothesis of entry 

without regard to the justness and reasonableness of rates. Sellers bear the burden in an 

FPA section 205 proceeding to demonstrate that rates are just and reasonable.392 We 

have also addressed Montana Counsel’s concern that we have placed the burden of 

proving barriers to entry on the intervenor. As stated above, the seller has the burden to 

show that its rates are just and reasonable and is required to make the requisite showing. 

The Commission will carefully examine the evidence that will be presented, and we will 

deny authority to charge a market-based rate for a long-term contract when the mitigated 

seller cannot meet its evidentiary burden. Intervenors are therefore in the position of 

 391 LT Sellers Rehearing Request at 11. 

392 18 CFR 35.3(a). 
Docket No. RM04-7-001 -185- 

rebutting this evidence; they do not carry the initial (or ultimate) burden of proof. 

Moreover, in any application for market-based rate authority, the seller has the burden to 

make the requisite disclosures regarding inputs to electric power production, describing 

its ownership of, control over, or affiliation with entities that own or control such 

facilities, as well as make an affirmative statement regarding whether it has erected 

barriers to entry in the relevant market and committing not to erect such barriers in the 

future. As noted in the Final Rule, “we are not preventing intervenors from raising other 

barriers to entry concerns for consideration on a case-by-case basis.”393

284. We do not share the concern espoused in Montana Counsel’s example of predatory 

pricing by the incumbent seller. Predatory pricing occurs when a firm sets prices below 

the competitive level in order to drive competitors out of business, then, once competitors 

exit the market, uses its market power to drive the price above the competitive level. The 

economic theory of predatory pricing requires both the ability and incentive to do so. In 

Montana Counsel’s example, if the mitigated firm did sell below the competitive price 

and drive out the competitors, it could not use its market power to raise the price at that 

time because it would be mitigated by the Commission to a cost-justified rate. In other 

words, such a strategy would be self-defeating because once competitors exit a particular 

market the remaining firm would no longer pass the indicative market power screens, and 

this would lead to its transactions being mitigated. Therefore, while a mitigated firm 

could, in theory, set prices below the competitive level to minimize or eliminate 

 393 Order No. 697 at P 449. 
Docket No. RM04-7-001 -186- 

competitors, the Commission’s mitigation policy creates an economic disincentive to do 

so, which erodes Montana Counsel’s theory of economic harm. 

285. With regard to APPA/TAPS’ suggestion that the scope of RTO/ISO mitigation is 

much narrower than the Commission’s default cost-based mitigation, we do not believe 

that such a distinction should require that cost-based mitigation be imposed on long-term 

contracts entered into by sellers with market power in RTO/ISO markets. In RTO/ISOs, 

buyers have access to centralized, bid-based short-term markets which will discipline a 

seller’s attempt to exercise market power in long-term contracts because the would-be 

buyer can always purchase from the short-term market if a seller tries to charge an 

excessive price. The RTO/ISOs have Commission-approved market mitigation rules that 

govern behavior and pricing in those short-term markets. Further, the RTO/ISOs have 

Commission-approved market monitoring, where there is continual oversight to identify 

market manipulation. 

c. Alternative Methods of Mitigation

Final Rule

286. The Commission determined that it will address on a case-by-case basis whether 

the use of an agreement that is not tied to the cost of any particular seller but rather to a 

group of sellers is an appropriate mitigation measure.394 

287. Specifically, the Final Rule concluded that use of the Western Systems Power 

Pool Agreement (WSPP Agreement) as a mitigation measure may be unjust, 

 394 Id. P 667. 
Docket No. RM04-7-001 -187- 

unreasonable or unduly discriminatory or preferential for certain sellers. The 

Commission instituted in Docket No. EL07-69-000 a proceeding under section 206 of the 

FPA to investigate whether the WSPP Agreement ceiling rate is just and reasonable for a 

public utility seller in a market in which such seller has been found to have market power 

or is presumed to have market power.395 

288. The Final Rule noted that the Commission had previously accepted the use of the 

WSPP Agreement ceiling rate as mitigation by a number of sellers. The Final Rule 

allowed the sellers to continue to use the WSPP Agreement ceiling rate as mitigation, 

subject to refund (as of the refund effective date established in Docket No. EL07-69-000) 

and subject to the outcome of the section 206 proceeding.396 

289. The Commission issued an order in the section 206 proceeding on February 21, 

2008, determining that the WSPP Agreement’s demand charge ceiling rate is no longer 

just and reasonable for use by public utility sellers in the market in which the sellers do 

not have market-based rate authority, unless such sellers can cost-justify the rate.397 The 

Commission found that in markets in which a seller has or is presumed to have market 

power it is unjust and unreasonable to allow such a seller to continue to use the WSPPwide “up-to” demand charge as a ceiling rate unless the seller can justify the costs of that 

charge based on its own costs. 

 395 Id.

396 Id. P 673-74. 

397 Western Systems Power Pool, 122 FERC ¶ 61,139 (2008). 
Docket No. RM04-7-001 -188- 

290. The Final Rule continued to permit alternative methods of mitigation to be costbased. However, while the Commission did not allow the use of alternative “marketbased” mitigation on a generic basis, the Commission held that it will permit sellers to 

submit alternative non-cost-based mitigation proposals for Commission consideration on 

a case-by-case basis.398

Requests for Rehearing

291. No entities sought rehearing regarding use of the WSPP Agreement to mitigate 

market power. APPA/TAPS request clarification that the Commission will entertain 

proposals for structural mitigation as a condition of the privilege of market-based rate 

authority in specific, future cases.399 APPA/TAPS argue that the Commission, on the one 

hand, approves structural measures to mitigate horizontal market power, such as the 

transfer of existing generation to third parties but, on the other hand, declares that 

structural conditions, such as joint planning and construction of new generation, are too 

burdensome.400 Where the Commission can impose conditions on an applicant’s marketbased rate authority, APPA/TAPS support structural mitigation as a potential condition, 

and urge the Commission to identify, in specific cases, structural conditions that would 

 398 Order No. 697 at P 693. 

399 APPA/TAPS Rehearing Request at 22 (citing California Indep. Sys. Operator 

Corp. v. FERC, 372 F.3d 395 (D.C. Cir. 2004)). 

400 Id.
Docket No. RM04-7-001 -189- 

allow applicants to obtain market-based rate authority rather than be limited to cost-based 

mitigation.401 

Commission Determination

292. As the April 14 Order and Final Rule both explained, “[p]roposals for alternative 

mitigation ... could include cost-based rates or other mitigation that the Commission may 

deem appropriate.”402 While APPA/TAPS complain that the Final Rule suggested some 

structural measures are too burdensome, in fact the Commission only determined that 

entities advocating structural mitigation as a condition on market-based rate authorization 

had not justified imposing such a burden on a generic basis. Rather than foreclosing the 

possibility of structural measures, the Commission will continue to permit sellers to 

submit non-cost-based mitigation proposals, including those involving structural 

measures, for Commission consideration on a case-by-case basis based on their particular 

circumstances.

293. APPA/TAPS also request that the Commission identify in specific cases structural 

conditions that will enable applicants to obtain market-based rate authority, as an 

alternative to ordering cost-based mitigation. The Commission believes that, because 

mitigation proposals are evaluated upon the particular facts and circumstances of 

individual proceedings, it would be premature to identify or list specific structural 

 401 APPA/TAPS Rehearing Request at 22-23 (citing California Indep. Sys. 

Operator Corp. v. FERC, 372 F.3d 395 (D.C. Cir. 2004)). 

402 April 14 Order, 107 FERC ¶ 61,018 at n.142; see also, Order No. 697 at n.46 

and P 698. 
Docket No. RM04-7-001 -190- 

measures on a generic basis. Further, it has been the Commission’s practice to allow 

sellers to propose mitigation to address market power concerns rather than the 

Commission imposing specific mitigation on mitigated sellers. 

2. Protecting Markets With Mitigated Sellers

a. Must Offer

Final Rule

294. In the Final Rule, the Commission determined not to impose an across-the-board 

“must offer” requirement for mitigated sellers, explaining that there was insufficient 

record evidence to support instituting a generic “must offer” requirement, as had been 

proposed by several commenters. While commenters proposed several methods for 

implementing a must offer requirement,403 the intent of these proposals was to preclude 

the mitigated seller from selling its available capacity in markets where it retains marketbased rate authority without first requiring the mitigated seller to offer available capacity 

in the balancing authority area in which it is mitigated. The Commission found that 

although wholesale customer commenters raised theoretical concerns that they would be 

unable to access power absent a “must offer” requirement, they did not provide any 

concrete examples of harm nor did they explain how the potential harm justified the 

generic remedy they sought.404 The Commission also found that there are potential 

 403 See, e.g., id. P 732. 

404 Id. P 759-60. 
Docket No. RM04-7-001 -191- 

remedies available on a case-by-case basis to a wholesale customer alleging undue 

discrimination or other unlawful behavior on the part of a mitigated seller.405 

295. While the Commission did not impose a generic “must offer” requirement in the 

Final Rule, the Commission did not rule out the possibility of finding that the imposition 

of a “must offer” requirement, or some other condition on the seller’s market-based rate 

authority, would be an appropriate remedy in a particular case, depending on the facts 

and circumstances, as the Commission has done in the past.406 

296. For many of the same reasons that the Commission declined to impose a generic 

“must offer” requirement, the Commission also declined to adopt a “right of first refusal” 

as proposed by NRECA, whereby captive customers would have the right of first refusal 

to purchase at a market price energy or capacity that the mitigated seller proposes to sell 

outside of the balancing authority area in which it is mitigated. The Commission 

determined that there was insufficient record evidence to support imposition of such an 

across-the-board requirement.407

Requests for Rehearing

297. APPA/TAPS and NRECA request that the Commission clarify that the Final Rule 

does not pre-judge the circumstances in which a must offer condition may be necessary 

and appropriate to remedy undue discrimination or ensure that rates are just and 

 405 Id. P 763. 

406 Id. P 764. 

407 Id. P 771. 
Docket No. RM04-7-001 -192- 

reasonable.408 APPA/TAPS state that the Commission appropriately ties a must offer 

condition to the need for a remedy to ensure that wholesale rates are just, reasonable and 

not unduly discriminatory, but objects that the Commission seems to be limiting any must 

offer condition or similar remedy only to cases involving OATT violations.409

298. NRECA states that one member of the Commission expressed uncertainty about 

whether a “must offer” requirement would be appropriate absent a showing that “the 

mitigated seller is the only entity physically able to meet all of the buyer’s needs.”410

NRECA requests that the Commission clarify that it has not pre-determined that it will 

set the bar for a must offer requirement to the standard of total monopoly because it is 

inconsistent with the standards adopted in the Final Rule. 

299. NRECA argues that if a public utility seller is subject to mitigation in its home 

balancing authority area, the seller either has a dominant market share, its generation is 

critical for meeting peak-period demand, or both. In such cases, NRECA contends that 

the withholding of the seller’s generation in its home balancing authority area could have 

 408 APPA/TAPS Rehearing Request at 4, 19 (citing Transmission Access Policy 

Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000)); NRECA Rehearing Request at 

29. 

409 APPA/TAPS Rehearing Request at 4. Additionally, APPA/TAPS disagrees 

with the characterization of its position as urging a “generic remedy” in the Final Rule. 

APPA/TAPS argues that it was careful to specify that the market power concerns posed 

by the particular market-based rate applicant would determine when a must offer 

condition would be appropriate. APPA/TAPS therefore states that it does not view the 

Final Rule as a rejection of its position. Id. at 18. 

410 NRECA Rehearing Request at 30 (citing Open Meeting Tr. at 61 (June 21, 

2007)).
Docket No. RM04-7-001 -193- 

a profound effect on the ability of a captive wholesale customer to provide electricity at a 

reasonable price.411 NRECA further argues that if a total-monopoly standard were 

applied, a customer would not be entitled to relief so long as it could find another entity 

able to sell power to it. But, if that single alternative supplier had market power in the 

absence of competition from the “mitigated” seller, then the customer would be forced to 

buy that alternative supplier’s power at monopoly prices, and the supposedly “mitigated” 

seller would be let off the hook. If that single alternative supplier were also subject to 

mitigation, then it too might choose to sell all of its power outside the balancing authority 

area, leaving the customer with no power at any price, contrary to FPA obligations.412

300. NRECA further argues that there is no clear guidance on who would have the 

burden of proof either to demonstrate that a must offer requirement or some alternative 

remedy is necessary or unnecessary, but that the Final Rule suggests that the customer 

 411 Id. at 31. NRECA also states that “[t]he Commission allows wholesale 

contracts executed or filed after July 9, 1996, to terminate by their own terms without 

prior notice to and approval by the Commission. Thus, a captive wholesale customer 

with a ‘new’ long-term contract may have no regulatory assurance of continued service 

even in a control area where the seller has generation market power.” NRECA at n.94 

(citing 18 CFR 35.15(b)).

412 Id. at 31 (citing 16 U.S.C. 824a(a) (authorizing Commission actions for 

‘assuring an abundant supply of electric energy throughout the United States with the 

greatest possibly economy’); 16 U.S.C. 824d(a) (requiring all rates to be just and 

reasonable); Energy Policy Act of 2005, section 1233, 119 Stat. 594, 957 (2005) (adding 

section 217 to FPA, to be codified at 16 U.S.C. 824q, to ensure long-term transmission 

rights to load-serving entities); Am. Gas Ass’n v. FERC, 912 F.2d 1496, 1516-18 (D.C. 

Cir. 1990) (remanding FERC’s pre-granted abandonment rule for failing to address the 

“protection of customers from pipeline exercise of monopoly power through refusal of 

service at the end of a contract period”)).
Docket No. RM04-7-001 -194- 

would have the burden to prove such a remedy is necessary.413 NRECA argues that the 

seller should bear the burden of proof in a particular case to demonstrate that this 

requirement or an alternative remedy is unnecessary.414 

301. TDU Systems also argue that the Final Rule’s determination not to impose an 

across-the-board “must offer” requirement for mitigated sellers leaves the Commission 

without any effective measures to assure that the granting of market-based rate authority 

in competitive markets will not make things worse in adjacent uncompetitive markets415

and asserts that the Commission should reconsider the narrow range of mitigation 

measures it will employ in the first instance and include must offer conditions, annual 

open seasons, and rights of first refusal.416 TDU Systems argue that the Commission's 

vague statement that it could consider such remedies in particular cases is not 

sufficient.417 TDU Systems argue that if the Commission does not embrace a “must 

offer” requirement, regulations should list it as an option418 because National Fuel419

 413 Id. at 30. 

414 Id. at 4 (citing Farmers Union Cent. Exch. v. FERC, 734 F.2d at 1510; NAACP 

v. FPC, 520 F.2d 432, 438 (D.C. Cir. 1975); 5 U.S.C. 556(d); 5 U.S.C. 706(2)(A), (C); 

16 U.S.C. 824d(e)); NRECA Rehearing Request at 30 (citing 5 U.S.C. 556(d); 16 U.S.C. 

824d(e)).

415 Id. at 4 (citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d 1486, 1510 

(D.C. Cir. 1984)). 

416 Id. at 8-9. 

417 Id. at 9, 22. 

418 Id. at 25. 
Docket No. RM04-7-001 -195- 

does not hold that the Commission must always determine that existing remedies and 

procedures are inadequate before it adopts any new regulation.420 

302. Additionally, TDU Systems argue that if the Commission declines to impose a 

“must offer” requirement, it should, upon a finding of market power in a seller’s home 

balancing authority area, deny market-based rate authorization in first-tier markets.421 

The immediate concern is the effects upon the public utility’s continuing obligations to 

provide service at conventionally regulated rates in markets where it has market 

power.

422 

303. TDU Systems argue that it may be appropriate to impose upon sellers the initial 

burden of coming forward with the proposed remedy.423 TDU Systems argue that the 

regulations should state that the Commission will look favorably upon a public utility’s 

proposal to mitigate market power by entering into an enforceable commitment to 

provide additional transmission capacity.424 

 419 Id. at 23 (citing National Fuel Gas Supply Corp. v. FERC, 468 F.3d 831 (D.C. 

Cir. 2006)).

420 Id. at 23-24. 

421 Id. at 9, 26. 

422 Id. at 24. 

423 Id. at 25. 

424 Id. at 26. 
Docket No. RM04-7-001 -196- 

304. Finally, TDU Systems argue that the Commission has been aware that relying 

upon the rights of individual customers to file complaints after the fact is often not 

enough to assure overall achievement of FPA mandates.425 

Commission Determination

305. In response to issues raised by APPA/TAPS and NRECA, we clarify that we have 

not pre-judged the types of specific situations in which we might impose a “must offer” 

requirement on a particular seller. 

306. With respect to which party bears the burden of proof regarding a “must offer” 

requirement, we cannot make that determination in the abstract. The public utility seller 

has the burden under section 205 to demonstrate that its mitigation proposal is just, 

reasonable and not unduly discriminatory. Circumstances in which a must-offer 

requirement warrants consideration cannot be determined in advance, as we made clear in 

the Final Rule. If the public utility seller can meet its burden of showing that its 

mitigation proposal is just and reasonable without a must-offer requirement, however, 

then the burden would be on the challenging party to show that more is required. 

307. TDU Systems continue to advocate the need for the Commission to impose an 

across-the-board “must offer” requirement on mitigated sellers; however, they do not 

provide evidence supporting such a requirement. For example, they have not provided 

evidence of a widespread and pervasive situation where customers were unable to access 

power due to a mitigated seller’s business decision to sell its power outside of the 

 425 Id. at 25. 
Docket No. RM04-7-001 -197- 

balancing authority area in which the seller has been found, or presumed, to have market 

power. Absent such compelling evidence, we will not impose an across-the-board “must 

offer” requirement. As discussed in the following section, we also reject TDU Systems’ 

request that the Commission, upon a finding of market power in a seller’s balancing 

authority area, deny market-based rate authorization in first-tier markets. 

308. We also reject TDU Systems’ argument that the Commission list “must offer” in 

its regulations as a mitigation option. Section 35.38 of the Commission’s regulations 

provides that a mitigated seller “may adopt the default mitigation... or may propose 

mitigation tailored to its own particular circumstances to eliminate its ability to exercise 

market power.”426 We find that defining in the regulations the mitigation options that are 

available to all sellers provides sufficient regulatory certainty and we decline to provide a 

list of possible remedies that may not be applicable to all sellers. To do otherwise would 

introduce needless regulatory uncertainty. 

309. TDU Systems argue that it may not be sufficient to rely on a customer’s right to 

file a complaint. However, customers are not limited to filing a complaint. At the time 

that a seller proposes mitigation, a customer has the opportunity to make its case 

regarding concerns it may have with respect to its ability to access power if the seller is 

mitigated in the balancing authority area. The Commission fully considers comments 

made by intervenors and, on a case-specific basis, if the facts and circumstances 

 426 18 CFR 35.38(a). 
Docket No. RM04-7-001 -198- 

demonstrate a “must offer” provision is needed to mitigate market power, the 

Commission may impose such a remedy. 

b. First-Tier Markets

Final Rule

310. In the Final Rule, the Commission retained its policy to limit mitigation to the 

balancing authority area in which a seller is found, or presumed, to have market power. 

The Commission did not place limitations on a mitigated seller’s ability to sell at marketbased rates in balancing authority areas in which the seller has not been found to have 

market power.427 

Requests for Rehearing

311. APPA/TAPS request the Commission to clarify that, while it sees no basis as part 

of the current proceeding to revoke an applicant’s market-based rate authority beyond the 

balancing authority areas in which the applicant has been found to have (or has accepted 

the presumption of) market power, it is not ruling out broader remedies where required to 

mitigate the applicant’s market power in a specific case.428

312. APPA/TAPS assert that they did not urge that widespread revocation of marketbased rate authority beyond the home balancing authority area occur on a generic basis, 

but rather, that the Commission not narrowly circumscribe its own remedial authority in a 

specific case where mitigation of a particular seller’s market power may require 

 427 Order No. 697 at P 790. 

428 APPA/TAPS Rehearing Request at 4 (citing Niagara Mohawk Power Corp. v. 

FPC, 379 F.2d 153 (D.C. Cir. 1967)).
Docket No. RM04-7-001 -199- 

revocation of its market-based rate authority beyond its home balancing authority area.429 

APPA/TAPS argue that the Commission’s statement that comments “favoring revocation 

of a mitigated seller’s market-based rate authority in markets where there has been no 

finding of market power, as well as those supporting broadening mitigation to first-tier 

markets, have not provided a sufficient legal basis for such a policy,”430 could be used 

against the Commission when it seeks to broaden the scope of mitigation in that future 

case where a more expansive remedy is factually and legally justified.431 

Commission Determination

313. The Commission allows market-based rate sales of energy and capacity in all 

balancing authority areas where the seller has been granted market-based rate authority. 

As the Commission explained in the Final Rule, “[w]e generally agree that it is desirable 

to allow market-based rate sales into markets where the seller has not been found to have 

market power.”432

314. With regard to APPA/TAPS’ concern that the Commission should not narrowly 

circumscribe its own remedial authority in a specific case where mitigation of a particular 

seller’s market power may require revocation of its market-based rate authority beyond 

 429 Id. at 20. 

430 Order No. 697 at P 791. 

431 Id. at 4, 20-21. 

432 Id. P 819. 
Docket No. RM04-7-001 -200- 

its home balancing authority area, we clarify that the Commission neither has nor will 

foreclose its authority to remedy market power. 

c. Sales that Sink in Markets Without Mitigated Sellers

Final Rule

315. In the Final Rule, the Commission continued to apply mitigation to all sales in the 

balancing authority area in which a seller is found, or presumed, to have market power.433 

However, the Commission allowed mitigated sellers to make market-based rate sales at 

the metered boundary between a balancing authority area in which a seller is found, or 

presumed, to have market power and a balancing authority area in which the seller has 

market-based rate authority, under certain circumstances.434

316. The Final Rule determined that allowing market-based rate sales by a seller that 

has been found to have market power, or has so conceded, in the very balancing authority 

area in which market power is a concern, is inconsistent with the Commission’s 

responsibility under the FPA to ensure that rates are just and reasonable and not unduly 

discriminatory.435 

 433 Although the Commission used the term “mitigated market” in Order No. 697, 

the Commission later determined that “balancing authority area in which a seller is found, 

or presumed, to have market power” is a more accurate way to describe the area in which 

a seller is mitigated. Clarification Order, 121 FERC ¶ 61,260, at P 7 & n.10. 

434 Order No. 697 at P 817 (citing North American Electric Reliability 

Corporation. Glossary of Terms Used in Reliability Standards at 2 (2007), available at 

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Glossary_02May07.pdf). 

435 Order No. 697 at P 819. 
Docket No. RM04-7-001 -201- 

Requests for Rehearing

317. OG&E complains that the Commission erred by barring utilities from selling 

power within a balancing authority area in which a seller is found, or presumed, to have 

market power where the buyer’s load sinks in a non-mitigated balancing authority 

area.436 OG&E claims that the Final Rule mistakenly assumes that the point of sale is 

relevant to the market power analysis rather than the location of the load.437 OG&E 

states that the Final Rule acknowledges that buyers taking title to power “at a metered 

boundary for delivery to serve load in a balancing authority where the seller has marketbased rate authority have competitive choices and therefore are not required to transact 

with the seller found to have market power within the mitigated balancing authority 

area(s).”438 OG&E suggests that this reasoning applies with equal force to a transaction 

where the buyer chooses to buy power at the seller's generator bus for load that is located 

in a balancing authority area where the seller has market-based rate authority because 

such a buyer also has competitive choices. OG&E argues that these choices are not 

reduced by the location at which title to the energy is transferred.439 

318. OG&E also claims that the Commission’s mitigation policy harms competition 

and consumers by undermining the ability of a mitigated company to compete in other 

 436 OG&E Rehearing Request at 3. 

437 Id. at 4-5. 

438 Order No. 697 at P 820. 

439 OG&E Rehearing Request at 5. 
Docket No. RM04-7-001 -202- 

markets within an RTO where that seller does not have market power.440 OG&E asserts 

that if a power purchaser located in a non-mitigated market within an RTO already takes 

network transmission service under an OATT and that purchaser solicits power supply 

bids based on the premise that the purchaser will arrange and pay for any necessary 

transmission service, then potential suppliers not subject to mitigation will bid on a 

"power only" basis. In contrast, a mitigated supplier’s bid would include the cost of 

transmission service to take the power to the metered boundary of the control area where 

the seller is mitigated. OG&E complains that in such an instance, the transmission 

service is not needed because the purchaser would prefer to use its existing network 

service - priced on the basis of load - to arrange for transmission. OG&E contends that 

the added transmission costs imposed on a mitigated supplier in such a scenario would 

undermine the competitiveness of a mitigated supplier’s bid, thereby reducing the 

competitive options available to the purchaser. OG&E contends that the Commission’s 

policy, because it can result in additional transmission costs for a mitigated supplier as 

described above, imposes a pancaked rate structure on mitigated suppliers, which 

undermines an essential benefit associated with RTO participation. This, OG&E 

complains, is inconsistent with the Commission’s goal of eliminating pancaked rates by 

establishing RTOs, and will interfere with the development and efficiency of competitive 

wholesale markets.441 OG&E adds that the Final Rule provides no justification for a 

 440 Id.

441 Id. at 6. 
Docket No. RM04-7-001 -203- 

policy under which a mitigated supplier may incur the cost of transmission service to take 

the power to the metered boundary of the control area when it seeks to sell power to a 

potential customer located in another non-mitigated balancing authority area within an 

RTO. These effects are even greater, OG&E asserts, because the Commission has 

approved other utilities' mitigation proposals that allow them to sell power at their 

generator bus so long as that power sinks in another balancing authority area. OG&E 

argues that those tariffs remain in full force and effect after Order No. 697. Like these 

sellers, OG&E should be permitted to compete on an equal basis to serve customers 

whose loads sink outside OG&E’s mitigated balancing authority area.442

319. OG&E argues that the Final Rule fails to acknowledge that the Commission’s new 

mitigation policy departs from prior policy.443 OG&E asserts that in several recent cases 

where sellers failed the market share screens in their balancing authority area, the 

Commission imposed mitigation prohibiting the seller from making sales to “loads that 

sink” in that balancing authority area.444 While the Commission later rejected this 

language, OG&E contends that it never has explained this change in position.445 When 

 442 Id. at 6-7. 

443 Id. at 7. 

444 Id. at 2 (citing Duke Power, 113 FERC ¶ 61,192 (2005); AEP Power 

Marketing, Inc., 114 FERC ¶ 61,025 (2006); LG&E Energy Marketing Inc., 113 FERC 

¶ 61,229 (2005); South Carolina Electric and Gas Co., 114 FERC ¶ 61,143 (2006); 

Florida Power Corp., 113 FERC ¶ 61,131 (2005)). 

445 Id. (citing Order No. 697 at P 794; MidAmerican Energy Co., 114 FERC 

¶ 61,280 (2006); Carolina Power & Light Co., 114 FERC ¶ 61,294 (2006); Aquila, Inc., 

(continued...) 
Docket No. RM04-7-001 -204- 

the Commission departs from established policy without explanation, as OG&E claims it 

did here, it acts arbitrarily and fails to engage in the reasoned decision making required 

by the law.446

Commission Determination

320. OG&E complains that the Commission erred by barring utilities from selling 

power within a balancing authority area in which a seller is found, or presumed, to have 

market power when the buyer’s load sinks in a non-mitigated balancing authority area. 

As noted in the Final Rule, another commenter similarly asserted that any buyer 

purchasing power at a generator bus or elsewhere in a balancing authority area in which a 

seller is found, or presumed, to have market power for purposes of moving that power 

beyond that mitigated balancing authority area should be treated no differently than a 

buyer who takes delivery of purchased power outside of that balancing authority area. 

OG&E, like earlier commenters advocating this approach, has failed to adequately 

address how the Commission could effectively monitor such sales to ensure that improper 

sales are not being made in the balancing authority area in which a seller is found, or 

presumed, to have market power. As the Commission stated in the Final Rule, several 

commenters noted the complex administrative problems that would be associated with 

trying to monitor compliance with such a policy.447 

 

114 FERC ¶ 61,281 (2006)). 

446 Id. at 8. 

447 Order No. 697 at P 818. 
Docket No. RM04-7-001 -205- 

321. Moreover, as the Commission explained in the Final Rule, allowing market-based 

rate sales by a seller found to have market power, or has so conceded, in the very 

balancing authority area in which market power is a concern is inconsistent with the 

Commission’s responsibility under the FPA to ensure that rates are just and reasonable 

and not unduly discriminatory. While we generally agree that it is desirable to allow 

market-based rate sales into balancing authority areas where the seller has not been found 

to have market power, a mitigated seller cannot make market-based rate sales anywhere 

within a balancing authority area in which a seller is found, or presumed, to have market 

power. It is unrealistic to believe that sales made anywhere in a balancing authority area 

can be traced to ensure that no improper sales are taking place. In contrast, sales made at 

the metered boundary for export do more readily lend themselves to being monitored for 

compliance, and the nature of these types of sales do not unduly disadvantage customers 

or competitors. Prohibiting market-based rate sales at the metered boundaries of a 

balancing authority area in which a seller is found, or presumed, to have market power 

could prevent or adversely impact cross border sales at these unique locations and reduce 

market liquidity unnecessarily in markets where the seller does not possess market 

power. 

322. OG&E also claims that not allowing sales at the generator bus undermines the 

ability of a mitigated company to compete in other markets within an RTO where that 

seller does not have market power. For example, if a mitigated seller attempts to transact 

with a purchaser willing to use the purchaser’s existing network transmission service, 

OG&E asserts that a mitigated seller’s ability to compete is undermined. OG&E claims 
Docket No. RM04-7-001 -206- 

that because a mitigated seller must incur transmission costs to deliver the power in the 

above scenario to the metered boundary rather than simply to a generator bus in the 

balancing authority area in which a seller is found, or presumed, to have market power, 

the mitigated seller would be unable to bid on a “power only” basis and would be forced 

to pay an additional transmission cost that is redundant due to the purchaser’s ability to 

use its network service if the mitigated seller could sell at the generator bus. This, OG&E 

suggests, not only undermines that mitigated seller’s ability to compete beyond the 

mitigated balancing authority area, but also would reduce the competitive options 

available to the buyer. 

323. OG&E’s concern regarding mitigation undermining a seller’s ability to compete 

fails to appreciate that mitigated sellers are prohibited from making sales at a generator 

bus in that particular balancing authority area because they have been shown to have, or 

conceded, market power in that market area. Mitigated sellers lose the privilege of 

market-based rate sales at generator bus locations within a balancing authority area in 

which a seller is found, or presumed, to have market power. Unlike sales at the 

generator bus bar, sales made at the metered boundary for export do lend themselves to 

being monitored for compliance, and these sales do not unduly disadvantage customers or 

competitors. 

324. OG&E also claims that its ability to compete is undermined because the 

Commission approved several tariffs that permit a mitigated entity to sell power at their 

generator bus so long as that power sinks beyond the balancing authority area in which a 

seller is found, or presumed, to have market power. However, a recent Commission 
Docket No. RM04-7-001 -207- 

order explained that such tariffs are inconsistent with the Commission’s policy as set 

forth in Order No. 697, as of the effective date of Order No. 697 (September 18, 2007).448 

In that order, the Commission explained that its acceptance of a mitigation proposal and 

tariff provisions that focused on sales that did not sink within the balancing authority area 

in which the seller was found, or presumed, to have market power was inconsistent with 

the April 14 and July 8 Orders and, therefore, in error.449 Moreover, the Commission’s 

recent order clarifying the Final Rule explained that sales made after September 18, 2007 

must be in compliance with the requirements of Order No. 697.450 Because a mitigated 

entity is precluded from limiting its mitigation to sales that sink in the balancing authority 

area in which it is found, or presumed to have, market power, all mitigated sellers are 

now on the same footing with regard to their ability to serve customers whose loads sink 

outside mitigated balancing authority areas. 

d. Tariff Language

Final Rule

325. In the Final Rule, the Commission adopted a requirement that mitigated sellers 

wishing to make market-based rate sales at the metered boundary between a balancing 

authority area in which the seller was found, or presumed, to have market power and a 

balancing authority area in which the seller has market-based rate authority maintain 

 448 See South Carolina Electric and Gas Company, 121 FERC ¶ 61,263 at P 12 

(2007). 

449 Id.

450 Clarification Order, 121 FERC ¶ 61,260 at P 4-8. 
Docket No. RM04-7-001 -208- 

sufficient documentation and use a specific tariff provision for such sales.451 In 

particular, the Final Rule requires that mitigated sellers that want to make market-based 

rate sales at the metered boundary adopt the following tariff provision: 

Sales of energy and capacity are permissible under this tariff in all 

balancing authority areas where the Seller has been granted market-based 

rate authority. Sales of energy and capacity under this tariff are also 

permissible at the metered boundary between the Seller’s mitigated 

balancing authority area and a balancing authority area where the Seller has 

been granted market-based rate authority provided: (i) legal title of the 

power sold transfers at the metered boundary of the balancing authority 

area where the seller has market-based rate authority; (ii) any power sold 

hereunder is not intended to serve load in the seller’s mitigated market; and 

(iii) no affiliate of the mitigated seller will sell the same power back into 

the mitigated seller’s mitigated market. Seller must retain, for a period of 

five years from the date of the sale, all data and information related to the 

sale that demonstrates compliance with items (i), (ii), and (iii) above. 

Requests for Rehearing 

326. Pinnacle requests clarification of the provision’s requirement that “any power sold 

is not intended to serve load in the seller’s mitigated market.” As written, Pinnacle 

argues that this requirement could limit liquidity, particularly for term sales transactions, 

in the market trading hubs.452 For example, Pinnacle states that it transacts at several 

liquid points in the Western markets such as Four Corners, which is at the border of the 

APS balancing authority area. Pinnacle explains that although it can assess its intent for 

the destination of power purchased at the border point, it does not have control over the 

 451 Order No. 697 at P 830. 

452 Pinnacle Rehearing Request at 4. Although Pinnacle does not provide a 

definition for “term sale,” we understand their use of that phrase to refer to a sale that is 

neither executed nor tagged immediately, and whose sink location is unknown at the time 

of the sale. 
Docket No. RM04-7-001 -209- 

intent of third parties purchasing the power. Further, Pinnacle asserts that it is unlikely 

that counterparties at liquid market hubs would agree to contractual limitations on where 

power can sink for term transactions.453 Pinnacle adds that the Commission has not 

placed any limits on the time at which intent is determined. For example, if a buyer 

intends to sink the power outside of the market in which the seller has or is presumed to 

have market power at the time of purchase, but at the time of delivery determines that it 

must liquidate its positions and sell power back into that market, the Final Rule is unclear 

whether the mitigated seller may be liable for this sale into the market in which it has 

market power. Pinnacle argues that without the clarification on intent, mitigated sellers 

may be limited to cost-based sales at the border. Pinnacle requests the Commission 

clarify that intent is only directed at the determination of the mitigated seller. 

327. If the Commission does not so clarify, Pinnacle requests on rehearing that the 

Commission revise the second requirement in the tariff provision to state: “(ii) the seller 

does not intend for any power sold to serve load in the seller’s mitigated market.” 

Pinnacle claims that this revision will provide greater regulatory certainty. 

328. Morgan Stanley similarly is unclear on how the Commission will ensure that a 

mitigated seller knows what an unaffiliated buyer intends to do with power. It adds that a 

restriction forbidding unaffiliated buyers from purchasing power at the metered boundary 

from a mitigated seller and then selling the same power back into a balancing authority 

area in which the seller was found, or presumed, to have market power would be 

 453 Id. at 5. 
Docket No. RM04-7-001 -210- 

burdensome because every sale would have to be tracked.454 Morgan Stanley therefore 

requests the Commission to clarify that buyers unaffiliated with a mitigated seller may 

purchase power at the metered boundary to sell to customers that serve load in the 

mitigated seller’s balancing authority area. It argues that if restrictions are imposed on 

unaffiliated buyers’ purchases at the metered boundary, the Commission should explain 

or, in the alternative, grant rehearing.455 

329. Pinnacle is further concerned about the metered boundary tariff provision’s 

requirement that mitigated sellers commit to and demonstrate that “no affiliate of the 

mitigated seller will sell the same power back into the mitigated seller’s mitigated 

market.” Pinnacle submits that it might generally have immediate documentation to meet 

the above requirement for real-time transactions because the NERC tag (that notes the 

sink point for the power) will be made upon the execution of a real-time transaction. 

However, in the context of a term sale, Pinnacle explains that NERC tags are generally 

created not at the time of the transaction, but rather the last scheduling day prior to the 

start of the sale. The result, Pinnacle submits, is that no immediate documentation is 

created to show that the mitigated seller intended to sink the sale outside of the mitigated 

market where a term sale followed by a “coincidental sale”456 that results in power 

 454 Morgan Stanley Rehearing Request at 3. 

455 Id. at 2-3. 

456 Pinnacle describes a “coincidental sale” as the situation where, after a mitigated 

seller makes a term sale to an unaffiliated counter-party at the metered boundary, an 

affiliate of the mitigated seller enters into an unrelated transaction to buy that same power 

(continued...) 
Docket No. RM04-7-001 -211- 

returning to the balancing authority area in which the seller has been found, or presumed, 

to have market power. Pinnacle therefore seeks clarification, or in the alternative 

rehearing, on whether the requirement that a mitigated seller commit to and demonstrate 

that “no affiliate of the mitigated seller will sell the same power back into the mitigated 

seller’s mitigated market” applies in the following scenario: A mitigated seller sells a 

term product to an unaffiliated counterparty at the metered boundary for delivery 

sometime in the future. Thereafter, an affiliated seller purchases the power in a 

coincidental sale and, despite any lack of arrangement, the affiliate of the mitigated seller 

then re-sells that power to the balancing authority area in which the mitigated seller has 

been found, or presumed, to have market power.457 If the unaffiliated counterparty does 

not advise the affiliate of the mitigated seller that the unaffiliated counterparty is selling 

to the affiliate of the mitigated seller the same power that the unaffiliated counterparty 

originally purchased from the mitigated seller, Pinnacle claims that it will only become 

apparent that the mitigated seller is sourcing the transaction between the unaffiliated 

counterparty and the affiliate of the mitigated seller when the NERC tags are prepared.458 

330. Pinnacle also seeks clarification, or in the alternative rehearing, as to the types of 

documentation that the Commission requires to show the intent of the seller, and 

particularly whether the Commission would consider audio tapes of transactions to be 

 

from the unaffiliated counterparty. 

457 Pinnacle Rehearing Request at 7-8. 

458 Id. 
Docket No. RM04-7-001 -212- 

sufficient. Pinnacle states that, generally, representative documentation for real-time 

trading is created. For a term sale, however, a representative tag is not created at the time 

of the transaction but rather around the last scheduling prior to the start of the sale. 

Therefore, when a term sale is involved, no immediate tag at the time of contracting is 

created that can be evidenced as intent to sink the sale outside of the market in which the 

seller has market power. 

331. Pinnacle also requests clarification that the physical point of the metered boundary 

is the mitigated seller’s side of the electrical boundary, and does not include points at the 

border that are in an adjacent balancing authority area.459 If the Commission does not 

provide the requested clarification, Pinnacle requests rehearing of this requirement. 

Pinnacle argues that, as currently written, the tariff language on metered boundaries does 

not provide the regulatory certainty necessary to accurately implement the 

requirements.460 

332. OG&E complains that the Final Rule’s new mitigation policy is improperly based 

on the assumption that utilities will violate their tariffs despite the fact that such a 

purposeful circumvention of a company’s mitigation tariff would subject the violator to 

the risk of substantial civil penalties. Moreover, OG&E adds that such conduct also 

could violate the Commission’s Market Manipulation Rule.461 OG&E points out that, in 

 459 Pinnacle Rehearing Request at 8. 

460 Id. at 8-9. 

461 OG&E Rehearing Request at 9. 
Docket No. RM04-7-001 -213- 

the Final Rule, the Commission rejected fears of gaming because such conduct would 

violate its existing rules.462 OG&E asserts that the same logic applies to the 

Commission’s concerns that a seller might violate its market-based rate tariff to 

purposefully make sales to a customer whose load sinks in the balancing authority area in 

which that seller was found, or presumed, to have market power. OG&E argues that, 

where a particular set of actions already are prohibited by the Commission’s rules, the 

Commission cannot impose new requirements unless it first finds that the existing rules 

are ineffective.463

Commission Determination 

333. As an initial matter, we will revise the tariff language governing market-based 

sales at the metered boundary to conform with the discussion in the Clarification Order 

regarding use of the term “mitigated market.” As we explained in the Clarification 

Order, we believe that “balancing authority area in which a seller is found, or presumed, 

to have market power” is a more accurate way to describe the area in which a seller is 

mitigated. 

334. After considering comments raised regarding the difficulty of determining and 

documenting intent, we have decided to eliminate the intent element of the tariff 

provision, which states that “any power sold hereunder is not intended to serve load in the 

seller’s mitigated market.” As we are eliminating the seller’s intent requirement, we will 

 462 Id. at 10. 

463 Id.
Docket No. RM04-7-001 -214- 

modify the other tariff provision to require that “the mitigated seller and its affiliates do 

not sell the same power back into the balancing authority area where the seller is 

mitigated.”464 Because we are eliminating the intent requirement, we need not address 

issues raised regarding documentation necessary to demonstrate the mitigated seller’s 

intent. 

335. Pinnacle also asks whether a mitigated seller would be liable if an affiliate 

purchases power from an unaffiliated intermediate party, then arranges to re-sell that 

power back into the mitigated seller’s balancing authority area, and it is subsequently 

discovered, when the NERC tags are prepared, that the mitigated seller was the initial 

source of that power via a term sale with the unaffiliated intermediate party. Under these 

circumstances, the mitigated seller would have violated its market-based rate tariff. 

Whether or not prearranged by affiliates, a series of transactions involving what Pinnacle 

describes as a “coincidental sale” that may result in an affiliate re-selling power back into 

the balancing authority area in which the seller has been found, or presumed, to have 

market power are prohibited by Order No. 697. This is because mitigated sellers and 

their affiliates are prohibited from selling power at market-based rates in the balancing 

authority area in which a seller is found, or presumed, to have market power. 

Accordingly, an affiliate of a mitigated seller is prohibited from selling power that was 

 464 To provide additional regulatory certainty for mitigated sellers, we clarify that 

once the power has been sold at the metered boundary at market-based rates, the 

mitigated seller and its affiliates may not sell that same power back into the mitigated 

balancing authority area, whether at cost-based or market-based rates. 
Docket No. RM04-7-001 -215- 

purchased at a market-based rate at the metered boundary back into the balancing 

authority area in which the seller has been found, or presumed, to have market power. 

336. To the extent that the mitigated seller or its affiliates believe that it is not practical 

to track such power, they can either choose to make no market-based rate sales at the 

metered boundary or limit such sales to sales to end users of the power, thereby 

eliminating the danger that they will violate their tariff by re-selling the power back into a 

balancing authority in which they are mitigated. 

337. We also clarify that when using the term “metered boundary,” the Commission 

intends that applicable mitigation applies to sales made at the metered boundary 

regardless of at which “side” of the border the sale takes place. We adopt this approach 

as a concession to mitigated sellers that wish to make sales that may technically take 

place in a balancing authority area where they do not have market-based rate authority. 

However, in adopting this approach we do not intend to do so with such precision that we 

are drawn into evidentiary hearings on this matter, which could result in long drawn out 

contractual disputes to determine the precise spot at which the sale took place. We 

further deny Pinnacle’s request for rehearing to seek a precise definition of “metered 

boundary” because we believe, with the clarification provided herein, the existing tariff 

language on metered boundaries does provide the regulatory certainty necessary to 

accurately implement Order No. 697’s requirements.

338. We disagree with OG&E’s contention that our policy is based on the assumption 

that utilities will purposely violate their tariffs. We make no such assumption; however, 

it would not be sensible for us to establish conditions that we are unable to monitor for 
Docket No. RM04-7-001 -216- 

compliance. Sales at the metered boundary are unique physical locations that lie on the 

borders of balancing authority areas, and we believe that we can monitor compliance for 

sales at the metered boundary more effectively than sales made anywhere within the 

balancing authority area. As explained above, such limitation is justified by the 

Commission’s need to monitor compliance with its conditions on sales within the 

balancing authority area in which the seller is mitigated. 

339. Consistent with the preceding discussion, we will revise the tariff provision for 

market-based rate sales at the metered boundary as follows (bold font indicates new text): 

Sales of energy and capacity are permissible under this tariff in all 

balancing authority areas where the Seller has been granted market-based 

rate authority. Sales of energy and capacity under this tariff are also 

permissible at the metered boundary between the Seller’s mitigated 

balancing authority area and a balancing authority area where the Seller has 

been granted market-based rate authority provided: (i) legal title of the 

power sold transfers at the metered boundary of the balancing authority 

area where the seller has market-based rate authority; and (ii) the Seller 

and its affiliates do not sell the same power back into the balancing 

authority area where the seller is mitigated. Seller must retain, for a 

period of five years from the date of the sale, all data and information 

related to the sale that demonstrates compliance with items (i) and (ii) 

above. 

340. Any sellers that have already adopted the tariff language prescribed in Order No. 

697 are directed to revise the provision in accordance with this discussion on the next 

occasion when they otherwise would be required to file revised tariff sheets with the 

Commission, a change in status filing, or triennial review. 
Docket No. RM04-7-001 -217- 

E. Implementation Process

Final Rule

341. In Order No. 697, the Commission created a category of market-based rate sellers 

(Category 1 sellers) that are exempt from the requirement to automatically submit 

updated market power analyses. These Category 1 sellers include “wholesale power 

marketers and wholesale power producers that own or control 500 MW or less of 

generation in aggregate per region; that do not own, operate or control transmission 

facilities other than limited equipment necessary to connect individual generating 

facilities to the transmission grid (or have been granted waiver of the requirements of 

Order No. 888); that are not affiliated with anyone that owns, operates or controls 

transmission facilities in the same region as the seller’s generation assets; that are not 

affiliated with a franchised public utility in the same region as the seller’s generation 

assets; and that do not raise other vertical market power issues.”465 Market power 

concerns for Category 1 sellers will be monitored through the change in status reporting 

requirement466 and through ongoing monitoring by the Commission’s Office of 

Enforcement. Category 2 sellers (all sellers that do not qualify for Category 1) will be 

required to file regularly scheduled updated market power analyses in addition to change 

in status reports. 

 465 18 CFR 35.36(a)(2) (citations omitted). 

466 See 18 CFR 35.42. 
Docket No. RM04-7-001 -218- 

342. In addition, to ensure greater consistency in the data used to evaluate Category 2 

sellers, the Commission modified the timing for the submission of updated market power 

analyses.467 Order No. 697 requires analyses to be filed for each seller’s region on a predetermined schedule, rotating by geographic region where two regions are reviewed each 

year, with the cycle repeating every three years.468 This process allows evaluation of 

each individual seller’s market power at the same time that other sellers in the same 

region are examined. For corporate families that own or control generation in multiple 

regions, the corporate family will be required to file an update for each region in which 

members of the corporate family sell power during the time period specified for that 

region. 

1. Category 1 and 2 Sellers

a. Establishment of Category 1 and 2 Sellers

Requests for Rehearing

343. On rehearing, NASUCA argues that the exemption from market power review for 

Category 1 sellers lacks factual and legal justification. NASUCA contends that this 

exemption is inconsistent with the justifications the Commission has previously given to 

the courts. In particular, NASUCA argues that it is inconsistent with the Commission’s 

 467 Previously, updated market power analyses were submitted within three years 

of any order granting a seller market-based rate authority, and every three years 

thereafter. 

468 See Order No. 697 at Appendix D. The regions include the Northeast, 

Southeast, Central, Southwest Power Pool, Southwest, and Northwest. 
Docket No. RM04-7-001 -219- 

arguments before the court that it carefully assesses the market power of any entity 

allowed to sell at market-based rates.469 

344. NASUCA contends that in Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 2004) 

(Lockyer), the Ninth Circuit mistakenly believed that the market power assessment under 

current Commission orders is made triannually (i.e., once every four months) when it is 

only required triennially (once every three years).470 NASUCA believes that, because the 

Final Rule would completely eliminate the triennial review for many sellers in Category 

1, the basis for the decision in Lockyer, to the extent it is based on the Court’s belief that 

the Commission reviews the market power of all sellers four times a year, is undermined. 

NASUCA concludes that the blanket exemption from market power review of all sellers 

owning or controlling less than 500 MW capacity is inconsistent with the Commission’s 

stated rationale for allowing a market-based rate system. 

345. NASUCA also argues that the Commission has reversed the burden previously 

placed on applicants for the “privilege” of having market-based rates.471 NASUCA notes 

that the Final Rule states, “‘[w]hile it is true that a portion of these sellers will continue to 

sell at market-based rates for a time until their updated market power analyses (in the 

case of Category 2 sellers) or their filings addressing qualification as Category 1 sellers 

 469 NASUCA Rehearing Request at 12-13. 

470 Id. at 13. 

471 Id. at 13-14 (citing Schaffer v. Weast, 546 U.S. 49 (2005); Lavine v. Milne, 

424 U.S. 577, 585 (1976)). 
Docket No. RM04-7-001 -220- 

are due, no commenter has submitted compelling evidence that Category 1 sellers have 

unmitigated market power.’”472 NASUCA contends that Order No. 697 essentially 

granted all Category 1 sellers market-based rates without their submitting an application 

demonstrating a lack of market power, and required objectors to submit “compelling 

evidence” in a non-evidentiary proceeding. 

346. NASUCA argues that the Commission cannot presume that the market price 

demanded by all Category 1 sellers will be a “competitive” price or a just and reasonable 

rate.473 NASUCA states that the Supreme Court “rejected any conflation of 

‘competitive’ market price with the ‘just and reasonable’ rate required by statute.”474 

NASUCA contends that for Category 1 sellers, which it asserts are now exempt from any 

market power test, “the ‘prevailing price in the marketplace’ is indeed the ‘final’ measure 

of the rates being demanded, changed and charged,” a result contrary to the intent of 

Congress.475 

347. NASUCA also argues that there is no basis in the record of this proceeding to 

assume that power marketers or producers who own or control less than 500 MW of 

generation lack market power at all times.476 NASUCA notes that in load pockets or 

 472 Id. (quoting Order No. 697 at P 334) (emphasis added by NASUCA). 

473 Id. at 14. 

474 Id. (citing FPC v. Texaco, 417 U.S. at 397). 

475 Id. at 15 (quoting FPC v. Texaco, 417 U.S. at 397). 

476 Id.
Docket No. RM04-7-001 -221- 

other transmission-constrained areas, sellers with less than 500 MW of capacity could 

exercise market power, either alone or acting strategically without overt collusion to 

inflate rates when supply margins are tight. NASUCA states that changing circumstances 

also may affect the opportunity of seemingly small sellers to exercise market power. 

348. Additionally, NASUCA argues that, because the definition of seller includes not 

only owners of generating plants but also power marketers, this loophole might 

encourage power marketers to control segments of power plants up to 499.9 MW and 

through strategic bidding and other methods exercise subtle market power in certain 

locations at certain times.477 NASUCA states that, as a result of this exemption, sales 

from these facilities will be at prices solely determined by market forces, in contravention 

of FPC v. Texaco. NASUCA therefore concludes that if the Commission desires to 

identify a threshold below which a seller cannot exercise market power, it should 

commence a new proceeding, conduct technical workshops, gather evidence from the 

public and from RTO market monitors, and receive comments before adopting an 

evidence-based standard. 

Commission Determination

349. NASUCA’s argument on rehearing that the Commission did not adequately justify 

its decision to exempt Category 1 sellers from filing regularly scheduled updated market 

power analyses is misplaced. As we reiterate below, we thoroughly discussed the basis 

of our decision in Order No. 697, including that exempting Category 1 sellers is fully 

 477 Id. at 16. 
Docket No. RM04-7-001 -222- 

consistent with our statutory mandate to ensure just and reasonable rates and with the 

court decisions that have construed that obligation.478 Moreover, as discussed below, in a 

number of instances NASUCA does not accurately describe the exemption or our 

justification for it. 

350. With regard to NASUCA’s argument that exempting sellers from market power 

reviews undermines the court’s decision in Lockyer, we note that the Commission 

addressed this concern in Order No. 697. Specifically, the Commission stated that “the 

reporting requirement relied upon by the court in Lockyer is the transaction-specific data 

found in EQRs, which we continue to require of all sellers, and not the updated market 

power analyses. Thus, exempting Category 1 sellers from routinely filing updated market 

power analyses does not run counter to Lockyer.”479 The court in Lockyer emphasized 

that the Commission “has broad discretion to establish effective reporting requirements” 

for administering tariffs, and that the FPA “explicitly leaves the timing and form” of rate 

filings to the Commission’s discretion. 480

351. In any case, NASUCA fails to recognize that the Commission has not exempted 

Category 1 sellers from initial market power reviews. In addition, the Commission left in 

place the change in status reporting requirements that allow the Commission to review 

market power of sellers on an ongoing basis. Thus, we reject NASUCA’s contention that 

 478 Order No. 697 at P 848. 

479 Id. P 854. 

480 Lockyer, 383 F.3d 1006, 1013. 
Docket No. RM04-7-001 -223- 

this exemption is inconsistent with the justifications the Commission has previously 

given to the courts. 

352. We also reject NASUCA’s contention that the Commission has reversed the 

burden previously placed on applicants for the “privilege” of having market-based rates 

by not requiring Category 1 sellers to file regularly scheduled updated market power 

analyses. As an initial matter, NASUCA argues incorrectly that Order No. 697 

“essentially granted all Category 1 sellers market[-based] rates without their applying and 

demonstrating a lack of market power, and required objectors to submit ‘compelling 

evidence’ in a non-evidentiary proceeding.”481 Order No. 697 did not grant Category 1 

sellers market-based rate authority without requiring the submission of an application 

demonstrating a lack of market power. To the contrary, all sellers seeking market-based 

rate authorization (including sellers that qualify as Category 1 sellers) must initially 

demonstrate either a lack of market power or that any market power is adequately 

mitigated in order to obtain Commission market-based rate authorization.482 All such 

proceedings are noticed and allow for public comment. Any party to the proceeding has 

 481 NASUCA Rehearing Request at 14. 

482 A seller who previously was not required to demonstrate a lack of horizontal 

market power based on the exemption contained in 18 CFR 35.27(a) and that believes it 

qualifies as a Category 1 seller, will be required to provide support for its claim to 

Category 1 status. This filing will give the Commission and interested parties an 

opportunity to review and, if appropriate, challenge a seller’s claim that it qualifies as a 

Category 1 seller. To the extent that an intervenor has concerns about a seller’s potential 

to exercise market power, the Commission will entertain them at that time. Order 

No. 697 at P 333. 
Docket No. RM04-7-001 -224- 

an opportunity during these proceedings to argue that a seller has market power.483 

Although Category 1 sellers are not required to file regularly scheduled updated market 

power analyses, they retain the initial burden of proof to demonstrate that they do not 

have or have adequately mitigated market power in the first instance. In addition, 

Category 1 sellers continue to have the burden of informing the Commission of any 

change in the circumstances that the Commission relied on in granting them marketbased rate authority. 

353. Further, NASUCA takes the Commission’s statement regarding the submission of 

compelling evidence out of context. The passage that NASUCA quotes from the Final 

Rule (Order No. 697 at P 334) discusses the elimination of the exemption for new 

generation (formerly § 35.27(a) of the Commission’s regulations), and the lack of 

compelling evidence that the Commission referenced there related to commenters’ 

unpersuasive reasons for retaining the § 35.27(a) exemption.484 The Commission 

discussed the establishment of Category 1 and 2 sellers in a separate part of the Final 

 483 Additionally, if a seller’s circumstances change from those which the 

Commission reviewed and made a determination upon, it is required to inform the 

Commission in a change in status filing. 

484 The Commission was responding to NASUCA’s concern that sellers that 

initially received market-based rate authority without any generation market power 

assessment pursuant to 18 CFR 35.27(a) would, as Category 1 sellers, be exempted from 

filing update market power analyses. The Commission explained that it would rely on 

additional procedures, namely the change in status filing requirements (triggered by the 

acquisition of additional generation), EQR transaction filings, and the Commission’s 

ability to require an updated market power analysis from any seller at any time, to 

address NASUCA’s concern. 
Docket No. RM04-7-001 -225- 

Rule (Order No. 697 at P 848-62); the Commission nowhere intimated that Category 1 

sellers need not demonstrate that they lack market power. Accordingly, NASUCA’s 

contention is rejected in this regard. 

354. With respect to NASUCA’s assertion that there is no basis in the record to assume 

that power marketers or producers who own or control less than 500 MW of generation 

lack market power at all times, in Order No. 697 the Commission fully explained the 

rationale underlying the adoption of Category 1, as well as the rationale for adopting 500 

MW or less of generating capacity per region as the cutoff. The Commission explained 

that Category 1 sellers have been carefully defined to have attributes that are not likely to 

present market power concerns: ownership or control of relatively small amounts of 

generation capacity; no affiliation with an entity with a franchised service territory in the 

same region as the seller’s generation facility; little or no ownership or control of 

transmission facilities and no affiliation with an entity that owns or controls transmission 

in the same region as the seller’s generation facility; and no indication of an ability to 

exercise vertical market power. The Commission further explained that, based on a 

review of past Commission orders, it is aware of no entity that would have qualified as a 

Category 1 seller but would nevertheless have failed the indicative screens, necessitating 

a more thorough analysis.485 Furthermore, we believe that we have maintained an ample 

degree of monitoring and oversight to detect sellers that are not required to file regularly 

scheduled market power updates but nevertheless obtain enough additional generation as 

 485 See Order No. 697 at P 864. 
Docket No. RM04-7-001 -226- 

to raise market power concerns. This is so because we require all sellers seeking marketbased rate authority to conduct a market power analysis and, once market-based rate 

authority is obtained, to submit change in status filings when the circumstances on which 

the Commission has granted market-based rate authority have changed. In these filings, 

such sellers must report on what effect, if any, the additional generation has on their 

market power. In addition, the Commission reserves the right to require an updated 

market power analysis from any market-based rate seller at any time.486 Finally, all 

sellers with market-based rates, whether Category 1 or Category 2 sellers, must file 

electronically with the Commission an EQR of transactions no later than 30 days after the 

end of each reporting quarter. 

355. Nevertheless, in light of concerns raised regarding the potential for Category 1 

sellers to exercise market power in load pockets or other transmission-constrained areas, 

we will modify our approach when analyzing the indicative screens (e.g., as a result of 

regularly scheduled updated market power analyses). Specifically, to the extent that a 

Commission-identified submarket is under analysis, we will consider whether there is an 

indication that any sellers in that submarket, including Category 1 sellers, have market 

power. While we will not routinely require Category 1 sellers with generation assets in a 

submarket to submit a regularly scheduled updated market power analysis, when 

evaluating the market power analyses of Category 2 sellers, we will conduct our own 

analysis, based on publicly available information, of whether there are any market power 

 486 Id. P 853. 
Docket No. RM04-7-001 -227- 

concerns related to any Category 1 seller in a submarket. If, based on our analysis, we 

determine that there may be potential market power concerns with respect to any 

Category 1 sellers in a submarket, we will, if appropriate, require an updated market 

power analysis to be filed by such sellers. We will also notice such filings for public 

comment, thus allowing parties to raise concerns regarding market power for 

Commission consideration. 

356. Regarding concerns about the specific threshold chosen, when the Commission 

proposed in the NOPR the establishment of Category 1 and Category 2 sellers, the 

Commission proposed to define Category 1 sellers as power marketers and power 

producers that own or control 500 MW or less of generation capacity in aggregate, 

among other requirements. The Commission received a variety of comments concerning 

the proposed threshold. After careful review of these comments, the Commission 

concluded that 500 MW or less of generation capacity per region is an appropriate 

threshold. The Commission explained in Order No. 697 that the 500 MW threshold 

would be used as a cutoff because, during the Commission’s 15 years of experience 

administering the market-based rate program, there had only rarely been allegations that 

sellers with capacity of 500 MW or less (in any geographic region) had market power. 

The Commission noted that when those claims have been raised, the Commission’s 

review either found no evidence of market power or found that the market power 

identified was adequately mitigated by Commission-enforced market power mitigation. 

The Commission explained that, while some commenters urged it to adopt either a higher 

or lower threshold, the Commission believes that a 500 MW threshold is both a 
Docket No. RM04-7-001 -228- 

reasonable balance as well as conservative enough to ensure that those unlikely to 

possess market power will be granted market-based rate authority. Moreover, 500 MW is 

a clear, bright line that will be easy to administer. On this basis, we reject NASUCA’s 

suggestion that the Commission should commence a new proceeding, conduct technical 

workshops, gather evidence from the public and from RTO market monitors, and receive 

comments to further address the appropriate threshold. 

b. Threshold for Category 1 Sellers

Requests for Rehearing

357. On rehearing, PPM contends that Order No. 697 does not provide any explanation 

as to why Category 1 membership is based on the ownership or control of generation in a 

“region,” as opposed to in the geographic area used to measure market power.487 PPM 

submits that the appropriate geographic area for measuring ownership or control of 

electric generation for purposes of identifying Category 1 sellers is the same area used to 

assess market power: the balancing authority area or, for RTOs and ISOs, the relevant 

RTO/ISO market or submarket. PPM submits that the use of regions for determining 

Category 1 membership would result in a seller owning or controlling 500 MW of 

generating capacity located entirely in one balancing authority area being considered to 

have less chance of possessing market power than a seller owning or controlling 300 MW 

of generating capacity each in two separate balancing authority areas separated by 

hundreds of miles but located in the same region pursuant to the map provided in 

 487 PPM Rehearing Request at 2-3. 
Docket No. RM04-7-001 -229- 

Appendix D to the Final Rule. PPM contends that there is neither evidence nor a rational 

basis for concluding that the seller in the second example should be included in Category 

2 and the seller in the first example should be included in Category 1. Thus, PPM 

concludes that the Commission’s basis for distinguishing between Category 1 and 

Category 2 sellers is arbitrary and capricious. 

358. PPM also asserts that the Commission should treat ownership or control of 

intermittent generating capacity differently from thermal generating capacity for the 

purposes of establishing whether a seller falls within Category 1 or Category 2. PPM 

claims that it is extremely unlikely that any public utility will attain market power as a 

result of its ownership or control of wind generation capacity due to the intermittent 

nature of such capacity.488 Thus, it argues that the Commission should adopt a less 

stringent limitation for purposes of establishing Category 1 status for sellers of power 

from intermittent generating capacity. PPM notes that the Commission rejected this 

suggestion from commenters, stating “[w]e believe that many sellers with wind and other 

non-thermal capacity will fall below the 500 MW threshold; those that do not may take 

advantage of simplifying assumptions and other means to minimize the burden of filing 

an updated market power analysis.”489 However, PPM asserts that, other than gas, wind 

 488 Id. at 4. 

489 Id. (citing Order No. 697 at P 867). 
Docket No. RM04-7-001 -230- 

power is the fastest growing source of electric generating capacity.490 According to 

PPM, several wind power developers already own or control more than 500 MW of 

intermittent generation capacity in a region, as designated by Appendix D, and several 

more are likely to attain this status before long. PPM contends that, as the United States 

seeks to promote investment in electric generation technologies that enhance national 

energy security and do not emit greenhouse gases, it would be unwise to impose a burden 

on wind power generators that will not enhance the competitiveness of wholesale electric 

markets. 

Commission Determination

359. With regard to PPM’s argument that the use of regions for determining Category 1 

membership would result in a seller owning or controlling 500 MW of generating 

capacity located entirely in one balancing authority area being considered to have less 

chance of possessing market power than a seller owning or controlling 300 MW of 

generating capacity each in two separate balancing authority areas separated by hundreds 

of miles but located in the same region pursuant to the map provided in Appendix D to 

the Final Rule, we find that PPM misses the point. The Commission’s creation of a 

category of sellers (Category 1 sellers) that are not required to submit regularly scheduled 

 490 Id. (citing Florence, Joseph, Global Wind Power Expands in 2006, “Wind is the 

world’s fastest-growing energy source with an average annual growth rate of 29 

percent over the last ten years. In contrast, over the same time period, coal use has 

grown by 2.5 percent per year, nuclear power by 1.8 percent, natural gas by 2.5 

percent, and oil by 1.7 percent.” June 28, 2006 http://www.earthpolicy.org/Indicators/Wind/2006.htm). 
Docket No. RM04-7-001 -231- 

updated market power analyses is based in part on recognizing the administrative burden 

imposed on smaller sellers that are unlikely to possess market power. In doing so, the 

Commission intends to remain conservative in its approach to identifying such sellers. 

While PPM’s argument may make sense from a strictly analytical viewpoint, it also 

greatly increases the universe of sellers that would not be required to submit regularly 

scheduled updated market power analyses. We are not willing to do so. 

360. The Commission explained in Order No. 697 that,“[i]n keeping with our 

conservative approach with regard to which entities qualify for Category 1, we find that 

aggregate capacity in a given region best meets our goal of ensuring that we do not create 

regulatory barriers to small sellers seeking to compete in the market while maintaining an 

ample degree of monitoring and oversight that such sellers do not obtain market 

power.”491 The Commission considered other formulations for a threshold, but it 

concluded that the other “methodologies are inconsistent with a straightforward, 

conservative means of screening sellers . . . .”492 Thus, we deny PPM’s request to define 

Category 1 sellers based on their ownership or control of generation capacity located in a 

balancing authority area or an RTO/ISO market rather than based on ownership in a 

region. 

361. With regard to PPM’s request that the Commission adopt a less stringent 

limitation for purposes of establishing Category 1 status for sellers of power from 

 491 Order No. 697 at P 865. 

492 Id. P 868. 
Docket No. RM04-7-001 -232- 

intermittent generating capacity, as PPM acknowledges, the Commission considered and 

rejected this suggestion in the Final Rule. The Commission stated that it believed “that 

many sellers with wind and other non-thermal capacity will fall below that 500 MW 

threshold”493 and reiterated that those sellers that exceed it may take advantage of 

simplifying assumptions to minimize the burden of filing an updated market power 

analysis. While there may theoretically be some merit to PPM’s assertion that it is 

unlikely that any public utility will attain market power as a result of its ownership or 

control of wind generation capacity due to the intermittent nature of such capacity, 

nevertheless, PPM’s remark that wind power is the fastest growing source of generating 

capacity (other than gas) is further reason that intermittent capacity should not be treated 

differently from thermal generating capacity for purposes of establishing Category 1 

status. There may be a time when a very large wind power facility could possibly have 

market power and will warrant Commission scrutiny. We note that PPM argues that the 

Commission should adopt a less stringent limitation for purposes of establishing 

Category 1 status for sellers of power from intermittent generating capacity because, in 

its view, it would be unwise to impose a burden on wind power generators that will not 

enhance the competitiveness of wholesale electric markets. However, PPM does not 

claim such a burden would be unduly burdensome. Nor should it. Our approach is 

balanced, reasonable, and consistent with our approach to examining market power of 

sellers seeking to obtain or retain market-based rate authority. On this basis, we believe 

 493 Id. P 867. 
Docket No. RM04-7-001 -233- 

it is appropriate that wind generators be subject to the same 500 MW threshold for 

Category 1 status as other sellers. At the same time, we note that we already afford 

intermittent generation more flexibility in conducting market power analyses than, for 

example, thermal generating capacity. In particular, we allow energy-limited resources to 

provide a market power analysis based on historical capacity factors to more accurately 

capture hydroelectric or wind availability, in lieu of using nameplate or seasonal 

capacity.494 This is an option not available to thermal generating units. In addition, as 

we stated in the Final Rule, such sellers can take advantage of simplifying assumptions 

(such as performing the indicative screens assuming no import capacity or treating the 

host balancing authority area utility as the only other competitor). As a result, to the 

extent that a wind power generator exceeds the 500 MW threshold and therefore is 

considered a Category 2 seller, we believe that any burden imposed on that seller to file 

an updated market power analysis would be minimal. 

2. Regional Review and Schedule

Requests for Rehearing

362. On rehearing, FirstEnergy and MidAmerican object to the regional filing approach 

adopted in the Final Rule. 

363. FirstEnergy argues that the Commission erroneously and unreasonably ruled that 

for corporate families that own or control generation in different regions, the corporate 

family would be required to file an update for each region in which members of the 

 494 Id. P 344. We also remind sellers that they may seek exemption from Category 

(continued...) 
Docket No. RM04-7-001 -234- 

corporate family sell power during the time period specified for that region.495 

FirstEnergy contends that a corporate family with generation assets in adjacent 

geographic markets finds it far more efficient to prepare and submit a single, allencompassing, updated market power analysis every three years than to prepare separate 

analyses for each region.496 It claims that adoption of a single filing date for all entities 

within a corporate family that have market-based rates will permit all necessary tariff 

revisions to be filed at the same time, and will thereby reduce the possibility for 

discrepancies among tariffs within the same corporate family. 

364. FirstEnergy reasons that it is unlikely that there are a significant number of 

corporate families that have affiliated generation suppliers operating in adjacent 

geographic markets. For that reason, FirstEnergy states that there is no reason to believe 

that authorizing affected sellers to make a single, all-encompassing, triennial market 

power update filing every three years will significantly undermine the Commission’s 

ability to obtain a complete view of market forces in each region in order to ensure that 

seller’s rates remain just and reasonable.497 In the event that the Commission permits all 

companies within a corporate family that operate in adjacent geographic markets to file a 

single market power updated analysis during a three-year filing cycle, FirstEnergy 

 

2 status on a case-by-case basis. See id. P 868. 

495 FirstEnergy Rehearing Request at 3. 

496 Id. at 5. 

497 Id. at 6-7. 
Docket No. RM04-7-001 -235- 

requests that the filing companies be given the option of selecting the region with which 

they will participate.498 

365. MidAmerican seeks a filing schedule that permits it to submit a single market 

power analysis reflecting the generating facilities within its own balancing authority area 

(part of the Central region) as well as its Quad Cities Station (QCS), which is located on 

the border of that balancing authority area (part of the Northeast region). MidAmerican 

seeks to align the filing schedules to lessen the burden on the Commission in evaluating 

MidAmerican’s market power, and the burden on MidAmerican in preparing multiple 

filings.499 Its affiliate Cordova operates a generating facility also electrically located 

within the Northeast region, and MidAmerican states that Order No. 697 could be 

construed to require Cordova to file with the Northeast region. 

366. MidAmerican states that, as affiliates, it and Cordova historically have prepared 

market power analyses that have evaluated the competitive effects of the aggregate 

generation owned and controlled by both. For that reason, Cordova is seeking to file on 

the same schedule as MidAmerican. QCS and Cordova’s facility electrically are located 

immediately adjacent to MidAmerican’s balancing authority area, and the metering 

points within the respective substations form part of the border between the Northeast 

and Central regions; each facility is geographically within the MidAmerican service 

 498 Id. at 7. Alternatively, FirstEnergy suggests that the Commission should 

establish a process by which it would determine which cycle should be followed. 

499 MidAmerican Rehearing Request at 2. 
Docket No. RM04-7-001 -236- 

territory and directly interconnected with the MidAmerican transmission system through 

facilities owned by MidAmerican.500

367. MidAmerican seeks clarification that its undivided ownership interest in QCS will 

not cause it to be deemed a seller that “operates” in the Northeast region subject to that 

region’s filing schedule.501 If the Commission is not willing to construe Order No. 697 in 

this manner, then, for the same reasons, MidAmerican seeks waiver of the filing schedule 

to permit QCS to be treated as part of MidAmerican’s on-system generating resources; 

i.e., as if QCS were within the Central region along with the other MidAmerican 

generating resources.502 Cordova also seeks a similar clarification or waiver of Order 

No. 697 to permit its updated market power analysis to be made pursuant to the Central 

region schedule applicable to MidAmerican. MidAmerican states that its request is 

narrowly tailored to the circumstances applicable to itself and Cordova, whose relevant 

generation is located electrically either within or at the border of MidAmerican’s 

balancing authority area in the Central region. By way of distinction, MidAmerican is 

not requesting permission to make a single filing for its entire corporate family.503 

 500 Id. at 4. 

501 Id. at 10. 

502 Id. at 10-11. 

503 Id. at 3-4. 
Docket No. RM04-7-001 -237- 

Commission Determination

368. The Commission specifically addressed FirstEnergy’s argument in Order No. 697. 

The Commission stated that its decision to adopt a regional review properly and fairly 

balances the need to effectively monitor and mitigate market power in the wholesale 

markets with the desire to minimize any administrative burden associated with the filings 

and review of updated market power analyses. The Commission recognized that some 

sellers may have to file updated market power analyses more frequently than they would 

have had to before Order No. 697, but the Final Rule carefully balanced the interests of 

all involved. The Commission explained that the regional approach will enhance the 

Commission’s ability to continue to ensure that sellers either lack market power or have 

adequately mitigated such market power.504 We recognize FirstEnergy’s contention that 

it is more efficient to prepare and submit a single, all-encompassing, updated market 

power analysis every three years than to prepare separate analyses for each region. 

However, such an approach does not satisfy our desire to ensure greater consistency in 

the data used to evaluate sellers’ market power. If corporate families are allowed to 

combine all of their facilities nationwide into a single updated market power analysis, the 

study year and associated data may not be consistent with that required for the 

corresponding region, and thus the Commission’s ability to ensure greater consistency in 

the data used to evaluate sellers’ market power and to reconcile conflicting submissions 

would be undermined. Thus, we deny FirstEnergy’s request for rehearing in this regard. 

 504 Order No. 697 at P 883. 
Docket No. RM04-7-001 -238- 

369. With regard to FirstEnergy’s claim that adoption of a single filing date for all 

entities within a corporate family that have market-based rates will permit all necessary 

tariff revisions to be filed at the same time, and will thereby reduce the possibility for 

discrepancies among tariffs within the same corporate family, from an administrative 

perspective, we agree and note that nothing in Order No. 697 prohibits FirstEnergy or any 

other seller from making such a filing revising all of its market-based rate tariffs at the 

same time. Our concern addressed above pertaining to data consistency is not present 

with regard to making a corporation’s market-based rate tariffs Order No. 697 compliant. 

Our analysis of market-based rate tariffs’ compliance with Order No. 697 is not 

dependent on analyzing data but rather analyzing whether the tariffs meet the standards 

set forth in Order No. 697. Unlike analysis of data that can vary depending on the source 

of the data and the underlying assumptions, Order No. 697 set forth the standard by 

which the market-based rate tariff will be judged and those standards do not vary nor are 

they subject to assumptions. 

370. We will deny MidAmerican’s request for clarification. To the extent that a seller’s 

generation facilities are electrically located in different regions, the intent of the regional 

review approach is for those facilities to be studied with their separate regions. We note 

that, prior to the adoption of the Final Rule, sellers were required to prepare a market 

power analysis for all of their generation assets nationwide. Some sellers with assets in 

multiple regions chose to submit their individual updated market power analyses when 

each was due rather than combining them into a single updated market power analysis. 

Others filed one updated market power analysis for the entire corporate family, with 
Docket No. RM04-7-001 -239- 

individual analyses of the different markets in which their assets are located. Either way, 

the same analyses were required to be filed before and after the Final Rule. Although the 

timing of the filings may differ post-Final Rule, the increased burden, if any, of filing 

pursuant to the regional approach is minimal. 

371. With respect to MidAmerican’s company-specific request for waiver from the 

requirements of Order No. 697, we will decline to act in the context of this generic 

rulemaking proceeding. We do not believe that this rehearing order is the proper vehicle 

to consider a waiver request which, as MidAmerican describes it, is narrowly tailored to 

itself and Cordova. MidAmerican’s request for waiver may be submitted in another 

individual proceeding, and the Commission will consider the merits of its request at that 

time. 

3. Clarifications on Implementation Process

372. During the period since Order No. 697 became effective, a number of 

implementation questions have come to the Commission’s attention, either as a result of 

questions received from sellers or as raised in various filings. As we describe above, 

several of these issues were addressed in the Clarification Order issued on December 14, 

2007. We will use this opportunity to provide additional guidance. 

373. In the Clarification Order, among other things, the Commission explained that 

there may have been confusion concerning which data and market share calculations 
Docket No. RM04-7-001 -240- 

must be submitted as part of sellers’ updated horizontal market power analyses.505 The 

Commission clarified that market shares calculated for the wholesale market share screen 

and the DPT analysis should be based on the four seasons, as defined in the April 14 

Order,506 rather than the four quarters of the calendar year. The Clarification Order 

revised Appendix D to Order No. 697 to incorporate this clarification and explained that 

the study period runs from December of one year through November of the following 

year. 

374. In the Clarification Order, the Commission also clarified which entities are 

required to file their updated market power analyses first. In Order No. 697, the 

Commission discussed the need for entities that have the information necessary to 

perform simultaneous transmission import limit studies to file in advance of those who 

will rely on that information.507 In Appendix D of Order No. 697, the Commission 

identified those required to file first as “Transmission Operators.” However, the 

Commission explained in the Clarification Order, consistent with the discussion in 

paragraph 889 of Order No. 697, that transmission-owning utilities with market-based 

rate authority and their affiliates with market-based rate authority are the entities required 

 505 We note that, in an effort to continue to improve upon the accuracy and 

consistency of data used within a region and to provide the Commission and the public 

with a more complete picture of the market, the Commission will allow RTO/ISOs to 

conduct market power studies that the RTO/ISO members can rely on in their market 

power filings. 

506 April 14 Order, 107 FERC ¶ 61,018 at n.85. 

507 Order No. 697 at P 889. 
Docket No. RM04-7-001 -241- 

to file their updated market power analyses first in each region.508 Accordingly, revised 

Appendix D makes clear that transmission owners and their affiliates have earlier filing 

periods than other entities required to file in each region. 

375. In the Final Rule, the Commission stated that it will entertain individual requests 

for exemption from Category 2, and that such requests must be filed no later than 120 

days before a seller’s next updated market power analysis is due. However, the period 

for filing updated market power analyses is not a specific date, but a month-long period 

(either December or June of each year). In response to questions regarding how to 

calculate 120 days prior to the filing period, we clarify that a seller must make a filing 

requesting an exemption from Category 2 no later than 120 days prior to the first day of 

the month in which its next updated market power analysis is due.509 

376. In Order No. 697, the Commission explained that a power marketer that does not 

own or control generation assets in any region must submit a filing explaining why it 

meets the criteria for Category 1 and directed that such filings be submitted with the first 

scheduled geographic region in which the power marketer makes any sales.510 Because 

the Commission has received several inquiries regarding this directive, we will provide 

further clarification here. If an unaffiliated power marketer has made no sales at any 

point in time since it obtained its market-based rate authority, it should make this 

 508 Clarification Order, 121 FERC ¶ 61,260 at P 9.

509 See id. P 868. 

510 Id. at n.1027. 
Docket No. RM04-7-001 -242- 

submission during the next filing period, i.e., June 1 – 30, 2008. We also clarify that, 

once a seller is determined to be in Category 1, it is not required to file updated market 

power analyses, or evidence of Category 1 status, for the other regions in which it makes 

sales so long as it continues to meet the criteria for a Category 1 seller.511

377. Additionally, in response to inquiries from certain sellers in the Central region, we 

will clarify the geographic area included in that region. Specifically, the Central region 

will now be defined to include portions of NERC Region RFC as follows: Central 

(Midwest ISO, NERC Regions MRO and RFC (not including PJM)).512 Appendix D has 

been revised to reflect this description of the Central region. 

378. Additionally, in Order No. 697 the Commission adopted a requirement that all 

sellers include an appendix listing generation assets as well as electric transmission and 

natural gas intrastate pipelines and/or gas storage facilities with certain filings, consistent 

with the example in Appendix B of Order No. 697.513 We clarify that the transmission 

facilities that we require to be included in that asset appendix are limited to those the 

ownership or control of which would require an entity to have an OATT on file with the 

Commission (even if the Commission has waived the OATT requirement for a particular 

seller). 

 511 See id. P 849 (stating that subsequent to being found to be in Category 1, “all 

Category 1 sellers will not be required to file regularly scheduled updated market power 

analyses.)” 

512 Id. at Appendix D. 

513 Order No. 697 at P 895. 
Docket No. RM04-7-001 -243- 

379. Further, we clarify the manner in which transmission assets should be identified 

and described in the asset appendix. In order to lessen the reporting burden for sellers 

with large numbers of transmission facilities, we will allow a company to combine lines 

of a common size into one “line item” for purposes of the appendix; i.e., 12 individual 

500 kV lines could be identified as one line item in the appendix. For companies using 

this approach, rather than listing each line separately, the appendix must be filled out in a 

slightly different manner. Specifically, under the Asset Name and Use section of the 

appendix, rather than using the actual line name, a seller would insert an appropriate asset 

identifier. For example, if combining all 500 kV lines together the asset identifier would 

be “Combined 500kV Lines.” As a result, the Size section of the appendix would also 

change. Rather than identifying the actual size of each line, the seller would include the 

transmission asset size, described as the total combined length of all the lines of that size. 

Because the combined lines could run through several balancing authority areas and 

regions, the seller should split up its combined assets into separate balancing authority 

areas. Accordingly, the transmission asset aspect of the appendix would be filled out 

similar to the following: 
Docket No. RM04-7-001 -244- 

Filing Location 

Entity 

and its 

Energy 

Affiliates 

Asset 

Name and 

Use 

Owned 

By 

Controlled 

By 

Date Control 

Transferred Balancing 

Authority 

Area 

Geographic 

Region (per 

Appendix D) 

Size 

ABC 

Corp. 

Combined 

500kV 

Lines 

ABC 

Corp. ABC Corp. NA 

New York 

ISO and 

Tucson BA 

Northeast and 

Southwest 

Approx. 

305 

combined 

miles 

ABC 

Corp. 

Combined 

500kV 

Lines 

ABC 

Corp. XYZ Inc. Jan. 1, 2000 Tucson BA Southwest 

185 

combined 

miles 

380. However, we note that this combined approach can only be used if lines of the 

same size are controlled by the same entity. If there are lines of the same size controlled 

by different entities, they must be identified in different line items; i.e., each combined 

set of lines can only be identified as controlled by one entity. Thus, if the 500 kV lines 

are owned or controlled by two different entities, there would have to be two line items 

for 500 kV lines listed in the appendix. We believe this approach will allow the 

Commission to continue to obtain the information it seeks regarding a seller’s affiliated 

transmission assets while allowing those entities with a great number of assets to simplify 

their appendices. 

381. Lastly, with regard to the asset appendix, we wish to make clear that sellers must 

submit both tables in their entirety. Even if a seller has no assets to list in a specific 

section, both the Market-Based Rate Authority and Generation Assets table, as well as 

the Electric Transmission Assets and/or Natural Gas Interstate Pipelines and/or Gas 

Storage Facilities table must be submitted. As stated in Appendix B to Order No. 697, a 
Docket No. RM04-7-001 -245- 

seller should indicate the fact that it has no assets or that a field is not applicable by 

inputting N/A. 

4. Market-Based Rate Tariff Clarifications

382. In Order No. 697 the Commission adopted a requirement that all sellers include a 

provision in their market-based rate tariffs identifying all limitations on their market 

based rate authority (including markets where the seller does not have market-based rate 

authority) and any exemptions from, waivers of, or blanket authorizations under the 

Commission’s regulations that the seller has been granted (such as exemption from the 

affiliate sales restrictions; waiver of the accounting regulations; blanket authority under 

part 34 for the issuances of securities and assumptions of liabilities). The Commission 

stated that this provision must include cites to the Commission orders approving each 

limitation, exemption, waiver or blanket authorization.514 On further review, the 

Commission will take this opportunity to clarify several aspects of this requirement. 

383. First, we clarify that if a seller’s market-based rate authority is not subject to any 

limitations (for example, the seller’s market-based rate authority is not limited to certain 

markets) or if the seller has not been granted any exemptions, waivers, or blanket 

authorizations under the Commission’s regulations, then the seller should so state in the 

required “Limitations and Exemptions” provision in its market-based rate tariff, i.e., 

including “not applicable,” or “N/A.”515 

 514 Order No. 697 at P 916. 

515 See Niagara Mohawk Power Corp., 121 FERC ¶ 61,275 at P11 (2007) (Niagara 

(continued...) 
Docket No. RM04-7-001 -246- 

384. Second, we provide additional guidance on the format for citations to pertinent 

Commission orders or proceedings in which the Commission imposed limitations on the 

seller’s market-based rate authority or granted the seller’s requested exemptions, waivers, 

or blanket authorizations. In particular, sellers which already have been granted marketbased rate authorization and which have previously been placed under any limitation or 

granted any exemption, waiver or blanket authorization should include the cite to the 

relevant orders in one of the following two citation forms: 

Cal. Contract Power, 99 FERC ¶ 61,xxx, at P xx (2002). 

WWW Corp., Docket No. ER03-xxxx-000, at 2 (Apr. 12, 2003) (unpublished 

letter order). 

385. When a seller files an application for market-based rate authority seeking certain 

exemptions, waivers or blanket authorizations, the seller should include in its proposed 

tariff sheets the docket number associated with the filing. Under current Commission 

procedure, a docket number is not assigned until after an application has been filed. 

However, to enable an applicant to identify and include the docket number of its filing in 

its proposed tariff sheets, the Commission is establishing a new process for sellers to 

obtain a docket number for their submission before filling. The Commission is creating a 

location on its website where a new applicant for market-based rate authorization will 

email516 the Commission and retrieve a docket number under which its filing can be 

 

Mohawk). 

516 Any sellers unable to obtain this docket number via the internet or email will be 

directed to include the pertinent information in their tariff sheets in a compliance filing. 
Docket No. RM04-7-001 -247- 

made and which will be a substitute for the required citation in the “Limitations and 

Exemptions” provision of its tariff.517 The point of this process is to alleviate the need 

for compliance filings just to add a docket number or citation once the Commission 

issues an order on the request. Any modifications to the information submitted with the 

application would be directed to be made in a compliance filing. Once the docket 

number is obtained, the filing must be submitted to the Commission within 72 hours or 

the docket number will expire and the applicant must request a new one. This reserved 

docket number should be included in the tariff and the transmittal sheet, and a copy of the 

Commission’s response assigning this docket number should be attached as the first page 

of the filing. Accordingly, the process for a seller newly filing for market-based rate 

authorization will now require reserving a docket number before submitting the filing. 

386. In Appendix C of Order No. 697, the Commission provided certain applicable 

tariff provisions that sellers must include in their market-based rate tariffs to the extent 

they are applicable based on the services provided by the seller. One of these is to be 

 517 We note that while this approach will allow most new applicants to comply 

with the Commission’s citing requirement in the “Limitations and Exemptions” provision 

of the market-based rate tariff, there may be some instances in which the Commission 

will require a seller to make a subsequent filing to include a full citation to the 

Commission order approving a limitation, exemption, waiver or blanket authorization. 

An example of when the Commission may require such a compliance filing is when the 

Commission exempts a seller from affiliate restrictions which have been codified in 

18 CFR 35.39 or when approving mitigation measures. However, unless an applicant is 

informed by order to revise its tariff to include a citation, the docket number used in the 

tariff in the initial submission will suffice. 
Docket No. RM04-7-001 -248- 

used if a seller makes sales of ancillary services as a third-party provider.518 We are 

revising this applicable provision so that it is consistent with the other ancillary service 

provisions by inserting the phrase “Seller offers.” Thus, the “Third Party Provider” 

provision that should be included in all applicable market-based rate tariffs is as follows: 

Third-party ancillary services: Seller offers [include all of the following 

that the seller is offering: Regulation Service, Energy Imbalance Service, 

Spinning Reserves, and Supplemental Reserves]. Sales will not include the 

following: (1) sales to an RTO or an ISO, i.e., where that entity has no 

ability to self-supply ancillary services but instead depends on third parties; 

(2) sales to a traditional, franchised public utility affiliated with the thirdparty supplier, or sales where the underlying transmission service is on the 

system of the public utility affiliated with the third-party supplier; and (3) 

sales to a public utility that is purchasing ancillary services to satisfy its 

own open access transmission tariff requirements to offer ancillary services 

to its own customers. 

387. Additionally, regarding other applicable tariff provisions, which include those 

needed if a seller makes sales of ancillary services in certain RTO/ISOs, the seller must 

include the standard ancillary services provision(s) in its tariff, as applicable, without 

variation.519 To the extent that a seller with market-based rate authority does not already 

have authority to make sales of ancillary services at market-based rates in one or more of 

the RTO/ISOs included in Appendix C, but wishes to do so, it may file revised tariff 

sheets including the standard applicable ancillary service tariff provision(s) without 

seeking separate authorization from the Commission under FPA section 205. Separate 

 518 See Order No. 697 at P 917-18. 

519 Id. P 916-917; see Appendix C for a listing of the standard ancillary services 

provisions. See also Niagara Mohawk Power Corp., 121 FERC ¶ 61,275, at P 14 & n.22 

(2007) (directing seller to conform with Appendix C). 
Docket No. RM04-7-001 -249- 

authorization for specific sellers is not needed given that Order No. 697 implicitly 

granted authorization for ancillary services sales by sellers with market-based rate 

authority by providing standard tariff provisions for ancillary services sales.520

388. The Commission also stated in Order No. 697 that it would permit sellers to list in 

their market-based rate tariffs additional seller-specific terms and conditions that go 

beyond the standard provisions set forth in Appendix C.521 In the Clarification Order, we 

clarified that these seller-specific terms and conditions do not include those provisions 

that the Commission has codified in 18 CFR Part 35, Subpart H. Specifically, we stated 

that “‘seller-specific terms and conditions’ are those provisions that are commonly found 

in power sales agreements, such as creditworthiness, force majeure, dispute resolution, 

billing, and payment provisions.”522 In addition, we clarify here that we expect that all 

provisions that were contained in a seller’s market-based rate tariff but that are now 

codified in the Commission’s regulations are to be removed from each seller’s marketbased rate tariff at the time the seller modifies its existing tariff to include the required 

provisions and any applicable provisions set forth in Appendix C of Order No. 697. For 

example, sellers should remove from their tariffs codes of conduct (which have been 

 520 See Niagara Mohawk Power Corp., 121 FERC ¶ 61,275, at P 18 (2007) 

(accepting tariff provisions that were new for National Grid that comported with ancillary 

services previously approved by the Commission for sale at market-based rates and were 

listed in Appendix C of Order No. 697). 

521 Order No. 697 at P 919-22. 

522 Clarification Order, 121 FERC ¶ 61,260 at P15. 
Docket No. RM04-7-001 -250- 

replaced by the affiliate restrictions in § 35.39), any language prohibiting affiliate sales 

without first receiving Commission authorization (which is codified in § 35.39(b)), 

market behavior rules (which are codified in § 35.41), and the change in status reporting 

requirement (which is codified in § 35.42). 

389. We remind sellers that, consistent with § 35.9(b)(4), all tariff sheets must include a 

proposed effective date. The regulation requires that the seller must place the specific 

effective date proposed by the company on the tariff sheets. To alleviate any confusion, 

we stated in the Clarification Order that, notwithstanding the fact that Order No. 697 did 

not require market-based rate sellers to make immediate compliance filings amending 

their market-based rate tariffs, the Commission intended that all requirements and 

limitations applicable to market-based rate sellers set forth in the Final Rule should 

become effective on September 18, 2007. The Clarification Order explained that, 

effective September 18, 2007, provisions in market-based rate tariffs that are inconsistent 

with the requirements of Order No. 697 are no longer in effect.523 Accordingly, sellers 

filing revised tariff sheets solely to comply with Order No. 697 should use September 18, 

2007 as the effective date of the tariff sheets. However, if there are any additional 

revisions other than those required by the Final Rule, whether it be a name change or the 

addition or modification of any provision for any other reason, sellers should propose the 

date on which they wish the tariff sheets to become effective. We note that, while the 

sheets will be made effective on the date that the seller proposes, the provisions relating 

 523 Id. at P 5. 
Docket No. RM04-7-001 -251- 

to and required by Order No. 697 are still effective as of the effective date of Order No. 

697.524

390. Additionally, the Commission provides clarification regarding requests for waiver 

of affiliate restrictions (including the affiliate sales restriction and what was formerly the 

codes of conduct). If a seller was granted waiver of a restriction by the Commission prior 

to the effective date of Order No. 697, and the seller still qualifies for that waiver, the 

waiver remains effective and no further action is needed.525 However, if a seller has not 

previously been granted waiver of the affiliate restrictions and seeks a finding that the 

affiliate restrictions do not apply to it, a seller must file a request with the Commission 

pursuant to FPA section 205. 

391. Lastly, in order to identify which sellers must file updated market power analyses, 

we will now require each seller to specify in its market-based rate tariff whether it is a 

Category 1 or Category 2 seller. In a separate provision of the market-based rate tariff 

entitled Seller Category, each seller should state whether it believes it is in Category 1 or 

Category 2.526 Specifically, the following provision should be included in each marketbased rate tariff: 

 524 See Clarification Order, 121 FERC ¶ 61,260 at P 5. 

525 Pursuant to Order No. 697, however, such a waiver must be identified in a 

seller’s tariff. See Order No. 697 at P 916 and Appendix C. 

526 Sellers that have received an exemption from Category 2, as described in Order 

No. 697 at P 868, should identify themselves as Category 1 sellers. 
Docket No. RM04-7-001 -252- 

Seller Category: Seller is a [insert Category 1 or Category 2] seller, as 

defined in 18 CFR 35.36(a). 

392. The Commission will make a finding on the category of each seller. To the extent 

that the Commission finds that a seller is in the other category, the Commission will order 

the appropriate tariff revisions. 

393. Any seller whose category has been determined in a Commission proceeding 

between the effective date of Order No. 697 and the issuance of this order and which has 

not included a Seller Category provision in its tariff should update its tariff with such a 

provision the next time that it files revised tariff sheets, a triennial review, or a change in 

status report. 

F. Legal Authority

1. Whether Market-Based Rates Can Satisfy the Just and 

Reasonable Standard Under the FPA

Final Rule

394. In the Final Rule, the Commission rejected arguments that it has no authority to 

adopt market-based rates or that the market-based rate program adopted in the Final Rule 

does not comply with the FPA. The Commission explained that it is settled law that 

market-based rates can satisfy the just and reasonable standard of the FPA, as most 

recently affirmed by the Ninth Circuit in Lockyer and Snohomish.

527 The Commission 

 527 Order No. 697 at P 943 (citing State of California, ex rel. Bill Lockyer v. 

FERC, 383 F.3d 1006 (9th Cir. 2004), cert. denied, (S. Ct. Nos. 06-888 and 06-1100 

(June 18, 2007) (Lockyer); Public Utility District No. 1 of Snohomish County, 

Washington v. FERC, 471 F.3d 1053 (9th Cir. 2006), cert. granted, 128 S. Ct. 31 

(Sept. 25, 2007) (Nos. 06-1457, 06-1462) (Snohomish)). 
Docket No. RM04-7-001 -253- 

explained that in Lockyer, the Ninth Circuit cited with approval the Commission’s dual 

requirement of an ex ante finding of the absence of market power and sufficient postapproval reporting requirements, finding that the Commission did not rely on market 

forces alone in approving market-based rate tariffs.528 The Final Rule also rejected 

arguments that the proposed rule impermissibly relied solely on the market to determine 

just and reasonable rates, explaining that in the market-based rate program adopted in the 

Final Rule and through other Commission actions, the Commission is not relying solely 

on the market, without adequate regulatory oversight, to set rates.529 Rather, it has 

adopted filing requirements, new market manipulation rules, and a significantly enhanced 

market oversight and enforcement division to help oversee potential increases in market 

power and potential market manipulation.530

395. The Commission retained its policy of granting market-based rate authority to 

sellers without market power under the terms and conditions set forth in the Final 

Rule.531 The Final Rule explained that the Commission has a long-established approach 

when a seller applies for market-based rate authority of focusing on whether the seller 

lacks market power. The Commission explained that this approach, combined with the 

Commission’s filing requirements (EQRs, change in status filings, and regularly 

 528 Id. P 953-954. 

529 Id. P 952. 

530 Id. 

531 Id. P 954-955. 
Docket No. RM04-7-001 -254- 

scheduled updated market power analyses for Category 2 sellers) and ongoing monitoring 

through the Commission’s Office of Enforcement and complaints filed pursuant to FPA 

section 206, allows the Commission to ensure that market-based rates remain just and 

reasonable. Moreover, for sellers in RTO/ISO organized markets, the Commission has in 

place market rules to help mitigate the exercise of market power, price caps where 

appropriate, and RTO/ISO market monitors to help oversee market behavior and 

conditions. 532

396. The Final Rule rejected arguments that the market-based rate program does not 

comply with the FPA, stating that “[t]he Supreme Court has held that ‘[f]ar from binding 

the Commission, the FPA’s just and reasonable requirement accords it broad ratemaking 

authority.... The Court has repeatedly held that the just and reasonable standard does not 

compel the Commission to use any single pricing formula in general....’”533 The 

Commission also pointed out that in the Lockyer court’s analysis of the Commission’s 

market-based rate authority, the Ninth Circuit cited the Supreme Court’s determination in 

Mobil Oil Exploration and also noted that the use of market-based rate tariffs was first 

 532 Id. P 955. 

533 Id. P 943 (quoting Mobil Oil Exploration v. United Distribution Co., 498 U.S. 

211, 224 (1991) (Mobil Oil Exploration), citing FPC v. Hope Natural Gas Co., 320 U.S. 

591, 602 (1944); FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian 

Basin Area Rate Cases, 390 U.S. 747, 776-77 (1968) (Permian); FPC v. Texaco, 417 U.S. 

380 (1974) (Texaco)). 
Docket No. RM04-7-001 -255- 

approved by the courts as to sellers of natural gas in Elizabethtown Gas, then as to 

wholesale sellers of electricity in Louisiana Energy and Power Authority v. FERC.

534 

397. The Commission rejected arguments that the Final Rule impermissibly relies 

solely on the market to determine just and reasonable rates.535 The Final Rule explained 

that in Texaco,

536 the Supreme Court noted that it had sustained rate regulation based on 

setting area rates that were based on composite cost considerations, citing its decision in 

FPC v. Hope Natural Gas Co.,

537 and added that ratemaking agencies are not bound to the 

service of any single regulatory formula.538 The Final Rule further explained that in 

Texaco, the Supreme Court found that the NGA permits the indirect regulation of smallproducer rates, and noted that cases under the NGA and the FPA are typically read in pari

materia.

539 The Commission stated that in the market-based rate program adopted in the 

Final Rule and through other Commission actions, unlike the situation in Texaco, the 

Commission is not relying solely on the market without adequate regulatory oversight to 

set rates. 

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

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

(LEPA). See also Order No. 697 at P 944. 

535 Order No. 697 at P 945-947. 

536 Id. P 946 (citing FPC v. Texaco, Inc., 417 U.S. 380 (1974) (Texaco)). 

537 Id. (citing 320 U.S. 602). 

538 Id. (quoting Permian, 390 U.S. at 776-77). 

539 Id. P 946 n.1070 (citing FPC v. Sierra Pacific Power Co., 350 U.S. 348, 353 

(1956) (Sierra); Arkansas-Louisiana Gas Company v. Hall, 453 U.S. 571 n.7 (1981)). 
Docket No. RM04-7-001 -256- 

398. The Final Rule also explained that in Elizabethtown Gas, a decision relying on 

Texaco, the D.C. Circuit addressed a Commission order approving a restructuring 

settlement under which Transcontinental Gas Pipeline Corporation (Transco) would no 

longer sell gas bundled with transportation, but would sell gas at the wellhead or pipeline 

receipt point, to be transported as the buyer sees fit, and the sales would be market-based 

while the rates for transportation on Transco’s system would be cost-of-service based.540 

In rejecting arguments that the proposed rule impermissibly relied solely on the market to 

determine just and reasonable rates, the Final Rule explained that in Elizabethtown Gas 

the D.C. Circuit upheld the Commission’s approval of market-based pricing.541 The 

Final Rule explained that the D.C. Circuit had also affirmed the Commission’s approval 

of an application by Central Louisiana Electric Company (CLECO) to sell electric energy 

at market-based rates.542 

Requests for Rehearing

399. Consumer Advocates argue that the Final Rule erred in claiming that the 

Commission can legally rely on the market (viz. wholesale buyers/re-sellers) to determine 

lawful rates. They contend that the Final Rule errs in relying on wholesale buyers/resellers to determine lawful rates by “‘negotiation,’” particularly where the buyers 

 540 Id. P 948. 

541 Id. P 949-950. 

542 Id. P 951 (citing LEPA, 141 F.3d at 365). 
Docket No. RM04-7-001 -257- 

generally bear no risk of loss in passing along such prices.543 They argue that such 

reliance constitutes an unlawful delegation of the Commission’s statutory obligations to 

wholesale buyers insofar as (1) the Commission overlooked the economic fact that such 

wholesale buyers/re-sellers generally bear no risk of loss because their negotiated prices 

must be passed through to retail ratepayers;544 and (2) the Final Rule may not rely on the 

markets to determine rates because the Commission may not delegate to others its FPA 

responsibilities to ensure that rates are lawful.545 

400. Consumer Advocates contend that the Final Rule failed to provide a standard 

whereby the Commission can determine whether actual market rate increases fall within a 

“‘zone of reasonableness’” not just in theory, but “‘in fact.’” According to Consumer 

Advocates, the Final Rule only addressed whether the “‘market’” is competitive546 and 

 543 Consumer Advocates Rehearing Request at 10. Richard Blumenthal, Attorney 

General for the State of Connecticut and the People of the State of Illinois, by and 

through the Illinois Attorney General, Lisa Madigan (Attorneys General of Connecticut 

and Illinois) submitted a request for rehearing on July 19, 2007 that adopts and 

incorporates by reference all of the arguments presented by the Consumer Advocates in 

their request for rehearing filed in this proceeding. 

544 Id. at 10 (citing Tejas Power Corp v. FERC, 908 F.2d 998 (D.C. Cir. 1990); 

Nantahala Power & Light Co. v. Thornburg, 476 U.S. 953, 970 (1986); Elizabethtown 

Gas). 

545 Id. at 10, 12. Consumer Advocates note that in a recent order the Commission 

correctly held that it could not delegate to state commissions its “ratemaking obligations 

under the FPA.” Id. at 12 (citing Entergy Services, Inc., 120 FERC ¶ 61,020 (2007), 

citing Louisiana, Inc. v. Louisiana Public Service Comm., 539 U.S. 39, 43 n.1; City of 

New Orleans v. Entergy Corp., 55 FERC ¶ 61,211, at 61,729 (1991)). 

546 As discussed at P 409 below, the Industrial Customers argue that the Final Rule 

erred insofar as it failed to make the finding that a competitive market exists. See

(continued...) 
Docket No. RM04-7-001 -258- 

sellers are manipulative, not whether wholesale rates are not excessive, as the FPA 

requires.547 Consumer Advocates argue that the Final Rule attempted to distinguish 

Supreme Court and other judicial precedent that requires the Commission to determine 

whether “‘market’” rates in fact fall within a “‘zone of reasonableness,’” but fails to do 

so.548 They also contend that the Final Rule failed to explain how the Commission, 

which is not an antitrust agency, acting under the FPA, which is not an antitrust statute 

but a rate filing regulatory statute, can rely entirely on its oft-changing antitrust analyses 

regarding market power to determine whether market-based rates are within a zone of 

reasonableness.549 NASUCA also asserts that the Final Rule failed to identify an 

objective standard by which to ascertain, after rates have been changed, charged and 

eventually reported, whether a market rate is or is not in the zone of reasonableness.550 

401. Consumer Advocates contend that the Final Rule erred in relying heavily on 

Natural Gas Act (NGA) cases and Interstate Commerce Act oil pipeline cases as judicial 

 

Industrial Customers Rehearing Request at 6-7. 

547 Consumer Advocates Rehearing Request at 12-13. 

548 Id. (citing Farmers Union Cent. Exch. v. FERC, 734 F.2d 1486 (D.C. Cir. 

1984) (Farmers Union)). 

549 Id. at 13-14 (citing MCI Telecommunications Corp. v. AT&T Co., 512 U.S. 

218 (1994) (MCI); Southwestern Bell Corp. v. FCC, 43 F.3d 1515 (D.C. Cir. 1995) 

(Southwestern Bell)). 

550 NASUCA Rehearing Request at 18. 
Docket No. RM04-7-001 -259- 

support for the Commission’s authority to allow market-based rates.551 Consumer 

Advocates assert that there are substantive differences among electricity and natural gas 

statutes, the physical operations of the industries, and the costs of providing service.552 

They argue that in addition to the fact that Congress has deregulated most natural gas 

wellhead sales, but has never deregulated wholesale electric sales, the FPA and NGA 

have always differed in certain respects, namely that NGA section 7 confers authority on 

the Commission to certify and condition natural gas service, whereas no such authority is 

given to the Commission under the FPA.553 Consumer Advocates argue that the 

regulation of generation and distribution was specifically reserved to the states554 and 

contend that the costs of production of natural gas and electricity differ markedly.555

They state that highly depreciated power plants have very different costs from new ones, 

and they note that in the Connecticut complaint against ISO New England, the complaint 

 551 Consumer Advocates Rehearing Request at 19 (citing Order No. 697 at P 943, 

n.1068 (citing Mobil Oil Exploration, 498 U.S. at 224, citing FPC v. Hope Natural Gas 

Co., 320 U.S. 591, 602 (1944); FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586 

(1942); Permian, 390 U.S. at 776-77; Texaco, 417 U.S. at 308)). 

552 Id. at 17-18. 

553 Id. at 18. 

554 Id. (citing FPA section 201(e)). 

555 Id. 
Docket No. RM04-7-001 -260- 

showed that excessive rates of return were being made, but the Commission found this 

“‘not relevant.’”556 

402. Consumer Advocates conclude that these differences result in very different 

bidding strategies by market participants, yet the Final Rule relied primarily on natural 

gas and oil cases in defense of the Commission’s market-based rate regime.557 In 

particular, they contend that the claim in the Final Rule that “costs of all natural gas 

companies need not be ascertained separately,” incorrectly cites to the fact that the courts 

treat virtually identically parts of the statute “‘in pari materia.’”558 They argue that 

because this language refers to the filing and rate review provisions of the two statutes, it 

does not contend that the cost elements or physical operations of these two distinct 

industries are the same.559 

403. Consumer Advocates argue that the incentive provided by the market-based rate 

regime is for plant owners to keep power supplies tight, thus raising their profits from 

remaining power plants or contracts.560 They state that because wholesale sellers have no 

obligation to serve, the Commission’s market-based rate regime requires the Commission 

to give incentives, like locational pricing, to essentially “‘bribe’” suppliers to build power 

 556 Id. at 19 (citing Richard Blumenthal v. ISO New England, Inc., 117 FERC 

¶ 61,038 (2006), reh’g denied, 118 FERC ¶ 61,205 (2007) (Blumenthal)). 

557 Id. (citing Order No. 697 at P 943, n. 1068). 

558 Id. (citing Order No. 697 at P 946, n.1070). 

559 Id. 

560 Id. at 20. 
Docket No. RM04-7-001 -261- 

plants.561 Consumer Advocates contend that the Final Rule failed to explain why this 

“‘perverse incentive’” is in either the public or the national interest. They also note that 

the court in Elizabethtown Gas did not address these “perverse economic incentives.”562 

404. Industrial Customers argue that a finding that competitive markets exist is a 

prerequisite to relying upon market-based rate authority to satisfy the mandates of the 

FPA. In particular, Industrial Customers contend that the Final Rule does not reflect 

reasoned decision-making because it fails to address their argument stating that the 

Commission must find the existence of a competitive market before it can rely on marketbased rate authority.563 Additionally, Industrial Customers contend that the Final Rule is 

arbitrary, capricious and insufficiently supported in presuming that existing price setting 

mechanisms are competitive markets that will enable the use of market-based rate 

authority to ensure just and reasonable rates.564 Industrial Customers argue that their 

NOPR comments relied on significant precedent for their argument that the Commission 

 561 Id. 

562 Id. at 21. 

563 Industrial Customers Rehearing Request at 6 (citing Electricity Consumers Res. 

Council v. FERC, 747 F.2d 1511, 1513; Burlington Truck Lines v. United States, 371 

U.S. 156, 168 (1962); W. Mass Elec. Co. v. FERC, 165 F.3d 922, 927 (D.C. Cir. 1997); 

Victor Broad, Inc. v. FCC, 722 F.2d 756, 760 (D.C. Cir. 1983); Transcontinental Gas 

Pipe Line Corp. v. FERC, 922 F.2d 865, 869 (D.C. Cir. 1991); KN Energy, Inc. v. FERC,

968 F.2d 1295, 1303 (D.C. Cir. 1992); PPL Wallingford, 419 F.3d at 1198; Canadian 

Petroleum Producers, 254 F.3d at 299; Tesoro Alaska Petroleum Co. v. FERC, 234 F.3d 

1286, 1294 (D.C. Cir. 2000)). Montana Counsel similarly argues that the Commission 

erred in assuming that long-term markets are inherently competitive. Montana Counsel 

Rehearing Request at 4-6. 
Docket No. RM04-7-001 -262- 

must point to “empirical proof” that competitive markets exist.565 Industrial Customers 

state that although the Commission provides settled law supporting its conclusion that 

market-based rates can satisfy the just and reasonable standard of the FPA,566 the issue 

posed by Industrial Customers was whether the Commission has made the necessary 

findings that a competitive market exists—and it has not.567 Industrial Customers 

therefore assert that the Commission failed its responsibility to respond to their 

arguments,568 and must either (1) explain why the case law underlying market-based rate 

authority no longer requires the prerequisite showing of competitive markets based on 

empirical proof, or (2) undertake the task of analyzing whether current wholesale 

electricity pricing mechanisms amount to a competitive market.569 Industrial Customers 

argue that the key question the Commission failed to answer in the Final Rule is what 

constitutes a truly competitive market and whether there are any in the country sufficient 

to enable use of market-based rate authority. 

 564 Id. at 8 (citing LEPA, 141 F.3d at 365; Elizabethtown Gas, 10 F.3d at 870). 

565 Id. at 7 (citing Industrial Customers’ August 7 Comments at 6-7; Farmers 

Union, 734 F.2d at 1510). 

566 Id. (citing Order No. 697 at P 943-955). 

567 Id. 

568 Id. (citing NorAm Gas, 148 F.3d at 1165; Brusco Tug & Barge Co. v. NLRB,

247 F.3d 273, 278 (D.C. Cir. 2001); Missouri PSC v. FERC, 234 F.3d 36, 41 (D.C. Cir. 

2001)). 

569 Id. at 7-8 (citing Tripoli Rocketry v. Bureau of Alcohol, Tobacco, 437 F.3d 75, 

81 (D.C. Cir. 2006)). 
Docket No. RM04-7-001 -263- 

405. Industrial Customers argue that as the Commission acknowledged in its approval 

of the Southwest Power Pool’s Energy Imbalance Service Market, the process for 

assessing market-based rate authority is a two-part analysis: (1) determining whether a 

competitive market exists and (2) ensuring that the seller-applicant cannot exercise 

market power, based either on a finding that no market power exists or based on a finding 

that mitigation is sufficient to protect against market power. 570 Industrial Customers 

contend that if this two-part analysis is not undertaken, the Commission cannot 

demonstrate that reliance on market-based rate authority is just and reasonable.571 

406. Industrial Customers state that there are definite criteria such as barriers to entry or 

exit, demand elasticity, ease of product deliverability, transparent market information, 

unconcentrated generation asset ownership, correct market design, and absence of market 

power that would help determine whether a competitive market exists.572 They present 

information about existing markets that they allege calls into question whether the 

Commission is capable of finding the presence of dynamically competitive markets. 

Industrial Customers argue that the widespread lack of demand elasticity and the equally 

pervasive presence of generation ownership concentration and high market shares within 

submarkets are the types of issues that the Final Rule erroneously overlooked by 

 570 Id. at 9 (citing Southwest Power Pool, Inc., 116 FERC ¶ 61,289, at P 30 

(2006)). 

571 Id. 

572 Id. 
Docket No. RM04-7-001 -264- 

presuming the existence of competitive markets.573 Industrial Customers contend that 

market power issues are prevalent in PJM,574 Midwest ISO, 575 Southwest Power Pool,576

and ISO New England.577 

Commission Determination

407. In the Final Rule, the Commission fully addressed the arguments raised by 

commenters challenging the Commission’s market-based rate program. Consumer 

Advocates and Industrial Customers repeat on rehearing many of the arguments that they 

raised in their comments. While these entities re-state their arguments in a variety of 

ways, their arguments basically fall into two categories: (1) that the Commission has no 

authority at all under the FPA to rely on the market to ensure just and reasonable rates, in 

lieu of cost-based ratemaking; and (2) that the standard adopted by the Commission in 

this rule for allowing market-based rates -- a demonstration by the individual seller that it 

 573 Id. at 10. 

574 Id. at 10-13 (citing PJM 2006 State of the Market Report at 89, 210 (Mar. 8, 

2007), http://www.pjm.org; PJM Preliminary Market Structure Screen for 2007-2008; 

PJM Preliminary Market Structure Screen for 2008-2009; PJM Preliminary Market 

Structure Screen for 2000-2010; Letter from PJM to Maryland Public Service 

Commission, dated June 8, 2007 at 8, Maryland PSC Administrative Docket No. PC 8; 

PJM 2008/2009 RPM Base Residual Auction Results at 1, (July 13, 2007); Statement of 

Joseph E. Bowring In Response to the Federal Energy Regulatory Commission’s Order 

of May 18, 2007 at 3, (filed June 12, 2007)). 

575 Id. at 14 (citing 2006 Midwest ISO State of Market Report). 

576 Id. at 15 (citing Monthly Metrics Report for SPP Energy Imbalance Services 

Market at 3, prepared by the SPP Market Monitoring Unit (Apr. 2007)). 

577 Id. (citing ISO New England Report). 
Docket No. RM04-7-001 -265- 

lacks or has mitigated both horizontal and vertical market power – does not comply with 

the FPA requirement that rates be just, reasonable, and not unduly discriminatory or 

preferential. As we set forth below, we find all the iterations of these basic arguments to 

be without merit because court precedent for the past 60 years validates the 

Commission’s discretion not to be bound to any particular ratemaking method and indeed 

in more recent years has sanctioned market-based rates under both the NGA and the FPA, 

and because the market-based rate analysis in this rule will result in rates that fall within a 

zone of reasonableness. Section 205 of the FPA requires that “[a]ll rates and charges 

made ... shall be just and reasonable.”578 The FPA does not prescribe any particular 

ratemaking methodology to be followed in setting rates so long as rates fall within a zone 

of reasonableness,579 i.e., the rates are neither less than compensatory to the seller nor 

excessive to the consumer.580 Further, the fixing of “just and reasonable” rates involves a 

 578 16 U.S.C. 824d(a). 

579 FPC v. Hope Natural Gas Co., 320 U.S. at 602 (“[u]nder the statutory standard 

of ‘just and reasonable’ it is the result reached not the method employed which is 

controlling”); Permian, 390 U.S. at 776-77 (“rate-making agencies are not bound to the 

service of any single regulatory formula; they are permitted, unless their statutory 

authority otherwise plainly indicates, ‘to make the pragmatic adjustments which may be 

called for by particular circumstances,’” citing FPC v. Natural Gas Pipeline Co., 315 U.S. 

at 586). 

580 Bluefield Water Works and Improvement Co. v. Public Service Commission, 

262 U.S. 679, 692-93 (1923) (Bluefield) (“[a] public utility is entitled to such rates as will 

permit it to earn a return . . . equal to that generally being made at the same time and in 

the same general part of the country on investments in other business undertakings which 

are attended by corresponding risks and uncertainties; but it has no constitutional right to 

profits such as are realized or anticipated in highly profitable enterprises or speculative 

ventures. The return should be reasonably sufficient to assure confidence in the financial 

(continued...) 
Docket No. RM04-7-001 -266- 

balancing of investor and consumer interests581 and the “zone of reasonableness” may 

take into account all relevant public interests, both existing and foreseeable.582 These 

public interests may appropriately include non-cost factors, such as the need to stimulate 

additional investment.583 As we explained in the Final Rule and reiterate here, the 

Supreme Court has held that “[f]ar from binding the Commission, the ‘just and 

reasonable’ requirement accords it broad ratemaking authority....The Court has 

repeatedly held that the just and reasonable standard does not compel the Commission to 

use any single pricing formula in general....”584 Accordingly, the FPA grants the 

Commission broad discretion as to how the statute’s ratemaking mandate will be 

 

soundness of the utility and should be adequate, under efficient and economical 

management, to maintain and support its credit and enable it to raise the money necessary 

for the proper discharge of its public duties”). 

581 FPC v. Hope Natural Gas Co., 320 U.S. at 603.

582 See Farmers Union, 734 F.2d at 1501. 

583 See id. at 1502. 

584 Id. P 943 (quoting Mobil Oil Exploration v. United Distribution Co., 498 U.S. 

211, 224 (1991) (Mobil Oil Exploration), citing FPC v. Hope Natural Gas Co., 320 U.S. 

591, 602 (1944); FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian 

Basin Area Rate Cases, 390 U.S. 747, 776-77 (1968) (Permian); FPC v. Texaco, 417 U.S. 

380 (1974) (Texaco)). 
Docket No. RM04-7-001 -267- 

satisfied.585 The market-based rate program represents a reasonable exercise of that 

discretion.586

408. It is settled law that market-based rates can satisfy the just and reasonable standard 

of the FPA and cognate statutes. For example, as the D.C. Circuit has held, “when there 

is a competitive market the FERC may rely upon market-based prices in lieu of cost-ofservice regulation to assure a ‘just and reasonable’ result.”587 Thus, the Commission 

may rely on markets for a just and reasonable rate provided that it has made the 

appropriate findings regarding whether sellers lack market power. 

409. The Commission exercises its statutory responsibility under the FPA to ensure that 

market-based rates are just and reasonable through the dual requirement of an ex ante

finding that the seller lacks or has mitigated both horizontal and vertical market power 

and post-approval oversight through reporting requirements and ongoing monitoring. 588 

In granting market-based rate authorization, the Commission thoroughly examines an 

applicant’s market power in the relevant geographic markets. An examination of both 

horizontal (generation market share) and vertical (transmission and other barriers to 

 585 Mobil Oil Exploration, 498 U.S. at 224, citing FPC v. Hope Natural Gas Co., 

320 U.S. at 602; FPC v. Natural Gas Pipeline Co., 315 U.S. at 586; Permian, 390 U.S. at 

776-77; Texaco, 417 U.S. at 386-89; Mobil Oil Corp. v. FPC, 417 U.S. 283, 308 (1974). 

586 Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080. 

587 Elizabethtown Gas, 10 F.3d at 870. See also Tejas Power, 908 F.2d at 1004; 

LEPA, 141 F.3d at 365. 

588 Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080; see also LEPA, 

141 F.3d at 370. 
Docket No. RM04-7-001 -268- 

entry) market power in the relevant markets gives the Commission assurance that the 

seller cannot increase price by restricting supply or denying customers access to 

alternative suppliers. When the Commission determines that a seller lacks or has 

mitigated market power, it is making a determination that the resulting rates will be 

established through competitive forces, not the exercise of market power, and thus will 

fall within a zone of reasonableness which protects customers against excessive rates, on 

the one hand, but allows the seller the opportunity to recover costs and earn a reasonable 

rate of return, on the other hand. This is fully consistent with the fundamental rate 

principles set forth in Hope and Bluefield, supra, and their progeny. In addition, in 

developing its market-based rate regime, the Commission has taken into account non-cost 

factors, recognized as appropriate by the courts, associated with greater reliance on 

competition; specifically, where sellers do not have market power, the Commission 

believes it can encourage greater market entry, greater efficiency and greater innovation 

in meeting the nation’s power needs through allowing such sellers a competitively set 

rate. 

410. Further, the Commission has in place multiple layers of protection for customers 

to ensure that market-based rates are just and reasonable and that they remain so. For 

public utilities selling in real-time and/or day-ahead markets administered by 

Commission-approved ISOs and RTOs (which cover five regions of the country), in 

addition to the market power analysis individual sellers must satisfy under this rule, 

sellers must comply with market rules contained in RTO/ISO tariffs approved by the 

Commission. These single price auction markets set clearing prices based on economic 
Docket No. RM04-7-001 -269- 

dispatch principles to which various safeguards have been added, as appropriate, 

including rules against improper bidding and, in some cases, bid price caps including 

conduct and impact tests. In addition, to ensure that market-based rates, once granted, 

remain just and reasonable and not unduly discriminatory or preferential, the Commission 

has incorporated filing and reporting requirements into the market-based rate program 

(EQRs, change in status filings, regularly-scheduled updated market power analyses). 

These filing requirements help the Commission to monitor potential gains in market 

power and to take remedial steps as appropriate, including revocation of market-based 

rate authority and civil penalties. The Commission has also required each of the 

RTO/ISOs to have market monitors to help oversee their wholesale markets and report to 

the Commission any concerns that market rules have been violated or concerns regarding 

seller behavior. This provides an added level of monitoring against the potential exercise 

of market power in the regional markets administered by the jurisdictional RTO/ISOs. 

411. That market-based rates are permissible under FPA was recently affirmed by the 

Ninth Circuit in Lockyer and Snohomish. In Lockyer, the Ninth Circuit cited with 

approval the Commission’s dual requirement of an ex ante finding of the absence of 

market power and sufficient post-approval reporting requirements and found that the 

Commission did not rely on market forces alone in approving market-based rate tariffs. 

The Ninth Circuit held that this dual requirement was “the crucial difference” between 

the Commission’s regulatory scheme and the FCC’s regulatory scheme, remanded in 
Docket No. RM04-7-001 -270- 

MCI, which had relied on market forces alone in approving market-based rate tariffs.589 

The Ninth Circuit thus held that “California’s facial challenge to market-based tariffs 

fails” and “agree[d] with FERC that both the Congressionally enacted statutory scheme, 

and the pertinent case law, indicate that market-based tariffs do not per se violate the 

FPA.”590 The Ninth Circuit determined that initial grant of market-based rate authority, 

together with ongoing oversight and timely reconsideration of market-based rate 

authorization under section 206 of the FPA, enables the Commission to meet its statutory 

duty to ensure that all rates are just and reasonable.591 While the court in Lockyer found 

that the Commission’s market-based rate reporting requirements were not followed in 

that particular case, it did not find those reporting requirements invalid and, in fact, 

upheld the Commission’s market program as complying with the FPA. The marketbased rate requirements and oversight adopted in this rule are more rigorous than those 

reviewed by the Lockyer court. 

 589 Lockyer, 383 F.3d at 1013. 

590 Id. at 1013 & n.5; id. at 1014 (“The structure of the tariff complied with the 

FPA, so long as it was coupled with enforceable post-approval reporting that would 

enable FERC to determine whether the rates were ‘just and reasonable’ and whether 

market forces were truly determining the price.”). 

591 See Snohomish, 471 F.3d at 1080 (in which the Ninth Circuit discusses its 

decision in Lockyer). In Snohomish, the Ninth Circuit explained, “As in Lockyer, we do 

not dispute that FERC may adopt a regulatory regime that differs from the historical costbased regime of the energy market, or that market-based rate authorization may be a 

tenable choice if sufficient safeguards are taken to provide for sufficient oversight.” Id. 

at 1086. 
Docket No. RM04-7-001 -271- 

412. Accordingly, we find to be without merit the arguments raised on rehearing that 

the Commission lacks authority to continue to permit market-based rates for wholesale 

sales of electric energy. The courts have sustained the Commission’s finding that 

market-based rates are one method of setting just and reasonable rates under the FPA. As 

supplemented by the Final Rule, the Commission finds that the market-based rate 

program complies with the statutory and judicial standards for acceptable market-based 

rates. We address below the specific arguments raised on rehearing. 

413. We reject Consumer Advocates’ argument that the Commission’s market-based 

rate program delegates to others the determination of lawful rates because it allows 

buyers and sellers to negotiate rates. The Commission, and no one else, undertakes the 

up-front analysis described above that a seller lacks or has mitigated market power and 

thus pre-determines that future rates charged by the seller will be just and reasonable. It 

is the Commission, not buyers and sellers, that makes the determination of whether and 

when negotiated rates will be lawful. It is also the Commission, not others, that makes a 

final determination with respect to any market rules or restrictions that must be put in 

place with respect to market-based rate sellers in RTO/ISO markets. 

414. Thus, contrary to Consumer Advocates’ claim, the Commission has not 

“delegat[ed] to wholesale buyers” its ratemaking obligations under the FPA.592 Consumer 

 592 Consumer Advocates Rehearing Request at 10, 12 (citing Entergy Services, 

Inc., 120 FERC ¶ 61,020 (2007) (Entergy), citing Louisiana, Inc. v. Louisiana Public 

Service Comm., 539 U.S. 39, 43 n.1; City of New Orleans v. Entergy Corp., 55 FERC 

¶ 61,211, at 61,729 (1991)). 
Docket No. RM04-7-001 -272- 

Advocates contend that the Commission held that it could not delegate to state 

commissions its “ratemaking obligations under the FPA,” and that it could not delegate 

such rate determinations to “jurisdictional utilities.”593 However, the case relied on by 

Consumer Advocates is distinguishable from the issue here. In Entergy, the Commission 

denied Entergy’s petition for a declaratory order requesting that the Commission find 

that, where a resource to be acquired or constructed by one or more of the Entergy 

Operating Companies has met certain approval requirements, including a public interest 

finding by such retail regulators as may have jurisdiction, the resource shall be a system 

resource and all costs of such facility may be reflected in the applicable formula rates. 

The Commission concluded that there was no local interest comparable to that present in 

the cases relied on by Entergy, and therefore denied Entergy’s request to delegate to state 

commissions, and to Entergy itself, the determination of the reasonableness of Entergy’s 

Commission jurisdictional rates.594 By contrast, in the instant rulemaking proceeding, the 

Commission is not delegating to a state commission or to a utility the determination of 

the reasonableness of Commission jurisdictional rates. Rather, as explained above, in 

granting market-based rate authority, the Commission exercises its statutory 

responsibility under the FPA to ensure that market-based rates are just and reasonable 

through the dual requirement of an ex ante finding of the absence of market power and 

post-approval oversight through reporting requirements and ongoing monitoring. 

 593 Consumer Advocates Rehearing Request at 12. 

594 Entergy Services, Inc., 120 FERC ¶ 61,020 (2007). 
Docket No. RM04-7-001 -273- 

415. Additionally, with respect to Consumer Advocates’ argument that the Commission 

has overlooked the economic fact that wholesale buyers/re-sellers do not bear the risk of 

loss because the prices paid by wholesale buyers/re-sellers “must be passed through to 

retail ratepayers,” not only is this argument irrelevant to whether the Commission has 

legal authority to permit market-based rates as just and reasonable under the FPA, the 

argument also is not accurate.595 It is true that only the Commission has the authority to 

determine the justness and reasonableness of a public utility’s wholesale rates and that a 

state cannot disallow pass-through in retail rates on the basis that it disagrees with the 

Commission’s just and reasonable determination. However, the Commission has 

consistently recognized that wholesale ratemaking does not, as a general matter, 

determine whether a purchaser has prudently chosen among available supply options.596

416. In most circumstances “a state commission may legitimately inquire into whether 

the retailer prudently chose to pay the FERC-approved wholesale rate of one source, as 

 595 Id. at 10. 

596 See Philadelphia Electric Co., 15 FERC ¶ 61,264, at 61,601 (1981); 

Pennsylvania Power & Light Co., 23 FERC ¶ 61,006, order on reh’g, 23 FERC ¶ 61,325, 

at 61,716 (1983) (“We do not view our responsibilities under the Federal Power Act as 

including a determination that the purchaser has purchased wisely or has made the best 

deal available.”); Southern Company Service, 26 FERC ¶ 61,360, at 61,795 (1984); 

Pacific Power & Light Co., 27 FERC ¶ 61,080, at 61,148 (1984); Minnesota Power & 

Light Co., 43 FERC ¶ 61,104, at 61,342-43, reh’g denied, 43 FERC ¶ 61,502, order 

denying reconsideration, 44 FERC ¶ 61,302 (1988); Palisades Generating Co., 48 FERC 

¶ 61,144, at 61,574 and n.10 (1989). 
Docket No. RM04-7-001 -274- 

opposed to the lower rate of another source.”597 It is in the narrow situation where the 

Commission, in setting a wholesale rate, leaves the purchaser no legal choice but to 

purchase a specified amount of power that such determinations would be precluded.598 

Thus, we reject Consumer Advocates’ arguments that these cases are relevant to the issue 

at hand. 

417. We also reject Consumer Advocates’ and NASUCA’s arguments that the Final 

Rule failed to provide an objective standard under which the Commission can determine 

whether rate increases fall within a “zone of reasonableness.”599 As part of their 

argument on rehearing, they again contend that markets alone cannot be relied on to set 

just and reasonable rates. As we explained in the Final Rule and reiterated above, the 

courts have sustained the Commission’s finding that market-based rates are one method 

 597 Pike County Light & Power Co. v. Pennsylvania Public Utility Comm’n, 

465 A.2d 735, 738 (1983) (Pike County) (finding that while the state cannot review the 

reasonableness of the wholesale rate set by the Commission, it may determine whether it 

is in the public interest for the wholesale purchaser whose retail rates it regulates to pay a 

particular price in light of its alternatives). The Supreme Court’s decisions in Nantahala, 

476 U.S. 953 and Mississippi Power & Light Co. v. Mississippi ex rel. Moore, 487 U.S. 

354 (1988) do not preclude, in every circumstance, state regulators from reviewing the 

prudence of a utility’s purchasing decisions. See, e.g., Kentucky West Virginia Gas Co. 

v. Pennsylvania Public Utility Comm’n, 837 F.2d 600, 609 (3d Cir.) cert. denied, 488 

U.S. 941 (1988) (Kentucky West Virginia); Doswell Limited Partnership, 50 FERC 

¶ 61,251, at 61,758 n.18 (1990). 

598 Nantahala, 476 U.S. 953; Mississippi Power & Light Co. v. Mississippi ex rel. 

Moore, 487 U.S. 354 (1988) (Mississippi Power). 

599 Consumer Advocates cite several court cases in support of their argument in 

this regard. We address these cases in detail below. 
Docket No. RM04-7-001 -275- 

of setting just and reasonable rates under the FPA.600 Before granting a seller marketbased rate authority, the Commission requires the seller to demonstrate that it and its 

affiliates lack or have adequately mitigated market power in relevant markets. The 

Commission undertakes a complete analysis of the seller’s horizontal and vertical market 

power in the relevant markets and permits negotiated rates only if the seller demonstrates 

that it lacks or has mitigated market power. While this is not the same “objective 

standard” as cost-of-service ratemaking, which calculates the seller’s costs and 

determines a specific rate of return, it nevertheless provides an objective standard for 

analyzing a seller’s ability to exercise market power and thus determine whether rates 

will fall within a zone which is not excessive to customers and which allows the seller a 

reasonable opportunity to recover costs and earn a reasonable rate of return. In addition, 

the Commission does not rely on the market without adequate oversight. It has adopted 

filing requirements (EQRs and change in status filings for all market-based rate sellers 

and regularly scheduled updated market power analyses for all Category 2 market-based 

rate sellers), market manipulation rules, and enhanced market oversight through its 

enforcement division to help oversee potential market manipulation.601 This approach, 

combined with the opportunity for interested parties to file complaints pursuant to FPA 

section 206, allows us to ensure that market-based rates remain just and reasonable. On 

 600 Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080; see also LEPA, 

131 F.3d at 370.

601 Order No. 697 at P 952, 967. 
Docket No. RM04-7-001 -276- 

this basis, we conclude that the rates charged pursuant to the Commission’s market-based 

rate program fall within the “zone of reasonableness.”602

418. Further, as explained in the Final Rule, we believe that the market-based rate 

program fully complies with judicial precedent.603 In Lockyer, the Ninth Circuit cited 

with approval the Commission’s dual requirement of an ex ante finding of the absence of 

market power and sufficient post-approval reporting requirements and found that the 

Commission did not rely on market forces alone in approving market-based rate tariffs.604 

In Snohomish, the Ninth Circuit again determined that the initial grant of market-based 

rate authority, together with ongoing oversight and timely reconsideration of marketbased rate authorization under section 206 of the FPA, enables the Commission to meet 

its statutory duty to ensure that all rates are just and reasonable.605

419. We disagree with Consumer Advocates’ argument that the “Final Rule also fails to 

explain how FERC, which is not an antitrust agency, acting under the FPA, which is not 

an antitrust statute but a rate filing regulatory statute, can rely entirely on FERC’s oftchanging antitrust analyses regarding ‘market power’ to determine whether ‘market-

 602 See Public Service Company of Indiana, Opinion No. 349, 51 FERC ¶ 61,367 

at 62,226 (determining that market-based rate pricing resulted in rates that were within 

the zone of reasonableness and concluding that such pricing resulted in just and 

reasonable rates), order on reh’g, Opinion No. 349-A, 52 FERC ¶ 61,260, clarified, 

53 FERC ¶ 61,131 (1990), dismissed, Northern Indiana Public Service Company v. 

FERC, 954 F.2d 736 (D.C. Cir. 1992). 

603 Id. P 943-955. 

604 Lockyer, 383 F.3d at 1013. 
Docket No. RM04-7-001 -277- 

based rates’ are within a zone of reasonableness.”606 As explained in the section of the 

Final Rule addressing the Commission’s horizontal market power analyses,607 when the 

Commission determines whether an applicant may sell wholesale electric power at 

market-based rates, it evaluates whether a seller lacks, or has adequately mitigated, 

market power in a particular market. When the Commission determines that a seller 

lacks both horizontal and vertical market power, it is making a determination that the 

resulting rates will be established through competitive forces, not the exercise of market 

power. Thus, rates resulting from competitive forces will not be excessive to customers 

and will allow the seller the opportunity to earn a fair return. As we explained in the 

Final Rule and reiterate above, the courts have sustained the Commission’s finding that 

market-based rates are one method of setting just and reasonable rates under the FPA. 

Further, market monitoring by both the RTO/ISO market monitors and by the 

Commission help ensure that rates remain within a zone of reasonableness. Thus, we 

reject Consumer Advocates’ argument that the Commission has failed to explain how it 

“determine[s] whether ‘market-based rates’ are within a zone of reasonableness.” 

420. We also reject Consumer Advocates’ contention that the Final Rule erroneously 

relied on NGA cases and Interstate Commerce Act oil pipeline cases. The most recent 

court cases affirming the Commission’s market-based rate authority under the FPA cite to 

 605 Snohomish, 471 F.3d at 1080. 

606 Consumer Advocates Rehearing Request at 13. 

607 See, e.g., Order No. 697 at P 62-79. 
Docket No. RM04-7-001 -278- 

the very same NGA and Interstate Commerce Act oil pipeline cases that the Commission 

discusses in the Final Rule.608 It is settled law that market-based rates can satisfy the just 

and reasonable standard of the FPA, as most recently affirmed by the Ninth Circuit in 

Lockyer and Snohomish.

609 The court in Lockyer expressly denied a “facial challenge to 

market-based [rate] tariffs.”610 Further, the Lockyer court’s analysis of the 

Commission’s market-based rate authority acknowledged that the use of market-based 

tariffs was first approved by the courts as to sellers of natural gas in Elizabethtown Gas, 

then as to wholesale sellers of electric energy in LEPA.611 The Lockyer court also cited 

the Supreme Court’s determination in Mobil Oil Exploration that “‘the just and 

reasonable standard does not compel the Commission to use any single pricing 

formula....’”612 Additionally, Elizabethtown Gas, a decision wherein the D.C. Circuit 

determined that markets were sufficiently competitive to preclude a pipeline from 

exercising market power to assure that prices were just and reasonable within the 

meaning of NGA section 4, was relied on by the D.C. Circuit in LEPA, a case in which 

the court affirmed the Commission’s approval of an application by CLECO to sell 

 608 Order No. 697 at P 953; see Lockyer, 383 F.3d at 1011-1014. 

609 Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080. 

610 Lockyer, 383 F.3d at 1013. 

611 Id. at 1012 (citing Elizabethtown Gas, 10 F.3d at 870; LEPA, 141 F.3d at 365). 

612 Id. (citing Mobil Oil Exploration, 498 U.S. at 224). 
Docket No. RM04-7-001 -279- 

electric energy at market-based rates under the FPA.613 Accordingly, we find that the 

Commission did not err in citing NGA and Interstate Commerce Act oil pipeline cases in 

the Final Rule. 

421. We also reject Consumer Advocates’ argument that the Final Rule incorrectly 

cites cases supporting the proposition that “[c]ases under the NGA and FPA are typically 

read in pari materia” because this language refers to the filing and rate review provisions 

of the two statutes, not the different cost elements of the electric and natural gas 

industries.614 Sierra and Arkansas-Louisiana Gas Co. v. Hall,

615 are correctly cited by 

the Final Rule for the proposition that cases under the NGA and FPA are typically read in

pari materia. The Final Rule noted this proposition in its discussion of Texaco, a case in 

which the Supreme Court held that the NGA permits the indirect regulation of smallproducer rates; however, in citing this proposition, the Final Rule did not claim that the 

cost elements of the electric and natural gas industries are the same. Further, the Final 

Rule clearly explained that Texaco may be distinguished from the market-based rate 

regime set forth in the Final Rule, stating “[i]n the market-based rate program adopted in 

the this rule and through other Commission actions, unlike the situation in Texaco, the 

Commission is not relying solely on the market, without adequate regulatory oversight, to 

 613 LEPA, 141 F.3d at 365 (citing Elizabethown Gas, 10 F.3d at 870). 

614 Consumer Advocates Rehearing Request at 19 (citing Order No. 697 at P 946, 

n.1070). 

615 453 U.S. 571, 578 n.7 (1981). 
Docket No. RM04-7-001 -280- 

set rates.”616 Accordingly, Consumer Advocates’ argument that the citation in the Final 

Rule to Sierra and Arkansas-Louisiana Gas Co. v. Hall is incorrect disregards the context 

in which these cases were cited. 

422. We find Consumer Advocates’ argument that the market-based rate regime gives 

plant owners an incentive to keep power supplies tight to raise their profits to be without 

merit. The two indicative horizontal market power screens, each of which serves as a 

cross-check on the other to determine whether sellers possess market power, take into 

account the availability of generating capacity. In particular, the first screen, the 

wholesale market share screen, measures for each of the four seasons whether a seller has 

a dominant position in the market based on the number of megawatts of uncommitted 

(available generation) capacity owned or controlled by the seller as compared to the 

uncommitted capacity of the entire relevant market.617 The second screen is the pivotal 

supplier screen, which evaluates the potential of a seller to exercise market power based 

on uncommitted capacity at the time of the balancing authority area’s annual peak 

demand. This screen focuses on the seller’s ability to exercise market power unilaterally 

and examines whether the market demand can be met absent the seller during peak 

times.618 

 616 Order No. 697 at P 952. 

617 Id. P 34 (citing April 14 Order, 107 FERC ¶ 61,018 at P 100). 

618 Id. P 35. 
Docket No. RM04-7-001 -281- 

423. If there is not sufficient competing uncommitted capacity, a seller fails the pivotal 

supplier analysis, which creates a rebuttable presumption of market power.619 Thus, 

through the use of the indicative horizontal market power screens, the Commission 

ensures that market-based rate sellers are not able to exercise market power and thereby 

should ensure that there is no incentive for plant owners to keep power supplies tight.620

424. Additionally, 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. Thus, if a market-based rate seller acquires ownership or control of 

generation capacity that results in a net increase of 100 MW or more, or of inputs to 

electric power production, or ownership, operation or control of transmission facilities, or 

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 

 619 Id. P 65. 

620 Consumer Advocates cite the Commission’s decision in Richard Blumenthal v. 

ISO New England, Inc., 117 FERC ¶ 61,038 (2006), reh’g denied, 118 FERC ¶ 61,205 

(2007) (Blumenthal) to support their statement that “in the Connecticut complaint against 

the ISO New England, the Complaint showed that excessive rates of return were being 

made, but the Commission found this ‘not relevant.’” Consumer Advocates Rehearing 

Request at 19. Consumer Advocates’ argument in this regard is not clear because they do 

not explain how the fact-specific determinations made by the Commission in addressing 

the section 206 complaint at issue in Blumenthal relate to the Commission’s policy of 

granting market-based rate authority to sellers without market power under the terms and 

conditions set forth in the Final Rule. In Blumenthal, the Commission denied a 

complaint filed against the ISO New England upon concluding that the complainants had 

not met their burden under section 206 to establish that the current provisions of the ISO 

New England’s Market Rule 1 were unjust and unreasonable. 
Docket No. RM04-7-001 -282- 

production, the seller must report the change to the Commission so that the Commission 

may re-evaluate whether the seller is able to exercise market power.621

425. We reject Industrial Customers’ argument that the Final Rule does not reflect 

reasoned decision-making because the Commission did not find the existence of a 

competitive market before relying on market-based rate authority. Under the FPA, the 

Commission is not bound to a particular ratemaking methodology in setting rates as long 

as rates fall within a zone of reasonableness,622 i.e., the rates are neither less than 

compensatory to the seller nor excessive to the consumer.623 In addition, the “zone of 

reasonableness” may take into account all relevant public interests, both existing and 

foreseeable.624 These public interests may appropriately include non-cost factors, such as 

 621 18 CFR 35.42. 

622 FPC v. Hope Natural Gas, 320 U.S. 591, 602 (1944) (“[u]nder the statutory 

standard of ‘just and reasonable’ it is the result reached not the method employed which 

is controlling”); Permian, 390 U.S at 776-777 (“rate-making agencies are not bound to 

the service of any single regulatory formula; they are permitted, unless their statutory 

authority otherwise plainly indicates, ‘to make the pragmatic adjustments which may be 

called for by particular circumstances,’” citing FPC v. Natural Gas Pipeline Co., 315 U.S. 

575, 586 (1942)). 

623 Bluefield, 262 U.S. at 692-93 (1923). 

624 Farmers Union, 734 F.2d at 1501 (citing Permian, 390 U.S. at 790 (“Congress 

delegated ratemaking authority to FERC in broad terms. Accordingly, ‘the breadth and 

complexity of the Commission’s responsibilities demand that it be given every 

reasonable opportunity to formulate methods of regulation appropriate for the solution of 

its intensely practical difficulties’”)). 
Docket No. RM04-7-001 -283- 

the need to stimulate additional investment.625 In permitting market-based rates in its 

regulation of electric markets, there are two approaches the Commission has used to 

ensure that rates are just and reasonable: either a finding that an individual seller and its 

affiliates lack or have mitigated market power in a particular market; or a finding that a 

particular market is competitive or yields competitive results. Since the mid-1980’s, the 

Commission’s approach in the electric area has been primarily to rely on an analysis of 

individual seller market power, as was recently affirmed in the Final Rule. In addition, 

with regard to rates for sales within RTO/ISOs, even if sellers have been found to lack 

market power on an individual seller basis, the Commission has relied on a blend of 

market and cost-based elements, e.g., some form of cost cap or mitigated bids, to ensure 

just and reasonable rates.626

 625 While the court in Farmers Union found that the Commission had failed to 

demonstrate that its ruling in the underlying orders would, in fact, stimulate new 

investment, the court acknowledged that such “non-cost factors may legitimate a 

departure from a rigid cost-based approach.” Farmers Union, 734 F.2d at 1502 (citing 

FERC v. Pennzoil Producing Co., 439 U.S. at 518; Mobil Oil Corp. v. FPC, 417 U.S. at 

308).

626 See Order No. 697 at P 952. At the time the Commission approved the tariffs 

for ISO New England, the New York Independent System Operator, and PJM, it applied 

mitigation procedures in markets administered by those organizations, and incorporated 

those procedures in the RTO/ISO tariffs so as to apply to all sellers in the RTO/ISO 

administered markets. See New England Power Pool, 85 FERC ¶ 61,379 (1998); Central 

Hudson Electric & Gas Corp., 86 FERC ¶ 61,062 (1999); Atlantic City Electric Co., 

86 FERC ¶ 61,248 (1999). See also AEP Power Marketing, Inc., 109 FERC ¶ 61,276 

(2004), reh’g denied, 112 FERC ¶ 61,320, at P 23 (2005) (after finding that AEP passed 

the generation market power screening test in PJM, the Commission also noted that 

“RTOs such as PJM with Commission-approved market monitoring and mitigation 

provide a check on the exercise of generation market power”), aff’d sub nom. Industrial 

Energy Users-Ohio v. FERC, No. 05-1435, 2007 U.S. App. LEXIS 3661, at *2 (D.C. Cir. 

(continued...) 
Docket No. RM04-7-001 -284- 

426. The Commission has previously considered a similar argument (that the 

Commission must find that a market is competitive before it can permit market-based 

rates) with regard to the Midwest ISO (MISO), and rejected it. We stated: 

The Commission rejects MISO Industrial Customers’ argument that, as a 

prerequisite to reliance upon market-based rate pricing to produce just and 

reasonable rates, the Commission must, in addition to finding that 

applicants lack or have adequately mitigated market power, make a separate 

and independent finding that a competitive market exists. . . . We . . . 

incorporate by reference the Commission’s discussion in its final rule on 

market-based rates (Order No. 697 [at P 943-71]) of the legality of its 

approach to market-based rates. The Commission’s long-established 

approach involves assessing whether a seller lacks market power, which 

includes an assessment of seller-specific market power. This approach, 

combined with the Commission’s filing requirements and ongoing 

monitoring, allows the Commission to ensure that market-based rates 

remain just and reasonable. Additionally, for sellers in RTO/ISO organized 

markets, the Commission has in place market monitoring and mitigation 

rules to mitigate the exercise of market power, including price caps where 

appropriate, and the Commission also uses RTO/ISO market monitors to 

help oversee market behavior and market conditions. . . .[

627] 

427. As we explained in the Final Rule, we retained our approach to determining 

whether a seller should receive authorization to charge market-based rates, as modified 

by the Final Rule, by analyzing seller-specific market power. We have a long-established 

approach when a seller applies for market-based rate authority of focusing on whether the 

seller lacks market power.628 

 

Feb. 16, 2007) (noting that “the Commission adequately considered and responded to 

petitioner’s arguments”) (unpublished). 

627 Midwest Independent Transmission System Operator, Inc., 120 FERC ¶ 61,202 

at P 9, 12 (2007). 

628 Order No. 697 at P 955 (citing Heartland Energy Services, Inc., 68 FERC 

¶ 61,223, at 62,060-61 (1994); Louisville Gas and Electric Co., 62 FERC ¶ 61,016, at 

(continued...) 
Docket No. RM04-7-001 -285- 

428. We reject Industrial Customers’ argument that the Final Rule is inconsistent with 

Farmers Union because that case requires the Commission to point to “empirical proof” 

that competitive markets exist.629 The regulatory scheme at issue in Farmers Union is 

distinguishable from the Commission’s market-based rate program. In Farmers Union, a 

case concerning rates for oil pipelines, the court found that the Commission “sought to 

establish maximum rate ceilings at a level far above the ‘zone of reasonableness’ required 

by the statute.”630 The court found that the Commission departed from established 

ratemaking principles when the Commission determined that oil pipeline rate regulation 

should “protect against only ‘egregious price exploitation and gross abuse’” by the 

regulated pipelines,631 since “the cost of pipeline transportation, relative to the price of 

oil, had become so insignificant that close regulation was not required.”632 The court 

found error in the Commission’s approach, finding that there was “only anecdotal 

 

61,143 n.16 (1993) (and the cases cited therein); Citizens Power & Light Corp., 48 FERC 

¶ 61,210, at 61,776 & n.11 (1989); Pacific Gas and Electric Co. (Turlock), 42 FERC 

¶ 61,406, at 62,194-98, order on reh’g, 43 FERC ¶ 61,403 (1988); Pacific Gas and 

Electric Co. (Modesto), 44 FERC ¶ 61,010, at 61,048-49, order on reh’g, 45 FERC 

¶ 61,061 (1988). See also, e.g., LEPA, 141 F.3d at 365; Consumers Energy Co., 

367 F.3d 915, 922-23 (D.C. Cir. 2004) (upholding Commission orders granting marketbased rate authority, noting that the Commission’s longstanding approach is to assess 

whether applicants for market-based rate authority do not have, or have adequately 

mitigated, market power); Lockyer, 383 F.3d at 1012-1013. 

629 Industrial Customers Rehearing Request at 7. 

630 Farmers Union, 734 F.2d at 1501. 

631 Id. at 1502 (citation omitted; emphasis supplied by court). 

632 Id. at 1507. 
Docket No. RM04-7-001 -286- 

evidence of intermodal competition on certain pipeline routes[,]”633 and noted that the 

Commission’s “evaluation of competition in the oil pipeline industry is not entirely 

clear.”634 The court concluded that “the fundamental flaw in the Commission’s scheme” 

was that “nothing in the regulatory scheme itself acts as a monitor to see if [actual prices 

are driven back down into the zone of reasonableness] or to check rates if [prices are not 

driven down].635 In this regard, the court also explained that: 

In setting extraordinarily high price ceilings as a substitute for close 

regulation, FERC assumed that, with the wide exposed zone between the 

ceiling and the ‘true’ market rate, existing competition would ensure that 

the actual price is just and reasonable. Without empirical proof that it 

would, this regulatory scheme, however, runs counter to the basic 

assumption of statutory regulation, that ‘Congress rejected the identity 

between the ‘true’ and the ‘actual’ market price.’636

Thus, the court found that the fundamental flaw in the Commission’s regulatory scheme 

in Farmers Union was that there was no monitoring. 

429. The Farmers Union court found that the Commission’s “largely undocumented 

reliance on market forces as the principal means of rate regulation” was misplaced.637 In 

this regard, it noted that “when Congress amended the Interstate Commerce Act to 

account for competition in the rail carrier industry, the amendment required the ICC to 

 633 Id. at 1509. 

634 Id. n.50. 

635 Id. at 1509 (citation omitted). 

636 Id. at 1510. 

637 Id. at 1508 (footnote omitted). 
Docket No. RM04-7-001 -287- 

make a specific finding that a particular rail carrier did not have ‘market dominance’ 

before deregulating the carrier. . . . We do not believe that the unamended oil pipeline 

rate provisions of the Interstate Commerce Act, which do not make any provision for 

deregulation, would require any less of a particularized showing before competition 

might be properly taken into account.”638 The court nonetheless concluded that “‘noncost’ factors may play a legitimate role in the setting of just and reasonable rates.”639 It 

also found that “[m]oving from heavy to lighthanded regulation within the boundaries set 

by an unchanged statute can, of course, be justified by a showing that under current 

circumstances the goals and purposes of the statute will be accomplished through 

substantially less regulatory oversight.”640

430. The defects that the court found to be present in the regulatory scheme under 

review in Farmers Union are not present in the Commission’s market-based rate program. 

As an initial matter, in the case under review in Farmers Union, the Commission had not 

undertaken any analysis of the sellers participating in the oil pipeline industry as part of 

its decision to adopt a generic ratemaking methodology to be applied to all oil pipelines. 

Unlike Farmers Union, before granting a seller market-based rate authority, the 

Commission performs an initial evaluation to determine whether the seller or any of its 

affiliates has horizontal or vertical market power and, if so, whether such market power 

 638 Id. at n. 50.

639 Id. at 1503. 

640 Id. at 1510. 
Docket No. RM04-7-001 -288- 

has been mitigated. The Commission only permits a seller to use market-based rate 

pricing if the Commission finds that the seller lacks, or has adequately mitigated, market 

power in the relevant market. 

431. Similarly, unlike Farmers Union, where the court identified as a “fundamental 

flaw” the absence of any monitoring to ensure that rates remain within a zone of 

reasonableness, the market-based rate program does not rely solely on the market, 

without adequate regulatory oversight, to determine rates. Rather, the market-based rate 

program includes post-approval oversight through reporting requirements and ongoing 

monitoring. In addition, market monitoring by the Commission helps ensure that rates 

remain within a zone of reasonableness.641 Thus, the Commission’s market-based rate 

program does not contain the defects that the court found to be present in Farmers 

Union,

642 and is not arbitrary and capricious because, contrary to Industrial Customers’ 

assertions, under the market-based rate program the Commission performs an initial 

evaluation of all sellers before granting market-based rate authority, and because the 

market-based rate program includes adequate oversight and monitoring. 

 641 On this basis, we find State AGs and Advocates’ reliance on Farmers Union to 

support their argument that the Final Rule failed to provide a standard under which the 

Commission can determine whether rate increases fall within a “zone of reasonableness” 

to be misplaced. 

642 See Midwest Independent Transmission System Operator, Inc., 120 FERC 

¶ 61,202, at P 9, 12 (2007); PJM Interconnection, L.L.C., 121 FERC ¶ 61,173, at P 22 

(2007). 
Docket No. RM04-7-001 -289- 

432. Industrial Customers contend that the Final Rule is inconsistent with the 

Commission’s decision in Southwest Power Pool, Inc. (SPP) where the Commission 

made a finding that the market was competitive before approving market-based rates for 

an energy imbalance service.643 In SPP, the Commission found that the SPP imbalance 

market is competitive in the absence of transmission constraints, and that SPP’s 

mitigation measures and monitoring plan are sufficient to protect customers from the 

exercise of market power that might occur in the energy imbalance market when 

transmission constraints bind.644 We reject Industrial Customers’ contention that the 

Commission may only grant market-based rate authorization if it first analyzes whether a 

competitive market exists. As explained above, the Commission has discretion645 to rely 

on an analysis of individual seller market power, as was affirmed in the Final Rule, and 

the courts have upheld this approach.646 Our use of this approach for SPP does not 

require its use elsewhere. At the same time, the Commission will allow RTO/ISOs to 

 643 116 FERC ¶ 61,289, at P 30 (2006), appeal pending sub nom., Southwest 

Indus. Customer Coalition v. FERC, No. 06-1390, et al. (D.C. Cir. Nov. 27, 2006). 

644 Id. 

645 See e.g., Exxon Co., USA v. FERC, 182 F.3d 30, 37-38 (D.C. Cir. 1999) 

(stating that where “the analysis to be preformed ‘requires a high level of technical 

expertise, we must defer to the informed discretion of the responsible federal agencies.’”) 

(internal citation omitted); Oxy USA, Inc. v. FERC, 64 F.3d 679, 690-91 (D.C. Cir. 

1995). 

646 Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080; LEPA, 141 F.3d at 

370. 
Docket No. RM04-7-001 -290- 

conduct market power studies that the RTO/ISO members can rely on in their market 

power filings, which will help ensure the accuracy and consistency of data. 

433. With regard to Industrial Customers’ contention that there are market power issues 

prevalent in the PJM, Midwest ISO, Southwest Power Pool, and ISO New England 

markets, we find that such issues are beyond the scope of this proceeding. The instant 

rulemaking proceeding codifies and revises the Commission’s standards for market-based 

rates and streamlines the administration of the market-based rate program; however, this 

rulemaking is not intended to evaluate market power issues with regard to particular 

markets throughout the United States. 

2. Consistency of Market-Based Rate Program with FPA Filing 

Requirements

a. Whether the Multiple Layers of Filing and Reporting 

Requirements Incorporated into the Market-Based Rate 

Program Provide Adequate Protection from Excessive 

Rates

Final Rule

434. In rejecting Consumer Advocates’ arguments that the Commission’s market-based 

rate program fails to comply with the FPA,647 the Commission pointed out in the Final 

Rule that the FPA requires that every public utility file with the Commission “‘schedules 

showing all rates and charges for any transmission or sale subject to the jurisdiction of 

the Commission,’” but it explicitly leaves the timing and form of those filings to the 

 647 Order No. 697 at P 959. 
Docket No. RM04-7-001 -291- 

Commission’s discretion.648 The Commission noted that the courts have recognized the 

Commission’s discretion in establishing its procedures to carry out its statutory 

functions.649 The Commission explained that the market-based rate tariff, with its 

appurtenant conditions and requirement for filing transaction-specific data in EQRs, is 

the filed rate.650 

435. The Commission also disagreed with Consumer Advocates’ arguments that the 

Commission failed to show how competitive market-based rates are just and reasonable 

and not unduly discriminatory or preferential, stating “the standard for judging undue 

discrimination or preference remains what it has always been: disparate rates or service 

for similarly situated customers.”651 The Commission explained that rates do not have to 

be set by reference to an accounting cost of service to be just, reasonable and not unduly 

discriminatory, stating that when the Commission determines that a seller lacks market 

power, it is making a determination that the resulting rates will be established through 

competition, not the exercise of market power. The Commission also explained that 

 648 Id. (quoting 16 U.S.C. 824d(c)). 

649 Id. P 960 (citing Lockyer, 383 F.3d at 1013; Wabash Valley Power Association 

v. FERC, 268 F.3d 1105, 1115 (D.C. Cir. 2001), Environmental Action v. FERC, 

996 F.2d 401, 407-08 (D.C. Cir. 1993)). 

650 Id. P 961. The Commission further noted that it has held that if every service 

agreement under a previously-granted market-based rate authorization had to be filed 

prior to approval, then the original market-based rate authorization would be a pointless 

exercise. Id. (citing GWF Energy LLC, 98 FERC ¶ 61,330, at 62,390 (2002)). 

651 Id. P 963 (citing Southwestern Electric Cooperative, Inc. v. FERC, 347 F.3d 

975, 981 (D.C. Cir. 2003)). 
Docket No. RM04-7-001 -292- 

courts have upheld the Commission’s determinations that rates that are established in a 

competitive market can be just, reasonable and not unduly discriminatory.652

436. In the Final Rule, the Commission disagreed with Consumer Advocates’ argument 

that the market-based rate program eliminates the statutory mandate that all rate increases 

be noticed by filing 60 days in advance and, if warranted, suspended for up to five 

months, set for hearing with the burden of proof on the seller, and made subject to refund 

pending the outcome of the hearing.653 The Commission explained that it has developed 

a thorough process to evaluate the sellers that it authorizes to enter into transactions at 

market-based rates.654 Under the market-based rate program, the rate change is initiated 

when a seller applies for authorization of market-based rate pricing. All applications are 

publicly noticed, entitling parties to challenge a seller’s claims. At that time, there is an 

opportunity for a hearing, with the burden of proof on the seller to show that it lacks, or 

has adequately mitigated, market power, and for the imposition of a refund obligation.655 

Additionally, if a seller is granted market-based rate authority, it must comply with postapproval reporting requirements, including the quarterly filing of transaction-specific data 

in EQRs, change in status filings for all sellers, and regularly-scheduled updated market 

 652 Id. (citing Lockyer, 383 F.3d at 1012-13; Tejas Power Corp. v. FERC, 980 F.2d 

998, 1004 (D.C. Cir. 1990)). 

653 Id. P 962. 

654 Id. 

655 Id. 
Docket No. RM04-7-001 -293- 

power analyses for Category 2 sellers.656 In the Final Rule the Commission explained 

that it may, based on its review of EQR filings or daily market price information, 

investigate a specific utility or anomalous market circumstances to determine whether 

there has been any conduct in violation of RTO/ISO market rules or Commission orders 

or tariffs, or any prohibited market manipulation, and take steps to remedy any violations. 

These steps could include, among other things, disgorgement of profits and refunds to 

customers if a seller is found to have violated Commission orders, tariffs or rules, or a 

civil penalty.657 

Requests for Rehearing

437. Consumer Advocates contend in their request for rehearing that the Final Rule 

failed to provide a standard for determining prohibited undue preference or 

discrimination under the Commission’s market-based rate regime.658 In particular, 

Consumer Advocates argue that the traditional FPA section 205(b) standard has no 

apparent application to market-based rates because such rates, by definition, are allowed 

to be any rate for any service on which the seller and buyer agree, regardless of the 

relation of such prices or services to any other market-based rate or service.659 Consumer 

Advocates assert that the Final Rule relies on buyers to negotiate non-excessive rates, and 

 656 Id. 

657 Id. P 964. 

658 Consumer Advocates Rehearing Request at 14 (citing 16 U.S.C. 824d(b)). 

659 Id. 
Docket No. RM04-7-001 -294- 

if the buyer is an affiliate or a competitor, the rationale supporting the idea that 

disinterested sellers and buyers will negotiate non-discriminatory rates, disappears 

altogether.660 They also argue that the Final Rule does not provide a reason for why 

long-term affiliate sales service agreements should not be filed.661 Consumer Advocates 

further argue that the Final Rule erred in assuming that the Commission’s statutory role is 

to protect electricity markets, regardless of the impact on consumers.662 They argue that 

the FPA was enacted to protect consumers from the market,663 and that mere market 

incentives alone cannot be relied upon to protect the public interest. 

438. Consumer Advocates contend that the Final Rule erred in finding that the 

Commission has legal authority to eliminate the Congressionally-mandated consumer 

protections of FPA section 205(e).664 Specifically, they argue that the Final Rule 

continues to effectively define rate increases out of existence by claiming that none 

occur, and in so doing, eliminates the FPA-mandated prior rate filings and review of rate 

increases required by section 205(d).665 Consumer Advocates argue that this definitional 

 660 Id. at 15. 

661 Id.

662 Id. at 21-22. 

663 Id. at 22 (citing Atlantic Ref. Co. v. Pub. Serv. Comm’n of State of N.Y., 360 

U.S. 378, 388 (1959); United Gas Pipe Line Co. v. Mobile Gas Service Corp., 352 U.S. 

332 (1956) (United Gas Pipe Line); Sierra; Electrical District No. 1 v. FERC, 774 F.2d 

490 (D.C. Cir. 1985) (Electrical District). 

664 Id. 

665 Id. 
Docket No. RM04-7-001 -295- 

ploy eliminates both the Commission’s and the consumers’ ability to exercise their 

statutory rights under section 205(e) applying to rate increases, including the opportunity 

for suspension of excessive rates, hearings with the burden of proof on sellers to justify 

rate increases and with immediately effective refund with interest obligations for 

consumers who are found to have paid excessive rates.666 Consumer Advocates contend 

that neither the Commission nor any court has the legal authority to gut these statutory 

protections for consumers against excessive rates, and the Final Rule erred in claiming 

such authority for either court or agency.667 

439. Consumer Advocates argue that because rate increase filings are controlled by a 

different FPA provision, the Final Rule erred in relying on the Commission’s discretion 

as to the form and timing of filings of initial rates as legal justification for eliminating 

prior filings of rate increases under market-based rate tariffs. They assert that the Final 

Rule relied on the Commission’s discretion under section 205(c) as to the form and 

timing of rate schedule filings to legally justify eliminating the FPA-mandated filing of 

specific rates and rate increases, yet insisted that the filing of market-based rate tariff 

authorizations is a “‘change’” in rate, and the filing of subsequent actual charges are 

merely filings in satisfaction of Commission-created “‘reporting requirements.’”668 

Consumer Advocates also contend that one serious flaw in this argument is that section 

 666 Id. 

667 Id. 

668 Id. at 23 (citing Order No. 697 at P 960; 962-63). 
Docket No. RM04-7-001 -296- 

205(d), not section 205(c), controls “‘changes’” in rates, and section 205(d) does not 

offer the same discretion as to the form and timing of rate increase filings.669 

440. Consumer Advocates contend that the market-based rate tariff authorization 

application would be, as a change in rate, subject to section 205(d), not section 205(c). 

They argue that the relied-upon discretion provided does not apply to any market-based 

rate, because under the legal logic of the Final Rule there never are any initial marketbased rates filed.670 According to Consumer Advocates, the Lockyer decision also relied 

erroneously on the Commission’s discretion under section 205(c) as authority to approve 

the Commission’s elimination of section 205(d) prior filings of rate changes.671 

Consumer Advocates conclude that the Final Rule erred insofar as: (1) it failed to 

explain how the Commission’s market-based rate authorization orders satisfy these plain 

requirements of section 205(d), which must apply to market-based rate tariff 

authorizations, as “‘changes’” in rates; (2) market-based rate authorizations fail to specify 

either a change in the amounts to be charged or the time when such new charges will go 

into effect; and (3) all subsequent actual increases in charges under the market-based rate 

 669 Id. 

670 Id. at 23-24. 

671 Id. at 24 (citing Lockyer, 383 F.3d at 1013; Order No. 697 at P 960). 

Consumer Advocates state that section 205(d) requires that all rate increases and other 

changes in rates or charges must be filed 60 days in advance of being charged, unless the 

Commission for good cause shown issues an order “‘specifying the changes’” to be made 

to the rates and charges, and specifying “‘the time when the change or changes will go 

into effect.’” Id. 
Docket No. RM04-7-001 -297- 

tariff, according to the Final Rule’s logic, are not changes in the rate, but merely reports, 

or EQRs, no matter how dramatically actual prices increase.672 

441. Consumer Advocates contend that the Final Rule claimed that the Commission 

can suspend the use of market-based rate tariffs when they are first filed, but does not try 

to justify either the consumer-protection rationale or the legal authority for its attempted 

elimination of the Commission’s ability to suspend all subsequent excessive rate 

increases under market-based “‘rates.’”673 Consumer Advocates contend that Lockyer

acknowledges that the Commission’s ability to suspend excessive rate increases is lost 

under the market-based rate regime, but appears to believe that the Commission can 

eliminate such protections if it so chooses.674 Consumer Advocates state that Lockyer

does not acknowledge the other consumer protections that are eliminated by the 

Commission’s definition of “‘change’” as including none of the specific rate charges filed 

as “‘reports.’” They contend that loss of rate suspensions alone eliminates 8 months of 

potential consumer protection from excessive rates: 5 months of the Commission’s lost 

ability to suspend rate increases and 3 months before the rates are even seen in reports 

and can be set for hearing under section 206.675 Consumer Advocates assert that this 

 672 Id. at 24-25. 

673 Consumer Advocates Rehearing Request at 31. 

674 Id. at 30. 

675 Id. at 31. 
Docket No. RM04-7-001 -298- 

result is directly contrary to Congress’ intent in the Energy Policy Act of 2005676 to 

extend the filing provisions of sections 205(c) and (d) to non-public transmitting utilities, 

and to reduce the time before section 206 rates can be made subject to refund.677

442. NASUCA argues that the Commission did not articulate an adequate legal basis to 

support the Final Rule’s reduced market power review and filing requirements.678 While 

NASUCA notes that the Final Rule responded to its concerns, citing the decision of the 

Ninth Circuit in Lockyer and relying on FPA section 205(c) as authority to adjust the 

timing of rate filing, 679 NASUCA contends that the adjacent statutory language of 

section FPA 205(d) limits that power.680 NASUCA argues that “[t]he ‘crucial difference’ 

between impermissible exclusive reliance on market rates found in the Lockyer decision 

... is absent in the revisions made in the Final Rule.”681 NASUCA also contends that the 

Ninth Circuit mistakenly believed that the Commission looks at a seller’s market power 

reviews in triannual reviews, i.e. conducted once every four months, rather than triennial 

reviews, i.e. once every three years.682 NASUCA concludes that the actions being taken 

 676 Pub. L. No. 109-58, 119 Stat. 594 (2005). 

677 Consumer Advocates Rehearing Request at 31 (citing 119 Stat. 594 sections 

1285 and 1290(a)(2)). 

678 NASUCA Rehearing Request at 17. 

679 Id. (citing Order No. 697 at P 953-954). 

680 Id. at n.16. 

681 Id. at 17. 

682 Id. at 18. 
Docket No. RM04-7-001 -299- 

to streamline filing requirements eliminate market power reviews for many sellers, and 

that to rely mainly on a post hoc monitoring process does not constitute the “bond” of 

protection required for consumers.683 

443. Consumer Advocates argue that the Final Rule erred in failing to explain what 

authority the Commission has to eliminate the statutory remedy of refunds of excessive 

charges, with interest, under section 205(e), and replace it with only disgorgement of 

excess profits or civil penalties whenever market manipulators are caught.684 They 

contend that the Final Rule erred in relying on the Lockyer decision’s erroneous finding 

that, because the market-based rate regime eliminates section 205(e) refunds for 

excessive charges paid, the Commission must create and substitute a new refund remedy 

to replace them.685 Consumer Advocates assert that courts may not rewrite statutes or 

direct agencies to do so.686 They argue that the Final Rule failed to explain (1) how 

Lockyer’s curious “two wrongs make a right” approach is within the Ninth Circuit’s 

authority, since only Congress can change a statute, (2) how Lockyer’s new remedy helps 

consumers, who are supposed to receive refunds from excessive charges paid, not 

administrative penalties for reports that have been omitted; and (3) how the Lockyer

 683 Id. (citing Order No. 697 at P 958-59). 

684 Id. at 32-33. 

685 Id. at 32. 

686 Id. (citing MCI; Southwestern Bell). 
Docket No. RM04-7-001 -300- 

decision’s remedy replaces section 205(e)’s other eliminated consumer protections—

prior review, suspension, and hearings with burden of proof on the seller.687 

444. Consumer Advocates also contend that punishing manipulators, as the Final Rule 

proposed to do, is fine, but it does not make whole customers who have paid excessive 

rates set in part by those who manipulated the market.688 They note that the Colorado 

Consumers Counsel section 206 proceeding is a case in which the Commission made the 

rates subject to refund under section 206 and subsequently found that all market-based 

rate tariffs which didn’t have behavior rules attached were unjust and unreasonable and 

that the Commission ordered no refunds, but merely added behavior conditions to the 

market-based rate tariffs prospectively.689

445. Consumer Advocates also argue that the Final Rule erred in assuming that the 

Ninth Circuit and the D.C. Circuit are authorized to eliminate or affirm agency 

elimination of statutory consumer protections that Congress has enacted into law.690 

They state that agencies are bound, not only by the ultimate purposes Congress has 

selected, but by the means it has deemed appropriate and prescribed for the pursuit of 

those purposes.691 They argue that in sections 205(d) and (e) of the FPA, Congress chose 

 687 Id. at 33-34. 

688 Id. at 33. 

689 Id. (citing 97 FERC ¶ 61,220 (2001); 105 FERC ¶ 61,218 (2003); 107 FERC 

¶ 61,175 (2004)). 

690 Id. at 34. 

691 Id. at 36 (citing MCI, 512 U.S. at 231 n.4). 
Docket No. RM04-7-001 -301- 

not only the goal of consumer protection from excessive rate increases, but also the 

means—advance rate filing and review, suspension, hearings with burden of proof on the 

seller, and immediate refund insurance—by which such protections would be afforded.692 

Consumer Advocates contend that the Final Rule ignored the clear mandates of the 

statute, and allows rate increases to be filed three months after they are charged, when the 

Commission has lost the power to initiate section 205(e) consumer protections.693 

446. Consumer Advocates contend that the Final Rule’s discussion of whether the 

Commission can simply eliminate any review of rate increases under the statutory 

protections of FPA section 205(e) appears to assume that the D.C. Circuit has authorized 

such elimination of section 205(e), and that the Court has the power to do so.694 

Consumer Advocates argue that the Supreme Court found that a wholesale seller’s major 

duty under the FPA is to file its rates for review by the Commission and the public to 

determine whether hearings should be instigated under section 206, for initial rates, or 

section 205, for changes in rates.695 They assert that the Final Rule ignored the lead cases 

on the FPA filing requirement, except to quote them for the proposition that the filing and 

hearing requirements are typically read in pari materia.

696 Consumer Advocates agree 

 692 Id. 

693 Id. at 35. 

694 Id. at 34 (citing Order No. 697 at P 948). 

695 Id. at 34-35 (citing United Gas Pipe Line, 350 U.S. at 341-42; Sierra). 

696 Id. at 35 (citing Order No. 697 at P 946, n.1070). 
Docket No. RM04-7-001 -302- 

with that citation, however they argue that the purpose of the advance rate filings is for 

the Commission and the public to review rates before they are charged.697 

447. Consumer Advocates argue that even if the Commission had authority to redefine 

rate increases as being mere rate “‘reports,’” or EQRs, the Final Rule erred by failing to 

explain why the Commission would wish to eliminate all section 205(e) consumer 

protections by adopting this definition, and how such elimination satisfies the 

Commission’s consumer protection responsibilities under the FPA.698 They contend that 

the Commission’s definition of rate increases as never occurring under the market-based 

rate regime, once a market-based rate tariff authorization is granted, allows the 

Commission to avoid prior review of all market-based rate increases and deprives 

consumers of all the protections provided by section 205(e).699 Consumer Advocates 

note that the Final Rule’s definitional elimination of rate “‘increase’” protections is of 

particular importance to consumers in Maryland, Delaware, Illinois, Montana, 

Connecticut, and Ohio, among many other states, where retail ratepayers have been 

charged huge retail rate increases resulting solely from the pass-through of huge 

wholesale rate “‘increases.’”700 They also contend that under the market-based rate 

 697 Id. 

698 Id. at 36-37 (citing 774 F.2d 490, 493). 

699 Id. (citing Atlantic Richfield; Electrical District; Lockyer, 383 F.3d at 1017). 

700 Id. at 37. 
Docket No. RM04-7-001 -303- 

regime as continued in the Final Rule, such wholesale increases have never been and 

never will be reviewed by the Commission under section 205(e) of the FPA.701 

448. Consumer Advocates also argue that the Final Rule erred by failing to adequately 

distinguish the Supreme Court and Circuit court decisions outlawing attempts by other 

regulatory agencies to replace statutorily-mandated specific rates with a range of rates, 

when the market-based rate tariffs allow a range of rates so broad as to include any rate 

the parties agree to. Consumer Advocates contend that “FERC’s claim that the MBR’s 

unlimited range of rates adequately substitutes for the ‘specific’ charges required under 

205(d)” is not sustainable under court precedent applying to the FPA and to other similar 

rate filing statutes.702 They argue that the market-based rate, a statement that the rate will 

be anything the parties agree to, is even less specific than the “‘legal and accounting 

principles’” which the D.C. Circuit rejected in Electrical District703 and state that it is 

instead, “‘no more than an invitation to negotiate,’” an invitation that the same court 

rejected as a rate in Southwestern Bell.

704 

449. Consumer Advocates contend that in unlawfully replacing the requirement of 

section 205(d) for filing specific rate changes with a range of rates,705 the Final Rule 

 701 Id. 

702 Id. at 27 (citing Electrical District; 16 U.S.C. 824e(a)). 

703 Id. 

704 Id. (quoting Southwestern Bell, 43 F.3d at 1521).

705 Id. at 28. 
Docket No. RM04-7-001 -304- 

erred in relying on Lockyer’s attempt to distinguish certain cases by claiming they were 

remanded by the Supreme Court because the agency had “‘relied on market forces 

alone.’”706 According to Consumer Advocates, the Lockyer decision erred in failing to 

recognize that Electrical District and Southwestern Bell found unlawful the agencies’ 

attempts to replace statutory requirements to file specific rates with “‘ranges of rates’” for 

“‘non-dominating’” entities.707 Consumer Advocates also argue that rate ranges only 

apply to “‘non-dominating’” wholesale sellers without market power, and that the courts 

have held that it is the Congress, not the agency, that determines what entities must 

continue to be regulated.708 

450. Consumer Advocates contend that in Regular Common Carrier Conference v. 

United States, the importance of actual rates contained in tariffs was found to be “‘utterly 

central’” to a rate filing statute.709 They note that the Final Rule relied repeatedly on 

LEPA, which relies on Elizabethtown Gas, yet neither court decided the issue of whether 

the market-based rate filings or the overall market-based rate regime complies with the 

FPA.710 Consumer Advocates also assert that the D.C. Circuit has repeatedly refused on 

 706 Id. (citing Lockyer, 353 F.3d at 1013; Order No. 697 at P 953). 

707 Id. at 29. 

708 Id. at 28-29 (citing Maislin Indus. U.S. v. Primary Steel Inc., 497 U.S. 

116 (1990) (Maislin); MCI; Southwestern Bell). 

709 Id. at 29 (citing Regular Common Carrier Conference v. United States, 

793 F.2d 376, 379 (D.C. Cir. 1986) (Regular Common Carrier)). 

710 Id. (citing Order No. 697 at P 949-951). Consumer Advocates contend that 

LEPA and Elizabethtown Gas both explicitly state that they are not deciding the question 

(continued...) 
Docket No. RM04-7-001 -305- 

procedural grounds to review the market-based rate regime’s elimination of rate filings 

and its disregard for other section 205 mandates.711 Consumer Advocates therefore 

conclude that the law of the D.C. Circuit on rate filings under section 206 of the FPA thus 

remains the decision in Electrical District.

451. Consumer Advocates argue that the Final Rule erred in relying chiefly on Lockyer

for legal support for replacing advance rate increase filings with after-the-fact “‘reporting 

requirements’” and that the Ninth Circuit panel, in turn, erroneously relied on 

Commission counsel’s argument that the market-based rate tariffs plus the specific 

information on actual charges filed pursuant to the “‘reporting requirements’” together 

comply with the FPA’s requirement for filing specific rates.712 Consumer Advocates 

state that if the reporting requirement filings contain a necessary component of the rate, 

that is, the component that renders the market-based rate specific enough to comply with 

the statute, then such reports must be filed 60 days in advance under section 205(d), 

otherwise, the rate reports must be filed as specifically directed by a section 205(d) order 

so as to allow for the full section 205(e) review, procedures and remedies.713 They 

 

of whether the market-based rate filing requirements or overall market-based rate regime 

comply with the FPA. Id. at 29-30 (citing LEPA, 141 F.3d at 366 n.2; Elizabethtown 

Gas, 10 F.3d at 871). 

711 Id. at 30 (citing Elizabethtown Gas; LEPA; Power Company of America, 

245 F.3d 839 (D.C. Cir. 2001); Colorado Office of Consumer Counsel v. FERC, 490 F.3d 

954 (D.C. Cir. 2007)). 

712 Id. at 25 (citing Lockyer, 383 F.3d 1015). 

713 Id. 
Docket No. RM04-7-001 -306- 

contend that the United Gas Pipe Line/Sierra cases and City of Piqua support this 

interpretation.714 Consumer Advocates argue that under the Commission’s “‘reporting 

requirements’” scheme, only prospective section 206 review, hearings or refunds are 

possible and that under the market-based rate regime, rates may be increased 

exponentially, yet there are never any section 205(e) procedural protections or remedies 

available to consumers regarding whether actual rate levels fall within a “‘zone of 

reasonableness.’”715

452. NASUCA contends that under the Final Rule, market power review is to be 

eliminated altogether for many sellers in the Category 1 classification, with no specific 

review of those sellers’ potential to exercise power.716 NASUCA argues that there is no 

record in this case to support a generic finding that a seller with 499 MW capacity needs 

no market power review and a seller of 501 MW does.717 NASUCA concludes that, in 

light of the Final Rule’s reduced requirements for market power review, the post hoc

reporting requirement is not sufficient to protect customers.718

 714 Id. at 25-26 (citing City of Piqua v. FERC, 610 F.2d 950 (1979), quoting City 

of Kaukauna, 458 F.2d 731 (1971)) (City of Piqua)). 

715 Id. at 26. 

716 NASUCA Rehearing Request at 18. 

717 Id. 

718 Id. 
Docket No. RM04-7-001 -307- 

Commission Determination

453. As we stated in the Final Rule, we disagree with Consumer Advocates’ arguments 

that the Commission failed to show how market-based rates are just and reasonable and 

not unduly discriminatory or preferential. We reject Consumer Advocates’ argument that 

the Final Rule failed to provide a standard for determining prohibited undue preference or 

discrimination under the Commission’s market-based rate regime. The standard for 

judging undue discrimination remains what it always has been: disparate rates or service 

for similarly situated customers.719 The Commission has held in prior cases, and the 

courts have upheld, that rates that are established in a market where a seller cannot 

exercise market power can be just, reasonable and not unduly discriminatory.720 

454. The Final Rule does not violate the FPA’s filing requirements. The FPA requires 

that every public utility file with the Commission “schedules showing all rates and 

charges for any transmission or sale subject to the jurisdiction of the Commission,” but it 

explicitly leaves the timing and form of those filings to the Commission’s discretion.721 

Public utilities must file “schedules showing all rates and charges” under “such rules and 

regulations as the Commission may prescribe,” and “within such time and form as the 

 719 See e.g., Southwestern Electric Cooperative, Inc. v. FERC, 347 F.3d 975, 

981 (D.C. Cir. 2003). 

720 See, e.g., Lockyer, 383 F.3d at 1012-13; Tejas Power Corp. v. FERC, 908 F.2d 

998, 1004 (D.C. Cir. 1990). 

721 16 U.S.C. 824d(c). 
Docket No. RM04-7-001 -308- 

Commission may designate.”722 Accordingly, “so long as FERC has approved a tariff 

within the scope of its FPA authority, it has broad discretion to establish effective 

reporting requirements for administration of the tariff.”723 As the Commission explained 

in the Final Rule, if a seller is granted market-based rate authority, it must comply with 

post-approval reporting requirements, including the quarterly filing of transactionspecific data in EQRs, change in status filings for all sellers, and regularly-scheduled 

updated market power analyses for Category 2 sellers.724 The Commission may, based 

on its review of EQR filings or daily market price information, investigate a specific 

utility or anomalous market circumstances to determine whether there has been any 

conduct in violation of RTO/ISO market rules or Commission orders or tariffs, or any 

 722 16 U.S.C. 824d. The FPA does not define “schedules,” leaving that to the 

Commission’s discretion as well. The Commission has defined “rate schedule” in its 

regulations at 18 CFR 35.2(b). 

723 Lockyer, 383 F.3d at 1013. 

724 Order No. 697 at P 962. The Commission explained in the NOPR that 

preceded Order No. 2001 that it needed to make changes to keep abreast of developments 

in the industry, and therefore implemented the revised filing requirements in Order 

No. 2001. Id. P 965-966 (citing Revised Public Utility Filing Requirements, Notice of 

Proposed Rulemaking, FERC Stats. & Regs., Proposed Regulations 1999-2003, ¶ 32,554, 

at 34,062 (2001); Revised Public Utility Filing Requirements, Order No. 2001, FERC 

Stats. & Regs. ¶ 31,127, at P 31 (Order No. 2001), reh’g denied, Order No. 2001-A, 

100 FERC ¶ 61,074, reh’g denied, Order No. 2001-B, 100 FERC ¶ 61,342, order 

directing filing, Order No. 2001-C, 101 FERC ¶ 61,314 (2002), order directing filing, 

Order No. 2001-D, 102 FERC ¶ 61,334 (2003)). The Commission has also issued Order 

No. 670, which adopted a new rule prohibiting the employment of manipulative or 

deceptive devices or contrivances in wholesale energy and natural gas markets. 

Prohibition of Energy Market Manipulation, Order No. 670, 71 FR 4244 (Jan. 26, 2006), 

FERC Stats. & Regs. ¶ 31,202 (2006), reh’g denied, 114 FERC ¶ 61,300 (2006). 
Docket No. RM04-7-001 -309- 

prohibited market manipulation, and take steps to remedy any violations. These steps 

could include, among other things, disgorgement of profits and refunds to customers if a 

seller is found to have violated Commission orders, tariffs or rules, or a civil penalty.725 

455. Additionally, in response to arguments that the Commission cannot or should not 

eliminate the triennial filing requirement for Category 1 sellers, as discussed above in the 

section on implementation, to the extent that any Category 1 sellers are located in a 

Commission-identified submarket, we will consider whether there is an indication that 

they have market power as we analyze the indicative screens submitted by other sellers. 

If any market power concerns arise with respect to any such Category 1 sellers, we may 

exercise our right to require the filing of an updated market power analysis and direct 

them at that time to submit one. 

456. We also disagree with Consumer Advocates’ argument that the market-based rate 

program eliminates the requirement in section 205(d) of the FPA that, absent waiver by 

the Commission, all rate increases be noticed by filing 60 days in advance, and the 

provision in section 205(e) which permits that, if warranted, rates be suspended for up to 

five months, set for hearing with the burden of proof on the seller, and made subject to 

refund pending the outcome of the hearing. Under the market-based rate program, a rate 

change is initiated when a seller applies for authorization of market-based rate pricing, 

 725 Order No. 697 at P 964. The Commission issued an Enforcement Policy 

Statement to provide guidance to the industry on how the Commission intends to 

determine remedies for violations, including applying its new and expanded civil penalty 

authority. Enforcement of Statutes, Orders, Rules, and Regulations, 113 FERC ¶ 61,068 

(2005). 
Docket No. RM04-7-001 -310- 

not when it subsequently enters into negotiated rates as interpreted by Consumer 

Advocates. A seller must give the requisite 60 days’ notice required by section 205(d) 

before it may charge any market-based rates. All applications are publicly noticed, 

entitling affected persons to intervene and challenge a seller’s proposed market-based 

rates. At that time, there is an opportunity for a hearing, with the burden of proof on the 

seller to show that it lacks, or has adequately mitigated, market power, and for the 

imposition of a refund obligation.726 The Commission has authority to suspend a request 

for market-based rates, subject to refund. Thus, contrary to Consumer Advocates’ claim, 

the Commission’s market-based rate program fully complies with both section 205(d) 

and section 205(e). Indeed, under Consumer Advocates’ interpretation of the law, if 

taken to its logical conclusion, the Commission would be precluded not only from 

authorizing market-based rates but also from authorizing flexible cost-based rates, e.g., 

“up to” rates in which sellers are pre-authorized to sell up to a specified cost-based rate 

cap. Under their theory, there would have to be 60 days’ notice of each rate charged 

under the cap (even though there was prior notice that sales would be up to the cap) so 

long as it represented a change from the previous amount charged. And presumably this 

requirement would apply even for day-ahead or monthly short-term sales for which it 

would be impossible to give 60 days’ notice. We simply do not read the FPA section 

205(d) and (e) or the parallel NGA section 4 provisions to hamstring the Commission in 

this way. Not only does section 205(c) provide flexibility regarding the timing and form 

 726 Id.; see also 18 CFR Part 35 (filing requirements and procedures). 
Docket No. RM04-7-001 -311- 

in which rates shall be filed, but 205(d) allows the Commission to waive the 60 days’ 

notice by order specifying the changes to be made and the time when they shall take 

effect and the manner in which they shall be filed and published. The Commission’s 

authorization of market-based rates (and flexible cost-based rates) is consistent with the 

flexibility allowed in section 205, and the public has notice of the types of rates that may 

be charged and the manner in which they will be filed and published. 

457. We reject arguments that the Commission has eliminated consumer protections 

under the FPA. Not only may the public intervene in section 205 market-based rate 

proceedings and file complaints under section 206 to eliminate market-based rate 

authorizations (with refund protection up to 15 months), but the Commission has in place 

a multi-part system for monitoring rates. If a seller is granted market-based rate 

authority, it must comply with post-approval reporting requirements, transaction-specific 

data in EQRs, change in status filings for all sellers, and regularly-scheduled updated 

market power analyses for Category 2 sellers.727 The quarterly reports (EQRs) that 

sellers are required to file, include, for each individual purchase and sale, the names of 

the parties, a description of the service, the delivery point of the service, the price charged 

and quantity provided, the contract duration, and any other attribute of the product being 

purchased or sold that contributed to its market value.728 That reporting requirement 

 727 Id. (citing Lockyer, 383 F.3d at 1016). 

728 Id. P 855. See also Order No. 2001, FERC Stats. & Regs. ¶ 31,127. Required 

data sets for contractual and transaction information are described in Attachments B and 

C of Order No. 2001. 
Docket No. RM04-7-001 -312- 

provides a means for the Commission and the public to spot pricing trends or 

discriminatory patterns that might indicate the exercise of market power. 

458. The Ninth Circuit has recognized that “FERC’s system consists of a finding that 

the applicant lacks market power (or has taken sufficient steps to mitigate market power), 

coupled with a strict reporting requirement to ensure that the rate is ‘just and reasonable’ 

and that markets are not subject to manipulation.”729 The Ninth Circuit has explained 

that the reporting requirements are “integral” to the market-based rate tariff and that they, 

together with the Commission’s initial approval of market-based rate authority, comply 

with the FPA’s requirements.730 Through the EQRs, the Commission has enhanced and 

updated the post-transaction quarterly reporting filing requirements that were in place 

during the time period at issue in Lockyer.

731

459. We disagree with the Consumer Advocates’ and NASUCA’s argument that the 

Final Rule erred in relying on Lockyer for legal support. The Final Rule correctly relied 

on Lockyer because in Lockyer, the Ninth Circuit cited with approval the Commission’s 

dual requirement of an ex ante finding of the absence of market power and sufficient 

post-approval reporting requirements and found that the Commission did not rely on 

market forces alone in approving market-based rate tariffs.732 Further, the market-based 

 729 Lockyer, 383 F.3d at 1013. 

730 Id. at 1015. 

731 Order No. 697 at n.1105. 

732 Lockyer, 383 F.3d at 1013. 
Docket No. RM04-7-001 -313- 

rate requirements and oversight adopted in the Final Rule are more rigorous than those 

reviewed by the Lockyer court.733 We find Consumer Advocates’ and NASUCA’s 

argument that in Lockyer the Ninth Circuit erroneously relied on Commission counsel’s 

argument that the market-based rate tariffs plus the specific information on actual charges 

filed pursuant to the reporting requirements together comply with the FPA’s filing 

requirements to be without merit. Lockyer has not been reversed, and in fact, was 

followed by the Ninth Circuit in Snohomish.

734

460. Consumer Advocates misapply United Gas Pipe Line, Sierra and City of Piqua in 

arguing that these cases require that specific sale prices must be filed ex ante under FPA 

section 205(d). In concluding that the NGA does not empower natural gas companies 

unilaterally to change their contracts in United Gas Pipe Line, the Supreme Court 

interpreted provisions of the NGA that parallel the FPA, and it stated that section 4(d) of 

the NGA says only that “a change in the filed rate cannot be made without proper notice 

to the Commission.”735 That same day the Supreme Court held in Sierra that the FPA 

does not authorize unilateral contract changes736 and determined that the Federal Power 

Commission could not declare a rate set by a contract to be “unreasonable solely because 

 733 See Order No. 697 at P 953. 

734 Snohomish, 471 F.3d at 1080-81. 

735 United Gas Pipe Line, 350 U.S. at 339 (emphasis in original). 

736 Sierra, 350 U.S. at 353. 
Docket No. RM04-7-001 -314- 

it yields less than a fair return on the next invested capital.”737 In City of Piqua, the D.C. 

Circuit explained that the primary purpose of section 205(d) is to notify the Commission 

of changes in rates and schedules between parties to a contract, stating “[a] change in 

rates cannot take place without first filing notice with the Commission.”738 

461. Consumer Advocates’ argument that United Gas Pipe Line, Sierra and City of 

Piqua require that rate reports must be filed ex ante under FPA section 205(d) overlooks 

the fact that, under the market-based rate program, the rate change is initiated when a 

seller applies for authorization of market-based rate pricing. As we explained, all 

applications are publicly noticed and affected persons are entitled to challenge a seller’s 

claims. There is an opportunity for a hearing at that time, with the burden of proof on the 

seller to show that it lacks, or has adequately mitigated, market power, and for the 

imposition of a refund obligation.739 That investigation fully satisfies the requirements of 

FPA section 205(d) and (e). 

462. With regard to Consumer Advocates’ argument that the Final Rule erred by failing 

to adequately distinguish certain Supreme Court and Circuit case decisions, we find that 

Consumer Advocates misinterpret Electrical District, Southwestern Bell, Maislin, MCI

and Regular Common Carrier in relying on these cases as support for their argument that 

 737 Id. at 355. 

738 City of Piqua, 610 F.2d at 953. 

739 Order No. 697 at P 962; see also 18 CFR Part 35 (filing requirements and 

procedures). 
Docket No. RM04-7-001 -315- 

the Commission’s market-based rate regime is unlawful. Electrical District addressed the 

issue of whether to make a rate increase effective as of the date of its order directing a 

compliance filing, rather than upon the date of acceptance of the compliance filing and 

resolved a “disagreement over what it means to ‘fix’ a rate within the meaning of [section 

206(a)] 16 U.S.C. 824e(a)” – not section 205(c).740 The D.C. Circuit rejected the 

Commission’s “policy of making rates effective as of the date of an order [under section 

206] setting forth no more than the basic principles pursuant to which the new rates are to 

be calculated.”741 Electrical District holds only that the Commission cannot, in a 

proceeding under section 206, “announce some formula and later reveal that formula was 

to govern from the date of announcement.”742 It says nothing about whether the 

Commission can establish rules under sections 205(c) and (d) that permit the filing and 

approval of market-based rate tariffs. 

463. In Southwestern Bell, the FCC “adopt[ed] a policy of permitting nondominant 

common carriers to file a range of rates as opposed to fixed rates showing a schedule of 

charges.”743 The court held that the FCC policy violated 47 U.S.C. section 203(a), which 

requires that every common carrier file “schedules showing all charges.”744 That statute 

 740 774 F.2d at 492. 

741 Id. at 493. 

742 Transwestern Pipeline Co. v. FERC, 897 F.2d 570, 578 (D.C. Cir. 1990) 

(emphasis added). 

743 43 F.3d at 1517. 

744 Id. 
Docket No. RM04-7-001 -316- 

requires a specific list of discernible rates, rather than a filing of a range of possible 

rates.745 The quarterly reports required under the Final Rule require each seller to list the 

terms of each transaction individually. The transaction-specific data required in the 

Commission’s quarterly reports do not constitute a range of rates similar to that rejected 

in Southwestern Bell. 

464. In Regular Common Carrier, the Interstate Commerce Commission (ICC) 

approved a tariff provision under which freight forwarders could provide services to 

shippers at unpublished rates determined by averaging prior charges to those shippers.746 

The court found that that provision violated 49 U.S.C. section 10761(a) (1982), which 

required that rates be “contained in a tariff,” because the agreed-upon average rates 

would never be published nor filed with the Commission.747 The court noted that section 

10761(a) expressly prohibited the charging of any rate different from the tariffed rate.748 

By contrast, FPA section 205(c) permits sellers to set rates either by tariff or by contract, 

and the Commission’s market-based rate program requires quarterly filings providing 

details of all transactions. 

465. Maislin involved an ICC policy that allowed carriers to charge privately 

negotiated contract rates that differed from the filed tariff rate, were never disclosed or 

 745 Id. at 1521. 

746 Regular Common Carrier, 793 F.2d at 377-78. 

747 Id. at 380. 

748 See id. at 379. 
Docket No. RM04-7-001 -317- 

reviewed by the ICC, and were not subject to challenge for discrimination.749 The 

Supreme Court found that the policy violated the filed-rate doctrine.750 Under the Final 

Rule, in contrast, market-based sales are made in accordance with a market-based rate 

umbrella tariff, approved only after the Commission determines, in a publicly-noticed 

proceeding with opportunity for interested parties to protest, that a seller lacks market 

power. Further, the Commission’s system requires quarterly filing of the actual rates 

charged for individual transactions, allowing both the Commission and the public to view 

all rates all rates charged. After market-based rate authority is granted, affected persons 

can file complaints, or the Commission can institute its own proceeding, to challenge 

market-based rates on the basis that the seller has gained the ability to exercise market 

power since the time the market-based rates were granted or that the market-based rates 

otherwise are unjust, unreasonable, or unduly discriminatory or preferential or to question 

whether a seller has market power. 

466. Consumer Advocates’ reliance on MCI is similarly misplaced. MCI rejected an 

FCC policy that relieved all non-dominant carriers of any requirement to file any of their 

rates with the agency. The Supreme Court found that such wholesale detariffing for 

nondominant carriers effectively removed all rate regulation where the FCC found 

competition to exist.751 By contrast, the market-based rate program implemented in 

 749 497 U.S. 116, 132-33 (1990). 

750 Id. at 127. 

751 512 U.S. 218, 231-32 (1994). 
Docket No. RM04-7-001 -318- 

Order No. 697 requires every seller with market-based rate authority to have on file an 

umbrella market-based rate tariff and to file quarterly reports detailing the specific rates 

charged for each sale. No detariffing occurs in these circumstances. As the MCI court 

held, it would not violate the filed-rate doctrine for the FCC to “modify the form, 

contents, and location of required filings, and [to] defer filing or perhaps even waive it 

altogether in limited circumstances.”752 

467. Consumer Advocates’ argument that the Commission relied repeatedly on 

Elizabethtown Gas and LEPA, yet neither court decided the issue whether the marketbased rate filings or the overall market-based rate regime complies with the FPA, misses 

the point that the Commission cited these cases in providing an overview of the cases 

relied on in the most recent court cases affirming the Commission’s market-based rate 

authority under the FPA.753 Further, the Commission properly cited Elizabethtown Gas

for the proposition that the use of market-based rate tariffs was first approved by the 

courts as to sellers of natural gas, 754 and properly cited LEPA for the proposition that use 

of market-based rate tariffs was first approved by the courts as to wholesale sellers of 

electricity. 755 In any event, as the Commission explained in the Final Rule, the more 

 752 Id. at 234. 

753 Order No. 697 at P 944; see also, id. at 945-953; Lockyer, 383 F.3d at 1011-

1014. 

754 Elizabethtown Gas, 10 F.3d at 869; see also Order No. 697 at P 948. 

755 LEPA, 141 F.3d at 365, 370; see also Order No. 697 at P 951. Consumer 

Advocates’ reliance on Power Company of America, 245 F.3d 839 (D.C. Cir. 2001) and 

(continued...) 
Docket No. RM04-7-001 -319- 

recent precedent in Lockyer and Snohomish has upheld the Commission’s dual 

requirement of an ex ante finding of the absence of market-power and sufficient postapproval reporting requirements as complying with the requirements of the FPA.756 

468. With respect to Consumer Advocates’ concern about long-term affiliate sales 

contracts not being filed, the Commission pointed out in the Final Rule that since 2002, 

its regulations have provided that long-term market-based rate power sales service 

agreements, with affiliates or otherwise, are not to be filed with the Commission.757 

However, the affiliate restrictions require that no wholesale sales of electric energy may 

 

Colorado Office of Consumer Counsel v. FERC, 490 F.3d 954 (D.C. Cir. 2007) does not 

support their argument that the Final Rule violates the FPA’s filing requirement. In 

Power Company of America the court declined to address Power Company of America’s 

(PCA) argument that umbrella agreements of power marketers were required to be on file 

because this argument was not raised in PCA’s opening brief. See Power Company of 

America, 245 F.3d at 845. In Colorado Office of Consumer Counsel, the court denied the 

Colorado Office of Consumer Counsel’s petition for review of a Commission order 

approving market behavior rules because FPA section 206’s plain language does not 

require the Commission, having found only one aspect of the market-based rate tariffs to 

be unjust and unreasonable, to revisit all elements of its market-based rate tariffs. Thus, 

the D.C. Circuit did not review the market-based rate regime’s filing requirements in 

these two cases because the filing requirement issue was not before the court. Consumer 

Advocates’ argument in this regard fails because it disregards the precedent upholding 

the Commission’s dual requirement of an ex ante finding of the absence of market power 

and sufficient post-approval reporting requirements. Lockyer, 383 F.3d 1006; 

Snohomish, 471 F.3d 1053. 

756 Lockyer, 383 F.3d 1006; Snohomish, 471 F.3d 1053. Consumer Advocates 

also argue that the Final Rule ignored the lead cases on the FPA filing requirement, 

except to quote them for the proposition that the filing and hearing requirements of the 

NGA and FPA are typically read in pari materia. Consumer Advocates Rehearing 

Request at 34-35 (citing United Gas Pipe Line; Sierra; Order No. 697 at P 946, n.1070). 

We address Consumer Advocates’ argument in this regard at supra P 412, 461-64. 

757 Order No. 697 at P 969 (citing 18 CFR 35.1(g)). 
Docket No. RM04-7-001 -320- 

be made between a franchised public utility with captive customers and a marketregulated power sales affiliate without first receiving Commission authorization (separate 

from the general market-based rate authorization at issue in this docket) for the 

transaction under section 205 of the FPA. As a result, a franchised public utility with 

captive customers cannot enter into a long-term contract with an affiliate without the 

seller under the contract (whether the franchised public utility or the affiliate) first 

receiving Commission authorization to engage in the affiliate sale.758 To the extent that a 

particular affiliate relationship presents issues of concern, it will be considered in the 

context of our determination whether to authorize any affiliate sales. Further, our 

market-based rate program incorporates numerous protections against excessive rates, 

regardless of the identities of the parties to a transaction. Finally, although long-term 

contracts generally are not filed at the Commission, all relevant contract information is 

contained in the EQRs and thus the same information is available to the public and the 

Commission. Thus, we will continue to direct sellers not to file long-term market-based 

rate sales contracts, unless otherwise permitted by Commission rule or order.759 

469. For the reasons stated in the section of this order addressing Implementation 

Process, we reject NASUCA’s argument that there is no record to support the finding that 

 758 Id. P 969-970. 

759 Id. P 970. 
Docket No. RM04-7-001 -321- 

a seller with 499 MW capacity needs no triennial power review and a seller of 501 MW 

does need market power review.760 

b. Whether the Final Rule Shifts the Burden of Proof Under 

Section 205 of the FPA 

Final Rule

470. In the Final Rule, the Commission noted that it had previously addressed and 

rejected the argument that the legal presumptions that follow from the Commission’s 

market power screens would unduly shift the burden of demonstrating the existence of 

market power to intervenors. On rehearing of the April 14 Order, the Commission 

explained that nothing in that order shifts the burden of proof that section 205 imposes on 

the filing utility. Passing both screens or failing one merely establishes a rebuttable 

presumption. To challenge a seller who passes both screens, the intervenor need not 

conclusively prove that the seller possesses market power. Rather, the intervenor need 

only meet a burden of going forward with evidence that rebuts the results of the screens. 

At that point, the burden of going forward would revert back to the seller to prove that it 

lacks market power. Thus, the burden of proof under section 205 ultimately belongs to 

the seller.761

 760 See supra P 344-47. 

761 Order No. 697 at P 968. The Commission also concluded that it will continue 

to direct sellers not to file long-term market-based rate sales contracts, unless otherwise 

permitted by Commission rule or order. Id. P 969-70. 
Docket No. RM04-7-001 -322- 

Requests for Rehearing

471. Consumer Advocates argue that the Final Rule unlawfully shifts the statutory 

burden of proof from the electricity seller under section 205(e), to justify increased rates, 

to the electricity consumer under section 206(a), to prove both that such increased rates 

are excessive and to justify different rates.762 They also contend that the Final Rule 

claims to justify this shift of burden of proof by stating that the burden is still on the seller 

to show it has no market power, even though sellers are no longer required to justify rate 

increases.763 Consumer Advocates assert that FPA section 205, under which marketbased rate tariff authorizations are approved, does not mention “‘market power,’” but 

requires that sellers have the burden of justifying proposed rate increases.764 Consumer 

Advocates state that the results on consumers can be seen in the Commission’s recent 

denial of a complaint by the Connecticut Attorney General because Connecticut failed to 

carry its burden of proof under section 206(a).765 

472. Southern contends that the Final Rule violates the requirement in FPA section 206 

that the Commission bear the burden of proof in section 206 proceedings and that the 

 762 Consumer Advocates Rehearing Request at 31-32. 

763 Id. at 32 (citing MCI; Southwestern Bell). 

764 Id. 

765 Id. (citing Blumenthal, 117 FERC ¶ 61,038 at P 57). 
Docket No. RM04-7-001 -323- 

Commission’s determinations be based on substantial evidence.766 According to 

Southern, this shifting of the burden of proof occurs through the use of indicative screens, 

which Southern contends are inherently flawed. Southern states that once a screen failure 

occurs and a presumption of market power arises, sellers only have two options: either 

accept a determination that it has market power and adopt cost-based mitigation 

measures, or provide the Commission with a DPT analysis.767 Southern concludes that 

by applying the indicative screens codified in the Final Rule the Commission will 

effectively shift to sellers the evidentiary burden in a section 206 proceeding.768 

473. Southern also argues that the screens are inherently flawed in their ability to 

definitively assess market power when none is actually present, noting that the Final Rule 

“acknowledges that the screens are ‘conservative’ in nature and will undoubtedly result in 

‘false positives’ indicating market power.”769 Southern argues that because of their 

conservative nature and propensity to result in false positives, such screens cannot 

properly provide a basis for shifting the burden of proof to sellers, and are incapable of 

providing substantial evidence of market power. 

 766 Southern Rehearing Request at 7-8 (citing 16 U.S.C. 824e(a); Sierra, 350 U.S. 

at 353; Public Service Commission of New York v. FERC, 642 F.2d 1335, 1345 (D.C. 

Cir. 1980); Public Service Co. of New Mexico, 115 FERC ¶ 61,090, at P 33 (2006)). 

767 Id. at 7 (citing Order No. 697 at P 63). 

768 Id. at 8. 

769 Id. at 8 (citing Order No. 697 at P 62, 71, 74, 89). 
Docket No. RM04-7-001 -324- 

474. Southern contends that by shifting the section 206 burden of proof to sellers, the 

Final Rule shifted to sellers the burden of rebutting the presumption of generation market 

power. Southern states that the unlawfulness of shifting this burden is exacerbated by the 

restriction placed on the type of evidence that sellers may present to rebut the market 

power presumption. Specifically, Southern asserts that the Final Rule only allows sellers 

to submit (1) historical sales and transmission data and (2) an analysis using the DPT 

(using only historical data) to demonstrate that they do not have market power, and that 

these limitations on sellers’ ability to rebut the false presumption of generation market 

power are inconsistent with the FPA since they arise in the context of a section 206 

proceeding, in which the Commission is required to bear the burden of proof.770 

475. Southern argues that the Commission should reconsider its determination in the 

Final Rule that a failure of an indicative screen results in a presumption of market power, 

and should instead determine that the indicative screens are only intended to identify 

sellers that appear to raise no horizontal market power concerns and thus can be 

considered for market-based rate authority without the necessity of further analysis.771 In 

other words, passing the screens should raise a favorable presumption that a seller does 

not have market power, and a seller would never be “presumed” to have generation 

market power.772 

 770 Id. at 10-11 (citing Order No. 697 at P 33, 75). 

771 Id. at 11. 

772 Id. 
Docket No. RM04-7-001 -325- 

Commission Determination

476. With regard to Consumer Advocates’ assertion that the Final Rule shifts the 

burden of proof from the electricity seller under section 205(e) to the electricity consumer 

under section 206(a), we reiterate that the Commission has not shifted the burden of 

proof that section 205 imposes on the filing utility. A utility seeking to make sales at 

market-based rates has the burden of proof under section 205 to show that it does not 

have, or has adequately mitigated, market power. Because passing both indicative 

horizontal market power screens establishes a rebuttable presumption that the seller lacks 

market power, the burden is then on the intervenor to provide evidence to rebut the 

presumption of no market power.773 To challenge a seller who passes both screens, the 

intervenor need not conclusively prove that the seller possesses market power. Rather, 

the intervenor need only meet a burden of going forward with evidence that rebuts the 

results of the screens. At that point, the burden of going forward would revert back to the 

seller to prove it lacks market power. Ultimately, however, the burden of proof under 

section 205 belongs to the seller.774 

 773 See Order No. 697 at P 968 (citing July 8 Order, 108 FERC ¶ 61,026, at P 29). 

774 See July 8 Order at P 29 (stating that passing both screens or failing one merely 

establishes a rebuttable presumption, and explaining that in the case of an intervenor in a 

section 205 proceeding that seeks to prove that the applicant possesses market power, 

“the intervenor need only meet a ‘burden of going forward’ with evidence that rebuts the 

results of the screens. At that point, the burden of going forward would revert back to the 

applicant to prove that it lacks market power.”) (citing Pennzoil Co. v. FERC, 645 F.2d 

360, 392 (5th Cir. 1981), cert. denied, 454 U.S. 1142 (1982); accord Transcontinental 

Gas Pipe Line Corp., Opinion No. 135, 17 FERC ¶ 61,232, at 61,450 (1981) (“The 

presumption ... is the same as that which arises from a prima facie case: it imposes on 

(continued...) 
Docket No. RM04-7-001 -326- 

477. We reject Consumer Advocates’ argument that the Final Rule shifts the FPA 

section 205 burden of proof to justify rate increases from the electricity seller to the 

electricity consumer under section 206(a) to prove both that such increased rates are 

excessive and to justify different rates, and that this can be seen in the Commission’s 

denial of the Connecticut Attorney General’s complaint in Blumenthal because 

Connecticut failed to carry its burden of proof under FPA section 206(a). Blumenthal

was an FPA section 206 complaint proceeding in which the complainants challenged 

ISO-NE’s current Market Rule 1 as unjust and unreasonable with regard to the 

compensation of generation facilities needed for reliability in Connecticut. Because that 

case was brought under section 206 of the FPA, the burden properly was on complainants 

to establish that the current provisions of Market Rule 1 are unjust and unreasonable. 

However, that case is distinguishable from the circumstance where a seller seeks 

authorization to make sales at market-based rates. As discussed above, in the case of a 

seller seeking market-based rate authority from the Commission under section 205, the 

burden of proof is on the seller to prove that it lacks market power. However, in a section 

206 complaint proceeding, the burden is on the complainant to show that the current rates 

are unjust and unreasonable. Thus, State AGs and Advocates’ argument that Blumenthal

 

the party against whom it is directed the burden of going forward with substantial 

evidence to rebut or meet the presumption, but does not shift the burden of persuasion.”); 

Generic Determination of Rate of Return on Common Equity for Electric Utilities, Order 

No. 389-A, 29 FERC ¶ 61,223 (1984) (concluding that the rebuttable presumption that a 

rate of return based on a benchmark is just and reasonable does not shift the ultimate 

burden of proof imposed by the FPA). 
Docket No. RM04-7-001 -327- 

supports their assertion that the Final Rule shifts the FPA section 205 burden of proof to 

justify rate increases from the electricity seller to the electricity consumer under section 

206(a) is without merit. 

478. For the reasons stated in the section of this order addressing horizontal market 

power, we reject Southern’s argument that the burden of proof in a section 206 

proceeding is shifted to entities that fail one of the indicative screens. 

c. Whether Elimination of the Requirement to File MarketBased Rate Contracts In A Prior Rulemaking Proceeding 

May Be Challenged in the Instant Rulemaking

Final Rule

479. The Final Rule concluded that the multiple layers of filing and reporting 

requirements incorporated into the market-based rate program, the Commission’s 

enhanced market oversight and enforcement functions, and the ability of the public to file 

section 206 complaints meet the filing requirements of the FPA and provide adequate 

protection from excessive rates. In reaching this determination, the Commission noted 

that the decision to eliminate the filing of market-based rate contracts was made almost 

five years ago in a generic rulemaking proceeding that was open to participation by all 

interested parties.775 The Commission explained that commenters’ failure to raise this 

concern in that proceeding precludes them from attacking the Commission’s well-settled 

practice in the instant rulemaking.776

 775 Order No. 697 at P 967, n.1112. 

776 Id. 
Docket No. RM04-7-001 -328- 

Requests for Rehearing

480. Consumer Advocates argue that the Final Rule erred in asserting that challengers 

to the Commission’s market-based rate regime are precluded by the passage of time and 

by earlier rulemaking proceedings from now raising their challenges to the Commission’s 

authority to issue its market-based rate regulations, including their arguments that the 

regulations are contrary to the filing and other requirements of FPA sections 205 and 

206.777 Consumer Advocates state that the Final Rule noted that the failure of 

commenters to object to an earlier rulemaking that eliminated the filing of market-based 

rate contracts almost five years ago now precludes them from asserting that the 

Commission’s actions in the instant rulemaking violate the FPA’s filing requirements.778 

Consumer Advocates contend that the Commission’s view that commenters are precluded 

from attacking the rules promulgated in this proceeding is incorrect insofar as the D.C. 

Circuit has made clear that where an agency itself reopens an issue by initiating a new 

rulemaking procedure, participants in the rulemaking are not barred from challenging the 

new rule by their failure to challenge prior agency actions.779 Consumer Advocates 

argue that members of the public may raise issues notwithstanding failure to participate 

 777 Consumer Advocates Rehearing Request at 37-38. 

778 Id. at 38 (citing Order No. 697 at P 967, n.1112). 

779 Id. (citing Montana v. Clark, 749 F.2d 740, 744 (D.C. Cir. 1984), cert. denied, 

474 U.S. 919 (1985)). 
Docket No. RM04-7-001 -329- 

in an earlier rulemaking “‘when the agency in question by some new promulgation 

creates the opportunity for renewed comment and objection.’”780 

481. Consumer Advocates argue that where the challenge is that the agency lacks 

statutory authority to take an action, a commenter’s earlier failure to challenge another 

regulation cannot bar consideration of the agency’s statutory authority for the action it 

now proposes to take. They conclude that where the petitioner challenges the substantive 

validity of a rule, failure to exercise a prior opportunity to challenge the regulation 

ordinarily will not preclude review.781 Consumer Advocates assert that the D.C. Circuit 

has held that the rule barring collateral attacks on regulations does not apply to claims 

that “an agency lacked the statutory authority to adopt the rule.”782 

482. Consumer Advocates also state that they filed a petition for review in the D.C. 

Circuit over three years ago raising these issues in the context of a challenge to the 

Commission’s actions in its Investigation of Terms and Conditions of Public Utility 

Market-Based Rate Authorizations, an FPA section 206 proceeding in which Consumer 

Advocates participated and presented their challenges to the market-based rate regime to 

 780 Id. at 38 (quoting Ohio v. EPA, 838 F.2d 1325, 1328 (D.C. Cir. 1988); accord

Ass’n of Am. R.Rs. v. ICC, 846 F.2d 1465, 1473 (D.C. Cir. 1988); Public Citizen v. 

NRC, 901 F.2d 147, 150 (D.C. Cir. 1990), cert. denied, 498 U.S. 992 (1990)). 

781 Id. at 39 (citing Montana v. Clark, 749 F.2d at 744 n.8). 

782 Id. (quoting Indep. Community Bankers of Am. v. Bd. of Governors of Fed. 

Reserve Sys., 195 F.3d 28, 34 (D.C. Cir. 1999); NRDC v. NRC, 666 F.2d 595, 602 (D.C. 

Cir. 1981)). 
Docket No. RM04-7-001 -330- 

the Commission in great detail.783 They state that the Commission has argued in the D.C. 

Circuit, successfully so far, that Consumer Advocates’ challenge to the market-based rate 

regime was not properly presented in that matter and should be addressed in some other 

appropriate proceeding.784 Consumer Advocates conclude that the Commission may not 

now assert that Consumer Advocates have slept on their rights and cannot present their 

arguments in a rulemaking that raises the issue of the lawfulness of the Commission’s 

market-based rate regime.785

Commission Determination

483. Consumer Advocates’ attack on a sentence in a footnote stating that 

“Commenters’ failure to raise this concern [regarding the filing of market-based rate 

contracts] in that proceeding precludes them from attacking the Commission’s wellsettled practice here”786 makes more of this footnote than it was intended to convey. This 

sentence was intended to clarify that the Commission had previously determined to 

eliminate the filing of market-based rate contracts in Order No. 2001,787 and to clarify 

that the Commission is not reconsidering this issue as part of this rulemaking proceeding. 

This sentence does not stand for the broad proposition, as suggested by Consumer 

 783 Id. at 40. 

784 Id. (citing Colorado Office of Consumer Counsel v. FERC, 490 F.3d 954 (D.C. 

Cir. 2007)). 

785 Id. 

786 Order No. 697 at n.1112. 

787 Order No. 2001, FERC Stats. & Regs. ¶ 31,127 at P 31. 
Docket No. RM04-7-001 -331- 

Advocates, that “challengers to the Commission’s market-based rate regime are 

precluded by the passage of time and by earlier rulemaking proceedings from now raising 

their challenges to the Commission’s authority to issue its market-based rate regulations, 

including their arguments that the regulations are contrary to the filing and other 

requirements of FPA sections 205 and 206.” Indeed, in the Final Rule, the Commission 

fully responded to the arguments raised by Consumer Advocates in their NOPR 

comments, in which they challenged the Commission’s authority to issue its marketbased rate regulations and argued, among other things, that the regulations are contrary to 

the filing and other requirements of FPA sections 205 and 206.788 Moreover, the 

Commission is responding to their arguments on rehearing in the instant order. Thus, the 

Commission has thoroughly addressed Consumer Advocates’ arguments regarding the 

instant market-based rate rulemaking proceeding in both the Final Rule and in this order. 

d. Whether the Commission Should Clarify That Sellers 

With Market Power Must File Their Actual Rates and 

Contracts Before the Charges Are Implemented

Final Rule

484. The Final Rule concluded that, with regard to NASUCA’s assertion that the rule 

would allow mitigated sellers with cost-based rates to declare their own rates without 

filing them, all mitigation proposals, whether based on the default cost-based rates or 

some other cost-based rates, must be filed with the Commission for review. The 

Commission stated that, as explained in the Mitigation section of the Final Rule, any such 

 788 Order No. 697 at P 943-955, 959-968. 
Docket No. RM04-7-001 -332- 

filings are noticed, and interested parties are given an opportunity to intervene, comment 

on, or protest the submittal.789

Requests for Rehearing

485. NASUCA raises a similar argument on rehearing, claiming that sellers with

market power should not be allowed to determine and change their rates without 

complying with FPA filing requirements.790 NASUCA states that sellers with market 

power, have, until now, been required to file cost-based rates, and argues that the Final 

Rule allows sellers with market power to dispense with the filing of contracts and 

changes in rates for sales of less than one year under the default mitigation rates.791 

NASUCA states that only contracts for sales greater than one year would be filed under 

section 205.792 According to NASUCA, a consequence is that there is no possibility of 

public notice, protest, Commission review prior to imposition of unreasonable new 

charges, and no opportunity for refund of unreasonable rates charged by sellers with 

market power for sales of up to one year’s duration.793 

 789 Id. P 971. 

790 NASUCA Rehearing Request at 8. 

791 Id. at 9 (citing Order No. 697 at 18 CFR 35.38). 

792 Although NASUCA refers to contracts for “sales greater than one year,” the 

Commission’s default rates for long-term sales cover sales of “one year or more.” Order 

No. 697 at P 659. 

793 NASUCA Rehearing Request at 9. 
Docket No. RM04-7-001 -333- 

486. NASUCA contends that allowing sellers with market power to dispense with the 

filing of contracts and changes in rates for sales of less than one year under the default 

mitigation rates, and “to set rates at will between marginal cost and embedded cost may 

not be reasonable and could allow discrimination.”794 NASUCA argues that even though 

looked at separately, the incremental cost rate base and the embedded cost rate could be 

within the zone of reasonableness, giving the utility the option to pick its rates and its 

customers in bilateral transactions, which could give the utility with wholesale market 

power the opportunity to extend it into retail markets, favoring its retail affiliate. 795 

NASUCA notes that in FPC v. Conway Corp., the Supreme Court held that a utility could 

not set low retail rates to attract retail industrial customers from other utilities and set 

wholesale rates at prices higher than the retail rate so that its wholesale competitors could 

not compete in the retail market. Thus, NASUCA concludes that the Commission should 

not allow this potentially discriminatory and predatory conduct in the name of granting 

“‘flexibility’” to utilities.796 

487. NASUCA also argues that allowing sellers with market power to make sales for 

less than one year without filing them is a subdelegation to private parties of basic duties 

conferred upon the Commission by Congress.797 In support of this point, NASUCA 

 794 Id. 

795 Id. 

796 Id. at 10 (citing 426 U.S. 271 (1976)). 

797 Id. (citing U.S. Telecom Ass’n v. FCC, 359 F.3d 554, 567-78 (D.C. Cir. 2004)). 
Docket No. RM04-7-001 -334- 

states that in ISO New England, Inc., Chairman Kelliher disagreed with the 

Commission’s decision to deny rehearing of an earlier order that accepted for filing three 

mitigation agreements and granted waiver of the 60 day prior notice requirement.798 

NASUCA concludes that the Final Rule has the same defect identified by Chairman 

Kelliher: rates of sellers with market power, when they involve sales for less than one 

year, are allowed to take effect without observing prior filing requirements, with the 

Commission relying on private parties to negotiate and charge reasonable rates.799 

NASUCA asserts that there is no provision in the FPA granting the Commission the 

power to direct utilities not to file their rates for sales of less than one year, and no 

evidence that such rates are reasonable.800 NASUCA states that the D.C. Circuit rejected 

rates that had been charged by utility negotiation at marginal cost plus 10 percent without 

being timely filed for possible review and revision by the Commission for lack of 

evidence, and argues that the same flaw applies here to the generic rate ranges approved 

for sellers with market power. According to NASUCA, there is no evidence that such 

rates are reasonable.801 

 798 Id. (citing ISO New England, Inc., 112 FERC ¶ 61,057 (2005), reversed on 

other grounds, NSTAR Electric & Gas Corp. v. FERC, 481 F.3d 794 (D.C. Cir. 2007) 

(NSTAR)). 

799 Id. at 11. 

800 Id. (citing MCI, 512 U.S. at 229-30; American Telephone & Telegraph Co. v. 

Central Office Telephone Inc., 524 U.S. 214 (1998)). 

801 Id. (citing NSTAR, 481 F.3d 794). 
Docket No. RM04-7-001 -335- 

488. NASUCA states the Final Rule responded to NASUCA’s concerns by saying that 

rate “‘proposals’” of mitigated sellers would be filed, but the Final Rule does not say 

rates, rate schedules, and contracts will be filed.802 NASUCA contends that the Final 

Rule adopted a rule which clearly states that only new contracts of a duration longer than 

one year are to be filed under section 205. NASUCA argues that in analogous 

circumstances where actual changes in rates and charges had not been filed, the D.C. 

Circuit stated that “‘making rates effective as of the date of an order setting forth no more 

than the basic principles pursuant to which the new rates are to be calculated would make 

unforeseeable liabilities a regular consequence of rate adjustments.’”803 NASUCA 

therefore requests that the Commission clarify that sellers with market power must file 

not only “‘proposals,’” but also schedules containing their actual rates and contracts, 

before the charges are implemented, in accordance with FPA section 205.804 

Commission Determination

489. With regard to NASUCA’s arguments concerning filing requirements for sellers 

with market power, to the extent a seller proposes a cost-based rate that is based on a 

formula, it is our practice to require that the rate formula used be provided for 

Commission review and such formula included in the cost-based rate tariff, including 

formulas used in calculating incremental cost for purposes of the Commission’s default 

 802 Id. at 12 (citing Order No. 697 at section 35.38). 

803 Id. (quoting Electrical District, 774 F.2d at 492-93). 

804 Id. 
Docket No. RM04-7-001 -336- 

cost-based rates.805 As the Commission explained in the Final Rule, all mitigation 

proposals by a seller found, or presumed, to have market power must be filed with the 

Commission for review. These filings are noticed and interested parties are provided the 

opportunity to intervene, comment or protest the submittal.806 In response to NASUCA’s 

concern regarding the Commission’s use of the word “proposals,” we clarify that by 

“mitigation proposals” we were referring to cost-based rate tariffs that incorporate the 

seller’s proposal for mitigation. As the Commission stated in the April 14 Order, where a 

seller proposes to adopt the default cost-based rates (or where it proposes other costbased rates), it must provide cost support for such rates. The Commission will examine 

the proposed rates on a case-by-case basis.807 With regard to sales of one week or less, 

where the seller fails to provide sufficient cost-support, the Commission will direct the 

seller to submit a compliance filing to provide the formulas and methodology according 

to which it intends to calculate incremental costs.808

490. With regard to sales of greater than one week but less than one year, the 

Commission similarly requires that the seller submit a cost-based rate tariff for filing that 

 805 Order No. 697 at P 630. 

806 Id. P 629. 

807 Id. P 630 (citing April 14 Order, 107 FERC ¶ 61,018 at P 208; Entergy 

Services, Inc., 115 FERC 61,260 at P 49 (2006) (accepting cost-based rates based on 

incremental cost plus 10 percent, noting that filing included the formula and methodology 

according to which seller intends to calculate incremental costs)). 

808 Id. P 630 (citing Aquila, Inc., 112 FERC ¶ 61,307, at P 26 (2005); Oklahoma 

Gas and Electric Co., 114 FERC ¶ 61,297, at P 19 (2006)). 
Docket No. RM04-7-001 -337- 

identifies the methodology to be used to calculate the rate. When a seller adopts the 

default cost-based rate for mid-term sales (which is based on the unit or units expected to 

run), or otherwise proposes a cost-based rate designed on the unit or units expected to 

run, the Commission stated that it will continue to allow the seller flexibility in selecting 

the particular units that form the basis of the “up to” rate. However, as the Commission 

also stated in the Final Rule, it considers all evidence when reviewing a cost-based rate 

proposal and, if a company has not justified selection of certain generation units, the 

Commission will not accept the proposed rate.809 Nevertheless, as with all cost-based 

mitigation proposals, the seller must file a cost-based rate tariff with the Commission and 

must provide cost support for such rates.810 Accordingly, we clarify in response to 

NASUCA’s request that when a mitigated seller files a cost-based mitigation proposal 

with the Commission, the seller must file an accompanying tariff. 

491. We reject NASUCA’s argument that there is no opportunity for public notice, or 

protest and Commission review of rates for mitigated sellers, and no opportunity for 

refund of unreasonable rates charged by sellers with market power for sales of up to one 

year’s duration. As noted above and as discussed in the Final Rule, all mitigation 

 809 Id. P 649, 651. 

810 As explained in the Final Rule, upon loss or surrender of market-based rate 

authority a seller has a number of options of how to make wholesale power sales. It can 

revert to a cost-based rate tariff on file with the Commission, file a new proposed costbased rate tariff, or propose other mitigation. See Order No. 697 at n.699. 
Docket No. RM04-7-001 -338- 

proposals must be filed with the Commission for review.811 These filings are noticed and 

interested parties are given an opportunity to intervene, comment or protest the 

submittal.812 As the Commission stated in the Final Rule, it will continue to conduct its 

own analysis of whether a proposed cost-based rate is just and reasonable and, if 

warranted, will set such a proposed rate for evidentiary hearing where there are issues of 

material fact.813 Under the FPA, the Commission has the authority to accept, reject, or 

modify a proposed rate based on the analysis of the specific facts and circumstances.814 

Contrary to NASUCA’s contention that the Commission provides no opportunity for 

review of, and for refund of, rates charged by mitigated sellers for sales of up to one 

year’s duration, the Commission has accepted, subject to refund, suspended and set for 

hearing cost-based mitigation proposals.815

492. We find NASUCA’s reliance on FPC v. Conway to support its argument that the 

Commission should not grant mitigated sellers the flexibility to propose rates between 

marginal cost and embedded cost to be misplaced. In FPC v. Conway, the Supreme 

 811 Order No. 697 at P 629. 

812 Id. 

813 Id. P 650. 

814 Id. P 651. 

815 See id. P 631 (citing AEP Power Marketing, Inc., 112 FERC ¶ 61,047, at P 28 

(2005) (accepting, subject to refund, and setting for hearing, AEP’s proposed rate for 

sales of power of more than one week but less than one year upon finding that AEP did 

not provide sufficient cost support for the rate levels proposed). See also, Duke Power, 

113 FERC ¶ 61,192, at P 38 (2005). 
Docket No. RM04-7-001 -339- 

Court held that a utility could not set low retail rates to attract retail industrial customers 

from other utilities and set wholesale rates at prices higher than the retail rate so that its 

wholesale competitors could not compete in the retail market. The Court also held that, 

although the FPC lacked the authority to fix retail rates, it may take those rates into 

account when it fixes the rates for interstate wholesale sales that are subject to its 

jurisdiction.816 As explained above, the Final Rule requires that the seller submit a costbased rate tariff for filing that identifies the methodology to be used to calculate the rate 

for mid-term sales. Further, the Final Rule requires that, to the extent a seller proposes a 

cost-based rate formula, the rate formula to be used must be provided for Commission 

review and such formula must be included in the cost-based rate tariff, including 

formulas used in calculating incremental cost.817 As the Final Rule explains, the 

Commission examines the proposed rate formulas of mitigated sellers on a case-by-case 

basis, and in doing so, fulfills its FPA mandate to ensure that rates are just and reasonable 

and not unduly discriminatory. Because the Final Rule requires sellers to submit a costbased rate tariff for filing that identifies the methodology to be used to calculate the rate, 

and thereby does not permit sellers with market power to “set rates at will,” NASUCA’s 

contention that allowing sellers with market power “to set rates at will between marginal 

cost and embedded cost ... could give the utility with wholesale market power the 

opportunity to extend it into retail markets” is without merit. Thus, NASUCA’s claim 

 816 426 U.S. 271, 279-80 (1976). 

817 Order No. 697 at P 630. 
Docket No. RM04-7-001 -340- 

that a scenario resulting in potentially discriminatory or predatory conduct could occur is 

speculative and unsupported by the facts in the record. 

493. We reject NASUCA’s argument that allowing mitigated sellers to make sales for 

less than one year without filing them is a subdelegation to private parties of the duties 

conferred upon the Commission by Congress. NASUCA relies on ISO New England, 

Inc. 818 to support its argument in this regard. In ISO New England, Inc., the Commission 

preauthorized ISO New England to enter into mitigation agreements intended to mitigate 

generation resources that ran out-of-economic merit order during periods of transmission 

constraints, and concluded that all such agreements were just and reasonable. On appeal, 

the D.C. Circuit remanded to the Commission the issue concerning whether the rates 

adopted in mitigation agreements were just and reasonable because the Commission had 

not reviewed data concerning generator costs for the rates in the mitigation 

agreements.819 Contrary to NASUCA’s argument, and unlike the situation in ISO New 

England, Inc., the Final Rule states that “where a seller proposes to adopt the default costbased rates (or where it proposes other cost-based rates), it must provide cost support for 

such rates. The Commission will examine the proposed rates on a case-by-case basis.”820 

Here, the Commission has not neglected to review a mitigation proposal, or the cost 

support for such a proposal. Rather, it is promulgating a rule which provides for 

 818 112 FERC ¶ 61,057 (2005), reversed in part, NSTAR, 481 F.3d 794. 

819 NSTAR, 481 F.3d 794. 

820 Order No. 697 at P 630. 
Docket No. RM04-7-001 -341- 

Commission examination of rates proposed by mitigated sellers, and that requires cost 

support for such rates. Thus, NASUCA’s argument in this regard is without merit. 

494. Further, as explained above, the Final Rule retained the Commission’s current 

policy of pricing sales of more than one week but less than one year at an embedded cost 

“up to” rate reflecting the costs of the generating unit(s) expected to provide the 

service.821 Although this approach allows sellers flexibility in designing “up to” rates for 

purposes of mitigation for sales of more than one week but less than one year, such rates 

are still subject to Commission review and approval.822 The Commission considers all 

evidence when reviewing a cost-based rate proposal and, if a company has not justified 

selection of certain generating units, we will not accept the proposed rate. Under the 

FPA, we have the authority to accept, reject, or modify a proposed rate based on an 

analysis of the specific facts and circumstances.823 NASUCA relies on U.S. Telecomm. 

Ass’n v. FCC,

824 and Chairman Kelliher’s dissent in ISO New England Inc. to support its 

contention that the Commission may not delegate its authority to private parties. As we 

explain above, however, because the Final Rule provides for Commission review of a 

seller’s proposed rates, and because the Commission will not accept the proposed rate if a 

 821 Order No. 697 at P 648. 

822 Id. P 652. 

823 Id. P 651. 

824 359 F.3d 554 (D.C. Cir. 2004) (finding that a federal agency may not delegate 

its authority to outside entities). 
Docket No. RM04-7-001 -342- 

company has not justified selection of certain generating units, the Final Rule is not 

subdelegating the Commission’s duties.825 

495. We also reject NASUCA’s argument that under the Final Rule, rates of mitigated 

sellers rely on private parties to negotiate and charge reasonable rates and thereby are in 

contravention of the holdings of MCI and Electrical District. In MCI, the Supreme Court 

rejected an FCC policy that relieved all non-dominant carriers of any requirement to file 

any of their rates with the agency. Electrical District holds that the Commission cannot, 

in a proceeding under section 206, “announce some formula and later reveal that formula 

was to govern from the date of announcement.”826 Both of these cases are 

distinguishable from the mitigation scheme set forth in the Final Rule. Because the Final 

Rule explains that “all mitigation proposals must be filed with the Commission for 

review” and states that “[t]hese filings will be noticed and interested parties will be given 

an opportunity to intervene, comment, or protest the submittal”827 the Final Rule does not 

rely on private parties to negotiate and charge reasonable rates and does not contravene 

the holdings in MCI and Electrical District. 

 825 See Order No. 697 at P 629, 651. 

826 Transwestern Pipeline Co. v. FERC, 897 F.2d 570, 578 (D.C. Cir. 1990). See

supra P 453. 

827 Order No. 697 at P 629. 
Docket No. RM04-7-001 -343- 

3. Whether Existing Tariffs Must Be Found To Be Unjust and 

Unreasonable, and Whether the Commission Must Establish a 

Refund Effective Date

Final Rule

496. The Final Rule determined that the Commission was not required to establish a 

refund effective date and concluded that continuing to allow basic inconsistencies in the 

market-based rate tariffs on file with the Commission is unjust and unreasonable.828 The 

Commission found that even if section 206 were read to require the establishment of a 

refund effective date in rulemakings initiated under section 206, rather than only in casespecific section 206 investigations initiated by complaints or sua sponte by the 

Commission, the Commission has broad discretion to adopt a generic policy or make 

generic findings through either rulemaking or adjudication.829 The Commission 

concluded that “[t]his proceeding is not an adjudicatory investigation of public utilities’ 

existing market-based rate tariffs for which refunds will be required. Rather, we are 

modifying existing market-based rate tariffs prospectively only through this rulemaking. 

Accordingly, the establishment of a refund effective date in this rulemaking would be 

meaningless.”830

 828 Id. P 974. 

829 Id. P 975 (citing Lockyer). 

830 Id. (citing Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985); 

SEC v. Chenery, 332 U.S. 194, 202-03, reh’g denied, 332 U.S. 747 (1947) (emphasis in 

original). 
Docket No. RM04-7-001 -344- 

Requests for Rehearing

497. Consumer Advocates contend that the Final Rule points to no specific legal 

authority under either section 205 or 206 that supports the Commission’s action. They 

state that the Commission claims it is not “adjudicating” in the Final Rule, but fails to 

recognize that the Commission’s authority to issue rules under sections 205 and 206 is 

narrowly constrained because the Commission has no independent ratemaking power 

under the FPA.831 Consumer Advocates state that pursuant to United Gas Pipe Line and 

Sierra, the Commission has authority under section 206(a) to review initial rates and 

contracts filed by utility sellers, or ongoing, previously effective rates. Consumer 

Advocates contend that before the Commission can act under section 206(a), it must find 

existing rates to be unlawful, and also must find market-based rates as modified by the 

rulemaking to be just and reasonable and not unduly preferential or discriminatory going 

forward. They submit that although the Final Rule purports to make the first finding that 

existing rates without the new rules are unjust and unreasonable, it fails to make the 

second finding that market-based rates that adhere to the Final Rule are just and 

reasonable. 832 Consumer Advocates contend that the Final Rule pointed to no legal 

authority under section 205 or 206 that supports the actions taken, but instead points only 

to policy choices regarding the market-based rate regime. Consumer Advocates assert 

 831 Id. at 16 (citing United Gas Pipe Line; Sierra). 

832 Id. (citing United Gas Pipe Line; Sierra). 
Docket No. RM04-7-001 -345- 

that the Commission has no authority, even to implement policy, unless the statute 

confers it.833 

Commission Determination

498. We disagree with Consumer Advocates’ contentions that the Commission must 

find existing market-based rates to be unlawful and must set new lawful rates going 

forward and that the Commission has no authority to implement the policies in this 

rulemaking. We have broad discretion to adopt generic policy or make generic findings 

through either rulemaking or adjudication,834 and we have discretion over whether to 

order refunds.835 We reiterate that this proceeding is not an adjudicatory investigation of 

public utilities’ existing market-based rate tariffs for which refunds will be required.836 

 833 Id. at 17 (citing Atlantic City Electric Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 

2002) (Atlantic City)). 

834 An agency enjoys broad discretion to determine its own procedures, including 

whether to act by a generic rulemaking or by case-by-case adjudication. Mobil Oil 

Exploration & Producing Southeast, Inc. v. United Distrib. Cos., 498 U.S. 211, 230 

(1991); NLRB v. Bell Aerospace Co., 416 U.S. 267, 293 (1974); Interstate Natural Gas 

Association of America v. FERC, 285 F.3d 18, 57-58 (D.C. Cir. 2001). 

835 See e.g., Lockyer, 383 F.3d at 1016. Consumer Advocates rely on Atlantic 

City for support for their argument that the Commission has no authority to implement 

policy unless a statute confers it. In Atlantic City, the court held that the Commission did 

not have authority to require utilities to give up their right to file rate changes or authority 

to mandate that withdrawal from an ISO could only become effective upon Commission 

approval. However, because the courts have repeatedly upheld the Commission’s 

authority to adopt market-based rates, Consumer Advocates’ reliance on Atlantic City for 

support for their argument in this regard is misplaced. See, e.g., LEPA, 141 F.3d 364; 

Lockyer, 383 F.3d 1006; Snohomish, 471 F.3d 1053. 

836 Order No. 697 at P 975. 
Docket No. RM04-7-001 -346- 

499. We also reject Consumer Advocates’ assertion that the instant rulemaking is in 

contravention of United Gas Pipe Line and Sierra because the Final Rule did not make 

the finding that market-based rates that adhere to the Final Rule are just and reasonable. 

In United Gas Pipe Line, the Supreme Court interpreted provisions of the NGA that 

parallel the FPA, and it stated that section 4(d) of the NGA says only that “a change in 

the filed rate cannot be made without proper notice to the Commission.”837 The Supreme 

Court held in Sierra that the FPA does not authorize unilateral contract changes and held 

that the Federal Power Commission could not declare a rate set by a contract to be 

“unreasonable solely because it yields less than a fair return on the next invested 

capital.”838 Unlike United Gas Pipe Line and Sierra, this rulemaking proceeding is not an 

adjudicatory investigation of a public utility’s existing rates for which refunds will be 

required. Rather, in the Final Rule the Commission revised and codified its market-based 

rate policy for public utilities on a generic basis. Contrary to Consumer Advocates’ 

argument that the Commission did not specify “exactly what it is doing in the Final 

Rule,” the Commission clearly stated that it is “modifying existing market-based rate 

tariffs prospectively only through this rulemaking.”839 

 837 United Gas Pipe Line, 350 U.S. at 339 (emphasis in original). 

838 Sierra, 350 U.S. at 355. 

839 Order No. 697 at P 975 (citing Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 

1166 (D.C. Cir. 1985); SEC v. Chenery, 332 U.S. 194, 202-03, reh’g denied, 332 U.S. 

747 (1947) (emphasis in original)). 
Docket No. RM04-7-001 -347- 

G. Miscellaneous

1. Change in Status

a. Reporting

Final Rule

500. In Order No. 697, the Commission continued its requirement for sellers to report 

any change in status that departs from the characteristics relied upon by the Commission 

in authorizing sales at market-based rates.840 Events that constitute a change in status 

include, among other things, ownership or control of generation capacity that result in net 

increases of 100 MW or more, and change in upstream ownership. Notification of any 

such changes in status must be filed no later than 30 days after the change occurs. 

501. Also in Order No. 697, the Commission created a category of market-based rate 

sellers that are exempt from the requirement to submit regularly scheduled updated 

market power analyses. These Category 1 sellers have been carefully defined by the 

Commission to have attributes that are not likely to present market power concerns.841 

Market power concerns for Category 1 sellers are monitored by the Commission through 

the change in status reporting requirement and through ongoing monitoring by the 

 840 Order No. 697 at P 1009-1045 (codifying the requirement, as amended, at 

18 CFR 35.42). 

841 Id. at P 853. 
Docket No. RM04-7-001 -348- 

Commission’s Office of Enforcement. All other sellers, Category 2 sellers, are, in 

addition, required to continue to file regularly scheduled updated market power 

analyses. 842

Requests for Rehearing

502. TDU Systems assert that to protect consumers more adequately, the Commission 

should require a Category 2 seller to submit an updated market power analysis in each 

instance in which a seller’s generation increases by a predetermined percentage or an 

absolute amount.843 TDU Systems state that under the Commission’s present rules, a 

public utility that builds or acquires new generation capacity or merges with another 

company is not required to submit a new horizontal market power analysis. It is required 

only to file a change in status report for any net increase of 100 MW or more. TDU 

Systems references a proposal made by another commenter in response to the NOPR 

asking the Commission to require an updated market power analysis in each instance in 

which a seller’s generation increases by a predetermined percentage or absolute amount. 

According to TDU Systems, the Commission did not directly address this proposal in the 

 842 Previously, updated market power analyses were submitted within three years 

of any order granting a seller market-based rate authority, and every three years 

thereafter. 

843 TDU Systems at 28 (citing NRECA NOPR comments at 24. NRECA gives 

examples of predetermined thresholds as a certain percentage increase over the current 

amount, or any increase over some absolute amount).
Docket No. RM04-7-001 -349- 

Final Rule,844 but indirectly touched on the issue by stating that an updated market power 

analysis may be required from any sellers, Category 1 or 2, at any time. 

503. TDU Systems assert that the Commission erred in failing to address the merits of 

this proposal in the Final Rule.845 They contend that the Commission should not burden 

itself with deciding when major additions to generation, revealed in a change in status 

report, are likely to alter the results of its market power tests. They submit that it would 

not be an unreasonable burden on Category 2 sellers to prepare updated analyses within a 

reasonable time from the acquisition of additional generation. 

Commission Determination

504. In the Final Rule, the Commission stated that it retains the tools necessary to 

ensure that all rates are just and reasonable, with initial market power evaluations, 

ongoing monitoring by the Commission, change in status reporting requirements, and 

scheduled updated market power analyses for Category 2 sellers.846 We continue to 

believe that these requirements provide the Commission with the tools it needs to ensure 

that rates remain just and reasonable. 

In Order No. 652, the Commission clarified and standardized market-based rate sellers’ 

reporting requirement for changes in status and the Commission considered and rejected 

 844 TDU Systems indicate that NRECA suggested this proposal. TDU Systems at 

27-28 (citing NRECA NOPR comments at 23-25). 

845 Id. at 4-5 (citing K N Energy, Inc. v. FERC, 968 F.2d 1295, 1303 (D.C. Cir. 

1991)). 

846 Order No. 697 at P 853-854. 
Docket No. RM04-7-001 -350- 

the idea that change in status filings include an updated market power analysis. The 

Commission explained that it is incumbent on an applicant to decide whether a change in 

status is a material change and that an applicant should provide adequate support and 

analysis, including an updated market power analysis if it chooses.847 Thus, if a marketbased rate seller believes that a change in status does not affect the continuing basis of the 

Commission’s grant of market-based rate authority, it should clearly state the reasons on 

which it bases this conclusion, including an updated market power analysis if it so 

chooses. 

505. While we appreciate TDU Systems’ proposal and agree that it would not 

necessarily be an unreasonable burden to require Category 2 sellers to prepare updated 

analyses within a reasonable time from the acquisition of additional generation, we are 

not persuaded that our current approach is not adequate. The existing reporting 

requirement provides the Commission a sufficient tool to allow it to assess whether there 

is a potential market power concern and, if so, the Commission reserves the right to 

require the seller to submit a market power study. In addition, the seller is required to 

provide an affirmative statement as to what effect, if any, the added generation has on its 

market power. For a seller to make such an affirmative statement, it must determine 

what effect the added generation has on the market power analysis. To the extent the 

seller makes an affirmative statement that there is no effect on its market power, it is 

 847 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 94-95. 
Docket No. RM04-7-001 -351- 

bound to that statement and faces remedial action, including civil penalties, if it has 

misrepresented the effect. 

506. Therefore, we will not require entities to automatically file an updated market 

power analysis with their change in status filings, such as that required by a triennial 

review. However, an entity may provide such an analysis if it chooses. Furthermore, 

regardless of the seller’s representation, if the Commission has concerns with a change in 

status filing (for example, market shares are below 20 percent, but are relatively high 

nonetheless), the Commission retains the right to require an updated market power 

analysis at any time.848 

b. Transmission Outages

Final Rule

507. The Final Rule adopted the NOPR proposal not to require the reporting of 

transmission outages per se as a change in status. The Commission explained that the 

reporting of all transmission outages, including the most routine, would be an excessive 

burden on sellers with no apparent countervailing benefit. However, the Final Rule 

stated that, consistent with Order No. 652, to the extent that a long-term transmission 

outage affects one or more of the factors of the Commission’s market-based rate analysis 

(e.g., if it reduces imports of capacity by competitors that, if reflected in the generation 

 848 Order No. 697 at P 856-857. 
Docket No. RM04-7-001 -352- 

market power screens, would change the results of the screens from a “pass” to a “fail”), 

a change in status filing is required.849 

Requests for Rehearing

508. Wisconsin Electric requests that the Commission clarify which entity is 

responsible for reporting long-term transmission outages as a change in status. 

Wisconsin Electric explains that companies such as itself that do not own transmission 

may not be in the position of knowing the details of transmission outages and the effects 

of an outage on their market power analyses. Therefore, Wisconsin Electric requests that 

the Commission clarify that non-transmission owning entities such as itself need not 

report long-term outages.850

Commission Determination

509. The Final Rule did not expand the events that trigger a change in status filing to 

include actions taken by a competitor (such as a decision to take transmission capacity 

out of service), beyond those adopted in Order No. 652. Furthermore, the Commission 

found that it is not reasonable to routinely require sellers to make a showing regarding 

potential barriers to entry that others might erect or are beyond the seller’s control.851 

Thus, as a general matter, a transmission outage that occurs beyond a seller’s control does 

 849 Order No. 697 at P 1025. 

850 Wisconsin Electric at 4-5. 

851 Order No. 697 at P 1035. 
Docket No. RM04-7-001 -353- 

not necessarily trigger a change in status filing.852 In certain circumstances, however, a 

seller, including a non-transmission owning entity, will be required to submit a change in 

status filing, as stated above,853 when it or its affiliate know that a long-term transmission 

outage has an effect on its market power analysis (e.g., the long-term transmission outage 

causes the seller to fail one or more of the indicative screens). 

c. Other Clarifications 

510. Below we provide a number of other clarifications regarding the change in status 

reporting requirement. Although no clarifications or rehearing requests were submitted 

on these particular issues, the Commission is aware of some confusion in the industry and 

accordingly provides clarification. 

Change in Status Reporting by Market

511. As codified in § 35.42 of the Commission’s regulations, events that constitute a 

change in status include, among other things, changes in ownership or control of 

generation capacity that result in net increases of 100 MW or more.854 

512. We clarify that a change in status should be filed to reflect a change in the 

ownership or control of generation capacity that results in a net increase of 100 MW or 

more in the geographic market that was the subject of the horizontal market power 

 852 We clarify that, to the extent the Commission becomes aware of a possible 

barrier to entry such as a long-term transmission outage, the Commission reserves the 

right to require any market-based rate seller to demonstrate what effect, if any, that 

barrier to entry has on its ability to exercise market power. 

853 Order No. 652, FERC Stats. & Regs. ¶ 31,175 at P 75. 

854 Id. at P 68.
Docket No. RM04-7-001 -354- 

analysis on which the Commission relied in granting the seller market-based rate 

authority. For example, if the Commission relied on a seller’s default geographic market 

in granting the seller market-based rate authority, the seller would be required to submit a 

change in status filing for a net increase of 100 MW or more of generation capacity in 

that geographic market. Similarly, if the Commission relied upon an alternative 

geographic market in granting a seller market-based rate authority, any net increase of 

100 MW or more of generation capacity in the alternative geographic market would 

require the seller to submit a change in status filing. On the other hand, if a seller has a 

net increase of 50 MW in the geographic market on which the Commission relied in 

granting the seller market-based rate authority and a 50 MW increase in a different 

geographic market that is in the same region as defined by Appendix D of Order No 697, 

the 100 MW or more threshold would not be met because the increase in generation 

capacity is less than 50 MW in each generation market and, accordingly, a change in 

status filing would not be required. 

Change in Status Reporting Cumulatively

513. A seller must submit an initial application to receive market-based rate authority 

and file change in status filings in compliance with its market-based rate authority, such 

as an increase of 100 MW or more in a geographic market. However, in the course of 

processing change in status filings made by sellers, the Commission believes that it has 

not been clear to some sellers that increases in generation should be reported 

cumulatively. For example, some sellers have submitted a series of change in status 

reports that consider only the additional capacity on a standalone basis rather than 
Docket No. RM04-7-001 -355- 

considering the total effect of each generation capacity increase since the seller’s last 

market power analysis. When a seller submits a change in status filing to report an 

increase of 100 MW or more of generation capacity in a geographic market, rather than 

treating each increase in generation capacity on a standalone basis, the seller should 

consider the cumulative effect of all increases in generation capacity since its most 

recently approved market power analysis. 

514. For example, if a seller acquires generation capacity resulting in a net increase of 

100 MW in a market in January, it is required to submit a change in status filing 

reflecting this net increase. However, if the seller adds an additional 100 MW of 

generation in the same market in February, the seller must account for a cumulative total 

of 200 MW in that market when submitting its change in status filing for the February 

addition of generation capacity. This cumulative net increase since a seller’s most 

recently approved market power analysis must be the basis of the seller’s change in status 

to reflect that it does or does not depart from the characteristics the Commission relied on 

in authorizing sales at market-based rates. 

2. Third Party Providers of Ancillary Services

Final Rule

515. In the Final Rule, the Commission modified its approach for third-party sellers of 
Docket No. RM04-7-001 -356- 

ancillary services at market-based rates as announced in Avista.

855 The Commission 

noted that the posting and reporting requirements imposed in Avista may be hindering the 

development of ancillary services markets, particularly by third-party providers. Thus, 

the Commission concluded that the EQR filing requirement provides an adequate means 

to monitor ancillary services sales by third parties such that the posting and reporting 

requirements established in Avista are no longer necessary.856 

516. In the Final Rule, the Commission stated that all sellers that seek authority to sell 

ancillary services at market-based rates pursuant to Avista857 must make a filing with the 

Commission to request that authority and must include language in their market-based 

rate tariffs identifying the ancillary services that they offer.858 Moreover, the Final Rule 

 855 Order No. 697 at P 1058. See Avista Corporation, 87 FERC ¶ 61,223 (Avista), 

order on reh’g, 89 FERC ¶ 61,136 (Avista II) (1999). 

856 With this modification adopted in the Final Rule of eliminating the specific 

posting and reporting requirements established in Avista for third-party sellers of 

ancillary services, the Commission expects to monitor ancillary services sales by third 

parties through the EQR. In a notice seeking comments on proposed revisions to the 

EQR Data Dictionary, Revised Public Utility Filing Requirements for Electric Quarterly 

Reports, 122 FERC ¶ 61,194 (2008), the Commission is seeking comment on proposed 

changes that would clarify that the ancillary services discussed in Avista must be reported 

whenever those services are provided. Under the proposed revisions, when a seller 

makes third-party sales of ancillary services, that seller would be required to file, in its 

EQR, transaction information including (but not limited to) the purchaser, the ancillary 

service provided, and the price of the service. (See http://www.ferc.gov/docsfiling/eqr.asp for more information on EQR filings). 

857 The Avista policy applies to the following four ancillary services: Regulation 

Service, Energy Imbalance Service, Spinning Reserves, and Supplemental Reserves. 

858 Order No. 697 at P 1060. Sellers that have been granted authority to provide 

third-party ancillary services need not reapply because their authority continues. 
Docket No. RM04-7-001 -357- 

retained the Commission’s current policy of not allowing sales of ancillary services by a 

third-party supplier in the following situations: (1) sales to an RTO or an ISO, i.e., where 

that entity has no ability to self-supply ancillary services but instead depends on third 

parties; (2) sales to a traditional, franchised public utility affiliated with the third-party 

supplier, or sales where the underlying transmission service is on the system of the public 

utility affiliated with the third-party supplier; and (3) sales to a public utility that is 

purchasing ancillary services to satisfy its own open access transmission tariff 

requirements to offer ancillary services to its own customers.859 Standard applicable 

tariff provisions to this affect appear in Appendix C of the Final Rule and must be 

included in the tariffs of any entities that sell ancillary services at market-based rates. 

The Commission reiterated that it is open to considering requests for market-based rate 

authorization to make such sales on a case-by-case basis.860

Requests for Rehearing

517. Wisconsin Electric requests that the Commission clarify that its decision to 

eliminate the posting and reporting requirements of Avista extends to providers of 

ancillary services that provide ancillary services other than the four services addressed in 

Avista.861 Wisconsin Electric states that it is a third-party provider of ancillary services 

and received Commission authorization to offer the four services addressed in Avista, but 

 859 Order No. 697 at P 1061 (citing Avista, 87 FERC ¶ 61,223 at 61,883, n. 12).

860 Id. 

861 Wisconsin Electric Rehearing Request at 3. 
Docket No. RM04-7-001 -358- 

it also received the authorization to offer Dynamic Capacity and Energy Service as an 

ancillary service, conditioned upon the requirements in Avista to establish and maintain 

an Internet-based site and to file periodic reports describing the company’s activities in 

the ancillary services markets.862 Wisconsin Electric requests that the Commission 

clarify that the decision to remove the Avista posting and reporting requirements pertains 

not only to the four ancillary services specifically mentioned in Avista, but also to the 

other ancillary services to which the Commission subsequently applied the Avista

requirements.863

518. Morgan Stanley seeks to clarify its own request to the Commission to identify 

ways to encourage more robust ancillary services markets outside of RTO/ISO control 

areas. Morgan Stanley states that its request was intended to support the creation of 

physically-settled bilateral ancillary services markets, not a market for financially-settled 

products that are beyond the Commission’s jurisdiction.864 

519. Furthermore, Morgan Stanley clarifies that it continues to regard the creation of a 

robust bilateral market for physically-settled ancillary services, particularly outside of 

ISOs and RTOs, as the next step to facilitating greater competition in the wholesale 

energy markets overall. It did not, however, provide details for specific ancillary services 

proposals, other than the elimination of the Avista posting requirement, because its 

 862 Id. at 4 (citing Wisconsin Electric Power Co., 93 FERC ¶ 61,302 (2000)). 

863 Id. 

864 Morgan Stanley Rehearing Request at 1, 4. 
Docket No. RM04-7-001 -359- 

comments were intended solely to show support for a policy position. Thus, Morgan 

Stanley reaffirms its prior request that the Commission continue to look for opportunities 

to jump-start competition in the physical ancillary services markets throughout the United 

States.865

Commission Determination

520. We will grant Wisconsin Electric’s request for clarification. As the Commission 

stated in the Final Rule, the ancillary services addressed in Avista are Regulation Service, 

Energy Imbalance Service, Spinning Reserves, and Supplemental Reserves. In Avista

however, the Commission also characterized Dynamic Capacity and Energy Service as an 

ancillary service stating it is a combination of two ancillary services, Regulation Service 

and Energy Imbalance Service, and is intended to satisfy the transmission provider’s 

option to allow customers to supply ancillary services to the system directly. As such, 

Dynamic Capacity and Energy Service is an approved ancillary service conditioned upon 

the requirements and limitations of Avista.

866 Similarly, in Wisconsin Electric Power 

Co., the Commission authorized Wisconsin Electric to provide Dynamic Capacity and 

Energy Service as an ancillary service conditioned upon Avista.

867 

521. Therefore, because Dynamic Energy and Capacity Service, as described in Avista, 

was authorized by the Commission as an ancillary service pursuant to the Avista policy, 

 865 Id. at 5. 

866 Avista II, 89 FERC ¶ 61,136 at 61,392. 

867 Wisconsin Electric Power Co., 93 FERC ¶ 61,302 (2000). 
Docket No. RM04-7-001 -360- 

consistent with the Final Rule, such sellers may continue to sell this ancillary service at 

market-based rates and are no longer required to meet the Avista posting and reporting 

requirements with regard to this service. The current EQR Data Dictionary does not 

include Dynamic Energy and Capacity Service in the standard list of products because 

this service is only offered by a few companies. However, the Commission invited 

comments on adding new ancillary service names in Docket No. RM01-8-009.868 Absent 

the addition of a specific EQR Product Name, sellers offering this service must report it 

as an “Other” product in both the contract and transaction sections of their EQR. 

522. We appreciate Morgan Stanley’s clarification of its intent to support the creation 

of physically-settled bilateral ancillary services markets but the formation of such 

markets is beyond the scope of this proceeding. 

3. Requesting Market-Based Rate Authority for QFs

523. The Final Rule amended the Commission’s regulations governing market-based 

rate authorizations for wholesale sales of electric energy, capacity and ancillary services 

by public utilities. Although the Final Rule did not address the specific applicability of 

market-based rate authority to QFs, below we address sales by QFs at market-based rates 

that are subject to the Commission’s jurisdiction. 

 868 Revised Public Utility Filing Requirements for Electric Quarterly Reports, 

73 FR 12983 (Mar. 11, 2008), FERC Stats. & Regs. ¶ 35,557 (Mar. 3, 2008) (seeking 

comments on proposed revisions to EQR Data Dictionary).
Docket No. RM04-7-001 -361- 

524. QFs making certain sales of energy,869 as defined below, are exempt from sections 

205 and 206 of the FPA. These QF exemptions are applicable to some sales at marketbased rates.870 Therefore, sales of a QF that meet specific criteria are exempt from 

section 205 and a QF is authorized to make those sales at market-based rates without 

making a section 205 filing. 

525. All sales of energy or capacity made by QFs 20 MW or smaller are exempt from 

section 205. Sales from a QF larger than 20 MW are exempt from section 205 only if 

those sales are made pursuant to a state regulatory authority’s implementation of PURPA, 

or if those sales are made pursuant to a contract executed on or before March 17, 2006871

(unless the sale is from a qualifying small power production facility with a power 

production capacity which exceeds 30 MW, if such facility uses any primary energy 

source other than geothermal resources, in which case the sale is not exempt).872 If a 

QF’s sales are not exempt from section 205, but the QF would like to make sales at 

market-based rates, the QF is required to request market-based rate authority.873 

 869 In the context of PURPA, the term energy includes capacity, energy and 

ancillary services. 

870 See 18 CFR 292.601(c)(1). 

871 Id. 

872 18 CFR 292.601(b). However, a qualifying facility that is an eligible solar, 

wind, waste, or geothermal facility, as defined by section 3(17)(E) of the Federal Power 

Act, is not subject to the 30 MW size limitation imposed by 18 CFR 292.601(b). See

Cambria Cogen Company, 53 FERC ¶ 61,459 (1990). 

873 We note that the Commission has previously granted market-based rate 

authority to QFs that are larger than 20 MW for sales of excess power. The Commission 

(continued...) 
Docket No. RM04-7-001 -362- 

526. When a QF submits an application for market-based rate authority, its application 

must fulfill the requirements in Order No. 697, as required by all applicants. A QF, 

however, must also inform the Commission in its market-based rate application of its QF 

status and explain its request to transact under market-based rates. For example, a QF 

must explain whether any of its sales meet the requirements for the exemption from 

section 205 contained in 18 CFR 292.601(c)(1). Furthermore, if a QF desires to make 

certain energy sales at market-based rates, while making other sales exempt from section 

205, the QF must list its limitations on sales at market-based rates in its market-based rate 

tariff (i.e., sales under Seller’s contract (Contract X), which was executed on March 17, 

2006, are exempt from section 205 and sales outside of Contract X would be under 

market-based rates) and cite to the Commission orders certifying or recertifying its QF 

status, and/or to the docket numbers in which it self-certified or self-recertified its QF 

status, as explained in Order No. 697.874

H. Clarifications of the Commission’s Regulations

527. The Commission finds, based on its further consideration of the regulations, that 

several provisions should be changed to provide additional clarity. 

528. First, one of the affiliate restrictions codified in the Final Rule contained 

some minor omissions. Section 35.39(b) restricts sales between a franchised 

 

has also rejected requests for market-based rate authority from QFs that are exempt from 

section 205. See, e.g., SP Newsprint, 103 FERC ¶ 61,186 (2003). 

874 Order No. 697 at P 916-17. 
Docket No. RM04-7-001 -363- 

public utility with captive customers and a market-regulated power sales affiliate 

unless the seller first receives Commission authorization for the transaction under 

section 205 of the FPA. Upon further review, the Commission notes that the 

phrase “or capacity” should be added to the term “wholesale sales of electric 

energy” to ensure that the provision covers the appropriate scope of affiliate sales. 

Therefore, we will amend § 35.39(b) accordingly. 

529. Second, in the Final Rule, the Commission adopted a regulation requiring sellers 

to 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. In particular, § 35.42 specifies that a change in status includes, but is not 

limited to, ownership or control of generation capacity that results in net increases of 100 

MW or more. 

530. Upon further consideration, the Commission recognizes that this provision 

deserves additional clarity. We take this opportunity to clarify that a change in status also 

includes long-term firm capacity purchases that result in net increases of 100 MW or 

more. This is consistent with a seller’s obligation to include long-term firm capacity 

purchases in determining uncommitted capacity, which is used in the indicative 

screens.875 We believe that revision to the regulation is appropriate because the 

Commission’s April 14 Order, reaffirmed in Order No. 697, stated that uncommitted 

capacity is determined “by adding the total nameplate or seasonal capacity of generation 

 875 See April 14 Order, 107 FERC ¶ 61,018 at P 95, 100. 
Docket No. RM04-7-001 -364- 

owned or controlled through contract and firm purchases, less operating reserves, native 

load commitments and long-term firm sales.”876 

531. Thus, long-term firm capacity purchases that result in net increases of 100 MW or 

more are a “departure from the characteristics the Commission relied upon in granting 

market-based rate authority.” Accordingly, § 35.42(a)(1) is revised so that a change in 

status includes, but is not limited to, ownership or control of generation capacity and 

long-term firm purchases of generation capacity that result in net increases of 100 MW or 

more. Because sellers may not have been on notice that this was the Commission’s 

intent, we will not hold any sellers responsible for failure to report such changes in status 

prior to the effective date of this order, which will be 30 days after issuance in the Federal 

Register.

532. Third, as explained earlier in the affiliate abuse section of this order, we are 

revising the definition of captive customers and adding a definition for affiliate. We will 

revise the definition of captive customers in § 35.36(a)(6) to mean any wholesale or retail 

electric energy customers served by a franchised public utility under cost-based 

regulation, to be consistent with the discussion in the Affiliate Transactions Final Rule 

and the definition of captive customers adopted in that rule at 18 CFR 35.42(a)(2). The 

definition of affiliate as that term is used in the Affiliate Transactions Final Rule will be 

codified at paragraph 35.36(a)(9).

 876 See Order No. 697 at P 38 (emphasis added; footnote omitted). 
Docket No. RM04-7-001 -365- 

533. Fourth, we are revising § 35.39(d)(1) to reflect the determination to adopt a oneway information sharing restriction. Finally, as discussed in the vertical market power 

section of this order, we are revising the definition of inputs to electric power production 

to clarify the types of coal supply that are intended to be included in the definition.

III. Information Collection Statement

534. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain information collection requirements imposed by an agency.877 The Final 

Rule’s revisions to the information collection requirements for market-based rate sellers 

were approved under OMB Control Nos. 1902-0234. While this order clarifies aspects of 

the existing information collection requirements for the market-based rate program, it 

does not add to these requirements. Accordingly, a copy of this order will be sent to 

OMB for informational purposes only. 

IV. Document Availability

535. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through FERC's Home Page 

(http://www.ferc.gov) and in FERC's Public Reference Room during normal business 

hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 20426. 

 877 5 CFR 1320.11. 
Docket No. RM04-7-001 -366- 

536. From FERC's Home Page on the Internet, this information is available on 

eLibrary. The full text of this document is available on eLibrary in PDF and Microsoft 

Word format for viewing, printing, and/or downloading. To access this document in 

eLibrary, type the docket number excluding the last three digits of this document in the 

docket number field. 

537. User assistance is available for eLibrary and the FERC’s website during normal 

business hours from FERC Online Support at 202-502-6652 (toll free at 1-866-208-3676) 

or email at ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-

8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

V. Effective Date 

538. Changes to Order No. 697 adopted in this order on rehearing will become effective 

[insert date 30 days from publication in the FEDERAL REGISTER.]

List of subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements. 

By the Commission. Commissioner Kelly concurring with a separate statement attached. 

( S E A L ) 

 Nathaniel J. Davis, Sr., 

 Deputy Secretary.
Docket No. RM04-7-001 -367- 

In consideration of the foregoing, the Commission amends part 35, Chapter I, Title 

18, Code of Federal Regulations, as follows: 

PART 35 – FILING OF RATE SCHEDULES AND TARIFFS 

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-

7152. 

2. In § 35.36, paragraphs (a)(4) and (a)(6) are revised and paragraph (a)(9) is added 

to read as follows: 

§ 35.36 Generally. 

 (a) * * * 

 (4) Inputs to electric power production means intrastate natural gas 

transportation, intrastate natural gas storage or distribution facilities; sites for generation 

capacity development; physical coal supply sources and ownership of or control over 

who may access transportation of coal supplies. 

 * * * * * 

 (6) Captive customers means any wholesale or retail electric energy customers 

served by a franchised public utility under cost-based regulation. 

 * * * * * 

 (9) Affiliate of a specified company means: 

 (i) For any person other than an exempt wholesale generator: 
Docket No. RM04-7-001 -368- 

(A) Any person that directly or indirectly owns, controls, or holds with power 

to vote, 10 percent or more of the outstanding voting securities of the specified company; 

(B) Any company 10 percent or more of whose outstanding voting securities 

are owned, controlled, or held with power to vote, directly or indirectly, by the specified 

company; 

 (C) Any person or class of persons that the Commission determines, after 

appropriate notice and opportunity for hearing, to stand in such relation to the specified 

company that there is liable to be an absence of arm’s-length bargaining in transactions 

between them as to make it necessary or appropriate in the public interest or for the 

protection of investors or consumers that the person be treated as an affiliate; and 

 (D) Any person that is under common control with the specified company. 

 (E) For purposes of paragraph (a)(9)(i), owning, controlling or holding with 

power to vote, less than 10 percent of the outstanding voting securities of a specified 

company creates a rebuttable presumption of lack of control. 

 (ii) For any exempt wholesale generator (as defined under § 366.1 of this 

chapter): 

 (A) Any person that directly or indirectly owns, controls, or holds with power to 

vote, 5 percent or more of the outstanding voting securities of the specified company; 

 (B) Any company 5 percent or more of whose outstanding voting securities are 

owned, controlled, or held with power to vote, directly or indirectly, by the specified 

company; 
Docket No. RM04-7-001 -369- 

 (C) Any individual who is an officer or director of the specified company, or of 

any company which is an affiliate thereof under paragraph (a)(9)(ii)(A); and 

(D) Any person or class of persons that the Commission determines, after 

appropriate notice and opportunity for hearing, to stand in such relation to the specified 

company that there is liable to be an absence of arm’s-length bargaining in transactions 

between them as to make it necessary or appropriate in the public interest or for the 

protection of investors or consumers that the person be treated as an affiliate. 

* * * * * 

3. In § 35.39, paragraphs (b) and (d)(1) are revised to read as follows: 

§ 35.39 Affiliate restrictions. 

 * * * * * 

 (b) Restriction on affiliate sales of electric energy or capacity. As a condition 

of obtaining and retaining market-based rate authority, no wholesale sale of electric 

energy or capacity may be made between a franchised public utility with captive 

customers and a market-regulated power sales affiliate without first receiving 

Commission authorization for the transaction under section 205 of the Federal Power 

Act. All authorizations to engage in affiliate wholesale sales of electric energy or 

capacity must be listed in a Seller’s market-based rate tariff. 

 * * * * * 

 (d) Information sharing. 
Docket No. RM04-7-001 -370- 

 (1) A franchised public utility with captive customers may not share market 

information with a market-regulated power sales affiliate if the sharing could be used to 

the detriment of captive customers, unless simultaneously disclosed to the public. 

 * * * * * 

4. In § 35.42, paragraph (a)(1) is revised to read as follows: 

§ 35.42 Change in status reporting requirement. 

 (a) * * * 

 (1) Ownership or control of generation capacity and long-term firm purchases 

of generation capacity that result in net increases of 100 MW or more, or of inputs to 

electric power production, or ownership, operation or control of transmission facilities, or 

 * * * * * 

5. Appendix A of subpart H is revised to read as follows: 
Docket No. RM04-7-001 -371- 

Appendix A to Subpart H 

Appendix A 

Standard Screen Format 

(Data provided for Illustrative Purposes only) 

Part I -- Pivotal Supplier Analysis 

Row Generation MW Reference 

Seller and Affiliate Capacity

A Installed Capacity 19,500 Workpaper 

B Long-Term Firm Purchases 500 Workpaper 

C Long-Term Firm Sales -1,000 Workpaper 

D Imported Power 0 Workpaper 

Non-Affiliate Capacity 

E Installed Capacity 8,000 Workpaper 

F Long-Term Firm Purchases 500 Workpaper 

G Long-Term Firm Sales -2,500 Workpaper 

H Imported Power 3,500 Workpaper 

I Balancing Authority Area Reserve Requirement -2,160 Workpaper 

J Amount of Line I Attributable to Seller, if any -2,160 Workpaper 

K 

Total Uncommitted Supply (SUM A,B,C,D,E,F,G, H, 

I,M) 9,840 

Load 

L Balancing Authority Area Annual Peak Load 18,000 Workpaper 

M Average Daily Peak Native Load in Peak Month -16,500 Workpaper 

N Amount of Line M Attributable to Seller, if any -16,500 Workpaper 

O Wholesale Load (SUM L,M) 1,500 

P Net Uncommitted Supply (K-O) 8,340

Q Seller's Uncommitted Capacity (SUM A,B,C,D,J,N) 340 

Result of Pivotal Supplier Screen (Pass if Line Q < Line P) PASS 

 (Fail if Line Q > Line P) 
Docket No. RM04-7-001 -372- 

Note: The following appendices will not be published in the Code of Federal 

Regulations. 

Appendix C to Order No. 697-A

Required Provisions of the Market-Based Rate Tariff 

Compliance with Commission Regulations

Seller shall comply with the provisions of 18 CFR Part 35, Subpart H, as applicable, and 

with any conditions the Commission imposes in its orders concerning seller’s marketbased rate authority, including orders in which the Commission authorizes seller to 

engage in affiliate sales under this tariff or otherwise restricts or limits the seller’s 

market-based rate authority. Failure to comply with the applicable provisions of 18 CFR 

Part 35, Subpart H, and with any orders of the Commission concerning seller’s marketbased rate authority, will constitute a violation of this tariff. 

Limitations and Exemptions Regarding Market-Based Rate Authority

[Seller should list all limitations (including markets where seller does not have 

market-based rate authority) on its market-based rate authority and any 

exemptions from or waivers granted of Commission regulations and include 

relevant cites to Commission orders]. 

Seller Category

Seller Category: Seller is a [insert Category 1 or Category 2] seller, as defined in 18 CFR 

35.36(a). 
Docket No. RM04-7-001 -373- 

Include All Of The Following Provisions That Are Applicable

Mitigated Sales

Sales of energy and capacity are permissible under this tariff in all balancing authority 

areas where the Seller has been granted market-based rate authority. Sales of energy and 

capacity under this tariff are also permissible at the metered boundary between the 

Seller’s mitigated balancing authority area and a balancing authority area where the 

Seller has been granted market-based rate authority provided: (i) legal title of the power 

sold transfers at the metered boundary of the balancing authority area; (ii) the mitigated 

seller and its affiliates do not sell the same power back into the balancing authority area 

where the seller is mitigated. Seller must retain, for a period of five years from the date 

of the sale, all data and information related to the sale that demonstrates compliance with 

items (i) and (ii) above. 

Ancillary Services

 RTO/ISO Specific – Include All Services the Seller Is Offering

PJM: Seller offers regulation and frequency response service, energy imbalance service, 

and operating reserve service (which includes spinning, 10-minute, and 30-minute 

reserves) for sale into the market administered by PJM Interconnection, L.L.C. ("PJM") 

and, where the PJM Open Access Transmission Tariff permits, the self-supply of these 

services to purchasers for a bilateral sale that is used to satisfy the ancillary services 

requirements of the PJM Office of Interconnection. 
Docket No. RM04-7-001 -374- 

New York: Seller offers regulation and frequency response service, and operating 

reserve service (which include 10-minute non-synchronous, 30-minute operating 

reserves, 10-minute spinning reserves, and 10-minute non-spinning reserves) for sale to 

purchasers in the market administered by the New York Independent System Operator, 

Inc. 

New England: Seller offers regulation and frequency response service (automatic 

generator control), operating reserve service (which includes 10-minute spinning reserve, 

10-minute non-spinning reserve, and 30-minute operating reserve service) to purchasers 

within the markets administered by the ISO New England, Inc. 

California: Seller offers regulation service, spinning reserve service, and non-spinning 

reserve service to the California Independent System Operator Corporation ("CAISO") 

and to others that are self-supplying ancillary services to the CAISO. 

 Third Party Provider

Third-party ancillary services: Seller offers [include all of the following that the seller is 

offering: Regulation Service, Energy Imbalance Service, Spinning Reserves, and 

Supplemental Reserves]. Sales will not include the following: (1) sales to an RTO or an 

ISO, i.e., where that entity has no ability to self-supply ancillary services but instead 

depends on third parties; (2) sales to a traditional, franchised public utility affiliated with 

the third-party supplier, or sales where the underlying transmission service is on the 

system of the public utility affiliated with the third-party supplier; and (3) sales to a 

public utility that is purchasing ancillary services to satisfy its own open access 

transmission tariff requirements to offer ancillary services to its own customers. 
Docket No. RM04-7-001 -375- 

Appendix D to Order No. 697-A 

Regions and Schedule for Regional Market Power Update Process 

The six regions are combinations of NERC regions; RTOs and ISOs and are depicted in 

the map that follows. 

Map of Geographic Regions 

Northeast (ISO-NE, NYISO, PJM) 

Southeast (NERC Regions SERC and FRCC (not including PJM or Midwest ISO)) 

Central (Midwest ISO, NERC Regions MRO and RFC (not including PJM)) 

Southwest Power Pool (NERC region SPP) 

Southwest (California, NERC region WECC-AZNMSNV) 

Northwest (NERC Regions WECC-NWPP and WECC-RMPA) 
Docket No. RM04-7-001 -376- 

Appendix D-1 

Schedule for Transmission Owning Utilities with Market-Based Rate 

Authority and their Affiliates in the Same Region 

Entities Required to File 

Filing Period 

(Anytime During 

the Month) Study Period 

 

Northeast Transmission 

Owners December, 2007 Dec. 1, 2005 - Nov. 30, 2006 

Southeast Transmission 

Owners June, 2008 Dec. 1, 2005 - Nov. 30, 2006 

Central Transmission 

Owners December, 2008 Dec. 1, 2006 - Nov. 30, 2007 

SPP Transmission Owners June, 2009 Dec. 1, 2006 - Nov. 30, 2007 

Southwest Transmission 

Owners December, 2009 Dec. 1, 2007 - Nov. 30, 2008 

Northwest Transmission 

Owners June, 2010 Dec. 1, 2007 - Nov. 30, 2008 

Northeast Transmission 

Owners December, 2010 Dec. 1, 2008 - Nov. 30, 2009 

Southeast Transmission 

Owners June, 2011 Dec. 1, 2008 - Nov. 30, 2009 

Central Transmission 

Owners December, 2011 Dec. 1, 2009 - Nov. 30, 2010 

SPP Transmission Owners June, 2012 Dec. 1, 2009 - Nov. 30, 2010 

Southwest Transmission 

Owners December, 2012 Dec. 1, 2010 - Nov. 30, 2011 

Northwest Transmission 

Owners June, 2013 Dec. 1, 2010 - Nov. 30, 2011 
Docket No. RM04-7-001 -377- 

Appendix D – 2 

Schedule for All Other Entities 

Entities Required to File 

Filing Period 

(Anytime During 

the Month) 

Study Period 

 

All others in Northeast that 

did not file in December 

including all power 

marketers that sold in the 

Northeast. 

June, 2008 Dec. 1, 2005 - Nov. 30, 2006 

All others in Southeast that 

did not file in June 

including all power 

marketers that sold in the 

Southeast and have not 

already been found to be 

Category 1 sellers. 

December, 2008 Dec. 1, 2005 - Nov. 30, 2006 

All others in Central that 

did not file in December 

including all power 

marketers that sold in the 

Central and have not 

already been found to be 

Category 1 sellers. 

June, 2009 Dec. 1, 2006 - Nov. 30, 2007 

All others in SPP that did 

not file in June including 

all power marketers that 

sold in SPP and have not 

already been found to be 

Category 1 sellers. 

December, 2009 Dec. 1, 2006 - Nov. 30, 2007 
Docket No. RM04-7-001 -378- 

Entities Required to File 

Filing Period 

(Anytime During 

the Month) 

Study Period 

Others in Northeast that 

did not file in December 

and have not been found to 

be Category 1 sellers. 

June, 2011 Dec. 1, 2008 - Nov. 30, 2009 

Others in Southeast that 

did not file in June and 

have not been found to be 

Category 1 sellers. 

December, 2011 Dec. 1, 2008 - Nov. 30, 2009 

Others in Central that did 

not file in December and 

have not been found to be 

Category 1 sellers. 

June, 2012 Dec. 1, 2009 - Nov. 30, 2010 

Others in SPP that did not 

file in June and have not 

been found to be Category 

1 sellers. 

December, 2012 Dec. 1, 2009 - Nov. 30, 2010 

Others in Southwest that 

did not file in December 

and have not been found to 

be Category 1 sellers. 

June, 2013 Dec. 1, 2010 - Nov. 30, 2011 

Others in Northwest that 

did not file in June and 

have not been found to be 

Category 1 sellers. 

December, 2013 Dec. 1, 2010 - Nov. 30, 2011 
Docket No. RM04-7-001 -379- 

Appendix E to Order No. 697-A 

Petitioner Acronyms

Abbreviation Petitioner Names 

Ameren Ameren Services Company 

APPA/TAPS American Public Power Association/Transmission 

Access Policy Study Group 

Attorneys General of 

Connecticut and Illinois 

Richard Blumenthal, Attorney General for the State 

of Connecticut and the People of the 

State of Illinois, by and through the Illinois Attorney 

General Lisa Madigan 

Consumer Advocates 

Attorneys General of New Mexico and Rhode 

Island, Colorado Office of Consumer Counsel, Utah 

Committee of Consumer Services, Public Utility 

Law Project of NY, and Public Citizen, Inc. 

EEI Edison Electric Institute 

El Paso E&P El Paso E&P Company, L.P. 

FirstEnergy FirstEnergy Service Company 

FP&L Florida Power & Light Company and FPL Energy, 

LLC 

Industrial Customers 

Coalition of Midwest Transmission Customers, PJM 

Industrial Customer Coalition, NEPOOL Industrial 

Customer Coalition, Industrial Energy Users of 

Ohio, Industrial Energy Consumers of PA, Southeast 

Electricity Consumers Association, West Virginia 

Energy Users Group, and Southwest Industrial 

Customer Coalition 

LT Sellers Long-Term Sellers 

MidAmerican MidAmerican Energy Company and Cordova 

Energy Company LLC 
Docket No. RM04-7-001 -380- 

Abbreviation Petitioner Names 

Montana Counsel Montana Consumer Counsel 

Morgan Stanley Morgan Stanley Capital Group Inc. 

NASUCA National Association of State Utility Consumer 

Advocates 

NRECA National Rural Electric Cooperative Association 

NYISO New York Independent System Operator, Inc. 

NRG NRG Energy, Inc 

Occidental Occidental Power Marketing, L.P. 

OG&E Oklahoma Gas and Electric Company and OGE 

Energy Resources, Inc. 

Pinnacle Pinnacle West Companies 

PPM PPM Energy, Inc. 

PSEG Companies 

Public Service Electric and Gas Company, PSEG 

Power LLC, and PSEG Energy Resources & Trade 

LLC 

Reliant Reliant Energy, Inc. 

Southern Southern Company Services, Inc. 

TDU Systems Transmission Dependent Utilities Systems 

Wisconsin Electric Wisconsin Electric Power Company 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

[Docket No. RM04-7-001; Order No. 697-A] 

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

Ancillary Services by Public Utilities 

(Issued April 21, 2008) 

KELLY, Commissioner, concurring: 

 Among other decisions in Order No. 697-A, the Commission has, on 

rehearing, determined that it will entertain applications that permit a mitigated 

seller to sell under a long-term contract at market-based rates. Specifically, we 

will allow a mitigated seller to demonstrate, on a case-by-case basis, that it does 

not have market power with respect to a specific long-term contract. I believe that 

if executed properly, allowing a mitigated seller the opportunity to demonstrate 

that, with respect to a specific contract, it does not have market power could be a 

useful and productive means for spurring competition and long-term contracting. 

Ideally, I believe the Commission should apply an ordered, transparent and 

predictable test to each mitigated seller’s application. Such a test should include 

an examination of barriers to entry, structural or otherwise. New entrants bring 

new capacity that, in theory at least, should exert downward pressure on prices. 

Our decision here hinges on the hypothesis that, absent barriers to new entrants, 

long-term markets may be presumed to be competitive. Ultimately, I would like 

to see the Commission confirm that hypothesis using the aforementioned test on a 

case-by-case basis. 

Until such time as we have developed such a test, however, we have 

decided that the case-by-case approach described in this order allows the 

Commission to examine these applications with the appropriate rigor. The 

mitigated seller will have to show that a buyer under a long-term contract has 

viable alternatives, including the entry of third-party newly-constructed resources 

during the relevant future period as an alternative to purchasing under the contract 

at issue. I would prefer that mitigated sellers, in their applications, include an 

identified buyer. I believe the presence of an identified buyer will ensure that any 

assessment of the application is confined to a set of circumstances specific to the 

transaction, thereby avoiding the potential for granting a more general market-
Docket No. RM04-7-001 2 

based rate authority to a mitigated seller for a particular area and period of time. I 

do not believe that such an outcome would be helpful to or consistent with our 

goals of promoting competition. 

As the Commission moves forward, I anticipate relying on the views and 

expertise of interested parties in developing a specific test to apply to each case. 

For these reasons, I respectfully concur with this order. 

______________________ 

Suedeen G. Kelly