125 FERC ¶ 61,326 

UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 35 

[Docket No. RM04-7-005; Order No. 697-B] 

Market-Based Rates For Wholesale Sales of Electric Energy, Capacity And Ancillary 

Services By Public Utilities 

(Issued December 19, 2008) 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Order on Rehearing and Clarification. 

SUMMARY: The Federal Energy Regulatory Commission affirms its basic 

determinations in Order No. 697-A, granting 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. 

EFFECTIVE DATE: This order on rehearing will become effective [Insert_Date 30 days 

after publication in the FEDERAL REGISTER]. 

FOR FURTHER INFORMATION CONTACT: 

Michelle Barnaby (Technical Information) 

Office of Energy Market Regulation 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-8407 
Docket No. RM04-7-005 - 2 - 

Paige Bullard (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-6462 

SUPPLEMENTARY INFORMATION

:
TABLE OF CONTENTS

Paragraph Numbers

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

II. Discussion ...................................................................................................................11.

A. Horizontal Market Power .......................................................................................11.

1. Transmission Imports..........................................................................................11.

2. Further Guidance Regarding Control and Commitment of Capacity.................26.

B. Vertical Market Power............................................................................................35.

 Other Barriers to Entry...........................................................................................35.

C. Affiliate Abuse........................................................................................................40.

1. General Affiliate Terms & Conditions ...............................................................40.

2. Power Sales Restrictions.....................................................................................49.

3. Market-Based Rate Affiliate Restrictions...........................................................55.

D. Mitigation ...............................................................................................................60.

 Protecting Mitigated Markets ................................................................................60.

E. Implementation Process ..........................................................................................83.

1. Category 1 and 2 Sellers .....................................................................................83.

2. Market-Based Rate Tariff Clarifications ............................................................88.

F. Clarifications of the Commission’s Regulations ....................................................91.

 Triggering Events for Change in Status Filings .....................................................92.

III. Information Collection Statement............................................................................103.

IV. Document Availability ............................................................................................104.

V. Effective Date ...........................................................................................................107.

Regulatory Text 

Appendix C to Order No. 697-B: Revised Tariff Language 
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. RM04-7-005 

ORDER NO. 697-B 

ORDER ON REHEARING AND CLARIFICATION 

(Issued December 19, 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 market- 

 

1

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

Ancillary Services by Public Utilities, Order No. 697, FERC Stats. & Regs. ¶ 31,252 

(Order No. 697 or Final Rule), clarified, 121 FERC ¶ 61,260 (2007), order on reh’g, 

Order No. 697-A, 73 FR 25832 (May 7, 2008), FERC Stats. & Regs. ¶ 31,268 (2008); 

clarified, 124 FERC ¶ 61,055 (2008) (July 17 Clarification Order). 
Docket No. RM04-7-005 - 2 -

based 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 

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. The Commission issued an order clarifying four aspects of Order No. 697 on 

December 14, 2007.2

 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 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 

 

2

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

Ancillary Services by Public Utilities, 72 FR 72239 (Dec. 20, 2007), 121 FERC ¶ 61,260 

(2007) (December 14 Clarification Order). 
Docket No. RM04-7-005 - 3 -

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

the December 14 Clarification Order. 

3. On April 21, 2008, the Commission issued Order No. 697-A,3

 in which it 

responded to a number of requests for rehearing and clarification of Order No. 697. In 

most respects, the Commission reaffirmed its determinations made in Order No. 697 and 

denied rehearing of the issues raised. However, with respect to several issues, the 

Commission granted rehearing or provided clarification. 

4. On July 17, 2008, the Commission issued an order clarifying certain aspects of 

Order No. 697-A related to the allocation of simultaneous transmission import capability 

for purposes of performing the indicative screens.4

 Specifically, that order granted the 

requests for rehearing with regard to footnote 208 of Order No. 697-A and clarified that 

in performing the indicative screen analysis, market-based rate sellers may allocate the 

simultaneous import limit capability on a pro rata basis (after accounting for the seller’s 

 

3

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

Ancillary Services by Public Utilities, Order No. 697-A, 73 FR 25832 (May 7, 2008), 

FERC Stats. & Regs. ¶ 31,268 (2008) (Order No. 697-A). 

4

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

Ancillary Services by Public Utilities, 124 FERC ¶ 61,055 (2008) (July 17 Clarification 

Order). 
Docket No. RM04-7-005 - 4 -

firm transmission rights) based on the relative shares of the seller’s (and its affiliates’) 

and competing suppliers’ uncommitted generation capacity in first-tier markets.5

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

and clarification of Order No. 697-A. 

6. For example, in response to requests for clarification concerning allocation of 

simultaneous transmission import limit capacity when conducting the indicative screens 

used in the horizontal market power analysis, the Commission clarifies and reaffirms that 

it will require applicants to allocate their seasonal and longer transmission reservations to 

themselves from the calculated simultaneous transmission import limit only up to the 

uncommitted first-tier generation capacity owned, operated or controlled by the seller and 

its affiliates. With regard to the request that it clarify that the term “month” in paragraph 

144 of Order No. 697-A means “calendar month,” the Commission clarifies that the term 

“month” may be defined as a calendar month, consisting of 28 to 31 days, and is not 

limited to a 28 day period. 

7. In response to a request for clarification that the Commission will not rely on 

representations as to control of generation assets made by sellers absent a “letter of 

concurrence” from the party alleged to control the generation asset, the Commission 

clarifies that it will require a seller making an affirmative statement as to whether a 

 

5

 Id. P 5. 
Docket No. RM04-7-005 - 5 -

contractual arrangement transfers control to seek a “letter of concurrence” from other 

affected parties identifying the degree to which each party controls a facility, and to 

submit these letters with its filing. The Commission also reiterates that the owner of a 

facility is presumed to have control of the facility unless such control has been transferred 

to another party by virtue of a contractual agreement. 

8. With regard to the definition of “inputs to electric power production” as it 

relates to sites for new generation development, the Commission denies the request that it 

clarify that only sites for which necessary permitting for a generation plant has been 

completed and/or sites on which construction for a generation plant has begun apply 

under the definition of “inputs to electric power production” in § 35.36(a)(4) of the 

Commission’s regulations. 

9. The Commission revises the definition of “affiliate” in § 35.36(a)(9) of its 

regulations to delete the separate definition for exempt wholesale generators (EWGs), 

explaining that use of the same definition for EWGs as for non-EWG utilities is 

appropriate and that the definition adopted in Order No. 697-A for non-EWG utilities will 

not affect the substance of the Commission’s analysis for market power issues. 

10. The Commission provides a number of other clarifications with regard to, 

among others, pricing of sales of non-power goods and services and the tariff provision 

governing sales at the metered boundary. 
Docket No. RM04-7-005 - 6 -

II. Discussion

A. Horizontal Market Power

1. Transmission Imports

Background

11. 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 study.6

 Thus, a seller that owns 

transmission will be required to conduct simultaneous transmission import limit studies 

for its home balancing authority area and each of its directly-interconnected first-tier 

balancing authority areas consistent with the requirements set forth in the April 14 

Order,7

 as clarified in Pinnacle West Capital Corp.

8

 The Commission commented that 

“the SIL [simultaneous transmission import limit] study is ‘intended to provide a 

reasonable simulation of historical conditions’ and is not ‘a theoretical maximum import 

capability or best import case scenario.’”9

 To determine the amount of transfer capability 

under the simultaneous transmission import limit study, the Commission stated that 

 

6

 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354. 

7

 AEP Power Marketing, Inc., 107 FERC ¶ 61,018, at P 95 (April 14 Order), on 

reh’g, 108 FERC ¶ 61,026, at P 45 (2004) (July 8 Order). 

8

 110 FERC ¶ 61,127 (2005). 

9

 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 354 (internal citations 

omitted). 
Docket No. RM04-7-005 - 7 -

historical operating conditions and practices of the applicable transmission provider 

should be used and the analysis should reasonably reflect the transmission provider’s 

Open Access Same-Time Information System operating practices. The Commission also 

stated that it will continue to allow sensitivity studies, but the sensitivity studies must be 

filed in addition to, not in lieu of, a simultaneous transmission import limit study.10

12. On rehearing in Order No. 697-A, the Commission clarified that for the 

reasons described in Order No. 697,11 applicants are not required to address short-term 

firm reservations in the market power screens. The Commission explained that the 

Commission’s Electric Quarterly Report Data Dictionary defines monthly as more than 

168 consecutive hours up to one month, and seasonal as greater than one month and less 

than 365 consecutive days.12 The Commission also explained that 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. Further, the Commission stated that 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 

 

10 Id. P 355. 

11 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 144 (citing Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 368). 

12 Order Adopting Electric Quarterly Report Data Dictionary, Order No. 2001-G, 

120 FERC ¶ 61,270, at P 35 (2007). 
Docket No. RM04-7-005 - 8 -

reservations typical for each season. The Commission explained that it is not practical to 

require applicants to provide data on every transmission reservation, yet the Commission 

cannot ignore the impact of transmission reservations on the potential for market power. 

It concluded that 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, the Commission stated that it will require applicants to allocate their seasonal 

and longer transmission reservations to themselves from the calculated simultaneous 

transmission import limit, where seasonal reservations are greater than one month and 

less than 365 consecutive days in duration, as defined in the Commission’s Electric 

Quarterly Report Data Dictionary.13

13. In addition, the Commission stated that it would allow sellers to use load shift 

methodology to calculate the 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 simultaneous 

transmission import limit number compares had the company used a generation shift 

methodology.14

 

13 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 144. 

14 Id. P 145. 
Docket No. RM04-7-005 - 9 -

Requests for Rehearing

a. Allocation of Transmission Reservations

14. Southern Company Services, Inc.15 and E.ON U.S., on behalf of its 

subsidiaries, PacifiCorp and Public Service Company of New Mexico (collectively, 

E.ON) request that the Commission clarify or revise its discussion in paragraph 144 of 

Order No. 697-A concerning the allocation of simultaneous transmission import limit 

capacity when conducting the indicative screens. E.ON argues that, as currently written, 

Order No. 697-A could be interpreted to result in no simultaneous transmission import 

limit capacity being allocated to competing generation, resulting in grossly overstated 

market shares for a seller in its home or first-tier balancing authority areas.16 E.ON 

contends that the Commission’s statement that “we will require applicants to allocate 

their seasonal and longer transmission reservations to themselves from the calculated 

simultaneous transmission import limit, where seasonal reservations are greater than one 

month and less than 365 days in duration, as defined in the Commission’s EQR [Electric 

Quarterly Report] Data Dictionary” may be interpreted to mean that, when conducting 

the indicative screens, simultaneous transmission import limit capacity is to be allocated 

 

15 Southern Company Services, Inc. filed its request for clarification or rehearing 

acting as agent for Alabama Power Company, Georgia Power Company, Gulf Power 

Company, Mississippi Power Company and Southern Companies Power Company 

(collectively, Southern Companies). 

16 E.ON Rehearing Request at 5. 
Docket No. RM04-7-005 - 10 -

first to an applicant up to the applicant’s long-term firm point-to-point transmission rights 

into the subject balancing authority area, regardless of whether the seller has 

uncommitted capacity at the point of receipt of a transmission reservation that could 

actually be imported using the transmission reservation.17

 

15. E.ON argues that considering only transmission reservations and ignoring 

remote uncommitted capacity results in a situation where the indicative screens 

effectively assume that a seller has uncommitted capacity to import even when it has 

none. It argues that this assumption results in competing, importable capacity being 

“squeezed out” and thus being assumed unable to compete in the market at issue. Further, 

E.ON states that the approach indicated by paragraph 144 is a material change from the 

approach to simultaneous transmission import limit capacity allocation directed in the 

April 14 Order and the July 8 Order18 because it appears to ignore uncommitted capacity 

entirely. In addition, E.ON contends that the approach to simultaneous transmission 

import limit capacity allocation indicated by paragraph 144 is unfounded when the 

realities of energy markets and utility practices are considered. According to E.ON, 

paragraph 144 assumes that a seller has generating capacity at the point of receipt of the 

firm transmission path and that the seller has preemptive rights to use it, thus precluding 

 

17 Id. at 8 (quoting Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 144). 

18 Id. at 9 (citing April 14 Order, 107 FERC ¶ 61,018 at P 95, order on reh’g, July 

8 Order, 108 FERC ¶ 61,026 at P 45). 
Docket No. RM04-7-005 - 11 -

competing sellers from using that transmission. It states that the Commission’s statement 

in paragraph 143 that “[a]n applicant’s firm transmission reservations represent 

transmission that is not available to competing suppliers” seems to echo this view.19

 

16. E.ON argues that many vertically integrated utilities with native load 

obligations hold long-term firm transmission rights to bring power home in quantities that 

exceed the quantity of the remote generation they own. E.ON states that these firm 

transmission import rights are used to support native load and ensure that native load is 

supplied reliably and in a cost-effective manner, often by using the uncommitted 

generation of others. E.ON therefore argues that use of these transmission rights 

facilitates the importation of competing uncommitted generation.20 Further, E.ON argues 

that under current Commission policy and the pro forma Open Access Transmission 

Tariff (OATT), the transmission capability under firm transmission reservations not 

scheduled by a specific day-ahead deadline is released to the market at large, on a nondiscriminatory basis, after that deadline is passed.

21 Thus, E.ON concludes that insofar as 

 

19 Id. at 10 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 143). 

20 Id. 

21 Id. (citing 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, FERC Stats. & Regs. ¶ 31,036 

(1996), order on reh’g, Order No. 888-A, FERC Stats. & Regs. ¶ 31,048, order on reh’g, 

Order No. 888-B, 81 FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC 

¶ 61,046 (1998), aff’d in relevant part sub nom. Transmission Access Policy Study Group 

(continued) 
Docket No. RM04-7-005 - 12 -

the Commission’s indicative screens measure spot, as opposed to, forward generation 

market power, it would be unreasonable for the Commission to assume that firm 

transmission reservations in excess of the applicant’s remote uncommitted capacity are 

not available to competing generation.22

17. E.ON therefore requests that the Commission clarify, or find on rehearing, that 

in conducting the indicative screens, simultaneous transmission import limit capacity will 

be allocated first to an applicant only up to the lesser of the applicant’s: (1) remote 

generation in the balancing authority area that contains the point of receipt of the 

transmission right at issue; or (2) firm transmission rights of 28 days or longer in duration. 

E.ON argues that if the Commission does not issue such clarification or finding, it should 

clarify that simultaneous transmission import limit capacity will be allocated first to an 

applicant only up to the amount of firm transmission rights one year or greater in duration. 

Further, E.ON asserts that regardless of the Commission’s action on the requested 

clarifications, the Commission should clarify that any applicant may seek to demonstrate 

in its filing that the allocation of simultaneous transmission import limit capacity to it 

 

v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 

(2002); Preventing Undue Discrimination and Preference in Transmission Service, Order 

No. 890, FERC Stats. & Regs. ¶ 31,241 (2007), order on reh’g, Order No. 890-A, 73 FR 

2984 (Jan. 16, 2008), FERC Stats & Regs. ¶ 31,261 (2007), order on reh’g, Order No. 

890-B, 123 FERC ¶61,299 (2008)). 

22 Id. at 11. 
Docket No. RM04-7-005 - 13 -

overstates the amount of power that it actually imports (or understates the competing 

importable generation) and that an alternative approach to allocating simultaneous 

transmission import limit capacity is more accurate.

23

18. Similarly, Southern Companies state that paragraph 144 contains language that 

might be construed as intent by the Commission to dispense with its consideration of 

whether a transmission reservation of an applicant must be tied to a remote generation 

resource in order to be reflected in the simultaneous transmission import limit calculation. 

Southern Companies argue that, historically, this factor was significant in the 

simultaneous transmission import limit calculation process. They explain that under the 

process set forth in the July 8 Order, only the portion of an applicant’s uncommitted 

remote generation capacity with firm or network reservations was modeled in base case 

and subtracted from available simultaneous transmission import capability, and the 

remaining simultaneous transmission import limit capacity was allocated proportionally 

among applicants and other suppliers based on relative proportions of uncommitted 

capacity in areas that are first-tier to the area under study.24

 

19. Southern Companies assert that in Order No. 697, the Commission appeared to 

alter this regime by reducing the minimum period for which an accounting of 

 

23 Id. 

24 Southern Companies Rehearing Request at 11-12 (citing April 14 Order, 107 

FERC ¶ 61,018, order on reh’g, July 8 Order, 108 FERC ¶ 61,026 at P 45). 
Docket No. RM04-7-005 - 14 -

reservations was required, and therefore expanding the pool of such reservations to be 

accounted for.25 Southern Companies also contend that Order No. 697 remains unclear 

as to whether the Commission intends to change the procedure of the July 8 Order with 

respect to the importance of a generating resource linked to seasonal and long-term 

transmission reservations.26 In addition, Southern Companies state that they do not 

believe the Commission intended to make such a change since this change would: (1) 

inject additional inconsistency insofar as the Commission has affirmed the July 8 Order 

and its simultaneous transmission import limit calculation methods elsewhere in Order 

Nos. 697 and 697-A; and (2) reduce the relevance the Commission has placed on factspecific determinations, as opposed to generic presumptions, regarding the requisite 

amount of control that justifies assigning a given amount of generation capacity to the 

applicant.27 For purposes of the indicative screens, Southern Companies argue that it is 

wrong to presume that such reservations would be used to effect delivery of the 

applicant’s uncommitted generation, as opposed to effecting delivery of the purchase of 

 

25 Id. at 12 (citing Order No. 697 at P 368). 

26 Id. 

27 Id. at 13. In this regard, Southern Companies notes that that the Commission 

has struck in Order Nos. 697 and 697-A “the appropriate balance on respecting 

representations of control, agreeing to rely on representations made by sellers regarding 

control, while requiring sellers to ‘seek a ‘letter of concurrence’ from other affected 

parties identifying the degree to which each party controls a facility and submit these 

letters with its filing.’” Id. at n.15 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 

at P 187; Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 150). 
Docket No. RM04-7-005 - 15 -

short-term capacity from a third party. Southern Companies state that transmission 

service that is unscheduled is released by the transmission provider for purchase by 

others on a non-firm basis. Therefore, Southern Companies request that the Commission 

clarify that it did not intend to overrule or otherwise alter the procedures set forth in the 

July 8 Order regarding the significance of generating capacity being linked to a firm or 

network reservation. Southern Companies request that the Commission clarify that 

applicants preparing simultaneous transmission import limit analyses and accounting for 

seasonal and long-term transmission reservations should only account for those seasonal 

and long-term transmission reservations that possess a linked generating resource, then, 

for any simultaneous transmission import limit capability that is not linked to remote 

generating resources, applicants are to apply the traditional pro rata principles, as set 

forth in the July 8 Order and affirmed in Order No. 697.28

b. Definition of “month”

20. Edison Electric Institute (EEI), Southern Companies and E.ON each request 

that the Commission clarify that the term “month” in paragraph 144 means “calendar 

month” which can range in length from 28 to 31 days, not merely 28 days.29 EEI states 

 

28 Id. at 14. 

29 EEI Rehearing Request at 15-16; Southern Companies Rehearing Request at 14-

15. E.ON supports EEI’s request concerning this issue, incorporates it by reference, and 

asks the Commission to grant the clarification requested by EEI on this issue. E.ON 

Rehearing Request at 2. 
Docket No. RM04-7-005 - 16 -

that at paragraph 144 of Order No. 697-A, the Commission states that it “‘will require 

applicants to allocate their seasonal and longer transmission reservations to themselves 

from the calculated SIL [simultaneous transmission import limit], where seasonal 

reservations are greater than one month and less than 365 consecutive days in duration, as 

defined in the Commission’s EQR [Electric Quarterly Report] Data Dictionary.’”30 EEI 

supports this clarification, and states that it concurs, consistent with the conclusion of the 

Commission, that striking the balance at reservations greater than one month and less 

than 365 days will permit the reasonable modeling of “‘historical conditions without 

requiring unreasonable amounts of information from applicants.’”31 However, EEI 

requests clarification of the statement in paragraph 144 that “‘[t]wenty-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.’”32

 

21. Specifically, EEI argues that to allow consistent use of the terminology, the 

Commission should clarify that it does not intend by its “‘[t]wenty-eight days’” statement 

to undo the clarification set out in paragraph 144, that short-term reservations are up to 

 

30 EEI Rehearing Request at 15 (quoting Order No. 697-A, FERC Stats. & Regs. 

¶ 31,268 at P 144). 

31 Id. 

32 Id. 
Docket No. RM04-7-005 - 17 -

one month, and long-term reservations are greater than one month. Southern Companies 

similarly argue that the presence of the “‘[t]wenty-eight days...’” statement offers the 

potential for confusion because taken in isolation and without the full context of the 

Commission’s express clarifications in paragraph 144, this statement might be 

represented by some as a reiteration by the Commission of its statements in Order No. 

697, and that such an interpretation would create dueling and irreconcilable directions in 

the same paragraph.33 EEI states that the Commission expressly indicates in paragraph 

144 that the term “month” means a calendar month (which varies in length from 28 to 31 

days), through its reference to the Commission’s definition in the Commission’s Electric 

Quarterly Report Data Dictionary. Both Southern Companies and EEI note that the 

Electric Quarterly Report Data Dictionary nowhere indicates the term “month” is capped 

at 28 days. They state that the Electric Quarterly Report Data Dictionary defines the term 

“Monthly” as greater than 168 consecutive hours and less than or equal to one month, and 

the term “Seasonal” as greater than one month and less than 365 consecutive days. EEI 

notes that for both of these definitions, “month” is left undefined, and thus presumably at 

its accepted meaning of calendar month.34

 

 

33 Southern Companies at 15 (citing General Chemical Corp. v. U.S., 817 F.2d 844, 

857 (D.C. Cir. 1987)). 

34 EEI Rehearing Request at 16; Southern Companies Rehearing Request at 15 

(citing Order Adopting EQR Data Dictionary, Order No. 2001-G, 120 FERC ¶ 61,270, at 

P 35 (2007)). 
Docket No. RM04-7-005 - 18 -

Commission Determination

22. In response to Southern Companies’ and E.ON’s comments regarding 

allocation of simultaneous transmission import limit capacity when conducting the 

indicative screens, we clarify that the Commission’s statement in paragraph 144 of Order 

No. 697-A is not intended to revise its approach to the simultaneous transmission import 

limit allocation, as suggested in the rehearing requests of Southern Companies and E.ON. 

We therefore clarify and reaffirm that we will require applicants to allocate their seasonal 

and longer transmission reservations to themselves from the calculated simultaneous 

transmission import limit only up to the uncommitted first-tier generation capacity owned, 

operated or controlled by the seller (and its affiliates). 

23. Further, as the Commission clarified in the July 17 Clarification Order,35 to 

determine the respective shares of uncommitted generation capacity to be used in 

performing the market power analysis, a seller should determine the amount of firm 

transmission capacity36 the seller has into the study area and assume that any seller’s 

uncommitted first-tier generation capacity fully utilizes the seller’s firm transmission 

rights. Then, to the extent the seller has remaining uncommitted first-tier generation 

 

35 124 FERC ¶ 61,055 at P 31-32. 

36 See, e.g., Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 368. “Firm 

transmission capacity” includes network and firm point-to-point. 
Docket No. RM04-7-005 - 19 -

capacity,37 the remaining simultaneous transmission import limit capability is allocated 

on a pro rata basis to import the remaining uncommitted first-tier generation capacity of 

both the seller and competing suppliers. 

24. With regard to E.ON’s request that the Commission clarify that any applicant 

may seek to demonstrate in its filing that the allocation of simultaneous transmission 

import limit capacity to it overstates the amount of power that it actually imports (or 

understates the competing importable generation) and that an alternative approach to 

allocating simultaneous transmission import limit capacity is more accurate, we reiterate 

that, as we stated in the Final Rule and in Order No. 697-A, applicants may submit 

additional sensitivity studies, including a more thorough import study as part of the 

delivered price test. However, we reaffirm that any such sensitivity studies must be filed 

in addition to, and not in lieu of, a simultaneous transmission import limit capacity 

study.38 As we explained in the Final Rule, sensitivity studies are intended to provide the 

seller with the ability to modify inputs to the simultaneous transmission import limit 

study such as generation dispatch, demand scaling, the addition of new transmission and 

 

37 In performing the indicative screens, to the extent the seller does not have any 

uncommitted generation capacity in the first-tier markets or its uncommitted generation 

capacity in the first-tier markets is fully accounted for through recognition of the seller’s 

firm transmission rights, no simultaneous import limit capability allocation is needed 

between the seller and competing suppliers. 

38 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 146; Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 355. 
Docket No. RM04-7-005 - 20 -

generation facilities (and the retirement of facilities), major outages, and demand 

response.

39

25. With regard to the request of EEI, Southern Companies and E.ON that we 

clarify that the term “month” in paragraph 144 of Order No. 697-A means “calendar 

month,” we clarify that the term “month” may be defined as a calendar month, consisting 

of 28 to 31 days, and is not limited to a 28-day period. We did not intend to undo the 

clarification that short-term reservations are up to one month, and long-term reservations 

are greater than one month by stating in Order No. 697-A at paragraph 144 that “twentyeight days fits within the definition of a month, and is a reasonable limit to separate shortterm reservations from long-term reservations for purposes of the generation market 

power screens.”40 With regard to Southern Companies’ argument that the presence of the 

“twenty-eight days” statement offers the potential for confusion, we reaffirm our finding 

that applicants are not required to address short-term firm reservations in the market 

power screens, and we reiterate that “we will require applicants to allocate their seasonal 

and longer transmission reservations to themselves from the calculated SIL [simultaneous 

transmission import limit], where seasonal reservations are greater than one month and 

 

39 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 355. 

40 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 144. 
Docket No. RM04-7-005 - 21 -

less than 365 days consecutive days in duration, as defined in the Commission’s EQR 

[Electric Quarterly Report] Data Dictionary.”41

 

2. Further Guidance Regarding Control and Commitment of Capacity

Background

26. 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. 

The Commission explained that no single factor or factors necessarily results in control. 

It 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. The Commission stated that if a seller has control over certain 

capacity such that the seller can affect the ability of the capacity to reach the relevant 

market, then that capacity should be attributed to the seller when performing the 

generation market power screens.42

27. The Commission 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, it concluded that it would be 

inappropriate to make a generic finding or generic presumption of control, but rather that 

 

41 Id. 

42 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 174. 
Docket No. RM04-7-005 - 22 -

it is appropriate to continue making determinations of control on a fact-specific basis.43 

The Commission explained, however, that it will continue its historical approach of 

relying on a set of principles or guidelines to determine what constitutes control. Thus, 

the Commission stated that it continues 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. It explained that its guiding principle is that an entity controls the facilities 

when it controls the decision-making over sales of electric energy, including discretion as 

to how and when power generated by these facilities will be sold.

44

28. The Commission also declined to adopt commenters’ suggestions that it 

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 the Commission 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, the Commission explained that it 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. The Commission’s historical practice has been to place on the filing party the 

 

43 Id. P 175. 

44 Id. P 176. 
Docket No. RM04-7-005 - 23 -

burden of determining which entity controls an asset. Therefore, the Commission 

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 control(s) the 

generation facility. However, the Commission explained that it retains the right at its 

discretion to request the seller to submit a copy of the underlying agreement(s) and any 

relevant supporting documentation. 

29. The Commission also explained in Order No. 697 that it understands that 

affected parties may hold differing views as to the extent to which control is held by the 

parties. Thus, the Commission stated that it will also require that a seller making such an 

affirmative statement seek a “letter of concurrence” from other affected parties 

identifying the degree to which each party controls a facility and submit these letters with 

its filing. Absent agreement between the parties involved, or where the Commission has 

additional concerns despite such agreement, the Commission will request additional 

information which may include, but not be limited to, any applicable contract so that it 

can make a determination as to which seller or sellers have control.45

30. In Order No. 697-A, the Commission determined that, given the increased 

level of investment in the electric utility industry as a result of the Energy Policy Act of 

 

45 Id. P 187. 
Docket No. RM04-7-005 - 24 -

2005 (EPAct 2005)46 and its implementing rules and regulations, it was necessary to 

provide further guidance with respect to the representations that a seller should make 

regarding which entity controls a particular asset. The Commission stated that an 

increasing number of investors are acquiring interests in assets that may be relevant to a 

seller’s market-based rate authority, and explained that it will continue to place on the 

filing party the burden of determining which entity controls an asset. The Commission 

stated that it will rely on the seller’s representations regarding control, absent extenuating 

circumstances. In order to provide further guidance to the industry, the Commission 

reiterated 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. The Commission 

stated that in doing so, the seller should make its representation in light of its discussion 

in Order No. 697 and cite to that order as the basis for which it has made its 

determination.47

Requests for Rehearing

 

46 Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 594 (2005). 

47 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 150. 
Docket No. RM04-7-005 - 25 -

31. SoCal Edison requests that the Commission clarify that it will not rely on 

representations as to control of generation assets made by sellers absent a letter of 

concurrence from the party alleged to control the generation asset. SoCal Edison asserts 

that Order No. 697-A at paragraph 150 is not clear with regard to this issue, and that the 

Commission should make clear that its reference to “our discussion in Order No. 697” 

means that “‘the owner of a facility is presumed to have control of the facility unless such 

control has been transferred to another party by virtue of a contractual agreement’” and 

that the Commission will only rely on the seller’s assertion of a lack of control if a letter 

of concurrence is submitted by the seller in accordance with paragraph 187 of Order No. 

697-A.48 It argues that if the Commission does not provide the requested clarification, 

the Commission erred in stating in paragraph 150 that it will rely on the assertion of a 

seller that another entity controls a generating asset owned by the seller, if that assertion 

is not supported by a letter of concurrence from the other entity.49

 

32. SoCal Edison explains that under the market power screens, the more 

generation a seller “controls,” the greater the possibility of failing one or more screens. It 

states that in Order No. 697, the Commission recognized that “‘affected parties may hold 

differing views as to the extent to which control [over generation] is held by the 

 

48 SoCal Edison Rehearing Request at 3 (quoting Order No. 697, FERC Stats. & 

Regs. ¶ 31,252 at P 183). 

49 Id. at 1 (citing Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 150). 
Docket No. RM04-7-005 - 26 -

parties.’”50 It also states that the Commission required that any seller making an 

affirmative statement of control seek a “‘letter of concurrence’” from other affected 

parties identifying the degree to which each party controls a facility and submit such 

letters with its filing. According to SoCal Edison, this approach is logical if the seller is 

trying to disclaim control over a generating facility because sellers have the incentive to 

claim that they lack control. However, SoCal Edison argues that in the absence of a letter 

of concurrence, the Commission should not assume that the seller lacks control of any 

particular generating asset identified in its Asset Appendix.51 Specifically, it argues that 

reliance on an assertion of a seller that it lacks control of a generation asset that it owns, 

absent a letter of concurrence from the other entity, is arbitrary and capricious and 

irrational, given that it is in the seller’s best interest for purposes of a market powerrelated filing to control as few generation assets as possible.52

 

33. Thus, SoCal Edison asserts that to the extent a seller represents that it controls 

generating assets, the Commission can rely on such representations, but, if the seller 

believes that another entity controls a generating asset, the seller should be required to 

 

50 Id. at 2 (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 187). 

51 Id. 

52 Id. (citing Motor Vehicle Mfrs. Ass’n of U.S. v. State Farm Mut. Auto. Ins. Co., 

463 U.S. 29, 43 (1983)). 
Docket No. RM04-7-005 - 27 -

provide a letter of concurrence. Absent such letters, SoCal Edison argues that the 

Commission should just assume the seller controls any assets that it owns.53

Commission Determination

34. We will grant the clarification requested by SoCal Edison. As we stated in 

Order No. 697, we will require a seller, who is making an affirmative statement that a 

contractual arrangement transfers control, to seek a “letter of concurrence” from other 

affected parties identifying the degree to which each party controls a facility and submit 

these letters with its filing.54 Further, we reiterate that the owner of a facility is presumed 

to have control of the facility unless such control has been transferred to another party by 

virtue of a contractual agreement55 and that the Commission will only rely on the seller’s 

assertion of a lack of control of a generating facility that it owns if a letter of concurrence 

from other affected parties is submitted by the seller with its filing in accordance with 

paragraph 187 of Order No. 697. Absent agreement between the parties involved, or 

where the Commission has additional concerns despite such agreement, the Commission 

will request additional information which may include, but not be limited to, any 

 

53 Id. at 4. 

54 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 187. 

55 Id. P 183. 
Docket No. RM04-7-005 - 28 -

applicable contract so that we can make a determination as to which seller or sellers have 

control.56

 

B. Vertical Market Power

Other Barriers to Entry

Background

35. Order No. 697 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.

57 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.58

36. On rehearing, the Commission clarified that it was not its 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 clarified that Order No. 697 encompasses physical coal sources and 

ownership of or control over who may access transportation of coal via barges and railcar 

 

56 Id. P 187. 

57 Order No. 697 FERC Stats. & Regs. ¶ 31,252 at P 440. 

58 Id. P 440. 
Docket No. RM04-7-005 - 29 -

trains.59 Thus, the Commission revised 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.”60

 

Requests for Rehearing

37. The Electric Power Supply Association (EPSA) requests that the Commission 

clarify its definition of “inputs to electric power production” as it relates to sites for new 

generation capacity development.61 EPSA points out that in response to a request by 

Southern Companies, Order No. 697-A clarifies that the reference to coal-related inputs 

extends only to ownership of or control over who may access transportation of coal via 

barges and railcar trains and was not intended “‘to encompass every instance of a seller 

entering into a coal supply contract with a coal vendor in the ordinary course of 

business.’”62 EPSA argues that consistent with the clarification granted with respect to 

coal-related inputs to generation, the Commission should clarify the “sites for new 

 

59 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176 (emphasis in original). 

60 Id. 

61 EPSA Rehearing Request at 30 (citing 18 CFR § 35.36(a)(4), 35.42(a)(1), (2) 

(2008)). 

62 Id. at 31 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 176). 
Docket No. RM04-7-005 - 30 -

generation capacity development” clause of the definition of “inputs to power 

production” in order to ensure that a market-based rate seller is not required to file 

notifications of change in status every time it or one of its affiliates acquires land. 

Specifically, EPSA argues that market-based rate sellers and their affiliates regularly 

acquire land for any number of purposes, including a wide range of purposes unrelated, 

or only indirectly related, to the development of new generation. It contends that it is 

difficult to see what useful regulatory purpose is served by notifying the Commission of 

the acquisition of a piece of land when no steps have been taken to put that land to use as 

a site for generation.63 Thus, EPSA requests clarification that the term “sites for new 

generation capacity development” means only sites with respect to which permits for new 

generation have been obtained or where construction of new generation is underway, and 

that this term does not encompass other land that could potentially be used for generation. 

EPSA argues that granting such clarification will prevent the Commission from being 

inundated with notifications of change in status relating to acquisitions of land, while 

ensuring that it still receives notices relating to changes in control over actual sites for 

generation development. 

 

63 Id. 
Docket No. RM04-7-005 - 31 -

Commission Determination

38. We appreciate the concerns raised by EPSA that market-based rate sellers 

regularly acquire land for many purposes unrelated to developing new generation and that 

the term “sites for new generation capacity development” should not be construed so 

broadly as to require unnecessary notifications of change in status relating to acquisitions 

of land to be filed. However, we are concerned that EPSA’s proposed clarification would 

define “sites for new generation capacity development” too narrowly. In particular, we 

disagree with EPSA’s proposal that the term “sites for new generation capacity 

development” should mean only sites with respect to which permits for new generation 

have been obtained or where construction of new generation is underway, and should not 

encompass land that could potentially be used for generation. We believe that “sites for 

new generation capacity development” should be construed to include ownership of land 

that could potentially be used for generation, not just sites for which permits for new 

generation have been obtained or where construction of new generation is underway. 

However, we clarify that “sites for new generation capacity development” does not 

include land that cannot be used for generation capacity development.64 Therefore, we 

deny EPSA’s request that we clarify that the term “sites for new generation capacity 

 

64 If a seller has acquired land but is explicitly prohibited from using that land for 

generation capacity development (for example, because of zoning requirements), it need 

not notify the Commission of the acquisition of that land. 
Docket No. RM04-7-005 - 32 -

development” means only sites with respect to which permits for new generation have 

been obtained or where construction of new generation is underway. 

39. In addition, in order to incorporate the clarification provided in Order No. 697-

A that it was not the 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 and the corresponding change to the regulatory 

text in § 35.36(a)(4), 65 we will revise § 35.37(e)(3) to read as follows: “Physical coal 

supply sources and ownership or control over who may access transportation of coal 

supplies.” 

C. Affiliate Abuse

1. General Affiliate Terms & Conditions

Affiliate Definition

Background

40. In Order No. 697-A, the Commission clarified 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 term is used in the regulations adopted in the Affiliate 

Transactions Final Rule.66 The Commission stated that it was taking this action in light 

 

65 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 176 

66 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), order on rehearing, Order No. 707-A, 73 FR 43072 (July 24, 

(continued) 
Docket No. RM04-7-005 - 33 -

of its 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. 

41. The Commission explained that in the Affiliate Transactions Final Rule, it 

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.67 In particular, the Commission considered its order in the 1995 Morgan 

Stanley case, in which it adopted distinct definitions of affiliate for EWGs and nonEWGs. The Commission noted there that section 214 of the Federal Power Act (FPA) 

required use of the Public Utility Holding Company Act of 1935 (PUHCA 1935) 

definition of affiliate to determine whether an electric utility is an affiliate of an EWG for 

purposes of evaluating EWG rates for wholesale sales of electric energy. The 

Commission thus stated in Morgan Stanley that the PUHCA 1935 definition of affiliate 

would apply to EWGs for matters arising under Part II of the FPA.68 For all other public 

utilities, the Commission adopted a definition that in essence treats all companies under 

the common control of another company, as well as that controlling company, as 

 

2008), FERC Stats. & Regs. ¶ 31,272 (2008) (Affiliate Transactions Final Rule 

Rehearing). 

67 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 182 (citing Morgan

Stanley Capital Group, Inc., 72 FERC ¶ 61,082, at 61,436-37 (1995) (Morgan Stanley)). 

68 Morgan Stanley, 72 FERC ¶ 61,082 at 61,436-37. 
Docket No. RM04-7-005 - 34 -

affiliates. The Commission also stated in Morgan Stanley that a ten percent or greater 

voting interest creates a rebuttable presumption of control.69 After reviewing the 

precedent established in Morgan Stanley, the Commission in the Affiliate Transactions 

Final Rule also reviewed FPA section 214 as revised by EPAct 2005 as well as the 

affiliate definitions contained in both PUHCA 193570 and the Public Utility Holding 

Company Act of 2005 (PUHCA 2005).71

 

69 Id. The Commission did this by adopting the definition of an affiliate found in 

its Standards of Conduct for Interstate Pipelines. 

70 15 U.S.C. 79a et seq. 

71 EPAct 2005 at 1261 et seq. Prior to its amendment by the Energy Policy Act of 

2005, section 214 of the FPA, 16 U.S.C. 824m, read as follows: 

No rate or charge received by an exempt wholesale generator for the sale 

of electric energy shall be lawful under section 824d of this title if, after 

notice and opportunity for hearing, the Commission finds that such rate or 

charge results from the receipt of any undue preference or advantage from 

an electric utility which is an associate company or an affiliate of the 

exempt wholesale generator. For purposes of this section, the terms 

“associate company” and “affiliate” shall have the same meaning as 

provided in section 2(a) of the Public Utility Holding Company Act of 

1935. 

EPAct 2005 amended section 214 of the FPA by substituting the reference to the 

PUHCA 1935 definition of affiliate with a reference to the PUHCA 2005 definition. 

PUHCA 2005 defines an affiliate of a specified company as any company in which the 

specified company has a five percent or greater voting interest. Thus, as revised by 

EPAct 2005, the only EWG affiliate sales that are subject to FPA section 214 are sales by 

an EWG to a company in which it owns a five percent or greater voting interest. 
Docket No. RM04-7-005 - 35 -

42. In Order No. 697-A, the Commission explained that after taking into account 

these differing definitions, and recognizing the need to provide greater clarity and 

consistency in its rules, the Commission found in the Affiliate Transactions Final Rule 

that it was important to try to adopt a more consistent definition in its various rules and 

also one that is sufficiently broad to allow the Commission to protect customers 

adequately.72 The Commission explained that on this basis, the definition of affiliate as 

adopted in the Affiliate Transactions Final Rule explicitly incorporated the PUHCA 1935 

definition of an affiliate for EWGs, which uses a five percent voting interest threshold, 

rather than incorporate it by reference, as previously had been done. The definition in the 

Affiliate Transactions Final Rule also adopted a parallel definition of affiliate for nonEWGs, but with adjustments to reflect the ten percent voting interest threshold for nonEWGs that was utilized up to that time and to eliminate certain language not applicable 

or necessary in the context of the FPA. The Commission in Order No. 697-A then 

adopted in this rule the same definition of “affiliate” that it had adopted in the Affiliate 

Transactions Final Rule. The Commission therefore codified the definition of affiliate in 

its market-based rate regulations at § 35.36. 

 

72 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 182. 
Docket No. RM04-7-005 - 36 -

Requests for Rehearing and Order Requesting Supplemental Comments73

43. EPSA, the Mirant Entities (Mirant),74 and Reliant Energy, Inc. (Reliant) argue 

on rehearing that the Commission erred in adopting a separate “affiliate” definition for 

EWGs.75

 

44. In response to the legal and policy arguments petitioners raised on rehearing in 

opposition to a separate definition of affiliate for EWGs, the Commission issued an order 

requesting supplemental comments on the definition of “affiliate” adopted in Order No. 

697-A and codified in § 35.36(a)(9) of the Commission’s regulations.76 In the Order 

Requesting Supplemental Comments, the Commission explained that having again 

analyzed FPA section 214, and irrespective of any Commission precedent to the contrary, 

a reasonable interpretation of FPA section 214 is that it does not require the Commission 

to use a five percent threshold affiliate test for EWGs for all purposes under Part II of the 

 

73 Market-Based Rates For Wholesale Sales of Electric Energy, Capacity and 

Ancillary Services by Public Utilities, 73 FR 51744 (Sept. 5, 2008), 124 FERC ¶ 61,213 

(2008) (Order Requesting Supplemental Comments). 

74 The Mirant Entities are Mirant California, LLC, Mirant Delta, LLC, Mirant 

Potrero, LLC, Mirant Canal, LLC, Mirant Kendal, LLC, Mirant Bowline, LLC, Mirant 

Lovett, LLC, Mirant Chalk Point, LLC, Mirant Mid-Atlantic, LLC, Mirant Potomac 

River, LLC, and Mirant Energy Trading, LLC. 

75 EPSA Rehearing Request at 5 (citing Order No. 697, FERC Stats. & Regs. 

¶ 31,252 at P 182-83); Mirant Rehearing Request at 6-7; Reliant Rehearing Request at 2-

3. These rehearing requests are addressed in greater detail in the Order Requesting 

Supplemental Comments. 

76Order Requesting Supplemental Comments, 124 FERC ¶ 61,213. 
Docket No. RM04-7-005 - 37 -

FPA, and in particular for purposes of analyzing market concentration and market 

power.

77 The Commission also found the arguments in support of a single definition of 

affiliate, applicable to both EWGs and non-EWGs, to be persuasive. Therefore, upon 

reconsideration, the Commission stated that using the same definition for EWGs as for 

non-EWGs is appropriate and that the definition the Commission adopted in Order No. 

697-A for non-EWG utilities would not affect the substance of the Commission’s 

analysis of market power issues. The Commission explained that this definition is based 

on the structure of the PUHCA 1935 definition, but modified in several ways, including 

use of a ten percent threshold instead of five percent.78

45. Therefore, in the Order Requesting Supplemental Comments, the Commission 

stated that it intends to revise the definition of affiliate in § 35.36(a)(9) of its regulations 

to delete the separate definition for EWGs and to revise the non-EWG part of the 

definition to delete the phrase “other than an exempt wholesale generator.”79 The 

Commission stated that before taking final action in response to the rehearing comments, 

 

77 Section 214 uses a five percent affiliate threshold with respect to determining 

whether the jurisdictional rates of an EWG are the result of a preference or advantage of 

an affiliate of the EWG. While an analysis of market power relates to an EWG’s rates, it 

does not involve the specific issue of whether an EWG has received an undue preference 

or advantage with respect to a particular wholesale sale. See id. n.23. 

78 Order Requesting Supplemental Comments, 124 FERC ¶ 61,213 at P 11. 

79 Id. P 12. 
Docket No. RM04-7-005 - 38 -

however, it would seek supplemental comments on the proposed revised definition of 

affiliate in § 35.36(a)(9). 

Comments

46. EPSA and the Edison Electric Institute (EEI) submitted comments in response 

to the Order Requesting Supplemental Comments. EPSA “applauds” the Commission’s 

proposal to delete the separate definition of affiliate for EWGs and to make all entities 

subject to the ten percent threshold, and urges the Commission to move forward as 

proposed in the Order Requesting Supplemental Comments.80 However, EPSA also 

requests that the Commission “make clear that codifying a technical definition of 

‘affiliate’ is without prejudice to the Commission’s providing guidance on ‘control’ and 

‘affiliation’ in both case-specific and generic proceedings.”81 In this regard, EPSA notes 

that its recently-submitted petition for guidance on “control” and “affiliation” issues 

relating to investments in publicly-traded companies addresses common control and 

reporting issues that are separate from the issue in this proceeding on the technical 

definition of affiliate for purposes of the Commission’s market-based rate regulations.82

 

EPSA’s supplemental comments also reiterate EPSA’s argument that a separate 

 

80 EPSA October 20, 2008 Supplemental Comments at 2. 

81 Id. 

82 Id. at n.5 (citing EPSA September 2, 2008 Petition for Guidance, Docket No. 

EL08-87-000). 
Docket No. RM04-7-005 - 39 -

definition of affiliate for EWGs and non-EWGs is not required by the FPA.83 EPSA 

further argues that a separate definition of affiliate for EWGs puts EWGs at an unfair 

disadvantage in determining market power under the Commission’s market-based rate 

program since use of a five percent ownership threshold for EWGs imposes substantially 

greater burdens on EWGs for no useful regulatory purpose.

84

47. In its supplemental comments, EEI states that it supports the proposed change 

in the Order Requesting Supplemental Comments, and agrees with the Commission’s 

reasoning that section 214 of the FPA does not require use of a five percent threshold for 

EWGs for all purposes under the FPA.85 EEI further states that the Affiliate Transactions

Final Rule fully addresses the requirement in FPA section 214 that the Commission 

ensure that the rates received by an EWG do not result from the receipt of any undue 

preference or advantage from an electric utility which is an associate company or an 

affiliate of the EWG. Thus, EEI concludes that there is no need to import the five percent 

threshold to market concentration and market power analyses under the market-based rate 

regulations. EEI also states that there is an advantage in terms of fairness and 

 

83 Id. at 3. 

84 Id. at 3-4. 

85 EEI October 20, 2008 Supplemental Comments at 2. 
Docket No. RM04-7-005 - 40 -

consistency to using the same ten percent threshold for both EWGs and non-EWGs in the 

market-based rate regulations.86

Commission Determination

48. As proposed in the Order Requesting Supplemental Comments, and for the 

reasons discussed therein and described above,87 the Commission will revise the 

definition of affiliate in § 35.36(a)(9) of its regulations to delete the separate definition 

for EWGs and to revise the non-EWG part of the definition to delete the phrase “other 

than an exempt wholesale generator.” Specifically, the definition of affiliate in § 

35.36(a)(9) is being revised to provide that an affiliate of a specified company means: (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 

 

86 Id. at 3. 

87 See supra P 43-44. 
Docket No. RM04-7-005 - 41 -

investors or consumers that the person be treated as an affiliate; and (d) Any person that 

is under common control with the specified company. For purposes of paragraph (a)(9), 

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. This revision to the definition of affiliate in § 35.36(a)(9) of the market-based 

rate regulations does not preclude the Commission from providing guidance on control 

and affiliation in both case-specific and generic proceedings. We note that the issue of 

what constitutes control for FPA section 203 purposes and market-based rate purposes is 

the subject of a petition for guidance filed by EPSA in Docket No. PL09-3-000. This is 

an issue of significance to the industry that the Commission intends to address in a 

separate docket, following consideration of EPSA’s petition in Docket No. PL09-3-000. 

2. Power Sales Restrictions

Sales of Non-Power Goods and Services

Background

49. 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, 
Docket No. RM04-7-005 - 42 -

unless otherwise authorized by the Commission. The Commission explained that this 

requirement protects a utility’s captive customers against inappropriate crosssubsidization of market-regulated power sales affiliates by ensuring that the utility with 

captive customers does not pay too much for goods and services that the utility receives 

from a market-regulated power sales affiliate.88

Requests for Rehearing

50. FP&L sought 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.89

 

51. 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 

 

88 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 597. 

89 FP&L March 24, 2008 Request for Clarification. 
Docket No. RM04-7-005 - 43 -

at fully-loaded cost as a reasonable proxy for market price.90 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)91 also 

applies with respect to the requirements of Order No. 697 where existing inter-affiliate 

transactions involving non-power goods and services are comparable to those provided 

by a centralized service company.

Commission Determination

52. In Order No. 697-A, the Commission explained that issues similar to those 

raised here by FP&L also were 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. The Commission stated that to ensure consistency in its approach to 

pricing of non-power goods and services between both rulemaking proceedings, the 

Commission would address FP&L’s arguments concerning Order No. 697 in a 

supplemental order.92 We address below the arguments raised by FP&L in its March 24, 

2008 request for clarification. 

 

90 Id. at 4. 

91 Id. at 13 (citing Affiliate Transactions Final Rule, FERC Stats. & Regs. ¶ 31,264 

at P 85). 

92 The Commission noted that it need not address all issues raised in a proceeding 

at one time. Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 222 (citing Mobil Oil 

Exploration & Producing Southeast, Inc. v. United Distribution Companies, 498 U.S. 211 

(continued) 
Docket No. RM04-7-005 - 44 -

53. We deny FP&L’s request for clarification that fully-loaded cost is a reasonable 

proxy for market price. On rehearing of the Affiliate Transactions Final Rule, the 

Commission found the arguments in favor of permitting companies within a single-state 

holding company system that does not have a centralized service company to provide 

each other general administrative and management services to be persuasive, and 

therefore revised its rules to permit affiliates within a single-state holding company 

system, as defined by Commission rules, that do not have a centralized service company, 

to provide “at cost” to other affiliates in the system the kinds of services typically 

provided by centralized service companies and the goods to support those services.93 In 

light of its determination to permit companies within a single state holding company 

system that do not have a centralized service company to provide each other general 

administrative and management services at cost, the Commission explained that there 

was no need to grant FP&L’s request for clarification that non-power goods and services 

may be provided at fully-loaded cost as a reasonable proxy for market price.94 It also 

explained that “making fully-loaded cost a proxy for market price unnecessarily clouds 

 

(1991) (holding that an agency enjoys broad discretion in determining procedurally how 

best to handle related yet discrete issues)); 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). 

93 Affiliate Transactions Final Rule Rehearing, FERC Stats. & Regs. ¶ 31,272 at 

P 23. 

94 Id. P 24-31. 
Docket No. RM04-7-005 - 45 -

the distinction between at-cost and market pricing embodied in [the Commission’s] 

rules.”95 Thus, consistent with our determination in the Affiliate Transactions Final Rule 

Rehearing, we will deny FP&L’s request for clarification in the instant proceeding that 

fully-loaded cost is a reasonable proxy for market price. 

54. With regard to FP&L’s argument that the Commission should make clear that 

the grandfathering language in the Affiliate Transactions Final Rule also applies with 

respect to the requirements of Order No. 697 where existing inter-affiliate transactions 

involving non-power goods and services are comparable to those provided by a 

centralized service company,96 we note that the Commission previously addressed and 

rejected this argument. In the Commission’s order granting an extension of time in the 

Affiliate Transactions rulemaking proceeding,97 the Commission explained “[o]ur 

‘grandfathering’ of preexisting contracts, agreements and arrangements was only for 

purposes of compliance of [the Affiliate Transactions Final Rule]. To the extent public 

utilities were required to comply with the same or similar pricing restrictions pursuant to 

a merger order or in conjunction with a market-based rate authorization, our action to 

make Order No. 707 compliance prospective only did not change any such obligations 

 

95 Id. P 31. 

96 FP&L March 24, 2008 Request for Clarification at 13-14. 

97 Cross-Subsidization Restrictions on Affiliate Transactions, 122 FERC ¶ 61,280, 

at n.5 (2008). 
Docket No. RM04-7-005 - 46 -

under other orders or rules. That is, pricing restrictions imposed pursuant to a merger 

order, a market-based rate authorization order or the Commission’s market-based rate 

rules are not within the scope of [the Affiliate Transactions Final Rule] and, consequently, 

the [Affiliate Transactions Final Rule] grandfathering provision does not relieve a public 

utility of its obligations under other orders and rules with respect to contracts, agreements 

or arrangements entered into prior to March 31, 2008.”98

 

3. Market-Based Rate Affiliate Restrictions

Risk Management Employees Under the No-Conduit Rule

Background

55. In Order No. 697, 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.99 Otherwise, Order No. 697 did not specifically address the sharing 

of risk management employees. 

56. On rehearing of Order No. 697, the Commission determined that “risk 

management personnel do not fall within the scope of the independent functioning rule, 

 

98 Id. at n.5. See also Affiliate Transactions Final Rule Rehearing, FERC Stats. & 

Regs. ¶ 31,272 at P 78. 

99 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 561 (codified at 18 CFR 

35.39(g)). 
Docket No. RM04-7-005 - 47 -

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.”

100

Requests for Rehearing

57. EEI stated that the Commission’s clarification with regard to risk management 

personnel is consistent with the Commission’s focus in the Commission’s evolving 

standards of conduct on clarifying that personnel who are neither transmission function 

nor marketing function employees are primarily governed by the no-conduit rule. 

However, EEI states that the regulatory text of Order No. 697, in the affiliate restrictions 

provisions at 18 CFR 35.39(c), does not reflect this clarification or fully reflect the 

evolution of the standards of conduct. It further states that Order No. 697-A does not 

modify the regulatory text to reflect these changes. 

58. Therefore, EEI encourages the Commission to amend the regulatory text at 18 

CFR 35.39(c) to reflect that all employees who are neither transmission nor wholesale 

marketing function employees are not within the scope of the independent functioning 

rule, but remain subject to the no-conduit rule. EEI argues that this change would 

 

100 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 256 (citing Standards of 

Conduct for Transmission Providers, Notice of Proposed Rulemaking, 73 FR 16228 

(March, 27, 2008), FERC Stats. & Regs. ¶ 32,630 (March 21, 2008). 
Docket No. RM04-7-005 - 48 -

conform regulations under Orders No. 697 and 697-A to the Commission’s current 

approach in the standards of conduct, moving away from the corporate separation 

approach to the functional approach, while recognizing the need for shared employees. 

Further, EEI asserts that this approach would be consistent with the Commission’s 

statement in Order No. 697 that “the requirements and exceptions in the affiliate 

restrictions should follow those requirements and exceptions codified in the standards of 

conduct, where applicable.”101

Commission Determination

59. As EEI notes, the Commission clarified in Order No. 697-A 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. As an initial 

matter, in response to EEI’s request for rehearing, we believe that clarification of the 

statement in Order No. 697-A would be helpful. In particular, the reference in Order No. 

697-A to “marketing function employees as defined in the standards of conduct” may 

have been misleading because the affiliate restrictions address franchised public utilities 

with captive customers and market-regulated power sales affiliates, not “marketing 

function employees as defined in the standards of conduct.” Accordingly the clarification 

 

101 Id. (quoting Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 550). 
Docket No. RM04-7-005 - 49 -

in Order No. 697-A should not have included the reference to marketing function 

employees. When the Commission stated 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, the intent was that a franchised public utility with 

captive customers and its market-regulated power sales affiliates should be permitted to 

share risk management personnel subject to the no conduit rule. In other words, risk 

management personnel may perform risk management activities on behalf of both a 

franchised public utility with captive customers and its market-regulated power sales 

affiliates. However, risk management personnel are prohibited from acting as a conduit 

for disclosing market information subject to the information sharing prohibition in 

section 35.39(d)(1). With this clarification, we do not believe that it is necessary to 

amend the regulatory text at 18 CFR 35.39(c) as requested by EEI. 

D. Mitigation

Protecting Mitigated Markets

Sales at the Metered Boundary

Background

60. In Order No. 697, the Commission stated that it would continue to apply 

mitigation to all sales in the balancing authority area in which a seller is found, or 
Docket No. RM04-7-005 - 50 -

presumed, to have market power.102 However, the Commission said it would allow 

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.103 The Commission also 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 sufficient documentation and use a specific tariff provision for such sales.104

61. On rehearing in Order No. 697-A, the Commission revised the tariff language 

governing market-based rate sales at the metered boundary to conform with the 

discussion in the December 14 Clarification Order regarding use of the term “mitigated 

market.” The Commission stated that, as explained in the December 14 Clarification 

 

102 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. December 14 Clarification Order, 121 FERC ¶ 61,260 at P 7 & n.10. 

103 Order No. 697, FERC Stats. & Regs. ¶ 31,252 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)). 

104 Id. P 830. 
Docket No. RM04-7-005 - 51 -

Order, “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.105

 

62. In addition, after considering comments regarding the difficulty of determining 

and documenting intent, the Commission decided in Order No. 697-A to eliminate the 

intent element of the tariff provision, which stated that “any power sold hereunder is not 

intended to serve load in the seller’s mitigated market.” Because the Commission 

eliminated the seller’s intent requirement, it modified the 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.”106 In this regard, the Commission noted that 

“[t]o provide additional regulatory certainty for mitigated sellers, the Commission 

clarified 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.”107 The 

Commission also stated that because it was eliminating the intent requirement, it need not 

address issues raised regarding documentation necessary to demonstrate the mitigated 

seller’s intent. 

 

105 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 333. 

106 Id. P 334. 

107 Id. at n.464. 
Docket No. RM04-7-005 - 52 -

63. Further, in response to a request for clarification submitted by Pinnacle, the 

Commission clarified that 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.108 Accordingly, the Commission clarified that an 

affiliate of a mitigated seller is prohibited from selling power that was 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. The Commission 

stated that 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.109

Requests for Rehearing

64. In response to the Commission’s modification of the condition on sales of 

market-based power at the border between a mitigated market and unmitigated market to 

state that “‘the Seller and its affiliates [may] not sell the same power back into the 

 

108 Id. P 335. 

109 Id. P 336. 
Docket No. RM04-7-005 - 53 -

balancing authority area where the seller is mitigated,’”110 E.ON argues that the 

Commission should delete this condition imposed on border sales or clarify (1) what is 

meant by the term “same power” and (2) that neither a seller nor its affiliate will be found 

in violation of this condition if the affiliate did not know that it was the “same power” 

being sold into the mitigated market. 

65. E.ON states that use of the term “same power” causes confusion, as it is 

unclear what practical need exists for the condition generally.111 E.ON submits that the 

condition is unnecessary insofar as where a given seller is prohibited from selling marketbased power into a given market, it is almost certain that any affiliate of that seller is also 

prohibited from making such sales, except under an agreement that predates the 

mitigation for that market (a grandfathered agreement).112 E.ON argues that in the 

limited case of such an agreement, the “same power” condition need not apply because 

sales under such a grandfathered agreement are permitted to continue after a finding of 

market power by the seller and its affiliates because the agreement was not tainted by 

market power and/or the buyer is protected from the exercise of market power. E.ON 

 

110 E.ON Rehearing Request at 11 (quoting Order No. 697-A, FERC Stats. & Regs. 

¶ 31,268 at P 339). 

111 Id. at 4 (citing Paralyzed Veterans of Amer. v. D.C. Arena L.P., 117 F.3d 579, 

584 (D.C. Cir. 1997), cert. denied sub nom Abe Pollin, et al. v. Paralyzed Veterans of 

Amer., 523 U.S. 1003 (1998)). 

112 Id. at 12 (citing MidAmerican Energy Co., 123 FERC ¶ 61,013, at P 37 (2008)). 
Docket No. RM04-7-005 - 54 -

asserts that under these circumstances, there is no reason not to allow the “same power” 

sold by a mitigated seller to be resold into the mitigated market by an affiliate under such 

a grandfathered agreement.113

66. Further, E.ON argues that the term “same power” is facially ambiguous and 

impossible to define or apply in a practical manner. E.ON submits that power cannot be 

“‘color coded’” so that a buyer knows exactly the source of the power received. E.ON 

states that where one single transmission tag indicates a change of specific transfers of 

possession of a block of power among several parties, it may be reasonable to assume the 

power sold and resold is the “same power.” However, E.ON argues that beyond this 

limited situation, it is unclear what the Commission would consider to be the “same 

power.” It asks whether it is the same power if Party A sells 100 MW to Party B at Bus 

X, and Party B, who is not affiliated with Party A and using a different transmission tag, 

wheels 100 MW to Bus Y and then sells 100 MW at Bus Y to Party C, who is an affiliate 

of Party A. E.ON also argues that Party A and Party C would have no meaningful ability 

to avoid dealing in the “same power” short of very unreasonable steps. It asserts that 

Party A and Party C could both cease making border sales, or Party A and Party C could 

require Party B to tell Party A and/or Party C that they are linked in the sale by Party B in 

order to avoid this risk. According to E.ON, such an obligation is not assumed by parties 

 

113 Id. 
Docket No. RM04-7-005 - 55 -

in any current structure of power sales transactions, and it would not be a burden the 

Commission should expect Party B to be willing to undertake.114

67. E.ON also contends that sellers of power often do not know the ultimate fate 

of power sold, and that a seller does not normally concern itself with the buyer’s ultimate 

plans for the power, particularly once the seller’s risk of loss and title has been 

transferred to the buyer. It submits that it is not normal industry practice for a seller of 

power to seek assurances or commitments from a buyer about what the buyer intends to 

do with the power, and that such activities could raise antitrust or other anticompetitive 

concerns.

115 Further, it argues that the Commission should not assume each seller is 

aware of all sales and purchases of power at the same location in the same hour by its 

affiliates because the affiliate restriction regulations promulgated by the Commission 

prevent any kind of sharing of “‘market information’” between a “‘franchised public 

utility’” and its “‘market-regulated power sales affiliate.’”116 E.ON therefore contends 

that two affiliates could theoretically deal in the “same power” without having any intent 

to do so. 

68. Pinnacle argues that the Commission should clarify that resales of mitigated 

border purchases are not permanently banned from reentering the mitigated area. 

 

114 Id. at 14. 

115 Id. at 13. 

116 Id. at 13-14 (quoting 18 CFR § 35.36 et seq.). 
Docket No. RM04-7-005 - 56 -

Specifically, Pinnacle argues that the Commission’s statement that “an affiliate of a 

mitigated seller is prohibited from selling power that was 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” is inaccurate as phrased.117 Pinnacle 

asserts that this statement appears to presume that power purchased at market-based rates 

from any party cannot be resold at cost-based rates. Pinnacle states that it is not aware of 

any prohibition against purchasing at market-based rates and re-selling that same power 

at cost-based rates as long as affiliates are not in the chain of sale. Further, Pinnacle 

argues that virtually all purchases by a mitigated seller in its mitigated area will be 

purchased at market-based rates, and states that if the Commission’s statement were true, 

it would preclude mitigated sellers from ever purchasing power from any party at the 

metered boundary of its mitigated area to serve wholesale load in the mitigated area at 

cost-based rates.118

69. In addition, Pinnacle argues that although the Commission’s statement that 

“[t]o 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 

 

117 Id. at 4 (quoting Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 335). 

118 Id. 
Docket No. RM04-7-005 - 57 -

eliminating the danger that they will violate their tariff by re-selling the power back into a 

balancing authority in which they are mitigated” eases documentation requirements for 

real-time sales, Pinnacle is concerned that such a requirement will reduce liquidity in the 

market by precluding longer term market-based rate sales at the metered boundaries of 

mitigated sellers.119 Pinnacle states that any long-term sales made, particularly to 

marketers, may change hands multiple times. It also argues that tracking power back to 

the original seller, and original point of purchase, to guarantee that none of the energy it 

is purchasing was originally part of the long-term sale made by its affiliate to the 

marketer will be nearly impossible on a real-time basis when a mitigated seller is trying 

to make a short-term purchase. Therefore, Pinnacle argues that the mitigated seller 

would effectively be precluded from making anything other than real-time sales to a 

marketer on the slim chance that some of that power might come back into the control 

area on a short-term basis in a subsequent purchase.

120

70. Further, Pinnacle states that even without the intent requirement, a seller in a 

long-term sale in many cases would only be able to track the path of the power through 

NERC tags after the power is delivered, since for a longer term sale, a tag is not created 

at the time the transaction is executed. Pinnacle states that it believes that counterparties 

 

119 Id. (quoting Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 336). 

120 Id. at 5. 
Docket No. RM04-7-005 - 58 -

will likely not agree to limitations on where the power can sink on term deals, 

particularly as neither Order No. 697 nor Order No. 697-A require contractual limits. 

Pinnacle explains that an example that illustrates this situation occurs “if APS sold power 

at Pinnacle Peak (a border of the Phoenix Valley Load Pocket, the Pinnacle West 

Companies’ mitigated area) for a year to a marketer, and then later, on a day during the 

season mitigated for [Pinnacle], APS’s affiliate purchased power from the same marketer 

to serve load in the Phoenix Valley Load Pocket, this transaction would violate the 

regulations as currently written, even though there was no intent to bring the power back 

into the mitigated area at the time of the sale.”121

 

71. Pinnacle explains that since there is no way to predict when the power is going 

to be needed in the mitigated area and from whom it may be purchased, the only way to 

ensure that this scenario does not occur inadvertently is for mitigated sellers to make no 

market-based rate sales at their mitigated borders for anything other than real-time sales. 

Pinnacle states that otherwise, all of the mitigated affiliates (including the initial border 

seller) would be precluded from purchasing power anywhere to serve load in their 

mitigated areas because they could not be sure that the power was not originally a 

market-based border sale.122 According to Pinnacle, even sales to serve load outside the 

 

121 Id. at 6. 

122 Id. 
Docket No. RM04-7-005 - 59 -

mitigated area are not guaranteed to remain out of the mitigated area since load may 

decrease or transmission problems getting the power to the purchaser’s load may require 

the purchaser to sell the power back to the mitigated seller or an affiliate, resulting in its 

possible return to the mitigated area. On this basis, Pinnacle asks the Commission to 

clarify that if a sale is made at a metered boundary point and there is no contemporaneous 

arrangement with the counter-party to return the power to the mitigated market area, then 

there is no ongoing requirement to track the power to ensure that it never reenters the 

mitigated market through an incidental sale. 

72. Pinnacle also submits that the Commission erred by providing default tariff 

language that defines the mitigated area to be a seller’s balancing authority area. 

Pinnacle argues that the Commission should clarify that the default tariff language for 

metered boundary sales is at the boundary of the mitigated area. Pinnacle argues that not 

all mitigated sellers are mitigated in an entire balancing authority area, and that in the 

case of the Pinnacle West Companies, the Commission has determined that the mitigation 

is limited to the Phoenix Valley Load Pocket (a small portion of the APS Balancing 

Authority Area) during the summer months only.123 Pinnacle requests that the 

Commission clarify that the tariff provision is meant to encompass only the mitigated 

area of each seller, and requests that the Commission revise this language to state that 

 

123 Id. at 3 (Pinnacle West Capital Corp., 120 FERC ¶ 61,153, at P 38 (2007), 

order on compliance filing and clarification, 122 FERC ¶ 61,035 (2008)). 
Docket No. RM04-7-005 - 60 -

“‘the mitigated seller and its affiliate do not sell the power back into the seller’s mitigated 

market.’” If the Commission declines to make this revision, Pinnacle seeks rehearing of 

the requirement, arguing that restrictions on sales should be limited to the more focused 

mitigated area defined for mitigated companies when the mitigation is for less than an 

entire balancing authority area.124

73. Wisconsin Electric states that it has a Commission-approved market-based rate 

tariff that permits it to make wholesale sales at or beyond the metered boundary of the 

Wisconsin-Upper Michigan System (WUMS) region, and that provides that the WUMS 

restriction does not apply to Wisconsin Electric’s transactions in the Midwest ISO energy 

market. It requests that the Commission clarify, or in the alternative, grant rehearing of 

Order No. 697-A to make clear that Order No. 697-A does not modify the terms of 

Wisconsin Electric’s market-based rate tariff or the manner in which wholesale sales are 

conducted in the Midwest ISO energy market. Specifically, Wisconsin Electric argues 

that the Commission should make clear that Wisconsin Electric remains able to sell 

energy into the Midwest ISO energy market without “at or beyond the metered 

boundary” restrictions or requirements to obtain transmission to effectuate the transaction. 

74. In addition, Wisconsin Electric argues that the Commission should make clear 

that, for bilateral energy and capacity transactions that are not covered by the Midwest 

 

124 Id. 
Docket No. RM04-7-005 - 61 -

ISO tariff, Wisconsin Electric, as a mitigated seller subject to an “at or beyond the 

metered boundary” limitation, or the purchaser may use network transmission service to 

effectuate the sale at or beyond the metered boundary if allowable. Wisconsin Electric 

argues that while network service is normally used to serve load rather than make offsystem sales,125 the Commission should permit network service to be used in this instance. 

It submits that mitigated sellers will be unable to compete if they are forced to bear the 

costs of point-to-point transmission service to transmit the power to the metered 

boundary, and further asserts that the requirement to bear such transmission costs will 

render useless the ability to make sales at the metered boundary, because the point-topoint transmission costs layered on top of the energy and capacity costs would likely 

render the sale uneconomic. Wisconsin Electric therefore concludes that wholesale 

customers in balancing authority areas in which the mitigated seller is authorized to make 

market-based sales will be left with fewer purchase options.126

75. Finally, Wisconsin Electric argues that the Commission should clarify that the 

metered boundary will not be the entire Midwest ISO footprint after the Midwest ISO 

ancillary services market becomes operational. In particular, it states that when the 

ancillary services market becomes operational, the Midwest ISO region will become a 

 

125 Id. at 5 (citing In re SCANA Corp., 118 FERC ¶ 61,028 (2007)). 

126 Id. 
Docket No. RM04-7-005 - 62 -

single balancing authority area, with the former balancing authorities becoming “local 

balancing authorities.” Thus, Wisconsin Electric concludes that the WUMS region will 

consist of a combination of “local balancing authority areas” within the Midwest ISO 

balancing authority area, rather than the current combination of balancing authority areas. 

Wisconsin Electric states that it lacks authority to make certain bilateral market-based 

rate sales within the WUMS region and is authorized to make such sales at or beyond the 

metered boundary between WUMS and neighboring regions.127 It argues that 

commencement of operations under the ancillary services market will have no effect on 

Wisconsin Electric’s market power, and that the Commission should make clear that the 

same geographic boundaries will continue to apply with respect to Wisconsin Electric’s 

market-based rate authority after the ancillary services market becomes operational so 

that following commencement of operations under the ancillary services market, 

Wisconsin Electric will still be permitted to make bilateral market-based sales at or 

beyond the metered boundary between WUMS and neighboring regions, and to make 

market-based sales within the Midwest ISO energy market.128

Commission Determination

 

127 Id. at 6 (citing Wisconsin Elec. Power Co., Docket No. ER98-855-009, 

(Apr. 18, 2008) (unpublished letter order). 

128 Id. at 6-7. 
Docket No. RM04-7-005 - 63 -

76. We appreciate E.ON’s concerns regarding the difficulty of defining the term 

“same power.” For this reason, we will revise the tariff provision for market-based rate 

sales at the metered boundary, which incorporated the provision that the “Seller and its 

affiliates do not sell the same power back into the balancing authority area where the 

seller is mitigated,” to state that “if the Seller wants to sell at the metered boundary of a 

mitigated balancing authority area at market-based rates, then neither it nor its affiliates 

can sell into that mitigated balancing authority area from the outside.” A seller that 

includes this provision in its market-based rate tariff should update its tariff with the 

revised provision the next time that it files revised tariff sheets, a triennial review, or a 

change in status report. 

77. With regard to the requests of E.ON and Pinnacle that the Commission clarify 

that neither a seller nor its affiliate will be found in violation of this tariff provision if the 

seller’s affiliate did not know that it was the “same power” being sold into the mitigated 

market, as explained above, we are revising the tariff provision for sales at the metered 

boundary to remove the language stating “the mitigated seller and its affiliates do not sell 

the same power back into the balancing authority area where the seller is mitigated” and 

replacing it with “if the Seller wants to sell at the metered boundary of a mitigated 

balancing authority area at market-based rates, then neither it nor its affiliates can sell 

into that mitigated balancing authority areas from the outside.” We note that this revised 

tariff language will prevent a mitigated seller making market-based rate sales at the 
Docket No. RM04-7-005 - 64 -

metered boundary from selling power into the mitigated market through its affiliates. In 

other words, sellers may choose to make no market-based rate sales at the metered 

boundary, or to limit such sales to sales to end users of the power, thereby eliminating the 

danger they will violate their tariff by re-selling power back into a balancing authority in 

which they are mitigated.129 In Order No. 697-A, in response to Pinnacle’s request for 

clarification of Order No. 697, the Commission clarified that “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.”130 Order No. 697-A therefore clarified that an affiliate of a mitigated 

seller is prohibited from selling power that was 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.131 To provide additional regulatory certainty 

for mitigated sellers, the Commission clarified that “once the power has been sold at the 

metered boundary at market-based rates, the mitigated seller and its affiliates may not sell 

 

129 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 336. 

130 Id. P 335. 

131 Id. 
Docket No. RM04-7-005 - 65 -

that same power back into the mitigated balancing authority area, whether at cost-based 

or market-based rates.”132

78. With regard to Pinnacle’s assertion that the Commission’s statement at 

paragraph 335 of Order No. 697-A that “an affiliate of a mitigated seller is prohibited 

from selling power that was 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” appears to presume that power purchased at market-based rates from 

any party cannot be resold at cost-based rates, we clarify that entities that are not

affiliated with the seller may sell power back into the mitigated market. 

79. With regard to Pinnacle’s request that we clarify that the tariff language for 

sales of power at market-based rates at the metered boundary is meant to encompass only 

the mitigated area of each seller, we note that we have granted Pinnacle’s request to 

permit it to revise its tariff language for metered boundary sales to replace “balancing 

authority area where the seller is mitigated” with “seller’s mitigated market.”133 However, 

we permitted Pinnacle to revise its tariff language in this regard because it is not 

mitigated in an entire balancing authority area; rather Pinnacle is mitigated in the Phoenix 

Valley Load Pocket, a small portion of the APS balancing authority area, during the 

 

132 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at n.464. 

133 Arizona Public Service Co., Docket No. EL08-1104-000, at 1 (July 3, 2008) 

(unpublished letter order). 
Docket No. RM04-7-005 - 66 -

summer months only. We will permit such tariff revisions only on a case-by-case basis. 

Thus, other mitigated sellers seeking to modify their tariffs in this regard must submit a 

filing at the Commission pursuant to section 205 of the FPA, and should explain why 

they should be permitted to revise their tariff language for sales of power at market-based 

rates at the metered boundary. 

80. With regard to Wisconsin Electric’s arguments on rehearing, we grant 

Wisconsin Electric’s request for clarification that Order No. 697-A did not modify the 

terms of Wisconsin Electric’s market-based rate tariff (which allowed Wisconsin Electric 

to sell energy into the Midwest ISO energy market without “at or beyond the metered 

boundary” restrictions) or the manner in which wholesale sales are conducted in the 

Midwest ISO energy market.134 We further note that, subsequent to the filing of its 

rehearing request in this proceeding, the Commission accepted a tariff filing by 

Wisconsin Electric that removed from its market-based rate tariff the provision 

prohibiting Wisconsin Electric from making bilateral market-based rate sales in 

WUMS.135

 

 

134 Wisconsin Electric Power Co., 110 FERC ¶ 61,340, reh’g denied, 111 FERC 

¶ 61,361 (2005). 

135 Wisconsin Electric Power Company, Docket No. ER08-1176-000 (Aug. 22, 

2008) (unpublished letter order). 
Docket No. RM04-7-005 - 67 -

81. With regard to Wisconsin Electric’s request for clarification that the same 

geographic boundaries will continue to apply with respect to Wisconsin Electric’s 

market-based rate authority after the Midwest ISO ancillary services market becomes 

operational, so that following commencement of operations under the Midwest ISO 

ancillary services market Wisconsin Electric will still be permitted to make bilateral 

market-based sales at or beyond the metered boundary between WUMS and neighboring 

regions and to make market-based sales within the Midwest ISO energy market, we find 

that this request for clarification is moot. As explained above, the Commission accepted 

Wisconsin Electric’s filing removing the tariff restriction prohibiting it from making 

market-based rate sales in WUMS.136 Thus, Wisconsin Electric is no longer subject to a

limitation that bilateral sales at market-based rates must be made at the metered boundary 

between WUMS and neighboring regions. Similarly, Wisconsin Electric’s request for 

clarification that, for bilateral energy and capacity transactions that are not covered by the 

Midwest ISO tariff, Wisconsin Electric, as a mitigated seller subject to an “at or beyond 

the metered boundary” limitation, or the purchaser may use network transmission service 

to effectuate the sale at or beyond the metered boundary if allowable is also moot in light 

of the removal of the WUMS restriction in Wisconsin Electric’s tariff. 

 

136 Id. 
Docket No. RM04-7-005 - 68 -

82. To the extent that Wisconsin Electric is also asking on rehearing that the 

Commission clarify that any mitigated seller with authority to make sales at the metered 

boundary may use its network transmission service (as opposed to point-to-point service) 

to transport the electric energy to or beyond the metered boundary to the extent that 

transmission service is necessary to engage in wholesale sales at or beyond the metered 

boundary, we will deny that request. The Commission rejected a similar argument by 

Oklahoma Gas & Electric (OG&E) in Order No. 697-A, and Wisconsin Electric has 

failed to persuade us on rehearing that our determination in that regard was in error. 

Similar to the arguments raised by Wisconsin Electric, OG&E claimed that a mitigated 

seller’s ability to compete will be undermined if it attempts to transact with a purchaser 

willing to use the purchaser’s existing network transmission service. OG&E complained 

that because a mitigated seller must incur transmission costs to deliver the power in this 

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. In response to 

these arguments, the Commission found that 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 
Docket No. RM04-7-005 - 69 -

because they have been shown to have, or conceded, market power in that market area. 

The Commission stated that OG&E had failed to adequately address how the 

Commission could effectively monitor sales at generator bus locations 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. In this regard, the Commission reiterated that 

commenters in the rulemaking proceeding had noted the complex administrative 

problems that would be associated with trying to monitor compliance with such a 

policy.137 The Commission explained that mitigated sellers thus 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, and that, unlike sales at the 

generation bus bar within a mitigated balancing authority area, 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.138 

 

137 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 320 (citing Order No. 697, 

FERC Stats. & Regs. ¶ 31,252 at P 818). 

138 Id. P 322-23. 
Docket No. RM04-7-005 - 70 -

E. Implementation Process

1. Category 1 and 2 Sellers

Background

83. 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, FERC Stats. & Regs. ¶ 31,036); that are not affiliated with anyone that 

owns, operates or controls transmission facilities in the same region as the seller’s 

generation assets; that are not affiliated with a franchised public utility in the same region 

as the seller’s generation assets; and that do not raise other vertical market power 

issues.”139 Market power concerns for Category 1 sellers will be monitored through the 

change in status reporting requirement140 and through ongoing monitoring by the 

Commission’s Office of Enforcement. Category 2 sellers (all sellers that do not qualify 

 

139 18 CFR 35.36(a)(2). 

140 See 18 CFR 35.42. 
Docket No. RM04-7-005 - 71 -

for Category 1) are required to file regularly scheduled updated market power analyses in 

addition to change in status reports. 

84. 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.141 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.142

 

85. On rehearing in Order No. 697-A, the Commission upheld its determination to 

create a category of market-based rate sellers (Category 1 sellers) that are exempt from 

the requirement to automatically submit updated market power analyses and its decision 

to adopt a regional review. The Commission also clarified, consistent with its December 

14 Clarification Order, that revised Appendix D to Order No. 697-A makes clear that 

transmission owners and their affiliates have earlier filing periods than the other entities 

required to file in each region.143

Requests for Rehearing

 

141 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. 

142 See Order No. 697, FERC Stats. & Regs. ¶ 31,252 at Appendix D. The regions 

include the Northeast, Southeast, Central, Southwest Power Pool, Southwest, and 

Northwest. 

143 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 374 (citing December 14 

Clarification Order, 121 FERC ¶ 61,260 at P 9). 
Docket No. RM04-7-005 - 72 -

86. Wisconsin Electric requests that the Commission clarify that Wisconsin 

Electric’s triennial market power update filing is due when all Category 2 sellers other 

than transmission owners or their affiliates are obligated to make such filings. Wisconsin 

Electric states that it transferred ownership of its transmission facilities to American 

Transmission Company, LLC (American Transmission Company). Thus, it argues that it 

is not a transmission owner and is not affiliated with a transmission owner with marketbased rate authority, and therefore its next triennial filing would be due in June 2009.144

 

Commission Determination

87. We will grant Wisconsin Electric’s request, and clarify that because Wisconsin 

Electric has divested its transmission to American Transmission Company,145 Wisconsin 

Electric falls within the category of all other Category 2 sellers in the Central region. 

Accordingly, Wisconsin Electric must submit its updated market power analysis at the 

Commission at the same time non-transmission owning utilities in the Central region file 

their updated market power analyses.146

2. Market-Based Rate Tariff Clarifications

Background

 

144 Wisconsin Electric Rehearing Request at 7. 

145 Wisconsin Electric Power Co., 90 FERC ¶ 61,346 (2000). 

146 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at Appendix D-2. 
Docket No. RM04-7-005 - 73 -

88. In Appendix C of Order No. 697, the Commission provided certain standard 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. The Commission stated that it 

will post these provisions on its web site and update them as appropriate.147 In Order No. 

697-A, the Commission clarified that 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.148

 

Requests for Rehearing

89. With respect to the standard applicable ancillary service tariff provision(s) set 

forth in Appendix C to Order No. 697-A, EEI states that Appendix C has not yet been 

updated to reflect that the Commission has approved the market power study performed 

by the Midwest ISO Independent Market Monitor. EEI encourages the Commission to 

add Midwest ISO to Appendix C, with an effective date matching the start of the 

market.149

Commission Determination

 

147 Order, No. 697, FERC Stats. & Regs. ¶ 31,252 at P 918. 

148 Id. P 387 (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 916-917;

Appendix C (for a listing of the standard ancillary services provisions); Niagara Mohawk 

Power Corp., 121 FERC ¶ 61,275, at P 14 & n.22 (2007) (directing seller to conform with 

Appendix C)). 

149 EEI Rehearing Request at 18. 
Docket No. RM04-7-005 - 74 -

90. The tariff provision for the Midwest ISO ancillary services market has been 

included in Appendix C and is available on the Commission’s website.150 The effective 

date of the tariff sheet with the required tariff provision for the Midwest ISO ancillary 

services market should match the start date of the Midwest ISO ancillary services market 

accepted by the Commission. 

F. Clarifications of the Commission’s Regulations

91. In Order No. 697-A, the Commission found that based on its further consideration 

of the regulations, several provisions should be changed to provide additional clarity.151

Triggering Events for Change in Status Filings 

Background

92. In Order No. 697, 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.”152

 

 

150 http://www.ferc.gov/industries/electric/gen-info/mbr.tariff.asp 

151 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 527. 

152 Id. P 528. 
Docket No. RM04-7-005 - 75 -

93. Upon further consideration, in Order No. 697-A, the Commission clarified that a 

change in status also includes long-term firm capacity purchases that result in net 

increases of 100 MW or more. The Commission explained that 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.

153 The Commission stated 

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 owned or controlled through 

contract and firm purchases, less operating reserves, native load commitments and longterm firm sales.”154 Thus, the Commission explained that 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, the Commission revised § 35.42(a)(1) 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.” The 

Commission stated that because sellers may not have been on notice that this was the 

Commission’s intent, it will not hold any sellers responsible for failure to report such 

 

153 Id. P 530 (citing April 14 Order, 107 FERC ¶ 61,018 at P 95, 100). 

154 Id. (citing Order No. 697, FERC Stats. & Regs. ¶ 31,252 at P 38) (footnote 

omitted). 
Docket No. RM04-7-005 - 76 -

changes in status prior to the effective date of this order, which will be 30 days after 

issuance in the Federal Register.

155

Requests for Rehearing

94. EPSA requests that the Commission clarify Order No. 697-A’s inclusion of 

long-term capacity purchases as a trigger for changes in status filings. 

95. EPSA argues that although the Commission intended to provide additional 

clarity, the Commission’s new reference to “long-term firm capacity purchases” is more 

confusing than illuminating. It argues that capacity purchases, which are distinct from 

energy purchases, are found primarily in RTOs/ISOs with forward capacity markets, and 

less frequently, in bilateral transactions with load serving entities that require additional 

capacity for planning purchases. EPSA asserts that the April 14 Order, on which the 

Commission relies, appears to be both broader in one respect than the new § 35.42(a)(1) 

requirement, and narrower in another. First, according to EPSA, the relevant portion of 

the April 14 Order appears to address long-term energy and capacity transactions, both of 

which fall into the ambit of firm purchases of generation, while Order No. 697-A appears 

to focus solely on long-term firm capacity purchases. Second, EPSA argues that the 

April 14 Order appears to require the element of control in the calculation of 

uncommitted capacity, while the modification to § 35.42(a)(1) promulgated in Order No. 

 

155 Id. P 531. 
Docket No. RM04-7-005 - 77 -

697-A appears to place all “‘long-term firm purchases of generation capacity’” into the 

calculation, regardless of control.156

96. EPSA argues that to the extent the Commission intended to include all longterm firm energy purchases in cumulating generation increases, or to include all longterm firm capacity and energy purchases regardless of control, this aspect of Order No. 

697-A appears inconsistent with the Commission’s prior orders. Specifically, EPSA 

asserts that in the Order No. 652 rehearing order, the Commission clarified that “‘to the 

extent ... a contract for a fixed quantity delivered energy does not confer control, it need 

not be reported [as a change in status].’”157 EPSA also states that more recently, the 

Commission concluded that the sale of a firm liquidated damages (LD) energy product 

under the EEI Master Power Purchase and Sale Agreement “‘would not reflect a 

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

rate authority and therefore would not necessitate the filing of a change in status report’” 

because the product “‘by itself gives the purchaser only a right to receive energy and thus 

no rights that would allow the purchaser to control generation capacity.’”158

 

156 ESPA Rehearing Request at 28 (citing Order No. 697-A, FERC Stats. & Regs. 

¶ 31,268 at P 530-31). 

157 Id. at 29 (quoting Reporting Requirement for Changes in Status for Public 

Utilities with Market-Based Rate Authority, 111 FERC ¶ 61,413, at P 12 (2005) 

(rehearing of Order No. 652). 

158 Id. (quoting Integrys Energy Group, Inc., 123 FERC ¶ 61,034, at P 11 (2008) 

(continued) 
Docket No. RM04-7-005 - 78 -

97. EPSA therefore requests guidance with respect to the following questions in 

order to facilitate full compliance with the Commission’s change in status reporting 

regulations: (1) Does the change articulated in Order No. 697-A require sellers to include 

only long-term firm capacity purchases in their cumulative generation count for changein-status purposes, or are they to include long-term firm energy purchases as well? (2) If 

sellers are to include only long-term firm capacity purchases in their cumulative 

generation count, did the Commission intend this terminology to encompass transactions 

in addition to the traditional capacity purchases as outlined above? (3) If sellers are to 

include long-term firm energy purchases in their cumulative generation counts for

change-in-status purchases, are they to include all long-term firm energy purchases or 

only those that confer some element of control, as implied by the Commission’s April 14 

Order, its order on rehearing of Order No. 652, and in the recent Integrys decision? and 

(4) If only contracts that confer control are to be included (whether capacity only, or 

energy and capacity), are entities with market-based rates permitted to exclude from their 

calculation those long-term firm energy contracts that contain either liquidated damage 

provisions or other provisions that permit the seller to retain a complete and unrestricted 

right to choose a generating resource or a monetized replacement resource?159

 

(Integrys)). 

159 Id. at 29-30. 
Docket No. RM04-7-005 - 79 -

98. EPSA submits that how the Commission addresses these questions will not 

only impact change in status reporting, but will also have significant bearing on the data 

sellers assemble and analyze in their updated market power analyses to the extent “longterm firm purchases” and “long-term firm sales” (as listed on the Commission’s standard 

screen format for the pivotal supplier analysis) are no longer limited to transactions 

which confer control, or alternatively are limited to capacity purchases and sales only.160

Commission Determination

99. In response to the first question posed by EPSA regarding whether Order No. 

697-A requires sellers to include long-term energy purchases in addition to long-term 

firm capacity purchases in their cumulative generation count for change-in-status 

purposes, we find that to the extent a contract for a fixed quantity of delivered energy 

does not confer control, it need not be reported.161 Consistent with the Commission’s 

determination in Integrys that the sale of a “Firm (LD)” product, as defined in the EEI 

Master Power Purchase & Sale Agreement, by itself gives the purchaser only a right to 

receive energy and thus no rights that would allow the purchaser to control generation 

 

160 Id. at 30. 

161 Integrys, 123 FERC ¶ 61,034 at P 11 (regarding energy only contracts in 

Reporting Requirement for Changes in Status for Public Utilities with Market-Based Rate 

Authority, 111 FERC ¶ 61,413, at P 12 (2005) (rehearing of Order No. 652) the 

Commission concluded that “‘to the extent ... a contract for a fixed quantity of delivered 

energy does not confer control, it need not be reported.’”). 
Docket No. RM04-7-005 - 80 -

capacity, we reiterate that the sale of the Firm (LD) product would not reflect a departure 

from the characteristics the Commission relied upon in granting market-based rate 

authority and therefore would not necessitate the filing of a change in status report.162

 

We note that in reaching this determination, the Commission relied on the representations 

of Integrys Energy Group, Inc. that the purchaser under a Firm (LD) product has no 

ability to withhold energy from the market or otherwise use the product as part of a 

capacity withholding strategy.163 For example, the Commission relied on the fact that the 

purchaser cannot force the seller to back down the output of any generator, and the fact 

that if the purchaser refuses to receive delivery, that refusal does not keep the power from 

entering the market because the seller has the right to resell the Firm (LD) product, as 

well as to receive damages from the purchaser. However, to the extent a long-term 

energy purchase would allow the purchaser to control generation capacity, it needs to be 

reported. A determination of whether a long-term firm energy purchase confers control 

over generation capacity to the purchaser must be based on a review of the totality of the 

circumstances on a fact-specific basis. Therefore, sellers who are uncertain as to whether 

they must include long-term energy purchases in their cumulative generation count 

because the facts and circumstances surrounding their long-term energy purchase(s) 

 

162 Id. 

163 Id. P 7. 
Docket No. RM04-7-005 - 81 -

differ from the facts relied on by the Commission in the Integrys order will need to obtain 

guidance from the Commission by making a filing at the Commission. Sellers will need 

to provide information on the facts, terms and circumstances concerning the long-term 

energy purchase(s) in their filing. The Commission will evaluate each such filing on a 

case-by-case basis and will make a determination based on those specific facts and 

circumstances. 

100. With regard to EPSA’s second question concerning whether sellers are to 

include only long-term firm capacity purchases in their cumulative generation count, and 

whether the Commission intended this terminology to encompass transactions in addition 

to traditional capacity purchases, we clarify that as the Commission explained in Integrys, 

where a purchase “does not result in a transfer of control of generation capacity to the 

purchaser” it does not have to be reported by the purchaser in a change in status report 

under the Commission’s regulations.164 However, we note that the Commission’s finding 

in Integrys was limited to the facts described by the Integrys group, and was dependent 

on the specific terms and conditions for a Firm (LD) product, as defined by the EEI 

Master Power Purchase and Sale Agreement. Thus, as the Commission explained in 

Integrys, different or additional facts, terms, or conditions could change the 

 

164 See id. 
Docket No. RM04-7-005 - 82 -

Commission’s analysis of whether other types of transactions transfer control of 

generation capacity to the purchaser.165

 

101. With regard to EPSA’s third question (if sellers are to include long-term firm 

energy purchases in their cumulative generation counts for change in status purchases, 

are they to include all long-term firm energy purchases or only those that confer some 

element of control), we clarify that, as stated above, only long-term firm energy 

purchases that confer some element of control must be included in a seller’s cumulative 

generation counts for change in status reports.166 A long-term firm energy purchase by 

itself gives the purchaser only a right to receive energy and thus no rights that would 

allow the purchaser to control generation capacity.167 As explained above, a 

determination of whether a long-term firm energy purchase confers control over 

generation capacity must be based on a review of the totality of the circumstances on a 

fact-specific basis. 

102. EPSA’s fourth question (if only contracts that confer control are to be included 

in their cumulative generation count (whether capacity only, or energy and capacity), are 

entities with market-based rates permitted to exclude from their calculation those long-

 

165 Id. 

166 Id. (citing Reporting Requirement for Changes in Status for Public Utilities 

with Market-Based Rate Authority, 111 FERC ¶ 61,413 at P 12). 

167 Id. 
Docket No. RM04-7-005 - 83 -

term firm energy contracts that contain either liquidated damage provisions or other 

provisions that permit the seller to retain a complete and unrestricted right to choose a 

generating resource or a monetized replacement resource) requires a fact-specific 

determination. As the Commission explained in Integrys, different or additional facts, 

terms, or conditions could change the Commission’s analysis. Thus, whether long-term 

firm energy contracts that contain either liquidated damage provisions or other provisions 

that permit the seller to retain a complete and unrestricted right to choose a generating 

resource result in a transfer control of generation capacity to the purchaser is an issue to 

be determined on a case-by-case basis.168 We will not make a generic finding on whether 

contracts with such provisions are exempt from being included in a market-based rate 

seller’s cumulative MW total for change in status reports.169

III. Information Collection Statement

103. The Office of Management and Budget (OMB) regulations require that OMB 

approve certain information collection requirements imposed by an agency.170 The Final 

 

168 Id. Although EPSA also asked this question in connection with contractual 

provisions that permit the seller to retain a complete and unrestricted right to choose a 

“monetized replacement resource,” EPSA does not define the term “monetized 

replacement resource” in its rehearing request. As a result, we do not include that term in 

our response above.

169 Reporting Requirement for Changes in Status for Public Utilities with MarketBased Rate Authority, 111 FERC ¶ 61,413, at P 12 (2005). 

170 5 CFR 1320.11. 
Docket No. RM04-7-005 - 84 -

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

104. 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. 

105. 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. 

106. 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 
Docket No. RM04-7-005 - 85 -

(202) 502-8371, TTY (202)502-8659. E-mail the Public Reference Room at 

public.referenceroom@ferc.gov. 

V. Effective Date

107. Changes to Order No. 697-A adopted in this order on rehearing will become 

effective [insert date 30 days from publication in FEDERAL REGISTER]. 

List of subjects in 18 CFR Part 35

Electric power rates, Electric utilities, Reporting and recordkeeping requirements. 

By the Commission. 

( S E A L ) 

Nathaniel J. Davis, Sr., 

Deputy Secretary. 

 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-
Docket No. RM04-7-005 - 86 -

7352. 

2. In § 35.36, paragraph (a)(9) is revised to read as follows: 

§ 35.36 Generally. 

 (a) * * * 

 (9) Affiliate of a specified company means: 

(i) 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; 

(ii) 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; 

 (iii) 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 

 (iv) Any person that is under common control with the specified company. 
Docket No. RM04-7-005 - 87 -

 (v) For purposes of paragraph (a)(9), 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. 

 * * * * * 

3. In § 35.37, paragraph (e)(3) is revised to read as follows: 

 § 35.37 Market power analysis required. 

(e) * * * 

(3) Physical coal supply sources and ownership or control over who may access 

transportation of coal supplies. 

 * * * * *
Docket No. RM04-7-005 - 88 -

Note: The following appendix 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. RM04-7-005 - 89 -

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) if the Seller 

wants to sell at the metered boundary of a mitigated balancing authority area at marketbased rates, then neither it nor its affiliates can sell into that mitigated balancing authority 

area from the outside.. 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 
Docket No. RM04-7-005 - 90 -

requirements of the PJM Office of Interconnection. 

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. 

Midwest ISO: Seller offers regulation service and operating reserve service (which 

include a 10-minute spinning reserve and 10-minute supplemental reserve) for sale to the 

Midwest Independent Transmission System Operator, Inc. (Midwest ISO) and to others 

that are self-supplying ancillary services to Midwest ISO. 

 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 
Docket No. RM04-7-005 - 91 -

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.