Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and Ancillary Services by Public Utilities, 79610-79628 [E8-30757]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 73, Number 250 (Tuesday, December 30, 2008)]
[Rules and Regulations]
[Pages 79610-79628]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: E8-30757]



[[Page 79610]]

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DEPARTMENT OF ENERGY

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: Final rule; order on rehearing and clarification.

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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.

DATES: Effective Date: The amendments to 18 CFR part 35 and the order 
on rehearing will become effective January 29, 2009.

FOR FURTHER INFORMATION CONTACT:
Michelle Barnaby (Technical Information), Office of Energy Market 
Regulation, Federal Energy Regulatory Commission, 888 First Street, 
NE., Washington, DC 20426, (202) 502-8407.
Paige Bullard (Legal Information), Office of the General Counsel, 
Federal Energy Regulatory Commission, 888 First Street, NE., 
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                     26
         Commitment of Capacity............................
    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.....
 

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

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-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.
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    \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).
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    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 directed in Order No. 697 from December 2007 to 30 days after the 
date of issuance of the December 14 Clarification Order.
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    \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).

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[[Page 79611]]

    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.
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    \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).
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    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 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\
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    \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).
    \5\ Id. P 5.
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    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 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 
Sec.  35.36(a)(4) of the Commission's regulations.
    9. The Commission revises the definition of ``affiliate'' in Sec.  
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.

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 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\
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    \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).
    \10\ Id. P 355.
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    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 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

[[Page 79612]]

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\
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    \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).
    \13\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 144.
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    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\
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    \14\ Id. P 145.
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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 
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\
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    \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.
    \17\ Id. at 8 (quoting Order No. 697-A, FERC Stats. & Regs. ] 
31,268 at P 144).
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    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 
Order \18\ 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 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\
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    \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).
    \19\ Id. at 10 (citing Order No. 697-A, FERC Stats. & Regs. ] 
31,268 at P 143).
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    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 non-discriminatory basis, after that 
deadline is passed.\21\ Thus, E.ON concludes that insofar as 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\
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    \20\ Id.
    \21\ Id. (citing Promoting Wholesale Competition Through Open 
Access Non-Discriminatory 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 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.
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    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

[[Page 79613]]

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.\23\
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    \23\ Id.
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    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\
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    \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).
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    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 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 fact-specific 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 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\
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    \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).
    \28\ Id. at 14.
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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 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\
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    \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.
    \30\ EEI Rehearing Request at 15 (quoting Order No. 697-A, FERC 
Stats. & Regs. ] 31,268 at P 144).
    \31\ Id.
    \32\ Id.
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    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 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

[[Page 79614]]

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\
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    \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)).
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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 capacity \36\ 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 
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.
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    \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.
    \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.
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    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 generation facilities (and the retirement of facilities), major 
outages, and demand response.\39\
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    \38\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 146; 
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 355.
    \39\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 355.
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    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 ``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.'' \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 less than 365 consecutive 
days in duration, as defined in the Commission's EQR [Electric 
Quarterly Report] Data Dictionary.'' \41\
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    \40\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 144.
    \41\ Id.
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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\
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    \42\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 174.
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    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 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\
---------------------------------------------------------------------------

    \43\ Id. P 175.
    \44\ Id. P 176.
---------------------------------------------------------------------------

    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).

[[Page 79615]]

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 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\
---------------------------------------------------------------------------

    \45\ Id. P 187.
---------------------------------------------------------------------------

    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 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\
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    \46\ Energy Policy Act of 2005, Public Law No. 109-58, 119 Stat. 
594 (2005).
    \47\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 150.
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Requests for Rehearing
    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\
---------------------------------------------------------------------------

    \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).
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    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 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 power-related filing to control as few generation assets as 
possible.\52\
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    \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)).
---------------------------------------------------------------------------

    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 
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\
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    \53\ Id. at 4.
---------------------------------------------------------------------------

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 agreement \55\ 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

[[Page 79616]]

despite such agreement, the Commission will request additional 
information which may include, but not be limited to, any applicable 
contract so that we can make a determination as to which seller or 
sellers have control.\56\
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    \54\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 187.
    \55\ Id. P 183.
    \56\ Id. P 187.
---------------------------------------------------------------------------

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\
---------------------------------------------------------------------------

    \57\ Order No. 697 FERC Stats. & Regs. ] 31,252 at P 440.
    \58\ Id. P 440.
---------------------------------------------------------------------------

    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 trains.\59\ Thus, the Commission revised 
its definition of ``inputs to electric power production'' in Sec.  
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\
---------------------------------------------------------------------------

    \59\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 176 
(emphasis in original).
    \60\ Id.
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \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).
    \63\ Id.
---------------------------------------------------------------------------

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 development'' means only sites with respect 
to which permits for new generation have been obtained or where 
construction of new generation is underway.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 Sec.  35.36(a)(4),\ 65\ we will revise Sec.  35.37(e)(3) to read as 
follows: ``Physical coal supply sources and ownership or control over 
who may access transportation of coal supplies.''
---------------------------------------------------------------------------

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

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 Sec.  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 of its goal to have a more consistent definition 
of affiliate for purposes of both EWGs and non-EWGs to the extent

[[Page 79617]]

possible, as well as to strengthen the Commission's ability to ensure 
that customers are protected.
---------------------------------------------------------------------------

    \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, 2008), FERC Stats. 
& Regs. ] 31,272 (2008) (Affiliate Transactions Final Rule 
Rehearing).
---------------------------------------------------------------------------

    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 non-EWGs. 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 
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 1935 \70\ and the Public 
Utility Holding Company Act of 2005 (PUHCA 2005).\71\
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    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 non-EWGs, but with 
adjustments to reflect the ten percent voting interest threshold for 
non-EWGs 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 Sec.  
35.36.
---------------------------------------------------------------------------

    \72\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 182.
---------------------------------------------------------------------------

Requests for Rehearing and Order Requesting Supplemental Comments.\73\
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 Sec.  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 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,