Document ID: FERC-2008-1862-0001
Agency: ferc
Document Type: Rule
Title: Market-Based Rates For Wholesale Sales of Electric Energy, Capacity And Ancillary Services By Public Utilities
Posted Date: 2008-12-30T05:00Z

[Federal Register: December 30, 2008 (Volume 73, Number 250)]
[Rules and Regulations]               
[Page 79610-79628]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr30de08-6]                         

[[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\
---------------------------------------------------------------------------

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

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

    \40\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 144.
    \41\ Id.
---------------------------------------------------------------------------

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

    \42\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 174.
---------------------------------------------------------------------------

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

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

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).
---------------------------------------------------------------------------

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

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

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

    \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, 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\
---------------------------------------------------------------------------

    \76\ Order Requesting Supplemental Comments, 124 FERC ] 61,213.
    \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.
---------------------------------------------------------------------------

    45. Therefore, in the Order Requesting Supplemental Comments, the 
Commission stated that it intends to revise the definition of affiliate 
in Sec.  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, however, it would seek supplemental comments on the

[[Page 79618]]

proposed revised definition of affiliate in Sec.  35.36(a)(9).
---------------------------------------------------------------------------

    \79\ Id. P 12.
---------------------------------------------------------------------------

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

    \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).
    \83\ Id. at 3.
    \84\ Id. at 3-4.
---------------------------------------------------------------------------

    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 consistency to using the same ten 
percent threshold for both EWGs and non-EWGs in the market-based rate 
regulations.\86\
---------------------------------------------------------------------------

    \85\ EEI October 20, 2008 Supplemental Comments at 2.
    \86\ Id. at 3.
---------------------------------------------------------------------------

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 Sec.  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 Sec.  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 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 Sec.  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.
---------------------------------------------------------------------------

    \87\ See supra P 43-44.
---------------------------------------------------------------------------

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, unless otherwise authorized by the 
Commission. The Commission explained that this requirement protects a 
utility's captive customers against inappropriate cross-subsidization 
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\
---------------------------------------------------------------------------

    \88\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 597.
---------------------------------------------------------------------------

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

    \89\ FP&L March 24, 2008, Request for Clarification.
---------------------------------------------------------------------------

    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 market-regulated power sales affiliate 
provides its affiliated franchised public utility with non-power 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 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

[[Page 79619]]

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

    \90\ Id. at 4.
    \91\ Id. at 13 (citing Affiliate Transactions Final Rule, FERC 
Stats. & Regs. ] 31,264 at P 85).
---------------------------------------------------------------------------

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

    \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 
(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 
(DC Cir. 2007) (holding that the Commission need not revisit all 
elements of a tariff upon finding one aspect to be unjust and 
unreasonable).
---------------------------------------------------------------------------

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

    \93\ Affiliate Transactions Final Rule Rehearing, FERC Stats. & 
Regs. ] 31,272 at P 23.
    \94\ Id. P 24-31.
    \95\ Id. P 31.
---------------------------------------------------------------------------

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

    \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).
    \98\ Id. at n.5. See also Affiliate Transactions Final Rule 
Rehearing, FERC Stats. & Regs. ] 31,272 at P 78.
---------------------------------------------------------------------------

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

    \99\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 561 
(codified at 18 CFR 35.39(g)).
---------------------------------------------------------------------------

    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, 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\
---------------------------------------------------------------------------

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

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 
conform regulations under Orders No.

[[Page 79620]]

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

    \101\ Id. (quoting Order No. 697, FERC Stats. & Regs. ] 31,252 
at P 550).
---------------------------------------------------------------------------

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

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

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

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

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

    \106\ Id. P 334.
    \107\ Id. at n.464.
---------------------------------------------------------------------------

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

    \108\ Id. P 335.
    \109\ Id. P 336.
---------------------------------------------------------------------------

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 balancing authority area 
where the seller is

[[Page 79621]]

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

    \110\ E.ON Rehearing Request at 11 (quoting Order No. 697-A, 
FERC Stats. & Regs. ] 31,268 at P 339).
---------------------------------------------------------------------------

    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 
market-based 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 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\
---------------------------------------------------------------------------

    \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)).
    \113\ Id.
---------------------------------------------------------------------------

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

    \114\ Id. at 14.
---------------------------------------------------------------------------

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

    \115\ Id. at 13.
    \116\ Id. at 13-14 (quoting 18 CFR 35.36 et seq.).
---------------------------------------------------------------------------

    68. Pinnacle argues that the Commission should clarify that resales 
of mitigated border purchases are not permanently banned from 
reentering the mitigated area. 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\
---------------------------------------------------------------------------

    \117\ Id. at 4 (quoting Order No. 697-A, FERC Stats. & Regs. ] 
31,268 at P 335).
    \118\ Id.
---------------------------------------------------------------------------

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

    \119\ Id. (quoting Order No. 697-A, FERC Stats. & Regs. ] 31,268 
at P 336).
    \120\ Id. at 5.
---------------------------------------------------------------------------

    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 will likely not agree to limitations on where the power 
can sink on term deals, particularly as neither Order No. 697

[[Page 79622]]

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

    \121\ Id. at 6.
---------------------------------------------------------------------------

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

    \122\ Id.
---------------------------------------------------------------------------

    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 `` `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\
---------------------------------------------------------------------------

    \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)).
    \124\ Id.
---------------------------------------------------------------------------

    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 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 off-system 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-to-point 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\
---------------------------------------------------------------------------

    \125\ Id. at 5 (citing In re SCANA Corp., 118 FERC ] 61,028 
(2007)).
    \126\ Id.
---------------------------------------------------------------------------

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

    \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.

---------------------------------------------------------------------------

[[Page 79623]]

Commission Determination
    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 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 that same power back into the mitigated 
balancing authority area, whether at cost-based or market-based 
rates.'' \132\
---------------------------------------------------------------------------

    \129\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 336.
    \130\ Id. P 335.
    \131\ Id.
    \132\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at n.464.
---------------------------------------------------------------------------

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

    \133\ Arizona Public Service Co., Docket No. EL08-1104-000, at 1 
(July 3, 2008) (unpublished letter order).
---------------------------------------------------------------------------

    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).
---------------------------------------------------------------------------

    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

[[Page 79624]]

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

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

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 requirement \140\ and through 
ongoing monitoring by the Commission's Office of Enforcement. Category 
2 sellers (all sellers that do not qualify for Category 1) are required 
to file regularly scheduled updated market power analyses in addition 
to change in status reports.
---------------------------------------------------------------------------

    \139\ 18 CFR 35.36(a)(2).
    \140\ See 18 CFR 35.42.
---------------------------------------------------------------------------

    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 pre-
determined schedule, rotating by geographic region where two regions 
are reviewed each year, with the cycle repeating every three 
years.\142\
---------------------------------------------------------------------------

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

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

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

Requests for Rehearing
    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 market-based rate authority, 
and therefore its next triennial filing would be due in June 2009.\144\
---------------------------------------------------------------------------

    \144\ Wisconsin Electric Rehearing Request at 7.
---------------------------------------------------------------------------

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

[[Page 79625]]

in the Central region file their updated market power analyses.\146\
---------------------------------------------------------------------------

    \145\ Wisconsin Electric Power Co., 90 FERC ] 61,346 (2000).
    \146\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at Appendix 
D-2.
---------------------------------------------------------------------------

2. Market-Based Rate Tariff Clarifications
Background
    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\
---------------------------------------------------------------------------

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

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

    \149\ EEI Rehearing Request at 18.
---------------------------------------------------------------------------

Commission Determination
    90. The tariff provision for the Midwest ISO ancillary services 
market has been included in Appendix C and is available on the 
Commission's Web site.\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.
---------------------------------------------------------------------------

    \150\ http://www.ferc.gov/industries/electric/gen-info/
mbr.tariff.asp.
---------------------------------------------------------------------------

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

    \151\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 527.
---------------------------------------------------------------------------

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, 
Sec.  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\
---------------------------------------------------------------------------

    \152\ Id. P 528.
---------------------------------------------------------------------------

    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 long-term 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 Sec.  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 changes in status prior to the effective date of 
this order, which will be 30 days after issuance in the Federal 
Register.\155\
---------------------------------------------------------------------------

    \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).
    \155\ Id. P 531.
---------------------------------------------------------------------------

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 Sec.  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 Sec.  35.42(a)(1) 
promulgated in Order No. 697-A appears to place all `` `long-term firm 
purchases of generation capacity' '' into the calculation, regardless 
of control.\156\
---------------------------------------------------------------------------

    \156\ ESPA Rehearing Request at 28 (citing Order No. 697-A, FERC 
Stats. & Regs. ] 31,268 at P 530-31).
---------------------------------------------------------------------------

    96. EPSA argues that to the extent the Commission intended to 
include all long-term firm energy purchases in cumulating generation 
increases, or to include all long-term 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

[[Page 79626]]

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

    \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) (Integrys)).
---------------------------------------------------------------------------

    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 change-in-
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\
---------------------------------------------------------------------------

    \159\ Id. at 29-30.
---------------------------------------------------------------------------

    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 ``long-term 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\
---------------------------------------------------------------------------

    \160\ Id. at 30.
---------------------------------------------------------------------------

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 
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) 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.
---------------------------------------------------------------------------

    \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.' '').
    \162\ Id.
    \163\ Id. P 7.
---------------------------------------------------------------------------

    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 Commission's 
analysis of whether other types of transactions transfer control of 
generation capacity to the purchaser.\165\
---------------------------------------------------------------------------

    \164\ See id.
    \165\ Id.
---------------------------------------------------------------------------

    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

[[Page 79627]]

over generation capacity must be based on a review of the totality of 
the circumstances on a fact-specific basis.
---------------------------------------------------------------------------

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

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

    \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 Market-Based Rate Authority, 111 FERC ] 61,413, at P 
12 (2005).
---------------------------------------------------------------------------

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 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.
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    \170\ 5 CFR 1320.11.
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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 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 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 Web 
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at 
ferconlinesupport@ferc.gov, or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
public.referenceroom@ferc.gov.

V. Effective Date

    107. Changes to Order No. 697-A adopted in this order on rehearing 
will become effective January 29, 2009.

List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and 
recordkeeping requirements.

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

0
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

0
1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7352.

0
2. In Sec.  35.36, paragraph (a)(9) is revised to read as follows:

Sec.  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.
    (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.
* * * * *

0
3. In Sec.  35.37, paragraph (e)(3) is revised to read as follows:

Sec.  35.37  Market power analysis required.

    (e) * * *
    (3) Physical coal supply sources and ownership or control over who 
may access transportation of coal supplies.
* * * * *

    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 market-based rate 
authority, including orders in which the Commission authorizes 
seller to engage in affiliate sales under this tariff or otherwise 
restricts or limits the seller's market-based rate authority. 
Failure to comply with the applicable provisions of 18 CFR Part 35, 
Subpart H, and with any orders of the Commission concerning seller's 
market-based rate authority, will constitute a violation of this 
tariff.

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).

[[Page 79628]]

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 market-based 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 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 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.

[FR Doc. E8-30757 Filed 12-29-08; 8:45 am]

BILLING CODE 6717-01-P