[Federal Register: December 30, 2008 (Volume 73, Number 250)]
[Rules and Regulations]
[Page 79610-79628]
[DOCID:fr30de08-6]

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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,<PHONE_NUMBER>.
Paige Bullard (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.

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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    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

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

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

consecutive hours and less than or equal to one month, and the term
``Seasonal'' as greater than one month and less than 365 consecutive
days. EEI notes that for both of these definitions, ``month'' is left
undefined, and thus presumably at its accepted meaning of calendar
month.\34\
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    \33\ Southern Companies at 15 (citing General Chemical Corp. v.
U.S., 817 F.2d 844, 857 (D.C. Cir. 1987)).
    \34\ EEI Rehearing Request at 16; Southern Companies Rehearing
Request at 15 (citing Order Adopting EQR Data Dictionary, Order No.
2001-G, 120 FERC ] 61,270, at P 35 (2007)).
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Commission Determination
    22. In response to Southern Companies' and E.ON's comments
regarding allocation of simultaneous transmission import limit capacity
when conducting the indicative screens, we clarify that the
Commission's statement in paragraph 144 of Order No. 697-A is not
intended to revise its approach to the simultaneous transmission import
limit allocation, as suggested in the rehearing requests of Southern
Companies and E.ON. We therefore clarify and reaffirm that we will
require applicants to allocate their seasonal and longer transmission
reservations to themselves from the calculated simultaneous
transmission import limit only up to the uncommitted first-tier
generation capacity owned, operated or controlled by the seller (and
its affiliates).
    23. Further, as the Commission clarified in the July 17
Clarification Order,\35\ to determine the respective shares of
uncommitted generation capacity to be used in performing the market
power analysis, a seller should determine the amount of firm
transmission capacity \36\ the seller has into the study area and
assume that any seller's uncommitted first-tier generation capacity
fully utilizes the seller's firm transmission rights. Then, to the
extent the seller has remaining uncommitted first-tier generation
capacity,\37\ the remaining simultaneous transmission import limit
capability is allocated on a pro rata basis to import the remaining
uncommitted first-tier generation capacity of both the seller and
competing suppliers.
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    \35\ 124 FERC ] 61,055 at P 31-32.
    \36\ See, e.g., Order No. 697, FERC Stats. & Regs. ] 31,252 at P
368. ``Firm transmission capacity'' includes network and firm point-
to-point.
    \37\ In performing the indicative screens, to the extent the
seller does not have any uncommitted generation capacity in the
first-tier markets or its uncommitted generation capacity in the
first-tier markets is fully accounted for through recognition of the
seller's firm transmission rights, no simultaneous import limit
capability allocation is needed between the seller and competing
suppliers.
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    24. With regard to E.ON's request that the Commission clarify that
any applicant may seek to demonstrate in its filing that the allocation
of simultaneous transmission import limit capacity to it overstates the
amount of power that it actually imports (or understates the competing
importable generation) and that an alternative approach to allocating
simultaneous transmission import limit capacity is more accurate, we
reiterate that, as we stated in the Final Rule and in Order No. 697-A,
applicants may submit additional sensitivity studies, including a more
thorough import study as part of the delivered price test. However, we
reaffirm that any such sensitivity studies must be filed in addition
to, and not in lieu of, a simultaneous transmission import limit
capacity study.\38\ As we explained in the Final Rule, sensitivity
studies are intended to provide the seller with the ability to modify
inputs to the simultaneous transmission import limit study such as
generation dispatch, demand scaling, the addition of new transmission
and generation facilities (and the retirement of facilities), major
outages, and demand response.\39\
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    \38\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at P 146;
Order No. 697, FERC Stats. & Regs. ] 31,252 at P 355.
    \39\ Order No. 697, FERC Stats. & Regs. ] 31,252 at P 355.
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    25. With regard to the request of EEI, Southern Companies and E.ON
that we clarify that the term ``month'' in paragraph 144 of Order No.
697-A means ``calendar month,'' we clarify that the term ``month'' may
be defined as a calendar month, consisting of 28 to 31 days, and is not
limited to a 28-day period. We did not intend to undo the clarification
that short-term reservations are up to one month, and long-term
reservations are greater than one month by stating in Order No. 697-A
at paragraph 144 that ``twenty-eight days fits within the definition of
a month, and is a reasonable limit to separate short-term reservations
from long-term reservations for purposes of the generation market power
screens.'' \40\ With regard to Southern Companies' argument that the
presence of the ``twenty-eight days'' statement offers the potential
for confusion, we reaffirm our finding that applicants are not required
to address short-term firm reservations in the market power screens,
and we reiterate that ``we will require applicants to allocate their
seasonal and longer transmission reservations to themselves from the
calculated SIL [simultaneous transmission import limit], where seasonal
reservations are greater than one month and less than 365 consecutive
days in duration, as defined in the Commission's EQR [Electric
Quarterly Report] Data Dictionary.'' \41\
---------------------------------------------------------------------------

    \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).

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

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

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

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

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.

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

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

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.

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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\
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    \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.
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    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.
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    \133\ Arizona Public Service Co., Docket No. EL08-1104-000, at 1
(July 3, 2008) (unpublished letter order).
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    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\
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    \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).
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    81. With regard to Wisconsin Electric's request for clarification
that the same geographic boundaries will continue to apply with respect
to Wisconsin Electric's market-based rate authority after the Midwest
ISO ancillary services market becomes operational, so that following
commencement of operations under the Midwest ISO ancillary services
market Wisconsin Electric will still be permitted to make bilateral
market-based sales at or beyond the metered boundary between WUMS and
neighboring regions and to make market-based sales within the Midwest
ISO energy market, we find that this request for clarification is moot.
As explained above, the Commission accepted Wisconsin Electric's filing
removing the tariff restriction prohibiting it from making market-based
rate sales in WUMS.\136\ Thus, Wisconsin Electric is no longer subject
to a limitation that bilateral sales at market-based rates must be made
at the metered boundary between WUMS and neighboring regions.
Similarly, Wisconsin Electric's request for clarification that, for
bilateral energy and capacity transactions that are not covered by the
Midwest ISO tariff, Wisconsin Electric, as a mitigated seller subject
to an ``at or beyond the metered

boundary'' limitation, or the purchaser may use network transmission
service to effectuate the sale at or beyond the metered boundary if
allowable is also moot in light of the removal of the WUMS restriction
in Wisconsin Electric's tariff.
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    \136\ Id.
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    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\
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    \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.
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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.
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    \139\ 18 CFR 35.36(a)(2).
    \140\ See 18 CFR 35.42.
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    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\
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    \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.
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    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\
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    \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).
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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\
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    \144\ Wisconsin Electric Rehearing Request at 7.
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Commission Determination
    87. We will grant Wisconsin Electric's request, and clarify that
because Wisconsin Electric has divested its transmission to American
Transmission Company,\145\ Wisconsin Electric falls within the category
of all other Category 2 sellers in the Central region. Accordingly,
Wisconsin Electric must submit its updated market power analysis at the
Commission at the same time non-transmission owning utilities

in the Central region file their updated market power analyses.\146\
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    \145\ Wisconsin Electric Power Co., 90 FERC ] 61,346 (2000).
    \146\ Order No. 697-A, FERC Stats. & Regs. ] 31,268 at Appendix
D-2.
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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\
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    \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)).
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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\
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    \149\ EEI Rehearing Request at 18.