Order 697-B in RM04�7�005 (issued 12/19/2008, as pub. in Fed. Reg. on 12/30/2008)

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ACTION: Final rule; order on rehearing
and clarification.

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.

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

AGENCY: Federal Energy Regulatory
Commission.

rehearing will become effective January
29, 2009.
FOR FURTHER INFORMATION CONTACT:
Michelle Barnaby (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–
8407.
Paige Bullard (Legal Information), Office
of the General Counsel, Federal
Energy Regulatory Commission, 888
First Street, NE., Washington, DC
20426, (202) 502–6462.
SUPPLEMENTARY INFORMATION:

TABLE OF CONTENTS
Paragraph
numbers
I. Introduction .........................................................................................................................................................................................
II. Discussion ..........................................................................................................................................................................................
A. Horizontal Market Power ...........................................................................................................................................................
1. Transmission Imports ..........................................................................................................................................................
2. Further Guidance Regarding Control and Commitment of Capacity ................................................................................
B. Vertical Market Power ................................................................................................................................................................
Other Barriers to Entry ............................................................................................................................................................
C. Affiliate Abuse ............................................................................................................................................................................
1. General Affiliate Terms & Conditions ................................................................................................................................
2. Power Sales Restrictions .....................................................................................................................................................
3. Market-Based Rate Affiliate Restrictions ............................................................................................................................
D. Mitigation ....................................................................................................................................................................................
Protecting Mitigated Markets ...................................................................................................................................................
E. Implementation Process .............................................................................................................................................................
1. Category 1 and 2 Sellers ......................................................................................................................................................
2. Market-Based Rate Tariff Clarifications ..............................................................................................................................
F. Clarifications of the Commission’s Regulations ........................................................................................................................
Triggering Events for Change in Status Filings ......................................................................................................................
III. Information Collection Statement ....................................................................................................................................................
IV. Document Availability .....................................................................................................................................................................
V. Effective Date .....................................................................................................................................................................................
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

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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
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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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.
2. The Commission issued an order
clarifying four aspects of Order No. 697
on December 14, 2007.2 Specifically,
2 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, 72 FR 72239 (Dec. 20, 2007), 121

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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 marketbased 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.

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.
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
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
3 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, Order No. 697–A, 73 FR 25832
(May 7, 2008), FERC Stats. & Regs. ¶ 31,268 (2008)
(Order No. 697–A).
4 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, 124 FERC ¶ 61,055 (2008) (July 17
Clarification Order).
5 Id. P 5.

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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
§ 35.36(a)(4) of the Commission’s
regulations.
9. The Commission revises the
definition of ‘‘affiliate’’ in § 35.36(a)(9)
of its regulations to delete the separate
definition for exempt wholesale
generators (EWGs), explaining that use
of the same definition for EWGs as for
non-EWG utilities is appropriate and
that the definition adopted in Order No.
697–A for non-EWG utilities will not
affect the substance of the Commission’s
analysis for market power issues.
10. The Commission provides a
number of other clarifications with
regard to, among others, pricing of sales
of non-power goods and services and
the tariff provision governing sales at
the metered boundary.
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 directly6 Order No. 697, FERC Stats. & Regs. & 31,252 at
P 354.

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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
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
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.
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).

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ignore the impact of transmission
reservations on the potential for market
power. It concluded that requiring
applicants to account for reservations
greater than one month in duration
strikes a balance between allowing the
screens to reasonably model historical
conditions without requiring
unreasonable amounts of information
from applicants. Therefore, the
Commission stated that it will require
applicants to allocate their seasonal and
longer transmission reservations to
themselves from the calculated
simultaneous transmission import limit,
where seasonal reservations are greater
than one month and less than 365
consecutive days in duration, as defined
in the Commission’s Electric Quarterly
Report Data Dictionary.13
13. In addition, the Commission
stated that it would allow sellers to use
load shift methodology to calculate the
simultaneous import limit while scaling
their load beyond the historical peak
load, provided they submit adequate
support and justification for the scaling
factor used in their load shift
methodology and how the resulting
simultaneous transmission import limit
number compares had the company
used a generation shift methodology.14
Requests for Rehearing

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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
13 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 144.
14 Id. P 145.
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.

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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-topoint transmission rights into the
subject balancing authority area,
regardless of whether the seller has
uncommitted capacity at the point of
receipt of a transmission reservation
that could actually be imported using
the transmission reservation.17
15. E.ON argues that considering only
transmission reservations and ignoring
remote uncommitted capacity results in
a situation where the indicative screens
effectively assume that a seller has
uncommitted capacity to import even
when it has none. It argues that this
assumption results in competing,
importable capacity being ‘‘squeezed
out’’ and thus being assumed unable to
compete in the market at issue. Further,
E.ON states that the approach indicated
by paragraph 144 is a material change
from the approach to simultaneous
transmission import limit capacity
allocation directed in the April 14 Order
and the July 8 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
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
17 Id. at 8 (quoting Order No. 697–A, FERC Stats.
& Regs. ¶ 31,268 at P 144).
18 Id. at 9 (citing April 14 Order, 107 FERC
¶ 61,018 at P 95, order on reh’g, July 8 Order,
108 FERC ¶ 61,026 at P 45).
19 Id. at 10 (citing Order No. 697–A, FERC Stats.
& Regs. ¶ 31,268 at P 143).

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states that these firm transmission
import rights are used to support native
load and ensure that native load is
supplied reliably and in a cost-effective
manner, often by using the
uncommitted generation of others. E.ON
therefore argues that use of these
transmission rights facilitates the
importation of competing uncommitted
generation.20 Further, E.ON argues that
under current Commission policy and
the pro forma Open Access
Transmission Tariff (OATT), the
transmission capability under firm
transmission reservations not scheduled
by a specific day-ahead deadline is
released to the market at large, on a nondiscriminatory basis, after that deadline
is passed.21 Thus, E.ON concludes that
insofar as the Commission’s indicative
screens measure spot, as opposed to,
forward generation market power, it
would be unreasonable for the
Commission to assume that firm
transmission reservations in excess of
the applicant’s remote uncommitted
capacity are not available to competing
generation.22
17. E.ON therefore requests that the
Commission clarify, or find on
rehearing, that in conducting the
indicative screens, simultaneous
transmission import limit capacity will
be allocated first to an applicant only up
to the lesser of the applicant’s: (1)
Remote generation in the balancing
authority area that contains the point of
receipt of the transmission right at issue;
or (2) firm transmission rights of 28 days
or longer in duration. E.ON argues that
if the Commission does not issue such
clarification or finding, it should clarify
that simultaneous transmission import
limit capacity will be allocated first to
an applicant only up to the amount of
firm transmission rights one year or
greater in duration. Further, E.ON
asserts that regardless of the
Commission’s action on the requested
clarifications, the Commission should
clarify that any applicant may seek to
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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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
18. Similarly, Southern Companies
state that paragraph 144 contains
language that might be construed as
intent by the Commission to dispense
with its consideration of whether a
transmission reservation of an applicant
must be tied to a remote generation
resource in order to be reflected in the
simultaneous transmission import limit
calculation. Southern Companies argue
that, historically, this factor was
significant in the simultaneous
transmission import limit calculation
process. They explain that under the
process set forth in the July 8 Order,
only the portion of an applicant’s
uncommitted remote generation
capacity with firm or network
reservations was modeled in base case
and subtracted from available
simultaneous transmission import
capability, and the remaining
simultaneous transmission import limit
capacity was allocated proportionally
among applicants and other suppliers
based on relative proportions of
uncommitted capacity in areas that are
first-tier to the area under study.24
19. Southern Companies assert that in
Order No. 697, the Commission
appeared to alter this regime by
reducing the minimum period for which
an accounting of 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
23 Id.
24 Southern Companies Rehearing Request at 11–
12 (citing April 14 Order, 107 FERC ¶ 61,018, order
on reh’g, July 8 Order, 108 FERC ¶ 61,026 at P 45).
25 Id. at 12 (citing Order No. 697 at P 368).
26 Id.

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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
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
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.
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.

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longer transmission reservations to
themselves from the calculated SIL
[simultaneous transmission import
limit], where seasonal reservations are
greater than one month and less than
365 consecutive days in duration, as
defined in the Commission’s EQR
[Electric Quarterly Report] Data
Dictionary.’ ’’ 30 EEI supports this
clarification, and states that it concurs,
consistent with the conclusion of the
Commission, that striking the balance at
reservations greater than one month and
less than 365 days will permit the
reasonable modeling of ‘‘ ‘historical
conditions without requiring
unreasonable amounts of information
from applicants.’ ’’ 31 However, EEI
requests clarification of the statement in
paragraph 144 that ‘‘ ‘[t]wenty-eight
days fits within the definition of a
month, and is a reasonable limit to
separate short-term reservations from
long-term reservations for purposes of
the generation market power
screens.’ ’’ 32
21. Specifically, EEI argues that to
allow consistent use of the terminology,
the Commission should clarify that it
does not intend by its ‘‘ ‘[t]wenty-eight
days’ ’’ statement to undo the
clarification set out in paragraph 144,
that short-term reservations are up to
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
30 EEI Rehearing Request at 15 (quoting Order No.
697–A, FERC Stats. & Regs. ¶ 31,268 at P 144).
31 Id.
32 Id.
33 Southern Companies at 15 (citing General
Chemical Corp. v. U.S., 817 F.2d 844, 857 (D.C. Cir.
1987)).

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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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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.
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
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)).
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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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
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
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.
40 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 144.

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[Electric Quarterly Report] Data
Dictionary.’’ 41
2. Further Guidance Regarding Control
and Commitment of Capacity
Background.
26. In Order No. 697, the Commission
concluded that the determination of
control is appropriately based on a
review of the totality of circumstances
on a fact-specific basis. The Commission
explained that no single factor or factors
necessarily results in control. It further
explained that the electric industry
remains a dynamic, developing
industry, and no bright-line standard
will encompass all relevant factors and
possibilities that may occur now or in
the future. The Commission stated that
if a seller has control over certain
capacity such that the seller can affect
the ability of the capacity to reach the
relevant market, then that capacity
should be attributed to the seller when
performing the generation market power
screens.42
27. The Commission determined that
the circumstances or combination of
circumstances that convey control vary
depending on the attributes of the
contract, the market and the market
participants. Therefore, it concluded
that it would be inappropriate to make
a generic finding or generic
presumption of control, but rather that
it is appropriate to continue making
determinations of control on a factspecific basis.43 The Commission
explained, however, that it will
continue its historical approach of
relying on a set of principles or
guidelines to determine what
constitutes control. Thus, the
Commission stated that it continues to
consider the totality of circumstances
and attach the presumption of control
when an entity can affect the ability of
capacity to reach the market. It
explained that its guiding principle is
that an entity controls the facilities
when it controls the decision-making
over sales of electric energy, including
discretion as to how and when power
generated by these facilities will be
sold.44
28. The Commission also declined to
adopt commenters’ suggestions that it
require all relevant contracts to be filed
for review and determination by the
Commission as to which entity controls
a particular asset (e.g., with an initial
application, updated market power
analysis, or change in status filing).
41 Id.
42 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 174.
43 Id. P 175.
44 Id. P 176.

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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
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,
45 Id.

P 187.
Policy Act of 2005, Public Law No. 109–
58, 119 Stat. 594 (2005).
46 Energy

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absent extenuating circumstances. In
order to provide further guidance to the
industry, the Commission reiterated that
the seller, in advising the Commission
of its determinations of control, should
specifically state whether a contractual
arrangement transfers control and
should identify the party or parties it
believes control(s) the generation
facility. The Commission stated that in
doing so, the seller should make its
representation in light of its discussion
in Order No. 697 and cite to that order
as the basis for which it has made its
determination.47
Requests for Rehearing
31. SoCal Edison requests that the
Commission clarify that it will not rely
on representations as to control of
generation assets made by sellers absent
a letter of concurrence from the party
alleged to control the generation asset.
SoCal Edison asserts that Order No.
697–A at paragraph 150 is not clear with
regard to this issue, and that the
Commission should make clear that its
reference to ‘‘our discussion in Order
No. 697’’ means that ‘‘ ‘the owner of a
facility is presumed to have control of
the facility unless such control has been
transferred to another party by virtue of
a contractual agreement’ ’’ and that the
Commission will only rely on the
seller’s assertion of a lack of control if
a letter of concurrence is submitted by
the seller in accordance with paragraph
187 of Order No. 697–A.48 It argues that
if the Commission does not provide the
requested clarification, the Commission
erred in stating in paragraph 150 that it
will rely on the assertion of a seller that
another entity controls a generating
asset owned by the seller, if that
assertion is not supported by a letter of
concurrence from the other entity.49
32. SoCal Edison explains that under
the market power screens, the more
generation a seller ‘‘controls,’’ the
greater the possibility of failing one or
more screens. It states that in Order No.
697, the Commission recognized that
‘‘ ‘affected parties may hold differing
views as to the extent to which control
[over generation] is held by the
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
47 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 150.
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).
50 Id. at 2 (quoting Order No. 697, FERC Stats. &
Regs. ¶ 31,252 at P 187).

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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
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
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
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)).
53 Id. at 4.
54 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 187.
55 Id. P 183.

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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
B. Vertical Market Power
Other Barriers to Entry
Background
35. Order No. 697 adopted the NOPR
proposal to consider a seller’s ability to
erect other barriers to entry as part of
the vertical market power analysis, but
modified the requirements when
addressing other barriers to entry.57 It
also provided clarification regarding the
information that a seller must provide
with respect to other barriers to entry
(including which inputs to electric
power production the Commission will
consider as other barriers to entry) and
modified the proposed regulatory text in
that regard.58
36. On rehearing, the Commission
clarified that it was not its intent for the
term ‘‘inputs to electric power
production’’ to encompass every
instance of a seller entering into a coal
supply contract with a coal vendor in
the ordinary course of business. The
Commission clarified that Order No. 697
encompasses physical coal sources and
ownership of or control over who may
access transportation of coal via barges
and railcar trains.59 Thus, the
Commission revised its definition of
‘‘inputs to electric power production’’ in
§ 35.36(a)(4) as follows: ‘‘Intrastate
natural gas transportation, intrastate
natural gas storage or distribution
facilities; sites for new generation
capacity development; physical coal
supply sources and ownership of or
control over who may access
transportation of coal supplies.’’ 60
Requests for Rehearing
37. The Electric Power Supply
Association (EPSA) requests that the
Commission clarify its definition of
‘‘inputs to electric power production’’ as
it relates to sites for new generation
capacity development.61 EPSA points
out that in response to a request by
Southern Companies, Order No. 697–A
clarifies that the reference to coalrelated inputs extends only to
ownership of or control over who may
56 Id.

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

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57 Order

P 440.
58 Id. P 440.
59 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 176 (emphasis in original).
60 Id.
61 EPSA Rehearing Request at 30 (citing 18 CFR
35.36(a)(4), 35.42(a)(1), (2) (2008)).

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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.
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
62 Id. at 31 (citing Order No. 697, FERC Stats. &
Regs. ¶ 31,252 at P 176).
63 Id.

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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.
39. In addition, in order to
incorporate the clarification provided in
Order No. 697–A that it was not the
intent for the term ‘‘inputs to electric
power production’’ to encompass every
instance of a seller entering into a coal
supply contract with a coal vendor in
the ordinary course of business and the
corresponding change to the regulatory
text in § 35.36(a)(4), 65 we will revise
§ 35.37(e)(3) to read as follows:
‘‘Physical coal supply sources and
ownership or control over who may
access transportation of coal supplies.’’
C. Affiliate Abuse
1. General Affiliate Terms & Conditions
Affiliate Definition
Background
40. In Order No. 697–A, the
Commission clarified that the term
‘‘affiliate’’ for purposes of Order No. 697
and the affiliate restrictions adopted in
§ 35.39 of our regulations is defined as
that term is used in the regulations
adopted in the Affiliate Transactions
Final Rule.66 The Commission stated
that it was taking this action in light of
its goal to have a more consistent
definition of affiliate for purposes of
both EWGs and non-EWGs to the extent
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.
65 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 176.
66 Cross-Subsidization Restrictions on Affiliate
Transaction, Order No. 707, 73 FR 11013 (Feb. 29,
2008), FERC Stats. & Regs. ¶ 31,264 (Feb. 21, 2008)
(Affiliate Transactions Final Rule), order on
rehearing, Order No. 707–A, 73 FR 43072 (July 24,
2008), FERC Stats. & Regs. ¶ 31,272 (2008) (Affiliate
Transactions Final Rule Rehearing).

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possible, as well as to strengthen the
Commission’s ability to ensure that
customers are protected.
41. The Commission explained that in
the Affiliate Transactions Final Rule, it
considered the use of the term affiliate
in the context of the Affiliate
Transactions NOPR, the Commission’s
Standards of Conduct for Transmission
Providers, and other precedent.67 In
particular, the Commission considered
its order in the 1995 Morgan Stanley
case, in which it adopted distinct
definitions of affiliate for EWGs and
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
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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 § 35.36.
Requests for Rehearing and Order
Requesting Supplemental Comments.73
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
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.
72 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 182.
73 Market-Based Rates For Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, 73 FR 51744 (Sept. 5, 2008), 124
FERC ¶ 61,213 (2008) (Order Requesting
Supplemental Comments).
74 The Mirant Entities are Mirant California, LLC,
Mirant Delta, LLC, Mirant Potrero, LLC, Mirant
Canal, LLC, Mirant Kendal, LLC, Mirant Bowline,
LLC, Mirant Lovett, LLC, Mirant Chalk Point, LLC,
Mirant Mid-Atlantic, LLC, Mirant Potomac River,
LLC, and Mirant Energy Trading, LLC.
75 EPSA Rehearing Request at 5 (citing Order No.
697, FERC Stats. & Regs. ¶ 31,252 at P 182–83);
Mirant Rehearing Request at 6–7; Reliant Rehearing
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44. In response to the legal and policy
arguments petitioners raised on
rehearing in opposition to a separate
definition of affiliate for EWGs, the
Commission issued an order requesting
supplemental comments on the
definition of ‘‘affiliate’’ adopted in
Order No. 697–A and codified in
§ 35.36(a)(9) of the Commission’s
regulations.76 In the Order Requesting
Supplemental Comments, the
Commission explained that having
again analyzed FPA section 214, and
irrespective of any Commission
precedent to the contrary, a reasonable
interpretation of FPA section 214 is that
it does not require the Commission to
use a five percent threshold affiliate test
for EWGs for all purposes under Part II
of the 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 nonEWG utilities would not affect the
substance of the Commission’s analysis
of market power issues. The
Commission explained that this
definition is based on the structure of
the PUHCA 1935 definition, but
modified in several ways, including use
of a ten percent threshold instead of five
percent.78
45. Therefore, in the Order Requesting
Supplemental Comments, the
Commission stated that it intends to
revise the definition of affiliate in
§ 35.36(a)(9) of its regulations to delete
the separate definition for EWGs and to
revise the non-EWG part of the
definition to delete the phrase ‘‘other
than an exempt wholesale generator.’’79
The Commission stated that before
taking final action in response to the
rehearing comments, however, it would
seek supplemental comments on the
addressed in greater detail in the Order Requesting
Supplemental Comments.
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.
79 Id. P 12.

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

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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 marketbased rate regulations.82 EPSA’s
supplemental comments also reiterate
EPSA’s argument that a separate
definition of affiliate for EWGs and nonEWGs is not required by the FPA.83
EPSA further argues that a separate
definition of affiliate for EWGs puts
EWGs at an unfair disadvantage in
determining market power under the
Commission’s market-based rate
program since use of a five percent
ownership threshold for EWGs imposes
substantially greater burdens on EWGs
for no useful regulatory purpose.84
47. In its supplemental comments, EEI
states that it supports the proposed
change in the Order Requesting
Supplemental Comments, and agrees
with the Commission’s reasoning that
section 214 of the FPA does not require
use of a five percent threshold for EWGs
for all purposes under the FPA.85 EEI
further states that the Affiliate
Transactions Final Rule fully addresses
the requirement in FPA section 214 that
the Commission ensure that the rates
received by an EWG do not result from
the receipt of any undue preference or
advantage from an electric utility which
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.
85 EEI October 20, 2008 Supplemental Comments
at 2.

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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
Commission Determination.
48. As proposed in the Order
Requesting Supplemental Comments,
and for the reasons discussed therein
and described above,87 the Commission
will revise the definition of affiliate in
§ 35.36(a)(9) of its regulations to delete
the separate definition for EWGs and to
revise the non-EWG part of the
definition to delete the phrase ‘‘other
than an exempt wholesale generator.’’
Specifically, the definition of affiliate in
§ 35.36(a)(9) is being revised to provide
that an affiliate of a specified company
means: (a) Any person that directly or
indirectly owns, controls, or holds with
power to vote, 10 percent or more of the
outstanding voting securities of the
specified company; (b) Any company 10
percent or more of whose outstanding
voting securities are owned, controlled,
or held with power to vote, directly or
indirectly, by the specified company; (c)
Any person or class of persons that the
Commission determines, after
appropriate notice and opportunity for
hearing, to stand in such relation to the
specified company that there is liable to
be an absence of arm’s-length bargaining
in transactions between them as to make
it necessary or appropriate in the public
interest or for the protection of investors
or consumers that the person be treated
as an affiliate; and (d) Any person that
is under common control with the
specified company. For purposes of
paragraph (a)(9), owning, controlling or
holding with power to vote, less than 10
percent of the outstanding voting
securities of a specified company
creates a rebuttable presumption of lack
of control. This revision to the
definition of affiliate in § 35.36(a)(9) of
the market-based rate regulations does
not preclude the Commission from
providing guidance on control and
affiliation in both case-specific and
generic proceedings. We note that the
issue of what constitutes control for
FPA section 203 purposes and marketbased rate purposes is the subject of a
petition for guidance filed by EPSA in
Docket No. PL09–3–000. This is an issue
86 Id.

at 3.
supra P 43–44.

87 See

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of significance to the industry that the
Commission intends to address in a
separate docket, following consideration
of EPSA’s petition in Docket No. PL09–
3–000.
2. Power Sales Restrictions
Sales of Non-Power Goods and Services.
Background.
49. In Order No. 697, the Commission
held that sales of non-power goods or
services by a franchised public utility
with captive customers to a marketregulated 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 crosssubsidization of market-regulated power
sales affiliates by ensuring that the
utility with captive customers does not
pay too much for goods and services
that the utility receives from a marketregulated power sales affiliate.88
Requests for Rehearing
50. FP&L sought limited clarification
or, in the alternative, reconsideration of
Order No. 697 on the issue of pricing of
non-power goods and services provided
for affiliates by either franchised public
utilities or their market-regulated power
sales affiliates when those services are
comparable to shared services provided
by a centralized service company.89
51. FP&L requests clarification that
when a franchised public utility
provides its market-regulated power
sales affiliates with non-power goods or
services, or a market-regulated power
sales affiliate provides its affiliated
franchised public utility with nonpower goods and services, and those
services are comparable to those
provided by a centralized service
company, then those non-power goods
and services may be provided 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
88 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 597.
89 FP&L March 24, 2008, Request for Clarification.
90 Id. at 4.

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therein are prospective only) 91 also
applies with respect to the requirements
of Order No. 697 where existing interaffiliate transactions involving nonpower goods and services are
comparable to those provided by a
centralized service company.

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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.
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
91 Id. at 13 (citing Affiliate Transactions Final
Rule, FERC Stats. & Regs. ¶ 31,264 at P 85).
92 The Commission noted that it need not address
all issues raised in a proceeding at one time. Order
No. 697–A, FERC Stats. & Regs. ¶ 31,268 at P 222
(citing Mobil Oil Exploration & Producing
Southeast, Inc. v. United Distribution Companies,
498 U.S. 211 (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).
93 Affiliate Transactions Final Rule Rehearing,
FERC Stats. & Regs. ¶ 31,272 at P 23.

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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.
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 interaffiliate transactions involving nonpower 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 marketbased 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

94 Id.

P 24–31.
P 31.
96 FP&L March 24, 2008, Request for Clarification
at 13–14.
97 Cross-Subsidization Restrictions on Affiliate
Transactions, 122 FERC ¶ 61,280, at n.5 (2008).
98 Id. at n.5. See also Affiliate Transactions Final
Rule Rehearing, FERC Stats. & Regs. ¶ 31,272 at P
78.
95 Id.

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3. Market-Based Rate Affiliate
Restrictions
Risk Management Employees Under the
No-Conduit Rule
Background
55. In Order No. 697, with regard to
the independent functioning
requirement in the affiliate restrictions,
the Commission adopted a ‘‘no-conduit
rule’’ that prohibits a franchised public
utility with captive customers and a
market-regulated power sales affiliate
from using anyone, including asset
managers, as a conduit to circumvent
the affiliate restrictions.99 Otherwise,
Order No. 697 did not specifically
address the sharing of risk management
employees.
56. On rehearing of Order No. 697, the
Commission determined that ‘‘risk
management personnel do not fall
within the scope of the independent
functioning rule, so long as they are
acting in their roles as risk management
personnel rather than as marketing
function employees, as defined in the
standards of conduct. Of course, such
risk management employees remain
subject to the no-conduit rule and may
not pass market information to
marketing function employees.’’ 100
Requests for Rehearing
57. EEI stated that the Commission’s
clarification with regard to risk
management personnel is consistent
with the Commission’s focus in the
Commission’s evolving standards of
conduct on clarifying that personnel
who are neither transmission function
nor marketing function employees are
primarily governed by the no-conduit
rule. However, EEI states that the
regulatory text of Order No. 697, in the
affiliate restrictions provisions at 18
CFR 35.39(c), does not reflect this
clarification or fully reflect the
evolution of the standards of conduct. It
further states that Order No. 697–A does
not modify the regulatory text to reflect
these changes.
58. Therefore, EEI encourages the
Commission to amend the regulatory
text at 18 CFR 35.39(c) to reflect that all
employees who are neither transmission
nor wholesale marketing function
employees are not within the scope of
the independent functioning rule, but
remain subject to the no-conduit rule.
EEI argues that this change would
conform regulations under Orders No.
99 Order No. 697, FERC Stats. & Regs. ¶ 31,252 at
P 561 (codified at 18 CFR 35.39(g)).
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).

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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

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

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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 marketbased rate sales at the metered boundary
between a balancing authority area in
which a seller is found, or presumed, to
have market power and a balancing
authority area in which the seller has
market-based rate authority, under
certain circumstances.103 The
Commission also adopted a requirement
that mitigated sellers wishing to make
market-based rate sales at the metered
boundary between a balancing authority
area in which the seller was found, or
presumed, to have market power and a
balancing authority area in which the
seller has market-based rate authority
maintain sufficient documentation and
use a specific tariff provision for such
sales.104
61. On rehearing in Order No. 697–A,
the Commission revised the tariff
language governing market-based rate
sales at the metered boundary to
conform with the discussion in the
December 14 Clarification Order
regarding use of the term ‘‘mitigated
market.’’ The Commission stated that, as
explained in the December 14
Clarification Order, ‘‘balancing
authority area in which a seller is found,
or presumed, to have market power’’ is
a more accurate way to describe the area
in which a seller is mitigated.105
62. In addition, after considering
comments regarding the difficulty of
determining and documenting intent,
the Commission decided in Order No.
697-A to eliminate the intent element of
the tariff provision, which stated that
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.
105 Order No. 697-A, FERC Stats. & Regs. ¶ 31,268
at P 333.

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‘‘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 marketbased 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.
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 marketbased rate sales at the metered boundary
or limit such sales to sales to end users
of the power, thereby eliminating the
danger that they will violate their tariff
by re-selling the power back into a
balancing authority in which they are
mitigated.109
Requests for Rehearing
64. In response to the Commission’s
modification of the condition on sales of
market-based power at the border
between a mitigated market and
unmitigated market to state that ‘‘ ‘the
Seller and its affiliates [may] not sell the
same power back into the balancing
authority area where the seller is
106 Id.

P 334.
at n.464.
108 Id. P 335.
109 Id. P 336.
107 Id.

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mitigated,’ ’’ 110 E.ON argues that the
Commission should delete this
condition imposed on border sales or
clarify (1) what is meant by the term
‘‘same power’’ and (2) that neither a
seller nor its affiliate will be found in
violation of this condition if the affiliate
did not know that it was the ‘‘same
power’’ being sold into the mitigated
market.
65. E.ON states that use of the term
‘‘same power’’ causes confusion, as it is
unclear what practical need exists for
the condition generally.111 E.ON
submits that the condition is
unnecessary insofar as where a given
seller is prohibited from selling marketbased power into a given market, it is
almost certain that any affiliate of that
seller is also prohibited from making
such sales, except under an agreement
that predates the mitigation for that
market (a grandfathered agreement).112
E.ON argues that in the limited case of
such an agreement, the ‘‘same power’’
condition need not apply because sales
under such a grandfathered agreement
are permitted to continue after a finding
of market power by the seller and its
affiliates because the agreement was not
tainted by market power and/or the
buyer is protected from the exercise of
market power. E.ON asserts that under
these circumstances, there is no reason
not to allow the ‘‘same power’’ sold by
a mitigated seller to be resold into the
mitigated market by an affiliate under
such a grandfathered agreement.113
66. Further, E.ON argues that the term
‘‘same power’’ is facially ambiguous and
impossible to define or apply in a
practical manner. E.ON submits that
power cannot be ‘‘’color coded’’’ so that
a buyer knows exactly the source of the
power received. E.ON states that where
one single transmission tag indicates a
change of specific transfers of
possession of a block of power among
several parties, it may be reasonable to
assume the power sold and resold is the
‘‘same power.’’ However, E.ON argues
that beyond this limited situation, it is
unclear what the Commission would
consider to be the ‘‘same power.’’ It asks
whether it is the same power if Party A
sells 100 MW to Party B at Bus X, and
Party B, who is not affiliated with Party
A and using a different transmission tag,
wheels 100 MW to Bus Y and then sells
100 MW at Bus Y to Party C, who is an
110 E.ON Rehearing Request at 11 (quoting Order
No. 697-A, FERC Stats. & Regs. ¶ 31,268 at P 339).
111 Id. at 4 (citing Paralyzed Veterans of Amer. v.
D.C. Arena L.P., 117 F.3d 579, 584 (D.C. Cir. 1997),
cert. denied sub nom Abe Pollin, et al. v. Paralyzed
Veterans of Amer., 523 U.S. 1003 (1998)).
112 Id. at 12 (citing MidAmerican Energy Co., 123
FERC ¶ 61,013, at P 37 (2008)).
113 Id.

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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
67. E.ON also contends that sellers of
power often do not know the ultimate
fate of power sold, and that a seller does
not normally concern itself with the
buyer’s ultimate plans for the power,
particularly once the seller’s risk of loss
and title has been transferred to the
buyer. It submits that it is not normal
industry practice for a seller of power to
seek assurances or commitments from a
buyer about what the buyer intends to
do with the power, and that such
activities could raise antitrust or other
anticompetitive concerns.115 Further, it
argues that the Commission should not
assume each seller is aware of all sales
and purchases of power at the same
location in the same hour by its
affiliates because the affiliate restriction
regulations promulgated by the
Commission prevent any kind of sharing
of ‘‘ ‘market information’ ’’ between a
‘‘ ‘franchised public utility’ ’’ and its
‘‘ ‘market-regulated power sales
affiliate.’ ’’ 116 E.ON therefore contends
that two affiliates could theoretically
deal in the ‘‘same power’’ without
having any intent to do so.
68. Pinnacle argues that the
Commission should clarify that resales
of mitigated border purchases are not
permanently banned from reentering the
mitigated area. 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 costbased rates. Pinnacle states that it is not
aware of any prohibition against
at 14.
at 13.
116 Id. at 13-14 (quoting 18 CFR 35.36 et seq.).
117 Id. at 4 (quoting Order No. 697-A, FERC Stats.
& Regs. ¶ 31,268 at P 335).

79621

purchasing at market-based rates and reselling that same power at cost-based
rates as long as affiliates are not in the
chain of sale. Further, Pinnacle argues
that virtually all purchases by a
mitigated seller in its mitigated area will
be purchased at market-based rates, and
states that if the Commission’s
statement were true, it would preclude
mitigated sellers from ever purchasing
power from any party at the metered
boundary of its mitigated area to serve
wholesale load in the mitigated area at
cost-based rates.118
69. In addition, Pinnacle argues that
although the Commission’s statement
that ‘‘[t]o the extent that the mitigated
seller or its affiliates believe that it is
not practical to track such power, they
can either choose to make no marketbased 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 shortterm basis in a subsequent purchase.120
70. Further, Pinnacle states that even
without the intent requirement, a seller
in a long-term sale in many cases would
only be able to track the path of the
power through NERC tags after the
power is delivered, since for a longer
term sale, a tag is not created at the time
the transaction is executed. Pinnacle
states that it believes that counterparties
will likely not agree to limitations on
where the power can sink on term deals,
particularly as neither Order No. 697

114 Id.
115 Id.

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

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nor Order No. 697-A require contractual
limits. Pinnacle explains that an
example that illustrates this situation
occurs ‘‘if APS sold power at Pinnacle
Peak (a border of the Phoenix Valley
Load Pocket, the Pinnacle West
Companies’ mitigated area) for a year to
a marketer, and then later, on a day
during the season mitigated for
[Pinnacle], APS’s affiliate purchased
power from the same marketer to serve
load in the Phoenix Valley Load Pocket,
this transaction would violate the
regulations as currently written, even
though there was no intent to bring the
power back into the mitigated area at
the time of the sale.’’ 121
71. Pinnacle explains that since there
is no way to predict when the power is
going to be needed in the mitigated area
and from whom it may be purchased,
the only way to ensure that this scenario
does not occur inadvertently is for
mitigated sellers to make no marketbased rate sales at their mitigated
borders for anything other than realtime 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.
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
121 Id.

at 6.

122 Id.

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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
73. Wisconsin Electric states that it
has a Commission-approved marketbased rate tariff that permits it to make
wholesale sales at or beyond the
metered boundary of the WisconsinUpper 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
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.
125 Id. at 5 (citing In re SCANA Corp., 118 FERC
¶ 61,028 (2007)).

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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-topoint transmission service to transmit
the power to the metered boundary, and
further asserts that the requirement to
bear such transmission costs will render
useless the ability to make sales at the
metered boundary, because the point-topoint transmission costs layered on top
of the energy and capacity costs would
likely render the sale uneconomic.
Wisconsin Electric therefore concludes
that wholesale customers in balancing
authority areas in which the mitigated
seller is authorized to make marketbased sales will be left with fewer
purchase options.126
75. Finally, Wisconsin Electric argues
that the Commission should clarify that
the metered boundary will not be the
entire Midwest ISO footprint after the
Midwest ISO ancillary services market
becomes operational. In particular, it
states that when the ancillary services
market becomes operational, the
Midwest ISO region will become a
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 marketbased 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
126 Id.
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 marketbased 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,
129 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 336.

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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
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
130 Id.

mitigated sellers seeking to modify their
tariffs in this regard must submit a filing
at the Commission pursuant to section
205 of the FPA, and should explain why
they should be permitted to revise their
tariff language for sales of power at
market-based rates at the metered
boundary.
80. With regard to Wisconsin
Electric’s arguments on rehearing, we
grant Wisconsin Electric’s request for
clarification that Order No. 697–A did
not modify the terms of Wisconsin
Electric’s market-based rate tariff (which
allowed Wisconsin Electric to sell
energy into the Midwest ISO energy
market without ‘‘at or beyond the
metered boundary’’ restrictions) or the
manner in which wholesale sales are
conducted in the Midwest ISO energy
market.134 We further note that,
subsequent to the filing of its rehearing
request in this proceeding, the
Commission accepted a tariff filing by
Wisconsin Electric that removed from
its market-based rate tariff the provision
prohibiting Wisconsin Electric from
making bilateral market-based rate sales
in WUMS.135
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 marketbased 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 marketbased 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

P 335.

131 Id.
132 Order

No. 697–A, FERC Stats. & Regs. ¶ 31,268

at n.464.
133 Arizona Public Service Co., Docket No. EL08–
1104–000, at 1 (July 3, 2008) (unpublished letter
order).

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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).
136 Id.

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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.
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

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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
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.
84. In addition, to ensure greater
consistency in the data used to evaluate
Category 2 sellers, the Commission
modified the timing for the submission
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.
139 18 CFR 35.36(a)(2).
140 See 18 CFR 35.42.

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of updated market power analyses.141
Order No. 697 requires analyses to be
filed for each seller’s region on a predetermined schedule, rotating by
geographic region where two regions are
reviewed each year, with the cycle
repeating every three years.142
85. On rehearing in Order No. 697–A,
the Commission upheld its
determination to create a category of
market-based rate sellers (Category 1
sellers) that are exempt from the
requirement to automatically submit
updated market power analyses and its
decision to adopt a regional review. The
Commission also clarified, consistent
with its December 14 Clarification
Order, that revised Appendix D to Order
No. 697–A makes clear that
transmission owners and their affiliates
have earlier filing periods than the other
entities required to file in each
region.143
Requests for Rehearing
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
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
141 Previously, updated market power analyses
were submitted within three years of any order
granting a seller market-based rate authority, and
every three years thereafter.
142 See Order No. 697, FERC Stats. & Regs.
¶ 31,252 at Appendix D. The regions include the
Northeast, Southeast, Central, Southwest Power
Pool, Southwest, and Northwest.
143 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 374 (citing December 14 Clarification Order,
121 FERC ¶ 61,260 at P 9).
144 Wisconsin Electric Rehearing Request at 7.
145 Wisconsin Electric Power Co., 90 FERC
¶ 61,346 (2000).

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

several provisions should be changed to
provide additional clarity.151

2. Market-Based Rate Tariff
Clarifications

Triggering Events for Change in Status
Filings

Background

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

92. In Order No. 697, the Commission
adopted a regulation requiring sellers to
timely report to the Commission any
change in status that would reflect a
departure from the characteristics the
Commission relied upon in granting
market-based rate authority. In
particular, § 35.42 specifies that a
change in status includes, but is not
limited to, ‘‘ownership or control of
generation capacity that results in net
increases of 100 MW or more.’’ 152
93. Upon further consideration, in
Order No. 697–A, the Commission
clarified that a change in status also
includes long-term firm capacity
purchases that result in net increases of
100 MW or more. The Commission
explained that this is consistent with a
seller’s obligation to include long-term
firm capacity purchases in determining
uncommitted capacity, which is used in
the indicative screens.153 The
Commission stated that revision to the
regulation is appropriate because the
Commission’s April 14 Order,
reaffirmed in Order No. 697, stated that
uncommitted capacity is determined
‘‘by adding the total nameplate or
seasonal capacity of generation owned
or controlled through contract and firm
purchases, less operating reserves,
native load commitments and long-term
firm sales.’’ 154 Thus, the Commission
explained that long-term firm capacity
purchases that result in net increases of
100 MW or more are a ‘‘departure from
the characteristics the Commission
relied upon in granting market-based
rate authority.’’ Accordingly, the
Commission revised § 35.42(a)(1) so that
a change in status includes, but is not
limited to, ‘‘ownership or control of
generation capacity and long-term firm
purchases of generation capacity that
result in net increases of 100 MW or
more.’’ The Commission stated that
because sellers may not have been on
notice that this was the Commission’s
intent, it will not hold any sellers
responsible for failure to report such
changes in status prior to the effective
date of this order, which will be 30 days
after issuance in the Federal Register.155

Requests for Rehearing
89. With respect to the standard
applicable ancillary service tariff
provision(s) set forth in Appendix C to
Order No. 697–A, EEI states that
Appendix C has not yet been updated to
reflect that the Commission has
approved the market power study
performed by the Midwest ISO
Independent Market Monitor. EEI
encourages the Commission to add
Midwest ISO to Appendix C, with an
effective date matching the start of the
market.149
Commission Determination
90. The tariff provision for the
Midwest ISO ancillary services market
has been included in Appendix C and
is available on the Commission’s Web
site.150 The effective date of the tariff
sheet with the required tariff provision
for the Midwest ISO ancillary services
market should match the start date of
the Midwest ISO ancillary services
market accepted by the Commission.
F. Clarifications of the Commission’s
Regulations

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91. In Order No. 697–A, the
Commission found that based on its
further consideration of the regulations,
146 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at Appendix D–2.
147 Order, No. 697, FERC Stats. & Regs. ¶ 31,252
at P 918.
148 Id. P 387 (citing Order No. 697, FERC Stats.
& Regs. ¶ 31,252 at P 916–917; Appendix C (for a
listing of the standard ancillary services
provisions); Niagara Mohawk Power Corp., 121
FERC ¶ 61,275, at P 14 & n.22 (2007) (directing
seller to conform with Appendix C)).
149 EEI Rehearing Request at 18.
150 http://www.ferc.gov/industries/electric/geninfo/mbr.tariff.asp.

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151 Order No. 697–A, FERC Stats. & Regs. ¶ 31,268
at P 527.
152 Id. P 528.
153 Id. P 530 (citing April 14 Order, 107 FERC
¶ 61,018 at P 95, 100).
154 Id. (citing Order No. 697, FERC Stats. & Regs.
¶ 31,252 at P 38) (footnote omitted).
155 Id. P 531.

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79625

Requests for Rehearing
94. EPSA requests that the
Commission clarify Order No. 697–A’s
inclusion of long-term capacity
purchases as a trigger for changes in
status filings.
95. EPSA argues that although the
Commission intended to provide
additional clarity, the Commission’s
new reference to ‘‘long-term firm
capacity purchases’’ is more confusing
than illuminating. It argues that capacity
purchases, which are distinct from
energy purchases, are found primarily
in RTOs/ISOs with forward capacity
markets, and less frequently, in bilateral
transactions with load serving entities
that require additional capacity for
planning purchases. EPSA asserts that
the April 14 Order, on which the
Commission relies, appears to be both
broader in one respect than the new
§ 35.42(a)(1) requirement, and narrower
in another. First, according to EPSA, the
relevant portion of the April 14 Order
appears to address long-term energy and
capacity transactions, both of which fall
into the ambit of firm purchases of
generation, while Order No. 697–A
appears to focus solely on long-term
firm capacity purchases. Second, EPSA
argues that the April 14 Order appears
to require the element of control in the
calculation of uncommitted capacity,
while the modification to § 35.42(a)(1)
promulgated in Order No. 697–A
appears to place all ‘‘ ‘long-term firm
purchases of generation capacity’ ’’ into
the calculation, regardless of control.156
96. EPSA argues that to the extent the
Commission intended to include all
long-term firm energy purchases in
cumulating generation increases, or to
include all long-term firm capacity and
energy purchases regardless of control,
this aspect of Order No. 697–A appears
inconsistent with the Commission’s
prior orders. Specifically, EPSA asserts
that in the Order No. 652 rehearing
order, the Commission clarified that
‘‘ ‘to the extent * * * a contract for a
fixed quantity delivered energy does not
confer control, it need not be reported
[as a change in status].’ ’’ 157 EPSA also
states that more recently, the
Commission concluded that the sale of
a firm liquidated damages (LD) energy
product under the EEI Master Power
Purchase and Sale Agreement ‘‘ ‘would
not reflect a departure from the
characteristics the Commission relied
156 ESPA Rehearing Request at 28 (citing Order
No. 697–A, FERC Stats. & Regs. ¶ 31,268 at P 530–
31).
157 Id. at 29 (quoting Reporting Requirement for
Changes in Status for Public Utilities with MarketBased Rate Authority, 111 FERC ¶ 61,413, at P 12
(2005) (rehearing of Order No. 652).

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upon in granting market-based rate
authority and therefore would not
necessitate the filing of a change in
status report’ ’’ because the product ‘‘ ‘by
itself gives the purchaser only a right to
receive energy and thus no rights that
would allow the purchaser to control
generation capacity.’ ’’ 158
97. EPSA therefore requests guidance
with respect to the following questions
in order to facilitate full compliance
with the Commission’s change in status
reporting regulations: (1) Does the
change articulated in Order No. 697–A
require sellers to include only long-term
firm capacity purchases in their
cumulative generation count for changein-status purposes, or are they to
include long-term firm energy purchases
as well? (2) If sellers are to include only
long-term firm capacity purchases in
their cumulative generation count, did
the Commission intend this terminology
to encompass transactions in addition to
the traditional capacity purchases as
outlined above? (3) If sellers are to
include long-term firm energy purchases
in their cumulative generation counts
for change-in-status purchases, are they
to include all long-term firm energy
purchases or only those that confer
some element of control, as implied by
the Commission’s April 14 Order, its
order on rehearing of Order No. 652,
and in the recent Integrys decision? and
(4) If only contracts that confer control
are to be included (whether capacity
only, or energy and capacity), are
entities with market-based rates
permitted to exclude from their
calculation those long-term firm energy
contracts that contain either liquidated
damage provisions or other provisions
that permit the seller to retain a
complete and unrestricted right to
choose a generating resource or a
monetized replacement resource? 159
98. EPSA submits that how the
Commission addresses these questions
will not only impact change in status
reporting, but will also have significant
bearing on the data sellers assemble and
analyze in their updated market power
analyses to the extent ‘‘long-term firm
purchases’’ and ‘‘long-term firm sales’’
(as listed on the Commission’s standard
screen format for the pivotal supplier
analysis) are no longer limited to
transactions which confer control, or
alternatively are limited to capacity
purchases and sales only.160
158 Id. (quoting Integrys Energy Group, Inc., 123
FERC ¶ 61,034, at P 11 (2008) (Integrys)).
159 Id. at 29–30.
160 Id. at 30.

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Commission Determination
99. In response to the first question
posed by EPSA regarding whether Order
No. 697–A requires sellers to include
long-term energy purchases in addition
to long-term firm capacity purchases in
their cumulative generation count for
change-in-status purposes, we find that
to the extent a contract for a fixed
quantity of delivered energy does not
confer control, it need not be
reported.161 Consistent with the
Commission’s determination in Integrys
that the sale of a ‘‘Firm (LD)’’ product,
as defined in the EEI Master Power
Purchase & Sale Agreement, by itself
gives the purchaser only a right to
receive energy and thus no rights that
would allow the purchaser to control
generation capacity, we reiterate that the
sale of the Firm (LD) product would not
reflect a departure from the
characteristics the Commission relied
upon in granting market-based rate
authority and therefore would not
necessitate the filing of a change in
status report.162 We note that in
reaching this determination, the
Commission relied on the
representations of Integrys Energy
Group, Inc. that the purchaser under a
Firm (LD) product has no ability to
withhold energy from the market or
otherwise use the product as part of a
capacity withholding strategy.163 For
example, the Commission relied on the
fact that the purchaser cannot force the
seller to back down the output of any
generator, and the fact that if the
purchaser refuses to receive delivery,
that refusal does not keep the power
from entering the market because the
seller has the right to resell the Firm
(LD) product, as well as to receive
damages from the purchaser. However,
to the extent a long-term energy
purchase would allow the purchaser to
control generation capacity, it needs to
be reported. A determination of whether
a long-term firm energy purchase
confers control over generation capacity
to the purchaser must be based on a
review of the totality of the
circumstances on a fact-specific basis.
Therefore, sellers who are uncertain as
to whether they must include long-term
energy purchases in their cumulative
generation count because the facts and
circumstances surrounding their long161 Integrys, 123 FERC ¶ 61,034 at P 11 (regarding
energy only contracts in Reporting Requirement for
Changes in Status for Public Utilities with MarketBased Rate Authority, 111 FERC ¶ 61,413, at P 12
(2005) (rehearing of Order No. 652) the Commission
concluded that ‘‘ ‘to the extent * * * a contract for
a fixed quantity of delivered energy does not confer
control, it need not be reported.’ ’’).
162 Id.
163 Id. P 7.

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term energy purchase(s) differ from the
facts relied on by the Commission in the
Integrys order will need to obtain
guidance from the Commission by
making a filing at the Commission.
Sellers will need to provide information
on the facts, terms and circumstances
concerning the long-term energy
purchase(s) in their filing. The
Commission will evaluate each such
filing on a case-by-case basis and will
make a determination based on those
specific facts and circumstances.
100. With regard to EPSA’s second
question concerning whether sellers are
to include only long-term firm capacity
purchases in their cumulative
generation count, and whether the
Commission intended this terminology
to encompass transactions in addition to
traditional capacity purchases, we
clarify that as the Commission
explained in Integrys, where a purchase
‘‘does not result in a transfer of control
of generation capacity to the purchaser’’
it does not have to be reported by the
purchaser in a change in status report
under the Commission’s regulations.164
However, we note that the
Commission’s finding in Integrys was
limited to the facts described by the
Integrys group, and was dependent on
the specific terms and conditions for a
Firm (LD) product, as defined by the EEI
Master Power Purchase and Sale
Agreement. Thus, as the Commission
explained in Integrys, different or
additional facts, terms, or conditions
could change the Commission’s analysis
of whether other types of transactions
transfer control of generation capacity to
the purchaser.165
101. With regard to EPSA’s third
question (if sellers are to include longterm firm energy purchases in their
cumulative generation counts for change
in status purchases, are they to include
all long-term firm energy purchases or
only those that confer some element of
control), we clarify that, as stated above,
only long-term firm energy purchases
that confer some element of control
must be included in a seller’s
cumulative generation counts for change
in status reports.166 A long-term firm
energy purchase by itself gives the
purchaser only a right to receive energy
and thus no rights that would allow the
purchaser to control generation
capacity.167 As explained above, a
determination of whether a long-term
firm energy purchase confers control
164 See

id.

165 Id.
166 Id. (citing Reporting Requirement for Changes
in Status for Public Utilities with Market-Based
Rate Authority, 111 FERC ¶ 61,413 at P 12).
167 Id.

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Federal Register / Vol. 73, No. 250 / Tuesday, December 30, 2008 / Rules and Regulations
over generation capacity must be based
on a review of the totality of the
circumstances on a fact-specific basis.
102. EPSA’s fourth question (if only
contracts that confer control are to be
included in their cumulative generation
count (whether capacity only, or energy
and capacity), are entities with marketbased rates permitted to exclude from
their calculation those long-term firm
energy contracts that contain either
liquidated damage provisions or other
provisions that permit the seller to
retain a complete and unrestricted right
to choose a generating resource or a
monetized replacement resource)
requires a fact-specific determination.
As the Commission explained in
Integrys, different or additional facts,
terms, or conditions could change the
Commission’s analysis. Thus, whether
long-term firm energy contracts that
contain either liquidated damage
provisions or other provisions that
permit the seller to retain a complete
and unrestricted right to choose a
generating resource result in a transfer
control of generation capacity to the
purchaser is an issue to be determined
on a case-by-case basis.168 We will not
make a generic finding on whether
contracts with such provisions are
exempt from being included in a
market-based rate seller’s cumulative
MW total for change in status reports.169

view and/or print the contents of this
document via the Internet through
FERC’s Home Page (http://www.ferc.gov)
and in FERC’s Public Reference Room
during normal business hours (8:30 a.m.
to 5 p.m. Eastern time) at 888 First
Street, NE., Room 2A, Washington, DC
20426.
105. From FERC’s Home Page on the
Internet, this information is available on
eLibrary. The full text of this document
is available on eLibrary in PDF and
Microsoft Word format for viewing,
printing, and/or downloading. To access
this document in eLibrary, type the
docket number excluding the last three
digits of this document in the docket
number field.
106. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from FERC
Online Support at 202–502–6652 (toll
free at 1–866–208–3676) or e-mail at
[email protected], or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. E-mail the
Public Reference Room at
[email protected].

III. Information Collection Statement
103. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain information
collection requirements imposed by an
agency.170 The Final Rule’s revisions to
the information collection requirements
for market-based rate sellers were
approved under OMB Control Nos.
1902–0234. While this order clarifies
aspects of the existing information
collection requirements for the marketbased rate program, it does not add to
these requirements. Accordingly, a copy
of this order will be sent to OMB for
informational purposes only.

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

IV. Document Availability
104. In addition to publishing the full
text of this document in the Federal
Register, the Commission provides all
interested persons an opportunity to

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168 Id.

Although EPSA also asked this question in
connection with contractual provisions that permit
the seller to retain a complete and unrestricted right
to choose a ‘‘monetized replacement resource,’’
EPSA does not define the term ‘‘monetized
replacement resource’’ in its rehearing request. As
a result, we do not include that term in our
response above.
169 Reporting Requirement for Changes in Status
for Public Utilities with Market-Based Rate
Authority, 111 FERC ¶ 61,413, at P 12 (2005).
170 5 CFR 1320.11.

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V. Effective Date
107. Changes to Order No. 697–A
adopted in this order on rehearing will
become effective January 29, 2009.
List of Subjects in 18 CFR Part 35

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

In consideration of the foregoing, the
Commission amends part 35 Chapter I,
Title 18, Code of Federal Regulations, as
follows:
PART 35—FILING OF RATE
SCHEDULES AND TARIFFS
1. The authority citation for part 35
continues to read as follows:

■

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

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

■

Generally.

(a) * * *
(9) Affiliate of a specified company
means:
(i) Any person that directly or
indirectly owns, controls, or holds with
power to vote, 10 percent or more of the
outstanding voting securities of the
specified company;
(ii) Any company 10 percent or more
of whose outstanding voting securities
are owned, controlled, or held with

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Fmt 4700

power to vote, directly or indirectly, by
the specified company;
(iii) Any person or class of persons
that the Commission determines, after
appropriate notice and opportunity for
hearing, to stand in such relation to the
specified company that there is liable to
be an absence of arm’s-length bargaining
in transactions between them as to make
it necessary or appropriate in the public
interest or for the protection of investors
or consumers that the person be treated
as an affiliate; and
(iv) Any person that is under common
control with the specified company.
(v) For purposes of paragraph (a)(9),
owning, controlling or holding with
power to vote, less than 10 percent of
the outstanding voting securities of a
specified company creates a rebuttable
presumption of lack of control.
*
*
*
*
*
3. In § 35.37, paragraph (e)(3) is
revised to read as follows:

■

§ 35.37

Market power analysis required.

(e) * * *
(3) Physical coal supply sources and
ownership or control over who may
access transportation of coal supplies.
*
*
*
*
*
Note: The following appendix will not be
published in the Code of Federal
Regulations.

Appendix C to Order No. 697-A
Required Provisions of the Market-Based
Rate Tariff

■

§ 35.36

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Compliance With Commission Regulations
Seller shall comply with the provisions of
18 CFR Part 35, Subpart H, as applicable, and
with any conditions the Commission imposes
in its orders concerning seller’s market-based
rate authority, including orders in which the
Commission authorizes seller to engage in
affiliate sales under this tariff or otherwise
restricts or limits the seller’s market-based
rate authority. Failure to comply with the
applicable provisions of 18 CFR Part 35,
Subpart H, and with any orders of the
Commission concerning seller’s market-based
rate authority, will constitute a violation of
this tariff.
Limitations and Exemptions Regarding
Market-Based Rate Authority
[Seller should list all limitations (including
markets where seller does not have marketbased rate authority) on its market-based rate
authority and any exemptions from or
waivers granted of Commission regulations
and include relevant cites to Commission
orders].
Seller Category
Seller Category: Seller is a [insert Category
1 or Category 2] seller, as defined in 18 CFR
35.36(a).

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Federal Register / Vol. 73, No. 250 / Tuesday, December 30, 2008 / Rules and Regulations

Include All of the Following Provisions That
Are Applicable

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Mitigated Sales
Sales of energy and capacity are
permissible under this tariff in all balancing
authority areas where the Seller has been
granted market-based rate authority. Sales of
energy and capacity under this tariff are also
permissible at the metered boundary between
the Seller’s mitigated balancing authority
area and a balancing authority area where the
Seller has been granted market-based rate
authority provided: (i) Legal title of the
power sold transfers at the metered boundary
of the balancing authority area; (ii) if the
Seller wants to sell at the metered boundary
of a mitigated balancing authority area at
market-based rates, then neither it nor its
affiliates can sell into that mitigated
balancing authority area from the outside.
Seller must retain, for a period of five years
from the date of the sale, all data and
information related to the sale that
demonstrates compliance with items (i) and
(ii) above.
Ancillary Services
RTO/ISO Specific—Include All Services the
Seller Is Offering
PJM: Seller offers regulation and frequency
response service, energy imbalance service,
and operating reserve service (which
includes spinning, 10-minute, and 30-minute
reserves) for sale into the market
administered by PJM Interconnection, L.L.C.
(‘‘PJM’’) and, where the PJM Open Access
Transmission Tariff permits, the self-supply
of these services to purchasers for a bilateral
sale that is used to satisfy the ancillary
services requirements of the PJM Office of
Interconnection.
New York: Seller offers regulation and
frequency response service, and operating
reserve service (which include 10-minute
non-synchronous, 30-minute operating
reserves, 10-minute spinning reserves, and
10-minute non-spinning reserves) for sale to
purchasers in the market administered by the
New York Independent System Operator, Inc.
New England: Seller offers regulation and
frequency response service (automatic
generator control), operating reserve service
(which includes 10-minute spinning reserve,
10-minute non-spinning reserve, and 30minute operating reserve service) to
purchasers within the markets administered
by the ISO New England, Inc.
California: Seller offers regulation service,
spinning reserve service, and non-spinning
reserve service to the California Independent
System Operator Corporation (‘‘CAISO’’) and
to others that are self-supplying ancillary
services to the CAISO.
Midwest ISO: Seller offers regulation
service and operating reserve service (which
include a 10-minute spinning reserve and 10minute supplemental reserve) for sale to the
Midwest Independent Transmission System
Operator, Inc. (Midwest ISO) and to others
that are self-supplying ancillary services to
Midwest ISO.
Third Party Provider
Third-party Ancillary Services: Seller offers
[include all of the following that the seller is

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Jkt 217001

offering: Regulation Service, Energy
Imbalance Service, Spinning Reserves, and
Supplemental Reserves]. Sales will not
include the following: (1) Sales to an RTO or
an ISO, i.e., where that entity has no ability
to self-supply ancillary services but instead
depends on third parties; (2) sales to a
traditional, franchised public utility affiliated
with the third-party supplier, or sales where
the underlying transmission service is on the
system of the public utility affiliated with the
third-party supplier; and (3) sales to a public
utility that is purchasing ancillary services to
satisfy its own open access transmission tariff
requirements to offer ancillary services to its
own customers.
[FR Doc. E8–30757 Filed 12–29–08; 8:45 am]
BILLING CODE 6717–01–P

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 284
[Docket No. RM08–1–001; Order No.
712–A]

Promotion of a More Efficient Capacity
Release Market
December 22, 2008.
AGENCY: Federal Energy Regulatory
Commission, DOE.
ACTION: Final rule; correction.

The Federal Regulatory
Commission (FERC) is correcting a final
rule that appeared in the Federal
Register of December 1, 2008 (73 FR
72692). The document revised
regulations governing interstate natural
gas pipelines to reflect changes in the
market for short-term transportation
services on pipelines and to improve the
efficiency of the Commission’s capacity
release program.
DATES: Effective Date: This rule will
become effective December 31, 2008.
FOR FURTHER INFORMATION CONTACT:
William Murrell, Office of Energy
Market Regulation, Federal Energy
Regulatory Commission, 888 First
Street, NE., Washington, DC 20426,
[email protected], (202) 502–
8703.
Robert McLean, Office of General
Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426,
[email protected], (202) 502–
8156.
David Maranville, Office of the
General Counsel, Federal Energy
Regulatory Commission, 888 First
Street, NE., Washington, DC 20426,
[email protected], (202) 502–
6351.
SUMMARY:

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In FR Doc.
E8–28217 appearing on page 72692 in
the Federal Register of Monday,
December 1, 2008, the following
corrections are made:
§ 284.8(h) [Corrected]
1. On page 72714, in the first column,
in § 284.8 Release of Capacity by
Interstate Pipelines, in paragraph
(h)(1)(i), ‘‘A release of capacity to an
asset manager as defined in paragraph
(h)(4) of this section’’ is corrected to
read ‘‘A release of capacity to an asset
manager as defined in paragraph (h)(3)
of this section;’’
§ 284.8(h) [Corrected]
2. On page 72714 in the first and
second columns, in § 284.8 Release of
Capacity by Interstate Pipelines, in
paragraph (h)(1)(ii), ‘‘A release of
capacity to a marketer participating in a
state-regulated retail access program as
defined in paragraph (h)(5) of this
section’’ is corrected to read ‘‘A release
of capacity to a marketer participating in
a state-regulated retail access program as
defined in paragraph (h)(4) of this
section’’

SUPPLEMENTARY INFORMATION:

Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. E8–30910 Filed 12–29–08; 8:45 am]
BILLING CODE 6717–01–P

PENSION BENEFIT GUARANTY
CORPORATION
29 CFR Parts 4001, 4211, and 4219
RIN 1212–AB07

Methods for Computing Withdrawal
Liability; Reallocation Liability Upon
Mass Withdrawal; Pension Protection
Act of 2006
AGENCY: Pension Benefit Guaranty
Corporation.
ACTION: Final rule.
SUMMARY: This final rule amends
PBGC’s regulation on Allocating
Unfunded Vested Benefits to
Withdrawing Employers (29 CFR part
4211) to implement provisions of the
Pension Protection Act of 2006 that
provide for changes in the allocation of
unfunded vested benefits to
withdrawing employers from a
multiemployer pension plan, and that
require adjustments in determining an
employer’s withdrawal liability when a
multiemployer plan is in critical status.
Pursuant to PBGC’s authority under
section 4211(c)(5) of ERISA to prescribe
standard approaches for alternative
withdrawal liability methods, the final
rule also amends this regulation to
provide additional modifications to the

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