Order 697-A (issued 4/21/08; published in Federal Register 5/7/08)

Wednesday,
May 7, 2008

Part II

Department of
Energy
Federal Energy Regulatory Commission

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18 CFR Part 35
Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary
Services by Public Utilities; Final Rule

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
Order on Rehearing and
Clarification.

ACTION:

DEPARTMENT OF ENERGY
Federal Energy Regulatory
Commission
18 CFR Part 35
[Docket No. RM04–7–001; Order No. 697–
A]

Market-Based Rates for Wholesale
Sales of Electric Energy, Capacity and
Ancillary Services by Public Utilities
Issued April 21, 2008.

Federal Energy Regulatory
Commission, DOE.

AGENCY:

SUMMARY: In this order on rehearing, the
Commission affirms its basic
determinations in Order No. 697, and
grants 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.
The Commission also clarifies several
aspects of the implementation process
adopted in Order No. 697.

Effective Date: This rule will
become effective June 6, 2008.
FOR FURTHER INFORMATION CONTACT:
Debra A. Dalton (Technical
Information), Office of Energy Market
Regulation, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–6253,
and Elizabeth Arnold (Legal
Information), Office of the General
Counsel, Federal Energy Regulatory
Commission, 888 First Street, NE.,
Washington, DC 20426, (202) 502–8818.
SUPPLEMENTARY INFORMATION:
DATES:

Table of Contents
Paragraph
numbers

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I. Introduction ...........................................................................................................................................................................................
II. Discussion ............................................................................................................................................................................................
A. Horizontal Market Power .............................................................................................................................................................
1. Whether to Retain the Indicative Screens ............................................................................................................................
2. Indicative Market Share Screen Threshold Levels ..............................................................................................................
3. DPT Criteria ............................................................................................................................................................................
4. Other Products and Models ...................................................................................................................................................
5. Native Load Deduction ..........................................................................................................................................................
6. Relevant Geographic Market .................................................................................................................................................
7. Use of Historical Data ............................................................................................................................................................
8. Transmission Imports ............................................................................................................................................................
9. Further Guidance Regarding Control and Commitment of Capacity ..................................................................................
B. Vertical Market Power ..................................................................................................................................................................
1. OATT Violations and Market-Based Rate Revocation .........................................................................................................
2. Treatment of FTRs .................................................................................................................................................................
3. Other Barriers to Entry ..........................................................................................................................................................
C. Affiliate Abuse ..............................................................................................................................................................................
1. General Affiliate Terms & Conditions ..................................................................................................................................
2. Power Sales Restrictions ........................................................................................................................................................
3. Market-Based Rate Affiliate Restrictions ..............................................................................................................................
D. Mitigation ......................................................................................................................................................................................
1. Cost-Based Rate Methodology ...............................................................................................................................................
2. Protecting Markets With Mitigated Sellers ...........................................................................................................................
E. Implementation Process ...............................................................................................................................................................
1. Category 1 and 2 Sellers ........................................................................................................................................................
2. Regional Review and Schedule .............................................................................................................................................
3. Clarifications on Implementation Process ............................................................................................................................
4. Market-Based Rate Tariff Clarifications ................................................................................................................................
F. Legal Authority .............................................................................................................................................................................
1. Whether Market-Based Rates Can Satisfy the Just and Reasonable Standard Under the FPA .........................................
2. Consistency of Market-Based Rate Program with FPA Filing Requirements .....................................................................
3. Whether Existing Tariffs Must Be Found To Be Unjust and Unreasonable, and Whether the Commission Must Establish a Refund Effective Date ..............................................................................................................................................
G. Miscellaneous ...............................................................................................................................................................................
1. Change in Status ....................................................................................................................................................................
2. Third Party Providers of Ancillary Services ........................................................................................................................
3. Requesting Market-Based Rate Authority for QFs ...............................................................................................................
H. Clarifications of the Commission’s Regulations .........................................................................................................................
III. Information Collection Statement ......................................................................................................................................................
IV. Document Availability .......................................................................................................................................................................
V. Effective Date .......................................................................................................................................................................................
Regulatory Text
Appendix A to Subpart H: Standard Screen Format
Appendix C to Order No. 697–A: Revised Tariff Language
Appendix D to Order No. 697–A: Revised Regional Review Schedule
Appendix E to Order No. 697–A: Petitioner Acronyms

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
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
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. On December 14, 2007, the
Commission issued an order clarifying
four aspects of Order No. 697.2
Specifically, that order addressed: (1)
The effective date for compliance with
the requirements of Order No. 697; (2)
which entities are required to file
updated market power analyses for the
Commission’s regional review; (3) the
data required for the horizontal market
power analyses; and (4) what constitutes
‘‘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
Clarification Order.
3. In this order, the Commission
responds to a number of requests for
rehearing and clarification of Order No.
697. In most respects, the Commission
1 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, Order No. 697, 72 FR 39,904 (Jul.
20, 2007), FERC Stats. & Regs. ¶ 31,252 (2007) (Final
Rule).
2 Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary Services by
Public Utilities, 121 FERC ¶ 61,260 (2007)
(Clarification Order).

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reaffirms its determinations made in
Order No. 697 and denies rehearing of
these issues. With respect to several
issues, however, the Commission grants
rehearing or provides clarification.
4. For example, the Commission
affirms in large part the determinations
made in Order No. 697 concerning the
horizontal market power analysis,
including the use of the 20 percent
threshold for the indicative wholesale
market share screen and the Delivered
Price Test (DPT), the use of a 2,500
Hirschman-Herfindahl Index (HHI)
threshold for the DPT analysis, and the
use of the average peak native load as
the native load proxy for the indicative
wholesale market share screen and DPT
analysis. The Commission also affirms
its decision to use a balancing authority
area or the RTO/ISO region as the
default relevant geographic market.
Similarly, the Commission affirms the
decision that, where the Commission
has made a specific finding that there is
a submarket within an RTO/ISO, that
submarket should be considered the
default relevant geographic market.
However, the Commission grants
rehearing concerning the finding that
Northern PSEG is a submarket within
PJM. On reconsideration, we conclude
that we erred in relying on a finding of
a submarket in a particular proceeding
that was subsequently vacated on
procedural grounds.
5. In response to requests for
clarification concerning existing
mitigation in RTO/ISOs, the
Commission adopts a rebuttable
presumption that the existing
Commission-approved RTO/ISO
mitigation is sufficient to address
market power concerns in the RTO/ISO
market, including mitigation applicable
to RTO/ISO submarkets. However,
intervenors may challenge that
presumption. Depending on the nature
of the evidence submitted by an
intervenor, the Commission will
consider whether to institute a separate
section 206 proceeding to investigate
whether the existing RTO/ISO
mitigation continues to be just and
reasonable.
6. While the Commission affirms its
determination to continue the use of
historical data and a ‘‘snapshot in time
approach,’’ the Commission will
consider sensitivity studies, on a caseby-case basis, that present clear and
compelling evidence that certain
changes in a market should be taken
into account as part of the market power
analysis in a particular case.
7. With regard to simultaneous
transmission import limit (SIL) studies,
the Commission clarifies that the use of
simultaneous total transfer capability

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(TTC) in the SIL study must properly
account for all firm transmission
reservations, transmission reliability
margin, and capacity benefit margin.
8. The Commission affirms its
determinations concerning the vertical
market power analysis and clarifies that
sellers are not required to report on
financial transmission rights as part of
the vertical market power analysis.
9. The Commission codifies in the
regulations at 18 CFR 35.36 a definition
of ‘‘affiliate’’ for purposes of Order No.
697 based on the definition adopted in
the Affiliate Transactions Final Rule.3 In
addition, the Commission reiterates in
this order a number of clarifications that
it made in the Affiliate Transactions
Final Rule regarding the term ‘‘captive
customers,’’ the purpose of the
definition, and its focus on ‘‘cost-based
regulation.’’ Among other things, the
Commission notes that if a state
regulatory authority in a retail choice
state does not believe that retail
customers are sufficiently protected and
that our affiliate restrictions should
apply to the local franchised public
utility, it may ask the Commission to
deem its retail customers to be captive
customers for purposes of applying the
affiliate restrictions.
10. The Commission clarifies that the
new affiliate restriction regulations
promulgated in Order No. 697
supersede codes of conduct approved by
the Commission prior to the effective
date of Order No. 697. The Commission
also provides a number of clarifications
concerning employees who are not
subject to the independent functioning
requirement. Further, the Commission
grants rehearing regarding the adoption
of a two-way information sharing
restriction in 18 CFR 35.39(d), finding,
among other things, that a one-way
information sharing restriction
adequately protects captive customers.
11. The Commission for the most part
affirms its determinations concerning
mitigation, including retaining the
Commission’s default mitigation and
declining to impose a generic ‘‘must
offer’’ requirement. The Commission
clarifies that it has not prejudged the
types of specific situations in which it
might impose a ‘‘must offer’’
requirement on a particular seller. In
response to rehearing requests
concerning the Commission’s mitigation
of long-term transactions based on the
result of a failure of a short-term
indicative screen, the Commission is
modifying its policy with respect to
3 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).

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mitigation of long-term transactions
(one year or more in duration). In this
regard, the Commission will allow a
mitigated seller to demonstrate on a
case-by-case basis that it does not have
market power with respect to a specific
long-term contract.
12. Concerning the tariff provision
adopted in the Final Rule for mitigated
sellers that want 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,
after considering comments raised
regarding the difficulty of determining
and documenting whether the power
sold is intended to serve load in the
balancing authority area in which the
seller has market power, the
Commission is revising the tariff
language to eliminate the intent
element.
13. The Commission affirms, among
other things, its determination in Order
No. 697 to create a category of marketbased rate sellers (Category 1 sellers)
that are not required to automatically
submit updated market power analyses,
as well as its decision to adopt a
regional filing process for updated
market power analyses. In response to
concerns raised regarding the potential
for Category 1 sellers to exercise market
power in load pockets or other
transmission-constrained areas, we
explain that we are modifying our
approach. To the extent that a
Commission-identified submarket is
under analysis (relevant submarket), if
the Commission determines based on
analysis of indicative screens filed by
other sellers that there may be potential
market power concerns with respect to
any Category 1 sellers in the relevant
submarket, the Commission will, if
appropriate, require an updated market
power analysis to be filed by such
Category 1 sellers and allow other
parties to comment. In this regard, the
Commission would be exercising its
right to require an updated market
power analysis at any time.
14. The Commission also provides
clarifications regarding other aspects of
the Final Rule, including addressing
questions that have arisen concerning
the implementation process adopted in
Order No. 697 and providing
clarifications concerning the change in
status reporting requirement.
15. Finally, the Commission rejects as
without merit arguments raised by
petitioners challenging the
Commission’s authority to adopt
market-based rates and alleging that the
market-based rate program fails to

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comply with the requirements of the
FPA.
II. Discussion
A. Horizontal Market Power
1. Whether To Retain the Indicative
Screens
Final Rule
16. In Order No. 697, the Commission
adopted, with some modifications, two
indicative market power screens (the
uncommitted market share screen and
the uncommitted pivotal supplier
screen) to determine whether sellers
may have market power and should be
further examined. The Commission
explained that sellers that fail either
screen would rebuttably be presumed to
have market power, but they would
have an opportunity to present evidence
(through the submission of a Delivered
Price Test (DPT) analysis)
demonstrating they do not have market
power. The Commission concluded that,
although some sellers disagree with the
use of two screens or find flaws in them,
the conservative approach of using two
screens together would allow the
Commission to more readily identify
potential market power by measuring
market power at both peak and off-peak
times and both unilaterally and in
coordinated interaction with other
sellers. The Commission explained that
a conservative approach at the
indicative screen stage of the proceeding
is warranted because, if a seller passes
both of the indicative screens, there is
a rebuttable presumption that it does
not possess horizontal market power.4
In conclusion, the approach represented
an appropriate balance between the
need to protect against market power
and the desire not to place unnecessary
filing burdens on utilities.5
17. The wholesale market share
screen measures for each of the four
seasons whether a seller has a dominant
position in the market based on the
number of megawatts of uncommitted
capacity owned or controlled by the
seller as compared to the uncommitted
capacity of the entire relevant market.
When calculating uncommitted
capacity, a seller adds the total
nameplate or seasonal capacity of
generation owned or controlled through
contract plus long-term firm purchases
and deducts operating reserves, native
load commitments, and long-term firm
sales.6
4 Order

No. 697 at P 62.
P 33, 35.
6 Order No. 697 states that uncommitted capacity
is determined by adding the total nameplate
capacity of generation owned or controlled through
contract and firm purchases, less operating reserves,
5 Id.

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18. The pivotal supplier analysis
evaluates the potential of a seller to
exercise market power based on
uncommitted capacity at the time of the
relevant market’s annual peak demand,
focusing on the seller’s ability to
exercise market power unilaterally. It
examines whether the market demand
can be met absent the seller during peak
times; a seller is determined to be
pivotal if demand cannot be met
without some contribution of supply by
the seller or its affiliates. For purposes
of identifying the wholesale market, the
Commission explained that the ‘‘proxy
for the wholesale load is the annual
peak load (needle peak) less the proxy
for native load obligation (i.e., the
average of the daily native load peaks
during the month in which the annual
peak load day occurs).’’ 7
19. The Commission chose not to
adopt suggestions to alter the indicative
screens in order to incorporate a
contestable load analysis, as proposed
by some commenters. Such an analysis
would consider the amount of excess
market supply available to serve the
amount of wholesale demand seeking
supply at a particular moment in time.8
The Commission reasoned that such an
analysis is essentially a variant on the
pivotal supplier screen with differences
in the calculation of wholesale load and
the test thresholds since it addresses
whether suppliers other than the seller
can meet the demand in the relevant
market. The Commission concluded that
incorporating such an analysis would
not improve its ability to establish a
presumption of whether a seller has
market power, and ‘‘without the market
share indicative screen, the Commission
would have insufficient information
because there would be no analysis of
a seller’s size relative to the other sellers
in the market, and no information on
the seller’s market power during offpeak periods.’’ 9 Additionally, the
native load commitments and long-term firm sales.
Order No. 697 at P 38. Order No. 697 further states
that uncommitted capacity from a seller’s remote
generation (generation located in an adjoining
balancing authority area) should be included in the
seller’s total uncommitted capacity amounts. Id.
However, one of the standard screen formats
included at Appendix A to Order No. 697 does not
capture these details. Part I—Pivotal Supplier
Analysis, inadvertently does not include Row H
(imported power) and Row M (average daily Peak
Native Load in Peak month, a proxy for native load
commitment) in calculating Row K (total
uncommitted supply). We thus correct this error in
the Revised Appendix A to include the missing
variables of the equation.
7 Id. P 41.
8 See Id. P 49. Generally, advocates of the
contestable load analysis believe that, if available
non-applicant supply is at least twice the
contestable load, that is sufficient to make a finding
that the market is competitive.
9 Id. P 66.

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
Commission noted that the contestable
load analysis fails to consider the
relative price of the competing supplies
and thus whether the available nonapplicant supply is competitively priced
and, hence, in the market.10
Requests for Rehearing

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20. On rehearing, Southern contends
that the Final Rule violates the
requirement in FPA section 206 that the
Commission bears the burden of proof
in section 206 proceedings and that the
Commission’s determinations be based
on substantial evidence.11 According to
Southern, this shifting of the burden of
proof occurs through the use of
indicative screens that Southern
submits are inherently flawed and
which, if failed, result in a presumption
of market power that must be rebutted
by sellers. Southern states that once a
screen failure occurs and a presumption
of market power arises, a seller only has
two options: either accept a
determination that it has market power
and adopt cost-based rate mitigation
measures, or provide the Commission
with a DPT analysis.12 Southern
concludes that by applying the
indicative screens codified in the Final
Rule, the Commission will effectively
shift to sellers the evidentiary burden in
a section 206 proceeding.13 Southern
argues that the screens are inherently
flawed in their ability to definitively
assess market power when none is
actually present, noting that the Final
Rule acknowledges that the screens are
conservative in nature and may result in
false positives indicating market
power.14 Southern argues that because
of their conservative nature and
propensity to result in false positives,
such screens cannot properly provide a
basis for shifting the burden of proof to
10 Order No. 697 also dealt with the following
issues, about which rehearing has not been sought:
Control and commitment of generation resources;
elimination of former 18 CFR 35.27, which had
exempted newly-constructed generation from the
horizontal market power analysis; reporting format
for the indicative screens; nameplate capacity; and
several procedural issues.
11 Southern Rehearing Request at 7–8 (citing 16
U.S.C. 824e(a); FPC v. Sierra Pacific Power Co., 350
U.S. 348 at 353 (1956) (Sierra); Public Service
Commission of New York v. FERC, 642 F.2d 1335,
1345 (D.C. Cir. 1980); Public Service Co. of New
Mexico, 115 FERC ¶ 61,090, at P 33 (2006)).
12 Id. at 7 (citing Order No. 697 at P 63).
13 Id. at 8.
14 Id. (citing Order No. 697 at P 62, 71, 74, 89).
Further, Southern asserts that only in instances of
high market share should a prima facie case of
market power be established, which would shift the
burden of proof. Id. at 10 & n.10 (citing U.S. v.
Syufy, 903 F.2d 659, 664 (9th Cir. 1990); HuntWesson Foods, Inc. v. Ragu Foods, Inc., 627 F.2d
919, 924 (9th Cir. 1980), cert. denied, 450 U.S. 921
(1981)).

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sellers, and are incapable of providing
substantial evidence of market power.
21. To remedy this, Southern argues
that the Commission should reconsider
its determination in the Final Rule that
a failure of an indicative screen results
in a presumption of market power.
Instead, the Commission should
determine that the indicative screens are
only intended to identify sellers that
appear to raise no horizontal market
power concerns and thus can be
considered for market-based rate
authority without the necessity of
further analysis. In other words, passing
the screens should raise a favorable
presumption that a seller does not have
market power, and a seller would never
be ‘‘presumed’’ to have generation
market power.15
22. Southern further argues that the
Final Rule’s market share screen and its
application of the DPT are arbitrary and
capricious, not supported by substantial
evidence, without a rational basis, and
contrary to established legal
precedent.16 Specifically, Southern
contends that the market share screen
and the DPT improperly fail to account
for the size of the wholesale market
demand that could be served by the
uncommitted capacity in the relevant
region.17 Southern argues that
wholesale market demand should be
considered in the market share screen
and the DPT because market power
concerns only exist if a seller has the
power to raise prices above competitive
levels or exclude competition in the
relevant market for a not insubstantial
amount of time.18 According to
Southern, even the Department of
Justice (DOJ) merger analysis, on which
the Final Rule relies, would take the
wholesale market into account when
determining an entity’s ‘‘market
share.’’ 19 Southern comments that in
the Final Rule the Commission
appeared to give four reasons why it
was unwilling to consider market
15 Id.

at 11.
at 20 (citing 5 U.S.C. 706(2)(A) and (E)
(2000); Union Pac. Fuels, Inc. v. FERC, 129 F.3d
157, 161 (D.C. Cir. 1997) (holding that review of
Commission orders is made under the arbitrary and
capricious standard of the Administrative
Procedure Act); Sithe Independence Power Partners
v. FERC, 165 F.3d 944 (D.C. Cir. 1999) (stating that
the Commission must be able to demonstrate that
it has ‘‘made a reasoned decision based upon
substantial evidence in the record’’ and the ‘‘path
of [its] reasoning’’ must be clear) (quoting Town of
Norwood v. FERC, 962 F.2d 20, 22 (D.C. Cir. 1992)).
17 Id. at 3–4 (citing United States v. Grinnell
Corp., 384 U.S. 563, 571 (1966); MetroNet Services
Corp. v. U.S. West Communications, 329 F.3d 986
(9th Cir. 2003); United States v. Dentsply
International, Inc., 399 F.3d 181, 187 (3rd Cir.
2005)).
18 Id. at 12–13.
19 Id. at 13.
16 Id.

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demand (i.e., contestable load), and
contends that these reasons provide an
insufficient basis for rejecting a
contestable load analysis.20 Southern
believes that the weight of the evidence
clearly demonstrates that to be
legitimate indicators of market power,
the market share screen and DPT should
take the relevant wholesale demand into
account.
Commission Determination
23. We disagree with Southern’s
contention that the Final Rule violates
the requirement in the FPA that the
Commission bears the burden of proof
in section 206 proceedings. We also
disagree with Southern’s view that
failure of the indicative screen(s) does
not provide a sufficient basis to
establish a rebuttable presumption of
market power.
24. As a general matter, we agree that
the burden of proof in a section 206
proceeding is on the Commission where
the Commission institutes the
proceeding on its own motion.
However, we find Southern’s argument
that the burden of proof in a section 206
proceeding is unlawfully shifted to
entities that fail one of the indicative
screens to be without merit. As an
initial matter, the burden of going
forward is on the Commission in the
first instance, and ultimately, when the
Commission institutes a proceeding
under section 206 of the FPA. In the
Final Rule, the Commission has
established through rulemaking a
generic test to support its burden of
going forward: A seller’s failure of one
of the indicative screens establishes a
rebuttable presumption of market
power. The burden of going forward
then shifts to the seller once such a
proceeding is initiated to rebut the
presumption of market power. Once the
seller submits additional evidence to
rebut the presumption of market power,
the Commission must determine, based
on substantial evidence in the record,
whether the seller has market power.
Thus, the ultimate burden of proof
under FPA section 206 remains with the
Commission.21 On this basis, the
20 Id. at 15 and Frame affidavit at ¶ 25, referring
to Order No. 697 at P 66–67.
21 See AEP Power Marketing, Inc., 108 FERC
¶ 61,026, at P 30 (2004) (July 8 Order) (‘‘Failure of
a screen establishes a rebuttable presumption of
market power, which satisfies the Commission’s
initial burden of going forward in such proceedings.
The burden of going forward will then be upon the
applicant once such a proceeding is initiated.’’); see
Id. P 29 (stating that passing both screens or failing
one merely establishes a rebuttable presumption,
and explaining that in the case of an intervenor in
a section 205 proceeding that seeks to prove that the
applicant possesses market power, ‘‘the intervenor
need only meet a ‘burden of going forward’ with

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Commission is not unlawfully shifting
the burden of proof to the seller that
fails one of the screens.
25. Moreover, in Order No. 697, the
Commission addressed an argument by
Southern that failure of the screens does
not provide a sufficient basis to
establish a rebuttable presumption of
market power, and Southern has failed
on rehearing to convince us that a seller
should never be presumed to have
generation market power. In particular,
the Commission explained that the
indicative screens are intended to
identify the sellers that raise no
horizontal market power concerns and
can otherwise be considered for marketbased rate authority. Sellers failing one
or both of the indicative screens, on the
other hand, are identified as sellers that
potentially possess horizontal market
power and for which a more robust
analysis is required. The Commission
explained that the uncommitted pivotal
supplier screen focuses on the ability to
exercise market power unilaterally.
Failure of this screen indicates that
some or all of the seller’s generation
must run to meet peak load. The
uncommitted market share analysis
indicates whether a supplier has a
dominant position in the market.
Failure of the uncommitted market
share screen may indicate that the seller
has unilateral market power and may
also indicate the presence of the ability
to facilitate coordinated interaction with
other sellers. It is on this basis that the
Commission finds that a rebuttable
presumption of market power is
warranted when a seller fails one or
both of the indicative screens. The
screens themselves represent the first
piece of evidence that the potential for
market power exists since failure of one
or both of the screens indicates that the
seller may be a pivotal supplier in the
evidence that rebuts the results of the screens. At
that point, the burden of going forward would
revert back to the applicant to prove that it lacks
market power.’’) (citing Pennzoil Co. v. FERC, 645
F.2d 360, 392 (5th Cir. 1981), cert. denied, 454 U.S.
1142 (1982); accord Transcontinental Gas Pipe Line
Corp., Opinion No. 135, 17 FERC ¶ 61,232, at
61,450 (1981) (‘‘The presumption * * * is the same
as that which arises from a prima facie case: It
imposes on the party against whom it is directed
the burden of going forward with substantial
evidence to rebut or meet the presumption, but does
not shift the burden of persuasion.’’); Generic
Determination of Rate of Return on Common Equity
for Electric Utilities, Order No. 389–A, 29 FERC
¶ 61,223, at 61,458 (1984) (concluding that
rebuttable presumption that a rate of return based
on a benchmark is just and reasonable does not shift
ultimate burden of proof imposed by Federal Power
Act)); see also Southern Companies Energy
Marketing, Inc., 111 FERC ¶ 61,144, at P 24 (2005)
(stating that a ‘‘screen failure satisfies the
Commission’s burden of going forward and shifts to
the applicant the burden of presenting evidence
rebutting the presumption of market power’’), order
dismissing reh’g as moot, 119 FERC ¶ 61,300 (2007).

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market or has a high enough market
share of uncommitted capacity to raise
horizontal market power concerns.22 In
addition, we note that although we find
that failure of an indicative screen is a
sufficient basis to establish a
presumption of market power, the
Commission allows such a seller to
continue to sell under market-based rate
authority until a definitive finding is
made, albeit with rates subject to refund
to protect customers.
26. We disagree with Southern’s
argument that the indicative screens
have a propensity to result in false
positive indications of market power, do
not provide substantial evidence of
market power and, therefore, cannot
provide a basis for shifting the
evidentiary burden to sellers. As we
explained in Order No. 697, the
indicative screens are intended to
screen out those sellers that raise no
horizontal market power concerns and
can otherwise be considered for marketbased rate authority from those sellers
that raise concerns but may not
necessarily possess horizontal market
power.23 While we recognize that the
conservative nature of the screens may
result in some false positives, a
conservative approach at the indicative
screen stage is warranted because if a
seller passes both of the indicative
screens, there is a rebuttable
presumption that it does not possess
horizontal market power. Thus, we must
weigh the risk of false positives and any
resulting repercussions on a seller (e.g.,
section 206 proceeding, rate subject to
refund, temporary regulatory
uncertainty) against the costs of
adopting a less conservative screen or
eliminating the market share indicative
screen.24 In particular, if the screens
result in a false positive indication of
market power, the seller has the
opportunity to rebut the presumption of
market power while it continues to have
market-based rate authority. However, if
we were to adopt a less conservative
screen, that could result in a false
negative, i.e., a false indication of no
market power and customers would not
be adequately protected. Accordingly, if
the Commission were to adopt
Southern’s approach we are concerned
that false negatives would become a
reality and the Commission would not
be able to fulfill its FPA section 205 and
206 mandate to ensure just, reasonable
and not unduly discriminatory rates. On
this basis, we believe that evidence of
an indicative screen failure is sufficient
to establish a rebuttable presumption of

market power, in which case the seller
will then have the opportunity to rebut
that presumption of market power.
27. Additionally, in response to
Southern’s concerns regarding the
conservative nature of the indicative
screens, Order No. 697 changed the
native load proxy under the market
share indicative screen from the
minimum native load peak demand for
the season to the average of the daily
native load peak demands for the
season, making the native load proxy for
the market share indicative screen
consistent with the native load proxy
under the pivotal supplier screen.25 A
native load proxy based on the average
of peak load conditions is more
representative, and thus more accurate,
than a proxy based on minimum peak
load conditions. Basing the native load
proxy on the average of the peaks will
make the screens more accurate in
eliminating sellers without market
power while focusing on ones that may
have market power.26 Thus, the updated
native load proxy will reduce the
likelihood that false positive indications
of market power will occur.
28. Accordingly, we affirm our
determination in the Final Rule that a
failure of an indicative screen results in
a presumption of market power, and
reject Southern’s proposal that a seller
never be ‘‘presumed’’ to have horizontal
market power as a result of an indicative
screen failure.27
29. The Commission also disagrees
with Southern’s assertion that the
market share screen and the DPT
analysis do not account for the size of
wholesale market demand, and are
therefore arbitrary and capricious.28
While Southern may disagree with our
approach to considering wholesale
market demand, both the market share
screen and the DPT consider wholesale
market demand by considering
uncommitted capacity. Uncommitted
capacity considers wholesale market
demand by reducing the seller’s
available capacity by the amount of
capacity committed to serve demand. In
addition, in both the initial screen and
the DPT, the Commission requires a
pivotal supplier analysis, which looks at
whether there is sufficient competing
supply to serve wholesale demand.
30. In addition, we disagree with
Southern that our choice of how to
account for the wholesale market
demand has resulted in the market share
screen and the DPT being arbitrary and
25 Id.

P 135.
P 137.
27 Southern Rehearing Request at 11.
28 We further address Southern’s arguments with
regard to the DPT analysis below.
26 Id.

22 See

Order No. 697 at P 65.
P 62.
24 Id. P 71.
23 Id.

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capricious. The development of the
market share screen and the DPT
resulted from lengthy public
proceedings at which varying
perspectives and arguments were taken
into account. Over the years, and in
light of the Commission’s FPA
responsibilities, the Commission has
carefully considered various points of
view in an open transparent dialogue
with the electric industry and has based
its determinations on sound regulatory
principles. In particular, the market
share screen provides a straightforward
economically sound and accepted
method to identify those sellers that
have the potential to exercise market
power.29 The uncommitted pivotal
supplier screen measures the ability of
the firm to dominate the market at peak
periods. Further, the market share
screen indicates whether a supplier may
have a dominant position in the market
and measures the ability of a seller to
affect coordinated interaction with other
sellers that could be accomplished
during both peak and off-peak times.
The market share screen is useful in
measuring market power because it
measures a seller’s size relative to others
in the market, specifically, the seller’s
share of generating capacity that is
uncommitted after accounting for its
obligations to serve native load. It also
provides a snapshot of these market
shares in each season of the year.30
Thus, the indicative screens measure a
seller’s market power at both peak and
off-peak times and therefore indirectly
measure market power potential during
periods of both relatively high and low
demand.31 With regard to Southern’s
argument that in the Final Rule the
Commission appeared to give four
reasons why it was unwilling to
consider market demand (i.e.,
contestable load), and Southern’s
contention that these reasons provide an
insufficient basis for rejecting a
contestable load analysis, we reaffirm
our determination that the contestable
load analysis is flawed and essentially
a variant on the pivotal supplier
29 See In the Matter of Merger Policy Under the
Federal Power Act, May 7, 1996, Comments of the
U.S. Department of Justice, Docket No. RM96–6–
000 (providing comments on the Commission’s
standards for determining whether a proposed
merger is in the public interest, recommending that
the Commission apply a market share screen to
identify quickly those mergers that are unlikely to
raise competitive issues and concluding that the
Horizontal Merger Guidelines provide ‘‘sound
competitive analysis’’); see also U.S. Department of
Justice and the Federal Trade Commission,
Horizontal Merger Guidelines, section 2.0, reprinted
at 4 Trade Reg. Rep. (CCH) ¶ 13,104 (Issued April
2, 1992, Revised April 8, 1998).
30 Order No. 697 at P 65.
31 Id.

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screen.32 Like the pivotal supplier
screen, the contestable load analysis
addresses whether suppliers other than
the seller can meet the demand in the
relevant market. Thus, incorporating
such an analysis would not improve our
ability to establish a presumption of
whether a seller possesses market power
and would add little useful
information.33
2. Indicative Market Share Screen
Threshold Levels
Final Rule
31. Order No. 697 retained the 20
percent threshold for the wholesale
market share screen (i.e., with a market
share of less than 20 percent, the seller
passes the screen). The Commission
reasoned that a relatively conservative
threshold for passing the market share
screen was appropriate, explaining that
the screens are indicative of market
power, not definitive. Responding to
arguments that the Commission should
use a 35 percent threshold as a
presumption of market power because
the U.S. Department of Justice (DOJ)
merger guidelines state that only firms
with 35 percent of more market share
have market power, the Commission
explained:
In a market comprised of five equal-sized
firms with 20 percent market shares, the HHI
is 2,000, which is above the DOJ/FTC HHI
threshold of 1,800 for a highly concentrated
market, and in markets for commodities with
low demand price-responsiveness like
electricity, market power is more likely to be
present at lower market shares than in
markets with high demand elasticity.34

32. The Commission continued that,
when arguing that a 20 percent
threshold for the market share screen is
too low, commenters ignored that the
indicative screens are based on
uncommitted capacity, not total
capacity; as a result, a substantial
amount of seller capacity may not be
counted in measures of market share.
The Commission, therefore, concluded
that the 20 percent threshold strikes the
right balance in seeking to avoid both
false negative and false positive
results.35
Requests for Rehearing
33. Southern asserts that the Final
Rule arbitrarily utilizes a 20 percent
market share threshold to establish a
presumption of market power.36
32 Id.

P 66.

33 Id.
34 Id.

P 89.
P 91.
36 Southern Rehearing Request at 4 (citing DOJ
1984 Merger Guidelines, Section 2.4; Edison
Mission Energy, Inc. v. FERC, 394 F.3d 964, 968
35 Id.

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25837

Further, Southern argues that the 20
percent threshold is contrary to legal
precedent holding that a higher market
share is required to warrant market
power concerns.37
34. Southern argues that, contrary to
the Commission’s assertions, the 1984
Merger Guidelines do not support the 20
percent figure used in the market share
screen. First, it states that while the
particular sentence cited by the
Commission from section 4.134 of the
1984 guidelines does actually contain
the words ‘‘market share of 20 percent,’’
it does not support the application of a
20 percent threshold under the market
share screen when considered in proper
context, since other portions of the 1984
Merger Guidelines indicate that the
DOJ’s definition of ‘‘market share’’ in
the context of merger evaluation is
different from the Commission’s
definition of ‘‘market share’’ under its
market share screen.38 Second,
Southern argues that according to the
very sentence cited in the Final Rule
from the 1984 Merger Guidelines, the 20
percent ‘‘market share’’ threshold refers
only to the market share of the acquired
firm in the overall context of a proposed
merger of multiple firms. It does not
refer to the market share of the merged
firm post-acquisition, nor does it even
refer to the market share of the acquiring
firm. Third, Southern argues that the
Commission’s reliance on the 20 percent
threshold in section 4.134 of DOJ’s 1984
Merger Guidelines is misplaced because
that provision is outdated—it is not
included in DOJ’s current horizontal
merger guidelines. In this regard, the
1984 Merger Guidelines were used to
evaluate both vertical and horizontal
mergers. The newer versions of DOJ’s
horizontal merger guidelines
subsequently adopted in 1992 and 1997
do not carry forward section 4.134’s 20
percent market share threshold. Thus,
the market share of a single firm does
not automatically translate into a high
HHI as the Commission suggests.39
35. Southern also argues on rehearing
that section 2 of the Sherman Antitrust
Act, which prohibits not only actual
(D.C. Cir. 2005) (stating that the Commission must
‘‘articulate a satisfactory explanation for its action
including a ‘rational connection between the facts
found and the choice made.’ ’’) (quoting Motor
Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins.
Co., 463 U.S. 29, 43 (1983)).
37 Id.
38 The Final Rule cited section 4.134, stating
‘‘[t]he 20 percent threshold is consistent with
§ 4.134 of the U.S. Department of Justice 1984
Merger Guidelines issued June 14, 1984, reprinted
in Trade Reg. Rep. P 13,103 (CCH 1988): ‘The
Department [of Justice] is likely to challenge any
merger satisfying the other conditions in which the
acquired firm has a market share of 20 percent or
more.’ ’’ Order No. 697 at n.21.
39 Id. at 16–19.

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monopolization but also attempted
monopolization and conspiracy to
monopolize, has spawned a wellestablished body of law to address the
type of market concerns that the
Commission attempts to address in the
Final Rule. Southern contends that the
Commission’s 20 percent threshold falls
short when measured against the
jurisprudence interpreting section 2 of
the Sherman Act and that a more
relevant threshold in a non-merger
context would arguably be closer to 90
percent than 20 percent.40 Whether the
Commission’s concern arises out of the
unilateral ability of a utility to exert
market power or the ability of two or
more utilities to act concertedly in a
way that restrains trade, Southern
argues that jurisprudence interpreting
the Sherman Act more appropriately
addresses those concerns than does
merger analysis. Aside from the
authorities supporting a rule of law that
less than at least a 50 percent market
share should be insufficient to suggest
market power, Southern argues that
many cases and commentators may be
cited for the proposition that the
Commission’s 20 percent threshold is
misguided and lacks a rational basis;
relatively low market shares should, as
a matter of law, preclude findings of
market power.41 Southern adds that the
courts have not only consistently held
that market shares in the 20 percent
range are insufficient to support a
finding of actual monopoly power under
section 2 of the Sherman Act, but also
have found little difficulty in
determining that such market share is
not enough to sustain even a claim of
attempted monopolization under
section 2.42
36. NASUCA argues on rehearing that
in calculating market share when
screening for horizontal market power,
the Commission should not subtract
capacity needed for long-term contracts
as ‘‘committed’’ if the contracts are
indexed or linked to spot market prices.
40 Id. at 20 (citing Hiland Dairy v. Kroger, 402
F.2d 968, 976 (8th Cir. 1968) (rejecting 60 or 33
percent market share); Robinson v. Magovern, 521
F. Supp. 842, 887 (W.D. Pa. 1981)).
41 Id. at 22–23 (citing Cargill, Inc. v. Monfort of
Colorado, Inc., 479 U.S. 104, 119 n.15 (1986)
(noting that 20.4 percent market share is probably
insufficient to sustain predatory pricing, and citing
authorities indicating that 60 percent or more
would be necessary); Bailey v. Allgas, Inc., 284 F.3d
1237, 1250 (11th Cir. 2002); Yoder Bros., Inc. v.
California-Florida Plant Corp., 537 F.2d 1347, 1368
(5th Cir. 1976) (stating that a 20 percent market
share was insufficient as a matter of law to prove
market power)).
42 Id. at 24 (citing H.L. Hayden Co. of New York,
Inc., v. Siemens Medical Systems, Inc., 879 F.2d
1005, 1017 (2nd Cir. 1989); Nifty Foods Corp. v.
Great Atl. & Pac. Tea Co., 614 F.2d 832, 841 (2nd
Cir. 1980) (one-third market share not enough); U.S.
v. ALCOA, 148 F.2d 416, 424 (2nd Cir. 1945).

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NASUCA asserts that a seller with a
market share of capacity greater than 20
percent can reduce it, and pass a market
power screen it would otherwise fail, by
‘‘committing’’ portions of its capacity.
NASUCA states that it requested in its
NOPR comments that the Commission
clarify that it will not consider capacity
dedicated to meeting long-term contract
sales of energy to be ‘‘committed’’—and
thus disregarded from market share—if
the price of energy in the long-term
contracts is indexed or linked to spot
market prices. NASUCA contends that it
identified relevant research in support
of its request in citing a model that
withdraws the capacity committed
under the long-term contracts from the
short-run market.43 NASUCA states that
the Commission overlooked NASUCA’s
request, and therefore requests that the
Commission grant its requested
clarification because research indicates
that long-term contracts linked to spot
market prices do not reduce, and may
exacerbate, the ability of a seller to raise
spot market prices above competitive
levels.44 In the alternative, NASUCA
seeks further proceedings to examine
the exercise of market power by sellers
who pass market screens due to their
contractual commitment to make longterm energy sales at rates indexed to
spot market prices.
Commission Determination
37. We affirm our determination to
retain the 20 percent threshold for the
indicative wholesale market share
screen. Use of the 20 percent market
share threshold is appropriate since the
screen is indicative, not dispositive.
Southern’s arguments suggest that the
20 percent is dispositive, but it is not.
If a seller fails the indicative screens, it
can submit a full DPT analysis in which
a range of factors are considered,
including market shares, HHIs (market
concentration) and other factors
affecting the relevant markets. A 20
percent market share is not even
considered dispositive at that stage;
rather, we have approved market-based
rates in several cases where a supplier
had a market share exceeding 20
percent.45 In addition, we note that the
cases cited by Southern, where much
43 NASUCA Rehearing Request at 8 (citing Chloe
Lo Coq. Index Contracts and Spot Market
Competition, University of California Energy
Institute, Center for the Study of Energy Markets,
June 2006, p. 15, available at http://www.ucei.
berkeley.edu/ThirdTierButtons/PDFButton_Off.jpg).
44 Id. (citing Order No. 697 at P 82–93).
45 PPL Montana, LLC, 115 FERC ¶ 61,204, at P 41
(2006), order denying reh’g, 120 FERC ¶ 61,096
(2007); Kansas City Power and Light Co., 113 FERC
¶ 61,074, at P 26, 30 (2005); PacifiCorp, 115 FERC
¶ 61,349, at P 29, 32 (2006); Tampa Electric Co., 117
FERC ¶ 61,311, at P 26–27 (2006).

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higher market shares were allowed,
involve markets other than electricity.46
Electricity markets possess unique
characteristics including, but not
limited to, inelastic demand and the
need to balance the entire transmission
grid in real-time. Economic theory and
empirical estimates of the short-run
elasticities of electricity demand suggest
that these unique conditions allow
sellers in wholesale electricity markets
to exercise market power using a much
more limited withholding of supply
than industries listed in the cases cited
by Southern.47 Thus, the use of a
conservative threshold such as a 20
percent market share is warranted,
particularly for an indicative screen.
38. Southern asserts that the Final
Rule’s reliance on the 1984 Merger
Guidelines for use of the ‘‘20 percent
market share’’ is incorrect. Section 4.134
of the 1984 Merger Guidelines states:
Entry through the acquisition of a
relatively small firm in the market may have
a competitive effect comparable to new entry.
Small firms frequently play peripheral roles
in collusive interactions, and the particular
advantages of the acquiring firm may convert
a fringe firm into a significant factor in the
market. The Department is unlikely to
challenge a potential competition merger
when the acquired firm has a market share
of five percent or less. Other things being
equal, the Department is increasingly likely
to challenge a merger as the market share of
the acquired firm increases above the
threshold. The Department is likely to
challenge any merger satisfying the other
conditions in which the acquired firm has a
market share of 20 percent of [sic] more.48
46 Hiland Dairy v. Kroger, 402 F.2d 968 (8th Cir.
1968) (concerning a claim of monopolization in the
milk and dairy business); Robinson v. Magovern,
521 F. Supp. 842 (W.D. Pa. 1981) (addressing an
antitrust action against a hospital); Cargill, Inc. v.
Monfort of Colorado, Inc., 479 U.S. 104 (1986)
(concerning a merger in the beef packing industry);
Bailey v. Allgas, Inc., 284 F.3d 1237 (11th Cir. 2002)
(addressing an antitrust action arising from a price
war between liquid propane gas competitors);
Yoder Bros., Inc. v. California-Florida Plant Corp.,
537 F.2d 1347 (5th Cir. 1976) (addressing antitrust
claims arising from infringement of plant patents);
H.L. Hayden Co. of New York, Inc., v. Siemens
Medical Systems, Inc., 879 F.2d 1005 (2nd Cir.
1989) (addressing antitrust claims relating to
distribution of dental x-ray equipment); Nifty Foods
Corp. v. Great Atl. & Pac. Tea Co., 614 F.2d 832
(2nd Cir. 1980) (concerning an antitrust suit arising
from the substitution of a supplier of frozen
waffles); U.S. v. ALCOA, 148 F.2d 416 (2nd Cir.
1945) (concerning claims of monopolization of
interstate and foreign commerce in the manufacture
and sale of aluminum).
47 Energy Information Administration,
‘‘Assumptions to the Annual Energy Outlook 2006,’’
Report #: DOE/EIA–0554 (2006); James A. Espey &
Molly Espey, ‘‘Turning on the Lights: A Metaanalysis of Residential Electricity Demand
Elasticities,’’ Journal of Agricultural and Applied
Economics, 36:1, at 65–81 (April 2004).
48 U.S. Department of Justice Non-Horizontal
Merger Guidelines sec. 4.134, originally issued June
14, 1984, as part of the U.S. Department of Justice

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39. Upon further review, the context
discussed in this quote differs from the
issue before us, and provides little
guidance here. In the market-based rate
context, we focus on whether the
applicant has a 20 percent market share
as a conservative measure because of the
electricity market’s characteristics
including inelastic demand and the
need to balance the entire transmission
grid in real-time.49 However, the NonHorizontal Merger Guidelines provide
that a firm with a 20 percent share is
unlikely to be a ‘‘fringe’’ firm and an
insignificant factor in the market. This
is the same reason that we use the 20
percent threshold in our indicative
screen: Firms with a 20 percent market
share would be unlikely to hold a
dominant position in the market.50
40. We also reject Southern’s
argument that the Commission’s 20
percent threshold falls short when
measured against the jurisprudence
interpreting section 2 of the Sherman
Act.51 Economic theory suggests that it
may be possible, given the unique
conditions in electricity markets, for
sellers to exercise market power, using
a much more limited withholding of
supply, than industries listed in the
cases relied upon by Southern.52
Moreover, in contrast to the cases cited,
the Commission uses 20 percent as an
indicative screen, not as a dispositive
factor in determining whether market
power exists. We have, as indicated,
approved market-based rates for firms
with market shares in excess of 20
percent.
41. We reject NASUCA’s request that
the Commission require sellers to treat
capacity that is committed to long-term
contracts that are indexed or linked to
spot market prices as uncommitted
capacity in calculating market share
when screening for horizontal market
power. As support, NASUCA cites a
model that withdraws the capacity
committed under the long-term
contracts from the short-run market, and
then concludes that the now reduced
capacity traded in the spot market
lowers the incentives for rival firms to
deviate from any collusive behavior by
reducing the number of firms in the
market and their available capacity.53
Merger Guidelines, reprinted in Trade Reg. Rep.
¶ 13,103 (CCH 1988) (footnote omitted).
49 A seller who has less than a 20 percent market
share in a season will be considered to satisfy the
market share analysis. AEP Power Marketing, Inc.,
107 FERC ¶ 61,018, at P 102 (April 14 Order), order
on reh’g, 108 FERC ¶ 61,026 (2004) (July 8 Order).
50 See Id. P 104.
51 Southern Rehearing Request at 22–23.
52 See supra n.46.
53 ‘‘If collective action is necessary for the
exercise of market power, as the number of firms

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Therefore, the model cited by NASUCA
subtracts capacity committed under
long-term contracts from the capacity
available in the short-run market, just as
we do in our analysis. Similarly, the
Commission believes that once capacity
is committed long-term, regardless of
how that capacity is priced (e.g.,
whether linked to spot prices or not),
the ability of the firm to use that
capacity to exercise market power in the
spot market is severely limited or nonexistent. The ability to collude will be
determined by the remaining
uncommitted capacity in the spot
market, not the capacity that is already
committed under long-term contracts.
Therefore, we conclude that it is
appropriate to subtract capacity
committed under long-term contracts
when calculating a seller’s uncommitted
capacity for purposes of performing the
indicative screens.
3. DPT Criteria
Final Rule
42. In Order No. 697, the Commission
announced that it would continue to use
the DPT to make a definitive
determination of whether a seller has
market power and that it would
continue to weigh both available
economic capacity and economic
capacity when analyzing market shares
and Hirschman-Herfindahl Indices
(HHI).54 The Commission chose to
retain the HHI threshold of 2,500 for
passing the DPT, and to retain the 20
percent market share threshold.
Responding to arguments that if a 2,500
HHI threshold is retained, it should be
used with a 15 percent market share
because these are the criteria of the oil
pipeline test from which the 2,500 HHI
was derived, the Commission noted that
it ‘‘had not seen cases where the HHI
was over 2,500 and the seller’s market
share was between 15 and 20 percent,
which would be the type of situation
about which [commenters] are
concerned.’’ 55
Requests for Rehearing
43. Montana Counsel argues that the
Commission should clarify that capacity
committed to a competitor’s native load
or otherwise unavailable on a firm basis
should not be considered available to
necessary to control a given percentage of total
supply decreases, the difficulties and costs of
reaching and enforcing an understanding with
respect to the control of that supply might be
reduced.’’ U.S. Department of Justice and the
Federal Trade Commission, Horizontal Merger
Guidelines, section 2.0, reprinted at 4 Trade Reg.
Rep. (CCH) ¶ 13,104 (Issued April 2, 1992, Revised
April 8, 1998).
54 Order No. 697 at P 13, 104, 106.
55 Id. P 113.

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25839

compete with the applicant’s
generation, and as such should not be
included as available capacity in the
DPT analysis. Montana Counsel states
that in its order on PPL Montana’s
request for renewal of market-based rate
authority, the Commission stated that it
was ‘‘not inconsistent with how DPTs
have historically been conducted’’ for
PPL Montana to include as available
competing generation capacity that was
committed elsewhere.56 Montana
Counsel contends that this is
inappropriate insofar as generation
committed to serve another utility’s
native load cannot be available to
compete with the applicant’s generation
on a firm basis. Montana Counsel states
that while it appears that Order No. 697
remedies this mistake in stating that
total supply is determined by adding the
total amount of uncommitted capacity
located in the relevant market
(including capacity owned by the seller
and competing suppliers) with that of
uncommitted supplies that can be
imported (limited by simultaneous
transmission import capability) into the
relevant market from the first-tier
markets, the Commission does not
explicitly change the Commission’s
prior policy.57 Accordingly, Montana
Counsel requests clarification that the
Commission will not allow applicants to
count as available economic capacity
generation that is in fact committed; if
necessary and in the alternative,
Montana Counsel requests rehearing of
this issue.
44. TDU Systems argue on rehearing
that the Final Rule fails to explain how
the adoption of a 2,500 HHI threshold
is rationally related to the Commission’s
objective of precluding market-based
rates in highly concentrated markets.58
They assert that the Commission should
lower the HHI threshold to 1,800 as the
appropriate threshold for treating a
market as highly concentrated, and that
the Commission’s refusal to do so in the
Final Rule was arbitrary and capricious.
TDU Systems state that, since the
Commission set out in the Final Rule
‘‘to provide ‘a rigorous up-front analysis
of whether market-based rates should be
56 Montana Counsel Rehearing Request at 9 (citing
PPL Montana, LLC, 115 FERC ¶ 61,204, at P 49
(2006)).
57 Id. at 10 (citing Order No. 697 at P 37–38).
58 TDU Systems state that ‘‘The Final Rule fails
to explain how the adoption of an 1,800 HerfindahlHirschman Index (‘HHI’) threshold is rationally
related to its objective of precluding market-based
rates in highly concentrated markets. TDU Systems
Rehearing Request at 2 (citing Motor Vehicle Mfrs.
Ass’n v. State Farm Mut. Auto Ins. Co., 463 U.S. 29,
42–43 (1983); Pac. Gas & Elec. Co. v. FERC, 373
F.3d 1315, 1319 (D.C. Cir. 2004)). However, the
Final Rule retained 2,500 as the appropriate
threshold for passing the HHI component of the
DPT.

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granted,’ it is somewhat puzzling as to
why the Commission believes that the
case for any change in the status quo
must be ‘compelling.’ ’’ 59
45. TDU Systems note that 1,800 is
the level which the Commission uses in
its merger regulations and contends that
the Commission placed too much
reliance on the 1994 DOJ
recommendations 60 as to market rates
in the very different oil pipeline market
for arriving at the 2,500 HHI threshold.
TDU Systems state that electric utilities
do not face the same competition from
other modes of transportation and
demand elasticity as do oil pipelines.
They state that these factors support
their argument for a lower HHI.61 If the
Commission does not adopt the 1,800
level consistent with effective
competition, TDU Systems contend that
it should reduce the market-share
threshold to 15 percent.62
46. TDU Systems argue that they
made a strong case for reducing the
triggering HHI level to 1,800 in their
NOPR comments, and that the
Commission appears not to have
considered it carefully. They assert that
if a market is regarded as ‘‘highly
concentrated,’’ the DOJ guidelines
indicate that even modest increases in
concentration will likely raise
significant competitive concerns. They
contend that, in such a market, other
agencies presume that an HHI increase
of 100 or more is likely to create or
enhance market power. They conclude
that, regardless of what the Commission
ordered in the April 14 Order, there is
no good reason at this time to regard a
market with a 2,000 HHI as not highly
concentrated.63
47. Southern argues that for the same
reasons that the market share screen
should take into account the overall size
of the wholesale market and include a
contestable load analysis, the DPT
should take into account the overall size
of the wholesale market, or should be
replaced by a contestable load
analysis.64
Commission Determination
48. In response to the Montana
Counsel’s request, we clarify that
capacity committed to a competitor’s
native load or otherwise unavailable on
a long-term firm basis, will not be
59 Id.

at 12–13 (citing Order No. 697 at P 2).
14 Order, 107 FERC ¶ 61,018, at P 110 &
n.96 (citing Comments of the U.S. Dept. of Justice,
Docket No. RM94–1–000 (Jan. 18, 1994)).
61 TDU Systems Rehearing Request at 14.
62 Id. at 6–7 (citing DOJ Comments, Docket No.
RM94–1–000 (Jan. 18, 1994), at 13).
63 Id. at 13.
64 Southern Rehearing Request at 3–4, 11–16 and
Frame Affidavit at ¶ 5, 21–22.

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considered available to compete with
the seller’s generation, and as such will
not be included as available economic
capacity in the DPT analysis. We also
note that Montana Counsel
misrepresents our findings in the PPL
Montana proceeding. In that proceeding,
it was not argued that the capacity in
question was committed elsewhere.
Rather, the Commission addressed the
argument that capacity ‘‘may’’ be
committed. PPL Companies rebutted
that argument by explaining that the
buyers at issue did not have long-term
firm transmission available to export the
energy in question from the
NorthWestern control area, and that
because the buyers could elect to leave
this capacity in the NorthWestern
control area, the capacity in question
should not be excluded from the
available economic capacity in the
NorthWestern control area. The
Commission noted that PPL Companies’
treatment of this capacity is not
inconsistent with how DPTs have
historically been conducted.
49. The Commission rejects TDU
Systems’ proposal to reduce the HHI
threshold level to 1,800. The
Commission will continue to use a
2,500 HHI and a 20 percent market
share as the thresholds for the DPT
analysis. The Commission believes that
the market share/HHI thresholds of 20
percent and 2,500, respectively, enable
the Commission to identify dominant
firms in highly concentrated markets,
rather than firms with market shares
above 20 percent that operate in less
concentrated markets (e.g., HHIs less
than 2,500), resulting in fewer false
positives.65 Further, the Commission
will continue to examine each DPT
analysis on a case-by-case basis,
weighing other factors, besides market
share and HHIs, such as historical sales
and transmission data.66 Thus, we will
retain 2,500 as the appropriate threshold
for passing the HHI component of the
DPT.67 Notwithstanding TDU Systems’
argument that the Final Rule fails to
explain how the adoption of a 2,500
HHI threshold is rationally related to the
Commission’s objective of precluding
market-based rates in highly
concentrated markets, the Commission
has explained why 2,500 is the
appropriate threshold, and we reject
TDU Systems’ contention that the
Commission did not carefully consider
arguments for reducing the threshold to
65 As explained in Order No. 697 at P 100,
lowering the HHI threshold to 1,800 will cause
more false positives and direct capital away from
the generation sector.
66 Order No. 697 at P 96.
67 Id. P 113; April 14 Order, 107 FERC ¶ 61,018,
at P 111.

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1,800. At less than 2,500 HHI in the
relevant market for all season/load
conditions, there is little likelihood of
coordinated interaction among suppliers
in a market.68 TDU Systems argue that
the DOJ Merger Guidelines use an 1,800
HHI, but fail to note that the focus of the
Guidelines is on increases in market
concentration produced by a merger.
For example, an existing market could
have an HHI of 2,400 and the DOJ
would take no action if the acquired
firm was very small. It is therefore not
the 1,800 HHI figure, standing alone,
that merits scrutiny by the DOJ, but
rather the relative increase in
concentration that could cause the DOJ
to investigate further. We therefore do
not believe that our approach conflicts
in any way with the DOJ merger
guidelines. We also reaffirm our
determination not to adopt TDU
Systems’ suggestion to lower the market
share threshold to 15 percent from 20
percent. As we explained, we believe
that the 20 percent threshold strikes the
right balance in seeking to avoid both
false negatives and false positives.69
50. With regard to Southern’s
argument that the DPT should take into
account the overall size of the wholesale
market or be replaced by a contestable
load analysis, the Commission reaffirms
its determination that the contestable
load analysis is essentially a variant on
the pivotal supplier screen, and
therefore redundant. As a variant of the
pivotal supplier screen, the contestable
load analysis has differences in the
calculation of wholesale load and the
test thresholds. Like the pivotal supplier
screen, it addresses whether suppliers
other than the seller can meet the
demand in the relevant market.
Incorporating such an analysis would
not improve our ability to establish a
presumption of whether a seller
possesses market power and would add
little useful information.70 In addition,
because the indicative screens measure
a seller’s market power at both peak and
off-peak times, they therefore measure
market power potential during periods
of both high and low demand, and this
concern need not be addressed in the
DPT.71
51. We also reject Southern’s
argument that the DPT should be
replaced by the contestable load
analysis. First, unlike the DPT, the
contestable load analysis fails to
consider relative prices of competing
68 April

14 Order, 107 FERC ¶ 61,018 at P 111.
No. 697 at P 113; July 8 Order, 108 FERC
¶ 61,026 at P 95–97; NOPR at P 41.
70 Order No. 697 at P 66.
71 Id. P 65–66.
69 Order

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
suppliers.72 Second, contrary to
Southern’s claim, the DPT does consider
wholesale load because it analyzes ten
different seasons/load periods and the
Available Economic Capacity (AEC)
analysis deducts the native load
commitments of all suppliers, which
includes wholesale commitments.
4. Other Products and Models
Final Rule
52. Regarding relevant product
markets, the Commission stated in the
Final Rule:
[w]e will not generically alter the
indicative screens or the DPT to allow
different product analyses for short-term or
long-term power as some commenters
suggest. As the Commission has stated in the
past, absent entry barriers, long-term capacity
markets are inherently competitive because
new market entrants can build alternative
generating supply. There is no reason to
generically require that the horizontal
analysis consider those products that are
affected by entry barriers. Instead, we will
consider intervenors’ arguments in this
regard on a case-by-case basis.73

53. The Commission also rejected
suggestions by some commenters that it
adopt behavioral modeling, such as
game theory, in addition to or in place
of the indicative screens and the DPT.
The Commission explained that,
although game theory has been used in
laboratory experiments and in
theoretical studies where the number of
players and choices available to players
are limited, it is not a practical approach
given the volume of analyses the
Commission must perform. The
Commission noted that a large number
of choices are available in market power
analyses and many of those are
unobservable, and concluded that data
gathering and analysis burden imposed
on sellers and the Commission if it were
to adopt behavior modeling would be
overly burdensome and impractical.74

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Requests for Rehearing
54. NASUCA argues that the
Commission must investigate whether
sellers are able to raise electricity
auction market rates to higher noncompetitive levels, without collusion,
through strategic bidding and gaming
behavior in Commission-approved
auction markets.75 NASUCA states that
experience, mathematical game theory
analysis, judicial decisions, and
laboratory simulations indicate that
market participants who pass market
power screens nonetheless may be able

to elevate prices in Commissionapproved auction markets through noncollusive strategic bidding, withholding,
and gaming tactics.76 NASUCA states
that the Commission’s market power
screens are based on a static analysis of
single sellers’ market shares, stating that
less than a 20 percent share of the
relevant market capacity is sufficient
and less than the supply margin on the
annual peak day satisfies the ‘‘supply
margin assessment.’’ NASUCA
concludes that neither of these tools
addresses the problem identified in the
research that sellers in these specialized
markets repeatedly communicate
through their bidding behavior.77
55. NASUCA states that, to its
knowledge, the Commission has never
publicly discussed mathematical game
theory analysis in depth in its orders,
has not investigated the problem, and
has held no technical conference or
workshop to invite researchers to
present their findings regarding
gameability of the wholesale electricity
markets.78 NASUCA argues that
strategic market behavior analysis is
needed to assess whether current market
designs allow participants, without
overt collusion, to elevate market prices
to unreasonable and non-competitive
levels. The purpose of such analysis
would be to take corrective action to
prevent gaming behavior, by revising
market designs or rules. NASUCA
asserts that the Commission
misunderstood NASUCA’s request in
finding that consideration and analysis
of such behavior would be
burdensome.79
56. NASUCA argues that the ‘‘primary
purpose’’ of the FPA and the
Commission is protection of utility
consumers. NASUCA states that, in
order to achieve confidence that rates
set in Commission-sanctioned markets
are reasonable, the Commission must
investigate strategic bidding and market
gaming by market participants.80
NASUCA therefore requests that, at a
minimum, the Commission commence a
proceeding to investigate this and begin
it by inviting researchers who have
identified strategic auction market
gaming as a problem in auction markets
of the type used for the sale of
electricity to present their research at a
public technical conference.
57. APPA/TAPS argue that, in
addition to the existing indicative
screens, the Commission should require
76 Id.

at 2.
at 6.
78 Id. at 7 (citing Order No. 697 at P 121, 124).
79 Id. at 7 (citing Order No. 697 at P 124).
80 Id. (citing Electrical Dist. No. 1 v. FERC, 774
F.2d 490, 492–93 (D.C. Cir. 1984)).

that the market share screen be
submitted using only firm transmission
capacity.81 In this regard, APPA/TAPS
state that applicants should be required
to ‘‘submit a ‘firm transmission Market
Share Screen’ where the SIL
[simultaneous transmission import
limit] study reflects only firm
transmission capacity.’’ 82 According to
APPA/TAPS, running the market share
screen using only firm transmission in
the SIL study would provide evidence
about who could realistically compete
to sell long-term, firm products. Further,
APPA/TAPS argue that the pivotal
supplier screen is not well adapted to
examining market conditions for longterm products, and that the firm
transmission market share screen could
be performed to provide better insight
into the market for long-term products.
APPA/TAPS assert that to understand
what long-term generation capacity may
be available and backed by firm
transmission service, the market share
screen should be run using an SIL study
of firm transmission capacity only,
preferably using available transfer
capability (ATC) for the upcoming
annual period, but at a minimum, run
without capacity benefit margin (CBM)
modeled as available, even on a nonfirm basis.83 APPA/TAPS also argue that
the Commission should require sellers
to calculate the simultaneous available
import capability of their systems using
the firm ATC values that transmission
customers are given, and use those
results to prepare one of the iterations
of the market share screen.84
Commission Determination
58. We have considered the strategic
bidding literature and various
theoretical models which demonstrate
that market participants who pass
market power screens nonetheless may
be able to elevate prices in Commissionapproved auction markets through
‘‘non-collusive strategic bidding,
withholding, and gaming tactics.’’
However, the Commission does not
think it is necessary to investigate the
possibility of whether sellers or market
participants are able to engage in
strategic bidding, withholding and
gaming tactics to elevate prices in
auction markets in order to determine
whether to grant market-based rate
authority. First, these theoretical or
gaming models require consideration of
numerous assumptions and
hypothetical future behavior that may
quickly become invalid because of the

77 Id.

72 Id.

P 67.
P 122.
74 Id. P 124.
75 NASUCA Rehearing Request at 5.
73 Id.

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81 APPA/TAPS
82 Id.
83 Id.
84 Id.

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at 17.

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changing behavior of market
participants, changes in the market or
changes in other factors, e.g., supply or
demand. Accordingly, the Commission
is concerned that they would not be
reliable tools in helping assess whether
a seller has market power. Second, the
type of behavior described by NASUCA
may be prohibited by the Commission’s
Anti-Manipulation Rule at section 1c.2
of the Commission’s regulations.85
Violations of the Anti-Manipulation
Rule include behavior constituting a
fraud that had the purpose of impairing,
obstructing, or defeating a wellfunctioning market.86 The
Commission’s Office of Enforcement
monitors activity in the electric markets
and conducts investigations to
determine whether market participants
are violating the Anti-Manipulation
Rule. To the extent that NASUCA or any
other entity has specific allegations of
market manipulation, that entity should
contact the Commission’s Enforcement
Hotline or the Division of Investigations
of the Office of Enforcement. Finally, as
the Commission stated in Order No.
697, for practical considerations the
data gathering and analysis burden
imposed on sellers and the Commission
to consider all the hypothetical types of
behavior would be overly burdensome
and impractical.87
59. With regard to APPA/TAPS’
argument that the existing indicative
screens should be altered so that sellers
are required to ‘‘submit a ‘firm
transmission Market Share Screen’
where the SIL study reflects only firm
transmission capacity’’ in order to
examine market conditions for longterm products, we reiterate that the
indicative screens are intended to
identify sellers that raise no horizontal
market power concerns in short-term
markets, and we decline to allow
different product analyses for short-term
or long-term power. We address the
issue of the analysis of the
competitiveness of long-term markets in
the section of this order addressing
mitigation. Thus, we reject APPA/TAPS’
argument that sellers should be required
to submit a firm transmission market
share screen where the SIL study
reflects only firm transmission capacity.

85 Prohibition of Energy Market Manipulation,
Order No. 670, 71 FR 4244 (Jan. 26, 2006), FERC
Stats. & Regs. ¶ 31,202 (2006), reh’g denied, 114
FERC ¶ 61,300 (2006).
86 Order No. 670, FERC Stats. & Regs. ¶ 31,202 at
P 50–53.
87 Order No. 697 at P 124.

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5. Native Load Deduction
Final Rule
60. In Order No. 697, the Commission
modified the native load proxy for the
market share screen from the minimum
peak day in the season to the average
peak native load, averaged across all
days in the season, making the native
load proxy for the market share
indicative screen consistent with the
native load proxy under the pivotal
supplier indicative screen. The
Commission found that using the
existing native load proxy did not
provide an accurate picture of the
conditions throughout the season. The
Commission explained that a native
load proxy based on the average of peak
load conditions is more representative,
and thus more accurate, than a proxy
based on extreme (minimum) peak load
conditions, and further, that basing the
native load proxy on the average of the
peaks is more accurate by eliminating
sellers without market power while
focusing on ones that may have market
power.
61. In addition, the Commission
clarified that native load can only
include load attributable to native load
customers based on the definition of
native load in section 33.3(d)(4)(i) of the
Commission’s regulations and gave
sellers the option of using seasonal
capacity instead of nameplate capacity.
Requests for Rehearing
62. TDU Systems assert on rehearing
that the Commission’s failure to explain
how its modification of the native load
proxy in the wholesale market share
screen is rationally related to the
objective of accurately detecting the
market power of electric utilities in their
home control areas is arbitrary and
capricious.88
63. TDU Systems argue that the
Commission should maintain the
existing native load proxy for use in the
wholesale market share screen 89
because the Commission does not
provide a reasoned analysis and
supporting evidence for increasing the
native load proxy for the market share
indicative screen from the minimum
daily native load peak demand for the
season to the average daily native load
peak demand for the season.90
64. TDU Systems point out the
Commission’s explanation that the
virtue of having the two indicative
screens is that they each measure
88 TDU Systems Rehearing Request at 3 (citing
Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto
Ins. Co., 463 U.S. 29, 42–43 (1983); Pac. Gas & Elec.
Co. v. FERC, 373 F.3d 1315, 1319 (D.C. Cir. 2004)).
89 Id. at 7.
90 Id. at 8, 18.

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different market conditions,91 and assert
that, to achieve that purpose, they
should use different proxies for native
load obligations. TDU Systems conclude
that the Commission should revise the
market share screen to use the minimum
native load during the season as the
proxy.92
Commission Determination
65. In response to TDU Systems’
assertion that changing the native load
proxy is arbitrary and capricious and
may not accurately detect the market
power of electric utilities in their home
balancing authority areas, we
acknowledge that increasing the native
load proxy may have the effect of
reducing the market share for traditional
utilities and could result in fewer
failures of the market share screen.93
However, as we explained in Order No.
697, the native load proxy adopted in
Order No. 697 more accurately describes
the conditions faced by sellers across
seasons rather than simply at the most
extreme peak load conditions.94 For
instance, using the minimum peak day
in the native load proxy only measures
sellers’ available capacity on a single
day, and does not reflect the more
general conditions faced by sellers
throughout the season. Because
changing the native load deduction will
lead to a more accurate measure of
uncommitted capacity for load-serving
entities, there will be a more accurate
measure of the conditions faced by
competing suppliers. Thus, the native
load proxy is more accurate in detecting
the market power of electric utilities in
their home balancing authority areas.
66. We reject TDU Systems’ argument
that because the pivotal supplier and
market share screens measure different
market conditions they should therefore
use different native load proxies. We
disagree and find that is not appropriate
to use different native load proxies for
the different screens. Although the
screens themselves use inherently
different methodologies, the native load
does not vary depending on which
91 April 14 Order, 107 FERC ¶ 61,018 at P 90
(2004).
92 TDU Systems Rehearing Request at 20.
93 We note that use of the average daily native
load peak demand for the season is also applicable
to first-tier competitors. Thus, while a traditional
utility applicant will have a lower amount of
uncommitted capacity than it would have had using
a native load proxy based on the minimum daily
native load peak demand for the season, so too will
traditional utility sellers in first-tier markets.
Accordingly, although the traditional utility
applicant’s uncommitted capacity is reduced, so too
is the relative size of the market considering
imports from first-tier markets. All else being equal,
the market shares of the traditional utility applicant
may not change much if at all.
94 94 Order No. 697 at P 137.

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screen is used. Accordingly, we find
that use of the average peak native load
as the native load proxy for both screens
provides an accurate picture of the
conditions throughout the season.
67. We also clarify the definition of
native load as it is used in the DPT
analysis. With regard to the statement in
the Final Rule that under the DPT, a
seller ‘‘will be considered pivotal if the
sum of the competing suppliers’
economic capacity is less than the load
level (plus a reserve requirement that is
no higher than State and Regional
Reliability Council operating
requirements for reliability) for the
relevant period’’ 95 we clarify that the
analysis should also be performed using
available economic capacity to account
for sellers’ and competing suppliers’
native load commitments. We further
clarify that native load in the relevant
market (sellers’ and competing
suppliers’) should be subtracted from
the total load in each season/load
period, and that the native load
subtracted should be the average of the
hourly native load for each season load
condition.96
6. Relevant Geographic Market
Final Rule
68. In Order No. 697, the Commission
adopted its existing approach with
respect to the default relevant
geographic market, with some
modifications. The Commission
announced that it would continue to use
a seller’s balancing authority area 97 or
the RTO/ISO market,98 as applicable, as
the default relevant geographic market,
explaining that the use of defined
default geographic markets provides the
industry with as much certainty as
possible while also providing parties the
right to challenge the default geographic
market definition and submit pertinent
evidence.99
69. With respect to traditional (nonRTO/ISO) markets, the Commission
adopted a rebuttable presumption that
the seller’s default relevant geographic
market under both indicative screens
would be the balancing authority area
where the seller is physically located,
and each of its neighboring first-tier
balancing authority areas.100
95 Id.

P 108.
id. P 150 (citing 18 CFR 33.3(d)(4)(i)).
97 Previously, the Commission had used the term
‘‘control area,’’ but in the Final Rule it replaced that
term with ‘‘balancing authority area’’ with regard to
relevant geographic markets.
98 An RTO/ISO must have a sufficient market
structure and a single energy market with
Commission-approved market monitoring and
mitigation.
99 Order No. 697 at P 235.
100 Id. P 231–32.

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70. With respect to RTO/ISO markets,
the Commission stated that sellers
located in and members of the RTO/ISO
may consider the geographic region
under the control of the RTO/ISO as the
default relevant geographic market for
purposes of completing their horizontal
analyses, unless the Commission has
already found the existence of a
submarket. Where the Commission
makes a specific finding that there is a
submarket within an RTO/ISO, that
submarket becomes the default relevant
geographic market for sellers located
within the submarket for purposes of
the market power analysis (both
indicative screens and DPT). In the
Final Rule, the Commission concluded
that sellers located in these RTO/ISO
submarkets should not use the entire
RTO/ISO footprints as their relevant
geographic markets. The Commission
explained that this policy is consistent
with how it has treated such submarkets
in the context of mergers; the Final Rule
cited several cases to support this
proposition, including Exelon Corp.,101
where the Commission found that PJMEast and Northern PSEG are sub-markets
within PJM Interconnection (PJM).
71. The Commission stated that it
would continue to allow sellers and
intervenors to present evidence on a
case-by-case basis to show that some
other geographic market should be
considered as the relevant market in a
particular case. To the extent that the
Commission finds that a submarket
exists within an RTO/ISO, intervenors
or sellers can provide evidence to the
contrary; thus, a submarket, like the
other default geographic markets, is a
rebuttable default geographic market.102
The Commission explained that it will
also consider arguments that a seller
operates in an RTO/ISO submarket even
if the Commission has not previously
found that a submarket exists. Likewise,
sellers and intervenors also may present
evidence that the relevant market is
broader than a particular balancing
authority area or RTO/ISO footprint or
submarket.
72. The Commission stated that
sellers may incorporate the mitigation
they are subject to in RTO/ISO markets
or submarkets with Commissionapproved market monitoring and
mitigation as part of their market power
analysis.103 By way of example, if a
market power analysis indicates that a
seller may have market power, the seller
may point to the RTO/ISO mitigation
101 112 FERC ¶ 61,011, reh’g denied, 113 FERC
¶ 61,299 (2005) (Exelon). The Commission noted
that Exelon later terminated the merger. Order No.
697 at P 236 and n.220.
102 Id. P 238.
103 Id. P 241.

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25843

rules as evidence that its market power
has been adequately mitigated. The
same is true for submarkets; for
instance, New York City will be treated
as a separate default market for marketbased rate study purposes, and its
existing In-City mitigation will be used
to assess whether any concerns over
market power are already mitigated.104
Requests for Rehearing
73. TDU Systems and NRECA object
to the Commission’s determination to
use a balancing authority area or RTO/
ISO region as a default relevant
geographic market; they believe that a
seller should always have the burden of
defining the appropriate geographic
market or submarket and that the
Commission cannot lawfully place the
burden on customers or intervenors to
show that the ‘‘default’’ market is not
the relevant geographic market.105 Thus,
NRECA argues that the Commission’s
determination to use the applicant
public utility’s balancing authority area
or the RTO/ISO region as the default
relevant geographic market is arbitrary,
capricious, contrary to law, in excess of
statutory authority, and not supported
by substantial evidence.106 Further,
according to NRECA, the Final Rule did
not adequately respond to NRECA’s
argument that default geographic
markets should not be used because the
Commission cannot place the burden on
intervenors to demonstrate that the
default market is not the relevant
geographic market, and failed to
satisfactorily explain the Commission’s
action ‘‘ ‘including a rational connection
between the facts found and the choice
made.’ ’’ 107
74. TDU Systems state that, although
the Commission has attempted to create
a ‘‘balanced approach,’’ it is arbitrary
and capricious to grant market-based
rate authority based on the inaccurate
assumption that in most cases, the
Commission will rely on RTO/ISO
regions as default geographic markets.
TDU Systems cite Keystone for the
proposition that evidentiary
presumptions are only permissible in
the presence of a connection between
104 Id.

P 242.
Systems Rehearing Request at 15; NRECA
Rehearing Request at 18.
106 NRECA Rehearing Request at 2–3 (citing
Secretary of Labor v. Keystone Coal Mining Corp.,
151 F.3d 1096, 1100 (D.C. Cir. 1998) (Keystone); 5
U.S.C. 556(d); 5 U.S.C. 706(2)(A), (C), (E); 16 U.S.C.
824d(e); 16 U.S.C. 825l(b); Preventing Undue
Discrimination and Preference in Transmission
Service, Order No. 890, 72 FR 12265 (March 15,
2007), FERC Stats. & Regs. ¶ 31,241, at P 901–1094
(2007), order on reh’g and clarification, Order No.
890–A, 73 FR 2984 (Jan. 16, 2008), FERC Stats. &
Regs. ¶ 31,261 (2007)).
107 Id. at 20 (quoting Pac. Gas & Elec. Co. v. FERC,
373 F.3d 1315, 1319 (D.C. Cir. 2004)).
105 TDU

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proven and inferred facts, and asserts
that, ‘‘[e]ven with the submarkets the
Commission identifies in the Final Rule
(at P 246), the exceptions to the rule are
still far too numerous to declare that the
proposal can pass the ‘so probable that
it is sensible’ test.’’ 108 It argues that
public utility sellers should have an
affirmative obligation, meeting the strict
standard for burden shifting, to identify
the relevant geographic market and
justify the market used in their
horizontal market power analyses.
Using the wrong default geographic
markets prevents the Commission from
accurately assessing the public utility’s
market power and thus contravenes the
statutory prerequisites.
75. NRECA and TDU Systems claim
that the use of RTO/ISO regions and
balancing authority areas as default
relevant markets in many cases will not
produce valid screen results because
they do not take into account wellknown binding transmission constraints
and load pockets, such as those the
Commission has found in the New York
Independent System Operator (NYISO)
and the ISO New England (ISO–NE)
submarkets.109 They assert that the
Commission should eliminate the use of
the seller’s balancing authority area or
RTO/ISO region as the relevant market
and instead require an applicant to
identify the relevant geographic market
based on actual data including grid
topology and existing transmission
constraints.110
76. In contrast to the arguments raised
on rehearing by NRECA and TDU
Systems, PSEG and Reliant find fault
with the Commission’s ruling that the
larger RTO/ISO region will not be used
as the default geographic market for
market-based rate sellers located in
RTO/ISO areas where the Commission
has found submarkets to exist. PSEG
claims that the ruling departs from
many years of Commission policy
utilizing the RTO/ISO as the default
relevant geographic market and is
inconsistent with the Commission’s
confidence in the impact of RTO/ISO
market monitoring and mitigation.111
PSEG asserts that this major change in
108 TDU

Systems Rehearing Request at 15.
Rehearing Request at 19 (‘‘Given that
the Commission was able to find submarkets in
relatively compact and contiguous regions such as
[NYISO] and [ISO–NE], then the notion of using farflung RTO/ISO regions such as the Midwest ISO
and SPP as default markets is untenable’’); TDU
Systems Rehearing Request at 15.
110 NRECA Rehearing Request at 20; TDU Systems
Rehearing Request at 16.
111 PSEG Rehearing Request at 2–3 (quoting Order
No. 697 at P 290 (‘‘We believe that a single market
with Commission-approved market monitoring and
mitigation and transparent prices provides added
protection against a seller’s ability to exercise
market power * * *’’)).

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policy is not supported by substantial
evidence, is not a product of reasoned
decision making,112 and claims that ‘‘it
is difficult to discern the legal or factual
basis for the change.’’ 113 Regarding the
Commission’s explanation that the
consideration of submarkets is
consistent with the Commission’s
merger analysis, PSEG states that
‘‘simply because the Commission
needed to examine submarket impacts
in the context of an individual merger
proceeding does not make that
submarket appropriate as a default
geographic market to be applied going
forward on a generic basis for all sellers
in that submarket.’’ 114 PSEG argues that
the focus of the market power analysis
is substantively different in the two
types of proceedings, and that the
public was not on notice that the
Commission might rely on findings from
a merger proceeding to create a generic
rule applicable to all parties located in
the same area, thus constituting
‘‘retroactive rulemaking.’’ Moreover,
PSEG contends that by basing a generic
determination of submarkets on prior
merger filings rather than after a
systematic review of market power in a
region, the Commission adopts a policy
that discriminates against some market
participants because a market-based rate
seller can be located in an RTO/ISO subregion that has greater instances of
transmission constraints than any of the
submarkets specifically identified in
Order No. 697, but will still be able to
proceed with a market-based rate
application using the RTO/ISO as the
default relevant geographic market.115
PSEG asserts that a fairer approach
would be to review potential
submarkets comprehensively as part of
the regional review process that will be
conducted according to the schedule
112 Id. at 6 (citing Moraine Pipeline Co. v. FERC,
906 F.2d 5, 9 (D.C. Cir. 1990) (reasoned decision
making requires that the Commission must not just
acknowledge arguments made, but must ‘‘respond
to [such] arguments and * * * articulate its
decision based on evidence in the record’’); Motor
Vehicles Mfrs. Ass’n. v. State Farm Mutual Auto.
Ins. Co., 463 U.S. 29, 43, 48, 57 (1983); Williams
Natural Gas Co. v. FERC, 90 F.3d 531, 533 (D.C. Cir.
1996) (To be upheld, the Commission’s order must
be ‘‘supported by substantial evidence and reached
by reasoned decision-making—that is, a process
demonstrating the connection between the facts
found and the choice made.’’)).
113 Id. PSEG also cites Missouri Public Service
Commission v. FERC, 234 F.3d 36, 40 (D.C. Cir.
2000) (when ‘‘the Commission balances competing
interests in arriving at its decision, it must explain
on the record the policies which guide it.’’).
114 Id. at 6–7. See also Reliant Rehearing Request
at 5–6, warning that sellers may have no choice but
to intervene and potentially litigate in additional
proceedings where the Commission may possibly
make a finding that identifies a new submarket.
115 Id. at 8.

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provided in Appendix D of the Final
Rule.116
77. Reliant states that the record does
not support the use of submarkets in
indicative screens, noting that one
commenter advocated use of a
submarket when applying the DPT but
that no commenters suggested that the
indicative screens should be performed
utilizing a submarket. Reliant argues
that when a submarket is used within an
RTO/ISO in indicative screens, the
applicable default market used will be
smaller than the full market within
which a seller participates. Reliant
claims that this is inconsistent with the
design and intent of the indicative
screens because identification of a
submarket is unpredictable, and because
a submarket identified in another
potentially unrelated proceeding may be
used.117
78. PSEG argues further that the
Commission ignored record evidence
proving the lack of technical and policy
merit in creating submarkets when
performing market power analyses
submitted by the three RTO/ISOs that
commented on the issue; and it claims
that California ISO (CAISO), ISO–NE,
and NYISO agree that there is no
technical and structural need for the
examination of RTO/ISO submarkets.118
According to PSEG, the Commission’s
failure to meaningfully consider that
evidence and to respond to it was
arbitrary and capricious and not
reasoned decisionmaking.119
79. PSEG contends that submarkets
are inappropriate as default relevant
geographic markets because they are
largely a product of transmission
constraints that periodically create
short-term price differences between
neighboring geographic areas. Such
differences, it states, are not static and
can be altered over the long term by
transmission reinforcements, new
generation entry, and changes in
load.120 It concludes that the
unpredictable nature of those forces
makes submarkets unreliable for
assessing market power, and believes
that the Commission should have
retained the RTO/ISO as the default
relevant geographic market so long as
the RTO/ISO has market monitoring and
116 Id.

at 9.

117 Reliant

Rehearing Request at 5–6.
Rehearing Request at 4–6 (citing NYISO
NOPR comments at 3–4; ISO–NE NOPR comments
at 4 and 6; and CAISO NOPR comments at 13).
119 Id. at 6 (citing Moraine Pipeline Co. v. FERC,
906 F.2d 5, 9 (D.C. Cir. 1990) (holding that the
Commission must not just acknowledge arguments
made but must respond to such arguments)).
120 Reliant Rehearing Request at 7–8; PSEG
Rehearing Request at 9–10. Reliant limits its
objections to the use of submarkets in indicative
screens.
118 PSEG

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mitigation programs in place in
conjunction with a regional
transmission expansion planning
program.
80. With specific reference to the
Commission’s generic finding of
submarkets in Eastern PJM and
Northern PSEG, PSEG alleges that the
Commission erred in relying on a prior
ruling in the Exelon-PSEG merger
proceeding,121 which merger was
subsequently terminated. According to
PSEG, the Commission cannot rely on
the Exelon-PSEG merger proceeding
because that analysis was dependent on
the assumption that Exelon and PSEG
would merge; the termination of the
merger changed key assumptions that
were material to the market power
analysis examining what changes to
competitive conditions would occur as
a consequence of the merger.
Commission Determination
81. We affirm our decision to use a
balancing authority area or RTO/ISO
region as a default relevant geographic
market. In Order No. 697, the
Commission fully explained the basis
for using default geographic markets.
The Commission explained that the use
of defined default geographic markets
provides sellers and intervenors a
measure of certainty regarding the
relevant market while also providing
parties the right to challenge the default
geographic market definition and
submit pertinent evidence of an
alternative geographic market based on
actual data.
82. As discussed more fully below, we
reject NRECA’s and TDU Systems’
argument that the Commission’s
determination to use the applicant
public utility’s balancing authority area
or the RTO/ISO region as the default
relevant geographic market is arbitrary,
capricious, contrary to law, in excess of
statutory authority, and not supported
by substantial evidence. In Order No.
697 the Commission carefully
considered and balanced various
arguments on both sides of the issue
concerning whether it is appropriate to
use default geographic markets for
purposes of the horizontal analysis.
83. Our use of the applicant public
utility’s balancing authority area or the
RTO/ISO region as the default relevant
geographic market is supported by the
evidence. In particular, with regard to
traditional (non-RTO/ISO) markets, the
Commission adopted as the default
geographic market first the balancing
authority area where the seller is
121 PSEG Rehearing Request at 10, referring to
Exelon Corp., 112 FERC ¶ 61,011, order on reh’g,
113 FERC ¶ 61,299 (2005).

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physically located and, second, the
markets directly interconnected to the
seller’s balancing authority area (firsttier balancing authority area markets).
Our decision to use the balancing
authority area or the RTO/ISO region as
the default geographic market closely
tracks our guidance provided in Order
No. 697 on what constitutes a market.122
Our experience has indicated that
typically there are frequently recurring
physical impediments to trade between
balancing authority areas that would
prevent competing supplies from firsttier markets from reaching wholesale
customers.123 Thus, our decision to
consider balancing authority areas as
the default geographic market is neither
arbitrary nor capricious but, rather,
firmly embedded in the characteristics
of our jurisdictional markets.
84. In addition, with regard to public
policy considerations and regulatory
certainty, the Commission explained in
Order No. 697 that using balancing
authority areas allows the Commission
and the public to rely on publicly
available data provided for balancing
authority areas that are relevant to the
market-based rate analysis.124 Further, it
is the interconnection and coordination
between balancing authority areas that
provides a foundation for the
Commission to analyze transmission
limitations and other transfers of energy
and provides reasonable measures of the
relevant geographic market under
typical circumstances.125
85. With regard to RTO/ISO markets,
the Commission’s approach has been
well considered and consistent with our
approach described above regarding
traditional markets. After weighing all
122 Order

No. 697 at P 231–232.
P 268.
124 Id. P 233.
125 Id. P 251. Similar to a control area, a balancing
authority area is physically defined with metered
boundaries that we refer to as the balancing
authority area. Every generator, transmission
facility, and end-use customer must be in a
balancing authority area. The responsibilities of a
balancing authority include the following: (1)
Match, at all times, the power output of the
generators within the balancing authority area and
capacity and energy purchased from or sold to
entities outside the balancing authority area, with
the load within the balancing authority area in
compliance with the Reliability Standards; (2)
maintain scheduled interchange and control the
impact of interchange ramping rates with other
balancing authority areas, in compliance with
Reliability Standards; (3) have available sufficient
generating capacity, and Demand Side Management
to maintain Contingency Reserves in compliance
with Reliability Standards; and (4) have available
sufficient generating capacity, Demand Side
Management, and frequency response to maintain
Regulating Reserves and Operating Reserves in
compliance with Reliability Standards. Id. (citing
Approved Reliability Standards. http://
www.ferc.gov/industries/electric/indus-act/
reliability/standards.asp).
123 Id.

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25845

the facts, including our experience
regulating these markets, the
Commission concluded that the
geographic region under the control of
the RTO/ISO is the appropriate market
absent evidence to the contrary. Thus,
as a starting point and consistent with
our guidance on what constitutes a
market, the Commission has made a
finding that the geographic region under
the control of the RTO/ISO is
appropriate for use as the default
geographic market. In addition, where
the Commission has made a specific
finding that there is a submarket within
an RTO/ISO, the Commission explained
that the submarket should be considered
as the default relevant geographic
market. Thus, our decision to consider
the geographic region under the control
of the RTO/ISO as the default
geographic market, unless the
Commission makes a specific finding of
the existence of a submarket, is neither
arbitrary nor capricious, but similarly
embedded in the characteristics of our
jurisdictional markets.
86. With regard to TDU Systems’ and
NRECA’s assertion that a seller should
always have the burden of defining the
appropriate geographic market or
submarket and that the Commission
cannot lawfully place the burden on
customers or intervenors to show that
the ‘‘default’’ market is not the relevant
geographic market, we disagree. As
stated above, after careful consideration
and based on the facts before us, the
Commission has made findings
regarding these geographic markets. We
reject TDU Systems’ and NRECA’s
argument that under Keystone, the
Commission may not grant marketbased rate authority based on the
assumption that, in most cases, the
Commission will rely on RTO/ISO
regions as default geographic markets
because such a presumption shifts the
burden of establishing the relevant
geographic market from the seller to
intervenors. In Keystone, the court
found that an evidentiary presumption
is only permissible if there is ‘‘a sound
and rational connection between the
proved and inferred facts.’’ 126 Contrary
to TDU Systems’ and NRECA’s
argument that there is no evidence to
support use of RTO/ISO regions as
default geographic markets, and, as
explained in the Final Rule, the RTO/
ISO regions have historically been used
as default geographic markets.127 As
126 Keystone,

151 F.3d 1096 at 1100.
April 14 Order at P 41, 187 (stating that
when performing the generation market power
analysis, applicants located in RTOs/ISOs with
sufficient market structure may consider the
geographic region under the control of the RTO/ISO
127 See

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explained in the Final Rule and prior
orders, we have used RTO/ISO regions
as the default market for many reasons,
including the central commitment and
dispatch in most RTOs/ISOs, the
elimination of trade barriers within
those regions (e.g., pancaked rates),
common market mitigation and other
factors.128 On rehearing, TDU Systems
and NRECA have presented no
empirical evidence demonstrating that
RTO/ISO regions should not be used as
default geographic markets, or that the
use of RTO/ISO regions as default
geographic markets is inadequate or
insufficient for the typical situation.
87. We agree with NRECA and TDU
Systems that we should take into
account binding transmission
constraints and load pockets in both
RTO/ISO regions and balancing
authority areas and Order 697 does so.
Based on our findings on binding
transmission constraints, the
Commission has identified six
submarkets in NYISO, PJM, and ISO–
NE, as described in Order No. 697.129
Where the Commission has made a
specific finding that there is a
submarket within an RTO/ISO or within
any other market, the market-based rate
analysis (both the indicative screens and
as the relevant default geographic region for
purposes of completing their analyses, and
comparing the practice to the Commission’s earlier
approach under the hub and spoke analysis).
128 See, e.g., April 14 Order at P 187–191; July 8
Order at P 177; Mystic I, LLC, 111 FERC ¶ 61,378,
at P 14–19 (2005) (rejecting challenge to the use of
ISO–NE market as the relevant geographic market
on the basis that local market power mitigation is
in place: ‘‘[W]ithout specific evidence to the
contrary, we are satisfied that ISO–NE has
Commission-approved tariff provisions in place to
address instances where transmission constraints
would otherwise allow generators to exercise local
market power and that these rules and procedures
will apply in the NEMA/Boston zone within ISO–
NE.’’); Wisconsin Electric Power Co., 110 FERC
¶ 61,340, at P 19–20, reh’g denied, 111 FERC
¶ 61,361, at P 13–15 (2005) (rejecting challenge to
use of Midwest ISO market as the relevant
geographic market on basis that local market power
mitigation measures exist: ‘‘The tighter thresholds
in NCAs such as WUMS in the Midwest ISO, and
the resulting tighter mitigation of bids, are local
market power mitigation measures’’ and should
adequately address specific concerns regarding the
possibility that Wisconsin Electric can exercise
market power in the WUMS region). Accord AEP
Power Marketing, Inc., 109 FERC ¶ 61,276 (2004),
reh’g denied, 112 FERC ¶ 61,320, at P 23–25 (2005),
aff’d, Industrial Energy Users-Ohio v. FERC, No.
05–1435 (D.C. Cir. Feb. 16, 2007) (use of PJM
footprint as relevant geographic market; noting
existence of Commission-approved market
monitoring and mitigation). See also Midwest
Independent Transmission System Operator, Inc.,
109 FERC ¶ 61,157, at P 463 (2004) (noting that the
Midwest ISO-wide market will not be considered as
the default geographic market until such time as the
Midwest ISO becomes a single market and performs
functions such as single central commitment and
dispatch with Commission-approved market
monitoring and mitigation).
129 Id. P 236.

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the DPT) should consider that
submarket as the default relevant
geographic market.130 We note that
NRECA and TDU Systems’ argument
that the use of RTO/ISO regions and
balancing authority areas as the default
relevant market in many cases will not
produce valid screen results because
this use does not take into account
‘‘well-known binding transmission
constraints and load pockets’’ is overly
simplistic. The Commission has
provided in Order No. 697 131 guidance
as to the record information needed to
make a determination that an alternative
geographic market is appropriate (e.g.,
expanded market, submarket). The
Commission will, and has,132 carefully
considered record evidence regarding
geographic markets. In particular, ‘‘wellknown’’ is an arbitrary term and does
not meet the type of evidence needed
for the Commission to base a
determination. Accordingly, we will
continue to use a seller’s balancing
authority area or the RTO/ISO market,
as applicable, as the default relevant
geographic market, unless the
Commission makes a specific finding of
the existence of a submarket.
88. We disagree with PSEG’s
statement that, ‘‘simply because the
Commission needed to examine
submarket impacts in the context of an
individual merger proceeding does not
make that submarket appropriate as a
default geographic market to be applied
going forward on a generic basis for all
sellers in that submarket.’’ As discussed
above, our determination of what
constitutes a geographic market is not
dependent upon whether the type of
proposal before us is in the context of
a market-based rate or merger
proceeding. Rather, we base our
determination on facts relating to a
particular region and the guidelines we
have provided regarding what
constitutes a geographic market.
Whether in a merger proceeding, RTO
proceeding, or market-based rate
proceeding the fundamental
characteristics of a market does not
change nor should we ignore our
findings because administratively they
were made in a different proceeding.
89. With regard to PSEG’s argument
that the public was not on notice that
the Commission might rely on findings
from a merger proceeding that could
apply in subsequent market-based rate
proceedings, we reiterate that, to the
extent that the Commission finds that a
submarket exists within an RTO/ISO,
131 Id.

P 267–278.
Pinnacle West Capital Corp., 122 FERC
¶ 61,035 (2008).
132 See

Frm 00016

133 Order

No. 697 at P 238.
at P 61; Order No. 697 at P 215.
135 Exelon Corp., 112 FERC ¶ 61,011, reh’g
denied, 113 FERC ¶ 61,299 (2005), vacated, PPL
Electric Utilities Corp. v. FERC, No. 06–1009 (D.C.
Cir. Dec. 21, 2006).
134 NOPR

130 Id.

PO 00000

intervenors or sellers can provide
evidence to the contrary (i.e., the
submarket, like our other default
geographic markets, is rebuttable).133
Moreover, in the NOPR in this
proceeding, the Commission explained
that its experience with corporate
mergers and acquisitions indicates that
the RTO/ISOs that the Commission has
identified as meeting the criteria for
being considered a single market for
purposes of performing the generation
market power screens have, at times,
been divided into smaller submarkets
for study purposes because frequently
binding transmission constraints
prevent some potential suppliers from
selling into the destination market.
Therefore, the Commission sought
comment on its approach under the
market-based rate program of
considering the entire geographic region
under control of the RTO/ISO, with a
sufficient market structure and a single
energy market, as the default relevant
market. Further, the NOPR asked
whether the Commission should
continue its approach of considering the
entire geographic region as the default
market for purposes of the indicative
screens but consider RTO/ISO
submarkets for purposes of the DPT.134
Thus, contrary to PSEG’s argument,
since the issuance of the NOPR in May
2006, the public has been on notice that
the Commission might rely on findings
from a merger proceeding that could
apply in determining RTO/ISO
submarkets that may be used in marketbased rate proceedings.
90. However, we will grant PSEG’s
request for rehearing regarding the
Commission’s determination in the
Final Rule that because the Commission
made a prior finding in the ExelonPSEG merger proceeding that Northern
PSEG is a separate market in PJM,
sellers in PJM should use that
submarket as the default geographic
market for their market-based rate
analysis. After the parties in that case
terminated the merger, the U.S. Court of
Appeals for the D.C. Circuit vacated the
Commission’s orders on procedural
grounds. In light of the ultimate
disposition of Exelon/PSEG merger
proceeding, on reconsideration, we
conclude that we erred in relying on a
prior finding of submarkets that was
made in that proceeding.135
91. With regard to PJM East, however,
we note that in proceedings other than
the Exelon/PSEG merger, the

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Commission also treated PJM-East as a
market within PJM.136 Accordingly, we
reaffirm our finding in the Final Rule
that because the Commission already
has found that PJM-East constitutes a
separate market in PJM, sellers located
in PJM should use PJM-East as the
default geographic market.
92. We reject PSEG’s argument that
the Commission’s policy discriminates
against some market participants. In
particular, PSEG contends that a marketbased rate seller can be located in an
RTO/ISO sub-region that has greater
instances of transmission constraints
than any of the submarkets specified in
the Final Rule, but will be able to
proceed with a market-based rate
application using the RTO/ISO as the
default relevant market. As the
Commission has stated, default
geographic markets are adequate and
sufficient for the typical situation, and
by defining default geographic markets,
we provide the industry as much
certainty as possible while also
providing affected parties the right to
challenge the default geographic market
definition and provide evidence in that
regard.137 Thus, in the example posited
by PSEG, if there is evidence that
indicates high instances of transmission
constraints within an RTO that has not
been previously found to constitute a
submarket, intervenors have the
opportunity to present that evidence to
the Commission. Accordingly, because
all market participants have the
opportunity to challenge the default
geographic market definition, this
policy does not discriminate against
some market participants. Rather, the
Commission’s policy in this regard
recognizes the findings the Commission
has already made and Order No. 697
provides guidance to parties that wish
to challenge the default geographic
markets.
93. With regard to PSEG’s claims that
the Commission failed to consider
evidence submitted by CAISO, ISO-NE,
and NYISO that there is no technical
and structural need for the examination
of RTO/ISO submarkets, we find that
where the Commission has made a
specific finding that there is a
submarket within an RTO/ISO, the
market-based rate analysis should
reflect the facts and consider that
submarket as the default relevant
geographic market. To do otherwise
would be inconsistent with our findings
of a submarket in the first instance. In
136 See, e.g., El Paso Energy Corporation, 92 FERC
¶ 61,076 (2000), Energy East Corporation, 96 FERC
¶ 61,322 (2001), Potomac Electric Power Company,
96 FERC ¶ 61,323 (2001).
137 Id. P 234.

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particular, the Commission has
consistently stated that the Commissionapproved market monitoring and
mitigation provides added protection
against a seller’s ability to exercise
market power, but cannot replace the
generation market power analysis.138
While we consider carefully comments
by interveners, this Commission will
also consider all the facts before us
before making a finding.
94. In addition, while PSEG is correct
that transmission constraints can be
temporary, as noted above, all of the
submarkets that the Commission has
identified result from frequently binding
transmission constraints during
historical seasonal peaks examined;
these particular constraints have not
tended to be temporary in nature.
Evidence with respect to whether a
transmission constraint is temporary or
is frequently binding will be considered
in determining whether a submarket
exists. To the extent that some existing
constraints may be alleviated by
construction of new transmission
facilities, parties may bring these
situations to our attention for further
consideration.
95. Without a correctly defined
submarket, sellers with market power in
the RTO/ISO market may not be
identified, and their market power
mitigated in both the real-time and dayahead markets. While we acknowledge
PSEG’s claim that the Commission’s
determination on RTO/ISO submarkets
departs from Commission policy
utilizing the RTO/ISO as the default
relevant geographic market, we disagree
with PSEG’s claim that this is
inconsistent with Commission
confidence in the impact of RTO/ISO
market monitoring and mitigation. The
purpose of this rulemaking proceeding
has been to consider and evaluate the
Commission’s current market-based rate
policy and to make adjustments to this
approach, as warranted. Thus, we have
carefully considered the facts before us,
including our historical approach, and
found it reasonable that where the
Commission has made a specific finding
that there is a submarket within an
RTO/ISO, the market-based rate analysis
should reflect those facts and consider
that submarket as the default relevant
geographic market because to do
otherwise would be inconsistent with
our findings of a submarket in the first
instance. In addition, the Commission
has been in the process of developing
and improving policies that best protect
customers and promote market
competition in a manner that accounts
for the changing nature of developing
138 See

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25847

electricity markets. We will not depart
from this basic approach.
96. Moreover, PSEG overstates the
difference between our prior policy and
the policy adopted in Order No. 697.
Prior to Order No. 697, the Commission
did not identify submarkets within an
RTO/ISO as default geographic markets,
but one of the principal reasons for this
policy was the ability to rely on
Commission-approved mitigation in
submarkets within RTOs/ISOs to
mitigate any localized market power.
Although Order No. 697 changed our
approach to geographic market
definition as it relates to submarkets,
applicants may propose to continue to
rely on Commission-approved
mitigation in these submarkets as
adequate to address any market
concerns.
RTO/ISO Exemption
Final Rule
97. Prior to the April 14 Order, the
Commission exempted sellers located in
markets with Commission-approved
market monitoring and mitigation from
providing generation market power
analyses stating that such sellers will be
governed by the specific thresholds and
mitigation provisions approved for the
particular markets.139 In the April 14
Order, the Commission determined that
it would no longer exempt these sellers,
on the basis that requiring sellers
located in such markets to submit
screen analyses provided an additional
check on the potential for market power.
In Order No. 697, the Commission
declined the request by commenters that
it reinstate the pre-April 14 Order
exemption for sellers located in markets
with Commission-approved market
monitoring and mitigation from
providing generation market power
analyses. Instead, the Commission
indicated that it would continue to
require generation market power
analyses from all sellers, including
those in RTO/ISO markets. The
Commission noted that while a single
market with Commission-approved
market monitoring and mitigation and
transparent prices provides added
protection against a seller’s ability to
exercise market power, it cannot replace
the generation market power
analysis.140
Requests for Rehearing
98. Reliant and PSEG argue that the
Commission should reconsider its
decision not to exempt sellers located in
markets with Commission-approved
139 See AEP Power Marketing, Inc., 97 FERC
¶ 61,219 (2001).
140 Id. P 290.

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market monitoring and mitigation from
submitting horizontal market power
analyses. Reliant contends that the
Commission did not explain what value
a separate horizontal market power
analysis would have, given that market
monitoring by an independent market
monitor consistent with Commissionapproved rules and mitigation already
identifies and mitigates market power.
According to Reliant, market monitoring
and mitigation provides a better picture
of market power issues in RTO/ISO
markets as compared to an individual
seller’s separate horizontal market
power analysis which considers only
market power at a fixed moment in time
and also provides relief from the costs
and burdens of producing a horizontal
market power analysis.141 In the
alternative, if the Commission declines
to reinstate the exemption, Reliant
asserts that the Commission should
clarify that Commission-approved
mitigation rules presumptively mitigate
a seller’s market power and, in addition,
the Commission should reconsider its
decision to utilize previously identified
RTO/ISO submarkets as the relevant
geographic market for the indicative
screens.
99. Reliant opines that a fundamental
purpose and objective of market
monitoring and mitigation is to detect
actual, and the potential for, market
power and to safeguard against it so as
to ensure that no seller in the market
can dominate the market, manipulate
price, or otherwise act to stifle
competition.142 Accordingly, Reliant
argues that a presumption that a seller’s
market power is adequately mitigated
where Commission-approved market
monitoring and mitigation rules are in
effect is entirely appropriate, unless an
intervenor can demonstrate why
Commission-approved mitigation is
insufficient in a particular case.
According to Reliant, it is not
appropriate to add the administrative
burden of applying indicative screens if
the Commission believes that market
monitoring and mitigation is generally
working.143
141 Reliant

Rehearing Request at 2–3.
at 3 (citing Market Monitoring Units in
Regional Transmission Organizations and
Independent System Operators, 111 FERC ¶ 61,267,
at P 1 (2005) (market monitoring units perform an
important role in enhancing competitiveness of
RTO/ISO markets by, among other things,
monitoring organized wholesale markets to identify
potential anticompetitive behavior by market
participants and providing comprehensive market
analysis critical for informed policy decision
making); April 14 Order, 107 FERC ¶ 61,018 at P
186, 190 (recognizing the pro-competitive benefits
of RTO/ISO markets with market monitoring and
mitigation)).
143 Id. at 7.

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100. PSEG asserts that the
Commission erred in failing to create a
presumption that, even when the
Commission has found submarkets to
exist, no further analysis of the
submarkets is required so long as a
robust RTO/ISO market monitoring and
mitigation scheme is in place.
According to PSEG, a demonstration of
a lack of market power in submarkets
should only be required if there is
reason to question whether such local
market power is being addressed. RTO/
ISO markets with Commission-approved
market monitoring and mitigation
programs in place should have a
presumption that analysis of potential
submarkets is not required. PSEG states
that, to the extent other market
participants believe otherwise, the
burden should fall on them to show that
an analysis of these submarkets was in
fact required.144
101. To further support its position,
PSEG notes that none of the three RTO/
ISOs that filed comments on the NOPR
saw any reason for applying mitigation
outside of their existing programs. PSEG
states that not accepting the efficacy of
the RTO/ISO mitigation for purposes of
the market-based rate assessment
potentially undermines the authority
and role of the RTO/ISOs.145 PSEG
suggests that the Advanced Notice of
Proposed Rulemaking on organized
markets would be a preferable way for
the Commission to fine-tune the market
monitoring and mitigation functions of
such organizations on a prospective
basis.146
102. Similarly, EEI requests that the
Commission clarify that ‘‘mitigated
sellers in RTOs and ISOs may rely on
Commission-approved market
monitoring and mitigation for sales
within the RTOs and ISOs without each
seller having to demonstrate that such
mitigation suffices in place of the
default mitigation, unless a complainant
demonstrates that the RTO and ISO
monitoring and mitigation does not
suffice as to a particular seller.’’ 147 EEI
is concerned that the Commission may
unnecessarily burden sellers in the
organized markets with having to
demonstrate in each individual
proceeding that the RTO/ISO mitigation
measures suffice as an alternative to
Order No. 697’s default mitigation.
144 PSEG

Rehearing Request at 11–12.
148 NRG

145 Id.
146 Id.

at 12 (citing Wholesale Competition in
Regions with Organized Electric Markets, Advanced
Notice of Proposed Rulemaking, 72 FR 36276 (July
2, 2007), FERC Stats. & Regs. ¶ 32,617 (2007)
(considering potential reforms to attributes of
organized markets, including market monitoring).
147 EEI Rehearing Request at 4–5.

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103. NRG believes that Order No. 697
creates ambiguity regarding how the
Commission’s default market power
mitigation regime will interact with
existing mitigation regimes that have
been approved in organized RTO/ISO
markets. NRG asserts that this ambiguity
will discourage suppliers from building
new generation in constrained areas.
Thus, NRG seeks clarification, and,
alternatively, rehearing, on two points.
First, NRG asks that the Commission
clarify that it will rebuttably presume
that existing RTO/ISO regimes
adequately mitigate market power for
any sellers located in an RTO/ISO
market that fail to pass indicative
screens and a DPT analysis.148 Second,
in the event that a seller’s market power
is found not to be adequately mitigated,
the Commission should clarify that the
seller is allowed to propose its own
tailored mitigation measures not
necessarily based on embedded costs.149
104. On the first point, NRG explains
that the Final Rule does not explicitly
state that RTO/ISO monitoring and
mitigation protocols will provide
sufficient mitigation for any market
power presumed if a seller fails the
screens. NRG asserts that any generation
market power a seller might possess has
already been mitigated by those
protocols. Thus, such sellers should not
automatically be treated the same way
as other mitigated sellers and subjected
to default mitigation. However, NRG
contends that the Final Rule leaves in
question whether existing RTO/ISO
mitigation regimes or the conflicting
mitigation regime adopted in the Final
Rule will govern in future seller-specific
cases. NRG warns that this regulatory
uncertainty will put new investment at
risk, an outcome that should be avoided
given the great efforts made to put in
place alternatives to RMR contracts.150
In addition, NRG claims that the
ambiguity threatens to harm statesanctioned competitive procurement
programs, which typically require
binding bids which cannot be
conditioned on obtaining subsequent
Commission approval.151
105. Regarding the second requested
clarification, NRG notes that in several
places in the Final Rule, the
Commission states that it will retain
existing cost-based default mitigation
rates, but is unclear whether alternative,
tailored mitigation rates must be cost-

Frm 00018

Fmt 4701

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Rehearing Request at 2.
at 3.
150 Id. at 7 (citing Devon Power LLC, 115 FERC
¶ 61,340 (2006) (concerning the New England FCM
settlement) and PJM Interconnection, L.L.C., 117
FERC ¶ 61,331 (2006) (concerning the PJM RPM
settlement)).
151 Id. at 10–12.
149 Id.

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based. NRG seeks clarification that the
apparent limitation to cost-based
alternatives was inadvertent. In
addition, NRG states that ‘‘the
Commission should make clear that in
reviewing alternative mitigation
measures proposed by merchant
generators in RTOs, it will consider
whether the proposed measures will
support and attract necessary
investment on reasonable terms, and
recover the supplier’s cost of
capital.’’ 152
106. NYISO states that it is unclear
whether the Commission intended to
adopt a default mitigation measure that
would be inconsistent with its
previously approved market design and
mitigation measures for the NYISO’s
bid-based, uniform clearing-price
auction markets.153 In particular, NYISO
argues that there is no evidentiary or
policy basis that would justify the
imposition of default mitigation in the
form of a revenue cap, rather than a bid
cap, in Commission-approved
Locational Based Marginal Price
markets like NYISO.154
107. NYISO argues that the
imposition of default market power
mitigation in the form of revenue caps
rather than bid caps would be
incompatible with the principles
underlying uniform clearing price
auctions. NYISO ensures that the market
clearing price will either be a
competitive price or it will be a
mitigated price.155 Thus, NYISO
requests clarification that cost-based
mitigation will limit a mitigated entity’s
permissible maximum bid, but not
constrain the mitigated entity from
receiving the market clearing price if it
is not the marginal seller. Additionally,
NYISO argues that if the Commission’s
default cost-based mitigation is
interpreted to impose a revenue cap as
well as a bid cap, the NYISO states that
it will face significant administrative
Id. at 16.
153 NYISO Rehearing Request at 4 (citing New
York Independent System Operator, Inc., 89 FERC
¶ 61,196 (1999), order on compliance and reh’g, 90
FERC ¶ 61,317, clarified, 91 FERC ¶ 61,154 (2000)
(orders addressing the NYISO’s proposed Market
Mitigation Measures); New York Independent
System Operator, Inc., et al., 99 FERC ¶ 61,246
(2002) (order on the NYISO’s comprehensive
mitigation measures filing); Midwest Independent
Transmission System Operator, Inc., 108 FERC
¶ 61,163, at P 257, order on reh’g, 109 FERC
¶ 61,157 (2004) (‘‘We find that the conduct and
impact approach with its associated thresholds is
an appropriate approach to mitigation in the
Midwest ISO’s market. The conduct and impact
approach allows for a lighter handed approach to
mitigation, in which the market is allowed to
function as is, except when problems are
detected.’’)).
154 Id. at 7.
155 Id. at 2, 3, 5.

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152

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burdens if revenue caps are imposed
rather than bid caps.156
108. APPA/TAPS, on the other hand,
believe that the Commission should
clarify that a seller relying on RTO/ISO
mitigation to remedy its market power
must demonstrate those measures’
effectiveness. APPA/TAPS note that the
Final Rule indicates sellers can
incorporate existing RTO/ISO mitigation
as part of their market power analyses,
but asks for clarification that an
applicant must make a specific showing
that those mitigation measures in fact
address the specific concerns in the
market-based rate analysis. APPA/TAPS
assert that the scope of RTO/ISO
mitigation is much narrower than the
default, cost-based mitigation the
Commission prescribes; it notes that the
Commission has stated that RTO/ISO
mitigation and the market-based rate
analysis are different and that‘‘ ‘pieces
of one should not automatically be used
as precedent for the other.’ ’’ 157 APPA/
TAPS state that RTO/ISO mitigation
measures apply only to spot markets
and day-ahead and/or real time, but do
not apply to weekly, monthly or longterm transactions, including those
negotiated on a bilateral basis, and that
RTO/ISO mitigation is often far less
protective than the Commission’s costbased default of incremental cost plus
10 percent. APPA/TAPS explain that
they are not asking the Commission to
make a generic finding that all RTO/ISO
mitigation is insufficient to mitigate
sellers’ generation market power, but
that they seek a ruling that the burden
of proof that the RTO/ISO mitigation
adequately addresses the seller’s market
power falls on the seller, rather than
intervenors. If the Commission does not
make that clarification, APPA/TAPS
state that it should clarify that it will
allow intervenors to challenge such
claims and will give meaningful
consideration to those challenges.158
Commission Determination
109. The Commission denies the
requests of PSEG and Reliant to
reconsider its decision to require sellers
located in markets with Commissionapproved market monitoring and
mitigation to submit horizontal market
power analyses. As we explained in
Order No. 697, while the Commissionapproved market monitoring and
mitigation in RTO/ISO markets provides
protection against a seller’s ability to
exercise market power, it cannot replace
156 Id.

at 7.

157 APPA/TAPS

Rehearing Request at 24 (citing
Midwest Independent Transmission System
Operator, Inc., 109 FERC ¶ 61,157, at P 242 (2004),
order on reh’g, 111 FERC ¶ 61,043 (2005)).
158 Id. at 26–27.

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25849

the horizontal market power analyses
which provide the Commission and the
industry with critical information
regarding the potential market power of
sellers in the market.
110. We conclude that the dual
protections of individual market power
analyses and mitigation rules of the
RTO/ISOs provide the Commission with
better ability to discern and protect
against potential market power. While,
as discussed below, mitigation rules for
the individual RTO/ISOs in most cases
should be sufficient to guard against the
exercises of market power, we are not
comfortable at this time with dispensing
of the requirement for sellers in RTO/
ISOs to provide us with horizontal
market power analyses. Any
administrative burden of submitting
such analyses is outweighed by the
additional information gleaned with
respect to a specific seller’s market
power.
111. APPA/TAPS request that the
Commission clarify on rehearing that a
seller relying on RTO/ISO mitigation to
mitigate its market power must
demonstrate the effectiveness of those
measures. A number of other
petitioners, on the other hand, request
that the Commission clarify that it will
rebuttably presume that existing RTO/
ISO regimes adequately mitigate market
power for any sellers located in an RTO/
ISO market that fail the indicative
screens and the DPT analysis. In
response to these requests, to the extent
a seller seeking to obtain or retain
market-based rate authority is relying on
existing Commission-approved RTO/
ISO market monitoring and mitigation,
we adopt a rebuttable presumption that
the existing mitigation is sufficient to
address any market power concerns.
However, intervenors may challenge the
effectiveness of that mitigation. We
agree with PSEG that the challenging
party should have the burden of proof
to demonstrate that existing RTO/ISO
mitigation is not sufficient. Thus,
because existing RTO/ISO mitigation
has been found to be just and reasonable
by the Commission in the context of a
proceeding specific to a particular RTO/
ISO and involving all of its
stakeholders, we believe it appropriate
and clarify herein that there is a
rebuttable presumption that such RTO/
ISO mitigation is adequate to mitigate
market power in the RTO/ISO market,
including Commission-approved
mitigation applicable to RTO/ISO
submarkets such as In-City New York.
To the extent that a party wishes to
challenge that presumption, the
challenging party will have the burden
of proof.

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112. In response to EEI, to the extent
the Commission has considered a
challenge to existing mitigation and has
found it to be adequate, any additional
challenges must demonstrate a change
in circumstances rather than just
rearguing issues on which the
Commission has already ruled.
113. A number of petitioners raise
issues regarding the types of mitigation
that the Commission might impose on
mitigated sellers in RTOs/ISOs. NRG
requests that, in the event a seller’s
market power is found not to be
adequately mitigated, the Commission
should clarify that the seller may
propose tailored mitigation measures
that are not necessarily based on
embedded costs. NYISO states that it is
unclear whether the Commission
intended to adopt a default mitigation
measure for any sellers located in an
RTO/ISO market that fail to pass the
indicative screens and the DPT analysis
and seeks clarification that cost-based
mitigation will only limit a mitigated
entity’s permissible maximum bid, but
will not constrain the mitigated entity
from receiving the market clearing price
if it is not the marginal seller.
114. In response to these issues raised
regarding the types of mitigation that
the Commission might impose on
mitigated sellers in RTO/ISO, the
Commission will, depending on the
nature of the evidence submitted by an
intervenor, consider whether to institute
a separate section 206 proceeding that
would be open to all interested entities
to investigate whether the existing RTO/
ISO mitigation continues to be just and
reasonable and, if not, how such
mitigation should be revised. Any
intervenor in such a section 206
proceeding may present evidence on the
adequacy of the existing mitigation. If
appropriate, the Commission will
consider modifying that mitigation on
an RTO/ISO-wide basis, rather than on
a seller-specific basis, because RTO/ISO
mitigation is designed to mitigate
market power generally. In other words,
if existing mitigation is found to be
inadequate for a particular seller, then it
is likely to be insufficient for all
similarly situated sellers. We note that
in reviewing alternative mitigation
measures in the context of RTOs, the
Commission will consider whether the
proposed mitigation measures will
adequately deter the exercise of market
power, are consistent with the RTO/
ISO’s market design and will support
and attract necessary investment on
reasonable terms, and recover the
suppliers’ cost of capital. With regard to
NYISO’s request, as discussed above,
with regard to sellers located in an RTO/
ISO market that fail to pass the

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indicative screens and the DPT analysis,
we will not impose default cost-based
rate mitigation (which is used in nonRTO/ISO markets) in addition to RTO/
ISO mitigation. Rather, we adopt a
rebuttable presumption that the existing
mitigation is sufficient to address any
market power concerns.
115. With regard to APPA/TAPS’
assertion that the scope of RTO/ISO
mitigation is much narrower than the
default cost-based rate mitigation and its
argument that RTO/ISO mitigation
provides less protection than the
Commission’s default mitigation of
incremental cost plus 10 percent, we
understand that RTO/ISO mitigation
measures apply to day-ahead and/or
real-time markets, and we reiterate that
RTO/ISO mitigation is determined to be
just and reasonable when it is approved
by the Commission.159 We review and
approve mitigation rules in RTO/ISO
markets on the basis of the specific facts
and circumstances prevailing in such
markets. Thus, customers and other
interested parties are fully able, in the
context of those proceedings, to
comment on whether the mitigation
rules are sufficiently strong to deter the
exercise of market power. In addition,
pursuant to the Final Rule, customers or
other affected parties may argue, in the
context of a specific market-based rate
application or triennial review, that
changed circumstances have rendered
such mitigation no longer just,
reasonable and not unduly
discriminatory.
7. Use of Historical Data
Final Rule
116. The Commission held in the
Final Rule that it would retain the
‘‘snapshot in time’’ approach for the
indicative screens and the DPT, so that
sellers will be required to use actual
historical data for the previous calendar
year in their market power analyses.
After careful consideration of the
comments received, the Commission
chose not to adopt the NOPR proposal
that the DPT analysis allow sellers and
intervenors to account for changes in
the market that are known and
measurable at the time of filing. Instead,
the Commission decided to retain its
existing practice that sellers are required
159 APPA/TAPS rely on Midwest Independent
Transmission System Operator, Inc., 109 FERC
¶ 61,157, at P 242 (2004), order on reh’g, 111 FERC
¶ 61,043 (2005) (Midwest ISO) in arguing that RTO
mitigation and the market-based rate analysis are
different. We recognize that in Midwest ISO the
Commission stated that its market-based rate
analysis and mitigation in the Midwest ISO differ,
and, as stated above, we reiterate that RTO
mitigation is determined to be just and reasonable
when it is approved by the Commission.

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Fmt 4701

Sfmt 4700

to use unadjusted historical data in the
preparation of a DPT for a market-based
rate analysis and clarified that it would
require the use of the actual historical
data for the previous calendar year.
117. The Commission distinguished
this treatment from the approach in the
Commission’s merger analysis, which
requires applicants and intervenors to
account for changes in the market that
are known and measurable at the time
of filing. The Commission found that
the purpose of using the DPT in marketbased rate proceedings is different from
that in a merger analysis. Whereas a
merger analysis is forward-looking and
it is difficult and costly to undo a
merger, the market-based rate analysis is
a ‘‘snapshot in time’’ approach where
the Commission’s focus is on whether
the seller passes the indicative screens
and the DPT based on unadjusted
historical data. The Commission
considered that its grant of market-based
rate authority is conditioned on, among
other things, the seller’s obligation to
inform the Commission of any change in
status from the circumstances the
Commission relied on in granting it
market-based rate authority on an
ongoing basis. Thus, the change in
status reporting requirement allows the
Commission to evaluate changes when
they actually happen rather than relying
on projections, making it unnecessary
and redundant for the Commission to
allow sellers to account for known and
measurable changes in the DPT.
Requests for Rehearing
118. Montana Counsel argues that the
Commission erred in refusing to allow
adjustments to the DPT analysis to
account for known and measurable
future changes, such as contracts for the
sale of capacity belonging to the seller
that will expire during the term of its
market-based rate authority. Montana
Counsel asserts that by refusing to
consider known and measurable
changes, the Commission is
intentionally allowing the DPT analysis
to be conducted based on data and
assumptions that are known not to be
representative of reality.160 Montana
Counsel argues that it is inherently
irrational, arbitrary, and capricious to
allow companies whose generation
market power is being analyzed to
deduct the generation that is being
tested from its supply on grounds that
the generation is committed, as the
Commission does when the contracts for
power from that generation are expiring.
Montana Counsel states that such a
market power test is inherently flawed,
and that this flawed test has concrete
160 Montana

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
results, with negative impacts for
consumers. Montana Counsel cites the
Commission’s May 2006 renewal of PPL
Montana’s market-based rate authority,
in spite of the fact that the main utility
in Montana, NorthWestern Energy, must
buy from PPL Montana to serve its load,
as an example of the negative impact
that the market power test can have on
consumers.161
119. Montana Counsel notes that the
Final Rule distinguishes the marketbased rate process from the
Commission’s merger analysis by saying
that while mergers are difficult to undo,
sellers with market-based rate authority
must file change in status reports,
allowing the Commission to evaluate
changes when they happen. Montana
Counsel argues that the Commission
misses the point that if the change in
status is caused by the expiration of a
long-term contract for the sale of
capacity, then by the time the change in
status report is submitted, the seller may
have already re-sold the capacity at a
price reflecting the seller’s underlying
market power.162
120. Montana Counsel contends that
the refusal to consider known and
measurable changes is especially
inappropriate in light of the fact that the
Commission considers mitigation
proposed by the seller.163 Montana
Counsel argues that, if the Commission
will consider an applicant’s
‘‘ ‘propos[al] to transfer operational
control of enough generation to a third
party such that the applicant would
satisfy [the Commission’s] generation
market power concerns’ ’’ it should also
consider whether an applicant’s
available capacity will increase during
the market-based rate authorization
period when contracts expire.164
121. NRECA similarly asserts that the
Final Rule’s failure to require applicants
and allow intervenors to incorporate
known and measurable changes to
historical data in the indicative screens
and the DPT in favor of a rigid
‘‘snapshot’’ analysis of historical data is
arbitrary, capricious, contrary to law,

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161 Id.

at 7–8 (citing PPL Montana, LLC, 115 FERC
¶ 61,204 (2006) (PPL Montana)). Montana Counsel
includes its request for rehearing of PPL Montana,
filed June 16, 2006 in Docket No. EL05–124, et al.,
as Attachment A to its request for rehearing of
Order No. 697. Id. at 8. The Montana Counsel’s
rehearing request in the PPL Montana proceeding
asserts that the Commission’s decision to renew the
market-based rate authority of the PPL Montana
Companies is error insofar as it is contrary to record
evidence and the requirements of the Federal Power
Act. The Commission denied Montana Counsel’s
request for rehearing in PLL Montana LLC, 120
FERC ¶ 61,096 (2007).
162 Id. at 8–9.
163 Id. at 9 (citing Order No. 697 at P 25, 63 n.46).
164 Id.

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and in excess of statutory authority.165
NRECA argues that, if the Commission
knows a change will take place, it
would be arbitrary and capricious to
grant market-based rate authority based
on an assumption that the change will
not take place.166 Long-term contracts
will expire on a known schedule, and
the seller should not be allowed to
assume that the capacity will remain
committed to the buyer. According to
NRECA, the Commission cannot,
consistent with the FPA, ignore that
pending change in circumstances. At a
minimum, intervenors should have the
opportunity to demonstrate the
applicant’s market power using data
reflecting conditions after the contracts
expire.167
122. NRECA states that the
Commission’s reliance on change in
status filings as the means to report the
expiration of a long-term contract is
illogical and does not constitute
reasoned decision making.168 NRECA
believes that absent a full market power
analysis, it is impossible to adequately
determine the effect of the change.
NRECA submits that the triennial
review will often come too late to
protect customers.169
123. TDU Systems also argue that the
Commission should require applicants’
market-power analyses to reflect
imminent changes which are known
and measurable. They agree that
historical data are more objective, but
object that when they are not
representative of market conditions that
will exist during the three-year period of
market-based rate authority, considering
imminent changes is legally required.170
For soon-to-expire long-term contracts,
TDU Systems assert that the seller
should not be permitted to assume that
the capacity will remain committed to
the buyer. The burden should not be
shifted to the intervenors to propose the
adjustment; rather, an applicant should
be required to include it as part of the
analysis.171
165 NRECA Rehearing Request at 3, 21 (citing Cal.
ex rel. Lockyer v. FERC, 383 F.3d 1006 (9th Cir.
2004) (Lockyer); 5 U.S.C. 706(2)(A), (C)).
166 Id. at 21 (citing Mo. Pub. Serv. Comm’n v.
FERC, 337 F.3d 1066, 1075 (D.C. Cir. 2003)
(‘‘Reliance on facts that an agency knows are false
at the time it relies on them is the essence of
arbitrary and capricious decision making.’’)).
167 Id. at 22.
168 Id. (citing Motor Vehicle Mfrs. Ass’n, 463 U.S.
at 43; Pac. Gas & Elec. Co. v. FERC, 373 F.3d at
1319).
169 Id. at 23 (citing Lockyer, 383 F.3d at 1014–15.
See also TDU Systems Rehearing Request at 17.
170 TDU Systems Rehearing Request at 7, 16
(citing Mo. Pub. Serv. Comm’n v. FERC, 337 F.3d
1066, 1075 (D.C. Cir. 2003)).
171 Id. at 17.

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25851

Commission Determination
124. We will continue the use of
historical data for both the indicative
screens and the DPT in market-based
rate cases. We reject several petitioners’
requests that the Commission require
sellers to reflect imminent changes that
are known and measurable, and
therefore we deny rehearing on this
issue. Regarding the Commission’s
reliance upon historical rather than
projected data in analyzing market
power studies, and its determination not
to require sellers to reflect changes that
are known and measurable, the
Commission’s practice for many years
has been to use a ‘‘snapshot in time
approach’’ based on the most recently
available historical data at the time of
filing, i.e., to rely upon studies based on
unadjusted historical data. We continue
to allow intervenors to submit
sensitivity analyses including projected
data, but we reject the proposal that
applicants include adjustments to
historical data as part of the required
analyses.
125. There are several reasons why
this approach benefits customers and is
otherwise in the public interest. First, as
we explained in the Final Rule,
historical data are more objective,
readily available, and less subject to
manipulation by applicants than future
projections.172 If the Commission were
to allow applicants to submit studies
based on their future projections or that
reflect ‘‘imminent changes,’’ then sellers
would be able to selectively ‘‘cherry
pick’’ those changes that benefited the
seller in obtaining market-based rate
authorization while ignoring other
equally likely future changes that would
undermine the seller’s chances for
obtaining such authorization. Second,
this approach benefits customers, state
commissions and other affected
intervenors because it requires the use
of a consistent methodology that can be
replicated by intervenors, rather than
allowing sellers to submit customized
market power studies that, due to
myriad selective adjustments, are
difficult to analyze and can hide the
presence of market power. Third, it is
important to note that the ‘‘snapshot in
time’’ approach does not preclude the
Commission from considering future
changes in market conditions; rather,
the Commission’s grant of market-based
rate authority is conditioned, among
other things, on the seller’s obligation to
inform the Commission of any change in
status from the circumstances the
Commission relied upon in granting it
market-based rate authority.
172 Order

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Accordingly, the market-based rate
change in status reporting requirement
allows the Commission to evaluate
changes when they actually happen
rather than relying on projections,
making it unnecessary and redundant
for the Commission to allow sellers to
account for predicted changes in the
DPT for market-based rate purposes.
126. Furthermore, accounting for
‘‘imminent changes’’ would be
excessively burdensome with regard to
expiring contracts because, for an
accurate representation, a review of all
expiring contracts and all contracts
being negotiated inside all balancing
authority areas in the relevant market
and the seller’s first-tier markets might
be necessary. In addition, because the
definition of ‘‘imminent’’ is a matter of
interpretation and may change
depending on the circumstances, it
would produce regulatory uncertainty.
Furthermore, future changes are not
necessarily known and measurable. For
example, a long-term contract may be
expiring in a year, but until it expires,
it often can be renewed for the same
term(s). Therefore, an analysis that
assumes that the long-term capacity of
that contract was uncommitted would
not always be correct, and therefore
could overstate the seller’s market
power. When a change does occur the
Commission has a method to evaluate
the new situation through its
requirement that sellers with marketbased rate authority report changes in
status and what effect, if any, such a
change has on the grant of market-based
rate authority. In any event, the
Commission may require a full market
power analysis at any time including as
a result of a seller’s change in status
filing.
127. With regard to Montana
Counsel’s argument that the
Commission should allow evidence of
known and measurable changes rather
than a strict adherence to historical data
because if a change in status is caused
by the expiration of a long-term contract
for the sale of capacity, then by the time
a seller’s change in status filing is
submitted, a seller may have already resold the capacity at a price reflecting the
seller’s underlying market power, we
recognize that a seller’s change in status
filing would not be filed until after a
long-term contract expires. However,
there are countervailing reasons why the
Commission believes that the use of
historical data is appropriate and
reaffirms its practice of using a
‘‘snapshot in time approach.’’ 173 As
173 For the reasons stated above, we also reject
NRECA’s argument that the triennial review and the
change in status filing will come too late.

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explained above, the Commission
adopted this approach because
historical data are more objective,
readily available, and less subject to
manipulation by sellers than future
projections. We reiterate our concern
that if the Commission were to require
sellers to submit studies or change in
status filings based on their future
projections such as ‘‘imminent
changes,’’ then sellers would be able to
selectively ‘‘cherry pick’’ those changes
that benefited the seller in retaining
market-based rate authorization while
ignoring other equally likely future
changes that would undermine the
seller’s chances for obtaining or
retaining market-based rate
authorization. Similarly, intervenors
could introduce only those imminent
changes that result in higher market
shares for a seller, thus artificially
increasing the seller’s market shares. In
addition, requiring a seller to submit
market power analyses that reflect
future or ‘‘imminent changes’’ such as
the future expiration of a long-term
contract would be excessively
burdensome because, for an accurate
representation, review of all expiring
contracts, and all contracts being
negotiated inside the relevant market
and the seller’s home balancing
authority area and its first-tier markets
may be necessary. Otherwise, the
seller’s analysis might be incomplete
and produce invalid results.
128. In addition, as explained above,
future changes are not necessarily
known and measurable since a longterm contract may be expiring in a year,
but until it expires, it often can be
renewed for the same term. Likewise,
the Commission does not allow the
seller to deduct capacity that it is
currently negotiating to sell to third
parties. To do so would allow the seller
to argue that it has an ‘‘imminent’’ sale
and the Commission should consider
that capacity to be committed, resulting
in lowering the seller’s market shares.
The danger in this circumstance is, like
the expiring contract that could be
extended, the sale may not actually
occur and the seller could appear to
have rebutted the presumption of
market power when in fact, based on
actual data, it has market power.
Therefore, an analysis that assumes that
the long-term capacity associated with
an expiring contract is uncommitted
would not always be correct. In
addition, because the definition of
‘‘imminent’’ is a matter of interpretation
and may change depending on the
circumstances, it would produce
regulatory uncertainty. For all of these
reasons, our determination to rely on

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unadjusted historical data in the
indicative screens and the DPT analysis
is based on reasoned decision making.
129. Notwithstanding our policy
requiring the use of historical data and
a ‘‘snapshot in time approach,’’ in
previous cases we nevertheless have
addressed evidence presented by
intervenors who sought to demonstrate
that upon expiration of a long-term
contract, a seller would be able to
exercise market power.174 Indeed, in
cases where this issue has arisen, the
Commission considered the impact of
the expiring long-term contract on the
seller’s market power and concluded
that even when adjustments were made
to the available economic capacity
measure to account for expiring
contracts, the seller did not fail the
indicative screens.175
130. While we continue to believe
that the ‘‘snapshot in time approach’’ is
appropriate, and will continue to
require the use of historical data in the
market power analysis, we nevertheless
will consider, on a case-by-case basis,
clear and compelling evidence
presented by sellers and intervenors that
seek to demonstrate that certain changes
in the market, such as the expiration of
a long-term contract, should be taken
into account as part of the market power
analysis in a particular case. Entities
who seek to make this demonstration
must present clear and compelling
evidence in support of their argument.
The Commission will address any
countervailing factors that affect
whether the seller will have the ability
to exercise market power. Such
countervailing factors could include,
but are not limited to, any competitor
that similarly has expiring long-term
contracts and any other factors that
might impact the market power analysis
such as plant retirements, transmission
access, and generation upgrades. In this
regard, we remind entities that they
must perform the market power screens
as designed but may also provide a
sensitivity analysis consistent with the
discussion above.
131. We reject Montana Counsel’s
argument that, if the Commission
considers a seller’s proposal to transfer
operational control of enough
generation to a third party as part of its
proposed mitigation so that the seller
would satisfy the Commission’s
horizontal market power concerns, then
the Commission should also consider
imminent changes that would increase a
174 PPL Montana, LLC, 115 FERC ¶ 61,204, at P 46
(2006), order denying reh’g, 120 FERC ¶ 61,096, at
P 52–54 (2007); Boralex Livermore Falls LP, 122
FERC ¶ 61,033, at P 43 (2008).
175 Id.

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
seller’s market shares. Consideration of
a proposal to transfer operational
control of generation as part of a seller’s
proposed mitigation, unlike
consideration of imminent changes as
part of a seller’s market power analysis,
does not run the risk that a seller’s
market power may be hidden. Moreover,
the act of transferring control may be
enough to reduce the seller’s market
shares sufficiently to address market
power concerns.
8. Transmission Imports

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Final Rule
132. 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 (SIL) study.176 Thus, a
seller that owns transmission will be
required to conduct simultaneous
transmission import capability studies
for its home balancing authority area
and each of its directly-interconnected
first-tier balancing authority areas
consistent with the requirements set
forth in the April 14 Order, as clarified
in Pinnacle West Capital Corp.177 The
Commission commented that ‘‘the SIL
study is ‘intended to provide a
reasonable simulation of historical
conditions’ and is not ‘a theoretical
maximum import capability or best
import case scenario.’ ’’ 178 To determine
the amount of transfer capability under
the SIL 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 OASIS
operating practices. The Commission
will also continue to allow sensitivity
studies, but the sensitivity studies must
be filed in addition to, not in lieu of, an
SIL study.179
133. In response to a commenter’s
suggestion, the Commission stated it
would allow the use of simultaneous
total transfer capability (TTC) values,
provided that these TTCs are the values
that are used in operating the
transmission system and posting
availability on OASIS. In addition, the
Commission stated that ‘‘[s]ellers
submitting simultaneous TTC values
must provide evidence that these values
account for simultaneity, account for all
internal transmission limitations,
account for all external transmission
176 Order

No. 697 at P 354.
FERC ¶ 61,127 (2005).
178 Order No. 697 at P 354 (internal citations
omitted).
179 Id. P 355.
177 110

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limitations existing in first-tier areas,
account for all transmission reliability
margins, and are used in operating the
transmission system and posting
availability on OASIS.’’180
134. The Commission also agreed
with several commenters that short-term
firm reservations can be unpredictable,
driven by real-time system conditions,
and do not necessarily indicate that the
associated transmission capacity is not
available for competing supplies. Thus,
the Commission concluded that, in
calculating simultaneous transmission
import limits, short-term reservations of
28 days or less in effect during the study
periods need not be accounted for.181
135. The Commission stated that
when actual OASIS practices conflict
with the instructions in Appendix E of
the April 14 Order, sellers should follow
OASIS practices and must provide
documentation of these practices.182
The Commission further stated that the
SIL is a benchmark of historical
conditions, including peak load, and
that if additional supplies could be
imported above a market’s study year
peak load, the Commission will
consider a sensitivity study that is
submitted in addition to the required
SIL study and supported by record
evidence.183
136. The Commission adopted the
requirement for use of the SIL study as
a basis for transmission access for both
the indicative screens and the DPT
analysis.184 The Commission stated that
this requirement assures that all factors
important in determining transmission
access to the seller’s market are taken
into account.185
Requests for Rehearing
137. APPA/TAPS request clarification
that the use of simultaneous TTC in the
SIL study must properly account for all
firm transmission reservations,
transmission reliability margin, and
capacity benefit margin.186 First, APPA/
TAPS assert that the Commission
should state that clarifications provided
in the Final Rule regarding firm
reservations apply to any use of
simultaneous TTC.187 APPA/TAPS
argue that transmission reserved by a
third party should not be doublecounted via pro-rata allocation of

unused transmission capacity.188
Second, APPA/TAPS read the Final
Rule’s mention of the need for
simultaneous TTC to ‘‘account for all
transmission reliability margins’’ 189 as
affirming that TRM set-asides should
not be included in transmission
capability, consistent with the July 8
Order.190 Third, APPA/TAPS ask the
Commission to affirm that it will apply
to simultaneous TTC its prior findings
in the July 8 Order that CBM set-asides
should be reflected in transmission
capability as non-firm capability unless
they are used for reliability during
seasonal peaks, in which case they
should not be treated as part of import
capability.191 APPA/TAPS point out
that transmission providers do not make
CBM available on a firm basis, and
when it is used for reliability, it should
not be deemed available at all to
competing suppliers.192
138. Southern states that the Final
Rule concludes that short-term
reservations of more than 28 days are to
be ‘‘accounted for’’ in the simultaneous
study, which suggests that they should
be deducted from the resulting import
values. Southern submits that this
treatment, if intended by the
Commission, is inappropriate and thus
should be reconsidered.193 Instead,
Southern argues that such reservations
should be assigned to the entity ‘‘that
actually controls that generation
capacity on a long-term basis and who,
by virtue of that long-term control,
might actually receive extra financial
benefits if the exercise of market power
in wholesale electricity markets caused
wholesale prices to rise.’’ 194 Southern
argues that there is a conflict between
the section on Control and
Commitment, where the Commission
concludes ‘‘that the determination of
control is appropriately based on a
review of the totality of circumstances
on a fact-specific basis,’’ 195 and the SIL
section that effectively assigns to
applicants any short-term purchases
that they make between one month and
one year in duration so long as those
purchases are covered with firm
transmission reservations. 196
139. Southern argues that the
Commission’s ‘‘after-the-fact’’
examination of short-term transmission
reservations to see how many were more

180 Id.

188 Id.

181 Id.

189 Order

P 364.
P 368.
182 Id. P 356.
183 Id. P 361.
184 Id. P 384.
185 Id. P 386.
186 APPA/TAPS Rehearing Request at 28–29
(citing Order No. 697 at P 364, 369; July 8 Order,
108 FERC ¶ 61,026).
187 Id. at 28 (citing Order No. 697 at P 369).

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25853

No. 697 at P 364.
Rehearing Request at 28–29.
191 Id. at 29.
192 Id.
193 Southern Rehearing Request at 32.
194 Id. at 32–33 (quoting Frame Affidavit at ¶ 20).
195 Order No. 697 at P 174.
196 Southern Rehearing Request, Frame Affidavit
at ¶ 19.
190 APPA/TAPS

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than 28 days in duration and who made
those reservations is arbitrary and
capricious decision-making. Southern
also contends that the Final Rule is
ambiguous and internally inconsistent
when the Commission states that shortterm firm transmission reservations
longer than 28 days must be accounted
for in the simultaneous import
capability study.197 The Final Rule also
provides that applicants do not need to
account for short-term reservations of
one month or less. However, according
to Southern, the Commission then
arbitrarily states that since the shortest
month of the year has only 28 days (in
non-leap years), reservations longer than
28 days must be accounted for in a
simultaneous import capability study.
Thus, the Final Rule is internally
inconsistent with regard to what
constitutes a month, and the
Commission selected the length of a
month that is contrary to the evidence
and is thus arbitrary and capricious.198
According to Southern, the Commission
should grant rehearing and make clear
that applicants are not required to
address short-term firm transmission
reservations in their simultaneous
import capability studies.199
140. Southern states that although
Appendix E required the use of
generation scaling for calculating
simultaneous import limit, the Final
Rule allowed sellers to use another
methodology when their actual OASIS
practice conflicts with the instructions
in Appendix E. Based on this
clarification, Southern states that
Southern is to use the same load shift
methodology that it has historically
used in calculating transfer capability
for OASIS posting instead of the
Appendix E mandated generation
scaling. Southern states that in order to
simulate a power transfer under the load
shift methodology to determine
simultaneous import capability into the
Southern Companies’ balancing
authority area for seasonal peak
conditions, load in the power flow case
is initially set to the seasonal peak load
level and served by a comparable
amount of generation in accordance
with the engineering principle that for
each control area, generation must equal
load plus losses plus interchange.
197 Id.

at 33.
at 34 (citing General Chemical Corp., 817
F.2d at 857 (reversing an order that was internally
inconsistent); East Texas Electric Co-op v. FERC,
218 F.3d 750, 754 (D.C. Cir. 2000); McElroy Elecs.
Corp. v. FCC, 990 F.2d 1351, 1358 (D.C. Cir. 1993);
Motor Vehicle Mfrs. Ass’n, 463 U.S. at 43 (finding
that agency rule would be arbitrary and capricious
if the explanation runs counter to the evidence
before the agency); FPL v. Lorion, 470 U.S. 729, 744
(1985)).
199 Id. at 34–35.

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198 Id.

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According to Southern, in order to
perform transfer analysis using the load
shift methodology, load is uniformly
increased in the Southern Companies
balancing authority area, while load is
simultaneously decreased in first-tier
control areas to simulate the appropriate
transfer of power between the areas.
Southern states that this commonly
used methodology has the effect of
increasing loads during the transfer to
levels that, by definition, exceed the
seasonal peak load represented in the
power flow case.200 Southern requests
clarification that, for purposes of
performing transfer analysis under the
load shift methodology, transmission
providers may allow the load shift
methodology to effect load levels that
are higher than the historical peak load
levels as the means of simulating
transfers. Otherwise, Southern contends
that the Final Rule will contain
inherently conflicting provisions that,
on the one hand direct the use of
historical practices related to load shift
transfer analyses, but at the same time
forbid the methodological process
whereby the load shift approach
simulates the power flows under
study.201
141. Southern agrees that a
simultaneous import capability study
conducted in accordance with
Appendix E or historical practice for
seasonal peaks may be appropriate for
the indicative screens. Further, the same
study approach used for the screens
may be appropriate for use in a DPT.
However, Southern states that there is
no legal or policy justification for
seeking a more complete analysis of
competitive conditions on the
generation side, while not permitting a
comparable effort pertaining to
transmission. Southern argues that to
treat these issues differently could
potentially lead to serious distortions of
the competitive analysis. Therefore,
Southern requests that the Commission
clarify that the Final Rule does not
foreclose an applicant from presenting a
more thorough simultaneous import
capability study based upon historical
conditions as part of a DPT study. Of
course, any such presentation would
have to be considered on a case-specific
basis and it would have to be consistent
with the fundamental determinations of
Appendix E related to simultaneous
feasibility, historical practices and the
like.202
200 Id.

at 31.

201 Id.
202 Id.

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Commission Determination
142. In response to the comments
from APPA/TAPS, we clarify that the
use of simultaneous TTC in the SIL
study must properly account for all firm
transmission reservations, transmission
reliability margin, and capacity benefit
margin. We agree that the clarifications
provided in the Final Rule regarding
firm reservations apply to all
simultaneous transmission import limit
studies, including those that use
simultaneous TTC.203 We agree that
transmission reserved by a third party
should not be double-counted, such as
by assuming it is available a second
time to other competitors via pro-rata
allocation of unused transmission
capacity.204 We affirm that the Final
Rule’s mention of the need for
simultaneous TTC to ‘‘account for all
transmission reliability margins’’ 205
means that TRM set-asides should not
be included in transmission capability,
consistent with the July 8 Order.206 We
also affirm that our prior findings in the
July 8 Order that capacity benefit
margin set-asides should be reflected in
transmission capability as non-firm
capability unless they are used for
reliability during seasonal peaks, in
which case they should not be treated
as part of import capability, also apply
to studies that use simultaneous TTC.207
APPA/TAPS has correctly interpreted
the Final Rule in these respects.
143. Southern argues that there is
inconsistency between the proposed
treatment of short-term transmission
reservations and the Control and
Commitment section of Order No. 697.
We disagree. In the Control and
Commitment section, we refer to the
control of a generation asset, including
the ability to dispatch the generation
asset. In the SIL section, we refer to a
firm transmission reservation. These are
different. The objective of the SIL
calculation is to determine the amount
of transmission imports available to
bring in supply from first-tier areas.208
203 Order

No. 697 at P 369.
Rehearing Request at 28.
205 Order No. 697 at P 364.
206 APPA/TAPS Rehearing Request at 28–29.
207 Id. at 29.
208 The Commission recognizes that there may be
confusion concerning the use of a pro-rata
allocation of generation capacity when performing
a simultaneous transmission import limit (SIL)
study and the requirement that, when performing
the indicative screens, ‘‘[a]ny simultaneous
transmission import capability should first be
allocated to the seller’s uncommitted remote
generation. Any remaining simultaneous
transmission import capability would then be
allocated to any uncommitted competing supplies.’’
See Order No. 697 at P 38.
With regard to performing a SIL study, pro-rata
allocation is used to assign shares to two ‘‘groups’’
204 APPA/TAPS

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An applicant’s firm transmission
reservations represent transmission that
is not available to competing suppliers.
Applicants who believe that their firm
transmission reservations should be
treated as available to import competing
supply may present evidence that the
Commission will consider on a case-bycase basis.
144. In response to Southern’s
comments regarding short-term
transmission reservations, we clarify
that for the reasons described in Order
No. 697,209 applicants are not required
to address short-term firm reservations
in the market power screens. Currently,
the Commission’s EQR 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.210
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. 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. It is not
practical to require applicants to
provide data on every transmission
reservation, yet we cannot ignore the
impact of transmission reservations on
the potential for market power.
of uncommitted generation capacity in the
aggregated first-tier market. The seller must first
calculate the sum of its owned and affiliated
uncommitted generation capacity, then it must sum
all other sellers’ uncommitted generation capacity.
The seller then divides these two numbers to
compute a ratio of the seller’s (and affiliated)
uncommitted generation capacity to all other
sellers’ uncommitted generation which determines
the ‘‘share’’ that each seller is allocated to import
into the study area. In other words, when
performing the SIL study, any uncommitted
generation capacity in the aggregate first-tier market
is allocated pro-rata for the purpose of determining
the value of the SIL.
With regard to performing the indicative screen
analyses, all of the seller’s and its affiliated
uncommitted generation capacity in first-tier
markets (remote capacity) should be allocated to the
seller’s total uncommitted capacity in the relevant
market (study area), up to the SIL limit. Any
remaining simultaneous transmission import
capability is then allocated to any uncommitted
competing generation.
For example, if the SIL limit is 200 MW, the seller
and its affiliates’ uncommitted generation capacity
in first-tier markets is 150 MW, and competing
uncommitted generation capacity in first-tier
markets is 350 MW, then to properly perform the
indicative screens the seller’s uncommitted
generation capacity in the relevant market is
increased by 150 MW and competing supply in the
relevant market is increased by 50 MW.
209 Order No. 697 at P 368.
210 Order Adopting Electric Quarterly Report Data
Dictionary, Order No. 2001–G, 72 FR 56735 (Oct. 4,
2007), 120 FERC ¶ 61,270, at P 35 (2007).

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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,
we will require applicants to allocate
their seasonal and longer transmission
reservations to themselves from the
calculated SIL, where seasonal
reservations are greater than one month
and less than 365 consecutive days in
duration, as defined in the
Commission’s EQR Data Dictionary.
145. We grant the clarification
Southern seeks in part. We would allow
sellers to use load shift methodology to
calculate 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 SIL number compares had
the company used a generation shift
methodology.
146. In response to Southern’s request
for clarification regarding whether
applicants may present more thorough
simultaneous import capability studies
based upon historical conditions as part
of a DPT study, we clarify that, as we
stated in the Final Rule, applicants may
submit additional sensitivity studies,
including a more thorough import study
as part of the DPT. We reaffirm,
however, that any such sensitivity
studies must be filed in addition to, and
not in lieu of, an SIL study.211
9. Further Guidance Regarding Control
and Commitment of Capacity
147. 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 factspecific basis. We explained that no
single factor or factors necessarily
results in control. We 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. 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.212
148. We 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, we 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 our
determinations of control on a factspecific basis. We explained, however,
that we continue our historical
approach of relying on a set of
principles or guidelines to determine
what constitutes control. Thus, we
stated that we continue 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. We explained that our
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.213
149. We declined to adopt
commenters’ suggestions that we require
all relevant contracts to be filed for
review and determination by the
Commission as to which entity controls
a particular asset (e.g., with an initial
application, updated market power
analysis, or change in status filing).
While we 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, we explained that the Commission
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. Our
historical practice has been to place on
the filing party the burden of
determining which entity controls an
asset. Therefore, we 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 the
generation facility, but explained that
the Commission retains the right at the
Commission’s discretion to request the
seller to submit a copy of the underlying
agreement(s) and any relevant
supporting documentation.
150. Given the increased level of
investment in the electric utility
industry as a result of the Energy Policy
Act of 2005 (EPAct 2005) 214 and our
implementing rules and regulations, we
find it necessary to provide further
guidance with respect to the
representations that a seller should
make regarding which entity controls a
particular asset. An increasing number
213 Id.

211 Id.

P 355.
212 Order No. 697 at P 174.

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P 175.
Policy Act of 2005, Pub. L. No. 109–
58, 119 Stat. 594 (2005).
214 Energy

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of investors are acquiring interests in
assets that may be relevant to a seller’s
market-based rate authority. As we
explained in Order No. 697, we will
continue to place on the filing party the
burden of determining which entity
controls an asset. We will rely on the
seller’s representations regarding
control, absent extenuating
circumstances. Therefore, to provide
further guidance to the industry, we
reiterate 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. In doing so, the
seller should make its representation in
light of our discussion in Order No. 697
and cite to that order as the basis for
which it has made its determination.
B. Vertical Market Power
1. OATT Violations and Market-Based
Rate Revocation

jlentini on PROD1PC65 with RULES2

Final Rule
151. In the Final Rule, the
Commission stated it will revoke an
entity’s market-based rate authority in
response to an OATT violation upon a
finding of a nexus between the specific
facts relating to the OATT violation and
the entity’s market-based rate authority,
and reiterated that an OATT violation
may subject the seller to other remedies
the Commission may deem appropriate,
such as disgorgement of profits or civil
penalties.215 The finding that an OATT
adequately mitigates transmission
market power rests on the assumption
that individual entities comply with the
OATT and that there may be OATT
violations in circumstances that, after
applying the factors in the Enforcement
Policy Statement,216 merit revocation or
limitation of market-based rate
authority. The Final Rule found,
however, that it is inappropriate to
revoke a seller’s market-based rate
authority for an OATT violation unless
there is a nexus between the specific
facts relating to the OATT violation and
the seller’s market-based rate authority.
The Commission declined to adopt a
rebuttable presumption that any OATT
violation has the requisite nexus to
support revocation of market-based rate
authority, explaining that there is a
wide range of types of OATT violations,
including ones that may be inadvertent
and others that are neither intended to
affect, nor in fact affect, the market-

based rate sales of the transmission
provider or its affiliates.217
152. The Commission stated that
determining what constitutes a
sufficient factual nexus is best left to a
case-by-case consideration, explaining
that the wide range of positions among
commenters on how to define a
sufficient factual nexus itself suggested
that this finding is best made after
review of a specific factual situation.
Some commenters had asserted that a
finding of a ‘‘material’’ violation of the
OATT would be sufficient. The
Commission disagreed. While a seller’s
inconsequential OATT violation would
not serve as a basis for revoking that
entity’s market-based rate authority, the
Commission stated that revocation is
warranted only when an OATT
violation has occurred and the violation
had a nexus to the market-based rate
authority of the violator or its
affiliates.218 The Commission also
clarified that it will allow intervenors
on a case-by-case basis to file evidence
if they believe they have been denied
transmission access in violation of the
OATT.219
153. The Commission emphasized in
the Final Rule that it has discretion to
fashion remedies for OATT violations
that relate to the violator’s market-based
rate authority in instances in which the
Commission does not find sufficient
justification for revocation of that
authority. For example, in appropriate
circumstances, the Commission may
modify or add additional conditions to
the violator’s market-based rate
authority or impose other requirements
to help ensure that the violator does not
commit future, similar misconduct. The
Commission also explained that it will
consider whether to impose sanctions
such as assessment of civil penalties for
particularly serious OATT violations in
addition to revocation of the violator’s
market-based rate authority.220
Requests for Rehearing
154. NRECA and TDU Systems argue
that the Final Rule’s determination that
the Commission will not revoke the
market-based rate authority of a public
utility or its affiliates upon the utility’s
violation of its OATT unless there is a
‘‘nexus’’ between the ‘‘specific facts’’ of
the violation and the violator’s marketbased rate authority is arbitrary,
capricious, contrary to law, and in
excess of statutory authority. NRECA
also argues that the Final Rule does not

215 Order

217 Order

216 Enforcement

218 Id.

No. 697 at P 417.
of Statutes, Orders, Rules and
Regulations, 113 FERC ¶ 61,068 (2005)
(Enforcement Policy Statement).

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No. 697 at P 417.
P 418.
219 Id. P 421.
220 Id. P 419.

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provide clear guidance as to what would
constitute a sufficient nexus.221
155. TDU Systems state that the
Commission must clarify the
circumstances in which it will find that
there is a sufficient nexus between a
transmission provider’s OATT
violations and the revocation of marketbased rate authorization of the provider
or its affiliates, and reconsider its
decision to determine what constitutes
a sufficient factual nexus on a case-bycase basis.222 TDU Systems state that,
apart from trivial violations, which
could be screened out by the kind of
materiality filter suggested by APPA/
TAPS,223 the Commission has not
explained why material OATT
violations should not create at least a
presumption that market-based rate
authorization is inappropriate.224 TDU
Systems state that, because having an
OATT on file and being bound by its
terms are necessary to mitigating the
public utility’s vertical market power,
there is logical reason to be concerned
that a violation may have undermined a
premise for the authorization. TDU
Systems therefore assert that an OATT
violation should automatically trigger a
Commission proceeding in which the
violator has the burden of justifying its
continued market-based rate
authority.225 Furthermore, TDU Systems
state that shifting the burden to the
transmission provider could encourage
transmission providers to be in full
compliance with coordinated and open
regional planning.226
156. TDU Systems also argue that the
Commission needs to address further
the content of the ‘‘nexus’’ requirement.
They contend that transmission-owning
public utilities might read Order No.
697 to allow for revocation of their
market-based rate authority only when
it would be arbitrary and capricious for
the Commission not to do so.227 TDU
Systems contend that the Commission
has offered no clue to understanding
why it may be relevant whether the
alleged violator has committed an
OATT violation in order to further a
specific sale under its own market-based
rate tariff or that of an affiliate. TDU
Systems conclude that if such a
connection is indeed critical, there
would appear to be a substantial danger
of deflecting attention from the
characteristics of a transmission
221 NRECA Rehearing Request at 28 (citing Order
No. 697 at P 418).
222 TDU Systems Rehearing Request at 8, 20.
223 Id. at 21 (citing APPA/TAPS Initial Comments
at 81).
224 Id. at 8, 21.
225 Id. at 21.
226 Id. at 8.
227 Id. at 22.

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provider’s conduct, i.e., whether it is
anticompetitive or reflects the exercise
of market power.228
157. These petitioners claim that the
Commission’s position appears to place
the burden of proof on customers,
competitors, or the Commission to
demonstrate the nexus, rather than
requiring the violator to demonstrate the
lack of any such nexus.229
158. NRECA asserts that when a
public utility violates its OATT, one of
the preconditions to the grant of marketbased rate authority is violated. It argues
that, under the FPA, the seller, not
customers, must bear the burden of
proof that its continuing sales under its
market-based rate tariff remain at just
and reasonable levels.230 NRECA
therefore contends that there should be
a presumption that there is a ‘‘nexus’’
between the OATT violation and the
seller’s market-based rate authority.231
NRECA states that the burden,
consistent with the FPA, should be on
the seller to rebut this presumption;
however, it suggests that the
Commission could evaluate the seller’s
showing, and if the issue is in doubt, set
the matter for investigation or hearing
and order a temporary suspension of
market-based rate authority until the
matter is resolved.232
Commission Determination
159. The Commission denies
rehearing of the decision to require a
factual nexus between a substantial
OATT violation and the entity’s marketbased rate authority to justify revocation
of that authority. As the Commission
explained in Order No. 697, the ‘‘nexus
condition’’ is required in order to ensure
that our actions are not arbitrary or
capricious or based on an inadequate
factual record. We disagree with NRECA
and TDU Systems that any material
OATT violation should necessarily
justify revocation of the entity’s marketbased rate authority since the violation
may have no relation to the marketbased rate authority. In such
circumstances, the Commission will
consider such other remedies as may be
appropriate. We also decline to provide
specific examples of what would
constitute a sufficient nexus between an
entity’s market-based rate authority and
an OATT violation because the factual
circumstances involved in a claimed
violation will be unique to the company
and, therefore, any list would be
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228 Id.
229 NRECA Rehearing Request at 3, 27–29; TDU
Systems Rehearing Request at 3–4, 20.
230 NRECA Rehearing Request at 28 (citing
Lockyer, 383 F.3d at 1014–15; 16 U.S.C. 824d(e)).
231 Id. at 29.
232 Id.

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incomplete. This is especially true in
light of continually developing markets.
We continue to believe that the
determination of what would be a
sufficient factual nexus between an
OATT violation and revocation of the
violator’s market-based rate authority is
best left to case-by-case consideration.
160. With regard to the transmission
provider’s planning obligations in
particular, violations of the planningrelated requirements of the pro forma
OATT may or may not have a sufficient
factual nexus with the transmission
provider’s market-based rate authority.
A case-by-case analysis will be
necessary to determine if the violation
justifies revocation of the transmission
provider’s market-based rate authority.
We agree with TDU Systems that OATT
violations by a transmission provider
that may not be explicitly connected
with its market-based rate authorization
may nonetheless promote conditions in
which the violator could gain an
advantage in future transactions.
However, we note that this is an
example of why a case-by-case
determination is needed so that the
Commission can consider the violation,
the seller’s market-based rate authority,
and market conditions in determining
what remedy, if any, best suits the
situation. Therefore, we will apply the
mechanisms adopted in Order No. 890
to aid us in determining on a case-bycase basis if a particular violation puts
that company at an advantage vis-a´ -vis
its market-based rate authority.233
161. We disagree with TDU Systems
and NRECA that the Commission
inappropriately shifted the burden of
proof regarding whether there is a
nexus. We anticipate that the
Commission’s consideration of a seller’s
OATT violation and whether or not
there is a nexus with its market-based
rate authority would normally arise as
part of a Commission-initiated
enforcement proceeding. In enforcement
proceedings, the Commission has
considerable discretion in how to
fashion an appropriate remedy and the
burden of justifying any remedial
actions taken against a violator,
including revocation of market-based
rate authority and determining what
remedies are required to ensure that any
future sales, market-based rate or
otherwise, are at just and reasonable
rates. Moreover, even if the issue arose
in publicly noticed proceedings (such as
a section 206 or 306 complaint), the
Commission would exercise its remedial
discretion based on the facts presented
and accordingly bear the burden of
233 See Order No. 890–A, FERC Stats. & Regs.
¶ 31,261 at P 1037.

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25857

justifying any remedy imposed on the
transmission provider for a violation of
its OATT. Whether or not a violation
justifies revocation of the seller’s
market-based rate authority will depend
on the facts and circumstances involved
in each case; therefore, it would not be
appropriate to adopt a presumption of
that nexus, as requested by petitioners.
The Commission will make a
determination based on the facts of each
particular case as to whether or not an
OATT violation has a nexus to the
seller’s market-based rate authority. In
sum, the Commission’s action in Order
No. 697 does not shift the burden of
proving a nexus to customers and
competitors.
162. Contrary to TDU Systems’
assertion, Order No. 697 does not limit
the Commission to revoking a seller’s
market-based rate authority only in
circumstances where it would be
arbitrary and capricious not to do so. If
an OATT violation occurs, the
Commission will investigate whether or
not the facts surrounding the violation
have a nexus to the seller’s marketbased rate authority. It would not be just
and reasonable for the Commission to
revoke a seller’s market-based rate
authority if in fact the violation had no
bearing on the seller’s market-based rate
position. The way to make such a
determination is based on an adequate
factual record and that is what would be
established in such a proceeding before
making any determinations.
2. Treatment of FTRs
Final Rule
163. In the Final Rule, the
Commission stated that provisions
concerning the reassignment or sale of
transmission capacity or firm
transmission rights, congestion
contracts, or fixed transmission rights
(as a group, FTRs) are not required to be
included in a seller’s market-based rate
tariff, nor is it appropriate to include
transmission-related services in a
seller’s market-based rate tariff.234 The
Commission explained that
Commission-approved market rules for
RTO/ISOs address resales of FTRs and
virtual trading to ensure that no market
power is exercised in such trades. In
addition, sellers engaging in these
activities sign a participation agreement
with RTO/ISOs which require them to
abide by those market rules. Hence, the
approval of the market rules in
conjunction with approval of the
generic participation agreement by the
Commission constitutes authorization
for public utilities to engage in the
234 Order

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resale of FTRs and virtual transactions,
and no separate authorization is
required under the FPA.
Requests for Rehearing
164. Morgan Stanley states that, when
assessing whether a potential marketbased rate seller has market power, the
Commission has focused on ownership
and control of physical transmission
(except for that which is necessary to
interconnect generation to the
transmission grid).235 Morgan Stanley
requests that the Commission clarify
whether a seller is required to include
and report the acquisition of financial
transmission rights when assessing
whether it has vertical market power.
Morgan Stanley states that the
Commission declined to adopt such a
requirement as part of Order No. 652
governing changes in status.236
However, Morgan Stanley asserts that
‘‘Commission staff and others have
taken inconsistent positions on whether
the failure to disclose the acquisition of
financial transmission rights constitutes
a violation of a seller’s market-based
rate tariff.’’237

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Commission Determination
165. The Commission clarifies herein
that sellers are not required to report on
financial transmission rights as part of
the vertical market power assessment.
Thus, failure to disclose the acquisition
of financial transmission rights in an
application for market-based rate
authority, a three-year update or a
change in status filing does not
constitute a violation of a seller’s
market-based rate tariff. While
ownership of financial transmission
rights could affect a seller’s incentive to
exercise market power, we find that
there are adequate mechanisms and
protections in place to minimize a
seller’s ability to do so (e.g., market
monitoring and mitigation in RTO/ISOs;
the requirement that a seller must abide
by its OATT and any violation thereof
could constitute a violation of a seller’s
market-based rate tariff; the
Commission’s enforcement
proceedings). Moreover, the
Commission does not analyze physical
rights that a seller has to transmission
235 Morgan Stanley Rehearing Request at 1–2
(citing Iowa Power Partners, 81 FERC ¶ 61,058, at
61,281 (1997)).
236 Reporting Requirement for Changes in Status
for Public Utilities with Market-Based Rate
Authority, Order No. 652, 70 FR 8253 (Feb. 18,
2005), FERC Stats. & Regs. ¶ 31,175, order on reh’g,
111 FERC ¶ 61,413 (2005).
237 Morgan Stanley Rehearing Request at 2. (citing
Enron Power Marketing, 119 FERC ¶ 63,013 (2007)
(discussing Enron’s use of FTRs to exercise market
power and its failure to report its FTRs to the
Commission)).

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service when analyzing vertical market
power, and the Commission will treat
financial rights in an equal manner.
Physical and financial rights to
transmission service do not enable the
customer to control transmission
capacity in a way that withholds the
capacity from the market. To the extent
there is an issue with potential market
manipulation by a seller, the
Commission would address this through
an Office of Enforcement proceeding.
3. Other Barriers to Entry
Final Rule
166. The Final Rule 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.
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.238
167. In the Final Rule, the
Commission drew a distinction between
two categories of inputs to electric
power production: One consisting of
natural gas supply, interstate natural gas
transportation (which includes
interstate natural gas storage), oil
supply, and oil transportation; and
another consisting of intrastate natural
gas transportation, intrastate natural gas
storage or distribution facilities, sites for
generation capacity development, and
sources of coal supplies and the
transportation of coal supplies such as
barges and rail cars.239
168. With regard to the first category,
the Commission removed the inputs
from the vertical market power analysis.
Thus, the Final Rule did not require a
description of or affirmative statement
with regard to ownership or control of,
or affiliation with an entity that owns or
controls, natural gas and oil supply,
including interstate natural gas
transportation and oil transportation.240
The Commission explained that prices
for wellhead sales of natural gas were
decontrolled by Congress,241 and that
the Commission has granted other
sellers blanket authority to make such
sales at market rates. In the case of
transportation of natural gas, the
Commission noted that pipelines
238 Order

No. 697 at P 440.
P 441.
240 Id. P 442.
241 INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002);
Natural Gas Decontrol Act of 1989, H.R. Rep. No.
101–29, 101st Cong., 1st Sess., at 6 (1989).
239 Id.

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operate pursuant to the open and nondiscriminatory requirements of Part 284
of the Commission’s regulations;242
these regulations mandate that all
available pipeline capacity be posted on
the pipelines’ website, and that
available capacity cannot be withheld
from a shipper willing to pay the
maximum approved tariff rate. The
Commission noted that, to the extent
intervenors are concerned about a
seller’s market power from ownership or
control of interstate natural gas
transportation, this would be actionable
first in a complaint proceeding under
section 5 of the Natural Gas Act before
turning to market-based rate
consequences, if any.243
169. Similarly, the Commission noted
that oil pipelines are common carriers
under the Interstate Commerce Act,
specifically under section 1(4), that they
are required to provide transportation
service ‘‘upon reasonable request
therefore,’’ and that Congress has not
chosen to regulate sales of oil.244
170. With regard to the second
category of inputs to electric power
production, the Commission adopted a
rebuttable presumption that sellers
cannot erect barriers to entry with
regard to the ownership or control of, or
affiliation with any entity that owns or
controls, those inputs.245 The
Commission noted that, to date, it has
not found such ownership, control or
affiliation to be a potential barrier to
entry warranting further analysis in the
context of market-based rate
proceedings. However, unlike the first
category of inputs, the Commission does
not have sufficient evidence to remove
these inputs from the analysis entirely.
Accordingly, the Commission stated
that it will rebuttably presume that
ownership or control of, or affiliation
with an entity that owns or controls, any
of the second category of inputs does
not allow a seller to raise entry barriers,
but intervenors will be allowed to
242 Order No. 697 at P 443 (citing Pipeline Service
Obligations and Revisions to Regulations Governing
Self-Implementing Transportation; and Regulation
of Natural Gas Pipelines After Partial Wellhead
Decontrol, Order No. 636, 57 FR 13267 (Apr. 16,
1992), FERC Stats. & Regs., Regulations Preambles
January 1991–June 1996 ¶ 30,939 (Apr. 8, 1992);
Regulation of Short-Term Natural Gas
Transportation Services and Regulation of
Interstate Natural Gas Transportation Services,
Order No. 637, FERC Stats. & Regs., Regulations
Preambles July 1996–December 2000 ¶ 31,091 (Feb.
9, 2000); clarified, Order No. 637–A, FERC Stats. &
Regs., Regulations Preambles July 1996–December
2000) ¶ 31,099 (May 19, 2000); reh’g denied, Order
No. 637–B, 92 FERC ¶ 61,062 (2000); aff’d in part
and remanded in part sub nom.).
243 Order No. 697 at P 445.
244 Id. P 444 (quoting 49 App. U.S.C. 1(4)).
245 Id. P 446. The Commission modified the
definition of ‘‘inputs to electric power production’’
in 18 CFR 35.36(a)(4) to reflect this clarification.

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demonstrate otherwise. The Final Rule
noted that this rebuttable presumption
only applies if the seller describes and
attests to these inputs to electric power
production in its market power analysis,
as discussed below.246
171. The Commission required a
seller to provide a description of its
ownership or control of, or affiliation
with an entity that owns or controls, any
of the second category of inputs. The
Final Rule required sellers to provide
this description and to make an
affirmative statement, with some
modifications to the affirmative
statement from what was proposed in
the NOPR. Instead of requiring sellers to
make an affirmative statement that they
have not erected barriers to entry into
the relevant market, the Final Rule
required sellers to make an affirmative
statement that they have not erected
barriers to entry into the relevant market
and will not erect barriers to entry into
the relevant market. The Final Rule
clarified that the obligation in this
regard applies both to the seller and its
affiliates, but is limited to the
geographic market(s) in which the seller
is located.247
172. Therefore, the Final Rule
modified the proposed regulations to
require a seller to provide a description
of its ownership or control of, or
affiliation with an entity that owns or
controls these types of assets, to ensure
that this information is included in the
record of each market-based rate
proceeding. In addition, the
Commission required sellers to make an
affirmative statement that they have not
erected barriers to entry into the
relevant market and will not erect
barriers to entry into the relevant
market.248
173. The Commission also modified
the change in status reporting
requirement in § 35.42 of the
Commission’s regulations to be
consistent with the other barriers to
entry part of the vertical market power
analysis as adopted in the Final Rule.
Requests for Rehearing
174. Southern notes that the Final
Rule modified the change in status
regulations adopted by the Commission
in Order No. 652. Specifically, Southern
states that the Commission modified the
definition of inputs to electric power
production to mean ‘‘ ‘intrastate natural
gas transportation, intrastate natural gas
storage or distribution facilities; sites for
new generation capacity development;
sources of coal supplies and the
246 Id.

P 446.
P 447.
248 Id. P 448.
247 Id.

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transportation of coal supplies such as
barges and railcars,’ ’’ 249 and comments
that under the change in status reporting
regulations, sellers would be required to
notify the Commission of any changes to
such inputs. Southern requests
clarification of what is meant by the
phrase ‘‘sources of coal supplies and the
transportation of coal supplies such as
barges and railcars’’ in the context of the
definition of ‘‘inputs to electric power
production.’’ Because such inputs to
electric power production are
considered in the Commission’s vertical
market power analysis,250 Southern
believes that the Commission’s
intention is for this phrase to mean
physical coal sources (i.e., coal mines)
and ownership or control over who may
access transportation of coal via barges
and railcar trains (e.g., control of a train
system, a railcar manufacturing or
supply company, or a barge production
or supply company), rather than merely
entering into a coal supply contract with
a coal vendor. Southern argues that if a
change in status filing were required
every time a large utility entered into a
coal purchase agreement, purchased or
leased a single railcar or barge, or
engaged in other such routine activities,
which Southern asserts are a necessary
and inherent part of keeping power
plants operating so that they can
reliably serve a utility’s customers, the
Commission could find itself inundated
with submissions. Accordingly,
Southern requests that the Commission
clarify that the phrase ‘‘inputs to electric
power production’’ is intended to
encompass physical coal sources and
ownership of control over who may
access transportation of coal via barges
and railcar trains.
175. APPA/TAPS request that the
Commission clarify that intervenors
may introduce evidence that control
and/or ownership of interstate natural
gas supply, transportation or storage, as
well as oil supply and transportation,
creates entry barriers.251 APPA/TAPS
request clarification that the Final
Rule’s stated case-by-case consideration
of other entry barriers will include
evidence that a seller’s or its affiliate’s
ownership or control of the first
category of entry barriers will be
considered.252 According to APPA/
TAPS, if, as the Commission believes,
markets in the first category are
competitive, intervenors will rarely
raise concerns about them in specific
249 Southern Rehearing Request at 41 (citing
Order No. 697 at P 1016).
250 Id. at 41 (citing Order No. 697 at P 446).
251 APPA/TAPS Rehearing Request at 29–30
(citing Order No. 697 at P 441–49; United States v.
Enova Corp., 107 F. Supp. 2d 10 (D.D.C. 2000)).
252 Id. at 30.

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cases, which means there is no basis to
reject this requested clarification on
grounds that allowing intervenors to
raise entry concerns will be unduly
burdensome for applicants or the
Commission. APPA/TAPS contend that
if there are concerns about these entry
barriers, the Commission provides no
justification for requiring an intervenor
to undertake the time and expense of a
‘‘ ‘complaint proceeding under section 5
of the Natural Gas Act before turning to
market-based rate consequences.’ ’’ 253
Further, APPA/TAPS state that by
allowing intervenor evidence regarding
market issues surrounding the first
category of inputs, the market-based rate
program ‘‘ ‘will allow unique or newly
developed barriers to entry to be
brought before the Commission.’ ’’ 254
Commission Determination
176. We agree with Southern that it
was not the Commission’s 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 clarifies 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. Thus, the
Commission will revise 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.’’
177. The Commission denies APPA/
TAPS’ request that the Commission
clarify that intervenors may introduce
evidence that control and/or ownership
of interstate natural gas supply,
transportation or storage, as well as oil
supply and transportation, create entry
barriers. As explained above and in
Order No. 697, prices for wellhead sales
were decontrolled by Congress,255 and
the Commission has granted other
sellers blanket authority to make such
sales at market rates. In the case of
transportation of natural gas, pipelines
operate pursuant to the open and nondiscriminatory requirements of Part 284
of the Commission’s regulations; 256
253 Id.

(quoting Order No. 697 at P 445).
(quoting Order No. 697 at P 449).
255 INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002);
Natural Gas Decontrol Act of 1989, H.R. Rep. No.
101–29, 101st Cong., 1st Sess., at 6 (1989).
256 Order No. 697 at P 443 (and cases cited
therein).
254 Id.

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these regulations require that all
available pipeline capacity be posted on
the pipelines’ Web site, and that
available capacity cannot be withheld
from a shipper willing to pay the
maximum approved tariff rate.
Similarly, the Final Rule noted that oil
pipelines are common carriers under the
Interstate Commerce Act, specifically
under section 1(4), that they are
required to provide transportation
service ‘‘upon reasonable request
therefore,’’ and that Congress has not
chosen to regulate sales of oil.257
178. As stated in the Final Rule, to the
extent intervenors are concerned about
a seller’s market power from ownership
or control of interstate natural gas
transportation, this would be actionable
first in a complaint proceeding under
section 5 of the Natural Gas Act before
turning to any market-based rate
consequences.
179. The Commission found in Order
No. 697 and we reiterate here that there
is no need to address these inputs to
electric power production as potential
barriers to entry in the context of the
market-based rate program. In light of
the precedent described above, we
conclude that sellers cannot erect
barriers to entry with regard to such
inputs.
180. Regarding APPA/TAPS’ assertion
that the Commission provides no
justification for requiring an intervenor
to file a complaint proceeding under
section 5 of the Natural Gas Act when
a concern arises regarding interstate
natural gas transportation, as explained
in Order No. 697, natural gas pipelines
operate pursuant to the open and nondiscriminatory requirements of Part 284
of the Commission’s regulations. On this
basis, the appropriate forum for
addressing a concern that may arise
regarding interstate natural gas
transportation would initially be a
proceeding under the Natural Gas Act,
not the FPA. Thus, a market-based rate
proceeding would not be the proper
forum for such a complaint. The place
to challenge a particular seller’s
potential market power in interstate
natural gas transportation markets is in
a complaint proceeding under section 5
of the Natural Gas Act.
C. Affiliate Abuse
181. In Order No. 697, the
Commission determined that affiliate
abuse should no longer be considered a
separate ‘‘prong’’ of the market-based
rate analysis, and instead codified the
affiliate requirements and restrictions as
an explicit requirement in section 35.39
of the Commission’s regulations. The
257 Id.

P 444 (quoting 49 App. U.S.C. 1(4)).

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affiliate requirements and restrictions
must be satisfied on an ongoing basis as
a condition of obtaining and retaining
market-based rate authority.258 The
regulations expressly prohibit power
sales between a franchised public utility
with captive customers and any marketregulated power sales affiliate, without
first receiving Commission
authorization for the transaction under
section 205 of the FPA. The regulations
also include the requirements formerly
known as the market-based rate ‘‘code of
conduct,’’ as revised in Order No. 697.
1. General Affiliate Terms & Conditions
a. Affiliate Definition
182. As an initial matter, we clarify
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. In the
Affiliate Transactions Final Rule, the
Commission 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.259 The Commission also
reviewed the affiliate definitions
contained in both the Public Utility
Holding Company Act of 1935 (PUHCA
1935) 260 and the Public Utility Holding
Company Act of 2005 (PUHCA
2005) 261. After taking into account these
differing definitions of affiliate, and
recognizing the need to provide greater
clarity and consistency in our rules, the
Commission explained that it believes it
is important to try to adopt a more
consistent definition in its various rules
and also one that is sufficiently broad to
allow us to adequately protect
customers.262 On this basis, the
definition of affiliate as adopted in the
Affiliate Transactions Final Rule
explicitly incorporates the PUHCA 1935
definition of affiliate for EWGs (rather
258 A seller seeking market-based rate authority
must provide information regarding its affiliates
and its corporate structure or upstream ownership.
To the extent that a seller’s owners are themselves
owned by others, the seller seeking to obtain or
retain market-based rate authority must identify
those upstream owners. Sellers must trace upstream
ownership until all upstream owners are identified.
Sellers must also identify all affiliates. Finally, an
entity seeking market-based rate authority must
describe the business activities of its owners, stating
whether they are in any way involved in the energy
industry.
259 See, e.g., Morgan Stanley Capital Group, Inc.,
72 FERC ¶ 61,082, at 61,436–37 (1995) (Morgan
Stanley).
260 15 U.S.C. 79a et seq.
261 EPAct 2005 at 1261 et seq.
262 For example, we adopt this definition of
affiliate for purposes of section 203 of the FPA in
the Affiliate Transactions Final Rule.

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than incorporate it by reference as
previously has been done).263 The
definition also adopts a parallel
definition of affiliate for non-EWGs, but
with adjustments to reflect the
previously-used 10 percent voting
interest threshold for non-EWGs and to
eliminate certain language not
applicable or necessary in the context of
the FPA.
183. In light of the Commission’s goal
to have a more consistent definition of
affiliate for purposes of both EWGs and
non-EWGs to the extent possible, as
well as to strengthen the Commission’s
ability to ensure that customers are
protected, we clarify that, for purposes
of Order No. 697, we will define
‘‘affiliate’’ as that term is used in the
Affiliate Transactions Final Rule,
codified in § 35.43(a)(1) of the
Commission’s regulations. Accordingly,
as discussed herein, we will codify the
definition of affiliate in our marketbased rate regulations at § 35.36.
b. Definition of Market-Regulated Power
Sales Affiliate
Final Rule
184. The Commission explained in
Order No. 697 that the market-based rate
affiliate restrictions codified in § 35.39
govern the relationship between a
franchised public utility with captive
customers and its market-regulated
power sales affiliates.264 The affiliate
restrictions codified in the regulations
include a provision expressly
prohibiting power sales between a
franchised public utility with captive
customers and a market-regulated power
sales affiliate without first receiving
Commission authorization.265 The
263 We note that in EPAct 2005 section 1277(b)(2),
Congress enacted a conforming amendment which
amended FPA section 214 to refer to the section 2(a)
PUHCA 2005 definition of ‘‘affiliate’’ rather than
the section 2(a) PUHCA 1935 definition of
‘‘affiliate.’’ Our Affiliate Transactions Final Rule
did not recognize this conforming amendment.
However, the conforming amendment is ambiguous.
There is no section 2(a) in PUHCA 2005 and,
inexplicably, the text of PUHCA 2005 retained only
a portion of the full PUHCA 1935 definition of
‘‘affiliate;’’ although it retained the PUHCA 1935
threshold of five percent, it dropped much of the
statutory text, thus leaving a potential gap in the
scope of entities that could be considered affiliates.
It is unclear whether this was a drafting oversight,
but we do not believe Congress intended to
preclude the Commission, in adopting regulations
preventing cross-subsidization, undue preferences
or the exercise of market power from using an
‘‘affiliate’’ definition that provides greater customer
protection with respect to EWG transactions. Our
Affiliate Transactions Final Rule and this rule thus
use the 1935 statutory text framework for EWGs. We
adopt the definition of affiliate promulgated in the
Affiliate Transactions Final Rule with a
modification to reflect the approach discussed
herein.
264 Id. at P 549.
265 Id. at P 467.

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Commission defined market-regulated
power sales affiliate to mean ‘‘any
power seller affiliate other than a
franchised public utility, including a
power seller affiliate, whose power sales
are regulated in whole or in part at
market-based rates.’’ 266

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Requests for Rehearing
185. Occidental states that, in its
current form, Order No. 697 could be
interpreted to permit franchised public
utilities to require their captive
customers to subsidize their marketbased rate activities, so long as their
regulated and market-based rate
activities were combined in a single
entity.267 To prevent that result,
Occidental requests that the
Commission explicitly require that the
functional attributes, rather than the
arbitrary structure of a utility, be
considered in determining compliance
with the rule’s affiliate abuse
provisions.268 Occidental states that the
Commission should focus on potential
market-based rate seller conduct rather
than on artificial structural distinctions
selected by the seller.269
186. Specifically, Occidental argues
that, because Order No. 697 focuses
solely on conduct between a utility and
a legally separate affiliate, it would
allow a utility to benefit its marketbased rate activities at the expense of its
captive regulated customers simply by
collapsing its regulated and marketbased rates sales activities into a single
entity that, while not technically an
affiliate of the utility, could attempt to
engage in the abuses that Order No. 697
seeks to prevent.270 Occidental asserts
that the Commission can focus on
potential market-based rate seller
conduct, rather than on artificial
structural distinctions selected by the
seller, by clarifying that it will not focus
solely on the narrow definitions of
franchised public utility, captive
customer, and market-regulated power
sales affiliate, but instead will use a
functional test that broadly applies the
concept embodied in the rule to seller
conduct.
187. Occidental states that the
Commission should either clarify that
the affiliate abuse requirements of the
rule apply equally to market-regulated
functions performed within a franchised
public utility, or revise the definition of
market-regulated power sales affiliate to
achieve that same result.271 In the
266 Id.

at P 490.
Rehearing Request at 2.

267 Occidental
268 Id.
269 Id.

at 5.
at 4.
271 Id. at 8.
270 Id.

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alternative, Occidental states the
Commission should grant rehearing and
modify ‘‘market-regulated power sales
affiliate’’ to ‘‘market-regulated power
sales function’’ which would necessitate
removing the provision stating that such
an entity is not a franchised public
utility.272
Commission Determination
188. We deny Occidental’s request for
rehearing and clarification. As we
explained in Order No. 697, we ‘‘are
concerned that there exists the potential
for a franchised public utility with
captive customers to interact with a
market-regulated power sales affiliate in
ways that transfer benefits to the
affiliates and its stockholders to the
detriment of the captive customers.’’ 273
Accordingly, we have adopted in our
regulations affiliate restrictions
intended to guard against such behavior.
189. If an entity decides to encompass
its marketing function within the
franchised public utility’s corporate
structure, then there is no longer any
affiliate entity to trigger the concerns of
affiliate abuse that the market-based rate
affiliate restrictions are designed to
address. For example, one of our
primary concerns in adopting affiliate
restrictions is to prevent a franchised
utility from making below-market sales
to its merchant affiliate and to prevent
the merchant affiliate from making
above-market sales to its franchised
utility affiliate.
In particular, Occidental’s argument
rests on the premise that the franchised
public utility that encompasses its
marketing function within the
franchised public utility corporate
structure could benefit its market-based
rate activities at the expense of its
captive customers. Occidental appears
to be suggesting that revenues from the
franchised public utility’s off-system
sales at market-based rates would be
funneled to the utility’s shareholders
rather than credited to the utility’s
customers. However, such a scenario is
at odds with Commission precedent
requiring that off-system sales be
reflected through allocation or revenue
credits in the rates of the utility’s
customers.274
272 Id.
273 Order

No. 697 at P 513.
e.g., Public Service Co. of New Mexico,
Opinion No. 146, 20 FERC ¶ 61,290 at 61,546–48
(crediting revenue from intersystem opportunity
sales to native load customers), reh’g denied, 21
FERC ¶ 61,334 (1982); Golden Spread Electric
Cooperative, Inc., Opinion No. 501, 123 FERC
¶ 61,047 at P 94–98 (crediting revenue from
intersystem opportunity sales to native load
customers) (2008); Boston Edison Co., Opinion No.
53, 8 FERC ¶ 61,077 at 61,283 (allocating costs to
firm services where the revenue crediting
274 See,

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190. Additionally, state commissions
have oversight authority for franchised
public utilities with captive customers
that make retail sales. Therefore, the
states should be able to ensure that a
franchised public utility with captive
customers does not attempt any
‘‘internal’’ cross-subsidization to the
detriment of captive customers.
Generally, states similarly require
revenue crediting to the utility’s retail
customers.
191. Thus, we will deny Occidental’s
request for rehearing and clarification
and retain the current requirements for
the affiliate restrictions. We will also
retain the current definition of marketregulated power sales affiliate under
Order No. 697.
c. Definition of Captive Customers
Final Rule
192. As adopted in Order No. 697, 18
CFR 35.36(a)(6) defines captive
customer as ‘‘any wholesale or retail
electric energy customers served under
cost-based regulation.’’ 275 The
Commission clarified that the definition
of captive customers did not include
those customers who have retail choice,
i.e., the ability to select a retail supplier
based on the rates, terms, and
conditions of service offered. Rather,
retail customers who have no ability to
choose an electric energy supplier are
considered captive because they must
purchase from the local utility pursuant
to cost-based rates set by a state or local
regulatory authority; that is, they are
served under cost-based regulation.
193. The Commission further
explained in Order No. 697 that retail
customers who choose to be served
under cost-based rates, even though
they have the ability to choose one retail
supplier over another, are not
considered to be under ‘‘cost-based
regulation’’ and therefore are not captive
under the definition.
194. While much of the discussion in
Order No. 697 focused on retail
customers, the Commission stated
‘‘regarding wholesale customers, sellers
should continue to explain why, if they
have wholesale customers, those
customers are not captive.’’ 276
195. The Commission also declined to
include transmission customers in the
definition of captive customers for
purposes of market-based rates for
public utilities. The Commission stated
that the open access policies in Order
methodology may result in over-allocation of costs
to the customers whose rates were at issue), reh’g
denied, Opinion No. 53–A, 9 FERC ¶ 61,002 (1979).
275 Order No. 697 at P 478 (to be codified at 18
CFR 35.36(a)(6)).
276 Order No. 697 at P 480.

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No. 890 protect transmission customers
from the exercise of vertical market
power.
Requests for Rehearing
196. Occidental argues that, just as
with retail customers that have retail
choice, wholesale customers with
alternatives should also not be deemed
to be ‘‘captive customers.’’ 277
Occidental argues that wholesale
customers, whether buying under costbased or market-based rates, have
alternatives and are therefore not
captive. Occidental states that a
wholesale seller does not have any
obligation to sell to any buyer, nor is a
wholesale buyer obligated to buy from
any particular seller. Occidental argues
that the Commission’s conclusion that
retail customers with retail choice ‘‘are
not served under cost-based regulation,
since that term indicates a regulatory
regime in which retail choice is not
available’’ dictates that a wholesale costbased customer cannot be captive
because choice is, by definition,
available.278 Accordingly, Occidental
requests that the Commission remove
wholesale customers from the definition
of captive customers.
Commission Determination
197. With regard to Occidental’s
request for rehearing concerning
whether wholesale customers should be
included in the definition of ‘‘captive
customers,’’ we note that Occidental
raised the same argument in its
comments in the Affiliate Transactions
rulemaking. In the course of responding
to Occidental’s concerns in that
proceeding, the Commission provided a
number of clarifications regarding the
term ‘‘captive customers,’’ the purpose
of the definition, and its focus on ‘‘costbased regulation’’ that we reiterate here.
198. The Commission explained that
its fundamental goal in categorizing
certain customers as ‘‘captive’’ is to
protect customers served by franchised
public utilities from inappropriately
subsidizing the market-regulated or nonutility affiliates 279 of the franchised
public utility or otherwise being
financially harmed as a result of affiliate
transactions and activities. In other
277 Occidental

Rehearing Request at 9.

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278 Id.
279 We note that the affiliate restrictions adopted
in Order No. 697 apply to power sales and nonpower goods and services transactions between
franchised public utilities with captive customers
and their market-regulated power sales affiliates,
whereas the Affiliate Restrictions Final Rule applies
to franchised public utilities with captive customers
and their market-regulated power sales affiliates as
well as their non-utility affiliates. Accordingly, the
discussion herein is limited to market-regulated
power sales affiliates.

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words, we are concerned about the
potential for the inappropriate transfer
of benefits from such customers to the
shareholders of the franchised public
utility or its holding company.280 Where
customers are served under marketbased regulation as opposed to costbased regulation, it is presumed that the
seller has no market power over a
customer and that the customer has a
choice of suppliers; thus, there is less
opportunity for a customer to
involuntarily be in a situation in which
its rates subsidize or support another
entity.
199. Under a regime of cost-based
regulation, however, we cannot make
these same assumptions. If a franchised
public utility is selling at a wholesale
cost-based rate under the FPA, the
franchised utility seller may be in the
position of potentially trying to flow
through its cost-based rates costs that
should instead be borne by its affiliates,
i.e., potentially subsidizing the ‘‘nonregulated’’ activities of its marketregulated power sales affiliates to the
detriment of the franchised public
utility’s customer(s). As the Commission
stated in the Affiliate Transactions Final
Rule, while there is some merit to
Occidental’s assertion that wholesale
customers, by definition, have
alternatives and that there is no
obligation for a wholesale customer to
sell to any buyer, nor for a buyer to buy
from any particular seller, for the
customer protection reasons stated
above, we believe it is important to err
on the side of a broad definition of
captive customers. On this basis, we
deny Occidental’s request for rehearing
that the Commission change its existing
analysis and generically exclude
wholesale customers from the definition
of captive customers.
200. Nevertheless, as the Commission
noted in the Affiliate Transactions Final
Rule, although we are erring on the side
of a broad definition of captive
customers, we recognize that there may
well be circumstances in which
customers fall within our definition,
280 For example, if a market-regulated seller sells
power to its affiliated franchised public utility at an
above market price, the customers of the franchised
public utility pay more than they need to for power
and the affiliate makes a higher profit for the
holding company’s shareholders. Similarly, if a
franchised public utility sells temporarily excess
fuel to its market-regulated power seller affiliate at
a price below its cost, the customers of the
franchised utility end up subsidizing the affiliate’s
operating costs, to the benefit of shareholders and
the detriment of the customers of the franchised
utility. In other contexts, an extreme example
would be a holding company that siphons funds
from a franchised public utility to support its failing
market-regulated power sales affiliate company;
again, this results in financial benefit to
shareholders at the expense of customers.

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even though there are sufficient
protections in place to protect such
customers against any risk of harm from
transactions between the franchised
public utility and its affiliates. For
example, it is possible that wholesale
customers with fixed rate contracts
would be adequately protected and that
the affiliate restrictions should not
apply to utilities whose customers all
have fixed rate contracts with no fuel
adjustment clause.281 The Commission
explained that it is not prepared at this
time to generically exclude such
customers from the definition of captive
customers but instead will allow
franchised public utilities, on a case-bycase basis, to argue that the affiliate
restrictions should not apply. This will
allow the Commission to closely
examine the facts related to each
franchised public utility. There may be
circumstances other than fixed rate
contracts in which we may be willing to
find that the affiliate restrictions do not
apply, but a public utility will need to
demonstrate that there is no opportunity
for wholesale customers of the
franchised public utility to be harmed as
a result of affiliate transactions.
201. We note that in Order No. 697,
we stated that ‘‘regarding wholesale
customers, sellers should continue to
explain why, if they have wholesale
customers, those customers are not
captive.’’ 282 Consistent with the
foregoing discussion, we will modify
that statement. If sellers have wholesale
customers, instead of explaining why
those customers are not captive, the
sellers should explain why those
customers are adequately protected
against affiliate abuse.
202. We also will revise the definition
of captive customers to be consistent
with the definition adopted in the
Affiliate Transactions Final Rule. In that
Final Rule, the Commission modified
the definition of captive customers to
make explicit what was only implicit in
its earlier rules—that the definition is
intended to apply to customers served
by a franchised public utility under
cost-based regulation. Accordingly, we
will revise the definition of captive
customers in 18 CFR 35.36(a)(6) to mean
‘‘any wholesale or retail electric energy
customers served by a franchised public
utility under cost-based regulation.’’
203. Additionally, as the Commission
recently stated in the Affiliate
281 The Commission would need to be assured
that all wholesale customers of a franchised public
utility have adequate fixed rate contracts, not just
a sub-set of the customers. Further, because such
contracts may have different expiration dates, the
Commission might need to place temporal
conditions on such a waiver.
282 Order No. 697 at P 480.

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Transactions Final Rule, if a state
regulatory authority in a retail choice
state does not believe that retail
customers are sufficiently protected and
that our affiliate restrictions should
apply to the local franchised public
utility, it may file a petition for
declaratory order to deem its retail
customers to be captive customers for
purposes of applying the affiliate
restrictions.283 A state regulatory
authority may also raise such an
argument as part of its comments in a
market-based rate proceeding.
d. Electric Cooperatives
Final Rule
204. The Commission declined to
subject to the affiliate restrictions and
regulations in § 35.39 electric
cooperatives that may otherwise be
subject to the Commission’s
jurisdiction. In Order No. 697, the
Commission reasoned that ‘‘affiliate
abuse takes place when the affiliated
public utility and the affiliated power
marketer transact in ways that result in
a transfer of benefits from the affiliated
public utility (and its ratepayers) to the
affiliated power marketer (and its
shareholders).’’ 284 The Commission
explained that, where a cooperative is
involved, the cooperative’s members are
both the ratepayers and the
shareholders. Therefore, there is no
potential danger of shifting the benefits
from the ratepayers to the
shareholders.285
Requests for Rehearing
205. El Paso E&P argues that the
Commission’s concerns regarding
affiliate transactions should apply
equally to sales by jurisdictional public
utility cooperatives to their affiliated
members,286 and that the Commission
cannot abdicate its obligation to protect
captive customers. According to El Paso
E&P, the fact that a cooperative is
comprised of its member distribution
cooperatives could actually facilitate the
exercise of market power, because a
cooperative, through its member board,
has an incentive to charge as much as
it can to captive customers in order to
subsidize the rates paid by its
283 Affiliate

Transactions Final Rule at P 45.
No. 697 at P 526 (citing Heartland
Energy Services, Inc., 68 FERC ¶ 61,223, at 62,062
(1994)).
285 Order No. 697 at P 526 (citing Old Dominion
Electric Cooperative, 81 FERC ¶ 61,044, at 61,236
(1997)).
286 El Paso E&P Rehearing Request at 8 (citing
Illonova Power Marketing, Inc., 88 FERC ¶ 61,189
(1999); First Energy Trading & Power Marketing,
Inc., 84 FERC ¶ 61,214 (1998)).

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284 Order

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residential and commercial
customers.287
206. El Paso E&P contends that the
Commission abdicated its responsibility
under the FPA to protect captive
customers by claiming lack of
jurisdiction over the cooperatives.288 El
Paso E&P explains that no Commission
precedent addresses the situation where
sales at market-based rates are
ultimately made to captive customers of
the distribution cooperatives. El Paso
E&P points out that, unlike other cases,
a generation and transmission
cooperative seller’s affiliate distribution
cooperatives are not the ultimate
consumers of the power.289 Therefore,
El Paso E&P maintains, they do intend
to pass on potential excessive purchased
power costs to captive customers.
207. For example, El Paso E&P argues
that the fact that Deseret and Moon Lake
may receive above-market rates from El
Paso E&P will not necessarily result in
profit to either entity. Rather, the
collection of such monopoly rents could
be used by either Deseret or Moon Lake
to subsidize the costs paid by other
ratepayers in their members’ franchised
service territories. Even if it did result
in profits to either Deseret or Moon
Lake, El Paso E&P asserts that there is
no assurance that El Paso E&P would
receive any share of such profits since
it is not a member of Deseret’s board
and has no say in what Deseret charges
to its members. Because it also is not a
member of Moon Lake’s board, El Paso
E&P argues it has no ability to vote on
whether any profits that may be earned
by Deseret, and may be credited to
Moon Lake, are actually paid back to
it.290
208. El Paso E&P also argues that the
Commission erred in justifying its
failure to protect captive ratepayers of
cooperatives on the ground that El Paso
E&P’s concern is really about
discrimination in the allocation of
benefits and burdens among retail
ratepayers, which is a state law issue. El
Paso E&P argues that this cannot be
squared with the protection that the
Commission provides in Order No. 697
for captive ratepayers of noncooperative sellers.291 El Paso E&P takes
the position that, if the Commission
permits cooperatives to charge marketbased rates, then the Commission is
obligated to ensure that all captive
customers are protected from any abuse
287 Id.

at 6, 12.
at 6.
289 Id. at 11.
290 Id. at 12–13.
291 Id. at 14.
288 Id.

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25863

or excessive rates resulting from those
market-based rates.292
209. Moreover, El Paso E&P argues
that the Commission has not explained
how state commissions could deny
pass-through of market-based rates by
distribution cooperatives to their retail
customers when the rates have been
approved by the Commission.293 It
asserts that the cases cited by the
Commission are not on point.
Specifically, the exception to federal
pre-emption discussed in Nantahala
Power and Light Co. v. Thornburg 294
relates to the quantity purchased, not
the price paid. El Paso E&P contends
that this exception is not applicable to
cooperatives because their cooperative
structure requires the distribution
cooperative members to purchase their
power from their generation and
transmission cooperative.295
Commission Determination
210. We deny El Paso E&P’s request
for rehearing. El Paso E&P has not raised
any new arguments on rehearing, and it
has not persuaded us to reverse our
finding from Order No. 697 that electric
cooperatives are not subject to the
Commission’s affiliate restrictions
codified in § 35.39.
211. The Commission explained in
Order No. 697 that, even if an electric
cooperative is not exempt from public
utility regulation by the FPA under
section 201(f), the Commission
previously determined that transactions
of an electric cooperative with its
members do not present dangers of
292 Id.

at 8.
at 7, 15 (citing Arkansas Power & Light Co.
v. Missouri Public Service Commission, 829 F.2d
1444, 1452–53 (8th Cir. 1987)) (Arkansas P&L)
(holding that the ordinary state-law process of
suspension and investigation of retail rates is not
preempted by the FPA ,and there is no language in
the FPA to indicate that Commission orders on
wholesale rates require an immediate pass-through
of those wholesale rates).
294 476 U.S. 953 (1986). Mississippi Power & Light
Co. v. Mississippi ex rel. Moore, 487 U.S.354 (1958)
(holding that state commissions must treat
Commission-approved costs for wholesale power as
reasonably incurred operating expenses for the
purposes of setting retail rates, but state
commissions are precluded from setting retail rates
that would ‘‘trap’’ the costs a seller was mandated
to pay under a Commission order, or from
undertaking a prudence review for the purpose of
deciding whether to approve such retail rates.);
Central Vermont Public Service Corporation, 84
FERC ¶ 61,194 (1998)) (holding that state
commissions are preempted by federal law from
reviewing the prudence of power purchases, if, as
a result of wholesale power supply allocation
directed by the Commission, the purchaser has no
legal choice but to make a particular purchase and
to permit such a review would interfere with the
Commission’s plenary authority over interstate
wholesale rates).
295 Id.
293 Id.

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affiliate abuse through self-dealing.296
Where a cooperative is involved and the
cooperative’s members are both the
ratepayers and the shareholders, any
profits earned by the cooperative will
inure to the benefit of the cooperative’s
ratepayers. As such, no potential danger
exists of shifting benefits from the
ratepayers to the shareholders. Deseret
is not a for-profit entity with an
incentive to maximize its rates for the
benefit of its shareholders; rather, its
ratepayers and shareholders are the
same entities. Similarly, Moon Lake is
not a power marketer concerned only
with passing its costs through to its
ratepayers for the benefit of its
shareholders. Rather, Moon Lake is
responsible to its members, including El
Paso E&P, which is entitled to vote in
Moon Lake’s Board elections and is
entitled to the same single vote held by
each residential and commercial
ratepayer of Moon Lake.297
212. Moreover, if Deseret charges
Moon Lake higher rates than Deseret
charges its other five member
cooperatives, it may be engaging in
discrimination, which is barred by
sections 205 and 206 of the FPA. As we
explained in Order No. 697, El Paso
E&P’s concern is not one that can be
addressed through affiliate restrictions
in market-based rates, but is rather more
of a concern of discrimination in the
allocation of benefits and burdens
among retail ratepayers.298
213. Therefore, we deny El Paso E&P’s
request for rehearing and reaffirm our
finding that electric cooperatives are not
subject to the affiliate restrictions
codified in § 35.39 because there is no
danger of affiliate abuse through selfdealing.
e. Public Utility Holding Company Act
of 2005 as a ‘‘Commission Rule or
Order’’ Permitting At-Cost Pricing

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Final Rule
214. Order No. 697 requires 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
permitted by Commission rule or
order.299 The Commission also adopted
the proposal to require that sales of nonpower goods or services by a franchised
public utility with captive customers to
a market-regulated power sales affiliate
be at the higher of cost or market price,
296 Order

No. 697 at P 526 (citing Heartland
Energy Services, Inc., 68 FERC ¶ 61,223, at 62,062
(1994)).
297 See El Paso E&P Rehearing Request at 13, n.7.
298 Order No. 697 at P 527.
299 Id. at P 597; 18 CFR 35.39(e).

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unless otherwise authorized by the
Commission. The Commission
explained that these requirements will
protect captive customers against
affiliate abuse by ensuring that the
utility with captive customers does not
recover too little for goods and services
provided to a market-regulated power
sales affiliate and that the franchised
public utility with captive customers
does not pay too much for goods and
services provided by a market-regulated
power sales affiliate.300
Requests for Rehearing
215. EEI states that the Final Rule
requires market-regulated affiliates to
sell non-power goods and services to
utilities with captive customers at or
below market prices, unless otherwise
authorized by the Commission. It seeks
rehearing of the Final Rule as that
requirement may apply to centralized
service companies.301 Specifically, EEI
notes that in Order No. 667, the
Commission issued a final rule
implementing the Public Utility Holding
Company Act of 2005, with a rebuttable
presumption that centralized service
companies may use ‘‘at cost’’ pricing for
services to affiliate utilities, unless
complainants demonstrate that the atcost pricing exceeds the market price.302
EEI requests that the Commission clarify
that Order No. 667 constitutes a
‘‘Commission rule or order’’ generally
authorizing use of at-cost pricing by
centralized service companies to utility
affiliates under Order No. 697, absent
complainant evidence that such pricing
exceeds the market price.303
Commission Determination
216. We will grant EEI’s request and
clarify that Order No. 667 constitutes a
Commission rule or order generally
authorizing the use of at-cost pricing by
a centralized service company to utility
affiliates absent any demonstration that
at-cost pricing exceeds the market price.
217. In Order No. 667, the
Commission allowed centralized service
companies to sell non-power goods and
services to affiliated franchised utilities
using an ‘‘at cost’’ standard, stating that
‘‘there is a rebuttable presumption that
such ‘at-cost’ sales for non-power goods
and services between a centralized
service company and its affiliates are
300 Id.
301 EEI

Rehearing Request at 2.
of the Public Utility Holding Company
Act of 1935 and Enactment of the Public Utility
Holding Company Act of 2005, Order No. 667,
FERC Stats. & Regs. ¶ 31,197, at P 169 (2005), order
on reh’g, Order No. 667–A, FERC Stats. & Regs.
¶ 31,213, order on reh’g, Order No. 667–B, FERC
Stats. & Regs. ¶ 31,224 (2006), order on reh’g, Order
No. 667–C, 118 FERC ¶ 61,133 (2007).
303 EEI Rehearing Request at 4, 7–8.
302 Repeal

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reasonable.’’304 The Commission made
clear that the rebuttable presumption for
‘‘at-cost’’ sales for non-power goods and
services only applies to sales by a
centralized service company to its
affiliates. Sales of non-power goods and
services made by market regulated or
unregulated affiliates other than
centralized service companies to their
franchised utility affiliates are subject to
the Commission’s ‘‘no higher than
market’’ standard.305 The Commission
also explained that while it will apply
a rebuttable presumption that costs
incurred under ‘‘at-cost’’ pricing for
services provided by centralized service
companies are reasonable, the
Commission will entertain complaints
that ‘‘at-cost’’ pricing for such services
exceeds the market price.306
218. Given the Commission’s
reasoning set forth in Order No. 667 and
Order No. 667–A, we clarify that, for
centralized service companies, as
defined in Order No. 667 and § 366.5 of
the Commission’s regulations, Order No.
667 constitutes a ‘‘Commission rule or
order’’ generally authorizing use of atcost pricing by centralized service
companies to their franchised public
utilities with captive customers, absent
complainant evidence that such at-cost
pricing exceeds the market price.
f. Sales of Non-Power Goods and
Services
Final Rule
219. In Order No. 697, the
Commission held that sales of nonpower goods or services by a franchised
public utility with captive customers to
a market-regulated power sales affiliate
are to be at the higher of cost or market
price, unless otherwise authorized by
the Commission. The Commission also
codified the requirement that sales of
any non-power goods or services by a
market-regulated power sales affiliate to
an affiliated franchised public utility
with captive customers will not be at a
price above market, unless otherwise
authorized by the Commission.307
Requests for Rehearing
220. FP&L seeks 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
304 Order No. 667–A, FERC Stats. & Regs. ¶ 31,213
at P 38.
305 Id.
306 Order No. 667, FERC Stats. & Regs. ¶ 31,197
at P 169.
307 Order No. 697 at P 597 (to be codified at 18
CFR 35.39(e)).

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
comparable to shared services provided
by a centralized service company.
221. 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 fullyloaded cost as a reasonable proxy for
market price.308 FP&L also requests that
the Commission clarify that the
grandfathering provision in the Affiliate
Transactions Final Rule (which
provides that the pricing rules adopted
therein are prospective only) 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.
Commission Determination
222. Issues similar to those raised
here by FP&L also have been 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. To
ensure consistency in our approach to
pricing of non-power goods and services
between both rulemaking proceedings,
the Commission will address FP&L’s
arguments concerning Order No. 697 in
a supplemental order.309
2. Power Sales Restrictions
a. Sales Between Two Affiliates
Requiring Prior Commission Approval
Final Rule
223. In paragraph 467 of the Final
Rule, the Commission stated that it was
adopting in the regulations a provision
expressly prohibiting power sales
between a franchised public utility with
captive customers and any marketregulated power sales affiliates without
first receiving Commission
authorization for the transaction under
section 205 of the FPA.310
308 FP&L

March 24, 2008 Request for Clarification

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at 4.
309 The Commission need not address all issues
raised in a proceeding at one time. See 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). See also Colorado Office
of Consumer Counsel v. FERC, 490 U.S. 954 (D.C.
Cir. 2007) (holding that the Commission need not
revisit all elements of a tariff upon finding one
aspect to be unjust and unreasonable).
310 Order No. 697 at P 467.

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224. The Commission further noted
(in paragraph 492) that while it has
historically placed affiliate restrictions
only on the relationship between a
franchised public utility with captive
customers and any affiliated marketregulated power sales affiliate, the
Commission believes there may be
circumstances in which it also would be
appropriate to impose similar
restrictions on the relationship of two
affiliated franchised public utilities
where one of the affiliates has captive
customers and one does not. The
Commission said it would not
generically impose the affiliate
restrictions on such relationships but
will evaluate whether to impose the
affiliate restrictions in such situations
on a case-by-case basis.311
Requests for Rehearing
225. Ameren argues that paragraphs
467 and 492 of Order No. 697, taken
together, provide that power sales
between two affiliated franchised public
utilities—one with captive customers
and one without—are not prohibited, do
not require prior authorization under
section 205 of the FPA, and are not
generally subject to the affiliate
restrictions. Instead, the Commission
said that it will consider applying the
restrictions on a case-by-case basis.312
Given that position, Ameren is confused
by § 35.39(h) of the new regulations,
which provides:
If necessary, any affiliate restrictions
regarding separation of functions, power
sales or non-power goods and services
transactions, or brokering involving two or
more franchised public utilities, one or more
of whom has captive customers and one or
more of whom does not have captive
customers, will be imposed on a case-by-case
basis. 313

226. Ameren states this provision is
meaningless if prior authorization of
such transactions is not required. With
regard to the Commission’s statement
that it will consider applying the
affiliate restrictions on a case-by-case
basis, Ameren states that the
Commission fails to explain how it will
conduct such an analysis of the need to
apply the restriction or when such an
obligation to abide by this particular
restriction would arise.
227. Ameren states that the
Commission should do one of three
things. Because the Commission itself
noted that commenters did not show a
potential for affiliate abuse in such a
situation, the Commission could clarify,
consistent with precedent, that prior
311 Id.

P 492.

312 Ameren

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authorization of power sales between
affiliated franchised public utilities is
not required and therefore § 35.39(h)
will be deleted. Alternatively, the
Commission could clarify that, absent a
specific finding imposed prospectively
under sections 205 or 206 of the FPA,
a utility has no obligation to seek prior
authorization of power sales between
affiliated franchised public utilities.
Conversely, Ameren maintains that, if
the Commission intends that public
utilities seek pre-approval of such
transactions, then it should clearly state
that intention. Without such
clarification, Ameren asserts that
franchised public utilities face an
uncertain regulatory regime when
transacting with another franchised
public utility.314
Commission Determination
228. In response to Ameren’s request,
we clarify that when a franchised public
utility receives section 205 authority to
sell at market-based rates, it does not
have to obtain a separate section 205
authority for power sales to another
franchised public utility, as would be
the case if it wanted to make power
sales to a non-franchised, marketregulated power sales affiliate. Thus, an
additional authorization is not required
for power sales between two affiliated
franchised public utilities, one with
captive customers and one without
captive customers. We clarify that,
when we said we would evaluate these
situations on a case-by-case basis, we
meant that the Commission, on its own
motion or in response to a complaint,
may decide to examine the
circumstances of any power sales
between two such affiliated franchised
public utilities, where one has captive
customers and the other does not. Any
determination based on such an
examination would be prospective only.
b. Affiliate Restrictions’ Applicability to
Franchised Public Utilities and
Commission Jurisdictional MarketRegulated Power Sales Affiliates
Final Rule
229. The Commission explained in
Order No. 697 that the market-based rate
affiliate restrictions codified in § 35.39
govern the relationship between a
franchised public utility with captive
customers and its market-regulated
power sales affiliates. This ensures that
captive customers are protected from
any potential for harm as a result of
affiliate dealings.

Rehearing Request at 5.

313 Emphasis

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314 Id.

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Requests for Rehearing
230. FP&L states that it remains
unclear whether the restrictions are
intended to cover non-franchised power
marketers whose sales are not subject to
Commission jurisdiction—for example
power marketers selling exclusively into
the Electric Reliability Counsel of Texas
(ERCOT).315 FP&L requests that the
Commission clarify that the affiliate
restrictions apply only to the relations
between franchised public utilities with
captive customers and their
Commission-jurisdictional marketregulated power sales affiliates, and do
not apply to affiliates engaged in power
sales exclusively within ERCOT.316
FP&L states that, given the magnitude of
an expansion of the affiliate restrictions
to cover non-Commission-jurisdictional
power marketers, and the absence of any
explicit discussion in either the
proposed rule or the Final Rule in this
proceeding, FP&L does not believe the
Commission intends such an
expansion.317

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Commission Determination
231. We grant in part FP&L’s request
for clarification. The Commission’s
market-based rate regulations, including
the affiliate restrictions, do not apply to
entities that are not considered public
utilities under FPA section 201(e),
which would include entities engaged
in power sales exclusively within
ERCOT.
232. The Commission’s market-based
rate regulations apply to any public
utility with market-based rates. If a
franchised public utility with marketbased rates sells to an affiliate company
in ERCOT (which would be a nonpublic utility), the affiliate restrictions
would apply to the franchised public
utility’s dealings with the affiliate. It
could not sell to or purchase from the
ERCOT affiliate unless consistent with
our regulations. The affiliate restrictions
would not apply to the ERCOT affiliate’s
dealings with the other non-public
utility affiliates since the ERCOT
affiliate is not a public utility.
3. Market-Based Rate Affiliate
Restrictions
233. In codifying the affiliate
restrictions in the regulations, the
Commission established certain
restrictions that govern the separation of
functions, sharing of market
information, sales of non-power goods
or services, and power brokering to
govern the relationship between
franchised public utilities with captive
315 FP&L

Rehearing Request at 11.
at 10, 12.
317 Id. at 12.
316 Id.

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customers and their market-regulated
affiliates. As a condition of receiving
and retaining market-based rate
authority, the Commission required
sellers to comply with these affiliate
restrictions unless otherwise permitted
by Commission rule or order.318
a. Two-Way Information Sharing
Restriction
Final Rule
234. The Commission adopted a twoway information sharing restriction in
§ 35.39(d) prohibiting a franchised
public utility with captive customers
from sharing information with a marketregulated power sales affiliate, and viceversa.319
Requests for Rehearing
235. Southern argues the Commission
erred in Order No. 697 by adopting a
two-way information restriction
(§ 35.39(d)) that prevents a franchised
public utility from receiving
information from its market-regulated
power sales affiliate. Southern claims
that the Commission failed to
demonstrate that communications from
a market-regulated power sales affiliate
to a franchised public utility would
harm captive customers and that the
existing one-way communication
restriction currently in many
Commission-accepted codes of conduct
is insufficient.
236. Southern states that the
Commission provided one example of
how information shared with a
franchised public utility by its marketregulated affiliate might harm captive
customers. Specifically, the Commission
stated that in an RFP situation where
both a franchised public utility and its
market-regulated affiliate are
considering whether to submit a bid and
the market-regulated affiliate is allowed
to share its price and quantity
information, the franchised public
utility could possibly use the
information for the benefit of its
stockholders at the expense of its
captive customers. However, Southern
submits that § 35.39(d) is written much
broader than is necessary to address this
concern, and could serve to
unnecessarily prevent a franchised
public utility from receiving operational
information under Commissionapproved generation pooling
arrangements. Southern argues that the
318 Order No. 697 at P 549. To the extent that the
Commission did not impose a code of conduct
requirement on a seller as a condition of marketbased rate authority because the seller had
demonstrated that it did not have captive
customers, that waiver remains in effect provided
that the seller still does not have captive customers.
319 Id. P 583.

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Commission has not suggested much
less demonstrated that a franchised
public utility’s knowledge of the status
of its market-regulated affiliate’s units
could advantage the market-regulated
affiliate at the expense of the franchised
public utility’s captive customers.
Accordingly, Southern alleges Order No.
697 is without a rational basis in this
regard and unsupported by substantial
evidence.320
237. Southern believes that the twoway restriction would actually harm
captive customers by impairing the
pooling arrangement, thereby denying
them the traditional benefits of
integration and coordinated operations
and by triggering costs and
inefficiencies that far outweigh any
conceivable benefit. Accordingly,
Southern requests that the Commission
reconsider the two-way information
sharing restriction.
238. Moreover, according to Southern,
the Commission failed to recognize the
implementation burden that will be
imposed by the two-way restriction.
Southern submits that the Commission
has grossly underestimated the expense
and effort that will be required for
utilities to implement the two-way
restriction.321 Based on its actual
experience, Southern believes that
compliance with the two-way restriction
will be very costly to utilities and
require a substantial amount of time to
complete, potentially in excess of six
months (a much longer period than is
allowed by an effective date of 60 days
after the Final Rule’s publication in the
Federal Register).322 While some
utilities may be able to complete their
implementation of the two-way
restriction within this period, Southern
argues it is more likely that most
utilities will need more time to ensure
compliance. Thus, to the extent the
Commission maintains the two-way
restriction, Southern requests that the
Commission allow utilities and their
market-regulated power sales affiliates
sufficient time to implement the twoway restriction.323
239. To the extent the Commission
maintains the restriction, in any form,
Southern requests that the Commission
clarify the scope of § 35.39(d) and limit
the types of information that are
320 Southern Rehearing Request at 6 (citing Motor
Vehicles Mfrs. Ass’n., 463 U.S. at 43 (1983) (stating
that the agency must articulate a ‘‘rational
connection between the facts found and the choice
made’’); Burlington Truck Lines v. U.S., 371 U.S.
156, 168 (1962); Western Union v FCC, 856 F.2d
315, 318 (D.C. Cir. 1988) (stating that an agency
must demonstrate a ‘‘rational connection between
the facts found and the choice made’’)).
321 Id. at 37.
322 Order No. 697 at P 1133.
323 Southern Rehearing Request at 36, 39.

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restricted to be consistent with the
above-described example set forth in
Order No. 697.324 Southern states that,
at a minimum, the Commission should
provide an exception for information
provided to franchised public utilities
by their market-regulated affiliate
pursuant to participation in
Commission-approved pooling
arrangements. Finally, and to the extent
the Commission retains any two-way
restrictions, it should allow franchised
public utilities and their marketregulated power sales affiliates
sufficient time to assess their
organizations and technology
infrastructures and implement the
measures necessary to ensure
compliance.325

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Commission Determination
240. After consideration of Southern’s
arguments, we will grant Southern’s
request for rehearing on this issue.
241. As previously explained, the
purpose of the affiliate restrictions is to
ensure that captive customers of a
franchised public utility are adequately
protected from any harm that may arise
from affiliate dealings. In an attempt to
provide regulatory certainty, and upon
further review, we find that the one-way
information sharing restriction, which
prohibits a franchised public utility
with captive customers from sharing
market information with a marketregulated power sales affiliate,
adequately protects captive customers.
We have not been presented with any
specific examples of how captive
customers have been harmed by a
market-regulated power sales affiliate
sharing market information with its
franchised public utility with captive
customers. We also note that adopting a
one-way information sharing restriction
is consistent with the Commission’s
approach in the Standards of Conduct.
242. While we are granting Southern’s
request for rehearing on this issue, we
remind sellers that the information
sharing provision, like all affiliate
restrictions, is subject to the no-conduit
rule. The no-conduit rule allows
permissibly-shared employees to receive
market information so long as they are
not conduits for sharing that
information with employees that are not
permissibly shared. Additionally, we
remind all market-based rate sellers that
the FPA prohibits any seller from
providing an undue preference to an
affiliate or any other seller.326
at 39.
at 40–41.
326 See 16 U.S.C. 824d (2001).

b. Affiliate Restrictions’ Precedence
Over Pre-Existing Codes of Conduct
Final Rule
243. As stated above, the Commission
expressly stated in Order No. 697 that
the regulations at 18 CFR part 35,
Subpart H, including the affiliate
restrictions, will become effective 60
days after publication of Order No. 697
in the Federal Register.327 Order No.
697 became effective on September 18,
2007.
Requests for Rehearing
244. Ameren asserts that a reasonable
interpretation of Order No. 697 is that
sellers with market-based rate authority
are to follow the affiliate restrictions in
§ 35.39 upon the effective date of the
regulation, but states nothing is said
regarding the potential for conflicts
between the new regulations and
existing affiliate restrictions/codes of
conduct and how such conflicts will be
resolved. Ameren states that the
Commission apparently intended the
new regulations to supersede the
existing affiliate restrictions/codes of
conduct, but asserts that clarification is
needed. Thus, in order to avoid
uncertainty and increase transparency,
Ameren asks the Commission to clarify
whether the new regulations take
precedence over the affiliate
restrictions/codes of conduct currently
on file upon the effective date of the
new regulations.328
Commission Determination
245. The Commission clarifies that
the new affiliate restriction regulations
promulgated in Order No. 697 and
codified in § 35.39 supersede the codes
of conduct approved by the Commission
prior to Order No. 697’s effective
date.329 The affiliate restrictions in
§ 35.39 now govern the relationship
between a franchised public utility with
captive customers and its marketregulated power sales affiliates. In the
event of a conflict between a seller’s
previously approved code of conduct
and the new affiliate restriction
regulations, the regulations supersede a
previously approved code of conduct.
For example, if a seller’s previous code
of conduct prohibited information
sharing of any market information,
public or non-public, because the
definition of market information in the
regulations does not prohibit the
disclosure of publicly available
information, a seller may share public

market information under the new
affiliate restrictions.330
246. Nevertheless, where the
Commission had imposed in a
Commission order in a particular case
specific limitations that are more
restrictive than those codified in
§ 35.39, such limitations would
continue to be in effect. We also clarify
that, while all sellers with market-based
rate authority must abide by the affiliate
restrictions as set forth in § 35.39 of the
Commission’s regulations, if a seller
wishes to impose a more restrictive
limitation than currently exists in the
affiliate restrictions, such seller may
propose additional tariff provisions for
the Commission to review in a filing
under FPA section 205.
c. Treatment of ‘‘Field & Maintenance’’
Employees and Shared Operation and
Maintenance Staff in Affiliate
Restrictions
Final Rule
247. In the Final Rule, the
Commission codified in its regulations
the requirement that, to the maximum
extent practical, the employees of a
market-regulated power sales affiliate
must operate separately from the
employees of any affiliated franchised
public utility with captive customers
(independent functioning requirement).
The Commission adopted an exception
to the independent functioning
requirement that permits a franchised
public utility with captive customers
and its market-regulated power sales
affiliates to share senior officers and
members of the board of directors,
support employees, and field and
maintenance employees that perform
purely manual, technical, or mechanical
duties and do not have planning or
direct operational responsibilities.331
Requests for Rehearing
248. FP&L states that certain of these
changes and refinements to the affiliate
restrictions (formerly code of conduct)
appear subject to interpretation, and
certain interpretations may be more
restrictive than intended.332
Specifically, FP&L states the
Commission should clarify that ‘‘field
and maintenance employees’’ include
technical and engineering personnel
engaged in generation-related activities,
provided that such employees do not
themselves: (1) Buy or sell energy; (2)
make economic dispatch decisions; (3)
determine (as opposed to implement)
outage schedules; or (4) engage in power

324 Id.

327 Id.

330 See

325 Id.

328 Ameren

331 Id.

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at P 924.
Rehearing Request at 7.
329 Clarification Order, 121 FERC ¶ 61,260 at P 5.

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id. P 592.
P 561–63, 565; 18 CFR 35.39(c)(2)(ii).
332 FP&L Rehearing Request at 2, 4.

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marketing activities.333 FP&L states that
sharing such employees does not
diminish or jeopardize the requirement
of separation of functions ‘‘to the
maximum extent practical,’’ and is
‘‘unlikely to harm captive
customers.’’ 334
249. Additionally, FP&L urges that the
Commission clarify that ‘‘field and
maintenance employees’’ include noncommercial technical and engineering
personnel involved in nuclear plant
operations.335 FP&L notes that, in the
context of nuclear plant operations,
adherence to Nuclear Regulatory
Commission (NRC) requirements and
safe operations in general often are
facilitated by the creation of a broad
knowledge pool using all of a
company’s personnel with expertise in
nuclear operations.336
250. EEI notes that Order No. 697
allows franchised public utilities with
captive customers and their marketregulated power sales affiliates to share
field and maintenance employees and
their supervisors, but that it conditions
this allowance on the employees and
supervisors not exercising ‘‘control’’
over generation facilities.337 If
interpreted broadly, EEI argues this
condition could eliminate the ability to
share such staff that work on generation
facilities, because operation and
maintenance of generation facilities
necessarily involve the ability to curtail
or stop operation of the facilities. EEI
requests that the Commission clarify
that companies may share such
employees and supervisors even if the
employees and supervisors have the
authority to curtail or stop the operation
of generation facilities as part of their
operation and maintenance functions,
so long as the employees are not
involved in decisions regarding the
marketing or sale of electricity from the
facilities.338

252. We have no evidence that such
field and maintenance employees have
engaged in behavior that would
adversely affect captive customers.
Additionally, we note that such field
and maintenance employees are still
subject to the no-conduit rule. Based on
the evidence before us, the existing
regulations and the overarching purpose
of the affiliate restrictions, we find that
excepting field and maintenance
employees from the independent
functioning requirement, provided such
employees do not engage in prohibited
actions as outlined above, is consistent
with the affiliate restrictions. This
clarification also is applicable to FP&L’s
request regarding shared employees
involved in nuclear plant operations.339
253. In response to EEI’s request for
clarification, although Order No. 697
states that operational employees may
not be shared, the Commission clarifies
that companies may share employees
and supervisors who have the authority
to curtail or stop the operation of
generation facilities solely for
operational reasons. However, shared
employees may not be involved in
decisions regarding the marketing or
sale of electricity from the facilities,
may not make economic dispatch
decisions, and may not determine the
timing of scheduled outages for
facilities. The Commission did not
create the exception for permissiblyshared field and maintenance
employees to enable those employees to
confer a benefit on a franchised power
utility’s market regulated power sales
affiliate to the detriment of captive
customers. Thus, to ensure that captive
customers are not harmed, shared field
and maintenance employees may not
make economic dispatch decisions or
determine when scheduled maintenance
outages (as opposed to emergency
forced outages) will occur.

Commission Determination

d. Risk Management Employees Under
the No-Conduit Rule

251. We grant FP&L’s request for
clarification that ‘‘field and
maintenance employees’’ includes
technical and engineering personnel
engaged in generation-related activities,
provided that such employees do not
themselves: (1) Buy or sell energy; (2)
make economic dispatch decisions; (3)
determine (as opposed to implement)
outage schedules; or (4) engage in power
marketing activities.
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333 Id.

at 3, 6–7.
at 6.
335 Id. at 7.
336 Id.
337 EEI Rehearing Request at 5 (citing Order No.
697 at P 565).
338 EEI Rehearing Request at 3–4 and 5–6.
334 Id.

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Final Rule
254. 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
339 Order No. 697 permits the sharing of
information to enable nuclear power plants to
comply with the requirements of the NRC as
described in the NRC’s February 1, 2006 Generic
Letter 2006–002, Grid Reliability and the Impact on
Plant Risk and the Operability of Offsite Power.
Order No. 697 at P 581.

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restrictions.340 Otherwise, Order No.
697 did not specifically address the
sharing of risk management employees.
Requests for Rehearing
255. FP&L requests that the
Commission clarify that, subject to the
no-conduit rule, risk management
employees may permissibly be shared
under the affiliate restrictions.341 FP&L
states that, while it does not believe
Order No. 697 establishes a prohibition
against shared risk management
employees, in the absence of an explicit
reference to risk management in
§ 35.39(c)(2)(ii), Order No. 697 has
created confusion.342
Commission Determination
256. We find 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 noconduit rule and may not pass market
information to marketing function
employees.343
e. Definition of ‘‘Market Information’’
Final Rule
257. In Order No. 697, the
Commission adopted a definition of
market information: ‘‘non-public
information related to the electric
energy and power business including,
but not limited to, information regarding
sales, cost of production, generator
outages, generator heat rates,
unconsummated transactions, or
historical generator volumes.’’ 344 The
Commission explained that market
information includes information that, if
shared between a franchised public
utility and a market-regulated affiliate,
could result in a detriment to the
franchised public utility’s captive
customers.345
Requests for Rehearing
258. Ameren argues that, in
introducing its new definition of
‘‘market information,’’ for purposes of
the restrictions on affiliates sharing
340 Order No. 697 (to be codified at 18 CFR
35.39(g)).
341 FP&L Rehearing Request at 8.
342 Id. at 10.
343 See Standards of Conduct for Transmission
Providers, Notice of Proposed Rulemaking, 73 FR
16,228 (March 27, 2008), FERC Stats. & Regs.
¶ 32,630 (March 21, 2008) (Standards of Conduct
NOPR).
344 Order No. 697 at P 591 (to be codified at 18
CFR 35.36(a)(8)).
345 Id. P 593.

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information, the Commission
incorrectly quotes from its 1996 order in
UtiliCorp United, Inc.346 Specifically,
Ameren alleges that the Commission
recited the list of types of data from
UtiliCorp, but added ‘‘past’’ to the
litany. According to Ameren, this
‘‘misquote’’ sets the stage for the new
definition to include past information,
such as ‘‘historical generator volumes’’
and ‘‘past sales and purchase activities.’’
Ameren requests rehearing of this
expansion of the definition of the term
‘‘market information’’ to include past
information. In addition, Ameren states
that the Commission does not explain
how past information, such as historical
generator volumes, could be used to the
detriment of the franchised public
utility’s captive customers.347
Commission Determination
259. The Commission denies
Ameren’s request for rehearing. The
Commission is intentionally including
past market information in the
information disclosure prohibitions
because there are instances in which the
sharing of historical (or past) market
information between a franchised public
utility with captive customers and a
market-regulated power sales affiliate
can potentially harm captive customers.
For example, if a market-regulated
power sales utility had knowledge of its
affiliated franchised public utility’s
prior costs of purchasing power, it could
use this information to outbid a
competitor in a request for proposals to
supply power to the franchised public
utility. We note, however, that the
restriction on sharing market
information, whether past, present, or
future, does not apply to information
that is publicly available.348
D. Mitigation
1. Cost-Based Rate Methodology
a. Selecting the Particular Units that
Form the Basis of the ‘‘Up To’’ Rate

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Final Rule
260. Where a seller adopts the default
cost-based mid-term rate or otherwise
proposes a cost-based rate designed on
the unit or units expected to run, the
Final Rule continues to allow the seller
flexibility in proposing the particular
units that form the basis of the ‘‘up to’’
rate. The Commission determines
whether such proposals are just and
reasonable on a case-by-case basis. The
346 75

FERC ¶ 61,168 (1996) (UtiliCorp).
Rehearing Request at 8.
348 Order No. 697 at P 592. To use an example
cited by Ameren, once past sales information is
filed with the Commission in an EQR, such
information would not be covered by the
information disclosure prohibition.
347 Ameren

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Final Rule also reiterated that any seller
proposing an alternative mitigation
methodology carries the burden of
justifying its proposal.349
Requests for Rehearing
261. TDU Systems and NRECA
suggest that allowing sellers to choose
the unit or units expected to run can
affect the ‘‘up to’’ default rate for midterm sales, and also skew the default
incremental cost rate for short-term
sales.350 TDU Systems 351 and
NRECA 352 claim that the Final Rule
failed to adopt measures to ensure that
the mitigated rates of large public
utilities reflect their actual cost of
service. TDU Systems and NRECA
submit that the Commission should
adopt more stringent controls over
sellers’ discretion in establishing costbased rates for mid-term sales in
markets where a seller has been found,
or is presumed, to have market
power.353 NRECA reiterates a proposal
made in its comments to the NOPR that,
for mid-term sales, the Commission
should enforce a matching or
consistency principle: The same
generating units should be used as the
basis for the fixed and variable costs in
determining the default embedded-cost
rate.354 NRECA asserts that a matching
or consistency principle would help to
ensure that a mitigated seller cannot
mix high-fixed-cost units with highvariable-cost units to artificially inflate
the embedded-cost rate. At the same
time, NRECA adds that if a seller can
show that a portfolio of generating units
is likely to be used to provide service,
then the seller might be permitted to use
a weighted average of the fixed and
variable costs of the portfolio.
262. NRECA also proposes that the
Commission require public utilities, in
addition to justifying their mitigated
rates prior to the rate becoming
effective, to also file ex post quarterly
reports of the actual sales and the actual
incremental or embedded costs incurred
in making sales for terms of one year or
less. Such mitigated cost-based rate
sales, NRECA reasons, would be subject
to a cost-based formula rate, and thus
349 Id.

P 649.
Rehearing Request at 25; TDU Systems
Rehearing Request at 9.
351 TDU Systems Rehearing Request at 4 (citing K
N Energy, Inc. v. FERC, 968 F.2d 1295, 1303 (D.C.
Cir. 1991)).
352 NRECA Rehearing Request at 3 (citing N.
States Power Co. v. FERC, 30 F.3d 177, 181–82 (D.C.
Cir. 1994); 5 U.S.C. 706(2)(A), (C)).
353 TDU Systems Rehearing Request at 4 (citing
American Mining Congress v. EPA, 907 F.2d 1179,
1187 (D.C. Cir. 1990)).
354 Id. at 27 (citing N. States Power Co. v. FERC,
30 F.3d 177, 181–82 (D.C. Cir. 1994)); see also TDU
Systems Rehearing Request at 26–27.
350 NRECA

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subject to refund. In NRECA’s view,
providing for a case-by-case review of
proposed cost-based rates prior to
implementation of the rates does not
address concerns that arise after the
mitigated cost-based rates become
effective.355
263. NRECA contends that it is
inconsistent with the FPA 356 to place
the burden on customers to file a
complaint pursuant to section 206 357 in
order to ensure that the mitigated rates
are just and reasonable in the first
instance. Moreover, NRECA claims that
because any rate relief would be
prospective from the date of the
complaint,358 this would allow unjust
and unreasonable rates to be charged
until a complaint is filed.359
Commission Determination
264. On the issue of selecting the
particular units that form the basis of
the ‘‘up to’’ rate for mitigated mid-term
sales, we will continue to apply our
current methodology. TDU Systems and
NRECA are concerned that the Final
Rule failed to adopt measures to ensure
that proposed mitigated rates for sales of
less than one year reflect the mitigated
sellers’ actual cost of service. These
entities assert that imposing a matching
or consistency principle on mitigated
sellers’ proposed cost-based rate
methodologies would help to prevent
mitigated sellers from mixing high
fixed-cost units with high variable-cost
units that could artificially inflate the
mitigated seller’s embedded cost rate.
We find that the Commission’s current
methodology allows mitigated sellers
reasonable discretion to propose units to
use in determining a cost-based rate
while at the same time requiring any
such proposal to be cost-justified and
approved by the Commission. This
balancing of a seller’s right under the
FPA to propose rates with the obligation
to cost-justify such rates to the
Commission provides the Commission
adequate oversight to ensure that rates
remain just and reasonable, and to
prevent the mitigated seller from
artificially inflating its cost-based rates.
Once a seller files proposed rates, they
are noticed for comment, and interested
parties may file requests to intervene
and comments. If there are issues of
material fact as to the proposed rates,
such issues may be set for hearing. The
Commission reviews the mitigated
seller’s proposed rates, including a
355 Id.

at 25–26.
at 26 (citing Mun. Light Bds. v. FPC, 450
F.2d 1341, 1348 (D.C. Cir. 1971)).
357 Id. (citing 16 U.S.C. 824e).
358 Id.(citing 16 U.S.C. 824e(b)).
359 Id. at 27 (citing Arkla v. Hall, 453 U.S. 571,
582 (1981)).
356 Id.

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stacking analysis to determine the
seller’s generation unit(s) likely to
provide the service.360 In addition, the
Commission analyzes the costjustifications for the proposed rates to
determine if the proposed rates meet the
just and reasonable standard. As such,
while a mitigated seller has the
discretion to propose its choice of units,
the Commission’s process of reviewing
the rate resulting from a seller’s
proposal ensures that such sellers do
not have ‘‘excessive leeway’’ in
proposing a cost-based rate, despite
NRECA’s claim to the contrary.
265. NRECA argues that placing the
burden on customers to file a section
206 complaint to ensure mitigated rates
are just and reasonable in the first
instance is inconsistent with the FPA.
Rather than placing a burden on
customers to ensure just and reasonable
rates, the Commission first requires the
mitigated seller to cost-justify any
proposed cost-based rates. To wit, the
mitigated seller may propose cost-based
rates for Commission review; however,
the seller does not have authorization to
charge such rates until the Commission
acts on the seller’s proposal. Thus, the
Commission’s process does ensure that
a mitigated seller’s rates are just and
reasonable in the first instance. To the
extent that a mitigated seller’s cost of
providing the service decreases, the
Commission’s long-standing practice is
to consider claims of over-recovery in
complaint proceedings.361 Moreover,
beyond proposing its matching
principle, NRECA has failed to explain
how adding this requirement would
improve our current mitigation
methodology. NRECA also provides no
justification for treating mitigated sellers
360 A stacking analysis is performed in order to
determine the fixed costs associated with the
generating units likely to participate in off-system
sales, where the related energy is priced based on
incremental costs. The first portion of the analysis
is the stacking of the generating units where data
is recorded from each unit in the order of increasing
Fuel O&M cost per kWh (lowest to highest). Power
for off-system sales will only be provided after the
utility has met its firm native load. The analysis
assumes that the native load approximates the
company’s annual peak (in other words, any unit
needed to serve the utility’s minimum annual peak
will not be available for off-system sales). The next
part of the analysis is to determine which units will
participate in the off-system sale. This part of the
analysis can be a judgmental process. First, one
eliminates those units that are uneconomical to
make the sale. Next, one selects those units that are
(1) usually stacked just above the peak and (2) have
fuel costs that are economical to make the offsystem sale.
361 Allegheny Power System Operating Cos., 111
FERC ¶ 61,308, at P 46 (2005) (‘‘if a concern arises
regarding over-recovery of transmission costs, such
parties are free to seek relief by filing a complaint
* * * pursuant to section 206 of the FPA.’’);
Michigan Wolverine Power Supply Coop., Inc., 99
FERC ¶ 61,326 (2002).

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using a cost-based rate differently than
any other cost-based rate sellers.
266. NRECA also complains that
without a reporting procedure for midterm sales requiring ex-post filings of
quarterly reports of actual sales and
costs incurred, the Commission cannot
ensure that the default cost-based rates
for mitigated mid-term sales reflect the
actual cost of service and are just and
reasonable.362 However, as the
Commission determined in Order No.
697, when a mitigated seller proposes
cost-based mitigation, such an entity is
obligated to comply with the
Commission’s accounting and reporting
regulations, found in Parts 41, 101 and
141 363 of the Commission’s
regulations.364 As the Commission
explained, these requirements are
imposed in order to maintain adequate
financial information with regard to
mitigated sellers so that the Commission
can exercise its duties and
responsibilities under the FPA to ensure
that rates remain just and reasonable
and not unduly discriminatory or
preferential.365 The Commission and
customers and competitors can rely on
these financial forms to evaluate the
adequacy of existing cost-based rates.366
The Commission expects that
customers’ access to this data will allow
them to demonstrate if rates have
become unjust and unreasonable.367
b. Sales of One Year or Greater
Final Rule
267. The Final Rule retained the
existing default mitigation policy for
sales of one year or more (long-term).
Specifically, the Commission
determined that it will continue to
require mitigated sellers to price long362 We note that while public utilities are
required to file electric quarterly reports detailing
transaction information, including price, for all
market-based and cost-based power sales, such
reports do not contain ex-post details of individual
cost components.
363 Part 41 pertains to adjustments of accounts
and reports; Part 101 contains the Uniform System
of Accounts for public utilities and licensees; Part
141 describes required forms and reports. Section
301(a) of the FPA authorizes the Commission to
prescribe rules and regulations concerning
accounts, records and memoranda as necessary or
appropriate for the purposes of administering the
FPA.
364 Order No. 697 at P 986, 992.
365 Id. P 993.
366 See, e.g., Quarterly Financial Reporting and
Revisions to the Annual Reports, Order No. 646,
FERC Stats. & Regs. ¶ 31,158, at P 16–17, order on
reh’g, Order No. 646–A, FERC Stats. & Regs.
¶ 31,163 (2004).
367 See Houlton Water Company, 55 FERC
¶ 61,037 (1991) (dismissing complaint where
customers failed to present prima facie case of
excessive rates and noting that they had access to
utility’s Form No. 1 data, among other data, and
could prepare cost study on that basis).

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term sales on an embedded cost of
service basis and to file each such
contract with the Commission for
review and approval prior to the
commencement of service.368 We note
that our mitigation in this regard is
prospective and does not impact any
existing long-term contracts.
268. Furthermore, the Final Rule
retained the existing generation market
power analyses (renamed to be a
horizontal market power analysis) with
minor changes and dismissed the
request that the Commission consider
different product analyses for short- and
long-term products.369 Instead, the Final
Rule retained the existing mitigation
where a failure to rebut the presumption
of short-term market power results in
the mitigation of both a seller’s shortterm and long-term sales.
Requests for Rehearing
269. Long-Term Sellers (LT
Sellers),370 Ameren, Southern, EEI, and
OG&E take positions, in whole or in
part, that the Commission erred in the
Final Rule by adopting a policy that (1)
generically mitigates long-term
transactions based on a finding of
market power under the Commission’s
horizontal market power analyses which
focuses on short-term markets; (2) fails
to recognize that absent entry barriers,
long-term capacity markets are
inherently competitive; and (3) does not
account for previously recognized
distinctions between short-term and
long-term transactions.371 Some assert
that mitigation of long-term transactions
is inconsistent with the Commission’s
finding in Order No. 697 that long-term
markets are presumptively competitive,
could reduce competition and raise
prices in long-term markets, and have
the effect of discouraging long-term
transactions and investment, which the
Commission has encouraged.372 They
seek clarification and/or rehearing of
this policy.
270. They put forth the following
arguments and rationale in support of
368 Id. P 659 (citing April 14 Order, 107 FERC
¶ 61,018 at P 151, 155).
369 Id. P 122.
370 LT Sellers include Public Service Company of
New Mexico, Duke Energy Corporation, E.ON U.S.,
Progress Energy, Inc. (filing on behalf of its
subsidiaries), Oklahoma Gas and Electric Company,
PacifiCorp, Tucson Electric Power Company,
Arizona Public Service Company, and Pinnacle
West Marketing & Trading Co., LLC.
371 Southern Rehearing Request at 26 (citing
Wholesale Competition in Regions with Organized
Electric Markets, Advance Notice of Proposed
Rulemaking, FERC Stats. & Regs. ¶ 32,617, at P 85
(2007), and Energy Policy Act of 2005, Pub. L. No.
109–58, 119 Stat. 594 (2005), sec. 1253).
372 Ameren Rehearing Request at 9; LT Sellers
Rehearing Request at 3, 10. See also EEI Rehearing
Request at 11; OG&E Rehearing Request at 11.

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their requests, and offer specific options
for the Commission to consider in terms
of relief. Southern states that, according
to the Final Rule, the indicative screens
are only ‘‘snapshots in time,’’ utilize
only short-term data inputs focusing
only on existing capacity holdings and
consider only historical energy markets;
thus, they cannot provide any
reasonable information regarding supply
and demand conditions in future
markets. Southern and OG&E argue that
the Commission should abandon the
indicative screens and the DPT as bases
for mitigation measures in long-term
markets and that a more appropriate
analysis for determining whether market
power exists in long-term markets is
whether potential suppliers are barred
from entering the market.373 LT Sellers,
Southern, and EEI argue that the
analysis of long-run market power
should consider vertical market
power.374 EEI offers that, absent barriers
to entry and vertical market power,
buyers in long-term markets have
competitive alternatives, including the
option to build new generation or to
enter long-term transactions for third
parties to do so, that will preclude
sellers from exercising market power.
EEI requests that the Commission clarify
that it will consider the ability of a
seller to exercise vertical market power
or to erect other barriers to entry, rather
than horizontal market power, in
determining whether sellers may enter
long-term transactions at market-based
rates.375
271. In terms of specific ways the
Commission may address the issue of
long-run market power, LT Sellers asked
the Commission to find that the Final
Rule allows sellers who fail one or both
indicative screens to file a separate tariff
for long-term capacity and energy sales
at market-based rates, and that such a
tariff would be accepted if that seller
satisfies the Commission’s vertical
market power analysis, which addresses
the relevant issues regarding long-term
sales: Transmission market power and
barriers to entry.376 According to LT
Sellers, such tariffs could be limited by
their terms to contracts of sufficient
duration and that begin sufficiently far
into the future to ensure that selfbuilding or new construction by others
is a viable option and, thus, that the
threat of new entry disciplines the

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373 Southern

Rehearing Request at 27–28; OG&E
Rehearing Request at 10.
374 LT Sellers Rehearing Request at 10; Southern
Rehearing Request at 28; and EEI Rehearing Request
at 5, 10–11.
375 EEI Rehearing Request at 10–11. See also
Ameren Rehearing Request at 10.
376 Id. at 21.

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prices under the contracts subject to the
tariff.377
272. LT Sellers recognizes that there
will be circumstances in which a tariff
for long-term sales at market-based rates
may not be appropriate for a particular
seller. Therefore, LT Sellers contends
that the Commission should establish
several safe harbors for factual
circumstances in which the Commission
can take comfort in the lack of long-term
market power such that a seller can file
stand-alone long-term contracts with the
Commission under a rebuttable
presumption that the contract rate is just
and reasonable.378 For example, LT
Sellers suggests that a safe harbor would
be appropriate where a seller
demonstrates that its buyer conducted
an Allegheny-type request for proposals,
or where it conducted an informal
procurement and provides sufficient
evidence that the contract was not the
result of any market power.
273. Southern, Ameren, OG&E, and
EEI similarly request that the
Commission clarify that even if a seller’s
blanket market-based rate authority is
revoked, the seller may still seek
Commission approval of long term
market-based rate contracts on an
individual basis.379 Southern argues
that this clarification is necessary and
appropriate because the absence of
blanket authorization to make marketbased rate sales should not preclude a
seller from entering into long-term
market-based rate transactions with
individual buyers over whom the seller
does not have market power. Southern
also requests that the Commission
clarify the standards that it would
utilize in determining whether to
approve individual long-term marketbased rate contracts on a case-by-case
basis. In this regard, Southern submits
that for each such long-term transaction
filed with the Commission for approval,
there would be no presumption that the
seller has market power over the
applicable buyer. Instead, there would
be a separate evaluation process that
would consider the specific
circumstances applicable to each
particular transaction and buyer.380
According to Southern, the Commission
should consider establishing other
exceptions to allow sellers without
blanket market-based rate authority to
transact on a long-term basis, and the
Commission should undertake to
identify the types of circumstances
377 Id.

at 10–11.
378 LT Sellers Rehearing Request at 11, 24–27.
379 Southern Rehearing Request at 29–30; Ameren
Rehearing Request at 10; OG&E Rehearing Request
at 11.
380 Southern Rehearing Request at 29.

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25871

where market power concerns generally
are not present, irrespective of whether
a seller ultimately passes the Final
Rule’s criteria for blanket authority.381
274. Several petitioners take a
contrary view. APPA/TAPS and
Montana Counsel, in whole or in part,
are concerned that the Commission’s
statement about the inherent
competitiveness of long-term markets
may invite public utilities to seek to
avoid any examination of market power
in long-term markets, even on a casespecific basis.382
275. While Montana Counsel agrees
that ‘‘[t]he markets for short-term energy
purchases and long-term firm capacity
supplies are undeniably distinct,’’ it
states that the Commission should not
assume that there can be no market
power for long-term firm capacity
supplies; instead, it should require
market-based rate applicants to
demonstrate that they do not possess
market power in the long-term
market.383 In particular, Montana
Counsel argues that the Commission
seems to assume that barriers to entry
are the exception rather than the rule,
and that generation will usually be built
to counteract long-term market power.
Montana Counsel argues that the
Commission’s reliance on an academic
hypothesis for its statement that ‘‘[a]s
the Commission has stated in the past,
absent entry barriers, long-term capacity
markets are inherently competitive
because new market entrants can build
alternative generating supply’’ in
support of a major policy is
unsupported, arbitrary, and capricious.
Montana Counsel offers that at least one
recent analysis of barriers to entry in
generation markets weighs against the
Commission’s assumption.384
276. Montana Counsel states that the
presence in a market of a seller with
market power can itself be a barrier to
entry, especially if the market is isolated
by transmission constraints; for
example, any new entrant would face
the risk of predatory pricing by the
incumbent seller, and transmission
constraints would prevent the newlybuilt generation from being ‘‘moved’’ to
a more hospitable market. Montana
Counsel states that if the Commission
grants market-based rate authority to a
seller based on a presumption that new
generation can enter the market and that
381 Id.

at 30.

382 APPA/TAPS

Rehearing Request at 12–13.
at 7.
384 Montana Counsel Rehearing Request at 4–5
(citing John M. Kelly, Power Plants Don’t Fly—and
Other Non-Artificial Barriers to Competition in
Wholesale Power Markets, 26th USAEE/IAEE North
American Conference Plenary Session, (Sept. 25,
2006)).
383 Id.

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seller in fact has market power, it will
be allowing unjust and unreasonable
rates.385
277. APPA/TAPS also challenge the
Commission’s statement regarding the
competitiveness of long-term markets,
arguing that an examination of the
evidence shows a lack of factual support
for this conclusion.386 In addition, they
assert that the scope of RTO/ISO
mitigation is much narrower than the
default, cost-based mitigation the
Commission prescribes; they note that
the Commission has stated that RTO/
ISO mitigation and the market-based
rate analysis are different and that
‘‘ ‘pieces of one should not
automatically be used as precedent for
the other.’ ’’ 387 APPA/TAPS state that
RTO/ISO mitigation measures apply
only to spot markets and day-ahead
and/or real-time, but do not apply to
weekly, monthly or long-term
transactions, including those negotiated
on a bilateral basis, and that RTO/ISO
mitigation is often far less protective
than the Commission’s default costbased rates.
278. Montana Counsel states that the
Commission should consider evidence
on the subject of barriers to entry in
generation markets in this rulemaking,
and in individual proceedings it should
require sellers seeking market-based rate
authority to present data on current
generation markets from which the
Commission can develop a factual
record on which it can base a reasoned
decision.388 Montana Counsel argues
that the burden of demonstrating the
existence of barriers to entry should not
be on intervenors; rather the burden
should be on the seller seeking the
privilege of market-based rate authority
385 Montana Counsel Rehearing Request at 5
(citing FPA sections 205–206; Gulf States Utils. Co.
v. FPC, 411 U.S. 747 (1973)).
386 APPA/TAPS Rehearing Request at 6 (citing
AEP Power Marketing, Inc., 107 FERC ¶ 61,018 at
P 155 (2004) (April 14 Order). APPA/TAPS also
cites a study that concluded that investment was
not occurring in high-priced LMP areas, which in
theory should attract new entry. The study
concluded ‘‘that the LMP price signals are
overwhelmed by other factors in these areas, such
as structural barriers to entry, competing economic
incentives, and the lack of a clear mechanism for
assuring return on investment in certain types of
projects.’’ Synapse Energy Economics, Inc., LMP
Electricity Markets: Market Operations, Market
Power, and Value for Consumers, Executive
Summary (Feb. 5, 2007) available at http://
www.appanet.org/files/PDFs/
SynapseLMPElectricity
MarketExecSumm013107.pdf (emphasis added by
APPA/TAPS).
387 APPA/TAPS Rehearing Request at 24 (citing
Midwest Independent Transmission System
Operator, Inc., 109 FERC ¶ 61,157, at P 242 (2004),
order on reh’g, 111 FERC ¶ 61,043 (2005).
388 Id. at 5 (citing 5 U.S.C. 706(2); Motor Vehicle
Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co., 463
U.S. 29 (1983)).

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to demonstrate the absence of barriers to
entry, i.e., the existence of a competitive
market for long-term power supply.
Commission Determination
279. As discussed below, we will
grant rehearing in part and modify our
policy regarding the mitigation of longterm sales. The Commission has long
held that long-term markets may be
presumed to be competitive, absent
barriers to entry, and has taken actions
within its authority to eliminate barriers
to entry.389 Even if a seller is found to
have market power in the short-term,
that market power can be mitigated or
eliminated by the meaningful
opportunity for other sellers to enter the
market in order to compete with the
seller and drive down prices.390 Given
adequate time, notice, and the absence
of entry barriers, proposals for new
infrastructure will emerge in response to
price signals. Sellers and buyers will
have an opportunity to plan and
respond, as their needs dictate. Whether
there is a meaningful opportunity for
entry and when that opportunity is
expected to occur may vary depending
on such factors as the type or size of
resource needed (e.g., system, peaking),
whether multiple resources are needed
(e.g., transmission and generation), and
siting and permitting considerations.
280. In this regard, we agree with
some of the concerns raised by
petitioners and will allow sellers to
demonstrate on a case-by-case basis that
they do not have market power with
respect to long-term contracts. We have
considered the arguments raised by LT
389 See 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, 61 FR 21540
(May 10, 1996), FERC Stats. & Regs. ¶ 31,036, 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);
Standardization of Generator Interconnection
Agreements and Procedures, Order No. 2003, FERC
Stats. & Regs. ¶ 31,146 (2003) order on reh’g, Order
No. 2003–A, FERC Stats. & Regs. ¶ 31,160, order on
reh’g, Order No. 2003–B, FERC Stats. & Regs.
¶ 31,171 (2004), order on reh’g, Order No. 2003–C,
FERC Stats. & Regs. ¶ 31,190 (2005), aff’d sub nom.
Nat’l Ass’n of Regulatory Util. Comm’rs v. FERC,
475 F.3d 1277 (D.C. Cir. 2007); Regulation of
Natural Gas Pipelines after Partial Wellhead
Decontrol, Order No. 436, FERC Stats. & Regs.
¶ 30,665 (1985); Preventing Undue Discrimination
and Preference in Transmission Service, Order No.
890, 72 FR 12,266 (Mar. 15, 2007), FERC Stats. &
Regs. ¶ 31,241, order on reh’g, Order No. 890–A, 73
FR 2984 (Jan. 16, 2008), FERC Stats. & Regs.
¶ 31,261 (2007).
390 See, e.g., W. Kip Viscusi, et al., Economics of
Regulation and Antitrust 153–55, (MIT Press 2000)
(1992).

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Sellers, Ameren, Southern, EEI and
OG&E that the Commission erred in the
Final Rule by adopting a policy that in
all circumstances mitigates long-term
sales based on a finding of market
power under the Commission’s
horizontal market power analyses. We
agree that the indicative screens and the
DPT only examine the presence of
market power in the short-term; the
Final Rule did not alter the indicative
screens or the DPT to allow different
product analyses for short-term or longterm power. In response to Southern’s
assertion that the short-term analyses
cannot provide any reasonable
information regarding supply and
demand conditions in future markets,
we find that historical data, while
perhaps an imperfect fit with regard to
analyzing market power in forward
markets and not to be relied on solely,
does provide some indication as to the
seller’s ability to exercise market power.
This notwithstanding, we believe that
there is merit to petitioners’ claims
regarding the differences between longand short-term markets, and the
potential impact of the Final Rule on
long-term contracting. As such, we grant
clarifications and rehearing as discussed
herein. Our decision to do so ensures
just and reasonable rates while not
impeding long-term contracting. To this
end, and as discussed below, we are not,
as Montana Counsel argues, simply
relying on an unsupported hypothesis
that entry will occur and discipline
these markets to ensure just and
reasonable rates. Rather, we will assess
the facts and record presented with each
individual section 205 application.
281. Accordingly, we grant rehearing
in part and provide that any seller who
fails the Commission’s market-based
rate test or surrenders market-based rate
authority (referred to herein as
‘‘mitigated sellers’’) may file with the
Commission under FPA section 205, on
a case-by-case basis, a request for
contract-specific market-based rates
based on a demonstration that the seller
does not have market power with
respect to the specific long-term
contract being filed. The Commission
will not in this rulemaking promulgate
tariffs of general applicability or provide
generic safe harbors for long-term sales.
As petitioners note, the market-based
rate program focuses on short-term
markets. The record before us is not
sufficient to justify a generic marketbased rate tariff for long-term sales or to
create a ‘‘safe harbor’’ for such
transactions.
282. Therefore, on a case-by-case
basis, the mitigated seller must show
that a buyer under a long-term contract
has viable alternatives including the

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entry of an appropriate amount of thirdparty newly-constructed resources
during the relevant future period as an
alternative to purchasing under the
contract at issue. In order to make the
relevant showing, the seller would have
to show that its proposed contract is of
a sufficiently long duration and
provides for service to commence
sufficiently far into the future, such that
other sellers had a reasonable
opportunity to enter the market; and
that a buyer had other viable,
comparable alternatives, which could
include self-build options and thirdparty new construction. This builds
upon the LT Sellers’ proposal (albeit in
the context of a tariff) that such
contracts ‘‘could be limited by their
terms to contracts of sufficient duration
and that begin sufficiently far into the
future to ensure that self-building or
new construction by others is a viable
option and, thus, that the threat of new
entry disciplines the prices under the
contracts subject to the tariff.’’ 391 At
this time we are not imposing any
specific requirements on the evidence
that the mitigated sellers must submit
with their application. Nevertheless, we
observe that mitigated sellers who
identify a specific buyer for a proposed
contract will be better able to provide
the Commission with an understanding
of the viable and comparable
alternatives that the particular buyer
may have.
283. The fact that the Commission
will review all of these contracts under
section 205 of the FPA and provide
notice and opportunity for comment
addresses Montana Counsel’s concern
that the Commission would rely on an
academic hypothesis of entry without
regard to the justness and
reasonableness of rates. Sellers bear the
burden in an FPA section 205
proceeding to demonstrate that rates are
just and reasonable.392 We have also
addressed Montana Counsel’s concern
that we have placed the burden of
proving barriers to entry on the
intervenor. As stated above, the seller
has the burden to show that its rates are
just and reasonable and is required to
make the requisite showing. The
Commission will carefully examine the
evidence that will be presented, and we
will deny authority to charge a marketbased rate for a long-term contract when
the mitigated seller cannot meet its
evidentiary burden. Intervenors are
therefore in the position of rebutting
this evidence; they do not carry the
initial (or ultimate) burden of proof.
Moreover, in any application for marketSellers Rehearing Request at 11.
392 18 CFR 35.3(a).

based rate authority, the seller has the
burden to make the requisite disclosures
regarding inputs to electric power
production, describing its ownership of,
control over, or affiliation with entities
that own or control such facilities, as
well as make an affirmative statement
regarding whether it has erected barriers
to entry in the relevant market and
committing not to erect such barriers in
the future. As noted in the Final Rule,
‘‘we are not preventing intervenors from
raising other barriers to entry concerns
for consideration on a case-by-case
basis.’’ 393
284. We do not share the concern
espoused in Montana Counsel’s
example of predatory pricing by the
incumbent seller. Predatory pricing
occurs when a firm sets prices below the
competitive level in order to drive
competitors out of business, then, once
competitors exit the market, uses its
market power to drive the price above
the competitive level. The economic
theory of predatory pricing requires
both the ability and incentive to do so.
In Montana Counsel’s example, if the
mitigated firm did sell below the
competitive price and drive out the
competitors, it could not use its market
power to raise the price at that time
because it would be mitigated by the
Commission to a cost-justified rate. In
other words, such a strategy would be
self-defeating because once competitors
exit a particular market the remaining
firm would no longer pass the indicative
market power screens, and this would
lead to its transactions being mitigated.
Therefore, while a mitigated firm could,
in theory, set prices below the
competitive level to minimize or
eliminate competitors, the
Commission’s mitigation policy creates
an economic disincentive to do so,
which erodes Montana Counsel’s theory
of economic harm.
285. With regard to APPA/TAPS’
suggestion that the scope of RTO/ISO
mitigation is much narrower than the
Commission’s default cost-based
mitigation, we do not believe that such
a distinction should require that costbased mitigation be imposed on longterm contracts entered into by sellers
with market power in RTO/ISO markets.
In RTO/ISOs, buyers have access to
centralized, bid-based short-term
markets which will discipline a seller’s
attempt to exercise market power in
long-term contracts because the wouldbe buyer can always purchase from the
short-term market if a seller tries to
charge an excessive price. The RTO/
ISOs have Commission-approved
market mitigation rules that govern

391 LT

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behavior and pricing in those short-term
markets. Further, the RTO/ISOs have
Commission-approved market
monitoring, where there is continual
oversight to identify market
manipulation.
c. Alternative Methods of Mitigation
Final Rule
286. The Commission determined that
it will address on a case-by-case basis
whether the use of an agreement that is
not tied to the cost of any particular
seller but rather to a group of sellers is
an appropriate mitigation measure.394
287. Specifically, the Final Rule
concluded that use of the Western
Systems Power Pool Agreement (WSPP
Agreement) as a mitigation measure may
be unjust, unreasonable or unduly
discriminatory or preferential for certain
sellers. The Commission instituted in
Docket No. EL07–69–000 a proceeding
under section 206 of the FPA to
investigate whether the WSPP
Agreement ceiling rate is just and
reasonable for a public utility seller in
a market in which such seller has been
found to have market power or is
presumed to have market power.395
288. The Final Rule noted that the
Commission had previously accepted
the use of the WSPP Agreement ceiling
rate as mitigation by a number of sellers.
The Final Rule allowed the sellers to
continue to use the WSPP Agreement
ceiling rate as mitigation, subject to
refund (as of the refund effective date
established in Docket No. EL07–69–000)
and subject to the outcome of the
section 206 proceeding.396
289. The Commission issued an order
in the section 206 proceeding on
February 21, 2008, determining that the
WSPP Agreement’s demand charge
ceiling rate is no longer just and
reasonable for use by public utility
sellers in the market in which the sellers
do not have market-based rate authority,
unless such sellers can cost-justify the
rate.397 The Commission found that in
markets in which a seller has or is
presumed to have market power it is
unjust and unreasonable to allow such
a seller to continue to use the WSPPwide ‘‘up-to’’ demand charge as a
ceiling rate unless the seller can justify
the costs of that charge based on its own
costs.
290. The Final Rule continued to
permit alternative methods of mitigation
to be cost-based. However, while the
Commission did not allow the use of
394 Id.

P 667.

395 Id.
396 Id.

P 673–74.
Systems Power Pool, 122 FERC
¶ 61,139 (2008).
397 Western

393 Order

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alternative ‘‘market-based’’ mitigation
on a generic basis, the Commission held
that it will permit sellers to submit
alternative non-cost-based mitigation
proposals for Commission consideration
on a case-by-case basis.398
Requests for Rehearing
291. No entities sought rehearing
regarding use of the WSPP Agreement to
mitigate market power. APPA/TAPS
request clarification that the
Commission will entertain proposals for
structural mitigation as a condition of
the privilege of market-based rate
authority in specific, future cases.399
APPA/TAPS argue that the Commission,
on the one hand, approves structural
measures to mitigate horizontal market
power, such as the transfer of existing
generation to third parties but, on the
other hand, declares that structural
conditions, such as joint planning and
construction of new generation, are too
burdensome.400 Where the Commission
can impose conditions on an applicant’s
market-based rate authority, APPA/
TAPS support structural mitigation as a
potential condition, and urge the
Commission to identify, in specific
cases, structural conditions that would
allow applicants to obtain market-based
rate authority rather than be limited to
cost-based mitigation.401
Commission Determination
292. As the April 14 Order and Final
Rule both explained, ‘‘[p]roposals for
alternative mitigation * * * could
include cost-based rates or other
mitigation that the Commission may
deem appropriate.’’ 402 While APPA/
TAPS complain that the Final Rule
suggested some structural measures are
too burdensome, in fact the Commission
only determined that entities advocating
structural mitigation as a condition on
market-based rate authorization had not
justified imposing such a burden on a
generic basis. Rather than foreclosing
the possibility of structural measures,
the Commission will continue to permit
sellers to submit non-cost-based
mitigation proposals, including those
involving structural measures, for
Commission consideration on a case-bycase basis based on their particular
circumstances.
398 Order

No. 697 at P 693.
Rehearing Request at 22 (citing
California Indep. Sys. Operator Corp. v. FERC, 372
F.3d 395 (D.C. Cir. 2004)).
400 Id.
401 APPA/TAPS Rehearing Request at 22–23
(citing California Indep. Sys. Operator Corp. v.
FERC, 372 F.3d 395 (D.C. Cir. 2004)).
402 April 14 Order, 107 FERC ¶ 61,018 at n.142;
see also, Order No. 697 at n.46 and P 698.

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399 APPA/TAPS

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293. APPA/TAPS also request that the
Commission identify in specific cases
structural conditions that will enable
applicants to obtain market-based rate
authority, as an alternative to ordering
cost-based mitigation. The Commission
believes that, because mitigation
proposals are evaluated upon the
particular facts and circumstances of
individual proceedings, it would be
premature to identify or list specific
structural measures on a generic basis.
Further, it has been the Commission’s
practice to allow sellers to propose
mitigation to address market power
concerns rather than the Commission
imposing specific mitigation on
mitigated sellers.
2. Protecting Markets With Mitigated
Sellers

based rate authority, would be an
appropriate remedy in a particular case,
depending on the facts and
circumstances, as the Commission has
done in the past.406
296. For many of the same reasons
that the Commission declined to impose
a generic ‘‘must offer’’ requirement, the
Commission also declined to adopt a
‘‘right of first refusal’’ as proposed by
NRECA, whereby captive customers
would have the right of first refusal to
purchase at a market price energy or
capacity that the mitigated seller
proposes to sell outside of the balancing
authority area in which it is mitigated.
The Commission determined that there
was insufficient record evidence to
support imposition of such an acrossthe-board requirement.407

a. Must Offer

Requests for Rehearing

Final Rule
294. In the Final Rule, the
Commission determined not to impose
an across-the-board ‘‘must offer’’
requirement for mitigated sellers,
explaining that there was insufficient
record evidence to support instituting a
generic ‘‘must offer’’ requirement, as
had been proposed by several
commenters. While commenters
proposed several methods for
implementing a must offer
requirement,403 the intent of these
proposals was to preclude the mitigated
seller from selling its available capacity
in markets where it retains market-based
rate authority without first requiring the
mitigated seller to offer available
capacity in the balancing authority area
in which it is mitigated. The
Commission found that although
wholesale customer commenters raised
theoretical concerns that they would be
unable to access power absent a ‘‘must
offer’’ requirement, they did not provide
any concrete examples of harm nor did
they explain how the potential harm
justified the generic remedy they
sought.404 The Commission also found
that there are potential remedies
available on a case-by-case basis to a
wholesale customer alleging undue
discrimination or other unlawful
behavior on the part of a mitigated
seller.405
295. While the Commission did not
impose a generic ‘‘must offer’’
requirement in the Final Rule, the
Commission did not rule out the
possibility of finding that the imposition
of a ‘‘must offer’’ requirement, or some
other condition on the seller’s market403 See,

e.g., id. P 732.
P 759–60.
405 Id. P 763.
404 Id.

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297. APPA/TAPS and NRECA request
that the Commission clarify that the
Final Rule does not pre-judge the
circumstances in which a must offer
condition may be necessary and
appropriate to remedy undue
discrimination or ensure that rates are
just and reasonable.408 APPA/TAPS
state that the Commission appropriately
ties a must offer condition to the need
for a remedy to ensure that wholesale
rates are just, reasonable and not unduly
discriminatory, but objects that the
Commission seems to be limiting any
must offer condition or similar remedy
only to cases involving OATT
violations.409
298. NRECA states that one member
of the Commission expressed
uncertainty about whether a ‘‘must
offer’’ requirement would be
appropriate absent a showing that ‘‘the
mitigated seller is the only entity
physically able to meet all of the buyer’s
needs.’’ 410 NRECA requests that the
Commission clarify that it has not predetermined that it will set the bar for a
must offer requirement to the standard
of total monopoly because it is
406 Id.

P 764.
P 771.
408 APPA/TAPS Rehearing Request at 4, 19 (citing
Transmission Access Policy Study Group v. FERC,
225 F.3d 667 (D.C. Cir. 2000)); NRECA Rehearing
Request at 29.
409 APPA/TAPS Rehearing Request at 4.
Additionally, APPA/TAPS disagrees with the
characterization of its position as urging a ‘‘generic
remedy’’ in the Final Rule. APPA/TAPS argues that
it was careful to specify that the market power
concerns posed by the particular market-based rate
applicant would determine when a must offer
condition would be appropriate. APPA/TAPS
therefore states that it does not view the Final Rule
as a rejection of its position. Id. at 18.
410 NRECA Rehearing Request at 30 (citing Open
Meeting Tr. at 61 (June 21, 2007)).
407 Id.

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inconsistent with the standards adopted
in the Final Rule.
299. NRECA argues that if a public
utility seller is subject to mitigation in
its home balancing authority area, the
seller either has a dominant market
share, its generation is critical for
meeting peak-period demand, or both.
In such cases, NRECA contends that the
withholding of the seller’s generation in
its home balancing authority area could
have a profound effect on the ability of
a captive wholesale customer to provide
electricity at a reasonable price.411
NRECA further argues that if a totalmonopoly standard were applied, a
customer would not be entitled to relief
so long as it could find another entity
able to sell power to it. But, if that single
alternative supplier had market power
in the absence of competition from the
‘‘mitigated’’ seller, then the customer
would be forced to buy that alternative
supplier’s power at monopoly prices,
and the supposedly ‘‘mitigated’’ seller
would be let off the hook. If that single
alternative supplier were also subject to
mitigation, then it too might choose to
sell all of its power outside the
balancing authority area, leaving the
customer with no power at any price,
contrary to FPA obligations.412
300. NRECA further argues that there
is no clear guidance on who would have
the burden of proof either to
demonstrate that a must offer
requirement or some alternative remedy
is necessary or unnecessary, but that the
Final Rule suggests that the customer
would have the burden to prove such a
remedy is necessary.413 NRECA argues
that the seller should bear the burden of
proof in a particular case to demonstrate
that this requirement or an alternative
remedy is unnecessary.414
411 Id. at 31. NRECA also states that ‘‘[t]he
Commission allows wholesale contracts executed or
filed after July 9, 1996, to terminate by their own
terms without prior notice to and approval by the
Commission. Thus, a captive wholesale customer
with a ‘new’ long-term contract may have no
regulatory assurance of continued service even in
a control area where the seller has generation
market power.’’ NRECA at n.94 (citing 18 CFR
35.15(b)).
412 Id. at 31 (citing 16 U.S.C. 824a(a) (authorizing
Commission actions for ‘assuring an abundant
supply of electric energy throughout the United
States with the greatest possibly economy’); 16
U.S.C. 824d(a) (requiring all rates to be just and
reasonable); Energy Policy Act of 2005, section
1233, 119 Stat. 594, 957 (2005) (adding section 217
to FPA, to be codified at 16 U.S.C. 824q, to ensure
long-term transmission rights to load-serving
entities); Am. Gas Ass’n v. FERC, 912 F.2d 1496,
1516–18 (D.C. Cir. 1990) (remanding FERC’s pregranted abandonment rule for failing to address the
‘‘protection of customers from pipeline exercise of
monopoly power through refusal of service at the
end of a contract period’’)).
413 Id. at 30.
414 Id. at 4 (citing Farmers Union Cent. Exch. v.
FERC, 734 F.2d at 1510; NAACP v. FPC, 520 F.2d

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301. TDU Systems also argue that the
Final Rule’s determination not to
impose an across-the-board ‘‘must offer’’
requirement for mitigated sellers leaves
the Commission without any effective
measures to assure that the granting of
market-based rate authority in
competitive markets will not make
things worse in adjacent uncompetitive
markets 415 and asserts that the
Commission should reconsider the
narrow range of mitigation measures it
will employ in the first instance and
include must offer conditions, annual
open seasons, and rights of first
refusal.416 TDU Systems argue that the
Commission’s vague statement that it
could consider such remedies in
particular cases is not sufficient.417 TDU
Systems argue that if the Commission
does not embrace a ‘‘must offer’’
requirement, regulations should list it as
an option 418 because National Fuel 419
does not hold that the Commission must
always determine that existing remedies
and procedures are inadequate before it
adopts any new regulation.420
302. Additionally, TDU Systems argue
that if the Commission declines to
impose a ‘‘must offer’’ requirement, it
should, upon a finding of market power
in a seller’s home balancing authority
area, deny market-based rate
authorization in first-tier markets.421
The immediate concern is the effects
upon the public utility’s continuing
obligations to provide service at
conventionally regulated rates in
markets where it has market power.422
303. TDU Systems argue that it may
be appropriate to impose upon sellers
the initial burden of coming forward
with the proposed remedy.423 TDU
Systems argue that the regulations
should state that the Commission will
look favorably upon a public utility’s
proposal to mitigate market power by
entering into an enforceable
commitment to provide additional
transmission capacity.424
304. Finally, TDU Systems argue that
the Commission has been aware that
relying upon the rights of individual
customers to file complaints after the
432, 438 (D.C. Cir. 1975); 5 U.S.C. 556(d); 5 U.S.C.
706(2)(A), (C); 16 U.S.C. 824d(e)); NRECA
Rehearing Request at 30 (citing 5 U.S.C. 556(d); 16
U.S.C. 824d(e)).
415 Id. at 4 (citing Farmers Union Cent. Exch., Inc.
v. FERC, 734 F.2d 1486, 1510 (D.C. Cir. 1984)).
416 Id. at 8–9.
417 Id. at 9, 22.
418 Id. at 25.
419 Id. at 23 (citing National Fuel Gas Supply
Corp. v. FERC, 468 F.3d 831 (D.C. Cir. 2006)).
420 Id. at 23–24.
421 Id. at 9, 26.
422 Id. at 24.
423 Id. at 25.
424 Id. at 26.

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25875

fact is often not enough to assure overall
achievement of FPA mandates.425
Commission Determination
305. In response to issues raised by
APPA/TAPS and NRECA, we clarify
that we have not pre-judged the types of
specific situations in which we might
impose a ‘‘must offer’’ requirement on a
particular seller.
306. With respect to which party
bears the burden of proof regarding a
‘‘must offer’’ requirement, we cannot
make that determination in the abstract.
The public utility seller has the burden
under section 205 to demonstrate that
its mitigation proposal is just,
reasonable and not unduly
discriminatory. Circumstances in which
a must-offer requirement warrants
consideration cannot be determined in
advance, as we made clear in the Final
Rule. If the public utility seller can meet
its burden of showing that its mitigation
proposal is just and reasonable without
a must-offer requirement, however, then
the burden would be on the challenging
party to show that more is required.
307. TDU Systems continue to
advocate the need for the Commission
to impose an across-the-board ‘‘must
offer’’ requirement on mitigated sellers;
however, they do not provide evidence
supporting such a requirement. For
example, they have not provided
evidence of a widespread and pervasive
situation where customers were unable
to access power due to a mitigated
seller’s business decision to sell its
power outside of the balancing authority
area in which the seller has been found,
or presumed, to have market power.
Absent such compelling evidence, we
will not impose an across-the-board
‘‘must offer’’ requirement. As discussed
in the following section, we also reject
TDU Systems’ request that the
Commission, upon a finding of market
power in a seller’s balancing authority
area, deny market-based rate
authorization in first-tier markets.
308. We also reject TDU Systems’
argument that the Commission list
‘‘must offer’’ in its regulations as a
mitigation option. Section 35.38 of the
Commission’s regulations provides that
a mitigated seller ‘‘may adopt the
default mitigation * * * or may propose
mitigation tailored to its own particular
circumstances to eliminate its ability to
exercise market power.’’ 426 We find that
defining in the regulations the
mitigation options that are available to
all sellers provides sufficient regulatory
certainty and we decline to provide a
list of possible remedies that may not be
425 Id.
426 18

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applicable to all sellers. To do otherwise
would introduce needless regulatory
uncertainty.
309. TDU Systems argue that it may
not be sufficient to rely on a customer’s
right to file a complaint. However,
customers are not limited to filing a
complaint. At the time that a seller
proposes mitigation, a customer has the
opportunity to make its case regarding
concerns it may have with respect to its
ability to access power if the seller is
mitigated in the balancing authority
area. The Commission fully considers
comments made by intervenors and, on
a case-specific basis, if the facts and
circumstances demonstrate a ‘‘must
offer’’ provision is needed to mitigate
market power, the Commission may
impose such a remedy.
b. First-Tier Markets
Final Rule
310. In the Final Rule, the
Commission retained its policy to limit
mitigation to the balancing authority
area in which a seller is found, or
presumed, to have market power. The
Commission did not place limitations
on a mitigated seller’s ability to sell at
market-based rates in balancing
authority areas in which the seller has
not been found to have market
power.427

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Requests for Rehearing
311. APPA/TAPS request the
Commission to clarify that, while it sees
no basis as part of the current
proceeding to revoke an applicant’s
market-based rate authority beyond the
balancing authority areas in which the
applicant has been found to have (or has
accepted the presumption of) market
power, it is not ruling out broader
remedies where required to mitigate the
applicant’s market power in a specific
case.428
312. APPA/TAPS assert that they did
not urge that widespread revocation of
market-based rate authority beyond the
home balancing authority area occur on
a generic basis, but rather, that the
Commission not narrowly circumscribe
its own remedial authority in a specific
case where mitigation of a particular
seller’s market power may require
revocation of its market-based rate
authority beyond its home balancing
authority area.429 APPA/TAPS argue
that the Commission’s statement that
comments ‘‘favoring revocation of a
mitigated seller’s market-based rate
427 Order

No. 697 at P 790.
428 APPA/TAPS Rehearing Request at 4 (citing
Niagara Mohawk Power Corp. v. FPC, 379 F.2d 153
(D.C. Cir. 1967)).
429 Id. at 20.

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authority in markets where there has
been no finding of market power, as
well as those supporting broadening
mitigation to first-tier markets, have not
provided a sufficient legal basis for such
a policy,’’ 430 could be used against the
Commission when it seeks to broaden
the scope of mitigation in that future
case where a more expansive remedy is
factually and legally justified.431
Commission Determination
313. The Commission allows marketbased rate sales of energy and capacity
in all balancing authority areas where
the seller has been granted market-based
rate authority. As the Commission
explained in the Final Rule, ‘‘[w]e
generally agree that it is desirable to
allow market-based rate sales into
markets where the seller has not been
found to have market power.’’ 432
314. With regard to APPA/TAPS’
concern that the Commission should not
narrowly circumscribe its own remedial
authority in a specific case where
mitigation of a particular seller’s market
power may require revocation of its
market-based rate authority beyond its
home balancing authority area, we
clarify that the Commission neither has
nor will foreclose its authority to
remedy market power.
c. Sales That Sink in Markets Without
Mitigated Sellers
Final Rule
315. In the Final Rule, the
Commission continued to apply
mitigation to all sales in the balancing
authority area in which a seller is found,
or presumed, to have market power.433
However, the Commission allowed
mitigated sellers to make market-based
rate sales at the metered boundary
between a balancing authority area in
which a seller is found, or presumed, to
have market power and a balancing
authority area in which the seller has
market-based rate authority, under
certain circumstances.434
316. The Final Rule determined that
allowing market-based rate sales by a
seller that has been found to have
430 Order

No. 697 at P 791.
at 4, 20–21.
432 Id. P 819.
433 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. Clarification Order, 121 FERC
¶ 61,260, at P 7 & n.10.
434 Order No. 697 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).
431 Id.

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market power, or has so conceded, in
the very balancing authority area in
which market power is a concern, is
inconsistent with the Commission’s
responsibility under the FPA to ensure
that rates are just and reasonable and
not unduly discriminatory.435
Requests for Rehearing
317. OG&E complains that the
Commission erred by barring utilities
from selling power within a balancing
authority area in which a seller is found,
or presumed, to have market power
where the buyer’s load sinks in a nonmitigated balancing authority area.436
OG&E claims that the Final Rule
mistakenly assumes that the point of
sale is relevant to the market power
analysis rather than the location of the
load.437 OG&E states that the Final Rule
acknowledges that buyers taking title to
power ‘‘at a metered boundary for
delivery to serve load in a balancing
authority where the seller has marketbased rate authority have competitive
choices and therefore are not required to
transact with the seller found to have
market power within the mitigated
balancing authority area(s).’’ 438 OG&E
suggests that this reasoning applies with
equal force to a transaction where the
buyer chooses to buy power at the
seller’s generator bus for load that is
located in a balancing authority area
where the seller has market-based rate
authority because such a buyer also has
competitive choices. OG&E argues that
these choices are not reduced by the
location at which title to the energy is
transferred.439
318. OG&E also claims that the
Commission’s mitigation policy harms
competition and consumers by
undermining the ability of a mitigated
company to compete in other markets
within an RTO where that seller does
not have market power.440 OG&E asserts
that if a power purchaser located in a
non-mitigated market within an RTO
already takes network transmission
service under an OATT and that
purchaser solicits power supply bids
based on the premise that the purchaser
will arrange and pay for any necessary
transmission service, then potential
suppliers not subject to mitigation will
bid on a ‘‘power only’’ basis. In contrast,
a mitigated supplier’s bid would
include the cost of transmission service
to take the power to the metered
boundary of the control area where the
435 Order

No. 697 at P 819.
Rehearing Request at 3.
437 Id. at 4–5.
438 Order No. 697 at P 820.
439 OG&E Rehearing Request at 5.
440 Id.
436 OG&E

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seller is mitigated. OG&E complains that
in such an instance, the transmission
service is not needed because the
purchaser would prefer to use its
existing network service—priced on the
basis of load—to arrange for
transmission. OG&E contends that the
added transmission costs imposed on a
mitigated supplier in such a scenario
would undermine the competitiveness
of a mitigated supplier’s bid, thereby
reducing the competitive options
available to the purchaser. OG&E
contends that the Commission’s policy,
because it can result in additional
transmission costs for a mitigated
supplier as described above, imposes a
pancaked rate structure on mitigated
suppliers, which undermines an
essential benefit associated with RTO
participation. This, OG&E complains, is
inconsistent with the Commission’s goal
of eliminating pancaked rates by
establishing RTOs, and will interfere
with the development and efficiency of
competitive wholesale markets.441
OG&E adds that the Final Rule provides
no justification for a policy under which
a mitigated supplier may incur the cost
of transmission service to take the
power to the metered boundary of the
control area when it seeks to sell power
to a potential customer located in
another non-mitigated balancing
authority area within an RTO. These
effects are even greater, OG&E asserts,
because the Commission has approved
other utilities’ mitigation proposals that
allow them to sell power at their
generator bus so long as that power
sinks in another balancing authority
area. OG&E argues that those tariffs
remain in full force and effect after
Order No. 697. Like these sellers, OG&E
should be permitted to compete on an
equal basis to serve customers whose
loads sink outside OG&E’s mitigated
balancing authority area.442
319. OG&E argues that the Final Rule
fails to acknowledge that the
Commission’s new mitigation policy
departs from prior policy.443 OG&E
asserts that in several recent cases
where sellers failed the market share
screens in their balancing authority
area, the Commission imposed
mitigation prohibiting the seller from
making sales to ‘‘loads that sink’’ in that
balancing authority area.444 While the
Commission later rejected this language,
441 Id.

at 6.
at 6–7.
443 Id. at 7.
444 Id. at 2 (citing Duke Power, 113 FERC ¶ 61,192
(2005); AEP Power Marketing, Inc., 114 FERC
¶ 61,025 (2006); LG&E Energy Marketing Inc., 113
FERC ¶ 61,229 (2005); South Carolina Electric and
Gas Co., 114 FERC ¶ 61,143 (2006); Florida Power
Corp., 113 FERC ¶ 61,131 (2005)).

OG&E contends that it never has
explained this change in position.445
When the Commission departs from
established policy without explanation,
as OG&E claims it did here, it acts
arbitrarily and fails to engage in the
reasoned decision making required by
the law.446
Commission Determination
320. OG&E complains that the
Commission erred by barring utilities
from selling power within a balancing
authority area in which a seller is found,
or presumed, to have market power
when the buyer’s load sinks in a nonmitigated balancing authority area. As
noted in the Final Rule, another
commenter similarly asserted that any
buyer purchasing power at a generator
bus or elsewhere in a balancing
authority area in which a seller is found,
or presumed, to have market power for
purposes of moving that power beyond
that mitigated balancing authority area
should be treated no differently than a
buyer who takes delivery of purchased
power outside of that balancing
authority area. OG&E, like earlier
commenters advocating this approach,
has failed to adequately address how the
Commission could effectively monitor
such sales 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. As
the Commission stated in the Final
Rule, several commenters noted the
complex administrative problems that
would be associated with trying to
monitor compliance with such a
policy.447
321. Moreover, as the Commission
explained in the Final Rule, allowing
market-based rate sales by a seller found
to have market power, or has so
conceded, in the very balancing
authority area in which market power is
a concern is inconsistent with the
Commission’s responsibility under the
FPA to ensure that rates are just and
reasonable and not unduly
discriminatory. While we generally
agree that it is desirable to allow marketbased rate sales into balancing authority
areas where the seller has not been
found to have market power, a mitigated
seller cannot make market-based rate
sales anywhere within a balancing
authority area in which a seller is found,
or presumed, to have market power. It
is unrealistic to believe that sales made

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445 Id. (citing Order No. 697 at P 794;
MidAmerican Energy Co., 114 FERC ¶ 61,280
(2006); Carolina Power & Light Co., 114 FERC
¶ 61,294 (2006); Aquila, Inc., 114 FERC ¶ 61,281
(2006)).
446 Id. at 8.
447 Order No. 697 at P 818.

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25877

anywhere in a balancing authority area
can be traced to ensure that no improper
sales are taking place. In contrast, sales
made at the metered boundary for
export do more readily lend themselves
to being monitored for compliance, and
the nature of these types of sales do not
unduly disadvantage customers or
competitors. Prohibiting market-based
rate sales at the metered boundaries of
a balancing authority area in which a
seller is found, or presumed, to have
market power could prevent or
adversely impact cross border sales at
these unique locations and reduce
market liquidity unnecessarily in
markets where the seller does not
possess market power.
322. OG&E also claims that not
allowing sales at the generator bus
undermines the ability of a mitigated
company to compete in other markets
within an RTO where that seller does
not have market power. For example, if
a mitigated seller attempts to transact
with a purchaser willing to use the
purchaser’s existing network
transmission service, OG&E asserts that
a mitigated seller’s ability to compete is
undermined. OG&E claims that because
a mitigated seller must incur
transmission costs to deliver the power
in the above 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. This, OG&E
suggests, not only undermines that
mitigated seller’s ability to compete
beyond the mitigated balancing
authority area, but also would reduce
the competitive options available to the
buyer.
323. 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. Mitigated sellers 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. Unlike sales at the
generator bus bar, sales made at the
metered boundary for export do lend
themselves to being monitored for
compliance, and these sales do not

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unduly disadvantage customers or
competitors.
324. OG&E also claims that its ability
to compete is undermined because the
Commission approved several tariffs
that permit a mitigated entity to sell
power at their generator bus so long as
that power sinks beyond the balancing
authority area in which a seller is found,
or presumed, to have market power.
However, a recent Commission order
explained that such tariffs are
inconsistent with the Commission’s
policy as set forth in Order No. 697, as
of the effective date of Order No. 697
(September 18, 2007).448 In that order,
the Commission explained that its
acceptance of a mitigation proposal and
tariff provisions that focused on sales
that did not sink within the balancing
authority area in which the seller was
found, or presumed, to have market
power was inconsistent with the April
14 and July 8 Orders and, therefore, in
error.449 Moreover, the Commission’s
recent order clarifying the Final Rule
explained that sales made after
September 18, 2007 must be in
compliance with the requirements of
Order No. 697.450 Because a mitigated
entity is precluded from limiting its
mitigation to sales that sink in the
balancing authority area in which it is
found, or presumed to have, market
power, all mitigated sellers are now on
the same footing with regard to their
ability to serve customers whose loads
sink outside mitigated balancing
authority areas.
d. Tariff Language
Final Rule
325. In the Final Rule, the
Commission 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.451 In particular, the Final Rule
requires that mitigated sellers that want
to make market-based rate sales at the
metered boundary adopt the following
tariff provision:

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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
448 See

South Carolina Electric and Gas
Company, 121 FERC ¶ 61,263 at P 12 (2007).
449 Id.
450 Clarification Order, 121 FERC ¶ 61,260 at P 4–
8.
451 Order No. 697 at P 830.

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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 where the seller has
market-based rate authority; (ii) any power
sold hereunder is not intended to serve load
in the seller’s mitigated market; and (iii) no
affiliate of the mitigated seller will sell the
same power back into the mitigated seller’s
mitigated market. 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),
(ii), and (iii) above.

Requests for Rehearing
326. Pinnacle requests clarification of
the provision’s requirement that ‘‘any
power sold is not intended to serve load
in the seller’s mitigated market.’’ As
written, Pinnacle argues that this
requirement could limit liquidity,
particularly for term sales transactions,
in the market trading hubs.452 For
example, Pinnacle states that it transacts
at several liquid points in the Western
markets such as Four Corners, which is
at the border of the APS balancing
authority area. Pinnacle explains that
although it can assess its intent for the
destination of power purchased at the
border point, it does not have control
over the intent of third parties
purchasing the power. Further, Pinnacle
asserts that it is unlikely that
counterparties at liquid market hubs
would agree to contractual limitations
on where power can sink for term
transactions.453 Pinnacle adds that the
Commission has not placed any limits
on the time at which intent is
determined. For example, if a buyer
intends to sink the power outside of the
market in which the seller has or is
presumed to have market power at the
time of purchase, but at the time of
delivery determines that it must
liquidate its positions and sell power
back into that market, the Final Rule is
unclear whether the mitigated seller
may be liable for this sale into the
market in which it has market power.
Pinnacle argues that without the
clarification on intent, mitigated sellers
may be limited to cost-based sales at the
border. Pinnacle requests the
Commission clarify that intent is only

directed at the determination of the
mitigated seller.
327. If the Commission does not so
clarify, Pinnacle requests on rehearing
that the Commission revise the second
requirement in the tariff provision to
state: ‘‘(ii) the seller does not intend for
any power sold to serve load in the
seller’s mitigated market.’’ Pinnacle
claims that this revision will provide
greater regulatory certainty.
328. Morgan Stanley similarly is
unclear on how the Commission will
ensure that a mitigated seller knows
what an unaffiliated buyer intends to do
with power. It adds that a restriction
forbidding unaffiliated buyers from
purchasing power at the metered
boundary from a mitigated seller and
then selling the same power back into
a balancing authority area in which the
seller was found, or presumed, to have
market power would be burdensome
because every sale would have to be
tracked.454 Morgan Stanley therefore
requests the Commission to clarify that
buyers unaffiliated with a mitigated
seller may purchase power at the
metered boundary to sell to customers
that serve load in the mitigated seller’s
balancing authority area. It argues that
if restrictions are imposed on
unaffiliated buyers’ purchases at the
metered boundary, the Commission
should explain or, in the alternative,
grant rehearing.455
329. Pinnacle is further concerned
about the metered boundary tariff
provision’s requirement that mitigated
sellers commit to and demonstrate that
‘‘no affiliate of the mitigated seller will
sell the same power back into the
mitigated seller’s mitigated market.’’
Pinnacle submits that it might generally
have immediate documentation to meet
the above requirement for real-time
transactions because the NERC tag (that
notes the sink point for the power) will
be made upon the execution of a realtime transaction. However, in the
context of a term sale, Pinnacle explains
that NERC tags are generally created not
at the time of the transaction, but rather
the last scheduling day prior to the start
of the sale. The result, Pinnacle submits,
is that no immediate documentation is
created to show that the mitigated seller
intended to sink the sale outside of the
mitigated market where a term sale
followed by a ‘‘coincidental sale’’ 456
that results in power returning to the
454 Morgan

452 Pinnacle

Rehearing Request at 4. Although
Pinnacle does not provide a definition for ‘‘term
sale,’’ we understand their use of that phrase to
refer to a sale that is neither executed nor tagged
immediately, and whose sink location is unknown
at the time of the sale.
453 Id. at 5.

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Stanley Rehearing Request at 3.
at 2–3.
456 Pinnacle describes a ‘‘coincidental sale’’ as the
situation where, after a mitigated seller makes a
term sale to an unaffiliated counter-party at the
metered boundary, an affiliate of the mitigated
seller enters into an unrelated transaction to buy
that same power from the unaffiliated counterparty.
455 Id.

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
balancing authority area in which the
seller has been found, or presumed, to
have market power. Pinnacle therefore
seeks clarification, or in the alternative
rehearing, on whether the requirement
that a mitigated seller commit to and
demonstrate that ‘‘no affiliate of the
mitigated seller will sell the same power
back into the mitigated seller’s mitigated
market’’ applies in the following
scenario: A mitigated seller sells a term
product to an unaffiliated counterparty
at the metered boundary for delivery
sometime in the future. Thereafter, an
affiliated seller purchases the power in
a coincidental sale and, despite any lack
of arrangement, the affiliate of the
mitigated seller then re-sells that power
to the balancing authority area in which
the mitigated seller has been found, or
presumed, to have market power.457 If
the unaffiliated counterparty does not
advise the affiliate of the mitigated
seller that the unaffiliated counterparty
is selling to the affiliate of the mitigated
seller the same power that the
unaffiliated counterparty originally
purchased from the mitigated seller,
Pinnacle claims that it will only become
apparent that the mitigated seller is
sourcing the transaction between the
unaffiliated counterparty and the
affiliate of the mitigated seller when the
NERC tags are prepared.458
330. Pinnacle also seeks clarification,
or in the alternative rehearing, as to the
types of documentation that the
Commission requires to show the intent
of the seller, and particularly whether
the Commission would consider audio
tapes of transactions to be sufficient.
Pinnacle states that, generally,
representative documentation for realtime trading is created. For a term sale,
however, a representative tag is not
created at the time of the transaction but
rather around the last scheduling prior
to the start of the sale. Therefore, when
a term sale is involved, no immediate
tag at the time of contracting is created
that can be evidenced as intent to sink
the sale outside of the market in which
the seller has market power.
331. Pinnacle also requests
clarification that the physical point of
the metered boundary is the mitigated
seller’s side of the electrical boundary,
and does not include points at the
border that are in an adjacent balancing
authority area.459 If the Commission
does not provide the requested
clarification, Pinnacle requests
rehearing of this requirement. Pinnacle
argues that, as currently written, the
tariff language on metered boundaries
457 Pinnacle

Rehearing Request at 7–8.

458 Id.
459 Pinnacle

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does not provide the regulatory
certainty necessary to accurately
implement the requirements.460
332. OG&E complains that the Final
Rule’s new mitigation policy is
improperly based on the assumption
that utilities will violate their tariffs
despite the fact that such a purposeful
circumvention of a company’s
mitigation tariff would subject the
violator to the risk of substantial civil
penalties. Moreover, OG&E adds that
such conduct also could violate the
Commission’s Market Manipulation
Rule.461 OG&E points out that, in the
Final Rule, the Commission rejected
fears of gaming because such conduct
would violate its existing rules.462
OG&E asserts that the same logic applies
to the Commission’s concerns that a
seller might violate its market-based rate
tariff to purposefully make sales to a
customer whose load sinks in the
balancing authority area in which that
seller was found, or presumed, to have
market power. OG&E argues that, where
a particular set of actions already are
prohibited by the Commission’s rules,
the Commission cannot impose new
requirements unless it first finds that
the existing rules are ineffective.463
Commission Determination
333. As an initial matter, we will
revise the tariff language governing
market-based sales at the metered
boundary to conform with the
discussion in the Clarification Order
regarding use of the term ‘‘mitigated
market.’’ As we explained in the
Clarification Order, we believe 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.
334. After considering comments
raised regarding the difficulty of
determining and documenting intent,
we have decided to eliminate the intent
element of the tariff provision, which
states that ‘‘any power sold hereunder is
not intended to serve load in the seller’s
mitigated market.’’ As we are
eliminating the seller’s intent
requirement, we will modify the other
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.’’ 464 Because we are
460 Id.

at 8–9.
Rehearing Request at 9.
462 Id. at 10.
463 Id.
464 To provide additional regulatory certainty for
mitigated sellers, we clarify that once the power has
been sold at the metered boundary at market-based
rates, the mitigated seller and its affiliates may not
461 OG&E

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25879

eliminating the intent requirement, we
need not address issues raised regarding
documentation necessary to
demonstrate the mitigated seller’s
intent.
335. Pinnacle also asks whether a
mitigated seller would be liable if an
affiliate purchases power from an
unaffiliated intermediate party, then
arranges to re-sell that power back into
the mitigated seller’s balancing
authority area, and it is subsequently
discovered, when the NERC tags are
prepared, that the mitigated seller was
the initial source of that power via a
term sale with the unaffiliated
intermediate party. Under these
circumstances, the mitigated seller
would have violated its market-based
rate tariff. Whether or not prearranged
by affiliates, a series of transactions
involving what Pinnacle describes as a
‘‘coincidental sale’’ that may result in an
affiliate re-selling power back into the
balancing authority area in which the
seller has been found, or presumed, to
have market power are prohibited by
Order No. 697. This is because mitigated
sellers and their affiliates are prohibited
from selling power at market-based rates
in the balancing authority area in which
a seller is found, or presumed, to have
market power. Accordingly, 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.
336. 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.
337. We also clarify that when using
the term ‘‘metered boundary,’’ the
Commission intends that applicable
mitigation applies to sales made at the
metered boundary regardless of at
which ‘‘side’’ of the border the sale
takes place. We adopt this approach as
a concession to mitigated sellers that
wish to make sales that may technically
take place in a balancing authority area
where they do not have market-based
rate authority. However, in adopting
this approach we do not intend to do so
with such precision that we are drawn
sell that same power back into the mitigated
balancing authority area, whether at cost-based or
market-based rates.

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into evidentiary hearings on this matter,
which could result in long drawn out
contractual disputes to determine the
precise spot at which the sale took
place. We further deny Pinnacle’s
request for rehearing to seek a precise
definition of ‘‘metered boundary’’
because we believe, with the
clarification provided herein, the
existing tariff language on metered
boundaries does provide the regulatory
certainty necessary to accurately
implement Order No. 697’s
requirements.
338. We disagree with OG&E’s
contention that our policy is based on
the assumption that utilities will
purposely violate their tariffs. We make
no such assumption; however, it would
not be sensible for us to establish
conditions that we are unable to
monitor for compliance. Sales at the
metered boundary are unique physical
locations that lie on the borders of
balancing authority areas, and we
believe that we can monitor compliance
for sales at the metered boundary more
effectively than sales made anywhere
within the balancing authority area. As
explained above, such limitation is
justified by the Commission’s need to
monitor compliance with its conditions
on sales within the balancing authority
area in which the seller is mitigated.
339. Consistent with the preceding
discussion, we will revise the tariff
provision for market-based rate sales at
the metered boundary as follows (bold
font indicates new text):

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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 where the seller has
market-based rate authority; and (ii) the
Seller and its affiliates do not sell the same
power back into the balancing authority
area where the seller is mitigated. 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.

340. Any sellers that have already
adopted the tariff language prescribed in
Order No. 697 are directed to revise the
provision in accordance with this
discussion on the next occasion when
they otherwise would be required to file
revised tariff sheets with the
Commission, a change in status filing, or
triennial review.

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E. Implementation Process
Final Rule
341. 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); 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; 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.’’ 465
Market power concerns for Category 1
sellers will be monitored through the
change in status reporting
requirement 466 and through ongoing
monitoring by the Commission’s Office
of Enforcement. Category 2 sellers (all
sellers that do not qualify for Category
1) will be required to file regularly
scheduled updated market power
analyses in addition to change in status
reports.
342. In addition, to ensure greater
consistency in the data used to evaluate
Category 2 sellers, the Commission
modified the timing for the submission
of updated market power analyses.467
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.468 This
process allows evaluation of each
individual seller’s market power at the
same time that other sellers in the same
region are examined. For corporate
families that own or control generation
in multiple regions, the corporate family
will be required to file an update for
each region in which members of the
465 18

CFR 35.36(a)(2) (citations omitted).
18 CFR 35.42.
467 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.
468 See Order No. 697 at Appendix D. The regions
include the Northeast, Southeast, Central,
Southwest Power Pool, Southwest, and Northwest.

corporate family sell power during the
time period specified for that region.
1. Category 1 and 2 Sellers
a. Establishment of Category 1 and 2
Sellers
Requests for Rehearing
343. On rehearing, NASUCA argues
that the exemption from market power
review for Category 1 sellers lacks
factual and legal justification. NASUCA
contends that this exemption is
inconsistent with the justifications the
Commission has previously given to the
courts. In particular, NASUCA argues
that it is inconsistent with the
Commission’s arguments before the
court that it carefully assesses the
market power of any entity allowed to
sell at market-based rates.469
344. NASUCA contends that in
Lockyer v. FERC, 383 F.3d 1006 (9th Cir.
2004) (Lockyer), the Ninth Circuit
mistakenly believed that the market
power assessment under current
Commission orders is made triannually
(i.e., once every four months) when it is
only required triennially (once every
three years).470 NASUCA believes that,
because the Final Rule would
completely eliminate the triennial
review for many sellers in Category 1,
the basis for the decision in Lockyer, to
the extent it is based on the Court’s
belief that the Commission reviews the
market power of all sellers four times a
year, is undermined. NASUCA
concludes that the blanket exemption
from market power review of all sellers
owning or controlling less than 500 MW
capacity is inconsistent with the
Commission’s stated rationale for
allowing a market-based rate system.
345. NASUCA also argues that the
Commission has reversed the burden
previously placed on applicants for the
‘‘privilege’’ of having market-based
rates.471 NASUCA notes that the Final
Rule states, ‘‘ ‘[w]hile it is true that a
portion of these sellers will continue to
sell at market-based rates for a time
until their updated market power
analyses (in the case of Category 2
sellers) or their filings addressing
qualification as Category 1 sellers are
due, no commenter has submitted
compelling evidence that Category 1
sellers have unmitigated market
power.’ ’’ 472 NASUCA contends that
Order No. 697 essentially granted all

466 See

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469 NASUCA

Rehearing Request at 12–13.
at 13.
471 Id. at 13–14 (citing Schaffer v. Weast, 546 U.S.
49 (2005); Lavine v. Milne, 424 U.S. 577, 585
(1976)).
472 Id. (quoting Order No. 697 at P 334) (emphasis
added by NASUCA).
470 Id.

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Category 1 sellers market-based rates
without their submitting an application
demonstrating a lack of market power,
and required objectors to submit
‘‘compelling evidence’’ in a nonevidentiary proceeding.
346. NASUCA argues that the
Commission cannot presume that the
market price demanded by all Category
1 sellers will be a ‘‘competitive’’ price
or a just and reasonable rate.473
NASUCA states that the Supreme Court
‘‘rejected any conflation of ‘competitive’
market price with the ‘just and
reasonable’ rate required by statute.’’ 474
NASUCA contends that for Category 1
sellers, which it asserts are now exempt
from any market power test, ‘‘the
‘prevailing price in the marketplace’ is
indeed the ‘final’ measure of the rates
being demanded, changed and
charged,’’ a result contrary to the intent
of Congress.475
347. NASUCA also argues that there
is no basis in the record of this
proceeding to assume that power
marketers or producers who own or
control less than 500 MW of generation
lack market power at all times.476
NASUCA notes that in load pockets or
other transmission-constrained areas,
sellers with less than 500 MW of
capacity could exercise market power,
either alone or acting strategically
without overt collusion to inflate rates
when supply margins are tight.
NASUCA states that changing
circumstances also may affect the
opportunity of seemingly small sellers
to exercise market power.
348. Additionally, NASUCA argues
that, because the definition of seller
includes not only owners of generating
plants but also power marketers, this
loophole might encourage power
marketers to control segments of power
plants up to 499.9 MW and through
strategic bidding and other methods
exercise subtle market power in certain
locations at certain times.477 NASUCA
states that, as a result of this exemption,
sales from these facilities will be at
prices solely determined by market
forces, in contravention of FPC v.
Texaco. NASUCA therefore concludes
that if the Commission desires to
identify a threshold below which a
seller cannot exercise market power, it
should commence a new proceeding,
conduct technical workshops, gather
evidence from the public and from RTO
market monitors, and receive comments
473 Id.

at 14.
(citing FPC v. Texaco, 417 U.S. at 397).
475 Id. at 15 (quoting FPC v. Texaco, 417 U.S. at
397).
476 Id.
477 Id. at 16.
474 Id.

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before adopting an evidence-based
standard.
Commission Determination
349. NASUCA’s argument on
rehearing that the Commission did not
adequately justify its decision to exempt
Category 1 sellers from filing regularly
scheduled updated market power
analyses is misplaced. As we reiterate
below, we thoroughly discussed the
basis of our decision in Order No. 697,
including that exempting Category 1
sellers is fully consistent with our
statutory mandate to ensure just and
reasonable rates and with the court
decisions that have construed that
obligation.478 Moreover, as discussed
below, in a number of instances
NASUCA does not accurately describe
the exemption or our justification for it.
350. With regard to NASUCA’s
argument that exempting sellers from
market power reviews undermines the
court’s decision in Lockyer, we note that
the Commission addressed this concern
in Order No. 697. Specifically, the
Commission stated that ‘‘the reporting
requirement relied upon by the court in
Lockyer is the transaction-specific data
found in EQRs, which we continue to
require of all sellers, and not the
updated market power analyses. Thus,
exempting Category 1 sellers from
routinely filing updated market power
analyses does not run counter to
Lockyer.’’ 479 The court in Lockyer
emphasized that the Commission ‘‘has
broad discretion to establish effective
reporting requirements’’ for
administering tariffs, and that the FPA
‘‘explicitly leaves the timing and form’’
of rate filings to the Commission’s
discretion.480
351. In any case, NASUCA fails to
recognize that the Commission has not
exempted Category 1 sellers from initial
market power reviews. In addition, the
Commission left in place the change in
status reporting requirements that allow
the Commission to review market power
of sellers on an ongoing basis. Thus, we
reject NASUCA’s contention that this
exemption is inconsistent with the
justifications the Commission has
previously given to the courts.
352. We also reject NASUCA’s
contention that the Commission has
reversed the burden previously placed
on applicants for the ‘‘privilege’’ of
having market-based rates by not
requiring Category 1 sellers to file
regularly scheduled updated market
power analyses. As an initial matter,
NASUCA argues incorrectly that Order
478 Order

No. 697 at P 848.
P 854.
480 Lockyer, 383 F.3d 1006, 1013.
479 Id.

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No. 697 ‘‘essentially granted all
Category 1 sellers market[-based] rates
without their applying and
demonstrating a lack of market power,
and required objectors to submit
‘compelling evidence’ in a nonevidentiary proceeding.’’ 481 Order No.
697 did not grant Category 1 sellers
market-based rate authority without
requiring the submission of an
application demonstrating a lack of
market power. To the contrary, all
sellers seeking market-based rate
authorization (including sellers that
qualify as Category 1 sellers) must
initially demonstrate either a lack of
market power or that any market power
is adequately mitigated in order to
obtain Commission market-based rate
authorization.482 All such proceedings
are noticed and allow for public
comment. Any party to the proceeding
has an opportunity during these
proceedings to argue that a seller has
market power.483 Although Category 1
sellers are not required to file regularly
scheduled updated market power
analyses, they retain the initial burden
of proof to demonstrate that they do not
have or have adequately mitigated
market power in the first instance. In
addition, Category 1 sellers continue to
have the burden of informing the
Commission of any change in the
circumstances that the Commission
relied on in granting them market-based
rate authority.
353. Further, NASUCA takes the
Commission’s statement regarding the
submission of compelling evidence out
of context. The passage that NASUCA
quotes from the Final Rule (Order No.
697 at P 334) discusses the elimination
of the exemption for new generation
(formerly § 35.27(a) of the Commission’s
regulations), and the lack of compelling
evidence that the Commission
referenced there related to commenters’
unpersuasive reasons for retaining the
§ 35.27(a) exemption.484 The
481 NASUCA

Rehearing Request at 14.
seller who previously was not required to
demonstrate a lack of horizontal market power
based on the exemption contained in 18 CFR
35.27(a) and that believes it qualifies as a Category
1 seller, will be required to provide support for its
claim to Category 1 status. This filing will give the
Commission and interested parties an opportunity
to review and, if appropriate, challenge a seller’s
claim that it qualifies as a Category 1 seller. To the
extent that an intervenor has concerns about a
seller’s potential to exercise market power, the
Commission will entertain them at that time. Order
No. 697 at P 333.
483 Additionally, if a seller’s circumstances
change from those which the Commission reviewed
and made a determination upon, it is required to
inform the Commission in a change in status filing.
484 The Commission was responding to
NASUCA’s concern that sellers that initially
482 A

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Commission discussed the
establishment of Category 1 and 2
sellers in a separate part of the Final
Rule (Order No. 697 at P 848–62); the
Commission nowhere intimated that
Category 1 sellers need not demonstrate
that they lack market power.
Accordingly, NASUCA’s contention is
rejected in this regard.
354. With respect to NASUCA’s
assertion that there is no basis in the
record to assume that power marketers
or producers who own or control less
than 500 MW of generation lack market
power at all times, in Order No. 697 the
Commission fully explained the
rationale underlying the adoption of
Category 1, as well as the rationale for
adopting 500 MW or less of generating
capacity per region as the cutoff. The
Commission explained that Category 1
sellers have been carefully defined to
have attributes that are not likely to
present market power concerns:
Ownership or control of relatively small
amounts of generation capacity; no
affiliation with an entity with a
franchised service territory in the same
region as the seller’s generation facility;
little or no ownership or control of
transmission facilities and no affiliation
with an entity that owns or controls
transmission in the same region as the
seller’s generation facility; and no
indication of an ability to exercise
vertical market power. The Commission
further explained that, based on a
review of past Commission orders, it is
aware of no entity that would have
qualified as a Category 1 seller but
would nevertheless have failed the
indicative screens, necessitating a more
thorough analysis.485 Furthermore, we
believe that we have maintained an
ample degree of monitoring and
oversight to detect sellers that are not
required to file regularly scheduled
market power updates but nevertheless
obtain enough additional generation as
to raise market power concerns. This is
so because we require all sellers seeking
market-based rate authority to conduct a
market power analysis and, once
market-based rate authority is obtained,
to submit change in status filings when
the circumstances on which the
Commission has granted market-based
rate authority have changed. In these
received market-based rate authority without any
generation market power assessment pursuant to 18
CFR 35.27(a) would, as Category 1 sellers, be
exempted from filing update market power
analyses. The Commission explained that it would
rely on additional procedures, namely the change
in status filing requirements (triggered by the
acquisition of additional generation), EQR
transaction filings, and the Commission’s ability to
require an updated market power analysis from any
seller at any time, to address NASUCA’s concern.
485 See Order No. 697 at P 864.

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filings, such sellers must report on what
effect, if any, the additional generation
has on their market power. In addition,
the Commission reserves the right to
require an updated market power
analysis from any market-based rate
seller at any time.486 Finally, all sellers
with market-based rates, whether
Category 1 or Category 2 sellers, must
file electronically with the Commission
an EQR of transactions no later than 30
days after the end of each reporting
quarter.
355. Nevertheless, in light of concerns
raised regarding the potential for
Category 1 sellers to exercise market
power in load pockets or other
transmission-constrained areas, we will
modify our approach when analyzing
the indicative screens (e.g., as a result of
regularly scheduled updated market
power analyses). Specifically, to the
extent that a Commission-identified
submarket is under analysis, we will
consider whether there is an indication
that any sellers in that submarket,
including Category 1 sellers, have
market power. While we will not
routinely require Category 1 sellers with
generation assets in a submarket to
submit a regularly scheduled updated
market power analysis, when evaluating
the market power analyses of Category
2 sellers, we will conduct our own
analysis, based on publicly available
information, of whether there are any
market power concerns related to any
Category 1 seller in a submarket. If,
based on our analysis, we determine
that there may be potential market
power concerns with respect to any
Category 1 sellers in a submarket, we
will, if appropriate, require an updated
market power analysis to be filed by
such sellers. We will also notice such
filings for public comment, thus
allowing parties to raise concerns
regarding market power for Commission
consideration.
356. Regarding concerns about the
specific threshold chosen, when the
Commission proposed in the NOPR the
establishment of Category 1 and
Category 2 sellers, the Commission
proposed to define Category 1 sellers as
power marketers and power producers
that own or control 500 MW or less of
generation capacity in aggregate, among
other requirements. The Commission
received a variety of comments
concerning the proposed threshold.
After careful review of these comments,
the Commission concluded that 500
MW or less of generation capacity per
region is an appropriate threshold. The
Commission explained in Order No. 697
that the 500 MW threshold would be
486 Id.

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Frm 00052

used as a cutoff because, during the
Commission’s 15 years of experience
administering the market-based rate
program, there had only rarely been
allegations that sellers with capacity of
500 MW or less (in any geographic
region) had market power. The
Commission noted that when those
claims have been raised, the
Commission’s review either found no
evidence of market power or found that
the market power identified was
adequately mitigated by Commissionenforced market power mitigation. The
Commission explained that, while some
commenters urged it to adopt either a
higher or lower threshold, the
Commission believes that a 500 MW
threshold is both a reasonable balance
as well as conservative enough to ensure
that those unlikely to possess market
power will be granted market-based rate
authority. Moreover, 500 MW is a clear,
bright line that will be easy to
administer. On this basis, we reject
NASUCA’s suggestion that the
Commission should commence a new
proceeding, conduct technical
workshops, gather evidence from the
public and from RTO market monitors,
and receive comments to further address
the appropriate threshold.
b. Threshold for Category 1 Sellers
Requests for Rehearing
357. On rehearing, PPM contends that
Order No. 697 does not provide any
explanation as to why Category 1
membership is based on the ownership
or control of generation in a ‘‘region,’’ as
opposed to in the geographic area used
to measure market power.487 PPM
submits that the appropriate geographic
area for measuring ownership or control
of electric generation for purposes of
identifying Category 1 sellers is the
same area used to assess market power:
The balancing authority area or, for
RTOs and ISOs, the relevant RTO/ISO
market or submarket. PPM submits that
the use of regions for determining
Category 1 membership would result in
a seller owning or controlling 500 MW
of generating capacity located entirely
in one balancing authority area being
considered to have less chance of
possessing market power than a seller
owning or controlling 300 MW of
generating capacity each in two separate
balancing authority areas separated by
hundreds of miles but located in the
same region pursuant to the map
provided in Appendix D to the Final
Rule. PPM contends that there is neither
evidence nor a rational basis for
concluding that the seller in the second
487 PPM

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example should be included in Category
2 and the seller in the first example
should be included in Category 1. Thus,
PPM concludes that the Commission’s
basis for distinguishing between
Category 1 and Category 2 sellers is
arbitrary and capricious.
358. PPM also asserts that the
Commission should treat ownership or
control of intermittent generating
capacity differently from thermal
generating capacity for the purposes of
establishing whether a seller falls within
Category 1 or Category 2. PPM claims
that it is extremely unlikely that any
public utility will attain market power
as a result of its ownership or control of
wind generation capacity due to the
intermittent nature of such capacity.488
Thus, it argues that the Commission
should adopt a less stringent limitation
for purposes of establishing Category 1
status for sellers of power from
intermittent generating capacity. PPM
notes that the Commission rejected this
suggestion from commenters, stating
‘‘[w]e believe that many sellers with
wind and other non-thermal capacity
will fall below the 500 MW threshold;
those that do not may take advantage of
simplifying assumptions and other
means to minimize the burden of filing
an updated market power analysis.’’ 489
However, PPM asserts that, other than
gas, wind power is the fastest growing
source of electric generating capacity.490
According to PPM, several wind power
developers already own or control more
than 500 MW of intermittent generation
capacity in a region, as designated by
Appendix D, and several more are likely
to attain this status before long. PPM
contends that, as the United States seeks
to promote investment in electric
generation technologies that enhance
national energy security and do not emit
greenhouse gases, it would be unwise to
impose a burden on wind power
generators that will not enhance the
competitiveness of wholesale electric
markets.
Commission Determination
359. With regard to PPM’s argument
that the use of regions for determining
Category 1 membership would result in
a seller owning or controlling 500 MW
of generating capacity located entirely
in one balancing authority area being
488 Id.

at 4.
(citing Order No. 697 at P 867).
490 Id. (citing Florence, Joseph, Global Wind
Power Expands in 2006, ‘‘Wind is the world’s
fastest-growing energy source with an average
annual growth rate of 29 percent over the last ten
years. In contrast, over the same time period, coal
use has grown by 2.5 percent per year, nuclear
power by 1.8 percent, natural gas by 2.5 percent,
and oil by 1.7 percent.’’ June 28, 2006 http://
www.earth-policy.org/Indicators/Wind/2006.htm).

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considered to have less chance of
possessing market power than a seller
owning or controlling 300 MW of
generating capacity each in two separate
balancing authority areas separated by
hundreds of miles but located in the
same region pursuant to the map
provided in Appendix D to the Final
Rule, we find that PPM misses the
point. The Commission’s creation of a
category of sellers (Category 1 sellers)
that are not required to submit regularly
scheduled updated market power
analyses is based in part on recognizing
the administrative burden imposed on
smaller sellers that are unlikely to
possess market power. In doing so, the
Commission intends to remain
conservative in its approach to
identifying such sellers. While PPM’s
argument may make sense from a
strictly analytical viewpoint, it also
greatly increases the universe of sellers
that would not be required to submit
regularly scheduled updated market
power analyses. We are not willing to
do so.
360. The Commission explained in
Order No. 697 that, ‘‘[i]n keeping with
our conservative approach with regard
to which entities qualify for Category 1,
we find that aggregate capacity in a
given region best meets our goal of
ensuring that we do not create
regulatory barriers to small sellers
seeking to compete in the market while
maintaining an ample degree of
monitoring and oversight that such
sellers do not obtain market power.’’ 491
The Commission considered other
formulations for a threshold, but it
concluded that the other
‘‘methodologies are inconsistent with a
straightforward, conservative means of
screening sellers * * *.’’ 492 Thus, we
deny PPM’s request to define Category
1 sellers based on their ownership or
control of generation capacity located in
a balancing authority area or an RTO/
ISO market rather than based on
ownership in a region.
361. With regard to PPM’s request that
the Commission adopt a less stringent
limitation for purposes of establishing
Category 1 status for sellers of power
from intermittent generating capacity, as
PPM acknowledges, the Commission
considered and rejected this suggestion
in the Final Rule. The Commission
stated that it believed ‘‘that many sellers
with wind and other non-thermal
capacity will fall below that 500 MW
threshold’’ 493 and reiterated that those
sellers that exceed it may take advantage
of simplifying assumptions to minimize
491 Order

No. 697 at P 865.
P 868.
493 Id. P 867.
492 Id.

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the burden of filing an updated market
power analysis. While there may
theoretically be some merit to PPM’s
assertion that it is unlikely that any
public utility will attain market power
as a result of its ownership or control of
wind generation capacity due to the
intermittent nature of such capacity,
nevertheless, PPM’s remark that wind
power is the fastest growing source of
generating capacity (other than gas) is
further reason that intermittent capacity
should not be treated differently from
thermal generating capacity for
purposes of establishing Category 1
status. There may be a time when a very
large wind power facility could possibly
have market power and will warrant
Commission scrutiny. We note that PPM
argues that the Commission should
adopt a less stringent limitation for
purposes of establishing Category 1
status for sellers of power from
intermittent generating capacity
because, in its view, it would be unwise
to impose a burden on wind power
generators that will not enhance the
competitiveness of wholesale electric
markets. However, PPM does not claim
such a burden would be unduly
burdensome. Nor should it. Our
approach is balanced, reasonable, and
consistent with our approach to
examining market power of sellers
seeking to obtain or retain market-based
rate authority. On this basis, we believe
it is appropriate that wind generators be
subject to the same 500 MW threshold
for Category 1 status as other sellers. At
the same time, we note that we already
afford intermittent generation more
flexibility in conducting market power
analyses than, for example, thermal
generating capacity. In particular, we
allow energy-limited resources to
provide a market power analysis based
on historical capacity factors to more
accurately capture hydroelectric or
wind availability, in lieu of using
nameplate or seasonal capacity.494 This
is an option not available to thermal
generating units. In addition, as we
stated in the Final Rule, such sellers can
take advantage of simplifying
assumptions (such as performing the
indicative screens assuming no import
capacity or treating the host balancing
authority area utility as the only other
competitor). As a result, to the extent
that a wind power generator exceeds the
500 MW threshold and therefore is
considered a Category 2 seller, we
believe that any burden imposed on that
494 Id. P 344. We also remind sellers that they
may seek exemption from Category 2 status on a
case-by-case basis. See id. P 868.

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seller to file an updated market power
analysis would be minimal.
2. Regional Review and Schedule
Requests for Rehearing
362. On rehearing, FirstEnergy and
MidAmerican object to the regional
filing approach adopted in the Final
Rule.
363. FirstEnergy argues that the
Commission erroneously and
unreasonably ruled that for corporate
families that own or control generation
in different regions, the corporate family
would be required to file an update for
each region in which members of the
corporate family sell power during the
time period specified for that region.495
FirstEnergy contends that a corporate
family with generation assets in
adjacent geographic markets finds it far
more efficient to prepare and submit a
single, all-encompassing, updated
market power analysis every three years
than to prepare separate analyses for
each region.496 It claims that adoption of
a single filing date for all entities within
a corporate family that have marketbased rates will permit all necessary
tariff revisions to be filed at the same
time, and will thereby reduce the
possibility for discrepancies among
tariffs within the same corporate family.
364. FirstEnergy reasons that it is
unlikely that there are a significant
number of corporate families that have
affiliated generation suppliers operating
in adjacent geographic markets. For that
reason, FirstEnergy states that there is
no reason to believe that authorizing
affected sellers to make a single, allencompassing, triennial market power
update filing every three years will
significantly undermine the
Commission’s ability to obtain a
complete view of market forces in each
region in order to ensure that seller’s
rates remain just and reasonable.497 In
the event that the Commission permits
all companies within a corporate family
that operate in adjacent geographic
markets to file a single market power
updated analysis during a three-year
filing cycle, FirstEnergy requests that
the filing companies be given the option
of selecting the region with which they
will participate.498
365. MidAmerican seeks a filing
schedule that permits it to submit a
single market power analysis reflecting
the generating facilities within its own
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495 FirstEnergy

Rehearing Request at 3.
at 5.
497 Id. at 6–7.
498 Id. at 7. Alternatively, FirstEnergy suggests
that the Commission should establish a process by
which it would determine which cycle should be
followed.
496 Id.

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balancing authority area (part of the
Central region) as well as its Quad Cities
Station (QCS), which is located on the
border of that balancing authority area
(part of the Northeast region).
MidAmerican seeks to align the filing
schedules to lessen the burden on the
Commission in evaluating
MidAmerican’s market power, and the
burden on MidAmerican in preparing
multiple filings.499 Its affiliate Cordova
operates a generating facility also
electrically located within the Northeast
region, and MidAmerican states that
Order No. 697 could be construed to
require Cordova to file with the
Northeast region.
366. MidAmerican states that, as
affiliates, it and Cordova historically
have prepared market power analyses
that have evaluated the competitive
effects of the aggregate generation
owned and controlled by both. For that
reason, Cordova is seeking to file on the
same schedule as MidAmerican. QCS
and Cordova’s facility electrically are
located immediately adjacent to
MidAmerican’s balancing authority
area, and the metering points within the
respective substations form part of the
border between the Northeast and
Central regions; each facility is
geographically within the MidAmerican
service territory and directly
interconnected with the MidAmerican
transmission system through facilities
owned by MidAmerican.500
367. MidAmerican seeks clarification
that its undivided ownership interest in
QCS will not cause it to be deemed a
seller that ‘‘operates’’ in the Northeast
region subject to that region’s filing
schedule.501 If the Commission is not
willing to construe Order No. 697 in this
manner, then, for the same reasons,
MidAmerican seeks waiver of the filing
schedule to permit QCS to be treated as
part of MidAmerican’s on-system
generating resources; i.e., as if QCS were
within the Central region along with the
other MidAmerican generating
resources.502 Cordova also seeks a
similar clarification or waiver of Order
No. 697 to permit its updated market
power analysis to be made pursuant to
the Central region schedule applicable
to MidAmerican. MidAmerican states
that its request is narrowly tailored to
the circumstances applicable to itself
and Cordova, whose relevant generation
is located electrically either within or at
the border of MidAmerican’s balancing
authority area in the Central region. By
way of distinction, MidAmerican is not
499 MidAmerican

Rehearing Request at 2.

at 4.
501 Id. at 10.
502 Id. at 10–11.

requesting permission to make a single
filing for its entire corporate family.503
Commission Determination
368. The Commission specifically
addressed FirstEnergy’s argument in
Order No. 697. The Commission stated
that its decision to adopt a regional
review properly and fairly balances the
need to effectively monitor and mitigate
market power in the wholesale markets
with the desire to minimize any
administrative burden associated with
the filings and review of updated market
power analyses. The Commission
recognized that some sellers may have
to file updated market power analyses
more frequently than they would have
had to before Order No. 697, but the
Final Rule carefully balanced the
interests of all involved. The
Commission explained that the regional
approach will enhance the
Commission’s ability to continue to
ensure that sellers either lack market
power or have adequately mitigated
such market power.504 We recognize
FirstEnergy’s contention that it is more
efficient to prepare and submit a single,
all-encompassing, updated market
power analysis every three years than to
prepare separate analyses for each
region. However, such an approach does
not satisfy our desire to ensure greater
consistency in the data used to evaluate
sellers’ market power. If corporate
families are allowed to combine all of
their facilities nationwide into a single
updated market power analysis, the
study year and associated data may not
be consistent with that required for the
corresponding region, and thus the
Commission’s ability to ensure greater
consistency in the data used to evaluate
sellers’ market power and to reconcile
conflicting submissions would be
undermined. Thus, we deny
FirstEnergy’s request for rehearing in
this regard.
369. With regard to FirstEnergy’s
claim that adoption of a single filing
date for all entities within a corporate
family that have market-based rates will
permit all necessary tariff revisions to be
filed at the same time, and will thereby
reduce the possibility for discrepancies
among tariffs within the same corporate
family, from an administrative
perspective, we agree and note that
nothing in Order No. 697 prohibits
FirstEnergy or any other seller from
making such a filing revising all of its
market-based rate tariffs at the same
time. Our concern addressed above
pertaining to data consistency is not
present with regard to making a

500 Id.

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No. 697 at P 883.

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corporation’s market-based rate tariffs
Order No. 697 compliant. Our analysis
of market-based rate tariffs’ compliance
with Order No. 697 is not dependent on
analyzing data but rather analyzing
whether the tariffs meet the standards
set forth in Order No. 697. Unlike
analysis of data that can vary depending
on the source of the data and the
underlying assumptions, Order No. 697
set forth the standard by which the
market-based rate tariff will be judged
and those standards do not vary nor are
they subject to assumptions.
370. We will deny MidAmerican’s
request for clarification. To the extent
that a seller’s generation facilities are
electrically located in different regions,
the intent of the regional review
approach is for those facilities to be
studied with their separate regions. We
note that, prior to the adoption of the
Final Rule, sellers were required to
prepare a market power analysis for all
of their generation assets nationwide.
Some sellers with assets in multiple
regions chose to submit their individual
updated market power analyses when
each was due rather than combining
them into a single updated market
power analysis. Others filed one
updated market power analysis for the
entire corporate family, with individual
analyses of the different markets in
which their assets are located. Either
way, the same analyses were required to
be filed before and after the Final Rule.
Although the timing of the filings may
differ post-Final Rule, the increased
burden, if any, of filing pursuant to the
regional approach is minimal.
371. With respect to MidAmerican’s
company-specific request for waiver
from the requirements of Order No. 697,
we will decline to act in the context of
this generic rulemaking proceeding. We
do not believe that this rehearing order
is the proper vehicle to consider a
waiver request which, as MidAmerican
describes it, is narrowly tailored to itself
and Cordova. MidAmerican’s request for
waiver may be submitted in another
individual proceeding, and the
Commission will consider the merits of
its request at that time.
3. Clarifications on Implementation
Process
372. During the period since Order
No. 697 became effective, a number of
implementation questions have come to
the Commission’s attention, either as a
result of questions received from sellers
or as raised in various filings. As we
describe above, several of these issues
were addressed in the Clarification
Order issued on December 14, 2007. We
will use this opportunity to provide
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373. In the Clarification Order, among
other things, the Commission explained
that there may have been confusion
concerning which data and market share
calculations must be submitted as part
of sellers’ updated horizontal market
power analyses.505 The Commission
clarified that market shares calculated
for the wholesale market share screen
and the DPT analysis should be based
on the four seasons, as defined in the
April 14 Order,506 rather than the four
quarters of the calendar year. The
Clarification Order revised Appendix D
to Order No. 697 to incorporate this
clarification and explained that the
study period runs from December of one
year through November of the following
year.
374. In the Clarification Order, the
Commission also clarified which
entities are required to file their updated
market power analyses first. In Order
No. 697, the Commission discussed the
need for entities that have the
information necessary to perform
simultaneous transmission import limit
studies to file in advance of those who
will rely on that information.507 In
Appendix D of Order No. 697, the
Commission identified those required to
file first as ‘‘Transmission Operators.’’
However, the Commission explained in
the Clarification Order, consistent with
the discussion in paragraph 889 of
Order No. 697, that transmissionowning utilities with market-based rate
authority and their affiliates with
market-based rate authority are the
entities required to file their updated
market power analyses first in each
region.508 Accordingly, revised
Appendix D makes clear that
transmission owners and their affiliates
have earlier filing periods than other
entities required to file in each region.
375. In the Final Rule, the
Commission stated that it will entertain
individual requests for exemption from
Category 2, and that such requests must
be filed no later than 120 days before a
seller’s next updated market power
analysis is due. However, the period for
filing updated market power analyses is
not a specific date, but a month-long
period (either December or June of each
year). In response to questions regarding
how to calculate 120 days prior to the
505 We note that, in an effort to continue to
improve upon the accuracy and consistency of data
used within a region and to provide the
Commission and the public with a more complete
picture of the market, the Commission will allow
RTO/ISOs to conduct market power studies that the
RTO/ISO members can rely on in their market
power filings.
506 April 14 Order, 107 FERC ¶ 61,018 at n.85.
507 Order No. 697 at P 889.
508 Clarification Order, 121 FERC ¶ 61,260 at P 9.

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filing period, we clarify that a seller
must make a filing requesting an
exemption from Category 2 no later than
120 days prior to the first day of the
month in which its next updated market
power analysis is due.509
376. In Order No. 697, the
Commission explained that a power
marketer that does not own or control
generation assets in any region must
submit a filing explaining why it meets
the criteria for Category 1 and directed
that such filings be submitted with the
first scheduled geographic region in
which the power marketer makes any
sales.510 Because the Commission has
received several inquiries regarding this
directive, we will provide further
clarification here. If an unaffiliated
power marketer has made no sales at
any point in time since it obtained its
market-based rate authority, it should
make this submission during the next
filing period, i.e., June 1–30, 2008. We
also clarify that, once a seller is
determined to be in Category 1, it is not
required to file updated market power
analyses, or evidence of Category 1
status, for the other regions in which it
makes sales so long as it continues to
meet the criteria for a Category 1
seller.511
377. Additionally, in response to
inquiries from certain sellers in the
Central region, we will clarify the
geographic area included in that region.
Specifically, the Central region will now
be defined to include portions of NERC
Region RFC as follows: Central
(Midwest ISO, NERC Regions MRO and
RFC (not including PJM)).512 Appendix
D has been revised to reflect this
description of the Central region.
378. Additionally, in Order No. 697
the Commission adopted a requirement
that all sellers include an appendix
listing generation assets as well as
electric transmission and natural gas
intrastate pipelines and/or gas storage
facilities with certain filings, consistent
with the example in Appendix B of
Order No. 697.513 We clarify that the
transmission facilities that we require to
be included in that asset appendix are
limited to those the ownership or
control of which would require an
entity to have an OATT on file with the
Commission (even if the Commission
has waived the OATT requirement for a
particular seller).
509 See

id. P 868.
at n.1027.
511 See id. P 849 (stating that subsequent to being
found to be in Category 1, ‘‘all Category 1 sellers
will not be required to file regularly scheduled
updated market power analyses.’’)
512 Id. at Appendix D.
513 Order No. 697 at P 895.
510 Id.

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379. Further, we clarify the manner in
which transmission assets should be
identified and described in the asset
appendix. In order to lessen the
reporting burden for sellers with large
numbers of transmission facilities, we
will allow a company to combine lines
of a common size into one ‘‘line item’’
for purposes of the appendix; i.e., 12
individual 500 kV lines could be
identified as one line item in the
appendix. For companies using this

approach, rather than listing each line
separately, the appendix must be filled
out in a slightly different manner.
Specifically, under the Asset Name and
Use section of the appendix, rather than
using the actual line name, a seller
would insert an appropriate asset
identifier. For example, if combining all
500 kV lines together the asset identifier
would be ‘‘Combined 500kV Lines.’’ As
a result, the Size section of the appendix
would also change. Rather than

identifying the actual size of each line,
the seller would include the
transmission asset size, described as the
total combined length of all the lines of
that size. Because the combined lines
could run through several balancing
authority areas and regions, the seller
should split up its combined assets into
separate balancing authority areas.
Accordingly, the transmission asset
aspect of the appendix would be filled
out similar to the following:
Location

Filing entity and
its energy
affiliates

Asset name
and use

Owned by

Controlled by

Date control
transferred

ABC Corp .........

Combined
500kV Lines.

ABC Corp ........

ABC Corp ........

NA ...................

ABC Corp .........

Combined
500kV Lines.

ABC Corp ........

XYZ Inc ...........

Jan. 1, 2000 ....

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380. However, we note that this
combined approach can only be used if
lines of the same size are controlled by
the same entity. If there are lines of the
same size controlled by different
entities, they must be identified in
different line items; i.e., each combined
set of lines can only be identified as
controlled by one entity. Thus, if the
500 kV lines are owned or controlled by
two different entities, there would have
to be two line items for 500 kV lines
listed in the appendix. We believe this
approach will allow the Commission to
continue to obtain the information it
seeks regarding a seller’s affiliated
transmission assets while allowing
those entities with a great number of
assets to simplify their appendices.
381. Lastly, with regard to the asset
appendix, we wish to make clear that
sellers must submit both tables in their
entirety. Even if a seller has no assets to
list in a specific section, both the
Market-Based Rate Authority and
Generation Assets table, as well as the
Electric Transmission Assets and/or
Natural Gas Interstate Pipelines and/or
Gas Storage Facilities table must be
submitted. As stated in Appendix B to
Order No. 697, a seller should indicate
the fact that it has no assets or that a
field is not applicable by inputting
N/A.
4. Market-Based Rate Tariff
Clarifications
382. In Order No. 697 the Commission
adopted a requirement that all sellers
include a provision in their marketbased rate tariffs identifying all
limitations on their market based rate
authority (including markets where the
seller does not have market-based rate

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Balancing
authority area
New York ISO
and Tucson
BA.
Tucson BA ......

authority) and any exemptions from,
waivers of, or blanket authorizations
under the Commission’s regulations that
the seller has been granted (such as
exemption from the affiliate sales
restrictions; waiver of the accounting
regulations; blanket authority under part
34 for the issuances of securities and
assumptions of liabilities). The
Commission stated that this provision
must include cites to the Commission
orders approving each limitation,
exemption, waiver or blanket
authorization.514 On further review, the
Commission will take this opportunity
to clarify several aspects of this
requirement.
383. First, we clarify that if a seller’s
market-based rate authority is not
subject to any limitations (for example,
the seller’s market-based rate authority
is not limited to certain markets) or if
the seller has not been granted any
exemptions, waivers, or blanket
authorizations under the Commission’s
regulations, then the seller should so
state in the required ‘‘Limitations and
Exemptions’’ provision in its marketbased rate tariff, i.e., including ‘‘not
applicable,’’ or ‘‘N/A.’’ 515
384. Second, we provide additional
guidance on the format for citations to
pertinent Commission orders or
proceedings in which the Commission
imposed limitations on the seller’s
market-based rate authority or granted
the seller’s requested exemptions,
waivers, or blanket authorizations. In
particular, sellers which already have
been granted market-based rate
514 Order

No. 697 at P 916.
Niagara Mohawk Power Corp., 121 FERC
¶ 61,275 at P11 (2007) (Niagara Mohawk).
515 See

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Geographic
region (per
Appendix D)
Northeast and
Southwest.
Southwest .......

Size

Approx. 305
combined
miles.
185 combined
miles.

authorization and which have
previously been placed under any
limitation or granted any exemption,
waiver or blanket authorization should
include the cite to the relevant orders in
one of the following two citation forms:
Cal. Contract Power, 99 FERC
¶ 61,xxx, at P xx (2002).
WWW Corp., Docket No. ER03–xxxx–
000, at 2 (Apr. 12, 2003) (unpublished
letter order).
385. When a seller files an application
for market-based rate authority seeking
certain exemptions, waivers or blanket
authorizations, the seller should include
in its proposed tariff sheets the docket
number associated with the filing.
Under current Commission procedure, a
docket number is not assigned until
after an application has been filed.
However, to enable an applicant to
identify and include the docket number
of its filing in its proposed tariff sheets,
the Commission is establishing a new
process for sellers to obtain a docket
number for their submission before
filling. The Commission is creating a
location on its Web site where a new
applicant for market-based rate
authorization will e-mail 516 the
Commission and retrieve a docket
number under which its filing can be
made and which will be a substitute for
the required citation in the ‘‘Limitations
and Exemptions’’ provision of its
tariff.517 The point of this process is to
516 Any sellers unable to obtain this docket
number via the internet or e-mail will be directed
to include the pertinent information in their tariff
sheets in a compliance filing.
517 We note that while this approach will allow
most new applicants to comply with the
Commission’s citing requirement in the
‘‘Limitations and Exemptions’’ provision of the

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
alleviate the need for compliance filings
just to add a docket number or citation
once the Commission issues an order on
the request. Any modifications to the
information submitted with the
application would be directed to be
made in a compliance filing. Once the
docket number is obtained, the filing
must be submitted to the Commission
within 72 hours or the docket number
will expire and the applicant must
request a new one. This reserved docket
number should be included in the tariff
and the transmittal sheet, and a copy of
the Commission’s response assigning
this docket number should be attached
as the first page of the filing.
Accordingly, the process for a seller
newly filing for market-based rate
authorization will now require reserving
a docket number before submitting the
filing.
386. In Appendix C of Order No. 697,
the Commission provided certain
applicable 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. One of these is to be used if a
seller makes sales of ancillary services
as a third-party provider.518 We are
revising this applicable provision so
that it is consistent with the other
ancillary service provisions by inserting
the phrase ‘‘Seller offers.’’ Thus, the
‘‘Third Party Provider’’ provision that
should be included in all applicable
market-based rate tariffs is as follows:

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Third-party ancillary services: Seller offers
[include all of the following that the seller is
offering: Regulation Service, Energy
Imbalance Service, Spinning Reserves, and
Supplemental Reserves]. Sales will not
include the following: (1) Sales to an RTO or
an ISO, i.e., where that entity has no ability
to self-supply ancillary services but instead
depends on third parties; (2) sales to a
traditional, franchised public utility affiliated
with the third-party supplier, or sales where
the underlying transmission service is on the
system of the public utility affiliated with the
third-party supplier; and (3) sales to a public
utility that is purchasing ancillary services to
satisfy its own open access transmission tariff
requirements to offer ancillary services to its
own customers.
market-based rate tariff, there may be some
instances in which the Commission will require a
seller to make a subsequent filing to include a full
citation to the Commission order approving a
limitation, exemption, waiver or blanket
authorization. An example of when the Commission
may require such a compliance filing is when the
Commission exempts a seller from affiliate
restrictions which have been codified in 18 CFR
35.39 or when approving mitigation measures.
However, unless an applicant is informed by order
to revise its tariff to include a citation, the docket
number used in the tariff in the initial submission
will suffice.
518 See Order No. 697 at P 917–18.

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387. Additionally, regarding other
applicable tariff provisions, which
include those needed 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.519 To the extent that a seller
with market-based rate authority does
not already have authority to make sales
of ancillary services at market-based
rates in one or more of the RTO/ISOs
included in Appendix C, but wishes to
do so, it may file revised tariff sheets
including the standard applicable
ancillary service tariff provision(s)
without seeking separate authorization
from the Commission under FPA
section 205. Separate authorization for
specific sellers is not needed given that
Order No. 697 implicitly granted
authorization for ancillary services sales
by sellers with market-based rate
authority by providing standard tariff
provisions for ancillary services
sales.520
388. The Commission also stated in
Order No. 697 that it would permit
sellers to list in their market-based rate
tariffs additional seller-specific terms
and conditions that go beyond the
standard provisions set forth in
Appendix C.521 In the Clarification
Order, we clarified that these sellerspecific terms and conditions do not
include those provisions that the
Commission has codified in 18 CFR Part
35, Subpart H. Specifically, we stated
that ‘‘ ‘seller-specific terms and
conditions’ are those provisions that are
commonly found in power sales
agreements, such as creditworthiness,
force majeure, dispute resolution,
billing, and payment provisions.’’ 522 In
addition, we clarify here that we expect
that all provisions that were contained
in a seller’s market-based rate tariff but
that are now codified in the
Commission’s regulations are to be
removed from each seller’s marketbased rate tariff at the time the seller
modifies its existing tariff to include the
required provisions and any applicable
provisions set forth in Appendix C of
Order No. 697. For example, sellers
should remove from their tariffs codes
of conduct (which have been replaced
519 Id. P 916–917; see Appendix C for a listing of
the standard ancillary services provisions. See also
Niagara Mohawk Power Corp., 121 FERC ¶ 61,275,
at P 14 & n.22 (2007) (directing seller to conform
with Appendix C).
520 See Niagara Mohawk Power Corp., 121 FERC
¶ 61,275, at P 18 (2007) (accepting tariff provisions
that were new for National Grid that comported
with ancillary services previously approved by the
Commission for sale at market-based rates and were
listed in Appendix C of Order No. 697).
521 Order No. 697 at P 919–22.
522 Clarification Order, 121 FERC ¶ 61,260 at P15.

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25887

by the affiliate restrictions in § 35.39),
any language prohibiting affiliate sales
without first receiving Commission
authorization (which is codified in
§ 35.39(b)), market behavior rules
(which are codified in § 35.41), and the
change in status reporting requirement
(which is codified in § 35.42).
389. We remind sellers that,
consistent with § 35.9(b)(4), all tariff
sheets must include a proposed effective
date. The regulation requires that the
seller must place the specific effective
date proposed by the company on the
tariff sheets. To alleviate any confusion,
we stated in the Clarification Order that,
notwithstanding the fact that Order No.
697 did not require market-based rate
sellers to make immediate compliance
filings amending their market-based rate
tariffs, the Commission intended that all
requirements and limitations applicable
to market-based rate sellers set forth in
the Final Rule should become effective
on September 18, 2007. The
Clarification Order explained that,
effective September 18, 2007, provisions
in market-based rate tariffs that are
inconsistent with the requirements of
Order No. 697 are no longer in effect.523
Accordingly, sellers filing revised tariff
sheets solely to comply with Order No.
697 should use September 18, 2007 as
the effective date of the tariff sheets.
However, if there are any additional
revisions other than those required by
the Final Rule, whether it be a name
change or the addition or modification
of any provision for any other reason,
sellers should propose the date on
which they wish the tariff sheets to
become effective. We note that, while
the sheets will be made effective on the
date that the seller proposes, the
provisions relating to and required by
Order No. 697 are still effective as of the
effective date of Order No. 697.524
390. Additionally, the Commission
provides clarification regarding requests
for waiver of affiliate restrictions
(including the affiliate sales restriction
and what was formerly the codes of
conduct). If a seller was granted waiver
of a restriction by the Commission prior
to the effective date of Order No. 697,
and the seller still qualifies for that
waiver, the waiver remains effective and
no further action is needed.525 However,
if a seller has not previously been
granted waiver of the affiliate
restrictions and seeks a finding that the
affiliate restrictions do not apply to it,
a seller must file a request with the
523 Id.

at P 5.
Clarification Order, 121 FERC ¶ 61,260 at

524 See

P 5.
525 Pursuant to Order No. 697, however, such a
waiver must be identified in a seller’s tariff. See
Order No. 697 at P 916 and Appendix C.

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Commission pursuant to FPA section
205.
391. Lastly, in order to identify which
sellers must file updated market power
analyses, we will now require each
seller to specify in its market-based rate
tariff whether it is a Category 1 or
Category 2 seller. In a separate provision
of the market-based rate tariff entitled
Seller Category, each seller should state
whether it believes it is in Category 1 or
Category 2.526 Specifically, the
following provision should be included
in each market-based rate tariff:
Seller Category: Seller is a [insert Category
1 or Category 2] seller, as defined in 18 CFR
35.36(a).

392. The Commission will make a
finding on the category of each seller.
To the extent that the Commission finds
that a seller is in the other category, the
Commission will order the appropriate
tariff revisions.
393. Any seller whose category has
been determined in a Commission
proceeding between the effective date of
Order No. 697 and the issuance of this
order and which has not included a
Seller Category provision in its tariff
should update its tariff with such a
provision the next time that it files
revised tariff sheets, a triennial review,
or a change in status report.
F. Legal Authority
1. Whether Market-Based Rates Can
Satisfy the Just and Reasonable
Standard Under the FPA
Final Rule

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394. In the Final Rule, the
Commission rejected arguments that it
has no authority to adopt market-based
rates or that the market-based rate
program adopted in the Final Rule does
not comply with the FPA. The
Commission explained that it is settled
law that market-based rates can satisfy
the just and reasonable standard of the
FPA, as most recently affirmed by the
Ninth Circuit in Lockyer and
Snohomish.527 The Commission
explained that in Lockyer, the Ninth
Circuit cited with approval the
Commission’s dual requirement of an ex
ante finding of the absence of market
power and sufficient post-approval
reporting requirements, finding that the
526 Sellers that have received an exemption from
Category 2, as described in Order No. 697 at P 868,
should identify themselves as Category 1 sellers.
527 Order No. 697 at P 943 (citing State of
California, ex rel. Bill Lockyer v. FERC), 383 F.3d
1006 (9th Cir. 2004), cert. denied (S. Ct. Nos. 06–
888 and 06–1100 (June 18, 2007) (Lockyer); Public
Utility District No. 1 of Snohomish County,
Washington v. FERC, 471 F.3d 1053 (9th Cir. 2006),
cert. granted, 128 S. Ct. 31 (Sept. 25, 2007) (Nos.
06–1457, 06–1462) (Snohomish)).

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Commission did not rely on market
forces alone in approving market-based
rate tariffs.528 The Final Rule also
rejected arguments that the proposed
rule impermissibly relied solely on the
market to determine just and reasonable
rates, explaining that in the marketbased rate program adopted in the Final
Rule and through other Commission
actions, the Commission is not relying
solely on the market, without adequate
regulatory oversight, to set rates.529
Rather, it has adopted filing
requirements, new market manipulation
rules, and a significantly enhanced
market oversight and enforcement
division to help oversee potential
increases in market power and potential
market manipulation.530
395. The Commission retained its
policy of granting market-based rate
authority to sellers without market
power under the terms and conditions
set forth in the Final Rule.531 The Final
Rule explained that the Commission has
a long-established approach when a
seller applies for market-based rate
authority of focusing on whether the
seller lacks market power. The
Commission explained that this
approach, combined with the
Commission’s filing requirements
(EQRs, change in status filings, and
regularly scheduled updated market
power analyses for Category 2 sellers)
and ongoing monitoring through the
Commission’s Office of Enforcement
and complaints filed pursuant to FPA
section 206, allows the Commission to
ensure that market-based rates remain
just and reasonable. Moreover, for
sellers in RTO/ISO organized markets,
the Commission has in place market
rules to help mitigate the exercise of
market power, price caps where
appropriate, and RTO/ISO market
monitors to help oversee market
behavior and conditions.532
396. The Final Rule rejected
arguments that the market-based rate
program does not comply with the FPA,
stating that ‘‘[t]he Supreme Court has
held that ‘[f]ar from binding the
Commission, the FPA’s just and
reasonable requirement accords it broad
ratemaking authority * * *. The Court
has repeatedly held that the just and
reasonable standard does not compel
the Commission to use any single
pricing formula in general * * *.’ ’’ 533
528 Id.
529 Id.

P 953–954.
P 952.

530 Id.
531 Id.

P 954–955.
P 955.
533 Id. P 943 (quoting Mobil Oil Exploration v.
United Distribution Co., 498 U.S. 211, 224 (1991)
(Mobil Oil Exploration), citing FPC v. Hope Natural
Gas Co., 320 U.S. 591, 602 (1944); FPC v. Natural
532 Id.

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The Commission also pointed out that
in the Lockyer court’s analysis of the
Commission’s market-based rate
authority, the Ninth Circuit cited the
Supreme Court’s determination in Mobil
Oil Exploration and also noted that the
use of market-based rate tariffs was first
approved by the courts as to sellers of
natural gas in Elizabethtown Gas, then
as to wholesale sellers of electricity in
Louisiana Energy and Power Authority
v. FERC.534
397. The Commission rejected
arguments that the Final Rule
impermissibly relies solely on the
market to determine just and reasonable
rates.535 The Final Rule explained that
in Texaco,536 the Supreme Court noted
that it had sustained rate regulation
based on setting area rates that were
based on composite cost considerations,
citing its decision in FPC v. Hope
Natural Gas Co.,537 and added that
ratemaking agencies are not bound to
the service of any single regulatory
formula.538 The Final Rule further
explained that in Texaco, the Supreme
Court found that the NGA permits the
indirect regulation of small-producer
rates, and noted that cases under the
NGA and the FPA are typically read in
pari materia.539 The Commission stated
that in the market-based rate program
adopted in the Final Rule and through
other Commission actions, unlike the
situation in Texaco, the Commission is
not relying solely on the market without
adequate regulatory oversight to set
rates.
398. The Final Rule also explained
that in Elizabethtown Gas, a decision
relying on Texaco, the D.C. Circuit
addressed a Commission order
approving a restructuring settlement
under which Transcontinental Gas
Pipeline Corporation (Transco) would
no longer sell gas bundled with
transportation, but would sell gas at the
wellhead or pipeline receipt point, to be
transported as the buyer sees fit, and the
sales would be market-based while the
rates for transportation on Transco’s
system would be cost-of-service
Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian
Basin Area Rate Cases, 390 U.S. 747, 776–77 (1968)
(Permian); FPC v. Texaco, 417 U.S. 380 (1974)
(Texaco)).
534 Elizabethtown Gas Co. v. FERC, 10 F.3d 866
(D.C. Cir. 1993) (Elizabethtown Gas); Louisiana
Energy and Power Authority v. FERC, 141 F.3d 364
(D.C. Cir. 1998) (LEPA). See also Order No. 697 at
P 944.
535 Order No. 697 at P 945–947.
536 Id. P 946 (citing FPC v. Texaco, Inc., 417 U.S.
380 (1974) (Texaco)).
537 Id. (citing 320 U.S. 602).
538 Id. (quoting Permian, 390 U.S. at 776–77).
539 Id. P 946 n.1070 (citing FPC v. Sierra Pacific
Power Co., 350 U.S. 348, 353 (1956) (Sierra);
Arkansas-Louisiana Gas Company v. Hall, 453 U.S.
571 n.7 (1981)).

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
based.540 In rejecting arguments that the
proposed rule impermissibly relied
solely on the market to determine just
and reasonable rates, the Final Rule
explained that in Elizabethtown Gas the
D.C. Circuit upheld the Commission’s
approval of market-based pricing.541
The Final Rule explained that the D.C.
Circuit had also affirmed the
Commission’s approval of an
application by Central Louisiana
Electric Company (CLECO) to sell
electric energy at market-based rates.542
Requests for Rehearing
399. Consumer Advocates argue that
the Final Rule erred in claiming that the
Commission can legally rely on the
market (viz. wholesale buyers/re-sellers)
to determine lawful rates. They contend
that the Final Rule errs in relying on
wholesale buyers/re-sellers to determine
lawful rates by ‘‘negotiation,’’
particularly where the buyers generally
bear no risk of loss in passing along
such prices.543 They argue that such
reliance constitutes an unlawful
delegation of the Commission’s
statutory obligations to wholesale
buyers insofar as (1) the Commission
overlooked the economic fact that such
wholesale buyers/re-sellers generally
bear no risk of loss because their
negotiated prices must be passed
through to retail ratepayers; 544 and (2)
the Final Rule may not rely on the
markets to determine rates because the
Commission may not delegate to others
its FPA responsibilities to ensure that
rates are lawful.545
400. Consumer Advocates contend
that the Final Rule failed to provide a
standard whereby the Commission can
determine whether actual market rate
increases fall within a ‘‘zone of
reasonableness’’ not just in theory, but
540 Id.

P 948.
P 949–950.
542 Id. P 951 (citing LEPA, 141 F.3d at 365).
543 Consumer Advocates Rehearing Request at 10.
Richard Blumenthal, Attorney General for the State
of Connecticut and the People of the State of
Illinois, by and through the Illinois Attorney
General, Lisa Madigan (Attorneys General of
Connecticut and Illinois) submitted a request for
rehearing on July 19, 2007 that adopts and
incorporates by reference all of the arguments
presented by the Consumer Advocates in their
request for rehearing filed in this proceeding.
544 Id. at 10 (citing Tejas Power Corp v. FERC, 908
F.2d 998 (D.C. Cir. 1990); Nantahala Power & Light
Co. v. Thornburg, 476 U.S. 953, 970 (1986);
Elizabethtown Gas).
545 Id. at 10, 12. Consumer Advocates note that in
a recent order the Commission correctly held that
it could not delegate to state commissions its
‘‘ratemaking obligations under the FPA.’’ Id. at 12
(citing Entergy Services, Inc., 120 FERC ¶ 61,020
(2007), citing Louisiana, Inc. v. Louisiana Public
Service Comm., 539 U.S. 39, 43 n.1; City of New
Orleans v. Entergy Corp., 55 FERC ¶ 61,211, at
61,729 (1991)).

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541 Id.

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‘‘in fact.’’ According to Consumer
Advocates, the Final Rule only
addressed whether the ‘‘market’’ is
competitive 546 and sellers are
manipulative, not whether wholesale
rates are not excessive, as the FPA
requires.547 Consumer Advocates argue
that the Final Rule attempted to
distinguish Supreme Court and other
judicial precedent that requires the
Commission to determine whether
‘‘market’’ rates in fact fall within a
‘‘zone of reasonableness,’’ but fails to do
so.548 They also contend that the Final
Rule failed to explain how the
Commission, which is not an antitrust
agency, acting under the FPA, which is
not an antitrust statute but a rate filing
regulatory statute, can rely entirely on
its oft-changing antitrust analyses
regarding market power to determine
whether market-based rates are within a
zone of reasonableness.549 NASUCA
also asserts that the Final Rule failed to
identify an objective standard by which
to ascertain, after rates have been
changed, charged and eventually
reported, whether a market rate is or is
not in the zone of reasonableness.550
401. Consumer Advocates contend
that the Final Rule erred in relying
heavily on Natural Gas Act (NGA) cases
and Interstate Commerce Act oil
pipeline cases as judicial support for the
Commission’s authority to allow
market-based rates.551 Consumer
Advocates assert that there are
substantive differences among
electricity and natural gas statutes, the
physical operations of the industries,
and the costs of providing service.552
They argue that in addition to the fact
that Congress has deregulated most
natural gas wellhead sales, but has
never deregulated wholesale electric
sales, the FPA and NGA have always
differed in certain respects, namely that
NGA section 7 confers authority on the
Commission to certify and condition
546 As discussed at P 409 below, the Industrial
Customers argue that the Final Rule erred insofar
as it failed to make the finding that a competitive
market exists. See Industrial Customers Rehearing
Request at 6–7.
547 Consumer Advocates Rehearing Request at 12–
13.
548 Id. (citing Farmers Union Cent. Exch. v. FERC,
734 F.2d 1486 (D.C. Cir. 1984) (Farmers Union)).
549 Id. at 13–14 (citing MCI Telecommunications
Corp. v. AT&T Co., 512 U.S. 218 (1994) (MCI);
Southwestern Bell Corp. v. FCC, 43 F.3d 1515 (D.C.
Cir. 1995) (Southwestern Bell)).
550 NASUCA Rehearing Request at 18.
551 Consumer Advocates Rehearing Request at 19
(citing Order No. 697 at P 943, n. 1068 (citing Mobil
Oil Exploration, 498 U.S. at 224, citing FPC v. Hope
Natural Gas Co., 320 U.S. 591, 602 (1944); FPC v.
Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942);
Permian, 390 U.S. at 776–77; Texaco, 417 U.S. at
308)).
552 Id. at 17–18.

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natural gas service, whereas no such
authority is given to the Commission
under the FPA.553 Consumer Advocates
argue that the regulation of generation
and distribution was specifically
reserved to the states 554 and contend
that the costs of production of natural
gas and electricity differ markedly.555
They state that highly depreciated
power plants have very different costs
from new ones, and they note that in the
Connecticut complaint against ISO New
England, the complaint showed that
excessive rates of return were being
made, but the Commission found this
‘‘ ‘not relevant.’ ’’ 556
402. Consumer Advocates conclude
that these differences result in very
different bidding strategies by market
participants, yet the Final Rule relied
primarily on natural gas and oil cases in
defense of the Commission’s marketbased rate regime.557 In particular, they
contend that the claim in the Final Rule
that ‘‘costs of all natural gas companies
need not be ascertained separately,’’
incorrectly cites to the fact that the
courts treat virtually identically parts of
the statute ‘‘ ‘in pari materia.’ ’’ 558 They
argue that because this language refers
to the filing and rate review provisions
of the two statutes, it does not contend
that the cost elements or physical
operations of these two distinct
industries are the same.559
403. Consumer Advocates argue that
the incentive provided by the marketbased rate regime is for plant owners to
keep power supplies tight, thus raising
their profits from remaining power
plants or contracts.560 They state that
because wholesale sellers have no
obligation to serve, the Commission’s
market-based rate regime requires the
Commission to give incentives, like
locational pricing, to essentially
‘‘ ‘bribe’ ’’ suppliers to build power
plants.561 Consumer Advocates contend
that the Final Rule failed to explain why
this ‘‘ ‘perverse incentive’ ’’ is in either
the public or the national interest. They
also note that the court in Elizabethtown
Gas did not address these ‘‘perverse
economic incentives.’’ 562
404. Industrial Customers argue that a
finding that competitive markets exist is
a prerequisite to relying upon market553 Id.
554 Id.

at 18.
(citing FPA section 201(e)).

555 Id.
556 Id. at 19 (citing Richard Blumenthal v. ISO
New England, Inc., 117 FERC ¶ 61,038 (2006), reh’g
denied, 118 FERC ¶ 61,205 (2007) (Blumenthal)).
557 Id. (citing Order No. 697 at P 943, n. 1068).
558 Id. (citing Order No. 697 at P 946, n. 1070).
559 Id.
560 Id. at 20.
561 Id.
562 Id. at 21.

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based rate authority to satisfy the
mandates of the FPA. In particular,
Industrial Customers contend that the
Final Rule does not reflect reasoned
decisionmaking because it fails to
address their argument stating that the
Commission must find the existence of
a competitive market before it can rely
on market-based rate authority.563
Additionally, Industrial Customers
contend that the Final Rule is arbitrary,
capricious and insufficiently supported
in presuming that existing price setting
mechanisms are competitive markets
that will enable the use of market-based
rate authority to ensure just and
reasonable rates.564 Industrial
Customers argue that their NOPR
comments relied on significant
precedent for their argument that the
Commission must point to ‘‘empirical
proof’’ that competitive markets exist.565
Industrial Customers state that although
the Commission provides settled law
supporting its conclusion that marketbased rates can satisfy the just and
reasonable standard of the FPA,566 the
issue posed by Industrial Customers was
whether the Commission has made the
necessary findings that a competitive
market exists—and it has not.567
Industrial Customers therefore assert
that the Commission failed its
responsibility to respond to their
arguments,568 and must either (1)
explain why the case law underlying
market-based rate authority no longer
requires the prerequisite showing of
competitive markets based on empirical
proof, or (2) undertake the task of
analyzing whether current wholesale
electricity pricing mechanisms amount
to a competitive market.569 Industrial
563 Industrial Customers Rehearing Request at 6
(citing Electricity Consumers Res. Council v. FERC,
747 F.2d 1511, 1513; Burlington Truck Lines v.
United States, 371 U.S. 156, 168 (1962); W. Mass
Elec. Co. v. FERC, 165 F.3d 922, 927 (D.C. Cir.
1997); Victor Broad, Inc. v. FCC, 722 F.2d 756, 760
(D.C. Cir. 1983); Transcontinental Gas Pipe Line
Corp. v. FERC, 922 F.2d 865, 869 (D.C. Cir. 1991);
KN Energy, Inc. v. FERC, 968 F.2d 1295, 1303 (D.C.
Cir. 1992); PPL Wallingford, 419 F.3d at 1198;
Canadian Petroleum Producers, 254 F.3d at 299;
Tesoro Alaska Petroleum Co. v. FERC, 234 F.3d
1286, 1294 (D.C. Cir. 2000)). Montana Counsel
similarly argues that the Commission erred in
assuming that long-term markets are inherently
competitive. Montana Counsel Rehearing Request at
4–6.
564 Id. at 8 (citing LEPA, 141 F.3d at 365;
Elizabethtown Gas, 10 F.3d at 870).
565 Id. at 7 (citing Industrial Customers’ August 7
Comments at 6–7; Farmers Union, 734 F.2d at
1510).
566 Id. (citing Order No. 697 at P 943–955).
567 Id.
568 Id. (citing NorAm Gas, 148 F.3d at 1165;
Brusco Tug & Barge Co. v. NLRB, 247 F.3d 273, 278
(D.C. Cir. 2001); Missouri PSC v. FERC, 234 F.3d 36,
41 (D.C. Cir. 2001)).
569 Id. at 7–8 (citing Tripoli Rocketry v. Bureau of
Alcohol, Tobacco, 437 F.3d 75, 81 (D.C. Cir. 2006)).

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Customers argue that the key question
the Commission failed to answer in the
Final Rule is what constitutes a truly
competitive market and whether there
are any in the country sufficient to
enable use of market-based rate
authority.
405. Industrial Customers argue that
as the Commission acknowledged in its
approval of the Southwest Power Pool’s
Energy Imbalance Service Market, the
process for assessing market-based rate
authority is a two-part analysis: (1)
Determining whether a competitive
market exists and (2) ensuring that the
seller-applicant cannot exercise market
power, based either on a finding that no
market power exists or based on a
finding that mitigation is sufficient to
protect against market power.570
Industrial Customers contend that if this
two-part analysis is not undertaken, the
Commission cannot demonstrate that
reliance on market-based rate authority
is just and reasonable.571
406. Industrial Customers state that
there are definite criteria such as
barriers to entry or exit, demand
elasticity, ease of product deliverability,
transparent market information,
unconcentrated generation asset
ownership, correct market design, and
absence of market power that would
help determine whether a competitive
market exists.572 They present
information about existing markets that
they allege calls into question whether
the Commission is capable of finding
the presence of dynamically competitive
markets. Industrial Customers argue that
the widespread lack of demand
elasticity and the equally pervasive
presence of generation ownership
concentration and high market shares
within submarkets are the types of
issues that the Final Rule erroneously
overlooked by presuming the existence
of competitive markets.573 Industrial
Customers contend that market power
issues are prevalent in PJM,574 Midwest
570 Id. at 9 (citing Southwest Power Pool, Inc., 116
FERC ¶ 61,289, at P 30 (2006)).
571 Id.
572 Id.
573 Id. at 10.
574 Id. at 10–13 (citing PJM 2006 State of the
Market Report at 89, 210 (Mar. 8, 2007), http://
www.pjm.org; PJM Preliminary Market Structure
Screen for 2007–2008; PJM Preliminary Market
Structure Screen for 2008–2009; PJM Preliminary
Market Structure Screen for 2000–2010; Letter from
PJM to Maryland Public Service Commission, dated
June 8, 2007 at 8, Maryland PSC Administrative
Docket No. PC 8; PJM 2008/2009 RPM Base
Residual Auction Results at 1, (July 13, 2007);
Statement of Joseph E. Bowring In Response to the
Federal Energy Regulatory Commission’s Order of
May 18, 2007 at 3, (filed June 12, 2007)).

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ISO,575 Southwest Power Pool,576 and
ISO New England.577
Commission Determination
407. In the Final Rule, the
Commission fully addressed the
arguments raised by commenters
challenging the Commission’s marketbased rate program. Consumer
Advocates and Industrial Customers
repeat on rehearing many of the
arguments that they raised in their
comments. While these entities re-state
their arguments in a variety of ways,
their arguments basically fall into two
categories: (1) That the Commission has
no authority at all under the FPA to rely
on the market to ensure just and
reasonable rates, in lieu of cost-based
ratemaking; and (2) that the standard
adopted by the Commission in this rule
for allowing market-based rates—a
demonstration by the individual seller
that it lacks or has mitigated both
horizontal and vertical market power—
does not comply with the FPA
requirement that rates be just,
reasonable, and not unduly
discriminatory or preferential. As we set
forth below, we find all the iterations of
these basic arguments to be without
merit because court precedent for the
past 60 years validates the
Commission’s discretion not to be
bound to any particular ratemaking
method and indeed in more recent years
has sanctioned market-based rates under
both the NGA and the FPA, and because
the market-based rate analysis in this
rule will result in rates that fall within
a zone of reasonableness. Section 205 of
the FPA requires that ‘‘[a]ll rates and
charges made * * * shall be just and
reasonable.’’ 578 The FPA does not
prescribe any particular ratemaking
methodology to be followed in setting
rates so long as rates fall within a zone
of reasonableness,579 i.e., the rates are
neither less than compensatory to the
seller nor excessive to the consumer.580
575 Id. at 14 (citing 2006 Midwest ISO State of
Market Report).
576 Id. at 15 (citing Monthly Metrics Report for
SPP Energy Imbalance Services Market at 3,
prepared by the SPP Market Monitoring Unit (Apr.
2007)).
577 Id. (citing ISO New England Report).
578 16 U.S.C. 824d(a).
579 FPC v. Hope Natural Gas Co., 320 U.S. at 602
(‘‘[u]nder the statutory standard of ‘just and
reasonable’ it is the result reached not the method
employed which is controlling’’); Permian, 390 U.S.
at 776–77 (‘‘rate-making agencies are not bound to
the service of any single regulatory formula; they
are permitted, unless their statutory authority
otherwise plainly indicates, ‘to make the pragmatic
adjustments which may be called for by particular
circumstances,’ ’’ citing FPC v. Natural Gas Pipeline
Co., 315 U.S. at 586).
580 Bluefield Water Works and Improvement Co.
v. Public Service Commission, 262 U.S. 679, 692–

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Further, the fixing of ‘‘just and
reasonable’’ rates involves a balancing
of investor and consumer interests 581
and the ‘‘zone of reasonableness’’ may
take into account all relevant public
interests, both existing and
foreseeable.582 These public interests
may appropriately include non-cost
factors, such as the need to stimulate
additional investment.583 As we
explained in the Final Rule and reiterate
here, the Supreme Court has held that
‘‘[f]ar from binding the Commission, the
‘just and reasonable’ requirement
accords it broad ratemaking authority
* * *. The Court has repeatedly held
that the just and reasonable standard
does not compel the Commission to use
any single pricing formula in general
* * *.’’ 584 Accordingly, the FPA grants
the Commission broad discretion as to
how the statute’s ratemaking mandate
will be satisfied.585 The market-based
rate program represents a reasonable
exercise of that discretion.586
408. It is settled law that market-based
rates can satisfy the just and reasonable
standard of the FPA and cognate
statutes. For example, as the D.C. Circuit
has held, ‘‘when there is a competitive
market the FERC may rely upon marketbased prices in lieu of cost-of-service
regulation to assure a ‘just and
reasonable’ result.’’ 587 Thus, the
Commission may rely on markets for a
just and reasonable rate provided that it
has made the appropriate findings
93 (1923) (Bluefield) (‘‘[a] public utility is entitled
to such rates as will permit it to earn a return * * *
equal to that generally being made at the same time
and in the same general part of the country on
investments in other business undertakings which
are attended by corresponding risks and
uncertainties; but it has no constitutional right to
profits such as are realized or anticipated in highly
profitable enterprises or speculative ventures. The
return should be reasonably sufficient to assure
confidence in the financial soundness of the utility
and should be adequate, under efficient and
economical management, to maintain and support
its credit and enable it to raise the money necessary
for the proper discharge of its public duties’’).
581 FPC v. Hope Natural Gas Co., 320 U.S. at 603.
582 See Farmers Union, 734 F.2d at 1501.
583 See id. at 1502.
584 Id. P 943 (quoting Mobil Oil Exploration v.
United Distribution Co., 498 U.S. 211, 224 (1991)
(Mobil Oil Exploration), citing FPC v. Hope Natural
Gas Co., 320 U.S. 591, 602 (1944); FPC v. Natural
Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian
Basin Area Rate Cases, 390 U.S. 747, 776–77 (1968)
(Permian); FPC v. Texaco, 417 U.S. 380 (1974)
(Texaco)).
585 Mobil Oil Exploration, 498 U.S. at 224, citing
FPC v. Hope Natural Gas Co., 320 U.S. at 602; FPC
v. Natural Gas Pipeline Co., 315 U.S. at 586;
Permian, 390 U.S. at 776–77; Texaco, 417 U.S. at
386–89; Mobil Oil Corp. v. FPC, 417 U.S. 283, 308
(1974).
586 Lockyer, 383 F.3d at 1013; Snohomish, 471
F.3d at 1080.
587 Elizabethtown Gas, 10 F.3d at 870. See also
Tejas Power, 908 F.2d at 1004; LEPA, 141 F.3d at
365.

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regarding whether sellers lack market
power.
409. The Commission exercises its
statutory responsibility under the FPA
to ensure that market-based rates are
just and reasonable through the dual
requirement of an ex ante finding that
the seller lacks or has mitigated both
horizontal and vertical market power
and post-approval oversight through
reporting requirements and ongoing
monitoring.588 In granting market-based
rate authorization, the Commission
thoroughly examines an applicant’s
market power in the relevant geographic
markets. An examination of both
horizontal (generation market share) and
vertical (transmission and other barriers
to entry) market power in the relevant
markets gives the Commission
assurance that the seller cannot increase
price by restricting supply or denying
customers access to alternative
suppliers. When the Commission
determines that a seller lacks or has
mitigated market power, it is making a
determination that the resulting rates
will be established through competitive
forces, not the exercise of market power,
and thus will fall within a zone of
reasonableness which protects
customers against excessive rates, on the
one hand, but allows the seller the
opportunity to recover costs and earn a
reasonable rate of return, on the other
hand. This is fully consistent with the
fundamental rate principles set forth in
Hope and Bluefield, supra, and their
progeny. In addition, in developing its
market-based rate regime, the
Commission has taken into account
non-cost factors, recognized as
appropriate by the courts, associated
with greater reliance on competition;
specifically, where sellers do not have
market power, the Commission believes
it can encourage greater market entry,
greater efficiency and greater innovation
in meeting the nation’s power needs
through allowing such sellers a
competitively set rate.
410. Further, the Commission has in
place multiple layers of protection for
customers to ensure that market-based
rates are just and reasonable and that
they remain so. For public utilities
selling in real-time and/or day-ahead
markets administered by Commissionapproved ISOs and RTOs (which cover
five regions of the country), in addition
to the market power analysis individual
sellers must satisfy under this rule,
sellers must comply with market rules
contained in RTO/ISO tariffs approved
by the Commission. These single price
auction markets set clearing prices
588 Lockyer, 383 F.3d at 1013; Snohomish, 471
F.3d at 1080; see also LEPA, 141 F.3d at 370.

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based on economic dispatch principles
to which various safeguards have been
added, as appropriate, including rules
against improper bidding and, in some
cases, bid price caps including conduct
and impact tests. In addition, to ensure
that market-based rates, once granted,
remain just and reasonable and not
unduly discriminatory or preferential,
the Commission has incorporated filing
and reporting requirements into the
market-based rate program (EQRs,
change in status filings, regularlyscheduled updated market power
analyses). These filing requirements
help the Commission to monitor
potential gains in market power and to
take remedial steps as appropriate,
including revocation of market-based
rate authority and civil penalties. The
Commission has also required each of
the RTO/ISOs to have market monitors
to help oversee their wholesale markets
and report to the Commission any
concerns that market rules have been
violated or concerns regarding seller
behavior. This provides an added level
of monitoring against the potential
exercise of market power in the regional
markets administered by the
jurisdictional RTO/ISOs.
411. That market-based rates are
permissible under FPA was recently
affirmed by the Ninth Circuit in Lockyer
and Snohomish. In Lockyer, the Ninth
Circuit cited with approval the
Commission’s dual requirement of an ex
ante finding of the absence of market
power and sufficient post-approval
reporting requirements and found that
the Commission did not rely on market
forces alone in approving market-based
rate tariffs. The Ninth Circuit held that
this dual requirement was ‘‘the crucial
difference’’ between the Commission’s
regulatory scheme and the FCC’s
regulatory scheme, remanded in MCI,
which had relied on market forces alone
in approving market-based rate
tariffs.589 The Ninth Circuit thus held
that ‘‘California’s facial challenge to
market-based tariffs fails’’ and ‘‘agree[d]
with FERC that both the Congressionally
enacted statutory scheme, and the
pertinent case law, indicate that marketbased tariffs do not per se violate the
FPA.’’590 The Ninth Circuit determined
that initial grant of market-based rate
authority, together with ongoing
oversight and timely reconsideration of
market-based rate authorization under
589 Lockyer,

383 F.3d at 1013.
at 1013 & n.5; id. at 1014 (‘‘The structure
of the tariff complied with the FPA, so long as it
was coupled with enforceable post-approval
reporting that would enable FERC to determine
whether the rates were ‘just and reasonable’ and
whether market forces were truly determining the
price.’’).
590 Id.

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section 206 of the FPA, enables the
Commission to meet its statutory duty to
ensure that all rates are just and
reasonable.591 While the court in
Lockyer found that the Commission’s
market-based rate reporting
requirements were not followed in that
particular case, it did not find those
reporting requirements invalid and, in
fact, upheld the Commission’s market
program as complying with the FPA.
The market-based rate requirements and
oversight adopted in this rule are more
rigorous than those reviewed by the
Lockyer court.
412. Accordingly, we find to be
without merit the arguments raised on
rehearing that the Commission lacks
authority to continue to permit marketbased rates for wholesale sales of
electric energy. The courts have
sustained the Commission’s finding that
market-based rates are one method of
setting just and reasonable rates under
the FPA. As supplemented by the Final
Rule, the Commission finds that the
market-based rate program complies
with the statutory and judicial standards
for acceptable market-based rates. We
address below the specific arguments
raised on rehearing.
413. We reject Consumer Advocates’
argument that the Commission’s marketbased rate program delegates to others
the determination of lawful rates
because it allows buyers and sellers to
negotiate rates. The Commission, and no
one else, undertakes the up-front
analysis described above that a seller
lacks or has mitigated market power and
thus pre-determines that future rates
charged by the seller will be just and
reasonable. It is the Commission, not
buyers and sellers, that makes the
determination of whether and when
negotiated rates will be lawful. It is also
the Commission, not others, that makes
a final determination with respect to
any market rules or restrictions that
must be put in place with respect to
market-based rate sellers in RTO/ISO
markets.
414. Thus, contrary to Consumer
Advocates’ claim, the Commission has
not ‘‘delegat[ed] to wholesale buyers’’
its ratemaking obligations under the
FPA.592 Consumer Advocates contend
591 See Snohomish, 471 F.3d at 1080 (in which
the Ninth Circuit discusses its decision in Lockyer).
In Snohomish, the Ninth Circuit explained, ‘‘As in
Lockyer, we do not dispute that FERC may adopt
a regulatory regime that differs from the historical
cost-based regime of the energy market, or that
market-based rate authorization may be a tenable
choice if sufficient safeguards are taken to provide
for sufficient oversight.’’ Id. at 1086.
592 Consumer Advocates Rehearing Request at 10,
12 (citing Entergy Services, Inc., 120 FERC ¶ 61,020
(2007) (Entergy), citing Louisiana, Inc. v. Louisiana
Public Service Comm., 539 U.S. 39, 43 n.1; City of

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that the Commission held that it could
not delegate to state commissions its
‘‘ratemaking obligations under the
FPA,’’ and that it could not delegate
such rate determinations to
‘‘jurisdictional utilities.’’ 593 However,
the case relied on by Consumer
Advocates is distinguishable from the
issue here. In Entergy, the Commission
denied Entergy’s petition for a
declaratory order requesting that the
Commission find that, where a resource
to be acquired or constructed by one or
more of the Entergy Operating
Companies has met certain approval
requirements, including a public
interest finding by such retail regulators
as may have jurisdiction, the resource
shall be a system resource and all costs
of such facility may be reflected in the
applicable formula rates. The
Commission concluded that there was
no local interest comparable to that
present in the cases relied on by
Entergy, and therefore denied Entergy’s
request to delegate to state commissions,
and to Entergy itself, the determination
of the reasonableness of Entergy’s
Commission jurisdictional rates.594 By
contrast, in the instant rulemaking
proceeding, the Commission is not
delegating to a state commission or to a
utility the determination of the
reasonableness of Commission
jurisdictional rates. Rather, as explained
above, in granting market-based rate
authority, the Commission exercises its
statutory responsibility under the FPA
to ensure that market-based rates are
just and reasonable through the dual
requirement of an ex ante finding of the
absence of market power and postapproval oversight through reporting
requirements and ongoing monitoring.
415. Additionally, with respect to
Consumer Advocates’ argument that the
Commission has overlooked the
economic fact that wholesale buyers/resellers do not bear the risk of loss
because the prices paid by wholesale
buyers/re-sellers ‘‘must be passed
through to retail ratepayers,’’ not only is
this argument irrelevant to whether the
Commission has legal authority to
permit market-based rates as just and
reasonable under the FPA, the argument
also is not accurate.595 It is true that
only the Commission has the authority
to determine the justness and
reasonableness of a public utility’s
wholesale rates and that a state cannot
disallow pass-through in retail rates on
New Orleans v. Entergy Corp., 55 FERC ¶ 61,211, at
61,729 (1991)).
593 Consumer Advocates Rehearing Request at 12.
594 Entergy Services, Inc., 120 FERC ¶ 61,020
(2007).
595 Id. at 10.

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the basis that it disagrees with the
Commission’s just and reasonable
determination. However, the
Commission has consistently recognized
that wholesale ratemaking does not, as
a general matter, determine whether a
purchaser has prudently chosen among
available supply options.596
416. In most circumstances ‘‘a state
commission may legitimately inquire
into whether the retailer prudently
chose to pay the FERC-approved
wholesale rate of one source, as opposed
to the lower rate of another source.’’ 597
It is in the narrow situation where the
Commission, in setting a wholesale rate,
leaves the purchaser no legal choice but
to purchase a specified amount of power
that such determinations would be
precluded.598 Thus, we reject Consumer
Advocates’ arguments that these cases
are relevant to the issue at hand.
417. We also reject Consumer
Advocates’ and NASUCA’s arguments
that the Final Rule failed to provide an
objective standard under which the
Commission can determine whether rate
increases fall within a ‘‘zone of
reasonableness.’’ 599 As part of their
argument on rehearing, they again
contend that markets alone cannot be
relied on to set just and reasonable rates.
As we explained in the Final Rule and
reiterated above, the courts have
sustained the Commission’s finding that
596 See Philadelphia Electric Co., 15 FERC
¶ 61,264, at 61,601 (1981); Pennsylvania Power &
Light Co., 23 FERC ¶ 61,006, order on reh’g, 23
FERC ¶ 61,325, at 61,716 (1983) (‘‘We do not view
our responsibilities under the Federal Power Act as
including a determination that the purchaser has
purchased wisely or has made the best deal
available.’’); Southern Company Service, 26 FERC
¶ 61,360, at 61,795 (1984); Pacific Power & Light
Co., 27 FERC ¶ 61,080, at 61,148 (1984); Minnesota
Power & Light Co., 43 FERC ¶ 61,104, at 61,342–43,
reh’g denied, 43 FERC ¶ 61,502, order denying
reconsideration, 44 FERC ¶ 61,302 (1988); Palisades
Generating Co., 48 FERC ¶ 61,144, at 61,574 and
n.10 (1989).
597 Pike County Light & Power Co. v.
Pennsylvania Public Utility Comm’n, 465 A.2d 735,
738 (1983) (Pike County) (finding that while the
state cannot review the reasonableness of the
wholesale rate set by the Commission, it may
determine whether it is in the public interest for the
wholesale purchaser whose retail rates it regulates
to pay a particular price in light of its alternatives).
The Supreme Court’s decisions in Nantahala, 476
U.S. 953 and Mississippi Power & Light Co. v.
Mississippi ex rel. Moore, 487 U.S. 354 (1988) do
not preclude, in every circumstance, state regulators
from reviewing the prudence of a utility’s
purchasing decisions. See, e.g., Kentucky West
Virginia Gas Co. v. Pennsylvania Public Utility
Comm’n, 837 F.2d 600, 609 (3d Cir.) cert. denied,
488 U.S. 941 (1988) (Kentucky West Virginia);
Doswell Limited Partnership, 50 FERC ¶ 61,251, at
61,758 n.18 (1990).
598 Nantahala, 476 U.S. 953; Mississippi Power &
Light Co. v. Mississippi ex rel. Moore, 487 U.S. 354
(1988) (Mississippi Power).
599 Consumer Advocates cite several court cases
in support of their argument in this regard. We
address these cases in detail below.

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market-based rates are one method of
setting just and reasonable rates under
the FPA.600 Before granting a seller
market-based rate authority, the
Commission requires the seller to
demonstrate that it and its affiliates lack
or have adequately mitigated market
power in relevant markets. The
Commission undertakes a complete
analysis of the seller’s horizontal and
vertical market power in the relevant
markets and permits negotiated rates
only if the seller demonstrates that it
lacks or has mitigated market power.
While this is not the same ‘‘objective
standard’’ as cost-of-service ratemaking,
which calculates the seller’s costs and
determines a specific rate of return, it
nevertheless provides an objective
standard for analyzing a seller’s ability
to exercise market power and thus
determine whether rates will fall within
a zone which is not excessive to
customers and which allows the seller
a reasonable opportunity to recover
costs and earn a reasonable rate of
return. In addition, the Commission
does not rely on the market without
adequate oversight. It has adopted filing
requirements (EQRs and change in
status filings for all market-based rate
sellers and regularly scheduled updated
market power analyses for all Category
2 market-based rate sellers), market
manipulation rules, and enhanced
market oversight through its
enforcement division to help oversee
potential market manipulation.601 This
approach, combined with the
opportunity for interested parties to file
complaints pursuant to FPA section
206, allows us to ensure that marketbased rates remain just and reasonable.
On this basis, we conclude that the rates
charged pursuant to the Commission’s
market-based rate program fall within
the ‘‘zone of reasonableness.’’ 602
418. Further, as explained in the Final
Rule, we believe that the market-based
rate program fully complies with
judicial precedent.603 In Lockyer, the
Ninth Circuit cited with approval the
Commission’s dual requirement of an ex
ante finding of the absence of market
power and sufficient post-approval
reporting requirements and found that
600 Lockyer, 383 F.3d at 1013; Snohomish, 471
F.3d at 1080; see also LEPA, 131 F.3d at 370.
601 Order No. 697 at P 952, 967.
602 See Public Service Company of Indiana,
Opinion No. 349, 51 FERC ¶ 61,367 at 62,226
(determining that market-based rate pricing resulted
in rates that were within the zone of reasonableness
and concluding that such pricing resulted in just
and reasonable rates), order on reh’g, Opinion No.
349–A, 52 FERC ¶ 61,260, clarified, 53 FERC
¶ 61,131 (1990), dismissed, Northern Indiana Public
Service Company v. FERC, 954 F.2d 736 (D.C. Cir.
1992).
603 Id. P 943–955.

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the Commission did not rely on market
forces alone in approving market-based
rate tariffs.604 In Snohomish, the Ninth
Circuit again determined that the initial
grant of market-based rate authority,
together with ongoing oversight and
timely reconsideration of market-based
rate authorization under section 206 of
the FPA, enables the Commission to
meet its statutory duty to ensure that all
rates are just and reasonable.605
419. We disagree with Consumer
Advocates’ argument that the ‘‘Final
Rule also fails to explain how FERC,
which is not an antitrust agency, acting
under the FPA, which is not an antitrust
statute but a rate filing regulatory
statute, can rely entirely on FERC’s oftchanging antitrust analyses regarding
‘market power’ to determine whether
‘market-based rates’ are within a zone of
reasonableness.’’ 606 As explained in the
section of the Final Rule addressing the
Commission’s horizontal market power
analyses,607 when the Commission
determines whether an applicant may
sell wholesale electric power at marketbased rates, it evaluates whether a seller
lacks, or has adequately mitigated,
market power in a particular market.
When the Commission determines that
a seller lacks both horizontal and
vertical market power, it is making a
determination that the resulting rates
will be established through competitive
forces, not the exercise of market power.
Thus, rates resulting from competitive
forces will not be excessive to customers
and will allow the seller the opportunity
to earn a fair return. As we explained in
the Final Rule and reiterate above, the
courts have sustained the Commission’s
finding that market-based rates are one
method of setting just and reasonable
rates under the FPA. Further, market
monitoring by both the RTO/ISO market
monitors and by the Commission help
ensure that rates remain within a zone
of reasonableness. Thus, we reject
Consumer Advocates’ argument that the
Commission has failed to explain how
it ‘‘determine[s] whether ‘market-based
rates’ are within a zone of
reasonableness.’’
420. We also reject Consumer
Advocates’ contention that the Final
Rule erroneously relied on NGA cases
and Interstate Commerce Act oil
pipeline cases. The most recent court
cases affirming the Commission’s
market-based rate authority under the
FPA cite to the very same NGA and
Interstate Commerce Act oil pipeline
cases that the Commission discusses in
604 Lockyer,

383 F.3d at 1013.
471 F.3d at 1080.
606 Consumer Advocates Rehearing Request at 13.
607 See, e.g., Order No. 697 at P 62–79.
605 Snohomish,

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25893

the Final Rule.608 It is settled law that
market-based rates can satisfy the just
and reasonable standard of the FPA, as
most recently affirmed by the Ninth
Circuit in Lockyer and Snohomish.609
The court in Lockyer expressly denied a
‘‘facial challenge to market-based [rate]
tariffs.’’ 610 Further, the Lockyer court’s
analysis of the Commission’s marketbased rate authority acknowledged that
the use of market-based tariffs was first
approved by the courts as to sellers of
natural gas in Elizabethtown Gas, then
as to wholesale sellers of electric energy
in LEPA.611 The Lockyer court also cited
the Supreme Court’s determination in
Mobil Oil Exploration that ‘‘the just and
reasonable standard does not compel
the Commission to use any single
pricing formula * * *.’’ 612
Additionally, Elizabethtown Gas, a
decision wherein the D.C. Circuit
determined that markets were
sufficiently competitive to preclude a
pipeline from exercising market power
to assure that prices were just and
reasonable within the meaning of NGA
section 4, was relied on by the D.C.
Circuit in LEPA, a case in which the
court affirmed the Commission’s
approval of an application by CLECO to
sell electric energy at market-based rates
under the FPA.613 Accordingly, we find
that the Commission did not err in
citing NGA and Interstate Commerce
Act oil pipeline cases in the Final Rule.
421. We also reject Consumer
Advocates’ argument that the Final Rule
incorrectly cites cases supporting the
proposition that ‘‘[c]ases under the NGA
and FPA are typically read in pari
materia’’ because this language refers to
the filing and rate review provisions of
the two statutes, not the different cost
elements of the electric and natural gas
industries.614 Sierra and ArkansasLouisiana Gas Co. v. Hall,615 are
correctly cited by the Final Rule for the
proposition that cases under the NGA
and FPA are typically read in pari
materia. The Final Rule noted this
proposition in its discussion of Texaco,
a case in which the Supreme Court held
that the NGA permits the indirect
regulation of small-producer rates;
however, in citing this proposition, the
608 Order No. 697 at P 953; see Lockyer, 383 F.3d
at 1011–1014.
609 Lockyer, 383 F.3d at 1013; Snohomish, 471
F.3d at 1080.
610 Lockyer, 383 F.3d at 1013.
611 Id. at 1012 (citing Elizabethtown Gas, 10 F.3d
at 870; LEPA, 141 F.3d at 365).
612 Id. (citing Mobil Oil Exploration, 498 U.S. at
224).
613 LEPA, 141 F.3d at 365 (citing Elizabethown
Gas, 10 F.3d at 870).
614 Consumer Advocates Rehearing Request at 19
(citing Order No. 697 at P 946, n.1070).
615 453 U.S. 571, 578 n.7 (1981).

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Final Rule did not claim that the cost
elements of the electric and natural gas
industries are the same. Further, the
Final Rule clearly explained that Texaco
may be distinguished from the marketbased rate regime set forth in the Final
Rule, stating ‘‘[i]n the market-based rate
program adopted in this rule and
through other Commission actions,
unlike the situation in Texaco, the
Commission is not relying solely on the
market, without adequate regulatory
oversight, to set rates.’’ 616 Accordingly,
Consumer Advocates’ argument that the
citation in the Final Rule to Sierra and
Arkansas-Louisiana Gas Co. v. Hall is
incorrect disregards the context in
which these cases were cited.
422. We find Consumer Advocates’
argument that the market-based rate
regime gives plant owners an incentive
to keep power supplies tight to raise
their profits to be without merit. The
two indicative horizontal market power
screens, each of which serves as a crosscheck on the other to determine whether
sellers possess market power, take into
account the availability of generating
capacity. In particular, the first screen,
the wholesale market share screen,
measures for each of the four seasons
whether a seller has a dominant
position in the market based on the
number of megawatts of uncommitted
(available generation) capacity owned or
controlled by the seller as compared to
the uncommitted capacity of the entire
relevant market.617 The second screen is
the pivotal supplier screen, which
evaluates the potential of a seller to
exercise market power based on
uncommitted capacity at the time of the
balancing authority area’s annual peak
demand. This screen focuses on the
seller’s ability to exercise market power
unilaterally and examines whether the
market demand can be met absent the
seller during peak times.618
423. If there is not sufficient
competing uncommitted capacity, a
seller fails the pivotal supplier analysis,
which creates a rebuttable presumption
of market power.619 Thus, through the
use of the indicative horizontal market
power screens, the Commission ensures
that market-based rate sellers are not
able to exercise market power and
thereby should ensure that there is no
incentive for plant owners to keep
power supplies tight.620
616 Order

No. 697 at P 952.
P 34 (citing April 14 Order, 107 FERC
¶ 61,018 at P 100).
618 Id. P 35.
619 Id. P 65.
620 Consumer Advocates cite the Commission’s
decision in Richard Blumenthal v. ISO New
England, Inc., 117 FERC ¶ 61,038 (2006), reh’g
denied, 118 FERC ¶ 61,205 (2007) (Blumenthal) to

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424. Additionally, as a condition of
obtaining and retaining market-based
rate authority, a seller must 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. Thus, if a market-based
rate seller acquires ownership or control
of generation capacity that results in a
net increase of 100 MW or more, or of
inputs to electric power production, or
ownership, operation or control of
transmission facilities, or affiliation
with any entity not disclosed in the
application for market-based rate
authority that owns or controls
generation or transmission facilities or
inputs to electric power production, the
seller must report the change to the
Commission so that the Commission
may re-evaluate whether the seller is
able to exercise market power.621
425. We reject Industrial Customers’
argument that the Final Rule does not
reflect reasoned decision-making
because the Commission did not find
the existence of a competitive market
before relying on market-based rate
authority. Under the FPA, the
Commission is not bound to a particular
ratemaking methodology in setting rates
as long as rates fall within a zone of
reasonableness,622 i.e., the rates are
neither less than compensatory to the
seller nor excessive to the consumer.623
In addition, the ‘‘zone of
reasonableness’’ may take into account
all relevant public interests, both
existing and foreseeable.624 These
support their statement that ‘‘in the Connecticut
complaint against the ISO New England, the
Complaint showed that excessive rates of return
were being made, but the Commission found this
‘not relevant.’ ’’ Consumer Advocates Rehearing
Request at 19. Consumer Advocates’ argument in
this regard is not clear because they do not explain
how the fact-specific determinations made by the
Commission in addressing the section 206
complaint at issue in Blumenthal relate to the
Commission’s policy of granting market-based rate
authority to sellers without market power under the
terms and conditions set forth in the Final Rule. In
Blumenthal, the Commission denied a complaint
filed against the ISO New England upon concluding
that the complainants had not met their burden
under section 206 to establish that the current
provisions of the ISO New England’s Market Rule
1 were unjust and unreasonable.
621 18 CFR 35.42.
622 FPC v. Hope Natural Gas, 320 U.S. 591, 602
(1944) (‘‘[u]nder the statutory standard of ‘just and
reasonable’ it is the result reached not the method
employed which is controlling’’); Permian, 390 U.S
at 776–777 (‘‘rate-making agencies are not bound to
the service of any single regulatory formula; they
are permitted, unless their statutory authority
otherwise plainly indicates, ‘to make the pragmatic
adjustments which may be called for by particular
circumstances,’ ’’ citing FPC v. Natural Gas Pipeline
Co., 315 U.S. 575, 586 (1942)).
623 Bluefield, 262 U.S. at 692–93 (1923).
624 Farmers Union, 734 F.2d at 1501 (citing
Permian, 390 U.S. at 790 (‘‘Congress delegated

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public interests may appropriately
include non-cost factors, such as the
need to stimulate additional
investment.625 In permitting marketbased rates in its regulation of electric
markets, there are two approaches the
Commission has used to ensure that
rates are just and reasonable: Either a
finding that an individual seller and its
affiliates lack or have mitigated market
power in a particular market; or a
finding that a particular market is
competitive or yields competitive
results. Since the mid-1980’s, the
Commission’s approach in the electric
area has been primarily to rely on an
analysis of individual seller market
power, as was recently affirmed in the
Final Rule. In addition, with regard to
rates for sales within RTO/ISOs, even if
sellers have been found to lack market
power on an individual seller basis, the
Commission has relied on a blend of
market and cost-based elements, e.g.,
some form of cost cap or mitigated bids,
to ensure just and reasonable rates.626
426. The Commission has previously
considered a similar argument (that the
Commission must find that a market is
competitive before it can permit marketbased rates) with regard to the Midwest
ISO (MISO), and rejected it. We stated:
The Commission rejects MISO Industrial
Customers’ argument that, as a prerequisite to
reliance upon market-based rate pricing to
produce just and reasonable rates, the
ratemaking authority to FERC in broad terms.
Accordingly, ‘the breadth and complexity of the
Commission’s responsibilities demand that it be
given every reasonable opportunity to formulate
methods of regulation appropriate for the solution
of its intensely practical difficulties’ ’’)).
625 While the court in Farmers Union found that
the Commission had failed to demonstrate that its
ruling in the underlying orders would, in fact,
stimulate new investment, the court acknowledged
that such ‘‘non-cost factors may legitimate a
departure from a rigid cost-based approach.’’
Farmers Union, 734 F.2d at 1502 (citing FERC v.
Pennzoil Producing Co., 439 U.S. at 518; Mobil Oil
Corp. v. FPC, 417 U.S. at 308).
626 See Order No. 697 at P 952. At the time the
Commission approved the tariffs for ISO New
England, the New York Independent System
Operator, and PJM, it applied mitigation procedures
in markets administered by those organizations, and
incorporated those procedures in the RTO/ISO
tariffs so as to apply to all sellers in the RTO/ISO
administered markets. See New England Power
Pool, 85 FERC ¶ 61,379 (1998); Central Hudson
Electric & Gas Corp., 86 FERC ¶ 61,062 (1999);
Atlantic City Electric Co., 86 FERC ¶ 61,248 (1999).
See also AEP Power Marketing, Inc., 109 FERC
¶ 61,276 (2004), reh’g denied, 112 FERC ¶ 61,320,
at P 23 (2005) (after finding that AEP passed the
generation market power screening test in PJM, the
Commission also noted that ‘‘RTOs such as PJM
with Commission-approved market monitoring and
mitigation provide a check on the exercise of
generation market power’’), aff’d sub nom.
Industrial Energy Users-Ohio v. FERC, No. 05–1435,
2007 U.S. App. LEXIS 3661, at *2 (D.C. Cir. Feb.
16, 2007) (noting that ‘‘the Commission adequately
considered and responded to petitioner’s
arguments’’) (unpublished).

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Commission must, in addition to finding that
applicants lack or have adequately mitigated
market power, make a separate and
independent finding that a competitive
market exists. * * * We * * * incorporate
by reference the Commission’s discussion in
its final rule on market-based rates (Order
No. 697 [at P 943–71]) of the legality of its
approach to market-based rates. The
Commission’s long-established approach
involves assessing whether a seller lacks
market power, which includes an assessment
of seller-specific market power. This
approach, combined with the Commission’s
filing requirements and ongoing monitoring,
allows the Commission to ensure that
market-based rates remain just and
reasonable. Additionally, for sellers in RTO/
ISO organized markets, the Commission has
in place market monitoring and mitigation
rules to mitigate the exercise of market
power, including price caps where
appropriate, and the Commission also uses
RTO/ISO market monitors to help oversee
market behavior and market conditions.
* * *627

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427. As we explained in the Final
Rule, we retained our approach to
determining whether a seller should
receive authorization to charge marketbased rates, as modified by the Final
Rule, by analyzing seller-specific market
power. We have a long-established
approach when a seller applies for
market-based rate authority of focusing
on whether the seller lacks market
power.628
428. We reject Industrial Customers’
argument that the Final Rule is
inconsistent with Farmers Union
because that case requires the
Commission to point to ‘‘empirical
proof’’ that competitive markets exist.629
The regulatory scheme at issue in
Farmers Union is distinguishable from
the Commission’s market-based rate
program. In Farmers Union, a case
concerning rates for oil pipelines, the
court found that the Commission
‘‘sought to establish maximum rate
ceilings at a level far above the ‘zone of
reasonableness’ required by the
statute.’’ 630 The court found that the
627 Midwest Independent Transmission System
Operator, Inc., 120 FERC ¶ 61,202 at P 9, 12 (2007).
628 Order No. 697 at P 955 (citing Heartland
Energy Services, Inc., 68 FERC ¶ 61,223, at 62,060–
61 (1994); Louisville Gas and Electric Co., 62 FERC
¶ 61,016, at 61,143 n.16 (1993) (and the cases cited
therein); Citizens Power & Light Corp., 48 FERC
¶ 61,210, at 61,776 & n.11 (1989); Pacific Gas and
Electric Co. (Turlock), 42 FERC ¶ 61,406, at 62,194–
98, order on reh’g, 43 FERC ¶ 61,403 (1988); Pacific
Gas and Electric Co. (Modesto), 44 FERC ¶ 61,010,
at 61,048–49, order on reh’g, 45 FERC ¶ 61,061
(1988). See also, e.g., LEPA, 141 F.3d at 365;
Consumers Energy Co., 367 F.3d 915, 922–23 (D.C.
Cir. 2004) (upholding Commission orders granting
market-based rate authority, noting that the
Commission’s longstanding approach is to assess
whether applicants for market-based rate authority
do not have, or have adequately mitigated, market
power); Lockyer, 383 F.3d at 1012–1013.
629 Industrial Customers Rehearing Request at 7.
630 Farmers Union, 734 F.2d at 1501.

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Commission departed from established
ratemaking principles when the
Commission determined that oil
pipeline rate regulation should ‘‘protect
against only ‘egregious price
exploitation and gross abuse’ ’’ by the
regulated pipelines,631 since ‘‘the cost of
pipeline transportation, relative to the
price of oil, had become so insignificant
that close regulation was not
required.’’ 632 The court found error in
the Commission’s approach, finding that
there was ‘‘only anecdotal evidence of
intermodal competition on certain
pipeline routes[,]’’ 633 and noted that the
Commission’s ‘‘evaluation of
competition in the oil pipeline industry
is not entirely clear.’’ 634 The court
concluded that ‘‘the fundamental flaw
in the Commission’s scheme’’ was that
‘‘nothing in the regulatory scheme itself
acts as a monitor to see if [actual prices
are driven back down into the zone of
reasonableness] or to check rates if
[prices are not driven down].635 In this
regard, the court also explained that:
In setting extraordinarily high price
ceilings as a substitute for close regulation,
FERC assumed that, with the wide exposed
zone between the ceiling and the ‘true’
market rate, existing competition would
ensure that the actual price is just and
reasonable. Without empirical proof that it
would, this regulatory scheme, however, runs
counter to the basic assumption of statutory
regulation, that ‘Congress rejected the
identity between the ‘true’ and the ‘actual’
market price.’ 636

Thus, the court found that the
fundamental flaw in the Commission’s
regulatory scheme in Farmers Union
was that there was no monitoring.
429. The Farmers Union court found
that the Commission’s ‘‘largely
undocumented reliance on market
forces as the principal means of rate
regulation’’ was misplaced.637 In this
regard, it noted that ‘‘when Congress
amended the Interstate Commerce Act
to account for competition in the rail
carrier industry, the amendment
required the ICC to make a specific
finding that a particular rail carrier did
not have ‘market dominance’ before
deregulating the carrier. * * * We do
not believe that the unamended oil
pipeline rate provisions of the Interstate
Commerce Act, which do not make any
provision for deregulation, would
require any less of a particularized
showing before competition might be
631 Id. at 1502 (citation omitted; emphasis
supplied by court).
632 Id. at 1507.
633 Id. at 1509.
634 Id. n.50.
635 Id. at 1509 (citation omitted).
636 Id.
637 Id.

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at 1508 (footnote omitted).

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25895

properly taken into account.’’ 638 The
court nonetheless concluded that ‘‘ ‘noncost’ factors may play a legitimate role
in the setting of just and reasonable
rates.’’ 639 It also found that ‘‘[m]oving
from heavy to lighthanded regulation
within the boundaries set by an
unchanged statute can, of course, be
justified by a showing that under
current circumstances the goals and
purposes of the statute will be
accomplished through substantially less
regulatory oversight.’’ 640
430. The defects that the court found
to be present in the regulatory scheme
under review in Farmers Union are not
present in the Commission’s marketbased rate program. As an initial matter,
in the case under review in Farmers
Union, the Commission had not
undertaken any analysis of the sellers
participating in the oil pipeline industry
as part of its decision to adopt a generic
ratemaking methodology to be applied
to all oil pipelines. Unlike Farmers
Union, before granting a seller marketbased rate authority, the Commission
performs an initial evaluation to
determine whether the seller or any of
its affiliates has horizontal or vertical
market power and, if so, whether such
market power has been mitigated. The
Commission only permits a seller to use
market-based rate pricing if the
Commission finds that the seller lacks,
or has adequately mitigated, market
power in the relevant market.
431. Similarly, unlike Farmers Union,
where the court identified as a
‘‘fundamental flaw’’ the absence of any
monitoring to ensure that rates remain
within a zone of reasonableness, the
market-based rate program does not rely
solely on the market, without adequate
regulatory oversight, to determine rates.
Rather, the market-based rate program
includes post-approval oversight
through reporting requirements and
ongoing monitoring. In addition, market
monitoring by the Commission helps
ensure that rates remain within a zone
of reasonableness.641 Thus, the
Commission’s market-based rate
program does not contain the defects
that the court found to be present in
Farmers Union,642 and is not arbitrary
638 Id.

at n. 50.
at 1503.
640 Id. at 1510.
641 On this basis, we find State AGs and
Advocates’ reliance on Farmers Union to support
their argument that the Final Rule failed to provide
a standard under which the Commission can
determine whether rate increases fall within a
‘‘zone of reasonableness’’ to be misplaced.
642 See Midwest Independent Transmission
System Operator, Inc., 120 FERC ¶ 61,202, at P 9,
12 (2007); PJM Interconnection, L.L.C., 121 FERC
¶ 61,173, at P 22 (2007).
639 Id.

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and capricious because, contrary to
Industrial Customers’ assertions, under
the market-based rate program the
Commission performs an initial
evaluation of all sellers before granting
market-based rate authority, and
because the market-based rate program
includes adequate oversight and
monitoring.
432. Industrial Customers contend
that the Final Rule is inconsistent with
the Commission’s decision in Southwest
Power Pool, Inc. (SPP) where the
Commission made a finding that the
market was competitive before
approving market-based rates for an
energy imbalance service.643 In SPP, the
Commission found that the SPP
imbalance market is competitive in the
absence of transmission constraints, and
that SPP’s mitigation measures and
monitoring plan are sufficient to protect
customers from the exercise of market
power that might occur in the energy
imbalance market when transmission
constraints bind.644 We reject Industrial
Customers’ contention that the
Commission may only grant marketbased rate authorization if it first
analyzes whether a competitive market
exists. As explained above, the
Commission has discretion 645 to rely on
an analysis of individual seller market
power, as was affirmed in the Final
Rule, and the courts have upheld this
approach.646 Our use of this approach
for SPP does not require its use
elsewhere. At the same time, the
Commission will allow RTO/ISOs to
conduct market power studies that the
RTO/ISO members can rely on in their
market power filings, which will help
ensure the accuracy and consistency of
data.
433. With regard to Industrial
Customers’ contention that there are
market power issues prevalent in the
PJM, Midwest ISO, Southwest Power
Pool, and ISO New England markets, we
find that such issues are beyond the
scope of this proceeding. The instant
rulemaking proceeding codifies and
revises the Commission’s standards for
market-based rates and streamlines the
administration of the market-based rate
program; however, this rulemaking is
643 116 FERC ¶ 61,289, at P 30 (2006), appeal
pending sub nom., Southwest Indus. Customer
Coalition v. FERC, No. 06–1390, et al. (D.C. Cir.
Nov. 27, 2006).
644 Id.
645 See e.g., Exxon Co., USA v. FERC, 182 F.3d
30, 37–38 (D.C. Cir. 1999) (stating that where ‘‘the
analysis to be preformed ‘requires a high level of
technical expertise, we must defer to the informed
discretion of the responsible federal agencies.’ ’’)
(internal citation omitted); Oxy USA, Inc. v. FERC,
64 F.3d 679, 690–91 (D.C. Cir. 1995).
646 Lockyer, 383 F.3d at 1013; Snohomish, 471
F.3d at 1080; LEPA, 141 F.3d at 370.

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not intended to evaluate market power
issues with regard to particular markets
throughout the United States.
2. Consistency of Market-Based Rate
Program With FPA Filing Requirements
a. Whether the Multiple Layers of Filing
and Reporting Requirements
Incorporated into the Market-Based Rate
Program Provide Adequate Protection
from Excessive Rates
Final Rule
434. In rejecting Consumer Advocates’
arguments that the Commission’s
market-based rate program fails to
comply with the FPA,647 the
Commission pointed out in the Final
Rule that the FPA requires that every
public utility file with the Commission
‘‘ schedules showing all rates and
charges for any transmission or sale
subject to the jurisdiction of the
Commission,’’ but it explicitly leaves
the timing and form of those filings to
the Commission’s discretion.648 The
Commission noted that the courts have
recognized the Commission’s discretion
in establishing its procedures to carry
out its statutory functions.649 The
Commission explained that the marketbased rate tariff, with its appurtenant
conditions and requirement for filing
transaction-specific data in EQRs, is the
filed rate.650
435. The Commission also disagreed
with Consumer Advocates’ arguments
that the Commission failed to show how
competitive market-based rates are just
and reasonable and not unduly
discriminatory or preferential, stating
‘‘the standard for judging undue
discrimination or preference remains
what it has always been: Disparate rates
or service for similarly situated
customers.’’ 651 The Commission
explained that rates do not have to be
set by reference to an accounting cost of
service to be just, reasonable and not
unduly discriminatory, stating that
when the Commission determines that a
seller lacks market power, it is making
a determination that the resulting rates
will be established through competition,
647 Order

No. 697 at P 959.
(quoting 16 U.S.C. 824d(c)).
649 Id. P 960 (citing Lockyer, 383 F.3d at 1013;
Wabash Valley Power Association v. FERC, 268
F.3d 1105, 1115 (D.C. Cir. 2001), Environmental
Action v. FERC, 996 F.2d 401, 407–08 (D.C. Cir.
1993)).
650 Id. P 961. The Commission further noted that
it has held that if every service agreement under a
previously-granted market-based rate authorization
had to be filed prior to approval, then the original
market-based rate authorization would be a
pointless exercise. Id. (citing GWF Energy LLC, 98
FERC ¶ 61,330, at 62,390 (2002)).
651 Id. P 963 (citing Southwestern Electric
Cooperative, Inc. v. FERC, 347 F.3d 975, 981 (D.C.
Cir. 2003)).
648 Id.

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not the exercise of market power. The
Commission also explained that courts
have upheld the Commission’s
determinations that rates that are
established in a competitive market can
be just, reasonable and not unduly
discriminatory.652
436. In the Final Rule, the
Commission disagreed with Consumer
Advocates’ argument that the marketbased rate program eliminates the
statutory mandate that all rate increases
be noticed by filing 60 days in advance
and, if warranted, suspended for up to
five months, set for hearing with the
burden of proof on the seller, and made
subject to refund pending the outcome
of the hearing.653 The Commission
explained that it has developed a
thorough process to evaluate the sellers
that it authorizes to enter into
transactions at market-based rates.654
Under the market-based rate program,
the rate change is initiated when a seller
applies for authorization of marketbased rate pricing. All applications are
publicly noticed, entitling parties to
challenge a seller’s claims. At that time,
there is an opportunity for a hearing,
with the burden of proof on the seller
to show that it lacks, or has adequately
mitigated, market power, and for the
imposition of a refund obligation.655
Additionally, if a seller is granted
market-based rate authority, it must
comply with post-approval reporting
requirements, including the quarterly
filing of transaction-specific data in
EQRs, change in status filings for all
sellers, and regularly-scheduled
updated market power analyses for
Category 2 sellers.656 In the Final Rule
the Commission explained that it may,
based on its review of EQR filings or
daily market price information,
investigate a specific utility or
anomalous market circumstances to
determine whether there has been any
conduct in violation of RTO/ISO market
rules or Commission orders or tariffs, or
any prohibited market manipulation,
and take steps to remedy any violations.
These steps could include, among other
things, disgorgement of profits and
refunds to customers if a seller is found
to have violated Commission orders,
tariffs or rules, or a civil penalty.657
Requests for Rehearing
437. Consumer Advocates contend in
their request for rehearing that the Final
652 Id. (citing Lockyer, 383 F.3d at 1012–13; Tejas
Power Corp. v. FERC, 980 F.2d 998, 1004 (D.C. Cir.
1990)).
653 Id. P 962.
654 Id.
655 Id.
656 Id.
657 Id. P 964.

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
Rule failed to provide a standard for
determining prohibited undue
preference or discrimination under the
Commission’s market-based rate
regime.658 In particular, Consumer
Advocates argue that the traditional
FPA section 205(b) standard has no
apparent application to market-based
rates because such rates, by definition,
are allowed to be any rate for any
service on which the seller and buyer
agree, regardless of the relation of such
prices or services to any other marketbased rate or service.659 Consumer
Advocates assert that the Final Rule
relies on buyers to negotiate nonexcessive rates, and if the buyer is an
affiliate or a competitor, the rationale
supporting the idea that disinterested
sellers and buyers will negotiate nondiscriminatory rates, disappears
altogether.660 They also argue that the
Final Rule does not provide a reason for
why long-term affiliate sales service
agreements should not be filed.661
Consumer Advocates further argue that
the Final Rule erred in assuming that
the Commission’s statutory role is to
protect electricity markets, regardless of
the impact on consumers.662 They argue
that the FPA was enacted to protect
consumers from the market,663 and that
mere market incentives alone cannot be
relied upon to protect the public
interest.
438. Consumer Advocates contend
that the Final Rule erred in finding that
the Commission has legal authority to
eliminate the Congressionally-mandated
consumer protections of FPA section
205(e).664 Specifically, they argue that
the Final Rule continues to effectively
define rate increases out of existence by
claiming that none occur, and in so
doing, eliminates the FPA-mandated
prior rate filings and review of rate
increases required by section 205(d).665
Consumer Advocates argue that this
definitional ploy eliminates both the
Commission’s and the consumers’
ability to exercise their statutory rights
under section 205(e) applying to rate
increases, including the opportunity for
suspension of excessive rates, hearings
with the burden of proof on sellers to
justify rate increases and with

immediately effective refund with
interest obligations for consumers who
are found to have paid excessive
rates.666 Consumer Advocates contend
that neither the Commission nor any
court has the legal authority to gut these
statutory protections for consumers
against excessive rates, and the Final
Rule erred in claiming such authority
for either court or agency.667
439. Consumer Advocates argue that
because rate increase filings are
controlled by a different FPA provision,
the Final Rule erred in relying on the
Commission’s discretion as to the form
and timing of filings of initial rates as
legal justification for eliminating prior
filings of rate increases under marketbased rate tariffs. They assert that the
Final Rule relied on the Commission’s
discretion under section 205(c) as to the
form and timing of rate schedule filings
to legally justify eliminating the FPAmandated filing of specific rates and
rate increases, yet insisted that the filing
of market-based rate tariff authorizations
is a ‘‘change’’ in rate, and the filing of
subsequent actual charges are merely
filings in satisfaction of Commissioncreated ‘‘ ‘reporting requirements.’ ’’ 668
Consumer Advocates also contend that
one serious flaw in this argument is that
section 205(d), not section 205(c),
controls ‘‘’changes’’’ in rates, and
section 205(d) does not offer the same
discretion as to the form and timing of
rate increase filings.669
440. Consumer Advocates contend
that the market-based rate tariff
authorization application would be, as a
change in rate, subject to section 205(d),
not section 205(c). They argue that the
relied-upon discretion provided does
not apply to any market-based rate,
because under the legal logic of the
Final Rule there never are any initial
market-based rates filed.670 According
to Consumer Advocates, the Lockyer
decision also relied erroneously on the
Commission’s discretion under section
205(c) as authority to approve the
Commission’s elimination of section
205(d) prior filings of rate changes.671
Consumer Advocates conclude that the
Final Rule erred insofar as: (1) It failed
666 Id.

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658 Consumer

Advocates Rehearing Request at 14
(citing 16 U.S.C. 824d(b)).
659 Id.
660 Id. at 15.
661 Id.
662 Id. at 21–22.
663 Id. at 22 (citing Atlantic Ref. Co. v. Pub. Serv.
Comm’n of State of N.Y., 360 U.S. 378, 388 (1959);
United Gas Pipe Line Co. v. Mobile Gas Service
Corp., 352 U.S. 332 (1956) (United Gas Pipe Line);
Sierra; Electrical District No. 1 v. FERC, 774 F.2d
490 (D.C. Cir. 1985) (Electrical District).
664 Id.
665 Id.

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667 Id.
668 Id.

at 23 (citing Order No. 697 at P 960; 962–

63).
669 Id.

at 23–24.
at 24 (citing Lockyer, 383 F.3d at 1013;
Order No. 697 at P 960). Consumer Advocates state
that section 205(d) requires that all rate increases
and other changes in rates or charges must be filed
60 days in advance of being charged, unless the
Commission for good cause issues an order
‘‘specifying the changes’’ to be made to the rates
and charges, and specifying ‘‘the time when the
change or changes will go into effect.’’ Id.

25897

to explain how the Commission’s
market-based rate authorization orders
satisfy these plain requirements of
section 205(d), which must apply to
market-based rate tariff authorizations,
as ‘‘changes’’ in rates; (2) market-based
rate authorizations fail to specify either
a change in the amounts to be charged
or the time when such new charges will
go into effect; and (3) all subsequent
actual increases in charges under the
market-based rate tariff, according to the
Final Rule’s logic, are not changes in the
rate, but merely reports, or EQRs, no
matter how dramatically actual prices
increase.672
441. Consumer Advocates contend
that the Final Rule claimed that the
Commission can suspend the use of
market-based rate tariffs when they are
first filed, but does not try to justify
either the consumer-protection rationale
or the legal authority for its attempted
elimination of the Commission’s ability
to suspend all subsequent excessive rate
increases under market-based
‘‘rates.’’ 673 Consumer Advocates
contend that Lockyer acknowledges that
the Commission’s ability to suspend
excessive rate increases is lost under the
market-based rate regime, but appears to
believe that the Commission can
eliminate such protections if it so
chooses.674 Consumer Advocates state
that Lockyer does not acknowledge the
other consumer protections that are
eliminated by the Commission’s
definition of ‘‘change’’ as including
none of the specific rate charges filed as
‘‘reports.’’ They contend that loss of rate
suspensions alone eliminates 8 months
of potential consumer protection from
excessive rates: 5 months of the
Commission’s lost ability to suspend
rate increases and 3 months before the
rates are even seen in reports and can
be set for hearing under section 206.675
Consumer Advocates assert that this
result is directly contrary to Congress’
intent in the Energy Policy Act of
2005 676 to extend the filing provisions
of sections 205(c) and (d) to non-public
transmitting utilities, and to reduce the
time before section 206 rates can be
made subject to refund.677
442. NASUCA argues that the
Commission did not articulate an
adequate legal basis to support the Final
Rule’s reduced market power review
and filing requirements.678 While

670 Id.
671 Id.

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672 Id.

at 24–25.
Advocates Rehearing Request at 31.
674 Id. at 30.
675 Id. at 31.
676 Pub. L. No. 109–58, 119 Stat. 594 (2005).
677 Consumer Advocates Rehearing Request at 31
(citing 119 Stat. 594 sections 1285 and 1290(a)(2)).
678 NASUCA Rehearing Request at 17.
673 Consumer

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NASUCA notes that the Final Rule
responded to its concerns, citing the
decision of the Ninth Circuit in Lockyer
and relying on FPA section 205(c) as
authority to adjust the timing of rate
filing, 679 NASUCA contends that the
adjacent statutory language of section
FPA 205(d) limits that power.680
NASUCA argues that ‘‘[t]he ‘crucial
difference’ between impermissible
exclusive reliance on market rates found
in the Lockyer decision * * * is absent
in the revisions made in the Final
Rule.’’ 681 NASUCA also contends that
the Ninth Circuit mistakenly believed
that the Commission looks at a seller’s
market power reviews in triannual
reviews, i.e., conducted once every four
months, rather than triennial reviews,
i.e., once every three years.682 NASUCA
concludes that the actions being taken
to streamline filing requirements
eliminate market power reviews for
many sellers, and that to rely mainly on
a post hoc monitoring process does not
constitute the ‘‘bond’’ of protection
required for consumers.683
443. Consumer Advocates argue that
the Final Rule erred in failing to explain
what authority the Commission has to
eliminate the statutory remedy of
refunds of excessive charges, with
interest, under section 205(e), and
replace it with only disgorgement of
excess profits or civil penalties
whenever market manipulators are
caught.684 They contend that the Final
Rule erred in relying on the Lockyer
decision’s erroneous finding that,
because the market-based rate regime
eliminates section 205(e) refunds for
excessive charges paid, the Commission
must create and substitute a new refund
remedy to replace them.685 Consumer
Advocates assert that courts may not
rewrite statutes or direct agencies to do
so.686 They argue that the Final Rule
failed to explain (1) how Lockyer’s
curious ‘‘two wrongs make a right’’
approach is within the Ninth Circuit’s
authority, since only Congress can
change a statute, (2) how Lockyer’s new
remedy helps consumers, who are
supposed to receive refunds from
excessive charges paid, not
administrative penalties for reports that
have been omitted; and (3) how the
Lockyer decision’s remedy replaces
section 205(e)’s other eliminated
consumer protections—prior review,

suspension, and hearings with burden
of proof on the seller.687
444. Consumer Advocates also
contend that punishing manipulators, as
the Final Rule proposed to do, is fine,
but it does not make whole customers
who have paid excessive rates set in
part by those who manipulated the
market.688 They note that the Colorado
Consumers Counsel section 206
proceeding is a case in which the
Commission made the rates subject to
refund under section 206 and
subsequently found that all marketbased rate tariffs which didn’t have
behavior rules attached were unjust and
unreasonable and that the Commission
ordered no refunds, but merely added
behavior conditions to the market-based
rate tariffs prospectively.689
445. Consumer Advocates also argue
that the Final Rule erred in assuming
that the Ninth Circuit and the D.C.
Circuit are authorized to eliminate or
affirm agency elimination of statutory
consumer protections that Congress has
enacted into law.690 They state that
agencies are bound, not only by the
ultimate purposes Congress has
selected, but by the means it has
deemed appropriate and prescribed for
the pursuit of those purposes.691 They
argue that in sections 205(d) and (e) of
the FPA, Congress chose not only the
goal of consumer protection from
excessive rate increases, but also the
means—advance rate filing and review,
suspension, hearings with burden of
proof on the seller, and immediate
refund insurance—by which such
protections would be afforded.692
Consumer Advocates contend that the
Final Rule ignored the clear mandates of
the statute, and allows rate increases to
be filed three months after they are
charged, when the Commission has lost
the power to initiate section 205(e)
consumer protections.693
446. Consumer Advocates contend
that the Final Rule’s discussion of
whether the Commission can simply
eliminate any review of rate increases
under the statutory protections of FPA
section 205(e) appears to assume that
the D.C. Circuit has authorized such
elimination of section 205(e), and that
the Court has the power to do so.694
Consumer Advocates argue that the
Supreme Court found that a wholesale
seller’s major duty under the FPA is to
687 Id.

679 Id.

(citing Order No. 697 at P 953–954).
at n.16.
681 Id. at 17.
682 Id. at 18.
683 Id. (citing Order No. 697 at P 958–59).
684 Id. at 32–33.
685 Id. at 32.
686 Id. (citing MCI; Southwestern Bell).

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680 Id.

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at 33–34.
688 Id. at 33.
689 Id. (citing 97 FERC ¶ 61,220 (2001); 105 FERC
¶ 61,218 (2003); 107 FERC ¶ 61,175 (2004)).
690 Id. at 34.
691 Id. at 36 (citing MCI, 512 U.S. at 231 n.4).
692 Id.
693 Id. at 35.
694 Id. at 34 (citing Order No. 697 at P 948).

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file its rates for review by the
Commission and the public to
determine whether hearings should be
instigated under section 206, for initial
rates, or section 205, for changes in
rates.695 They assert that the Final Rule
ignored the lead cases on the FPA filing
requirement, except to quote them for
the proposition that the filing and
hearing requirements are typically read
in pari materia.696 Consumer Advocates
agree with that citation, however they
argue that the purpose of the advance
rate filings is for the Commission and
the public to review rates before they
are charged.697
447. Consumer Advocates argue that
even if the Commission had authority to
redefine rate increases as being mere
rate ‘‘reports,’’ or EQRs, the Final Rule
erred by failing to explain why the
Commission would wish to eliminate all
section 205(e) consumer protections by
adopting this definition, and how such
elimination satisfies the Commission’s
consumer protection responsibilities
under the FPA.698 They contend that the
Commission’s definition of rate
increases as never occurring under the
market-based rate regime, once a
market-based rate tariff authorization is
granted, allows the Commission to
avoid prior review of all market-based
rate increases and deprives consumers
of all the protections provided by
section 205(e).699 Consumer Advocates
note that the Final Rule’s definitional
elimination of rate ‘‘increase’’
protections is of particular importance
to consumers in Maryland, Delaware,
Illinois, Montana, Connecticut, and
Ohio, among many other states, where
retail ratepayers have been charged huge
retail rate increases resulting solely from
the pass-through of huge wholesale rate
‘‘increases.’’700 They also contend that
under the market-based rate regime as
continued in the Final Rule, such
wholesale increases have never been
and never will be reviewed by the
Commission under section 205(e) of the
FPA.701
448. Consumer Advocates also argue
that the Final Rule erred by failing to
adequately distinguish the Supreme
Court and Circuit court decisions
outlawing attempts by other regulatory
agencies to replace statutorily-mandated
specific rates with a range of rates, when
695 Id. at 34–35 (citing United Gas Pipe Line, 350
U.S. at 341–42; Sierra).
696 Id. at 35 (citing Order No. 697 at P 946,
n.1070).
697 Id.
698 Id. at 36–37 (citing 774 F.2d 490, 493).
699 Id. (citing Atlantic Richfield; Electrical
District; Lockyer, 383 F.3d at 1017).
700 Id. at 37.
701 Id.

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the market-based rate tariffs allow a
range of rates so broad as to include any
rate the parties agree to. Consumer
Advocates contend that ‘‘FERC’s claim
that the MBR’s unlimited range of rates
adequately substitutes for the ‘specific’
charges required under 205(d)’’ is not
sustainable under court precedent
applying to the FPA and to other similar
rate filing statutes.702 They argue that
the market-based rate, a statement that
the rate will be anything the parties
agree to, is even less specific than the
‘‘legal and accounting principles,’’
which the D.C. Circuit rejected in
Electrical District 703 and state that it is
instead, ‘‘no more than an invitation to
negotiate,’’ an invitation that the same
court rejected as a rate in Southwestern
Bell.704
449. Consumer Advocates contend
that in unlawfully replacing the
requirement of section 205(d) for filing
specific rate changes with a range of
rates,705 the Final Rule erred in relying
on Lockyer’s attempt to distinguish
certain cases by claiming they were
remanded by the Supreme Court
because the agency had ‘‘relied on
market forces alone.’’706 According to
Consumer Advocates, the Lockyer
decision erred in failing to recognize
that Electrical District and Southwestern
Bell found unlawful the agencies’
attempts to replace statutory
requirements to file specific rates with
‘‘ranges of rates’’ for ‘‘non-dominating’’
entities.707 Consumer Advocates also
argue that rate ranges only apply to
‘‘non-dominating’’ wholesale sellers
without market power, and that the
courts have held that it is the Congress,
not the agency, that determines what
entities must continue to be
regulated.708
450. Consumer Advocates contend
that in Regular Common Carrier
Conference v. United States, the
importance of actual rates contained in
tariffs was found to be ‘‘utterly central’’
to a rate filing statute.709 They note that
the Final Rule relied repeatedly on
LEPA, which relies on Elizabethtown
Gas, yet neither court decided the issue
of whether the market-based rate filings
702 Id. at 27 (citing Electrical District; 16 U.S.C.
824e(a)).
703 Id.
704 Id. (quoting Southwestern Bell, 43 F.3d at
1521).
705 Id. at 28.
706 Id. (citing Lockyer, 353 F.3d at 1013; Order
No. 697 at P 953).
707 Id. at 29.
708 Id. at 28–29 (citing Maislin Indus. U.S. v.
Primary Steel Inc., 497 U.S. 116 (1990) (Maislin);
MCI; Southwestern Bell)
709 Id. at 29 (citing Regular Common Carrier
Conference v. United States, 793 F.2d 376, 379 (D.C.
Cir. 1986) (Regular Common Carrier)).

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or the overall market-based rate regime
complies with the FPA.710 Consumer
Advocates also assert that the D.C.
Circuit has repeatedly refused on
procedural grounds to review the
market-based rate regime’s elimination
of rate filings and its disregard for other
section 205 mandates.711 Consumer
Advocates therefore conclude that the
law of the D.C. Circuit on rate filings
under section 206 of the FPA thus
remains the decision in Electrical
District.
451. Consumer Advocates argue that
the Final Rule erred in relying chiefly
on Lockyer for legal support for
replacing advance rate increase filings
with after-the-fact ‘‘reporting
requirements’’ and that the Ninth
Circuit panel, in turn, erroneously relied
on Commission counsel’s argument that
the market-based rate tariffs plus the
specific information on actual charges
filed pursuant to the ‘‘reporting
requirements’’ together comply with the
FPA’s requirement for filing specific
rates.712 Consumer Advocates state that
if the reporting requirement filings
contain a necessary component of the
rate, that is, the component that renders
the market-based rate specific enough to
comply with the statute, then such
reports must be filed 60 days in advance
under section 205(d), otherwise, the rate
reports must be filed as specifically
directed by a section 205(d) order so as
to allow for the full section 205(e)
review, procedures and remedies.713
They contend that the United Gas Pipe
Line/Sierra cases and City of Piqua
support this interpretation.714 Consumer
Advocates argue that under the
Commission’s ‘‘reporting requirements’’
scheme, only prospective section 206
review, hearings or refunds are possible
and that under the market-based rate
regime, rates may be increased
exponentially, yet there are never any
section 205(e) procedural protections or
remedies available to consumers
regarding whether actual rate levels fall
within a ‘‘zone of reasonableness.’’ 715
710 Id. (citing Order No. 697 at P 949–951).
Consumer Advocates contend that LEPA and
Elizabethtown Gas both explicitly state that they are
not deciding the question of whether the marketbased rate filing requirements or overall marketbased rate regime comply with the FPA. Id. at 29–
30 (citing LEPA, 141 F.3d at 366 n.2; Elizabethtown
Gas, 10 F.3d at 871).
711 Id. at 30 (citing Elizabethtown Gas; LEPA;
Power Company of America, 245 F.3d 839 (D.C. Cir.
2001); Colorado Office of Consumer Counsel v.
FERC, 490 F.3d 954 (D.C. Cir. 2007)).
712 Id. at 25 (citing Lockyer, 383 F.3d 1015).
713 Id.
714 Id. at 25–26 (citing City of Piqua v. FERC, 610
F.2d 950 (1979), quoting City of Kaukauna, 458
F.2d 731 (1971)) (City of Piqua)).
715 Id. at 26.

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25899

452. NASUCA contends that under
the Final Rule, market power review is
to be eliminated altogether for many
sellers in the Category 1 classification,
with no specific review of those sellers’
potential to exercise power.716 NASUCA
argues that there is no record in this
case to support a generic finding that a
seller with 499 MW capacity needs no
market power review and a seller of 501
MW does.717 NASUCA concludes that,
in light of the Final Rule’s reduced
requirements for market power review,
the post hoc reporting requirement is
not sufficient to protect customers.718
Commission Determination
453. As we stated in the Final Rule,
we disagree with Consumer Advocates’
arguments that the Commission failed to
show how market-based rates are just
and reasonable and not unduly
discriminatory or preferential. We reject
Consumer Advocates’ argument that the
Final Rule failed to provide a standard
for determining prohibited undue
preference or discrimination under the
Commission’s market-based rate regime.
The standard for judging undue
discrimination remains what it always
has been: disparate rates or service for
similarly situated customers.719 The
Commission has held in prior cases, and
the courts have upheld, that rates that
are established in a market where a
seller cannot exercise market power can
be just, reasonable and not unduly
discriminatory.720
454. The Final Rule does not violate
the FPA’s filing requirements. The FPA
requires that every public utility file
with the Commission ‘‘schedules
showing all rates and charges for any
transmission or sale subject to the
jurisdiction of the Commission,’’ but it
explicitly leaves the timing and form of
those filings to the Commission’s
discretion.721 Public utilities must file
‘‘schedules showing all rates and
charges’’ under ‘‘such rules and
regulations as the Commission may
prescribe,’’ and ‘‘within such time and
form as the Commission may
designate.’’ 722 Accordingly, ‘‘so long as
FERC has approved a tariff within the
scope of its FPA authority, it has broad
discretion to establish effective
716

NASUCA Rehearing Request at 18.

717 Id.
718 Id.
719 See e.g., Southwestern Electric Cooperative,
Inc. v. FERC, 347 F.3d 975, 981 (D.C. Cir. 2003).
720 See, e.g., Lockyer, 383 F.3d at 1012–13; Tejas
Power Corp. v. FERC, 908 F.2d 998, 1004 (D.C. Cir.
1990).
721 16 U.S.C. 824d(c).
722 16 U.S.C. 824d. The FPA does not define
‘‘schedules,’’ leaving that to the Commission’s
discretion as well. The Commission has defined
‘‘rate schedule’’ in its regulations at 18 CFR 35.2(b).

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reporting requirements for
administration of the tariff.’’ 723 As the
Commission explained in the Final
Rule, if a seller is granted market-based
rate authority, it must comply with postapproval reporting requirements,
including the quarterly filing of
transaction-specific data in EQRs,
change in status filings for all sellers,
and regularly-scheduled updated market
power analyses for Category 2 sellers.724
The Commission may, based on its
review of EQR filings or daily market
price information, investigate a specific
utility or anomalous market
circumstances to determine whether
there has been any conduct in violation
of RTO/ISO market rules or Commission
orders or tariffs, or any prohibited
market manipulation, and take steps to
remedy any violations. These steps
could include, among other things,
disgorgement of profits and refunds to
customers if a seller is found to have
violated Commission orders, tariffs or
rules, or a civil penalty.725
455. Additionally, in response to
arguments that the Commission cannot
or should not eliminate the triennial
filing requirement for Category 1 sellers,
as discussed above in the section on
implementation, to the extent that any
Category 1 sellers are located in a
Commission-identified submarket, we
will consider whether there is an
indication that they have market power
as we analyze the indicative screens
submitted by other sellers. If any market
power concerns arise with respect to
any such Category 1 sellers, we may
exercise our right to require the filing of
723 Lockyer,

383 F.3d at 1013.
No. 697 at P 962. The Commission
explained in the NOPR that preceded Order No.
2001 that it needed to make changes to keep abreast
of developments in the industry, and therefore
implemented the revised filing requirements in
Order No. 2001. Id. P 965–966 (citing Revised
Public Utility Filing Requirements, Notice of
Proposed Rulemaking, FERC Stats. & Regs.,
Proposed Regulations 1999–2003, ¶ 32,554, at
34,062 (2001); Revised Public Utility Filing
Requirements, Order No. 2001, FERC Stats. & Regs.
¶ 31,127, at P 31 (Order No. 2001), reh’g denied,
Order No. 2001–A, 100 FERC ¶ 61,074, reh’g
denied, Order No. 2001–B, 100 FERC ¶ 61,342,
order directing filing, Order No. 2001–C, 101 FERC
¶ 61,314 (2002), order directing filing, Order No.
2001–D, 102 FERC ¶ 61,334 (2003)). The
Commission has also issued Order No. 670, which
adopted a new rule prohibiting the employment of
manipulative or deceptive devices or contrivances
in wholesale energy and natural gas markets.
Prohibition of Energy Market Manipulation, Order
No. 670, 71 FR 4244 (Jan. 26, 2006), FERC Stats. &
Regs. ¶ 31,202 (2006), reh’g denied, 114 FERC
¶ 61,300 (2006).
725 Order No. 697 at P 964. The Commission
issued an Enforcement Policy Statement to provide
guidance to the industry on how the Commission
intends to determine remedies for violations,
including applying its new and expanded civil
penalty authority. Enforcement of Statutes, Orders,
Rules, and Regulations, 113 FERC ¶ 61,068 (2005).

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an updated market power analysis and
direct them at that time to submit one.
456. We also disagree with Consumer
Advocates’ argument that the marketbased rate program eliminates the
requirement in section 205(d) of the
FPA that, absent waiver by the
Commission, all rate increases be
noticed by filing 60 days in advance,
and the provision in section 205(e)
which permits that, if warranted, rates
be suspended for up to five months, set
for hearing with the burden of proof on
the seller, and made subject to refund
pending the outcome of the hearing.
Under the market-based rate program, a
rate change is initiated when a seller
applies for authorization of marketbased rate pricing, not when it
subsequently enters into negotiated
rates as interpreted by Consumer
Advocates. A seller must give the
requisite 60 days’ notice required by
section 205(d) before it may charge any
market-based rates. All applications are
publicly noticed, entitling affected
persons to intervene and challenge a
seller’s proposed market-based rates. At
that time, there is an opportunity for a
hearing, with the burden of proof on the
seller to show that it lacks, or has
adequately mitigated, market power,
and for the imposition of a refund
obligation.726 The Commission has
authority to suspend a request for
market-based rates, subject to refund.
Thus, contrary to Consumer Advocates’
claim, the Commission’s market-based
rate program fully complies with both
section 205(d) and section 205(e).
Indeed, under Consumer Advocates’
interpretation of the law, if taken to its
logical conclusion, the Commission
would be precluded not only from
authorizing market-based rates but also
from authorizing flexible cost-based
rates, e.g., ‘‘up to’’ rates in which sellers
are pre-authorized to sell up to a
specified cost-based rate cap. Under
their theory, there would have to be 60
days’ notice of each rate charged under
the cap (even though there was prior
notice that sales would be up to the cap)
so long as it represented a change from
the previous amount charged. And
presumably this requirement would
apply even for day-ahead or monthly
short-term sales for which it would be
impossible to give 60 days’ notice. We
simply do not read the FPA section
205(d) and (e) or the parallel NGA
section 4 provisions to hamstring the
Commission in this way. Not only does
section 205(c) provide flexibility
regarding the timing and form in which
rates shall be filed, but 205(d) allows the
726 Id.; see also 18 CFR Part 35 (filing
requirements and procedures).

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Commission to waive the 60 days’
notice by order specifying the changes
to be made and the time when they shall
take effect and the manner in which
they shall be filed and published. The
Commission’s authorization of marketbased rates (and flexible cost-based
rates) is consistent with the flexibility
allowed in section 205, and the public
has notice of the types of rates that may
be charged and the manner in which
they will be filed and published.
457. We reject arguments that the
Commission has eliminated consumer
protections under the FPA. Not only
may the public intervene in section 205
market-based rate proceedings and file
complaints under section 206 to
eliminate market-based rate
authorizations (with refund protection
up to 15 months), but the Commission
has in place a multi-part system for
monitoring rates. If a seller is granted
market-based rate authority, it must
comply with post-approval reporting
requirements, transaction-specific data
in EQRs, change in status filings for all
sellers, and regularly-scheduled
updated market power analyses for
Category 2 sellers.727 The quarterly
reports (EQRs) that sellers are required
to file, include, for each individual
purchase and sale, the names of the
parties, a description of the service, the
delivery point of the service, the price
charged and quantity provided, the
contract duration, and any other
attribute of the product being purchased
or sold that contributed to its market
value.728 That reporting requirement
provides a means for the Commission
and the public to spot pricing trends or
discriminatory patterns that might
indicate the exercise of market power.
458. The Ninth Circuit has recognized
that ‘‘FERC’s system consists of a
finding that the applicant lacks market
power (or has taken sufficient steps to
mitigate market power), coupled with a
strict reporting requirement to ensure
that the rate is ‘just and reasonable’ and
that markets are not subject to
manipulation.’’ 729 The Ninth Circuit
has explained that the reporting
requirements are ‘‘integral’’ to the
market-based rate tariff and that they,
together with the Commission’s initial
approval of market-based rate authority,
comply with the FPA’s requirements.730
Through the EQRs, the Commission has
enhanced and updated the post727 Id.

(citing Lockyer, 383 F.3d at 1016).
P 855. See also Order No. 2001, FERC
Stats. & Regs. ¶ 31,127. Required data sets for
contractual and transaction information are
described in Attachments B and C of Order No.
2001.
729 Lockyer, 383 F.3d at 1013.
730 Id. at 1015.
728 Id.

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transaction quarterly reporting filing
requirements that were in place during
the time period at issue in Lockyer.731
459. We disagree with the Consumer
Advocates’ and NASUCA’s argument
that the Final Rule erred in relying on
Lockyer for legal support. The Final
Rule correctly relied on Lockyer because
in Lockyer, the Ninth Circuit cited with
approval the Commission’s dual
requirement of an ex ante finding of the
absence of market power and sufficient
post-approval reporting requirements
and found that the Commission did not
rely on market forces alone in approving
market-based rate tariffs.732 Further, the
market-based rate requirements and
oversight adopted in the Final Rule are
more rigorous than those reviewed by
the Lockyer court.733 We find Consumer
Advocates’ and NASUCA’s argument
that in Lockyer the Ninth Circuit
erroneously relied on Commission
counsel’s argument that the marketbased rate tariffs plus the specific
information on actual charges filed
pursuant to the reporting requirements
together comply with the FPA’s filing
requirements to be without merit.
Lockyer has not been reversed, and in
fact, was followed by the Ninth Circuit
in Snohomish.734
460. Consumer Advocates misapply
United Gas Pipe Line, Sierra and City of
Piqua in arguing that these cases require
that specific sale prices must be filed ex
ante under FPA section 205(d). In
concluding that the NGA does not
empower natural gas companies
unilaterally to change their contracts in
United Gas Pipe Line, the Supreme
Court interpreted provisions of the NGA
that parallel the FPA, and it stated that
section 4(d) of the NGA says only that
‘‘a change in the filed rate cannot be
made without proper notice to the
Commission.’’ 735 That same day the
Supreme Court held in Sierra that the
FPA does not authorize unilateral
contract changes 736 and determined
that the Federal Power Commission
could not declare a rate set by a contract
to be ‘‘unreasonable solely because it
yields less than a fair return on the next
invested capital.’’ 737 In City of Piqua,
the D.C. Circuit explained that the
primary purpose of section 205(d) is to
notify the Commission of changes in
rates and schedules between parties to
a contract, stating ‘‘[a] change in rates
No. 697 at n.1105.
383 F.3d at 1013.
733 See Order No. 697 at P 953.
734 Snohomish, 471 F.3d at 1080–81.
735 United Gas Pipe Line, 350 U.S. at 339
(emphasis in original).
736 Sierra, 350 U.S. at 353.
737 Id. at 355.

cannot take place without first filing
notice with the Commission.’’ 738
461. Consumer Advocates’ argument
that United Gas Pipe Line, Sierra and
City of Piqua require that rate reports
must be filed ex ante under FPA section
205(d) overlooks the fact that, under the
market-based rate program, the rate
change is initiated when a seller applies
for authorization of market-based rate
pricing. As we explained, all
applications are publicly noticed and
affected persons are entitled to
challenge a seller’s claims. There is an
opportunity for a hearing at that time,
with the burden of proof on the seller
to show that it lacks, or has adequately
mitigated, market power, and for the
imposition of a refund obligation.739
That investigation fully satisfies the
requirements of FPA section 205(d) and
(e).
462. With regard to Consumer
Advocates’ argument that the Final Rule
erred by failing to adequately
distinguish certain Supreme Court and
Circuit case decisions, we find that
Consumer Advocates misinterpret
Electrical District, Southwestern Bell,
Maislin, MCI and Regular Common
Carrier in relying on these cases as
support for their argument that the
Commission’s market-based rate regime
is unlawful. Electrical District addressed
the issue of whether to make a rate
increase effective as of the date of its
order directing a compliance filing,
rather than upon the date of acceptance
of the compliance filing and resolved a
‘‘disagreement over what it means to
‘fix’ a rate within the meaning of
[section 206(a)] 16 U.S.C. 824e(a)’’—not
section 205(c).740 The D.C. Circuit
rejected the Commission’s ‘‘policy of
making rates effective as of the date of
an order [under section 206] setting
forth no more than the basic principles
pursuant to which the new rates are to
be calculated.’’ 741 Electrical District
holds only that the Commission cannot,
in a proceeding under section 206,
‘‘announce some formula and later
reveal that formula was to govern from
the date of announcement.’’ 742 It says
nothing about whether the Commission
can establish rules under sections 205(c)
and (d) that permit the filing and
approval of market-based rate tariffs.
463. In Southwestern Bell, the FCC
‘‘adopt[ed] a policy of permitting
nondominant common carriers to file a
range of rates as opposed to fixed rates

731 Order

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738 City

of Piqua, 610 F.2d at 953.
No. 697 at P 962; see also 18 CFR Part
35 (filing requirements and procedures).
740 774 F.2d at 492.
741 Id. at 493.
742 Transwestern Pipeline Co. v. FERC, 897 F.2d
570, 578 (D.C. Cir. 1990) (emphasis added).
739 Order

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25901

showing a schedule of charges.’’ 743 The
court held that the FCC policy violated
47 U.S.C. section 203(a), which requires
that every common carrier file
‘‘schedules showing all charges.’’ 744
That statute requires a specific list of
discernible rates, rather than a filing of
a range of possible rates.745 The
quarterly reports required under the
Final Rule require each seller to list the
terms of each transaction individually.
The transaction-specific data required in
the Commission’s quarterly reports do
not constitute a range of rates similar to
that rejected in Southwestern Bell.
464. In Regular Common Carrier, the
Interstate Commerce Commission (ICC)
approved a tariff provision under which
freight forwarders could provide
services to shippers at unpublished
rates determined by averaging prior
charges to those shippers.746 The court
found that that provision violated 49
U.S.C. section 10761(a) (1982), which
required that rates be ‘‘contained in a
tariff,’’ because the agreed-upon average
rates would never be published nor filed
with the Commission.747 The court
noted that section 10761(a) expressly
prohibited the charging of any rate
different from the tariffed rate.748 By
contrast, FPA section 205(c) permits
sellers to set rates either by tariff or by
contract, and the Commission’s marketbased rate program requires quarterly
filings providing details of all
transactions.
465. Maislin involved an ICC policy
that allowed carriers to charge privately
negotiated contract rates that differed
from the filed tariff rate, were never
disclosed or reviewed by the ICC, and
were not subject to challenge for
discrimination.749 The Supreme Court
found that the policy violated the filedrate doctrine.750 Under the Final Rule,
in contrast, market-based sales are made
in accordance with a market-based rate
umbrella tariff, approved only after the
Commission determines, in a publiclynoticed proceeding with opportunity for
interested parties to protest, that a seller
lacks market power. Further, the
Commission’s system requires quarterly
filing of the actual rates charged for
individual transactions, allowing both
the Commission and the public to view
all rates all rates charged. After marketbased rate authority is granted, affected
persons can file complaints, or the
743 43

F.3d at 1517.

744 Id.
745 Id.

at 1521.
Common Carrier, 793 F.2d at 377–78.
747 Id. at 380.
748 See id. at 379.
749 497 U.S. 116, 132–33 (1990).
750 Id. at 127.
746 Regular

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Commission can institute its own
proceeding, to challenge market-based
rates on the basis that the seller has
gained the ability to exercise market
power since the time the market-based
rates were granted or that the marketbased rates otherwise are unjust,
unreasonable, or unduly discriminatory
or preferential or to question whether a
seller has market power.
466. Consumer Advocates’ reliance on
MCI is similarly misplaced. MCI rejected
an FCC policy that relieved all nondominant carriers of any requirement to
file any of their rates with the agency.
The Supreme Court found that such
wholesale detariffing for nondominant
carriers effectively removed all rate
regulation where the FCC found
competition to exist.751 By contrast, the
market-based rate program implemented
in Order No. 697 requires every seller
with market-based rate authority to have
on file an umbrella market-based rate
tariff and to file quarterly reports
detailing the specific rates charged for
each sale. No detariffing occurs in these
circumstances. As the MCI court held, it
would not violate the filed-rate doctrine
for the FCC to ‘‘modify the form,
contents, and location of required
filings, and [to] defer filing or perhaps
even waive it altogether in limited
circumstances.’’ 752
467. Consumer Advocates’ argument
that the Commission relied repeatedly
on Elizabethtown Gas and LEPA, yet
neither court decided the issue whether
the market-based rate filings or the
overall market-based rate regime
complies with the FPA, misses the point
that the Commission cited these cases in
providing an overview of the cases
relied on in the most recent court cases
affirming the Commission’s marketbased rate authority under the FPA.753
Further, the Commission properly cited
Elizabethtown Gas for the proposition
that the use of market-based rate tariffs
was first approved by the courts as to
sellers of natural gas,754 and properly
cited LEPA for the proposition that use
of market-based rate tariffs was first
approved by the courts as to wholesale
sellers of electricity.755 In any event, as
751 512

U.S. 218, 231–32 (1994).
at 234.
753 Order No. 697 at P 944; see also, id. at 945–
953; Lockyer, 383 F.3d at 1011–1014.
754 Elizabethtown Gas, 10 F.3d at 869; see also
Order No. 697 at P 948.
755 LEPA, 141 F.3d at 365, 370; see also Order No.
697 at P 951. Consumer Advocates’ reliance on
Power Company of America, 245 F.3d 839 (D.C. Cir.
2001) and Colorado Office of Consumer Counsel v.
FERC, 490 F.3d 954 (D.C. Cir. 2007) does not
support their argument that the Final Rule violates
the FPA’s filing requirement. In Power Company of
America the court declined to address Power
Company of America’s (PCA) argument that

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the Commission explained in the Final
Rule, the more recent precedent in
Lockyer and Snohomish has upheld the
Commission’s dual requirement of an ex
ante finding of the absence of marketpower and sufficient post-approval
reporting requirements as complying
with the requirements of the FPA.756
468. With respect to Consumer
Advocates’ concern about long-term
affiliate sales contracts not being filed,
the Commission pointed out in the Final
Rule that since 2002, its regulations
have provided that long-term marketbased rate power sales service
agreements, with affiliates or otherwise,
are not to be filed with the
Commission.757 However, the affiliate
restrictions require that no wholesale
sales of electric energy may be made
between a franchised public utility with
captive customers and a marketregulated power sales affiliate without
first receiving Commission
authorization (separate from the general
market-based rate authorization at issue
in this docket) for the transaction under
section 205 of the FPA. As a result, a
franchised public utility with captive
customers cannot enter into a long-term
contract with an affiliate without the
seller under the contract (whether the
franchised public utility or the affiliate)
first receiving Commission
authorization to engage in the affiliate
sale.758 To the extent that a particular
affiliate relationship presents issues of
concern, it will be considered in the
context of our determination whether to
authorize any affiliate sales. Further, our
umbrella agreements of power marketers were
required to be on file because this argument was not
raised in PCA’s opening brief. See Power Company
of America, 245 F.3d at 845. In Colorado Office of
Consumer Counsel, the court denied the Colorado
Office of Consumer Counsel’s petition for review of
a Commission order approving market behavior
rules because FPA section 206’s plain language
does not require the Commission, having found
only one aspect of the market-based rate tariffs to
be unjust and unreasonable, to revisit all elements
of its market-based rate tariffs. Thus, the D.C.
Circuit did not review the market-based rate
regime’s filing requirements in these two cases
because the filing requirement issue was not before
the court. Consumer Advocates’ argument in this
regard fails because it disregards the precedent
upholding the Commission’s dual requirement of an
ex ante finding of the absence of market power and
sufficient post-approval reporting requirements.
Lockyer, 383 F.3d 1006; Snohomish, 471 F.3d 1053.
756 Lockyer, 383 F.3d 1006; Snohomish, 471 F.3d
1053. Consumer Advocates also argue that the Final
Rule ignored the lead cases on the FPA filing
requirement, except to quote them for the
proposition that the filing and hearing requirements
of the NGA and FPA are typically read in pari
materia. Consumer Advocates Rehearing Request at
34–35 (citing United Gas Pipe Line; Sierra; Order
No. 697 at P 946, n.1070). We address Consumer
Advocates’ argument in this regard at supra P 412,
461–64.
757 Order No. 697 at P 969 (citing 18 CFR 35.1(g)).
758 Id. P 969–970.

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market-based rate program incorporates
numerous protections against excessive
rates, regardless of the identities of the
parties to a transaction. Finally,
although long-term contracts generally
are not filed at the Commission, all
relevant contract information is
contained in the EQRs and thus the
same information is available to the
public and the Commission. Thus, we
will continue to direct sellers not to file
long-term market-based rate sales
contracts, unless otherwise permitted by
Commission rule or order.759
469. For the reasons stated in the
section of this order addressing
Implementation Process, we reject
NASUCA’s argument that there is no
record to support the finding that a
seller with 499 MW capacity needs no
triennial power review and a seller of
501 MW does need market power
review.760
b. Whether the Final Rule Shifts the
Burden of Proof Under Section 205 of
the FPA
Final Rule
470. In the Final Rule, the
Commission noted that it had
previously addressed and rejected the
argument that the legal presumptions
that follow from the Commission’s
market power screens would unduly
shift the burden of demonstrating the
existence of market power to
intervenors. On rehearing of the April
14 Order, the Commission explained
that nothing in that order shifts the
burden of proof that section 205
imposes on the filing utility. Passing
both screens or failing one merely
establishes a rebuttable presumption. To
challenge a seller who passes both
screens, the intervenor need not
conclusively prove that the seller
possesses market power. Rather, the
intervenor need only meet a burden of
going forward with evidence that rebuts
the results of the screens. At that point,
the burden of going forward would
revert back to the seller to prove that it
lacks market power. Thus, the burden of
proof under section 205 ultimately
belongs to the seller.761
Requests for Rehearing
471. Consumer Advocates argue that
the Final Rule unlawfully shifts the
statutory burden of proof from the
electricity seller under section 205(e), to
justify increased rates, to the electricity
759 Id.

P 970.
supra P 344–47.
761 Order No. 697 at P 968. The Commission also
concluded that it will continue to direct sellers not
to file long-term market-based rate sales contracts,
unless otherwise permitted by Commission rule or
order. Id. P 969–70.
760 See

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consumer under section 206(a), to prove
both that such increased rates are
excessive and to justify different
rates.762 They also contend that the
Final Rule claims to justify this shift of
burden of proof by stating that the
burden is still on the seller to show it
has no market power, even though
sellers are no longer required to justify
rate increases.763 Consumer Advocates
assert that FPA section 205, under
which market-based rate tariff
authorizations are approved, does not
mention ‘‘‘market power,’’’ but requires
that sellers have the burden of justifying
proposed rate increases.764 Consumer
Advocates state that the results on
consumers can be seen in the
Commission’s recent denial of a
complaint by the Connecticut Attorney
General because Connecticut failed to
carry its burden of proof under section
206(a).765
472. Southern contends that the Final
Rule violates the requirement in FPA
section 206 that the Commission bear
the burden of proof in section 206
proceedings and that the Commission’s
determinations be based on substantial
evidence.766 According to Southern, this
shifting of the burden of proof occurs
through the use of indicative screens,
which Southern contends are inherently
flawed. Southern states that once a
screen failure occurs and a presumption
of market power arises, sellers only have
two options: Either accept a
determination that it has market power
and adopt cost-based mitigation
measures, or provide the Commission
with a DPT analysis.767 Southern
concludes that by applying the
indicative screens codified in the Final
Rule the Commission will effectively
shift to sellers the evidentiary burden in
a section 206 proceeding.768
473. Southern also argues that the
screens are inherently flawed in their
ability to definitively assess market
power when none is actually present,
noting that the Final Rule
‘‘acknowledges that the screens are
‘conservative’ in nature and will
undoubtedly result in ‘false positives’
indicating market power.’’ 769 Southern
762 Consumer

Advocates Rehearing Request at 31–

32.
763 Id.

at 32 (citing MCI; Southwestern Bell).

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764 Id.
765 Id. (citing Blumenthal, 117 FERC ¶ 61,038 at
P 57).
766 Southern Rehearing Request at 7–8 (citing 16
U.S.C. 824e(a); Sierra, 350 U.S. at 353; Public
Service Commission of New York v. FERC, 642 F.2d
1335, 1345 (D.C. Cir. 1980); Public Service Co. of
New Mexico, 115 FERC ¶ 61,090, at P 33 (2006)).
767 Id. at 7 (citing Order No. 697 at P 63).
768 Id. at 8.
769 Id. at 8 (citing Order No. 697 at P 62, 71, 74,
89).

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argues that because of their conservative
nature and propensity to result in false
positives, such screens cannot properly
provide a basis for shifting the burden
of proof to sellers, and are incapable of
providing substantial evidence of
market power.
474. Southern contends that by
shifting the section 206 burden of proof
to sellers, the Final Rule shifted to
sellers the burden of rebutting the
presumption of generation market
power. Southern states that the
unlawfulness of shifting this burden is
exacerbated by the restriction placed on
the type of evidence that sellers may
present to rebut the market power
presumption. Specifically, Southern
asserts that the Final Rule only allows
sellers to submit (1) historical sales and
transmission data and (2) an analysis
using the DPT (using only historical
data) to demonstrate that they do not
have market power, and that these
limitations on sellers’ ability to rebut
the false presumption of generation
market power are inconsistent with the
FPA since they arise in the context of
a section 206 proceeding, in which the
Commission is required to bear the
burden of proof.770
475. Southern argues that the
Commission should reconsider its
determination in the Final Rule that a
failure of an indicative screen results in
a presumption of market power, and
should instead determine that the
indicative screens are only intended to
identify sellers that appear to raise no
horizontal market power concerns and
thus can be considered for market-based
rate authority without the necessity of
further analysis.771 In other words,
passing the screens should raise a
favorable presumption that a seller does
not have market power, and a seller
would never be ‘‘presumed’’ to have
generation market power.772
Commission Determination
476. With regard to Consumer
Advocates’ assertion that the Final Rule
shifts the burden of proof from the
electricity seller under section 205(e) to
the electricity consumer under section
206(a), we reiterate that the Commission
has not shifted the burden of proof that
section 205 imposes on the filing utility.
A utility seeking to make sales at
market-based rates has the burden of
proof under section 205 to show that it
does not have, or has adequately
mitigated, market power. Because
passing both indicative horizontal
market power screens establishes a
770 Id.
771 Id.

at 10–11 (citing Order No. 697 at P 33, 75).
at 11.

772 Id.

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25903

rebuttable presumption that the seller
lacks market power, the burden is then
on the intervenor to provide evidence to
rebut the presumption of no market
power.773 To challenge a seller who
passes both screens, the intervenor need
not conclusively prove that the seller
possesses market power. Rather, the
intervenor need only meet a burden of
going forward with evidence that rebuts
the results of the screens. At that point,
the burden of going forward would
revert back to the seller to prove it lacks
market power. Ultimately, however, the
burden of proof under section 205
belongs to the seller.774
477. We reject Consumer Advocates’
argument that the Final Rule shifts the
FPA section 205 burden of proof to
justify rate increases from the electricity
seller to the electricity consumer under
section 206(a) to prove both that such
increased rates are excessive and to
justify different rates, and that this can
be seen in the Commission’s denial of
the Connecticut Attorney General’s
complaint in Blumenthal because
Connecticut failed to carry its burden of
proof under FPA section 206(a).
Blumenthal was an FPA section 206
complaint proceeding in which the
complainants challenged ISO–NE’s
current Market Rule 1 as unjust and
unreasonable with regard to the
compensation of generation facilities
needed for reliability in Connecticut.
Because that case was brought under
section 206 of the FPA, the burden
properly was on complainants to
establish that the current provisions of
Market Rule 1 are unjust and
unreasonable. However, that case is
distinguishable from the circumstance
where a seller seeks authorization to
make sales at market-based rates. As
773 See Order No. 697 at P 968 (citing July 8
Order, 108 FERC ¶ 61,026, at P 29).
774 See July 8 Order at P 29 (stating that passing
both screens or failing one merely establishes a
rebuttable presumption, and explaining that in the
case of an intervenor in a section 205 proceeding
that seeks to prove that the applicant possesses
market power, ‘‘the intervenor need only meet a
‘burden of going forward’ with evidence that rebuts
the results of the screens. At that point, the burden
of going forward would revert back to the applicant
to prove that it lacks market power.’’) (citing
Pennzoil Co. v. FERC, 645 F.2d 360, 392 (5th Cir.
1981), cert. denied, 454 U.S. 1142 (1982); accord
Transcontinental Gas Pipe Line Corp., Opinion No.
135, 17 FERC ¶ 61,232, at 61,450 (1981) (‘‘The
presumption * * * is the same as that which arises
from a prima facie case: it imposes on the party
against whom it is directed the burden of going
forward with substantial evidence to rebut or meet
the presumption, but does not shift the burden of
persuasion.’’); Generic Determination of Rate of
Return on Common Equity for Electric Utilities,
Order No. 389–A, 29 FERC ¶ 61,223 (1984)
(concluding that the rebuttable presumption that a
rate of return based on a benchmark is just and
reasonable does not shift the ultimate burden of
proof imposed by the FPA).

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discussed above, in the case of a seller
seeking market-based rate authority
from the Commission under section 205,
the burden of proof is on the seller to
prove that it lacks market power.
However, in a section 206 complaint
proceeding, the burden is on the
complainant to show that the current
rates are unjust and unreasonable. Thus,
State AGs and Advocates’ argument that
Blumenthal supports their assertion that
the Final Rule shifts the FPA section
205 burden of proof to justify rate
increases from the electricity seller to
the electricity consumer under section
206(a) is without merit.
478. For the reasons stated in the
section of this order addressing
horizontal market power, we reject
Southern’s argument that the burden of
proof in a section 206 proceeding is
shifted to entities that fail one of the
indicative screens.
c. Whether Elimination of the
Requirement To File Market-Based Rate
Contracts in a Prior Rulemaking
Proceeding May Be Challenged in the
Instant Rulemaking

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Final Rule
479. The Final Rule concluded that
the multiple layers of filing and
reporting requirements incorporated
into the market-based rate program, the
Commission’s enhanced market
oversight and enforcement functions,
and the ability of the public to file
section 206 complaints meet the filing
requirements of the FPA and provide
adequate protection from excessive
rates. In reaching this determination, the
Commission noted that the decision to
eliminate the filing of market-based rate
contracts was made almost five years
ago in a generic rulemaking proceeding
that was open to participation by all
interested parties.775 The Commission
explained that commenters’ failure to
raise this concern in that proceeding
precludes them from attacking the
Commission’s well-settled practice in
the instant rulemaking.776
Requests for Rehearing
480. Consumer Advocates argue that
the Final Rule erred in asserting that
challengers to the Commission’s marketbased rate regime are precluded by the
passage of time and by earlier
rulemaking proceedings from now
raising their challenges to the
Commission’s authority to issue its
market-based rate regulations, including
their arguments that the regulations are
contrary to the filing and other
requirements of FPA sections 205 and
775 Order

No. 697 at P 967, n.1112.

776 Id.

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206.777 Consumer Advocates state that
the Final Rule noted that the failure of
commenters to object to an earlier
rulemaking that eliminated the filing of
market-based rate contracts almost five
years ago now precludes them from
asserting that the Commission’s actions
in the instant rulemaking violate the
FPA’s filing requirements.778 Consumer
Advocates contend that the
Commission’s view that commenters are
precluded from attacking the rules
promulgated in this proceeding is
incorrect insofar as the D.C. Circuit has
made clear that where an agency itself
reopens an issue by initiating a new
rulemaking procedure, participants in
the rulemaking are not barred from
challenging the new rule by their failure
to challenge prior agency actions.779
Consumer Advocates argue that
members of the public may raise issues
notwithstanding failure to participate in
an earlier rulemaking ‘‘ ‘when the
agency in question by some new
promulgation creates the opportunity
for renewed comment and
objection.’ ’’ 780
481. Consumer Advocates argue that
where the challenge is that the agency
lacks statutory authority to take an
action, a commenter’s earlier failure to
challenge another regulation cannot bar
consideration of the agency’s statutory
authority for the action it now proposes
to take. They conclude that where the
petitioner challenges the substantive
validity of a rule, failure to exercise a
prior opportunity to challenge the
regulation ordinarily will not preclude
review.781 Consumer Advocates assert
that the D.C. Circuit has held that the
rule barring collateral attacks on
regulations does not apply to claims that
‘‘an agency lacked the statutory
authority to adopt the rule.’’782
482. Consumer Advocates also state
that they filed a petition for review in
the D.C. Circuit over three years ago
raising these issues in the context of a
challenge to the Commission’s actions
in its Investigation of Terms and
Conditions of Public Utility Market777 Consumer

Advocates Rehearing Request at 37–

38.
778 Id. at 38 (citing Order No. 697 at P 967,
n.1112).
779 Id. (citing Montana v. Clark, 749 F.2d 740, 744
(D.C. Cir. 1984), cert. denied, 474 U.S. 919 (1985)).
780 Id. at 38 (quoting Ohio v. EPA, 838 F.2d 1325,
1328 (D.C. Cir. 1988); accord Ass’n of Am. R.Rs. v.
ICC, 846 F.2d 1465, 1473 (D.C. Cir. 1988); Public
Citizen v. NRC, 901 F.2d 147, 150 (D.C. Cir. 1990),
cert. denied, 498 U.S. 992 (1990)).
781 Id. at 39 (citing Montana v. Clark, 749 F.2d at
744 n.8).
782 Id. (quoting Indep. Community Bankers of
Am. v. Bd. of Governors of Fed. Reserve Sys., 195
F.3d 28, 34 (D.C. Cir. 1999); NRDC v. NRC, 666 F.2d
595, 602 (D.C. Cir. 1981)).

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Based Rate Authorizations, an FPA
section 206 proceeding in which
Consumer Advocates participated and
presented their challenges to the
market-based rate regime to the
Commission in great detail.783 They
state that the Commission has argued in
the D.C. Circuit, successfully so far, that
Consumer Advocates’ challenge to the
market-based rate regime was not
properly presented in that matter and
should be addressed in some other
appropriate proceeding.784 Consumer
Advocates conclude that the
Commission may not now assert that
Consumer Advocates have slept on their
rights and cannot present their
arguments in a rulemaking that raises
the issue of the lawfulness of the
Commission’s market-based rate
regime.785
Commission Determination
483. Consumer Advocates’ attack on a
sentence in a footnote stating that
‘‘Commenters’ failure to raise this
concern [regarding the filing of marketbased rate contracts] in that proceeding
precludes them from attacking the
Commission’s well-settled practice
here’’ 786 makes more of this footnote
than it was intended to convey. This
sentence was intended to clarify that the
Commission had previously determined
to eliminate the filing of market-based
rate contracts in Order No. 2001,787 and
to clarify that the Commission is not
reconsidering this issue as part of this
rulemaking proceeding. This sentence
does not stand for the broad
proposition, as suggested by Consumer
Advocates, that ‘‘challengers to the
Commission’s market-based rate regime
are precluded by the passage of time
and by earlier rulemaking proceedings
from now raising their challenges to the
Commission’s authority to issue its
market-based rate regulations, including
their arguments that the regulations are
contrary to the filing and other
requirements of FPA sections 205 and
206.’’ Indeed, in the Final Rule, the
Commission fully responded to the
arguments raised by Consumer
Advocates in their NOPR comments, in
which they challenged the
Commission’s authority to issue its
market-based rate regulations and
argued, among other things, that the
regulations are contrary to the filing and
other requirements of FPA sections 205
783 Id.

at 40.
(citing Colorado Office of Consumer
Counsel v. FERC, 490 F.3d 954 (D.C. Cir. 2007)).
785 Id.
786 Order No. 697 at n.1112.
787 Order No. 2001, FERC Stats. & Regs. ¶ 31,127
at P 31.
784 Id.

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and 206.788 Moreover, the Commission
is responding to their arguments on
rehearing in the instant order. Thus, the
Commission has thoroughly addressed
Consumer Advocates’ arguments
regarding the instant market-based rate
rulemaking proceeding in both the Final
Rule and in this order.
d. Whether the Commission Should
Clarify That Sellers With Market Power
Must File Their Actual Rates and
Contracts Before the Charges Are
Implemented
Final Rule
484. The Final Rule concluded that,
with regard to NASUCA’s assertion that
the rule would allow mitigated sellers
with cost-based rates to declare their
own rates without filing them, all
mitigation proposals, whether based on
the default cost-based rates or some
other cost-based rates, must be filed
with the Commission for review. The
Commission stated that, as explained in
the Mitigation section of the Final Rule,
any such filings are noticed, and
interested parties are given an
opportunity to intervene, comment on,
or protest the submittal.789
Requests for Rehearing
485. NASUCA raises a similar
argument on rehearing, claiming that
sellers with market power should not be
allowed to determine and change their
rates without complying with FPA filing
requirements.790 NASUCA states that
sellers with market power, have, until
now, been required to file cost-based
rates, and argues that the Final Rule
allows sellers with market power to
dispense with the filing of contracts and
changes in rates for sales of less than
one year under the default mitigation
rates.791 NASUCA states that only
contracts for sales greater than one year
would be filed under section 205.792
According to NASUCA, a consequence
is that there is no possibility of public
notice, protest, Commission review
prior to imposition of unreasonable new
charges, and no opportunity for refund
of unreasonable rates charged by sellers
with market power for sales of up to one
year’s duration.793
486. NASUCA contends that allowing
sellers with market power to dispense
with the filing of contracts and changes
in rates for sales of less than one year

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788 Order

No. 697 at P 943–955, 959–968.
789 Id. P 971.
790 NASUCA Rehearing Request at 8.
791 Id. at 9 (citing Order No. 697 at 18 CFR 35.38).
792 Although NASUCA refers to contracts for
‘‘sales greater than one year,’’ the Commission’s
default rates for long-term sales cover sales of ‘‘one
year or more.’’ Order No. 697 at P 659.
793 NASUCA Rehearing Request at 9.

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under the default mitigation rates, and
‘‘to set rates at will between marginal
cost and embedded cost may not be
reasonable and could allow
discrimination.’’ 794 NASUCA argues
that even though looked at separately,
the incremental cost rate base and the
embedded cost rate could be within the
zone of reasonableness, giving the
utility the option to pick its rates and its
customers in bilateral transactions,
which could give the utility with
wholesale market power the
opportunity to extend it into retail
markets, favoring its retail affiliate.795
NASUCA notes that in FPC v. Conway
Corp., the Supreme Court held that a
utility could not set low retail rates to
attract retail industrial customers from
other utilities and set wholesale rates at
prices higher than the retail rate so that
its wholesale competitors could not
compete in the retail market. Thus,
NASUCA concludes that the
Commission should not allow this
potentially discriminatory and
predatory conduct in the name of
granting ‘‘ ‘flexibility’ ’’ to utilities.796
487. NASUCA also argues that
allowing sellers with market power to
make sales for less than one year
without filing them is a subdelegation to
private parties of basic duties conferred
upon the Commission by Congress.797 In
support of this point, NASUCA states
that in ISO New England, Inc.,
Chairman Kelliher disagreed with the
Commission’s decision to deny
rehearing of an earlier order that
accepted for filing three mitigation
agreements and granted waiver of the 60
day prior notice requirement.798
NASUCA concludes that the Final Rule
has the same defect identified by
Chairman Kelliher: Rates of sellers with
market power, when they involve sales
for less than one year, are allowed to
take effect without observing prior filing
requirements, with the Commission
relying on private parties to negotiate
and charge reasonable rates.799
NASUCA asserts that there is no
provision in the FPA granting the
Commission the power to direct utilities
not to file their rates for sales of less
than one year, and no evidence that
such rates are reasonable.800 NASUCA
794 Id.
795 Id.
796 Id.

at 10 (citing 426 U.S. 271 (1976)).
(citing U.S. Telecom Ass’n v. FCC, 359 F.3d
554, 567–78 (D.C. Cir. 2004)).
798 Id. (citing ISO New England, Inc., 112 FERC
¶ 61,057 (2005), reversed on other grounds, NSTAR
Electric & Gas Corp. v. FERC, 481 F.3d 794 (D.C.
Cir. 2007) (NSTAR)).
799 Id. at 11.
800 Id. (citing MCI, 512 U.S. at 229–30; American
Telephone & Telegraph Co. v. Central Office
Telephone Inc., 524 U.S. 214 (1998)).
797 Id.

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25905

states that the D.C. Circuit rejected rates
that had been charged by utility
negotiation at marginal cost plus 10
percent without being timely filed for
possible review and revision by the
Commission for lack of evidence, and
argues that the same flaw applies here
to the generic rate ranges approved for
sellers with market power. According to
NASUCA, there is no evidence that such
rates are reasonable.801
488. NASUCA states the Final Rule
responded to NASUCA’s concerns by
saying that rate ‘‘ ‘proposals’ ’’ of
mitigated sellers would be filed, but the
Final Rule does not say rates, rate
schedules, and contracts will be filed.802
NASUCA contends that the Final Rule
adopted a rule which clearly states that
only new contracts of a duration longer
than one year are to be filed under
section 205. NASUCA argues that in
analogous circumstances where actual
changes in rates and charges had not
been filed, the D.C. Circuit stated that
‘‘ ‘making rates effective as of the date of
an order setting forth no more than the
basic principles pursuant to which the
new rates are to be calculated would
make unforeseeable liabilities a regular
consequence of rate adjustments.’ ’’ 803
NASUCA therefore requests that the
Commission clarify that sellers with
market power must file not only
‘‘ ‘proposals,’ ’’ but also schedules
containing their actual rates and
contracts, before the charges are
implemented, in accordance with FPA
section 205.804
Commission Determination
489. With regard to NASUCA’s
arguments concerning filing
requirements for sellers with market
power, to the extent a seller proposes a
cost-based rate that is based on a
formula, it is our practice to require that
the rate formula used be provided for
Commission review and such formula
included in the cost-based rate tariff,
including formulas used in calculating
incremental cost for purposes of the
Commission’s default cost-based
rates.805 As the Commission explained
in the Final Rule, all mitigation
proposals by a seller found, or
presumed, to have market power must
be filed with the Commission for
review. These filings are noticed and
interested parties are provided the
opportunity to intervene, comment or
801 Id.
802 Id.

(citing NSTAR, 481 F.3d 794).
at 12 (citing Order No. 697 at section

35.38).
803 Id. (quoting Electrical District, 774 F.2d at
492–93).
804 Id.
805 Order No. 697 at P 630.

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protest the submittal.806 In response to
NASUCA’s concern regarding the
Commission’s use of the word
‘‘proposals,’’ we clarify that by
‘‘mitigation proposals’’ we were
referring to cost-based rate tariffs that
incorporate the seller’s proposal for
mitigation. As the Commission stated in
the April 14 Order, where a seller
proposes to adopt the default cost-based
rates (or where it proposes other costbased rates), it must provide cost
support for such rates. The Commission
will examine the proposed rates on a
case-by-case basis.807 With regard to
sales of one week or less, where the
seller fails to provide sufficient costsupport, the Commission will direct the
seller to submit a compliance filing to
provide the formulas and methodology
according to which it intends to
calculate incremental costs.808
490. With regard to sales of greater
than one week but less than one year,
the Commission similarly requires that
the seller submit a cost-based rate tariff
for filing that identifies the methodology
to be used to calculate the rate. When
a seller adopts the default cost-based
rate for mid-term sales (which is based
on the unit or units expected to run), or
otherwise proposes a cost-based rate
designed on the unit or units expected
to run, the Commission stated that it
will continue to allow the seller
flexibility in selecting the particular
units that form the basis of the ‘‘up to’’
rate. However, as the Commission also
stated in the Final Rule, it considers all
evidence when reviewing a cost-based
rate proposal and, if a company has not
justified selection of certain generation
units, the Commission will not accept
the proposed rate.809 Nevertheless, as
with all cost-based mitigation proposals,
the seller must file a cost-based rate
tariff with the Commission and must
provide cost support for such rates.810
Accordingly, we clarify in response to
NASUCA’s request that when a
mitigated seller files a cost-based
mitigation proposal with the
806 Id.

P 629.
P 630 (citing April 14 Order, 107 FERC
¶ 61,018 at P 208; Entergy Services, Inc., 115 FERC
61,260 at P 49 (2006) (accepting cost-based rates
based on incremental cost plus 10 percent, noting
that filing included the formula and methodology
according to which seller intends to calculate
incremental costs)).
808 Id. P 630 (citing Aquila, Inc., 112 FERC
¶ 61,307, at P 26 (2005); Oklahoma Gas and Electric
Co., 114 FERC ¶ 61,297, at P 19 (2006)).
809 Id. P 649, 651.
810 As explained in the Final Rule, upon loss or
surrender of market-based rate authority a seller has
a number of options of how to make wholesale
power sales. It can revert to a cost-based rate tariff
on file with the Commission, file a new proposed
cost-based rate tariff, or propose other mitigation.
See Order No. 697 at n.699.

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807 Id.

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Commission, the seller must file an
accompanying tariff.
491. We reject NASUCA’s argument
that there is no opportunity for public
notice, or protest and Commission
review of rates for mitigated sellers, and
no opportunity for refund of
unreasonable rates charged by sellers
with market power for sales of up to one
year’s duration. As noted above and as
discussed in the Final Rule, all
mitigation proposals must be filed with
the Commission for review.811 These
filings are noticed and interested parties
are given an opportunity to intervene,
comment or protest the submittal.812 As
the Commission stated in the Final
Rule, it will continue to conduct its own
analysis of whether a proposed costbased rate is just and reasonable and, if
warranted, will set such a proposed rate
for evidentiary hearing where there are
issues of material fact.813 Under the
FPA, the Commission has the authority
to accept, reject, or modify a proposed
rate based on the analysis of the specific
facts and circumstances.814 Contrary to
NASUCA’s contention that the
Commission provides no opportunity
for review of, and for refund of, rates
charged by mitigated sellers for sales of
up to one year’s duration, the
Commission has accepted, subject to
refund, suspended and set for hearing
cost-based mitigation proposals.815
492. We find NASUCA’s reliance on
FPC v. Conway to support its argument
that the Commission should not grant
mitigated sellers the flexibility to
propose rates between marginal cost and
embedded cost to be misplaced. In FPC
v. Conway, the Supreme Court held that
a utility could not set low retail rates to
attract retail industrial customers from
other utilities and set wholesale rates at
prices higher than the retail rate so that
its wholesale competitors could not
compete in the retail market. The Court
also held that, although the FPC lacked
the authority to fix retail rates, it may
take those rates into account when it
fixes the rates for interstate wholesale
sales that are subject to its
jurisdiction.816 As explained above, the
Final Rule requires that the seller
submit a cost-based rate tariff for filing
that identifies the methodology to be
811 Order

No. 697 at P 629.

812 Id.
813 Id.

P 650.
P 651.
815 See Id. P 631 (citing AEP Power Marketing,
Inc., 112 FERC ¶ 61,047, at P 28 (2005) (accepting,
subject to refund, and setting for hearing, AEP’s
proposed rate for sales of power of more than one
week but less than one year upon finding that AEP
did not provide sufficient cost support for the rate
levels proposed). See also, Duke Power, 113 FERC
¶ 61,192, at P 38 (2005).
816 426 U.S. 271, 279–80 (1976).
814 Id.

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used to calculate the rate for mid-term
sales. Further, the Final Rule requires
that, to the extent a seller proposes a
cost-based rate formula, the rate formula
to be used must be provided for
Commission review and such formula
must be included in the cost-based rate
tariff, including formulas used in
calculating incremental cost.817 As the
Final Rule explains, the Commission
examines the proposed rate formulas of
mitigated sellers on a case-by-case basis,
and in doing so, fulfills its FPA mandate
to ensure that rates are just and
reasonable and not unduly
discriminatory. Because the Final Rule
requires sellers to submit a cost-based
rate tariff for filing that identifies the
methodology to be used to calculate the
rate, and thereby does not permit sellers
with market power to ‘‘set rates at will,’’
NASUCA’s contention that allowing
sellers with market power ‘‘to set rates
at will between marginal cost and
embedded cost * * * could give the
utility with wholesale market power the
opportunity to extend it into retail
markets’’ is without merit. Thus,
NASUCA’s claim that a scenario
resulting in potentially discriminatory
or predatory conduct could occur is
speculative and unsupported by the
facts in the record.
493. We reject NASUCA’s argument
that allowing mitigated sellers to make
sales for less than one year without
filing them is a subdelegation to private
parties of the duties conferred upon the
Commission by Congress. NASUCA
relies on ISO New England, Inc.818 to
support its argument in this regard. In
ISO New England, Inc., the Commission
preauthorized ISO New England to enter
into mitigation agreements intended to
mitigate generation resources that ran
out-of-economic merit order during
periods of transmission constraints, and
concluded that all such agreements
were just and reasonable. On appeal, the
D.C. Circuit remanded to the
Commission the issue concerning
whether the rates adopted in mitigation
agreements were just and reasonable
because the Commission had not
reviewed data concerning generator
costs for the rates in the mitigation
agreements.819 Contrary to NASUCA’s
argument, and unlike the situation in
ISO New England, Inc., the Final Rule
states that ‘‘where a seller proposes to
adopt the default cost-based rates (or
where it proposes other cost-based
rates), it must provide cost support for
such rates. The Commission will
817 Order

No. 697 at P 630.
112 FERC ¶ 61,057 (2005), reversed in
part, NSTAR, 481 F.3d 794.
819 NSTAR, 481 F.3d 794.
818 818

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
examine the proposed rates on a caseby-case basis.’’ 820 Here, the Commission
has not neglected to review a mitigation
proposal, or the cost support for such a
proposal. Rather, it is promulgating a
rule which provides for Commission
examination of rates proposed by
mitigated sellers, and that requires cost
support for such rates. Thus, NASUCA’s
argument in this regard is without merit.
494. Further, as explained above, the
Final Rule retained the Commission’s
current policy of pricing sales of more
than one week but less than one year at
an embedded cost ‘‘up to’’ rate reflecting
the costs of the generating unit(s)
expected to provide the service.821
Although this approach allows sellers
flexibility in designing ‘‘up to’’ rates for
purposes of mitigation for sales of more
than one week but less than one year,
such rates are still subject to
Commission review and approval.822
The Commission considers all evidence
when reviewing a cost-based rate
proposal and, if a company has not
justified selection of certain generating
units, we will not accept the proposed
rate. Under the FPA, we have the
authority to accept, reject, or modify a
proposed rate based on an analysis of
the specific facts and circumstances.823
NASUCA relies on U.S. Telecomm.
Ass’n v. FCC,824 and Chairman
Kelliher’s dissent in ISO New England
Inc. to support its contention that the
Commission may not delegate its
authority to private parties. As we
explain above, however, because the
Final Rule provides for Commission
review of a seller’s proposed rates, and
because the Commission will not accept
the proposed rate if a company has not
justified selection of certain generating
units, the Final Rule is not
subdelegating the Commission’s
duties.825
495. We also reject NASUCA’s
argument that under the Final Rule,
rates of mitigated sellers rely on private
parties to negotiate and charge
reasonable rates and thereby are in
contravention of the holdings of MCI
and Electrical District. In MCI, the
Supreme Court rejected an FCC policy
that relieved all non-dominant carriers
of any requirement to file any of their
rates with the agency. Electrical District
holds that the Commission cannot, in a
proceeding under section 206,
‘‘announce some formula and later

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820 Order

No. 697 at P 630.
821 Order No. 697 at P 648.
822 Id. P 652.
823 Id. P 651.
824 359 F.3d 554 (D.C. Cir. 2004) (finding that a
federal agency may not delegate its authority to
outside entities).
825 See Order No. 697 at P 629, 651.

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reveal that formula was to govern from
the date of announcement.’’826 Both of
these cases are distinguishable from the
mitigation scheme set forth in the Final
Rule. Because the Final Rule explains
that ‘‘all mitigation proposals must be
filed with the Commission for review’’
and states that ‘‘[t]hese filings will be
noticed and interested parties will be
given an opportunity to intervene,
comment, or protest the submittal’’ 827
the Final Rule does not rely on private
parties to negotiate and charge
reasonable rates and does not
contravene the holdings in MCI and
Electrical District.
3. Whether Existing Tariffs Must Be
Found To Be Unjust and Unreasonable,
and Whether the Commission Must
Establish a Refund Effective Date
Final Rule
496. The Final Rule determined that
the Commission was not required to
establish a refund effective date and
concluded that continuing to allow
basic inconsistencies in the marketbased rate tariffs on file with the
Commission is unjust and
unreasonable.828 The Commission
found that even if section 206 were read
to require the establishment of a refund
effective date in rulemakings initiated
under section 206, rather than only in
case-specific section 206 investigations
initiated by complaints or sua sponte by
the Commission, the Commission has
broad discretion to adopt a generic
policy or make generic findings through
either rulemaking or adjudication.829
The Commission concluded that ‘‘[t]his
proceeding is not an adjudicatory
investigation of public utilities’ existing
market-based rate tariffs for which
refunds will be required. Rather, we are
modifying existing market-based rate
tariffs prospectively only through this
rulemaking. Accordingly, the
establishment of a refund effective date
in this rulemaking would be
meaningless.’’ 830
Requests for Rehearing
497. Consumer Advocates contend
that the Final Rule points to no specific
legal authority under either section 205
or 206 that supports the Commission’s
action. They state that the Commission
claims it is not ‘‘adjudicating’’ in the
Final Rule, but fails to recognize that the
826 Transwestern Pipeline Co. v. FERC, 897 F.2d
570, 578 (D.C. Cir. 1990). See supra P 453.
827 Order No. 697 at P 629.
828 Id. P 974.
829 Id. P 975 (citing Lockyer).
830 Id. (citing Wisconsin Gas Co. v. FERC, 770
F.2d 1144, 1166 (D.C. Cir. 1985); SEC v. Chenery,
332 U.S. 194, 202–03, reh’g denied, 332 U.S. 747
(1947) (emphasis in original).

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25907

Commission’s authority to issue rules
under sections 205 and 206 is narrowly
constrained because the Commission
has no independent ratemaking power
under the FPA.831 Consumer Advocates
state that pursuant to United Gas Pipe
Line and Sierra, the Commission has
authority under section 206(a) to review
initial rates and contracts filed by utility
sellers, or ongoing, previously effective
rates. Consumer Advocates contend that
before the Commission can act under
section 206(a), it must find existing rates
to be unlawful, and also must find
market-based rates as modified by the
rulemaking to be just and reasonable
and not unduly preferential or
discriminatory going forward. They
submit that although the Final Rule
purports to make the first finding that
existing rates without the new rules are
unjust and unreasonable, it fails to make
the second finding that market-based
rates that adhere to the Final Rule are
just and reasonable.832 Consumer
Advocates contend that the Final Rule
pointed to no legal authority under
section 205 or 206 that supports the
actions taken, but instead points only to
policy choices regarding the marketbased rate regime. Consumer Advocates
assert that the Commission has no
authority, even to implement policy,
unless the statute confers it.833
Commission Determination
498. We disagree with Consumer
Advocates’ contentions that the
Commission must find existing marketbased rates to be unlawful and must set
new lawful rates going forward and that
the Commission has no authority to
implement the policies in this
rulemaking. We have broad discretion to
adopt generic policy or make generic
findings through either rulemaking or
adjudication,834 and we have discretion
over whether to order refunds.835 We
831 Id.

at 16 (citing United Gas Pipe Line; Sierra).
(citing United Gas Pipe Line; Sierra).
833 Id. at 17 (citing Atlantic City Electric Co. v.
FERC, 295 F.3d 1, 8 (D.C. Cir. 2002) (Atlantic City)).
834 An agency enjoys broad discretion to
determine its own procedures, including whether to
act by a generic rulemaking or by case-by-case
adjudication. Mobil Oil Exploration & Producing
Southeast, Inc. v. United Distrib. Cos., 498 U.S. 211,
230 (1991); NLRB v. Bell Aerospace Co., 416 U.S.
267, 293 (1974); Interstate Natural Gas Association
of America v. FERC, 285 F.3d 18, 57–58 (D.C. Cir.
2001).
835 See e.g., Lockyer, 383 F.3d at 1016. Consumer
Advocates rely on Atlantic City for support for their
argument that the Commission has no authority to
implement policy unless a statute confers it. In
Atlantic City, the court held that the Commission
did not have authority to require utilities to give up
their right to file rate changes or authority to
mandate that withdrawal from an ISO could only
become effective upon Commission approval.
However, because the courts have repeatedly
832 Id.

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reiterate that this proceeding is not an
adjudicatory investigation of public
utilities’ existing market-based rate
tariffs for which refunds will be
required.836
499. We also reject Consumer
Advocates’ assertion that the instant
rulemaking is in contravention of
United Gas Pipe Line and Sierra because
the Final Rule did not make the finding
that market-based rates that adhere to
the Final Rule are just and reasonable.
In United Gas Pipe Line, the Supreme
Court interpreted provisions of the NGA
that parallel the FPA, and it stated that
section 4(d) of the NGA says only that
‘‘a change in the filed rate cannot be
made without proper notice to the
Commission.’’ 837 The Supreme Court
held in Sierra that the FPA does not
authorize unilateral contract changes
and held that the Federal Power
Commission could not declare a rate set
by a contract to be ‘‘unreasonable solely
because it yields less than a fair return
on the next invested capital.’’ 838 Unlike
United Gas Pipe Line and Sierra, this
rulemaking proceeding is not an
adjudicatory investigation of a public
utility’s existing rates for which refunds
will be required. Rather, in the Final
Rule the Commission revised and
codified its market-based rate policy for
public utilities on a generic basis.
Contrary to Consumer Advocates’
argument that the Commission did not
specify ‘‘exactly what it is doing in the
Final Rule,’’ the Commission clearly
stated that it is ‘‘modifying existing
market-based rate tariffs prospectively
only through this rulemaking.’’ 839
G. Miscellaneous
1. Change in Status
a. Reporting

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Final Rule
500. In Order No. 697, the
Commission continued its requirement
for sellers to report any change in status
that departs from the characteristics
relied upon by the Commission in
authorizing sales at market-based
rates.840 Events that constitute a change
upheld the Commission’s authority to adopt
market-based rates, Consumer Advocates’ reliance
on Atlantic City for support for their argument in
this regard is misplaced. See, e.g., LEPA, 141 F.3d
364; Lockyer, 383 F.3d 1006; Snohomish, 471 F.3d
1053.
836 Order No. 697 at P 975.
837 United Gas Pipe Line, 350 U.S. at 339
(emphasis in original).
838 Sierra, 350 U.S. at 355.
839 Order No. 697 at P 975 (citing Wisconsin Gas
Co. v. FERC, 770 F.2d 1144, 1166 (D.C. Cir. 1985);
SEC v. Chenery, 332 U.S. 194, 202–03, reh’g denied,
332 U.S. 747 (1947) (emphasis in original)).
840 Order No. 697 at P 1009–1045 (codifying the
requirement, as amended, at 18 CFR 35.42).

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in status include, among other things,
ownership or control of generation
capacity that result in net increases of
100 MW or more, and change in
upstream ownership. Notification of any
such changes in status must be filed no
later than 30 days after the change
occurs.
501. Also in Order No. 697, the
Commission created a category of
market-based rate sellers that are
exempt from the requirement to submit
regularly scheduled updated market
power analyses. These Category 1 sellers
have been carefully defined by the
Commission to have attributes that are
not likely to present market power
concerns.841 Market power concerns for
Category 1 sellers are monitored by the
Commission through the change in
status reporting requirement and
through ongoing monitoring by the
Commission’s Office of Enforcement.
All other sellers, Category 2 sellers, are,
in addition, required to continue to file
regularly scheduled updated market
power analyses.842
Requests for Rehearing
502. TDU Systems assert that to
protect consumers more adequately, the
Commission should require a Category 2
seller to submit an updated market
power analysis in each instance in
which a seller’s generation increases by
a predetermined percentage or an
absolute amount.843 TDU Systems state
that under the Commission’s present
rules, a public utility that builds or
acquires new generation capacity or
merges with another company is not
required to submit a new horizontal
market power analysis. It is required
only to file a change in status report for
any net increase of 100 MW or more.
TDU Systems references a proposal
made by another commenter in response
to the NOPR asking the Commission to
require an updated market power
analysis in each instance in which a
seller’s generation increases by a
predetermined percentage or absolute
amount. According to TDU Systems, the
Commission did not directly address
this proposal in the Final Rule,844 but
indirectly touched on the issue by
stating that an updated market power
841 Id.

at P 853.

842 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.
843 TDU Systems at 28 (citing NRECA NOPR
comments at 24. NRECA gives examples of
predetermined thresholds as a certain percentage
increase over the current amount, or any increase
over some absolute amount).
844 TDU Systems indicate that NRECA suggested
this proposal. TDU Systems at 27–28 (citing NRECA
NOPR comments at 23–25).

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analysis may be required from any
sellers, Category 1 or 2, at any time.
503. TDU Systems assert that the
Commission erred in failing to address
the merits of this proposal in the Final
Rule.845 They contend that the
Commission should not burden itself
with deciding when major additions to
generation, revealed in a change in
status report, are likely to alter the
results of its market power tests. They
submit that it would not be an
unreasonable burden on Category 2
sellers to prepare updated analyses
within a reasonable time from the
acquisition of additional generation.
Commission Determination
504. In the Final Rule, the
Commission stated that it retains the
tools necessary to ensure that all rates
are just and reasonable, with initial
market power evaluations, ongoing
monitoring by the Commission, change
in status reporting requirements, and
scheduled updated market power
analyses for Category 2 sellers.846 We
continue to believe that these
requirements provide the Commission
with the tools it needs to ensure that
rates remain just and reasonable.
In Order No. 652, the Commission
clarified and standardized market-based
rate sellers’ reporting requirement for
changes in status and the Commission
considered and rejected the idea that
change in status filings include an
updated market power analysis. The
Commission explained that it is
incumbent on an applicant to decide
whether a change in status is a material
change and that an applicant should
provide adequate support and analysis,
including an updated market power
analysis if it chooses.847 Thus, if a
market-based rate seller believes that a
change in status does not affect the
continuing basis of the Commission’s
grant of market-based rate authority, it
should clearly state the reasons on
which it bases this conclusion,
including an updated market power
analysis if it so chooses.
505. While we appreciate TDU
Systems’ proposal and agree that it
would not necessarily be an
unreasonable burden to require Category
2 sellers to prepare updated analyses
within a reasonable time from the
acquisition of additional generation, we
are not persuaded that our current
approach is not adequate. The existing
reporting requirement provides the
845 Id. at 4–5 (citing K N Energy, Inc. v. FERC, 968
F.2d 1295, 1303 (D.C. Cir. 1991)).
846 Order No. 697 at P 853–854.
847 Order No. 652, FERC Stats. & Regs. ¶ 31,175
at P 94–95.

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
Commission a sufficient tool to allow it
to assess whether there is a potential
market power concern and, if so, the
Commission reserves the right to require
the seller to submit a market power
study. In addition, the seller is required
to provide an affirmative statement as to
what effect, if any, the added generation
has on its market power. For a seller to
make such an affirmative statement, it
must determine what effect the added
generation has on the market power
analysis. To the extent the seller makes
an affirmative statement that there is no
effect on its market power, it is bound
to that statement and faces remedial
action, including civil penalties, if it has
misrepresented the effect.
506. Therefore, we will not require
entities to automatically file an updated
market power analysis with their change
in status filings, such as that required by
a triennial review. However, an entity
may provide such an analysis if it
chooses. Furthermore, regardless of the
seller’s representation, if the
Commission has concerns with a change
in status filing (for example, market
shares are below 20 percent, but are
relatively high nonetheless), the
Commission retains the right to require
an updated market power analysis at
any time.848
b. Transmission Outages

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Final Rule
507. The Final Rule adopted the
NOPR proposal not to require the
reporting of transmission outages per se
as a change in status. The Commission
explained that the reporting of all
transmission outages, including the
most routine, would be an excessive
burden on sellers with no apparent
countervailing benefit. However, the
Final Rule stated that, consistent with
Order No. 652, to the extent that a longterm transmission outage affects one or
more of the factors of the Commission’s
market-based rate analysis (e.g., if it
reduces imports of capacity by
competitors that, if reflected in the
generation market power screens, would
change the results of the screens from a
‘‘pass’’ to a ‘‘fail’’), a change in status
filing is required.849
Requests for Rehearing
508. Wisconsin Electric requests that
the Commission clarify which entity is
responsible for reporting long-term
transmission outages as a change in
status. Wisconsin Electric explains that
companies such as itself that do not
own transmission may not be in the
position of knowing the details of
848 Order
849 Order

No. 697 at P 856–857.
No. 697 at P 1025.

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transmission outages and the effects of
an outage on their market power
analyses. Therefore, Wisconsin Electric
requests that the Commission clarify
that non-transmission owning entities
such as itself need not report long-term
outages.850
Commission Determination
509. The Final Rule did not expand
the events that trigger a change in status
filing to include actions taken by a
competitor (such as a decision to take
transmission capacity out of service),
beyond those adopted in Order No. 652.
Furthermore, the Commission found
that it is not reasonable to routinely
require sellers to make a showing
regarding potential barriers to entry that
others might erect or are beyond the
seller’s control.851 Thus, as a general
matter, a transmission outage that
occurs beyond a seller’s control does not
necessarily trigger a change in status
filing.852 In certain circumstances,
however, a seller, including a nontransmission owning entity, will be
required to submit a change in status
filing, as stated above,853 when it or its
affiliate know that a long-term
transmission outage has an effect on its
market power analysis (e.g., the longterm transmission outage causes the
seller to fail one or more of the
indicative screens).
c. Other Clarifications
510. Below we provide a number of
other clarifications regarding the change
in status reporting requirement.
Although no clarifications or rehearing
requests were submitted on these
particular issues, the Commission is
aware of some confusion in the industry
and accordingly provides clarification.
Change in Status Reporting by Market
511. As codified in § 35.42 of the
Commission’s regulations, events that
constitute a change in status include,
among other things, changes in
ownership or control of generation
capacity that result in net increases of
100 MW or more.854
512. We clarify that a change in status
should be filed to reflect a change in the
ownership or control of generation
capacity that results in a net increase of
100 MW or more in the geographic
850 Wisconsin

Electric at 4–5.
No. 697 at P 1035.
852 We clarify that, to the extent the Commission
becomes aware of a possible barrier to entry such
as a long-term transmission outage, the Commission
reserves the right to require any market-based rate
seller to demonstrate what effect, if any, that barrier
to entry has on its ability to exercise market power.
853 Order No. 652, FERC Stats. & Regs. ¶ 31,175
at P 75.
854 Id. at P 68.
851 Order

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25909

market that was the subject of the
horizontal market power analysis on
which the Commission relied in
granting the seller market-based rate
authority. For example, if the
Commission relied on a seller’s default
geographic market in granting the seller
market-based rate authority, the seller
would be required to submit a change in
status filing for a net increase of 100
MW or more of generation capacity in
that geographic market. Similarly, if the
Commission relied upon an alternative
geographic market in granting a seller
market-based rate authority, any net
increase of 100 MW or more of
generation capacity in the alternative
geographic market would require the
seller to submit a change in status filing.
On the other hand, if a seller has a net
increase of 50 MW in the geographic
market on which the Commission relied
in granting the seller market-based rate
authority and a 50 MW increase in a
different geographic market that is in
the same region as defined by Appendix
D of Order No 697, the 100 MW or more
threshold would not be met because the
increase in generation capacity is less
than 50 MW in each generation market
and, accordingly, a change in status
filing would not be required.
Change in Status Reporting
Cumulatively
513. A seller must submit an initial
application to receive market-based rate
authority and file change in status
filings in compliance with its marketbased rate authority, such as an increase
of 100 MW or more in a geographic
market. However, in the course of
processing change in status filings made
by sellers, the Commission believes that
it has not been clear to some sellers that
increases in generation should be
reported cumulatively. For example,
some sellers have submitted a series of
change in status reports that consider
only the additional capacity on a
standalone basis rather than considering
the total effect of each generation
capacity increase since the seller’s last
market power analysis. When a seller
submits a change in status filing to
report an increase of 100 MW or more
of generation capacity in a geographic
market, rather than treating each
increase in generation capacity on a
standalone basis, the seller should
consider the cumulative effect of all
increases in generation capacity since
its most recently approved market
power analysis.
514. For example, if a seller acquires
generation capacity resulting in a net
increase of 100 MW in a market in
January, it is required to submit a
change in status filing reflecting this net

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increase. However, if the seller adds an
additional 100 MW of generation in the
same market in February, the seller
must account for a cumulative total of
200 MW in that market when submitting
its change in status filing for the
February addition of generation
capacity. This cumulative net increase
since a seller’s most recently approved
market power analysis must be the basis
of the seller’s change in status to reflect
that it does or does not depart from the
characteristics the Commission relied
on in authorizing sales at market-based
rates.
2. Third Party Providers of Ancillary
Services
Final Rule

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515. In the Final Rule, the
Commission modified its approach for
third-party sellers of ancillary services
at market-based rates as announced in
Avista.855 The Commission noted that
the posting and reporting requirements
imposed in Avista may be hindering the
development of ancillary services
markets, particularly by third-party
providers. Thus, the Commission
concluded that the EQR filing
requirement provides an adequate
means to monitor ancillary services
sales by third parties such that the
posting and reporting requirements
established in Avista are no longer
necessary.856
516. In the Final Rule, the
Commission stated that all sellers that
seek authority to sell ancillary services
at market-based rates pursuant to
Avista 857 must make a filing with the
Commission to request that authority
and must include language in their
market-based rate tariffs identifying the
855 Order No. 697 at P 1058. See Avista
Corporation, 87 FERC ¶ 61,223 (Avista), order on
reh’g, 89 FERC ¶ 61,136 (Avista II) (1999).
856 With this modification adopted in the Final
Rule of eliminating the specific posting and
reporting requirements established in Avista for
third-party sellers of ancillary services, the
Commission expects to monitor ancillary services
sales by third parties through the EQR. In a notice
seeking comments on proposed revisions to the
EQR Data Dictionary, Revised Public Utility Filing
Requirements for Electric Quarterly Reports, 122
FERC ¶ 61,194 (2008), the Commission is seeking
comment on proposed changes that would clarify
that the ancillary services discussed in Avista must
be reported whenever those services are provided.
Under the proposed revisions, when a seller makes
third-party sales of ancillary services, that seller
would be required to file, in its EQR, transaction
information including (but not limited to) the
purchaser, the ancillary service provided, and the
price of the service. (See http://www.ferc.gov/docsfiling/eqr.asp for more information on EQR filings).
857 The Avista policy applies to the following four
ancillary services: Regulation Service, Energy
Imbalance Service, Spinning Reserves, and
Supplemental Reserves.

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ancillary services that they offer.858
Moreover, the Final Rule retained the
Commission’s current policy of not
allowing sales of ancillary services by a
third-party supplier in the following
situations: (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.859 Standard applicable tariff
provisions to this affect appear in
Appendix C of the Final Rule and must
be included in the tariffs of any entities
that sell ancillary services at marketbased rates. The Commission reiterated
that it is open to considering requests
for market-based rate authorization to
make such sales on a case-by-case
basis.860
Requests for Rehearing
517. Wisconsin Electric requests that
the Commission clarify that its decision
to eliminate the posting and reporting
requirements of Avista extends to
providers of ancillary services that
provide ancillary services other than the
four services addressed in Avista.861
Wisconsin Electric states that it is a
third-party provider of ancillary services
and received Commission authorization
to offer the four services addressed in
Avista, but it also received the
authorization to offer Dynamic Capacity
and Energy Service as an ancillary
service, conditioned upon the
requirements in Avista to establish and
maintain an Internet-based site and to
file periodic reports describing the
company’s activities in the ancillary
services markets.862 Wisconsin Electric
requests that the Commission clarify
that the decision to remove the Avista
posting and reporting requirements
pertains not only to the four ancillary
services specifically mentioned in
Avista, but also to the other ancillary
services to which the Commission
858 Order No. 697 at P 1060. Sellers that have
been granted authority to provide third-party
ancillary services need not reapply because their
authority continues.
859 Order No. 697 at P 1061 (citing Avista, 87
FERC ¶ 61,223 at 61,883, n. 12).
860 Id.
861 Wisconsin Electric Rehearing Request at 3.
862 Id. at 4 (citing Wisconsin Electric Power Co.,
93 FERC ¶ 61,302 (2000)).

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subsequently applied the Avista
requirements.863
518. Morgan Stanley seeks to clarify
its own request to the Commission to
identify ways to encourage more robust
ancillary services markets outside of
RTO/ISO control areas. Morgan Stanley
states that its request was intended to
support the creation of physicallysettled bilateral ancillary services
markets, not a market for financiallysettled products that are beyond the
Commission’s jurisdiction.864
519. Furthermore, Morgan Stanley
clarifies that it continues to regard the
creation of a robust bilateral market for
physically-settled ancillary services,
particularly outside of ISOs and RTOs,
as the next step to facilitating greater
competition in the wholesale energy
markets overall. It did not, however,
provide details for specific ancillary
services proposals, other than the
elimination of the Avista posting
requirement, because its comments were
intended solely to show support for a
policy position. Thus, Morgan Stanley
reaffirms its prior request that the
Commission continue to look for
opportunities to jump-start competition
in the physical ancillary services
markets throughout the United
States.865
Commission Determination
520. We will grant Wisconsin
Electric’s request for clarification. As
the Commission stated in the Final
Rule, the ancillary services addressed in
Avista are Regulation Service, Energy
Imbalance Service, Spinning Reserves,
and Supplemental Reserves. In Avista
however, the Commission also
characterized Dynamic Capacity and
Energy Service as an ancillary service
stating it is a combination of two
ancillary services, Regulation Service
and Energy Imbalance Service, and is
intended to satisfy the transmission
provider’s option to allow customers to
supply ancillary services to the system
directly. As such, Dynamic Capacity
and Energy Service is an approved
ancillary service conditioned upon the
requirements and limitations of
Avista.866 Similarly, in Wisconsin
Electric Power Co., the Commission
authorized Wisconsin Electric to
provide Dynamic Capacity and Energy
Service as an ancillary service
conditioned upon Avista.867
521. Therefore, because Dynamic
Energy and Capacity Service, as
863 Id.
864 Morgan

Stanley Rehearing Request at 1, 4.
at 5.
866 Avista II, 89 FERC ¶ 61,136 at 61,392.
867 Wisconsin Electric Power Co., 93 FERC
¶ 61,302 (2000).
865 Id.

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described in Avista, was authorized by
the Commission as an ancillary service
pursuant to the Avista policy, consistent
with the Final Rule, such sellers may
continue to sell this ancillary service at
market-based rates and are no longer
required to meet the Avista posting and
reporting requirements with regard to
this service. The current EQR Data
Dictionary does not include Dynamic
Energy and Capacity Service in the
standard list of products because this
service is only offered by a few
companies. However, the Commission
invited comments on adding new
ancillary service names in Docket No.
RM01–8–009.868 Absent the addition of
a specific EQR Product Name, sellers
offering this service must report it as an
‘‘Other’’ product in both the contract
and transaction sections of their EQR.
522. We appreciate Morgan Stanley’s
clarification of its intent to support the
creation of physically-settled bilateral
ancillary services markets but the
formation of such markets is beyond the
scope of this proceeding.

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3. Requesting Market-Based Rate
Authority for QFs
523. The Final Rule amended the
Commission’s regulations governing
market-based rate authorizations for
wholesale sales of electric energy,
capacity and ancillary services by
public utilities. Although the Final Rule
did not address the specific
applicability of market-based rate
authority to QFs, below we address
sales by QFs at market-based rates that
are subject to the Commission’s
jurisdiction.
524. QFs making certain sales of
energy,869 as defined below, are exempt
from sections 205 and 206 of the FPA.
These QF exemptions are applicable to
some sales at market-based rates.870
Therefore, sales of a QF that meet
specific criteria are exempt from section
205 and a QF is authorized to make
those sales at market-based rates
without making a section 205 filing.
525. All sales of energy or capacity
made by QFs 20 MW or smaller are
exempt from section 205. Sales from a
QF larger than 20 MW are exempt from
section 205 only if those sales are made
pursuant to a state regulatory authority’s
implementation of PURPA, or if those
sales are made pursuant to a contract
executed on or before March 17,
868 Revised Public Utility Filing Requirements for
Electric Quarterly Reports, 73 FR 12983 (Mar. 11,
2008), FERC Stats. & Regs. ¶ 35,557 (Mar. 3, 2008)
(seeking comments on proposed revisions to EQR
Data Dictionary).
869 In the context of PURPA, the term energy
includes capacity, energy and ancillary services.
870 See 18 CFR 292.601(c)(1).

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2006 871 (unless the sale is from a
qualifying small power production
facility with a power production
capacity which exceeds 30 MW, if such
facility uses any primary energy source
other than geothermal resources, in
which case the sale is not exempt).872 If
a QF’s sales are not exempt from section
205, but the QF would like to make
sales at market-based rates, the QF is
required to request market-based rate
authority.873
526. When a QF submits an
application for market-based rate
authority, its application must fulfill the
requirements in Order No. 697, as
required by all applicants. A QF,
however, must also inform the
Commission in its market-based rate
application of its QF status and explain
its request to transact under marketbased rates. For example, a QF must
explain whether any of its sales meet
the requirements for the exemption from
section 205 contained in 18 CFR
292.601(c)(1). Furthermore, if a QF
desires to make certain energy sales at
market-based rates, while making other
sales exempt from section 205, the QF
must list its limitations on sales at
market-based rates in its market-based
rate tariff (i.e., sales under Seller’s
contract (Contract X), which was
executed on March 17, 2006, are exempt
from section 205 and sales outside of
Contract X would be under marketbased rates) and cite to the Commission
orders certifying or recertifying its QF
status, and/or to the docket numbers in
which it self-certified or self-recertified
its QF status, as explained in Order No.
697.874
H. Clarifications of the Commission’s
Regulations
527. The Commission finds, based on
its further consideration of the
regulations, that several provisions
should be changed to provide additional
clarity.
528. First, one of the affiliate
restrictions codified in the Final Rule
contained some minor omissions.
Section 35.39(b) restricts sales between
a franchised public utility with captive
871 Id.
872 18 CFR 292.601(b). However, a qualifying
facility that is an eligible solar, wind, waste, or
geothermal facility, as defined by section 3(17)(E)
of the Federal Power Act, is not subject to the 30
MW size limitation imposed by 18 CFR 292.601(b).
See Cambria Cogen Company, 53 FERC ¶ 61,459
(1990).
873 We note that the Commission has previously
granted market-based rate authority to QFs that are
larger than 20 MW for sales of excess power. The
Commission has also rejected requests for marketbased rate authority from QFs that are exempt from
section 205. See, e.g., SP Newsprint, 103 FERC
¶ 61,186 (2003).
874 Order No. 697 at P 916–17.

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25911

customers and a market-regulated power
sales affiliate unless the seller first
receives Commission authorization for
the transaction under section 205 of the
FPA. Upon further review, the
Commission notes that the phrase ‘‘or
capacity’’ should be added to the term
‘‘wholesale sales of electric energy’’ to
ensure that the provision covers the
appropriate scope of affiliate sales.
Therefore, we will amend § 35.39(b)
accordingly.
529. Second, in the Final Rule, 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.
530. Upon further consideration, the
Commission recognizes that this
provision deserves additional clarity.
We take this opportunity to clarify that
a change in status also includes longterm firm capacity purchases that result
in net increases of 100 MW or more.
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.875 We believe
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.’’ 876
531. Thus, 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,
§ 35.42(a)(1) is revised 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. Because
sellers may not have been on notice that
this was the Commission’s intent, we
will not hold any sellers responsible for
failure to report such changes in status
prior to the effective date of this order,
875 See April 14 Order, 107 FERC ¶ 61,018 at P
95, 100.
876 See Order No. 697 at P 38 (emphasis added;
footnote omitted).

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which will be 30 days after issuance in
the Federal Register.
532. Third, as explained earlier in the
affiliate abuse section of this order, we
are revising the definition of captive
customers and adding a definition for
affiliate. We will revise the definition of
captive customers in § 35.36(a)(6) to
mean any wholesale or retail electric
energy customers served by a franchised
public utility under cost-based
regulation, to be consistent with the
discussion in the Affiliate Transactions
Final Rule and the definition of captive
customers adopted in that rule at 18
CFR 35.42(a)(2). The definition of
affiliate as that term is used in the
Affiliate Transactions Final Rule will be
codified at paragraph 35.36(a)(9).
533. Fourth, we are revising
§ 35.39(d)(1) to reflect the determination
to adopt a one-way information sharing
restriction. Finally, as discussed in the
vertical market power section of this
order, we are revising the definition of
inputs to electric power production to
clarify the types of coal supply that are
intended to be included in the
definition.

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III. Information Collection Statement
534. The Office of Management and
Budget (OMB) regulations require that
OMB approve certain information
collection requirements imposed by an
agency.877 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.

docket number excluding the last three
digits of this document in the docket
number field.
537. User assistance is available for
eLibrary and the FERC’s Web site during
normal business hours from FERC
Online Support at 202–502–6652 (toll
free at 1–866–208–3676) or e-mail at
ferconlinesupport@ferc.gov, or the
Public Reference Room at (202) 502–
8371, TTY (202) 502–8659. E-mail the
Public Reference Room at
public.referenceroom@ferc.gov.
V. Effective Date
538. Changes to Order No. 697
adopted in this order on rehearing will
become effective June 6, 2008.
List of Subjects in 18 CFR Part 35
Electric power rates, Electric utilities,
Reporting and recordkeeping
requirements.
By the Commission. Commissioner Kelly
concurring with a separate statement
attached.
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. 7101–7152.

2. In § 35.36, paragraphs (a)(4) and
(a)(6) are revised and paragraph (a)(9) is
added to read as follows:

■

§ 35.36

Generally.

(a) * * *
(4) Inputs to electric power
IV. Document Availability
production means intrastate natural gas
535. In addition to publishing the full transportation, intrastate natural gas
storage or distribution facilities; sites for
text of this document in the Federal
generation capacity development;
Register, the Commission provides all
physical coal supply sources and
interested persons an opportunity to
ownership of or control over who may
view and/or print the contents of this
access transportation of coal supplies.
document via the Internet through
FERC’s Home Page (http://www.ferc.gov) *
*
*
*
*
and in FERC’s Public Reference Room
(6) Captive customers means any
during normal business hours (8:30 a.m. wholesale or retail electric energy
to 5 p.m. Eastern time) at 888 First
customers served by a franchised public
utility under cost-based regulation.
Street, NE., Room 2A, Washington, DC
20426.
*
*
*
*
*
536. From FERC’s Home Page on the
(9) Affiliate of a specified company
Internet, this information is available on means:
eLibrary. The full text of this document
(i) For any person other than an
is available on eLibrary in PDF and
exempt wholesale generator:
(A) Any person that directly or
Microsoft Word format for viewing,
printing, and/or downloading. To access indirectly owns, controls, or holds with
power to vote, 10 percent or more of the
this document in eLibrary, type the
outstanding voting securities of the
877 5 CFR 1320.11.
specified company;

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(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.
(E) For purposes of paragraph (a)(9)(i),
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.
(ii) For any exempt wholesale
generator (as defined under § 366.1 of
this chapter):
(A) Any person that directly or
indirectly owns, controls, or holds with
power to vote, 5 percent or more of the
outstanding voting securities of the
specified company;
(B) Any company 5 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 individual who is an officer
or director of the specified company, or
of any company which is an affiliate
thereof under paragraph (a)(9)(ii)(A);
and
(D) 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.
*
*
*
*
*
■ 3. In § 35.39, paragraphs (b) and (d)(1)
are revised to read as follows:
§ 35.39

Affiliate restrictions.

*

*
*
*
*
(b) Restriction on affiliate sales of
electric energy or capacity. As a
condition of obtaining and retaining
market-based rate authority, no
wholesale sale of electric energy or
capacity may be made between a
franchised public utility with captive
customers and a market-regulated power
sales affiliate without first receiving

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
Commission authorization for the
transaction under section 205 of the
Federal Power Act. All authorizations to
engage in affiliate wholesale sales of
electric energy or capacity must be
listed in a Seller’s market-based rate
tariff.
*
*
*
*
*
(d) Information sharing.
(1) A franchised public utility with
captive customers may not share market
information with a market-regulated
power sales affiliate if the sharing could

be used to the detriment of captive
customers, unless simultaneously
disclosed to the public.
*
*
*
*
*
■ 4. In § 35.42, paragraph (a)(1) is
revised to read as follows:
§ 35.42 Change in status reporting
requirement.

(a) * * *
(1) Ownership or control of generation
capacity and long-term firm purchases
of generation capacity that result in net

increases of 100 MW or more, or of
inputs to electric power production, or
ownership, operation or control of
transmission facilities, or
*
*
*
*
*
5. Appendix A of subpart H is revised
to read as follows:

■

Appendix A to Subpart H
Appendix A
Standard Screen Format
(Data provided for Illustrative Purposes only)

PART I.—PIVOTAL SUPPLIER ANALYSIS
Row

Generation

MW

Reference

Seller and Affiliate Capacity
A
B
C
D

...........
...........
...........
...........

Installed Capacity ........................................................................................................................
Long-Term Firm Purchases .........................................................................................................
Long-Term Firm Sales .................................................................................................................
Imported Power ...........................................................................................................................

19,500
500
¥1,000
0

Workpaper.
Workpaper.
Workpaper.
Workpaper.

Installed Capacity ........................................................................................................................
Long-Term Firm Purchases .........................................................................................................
Long-Term Firm Sales .................................................................................................................
Imported Power ...........................................................................................................................
Balancing Authority Area Reserve Requirement ........................................................................
Amount of Line I Attributable to Seller, if any .............................................................................
Total Uncommitted Supply (SUM A,B,C,D,E,F,G,H,I,M) ............................................................

8,000
500
¥2,500
3,500
¥2,160
¥2,160
9,840

Workpaper.
Workpaper.
Workpaper.
Workpaper.
Workpaper.
Workpaper.

Balancing Authority Area Annual Peak Load ..............................................................................
Average Daily Peak Native Load in Peak Month ........................................................................
Amount of Line M Attributable to Seller, if any ...........................................................................
Wholesale Load (SUM L,M) ........................................................................................................
Net Uncommitted Supply (K–O) ..................................................................................................
Seller’s Uncommitted Capacity (SUM A,B,C,D,J,N) ...................................................................
Result of Pivotal Supplier Screen (Pass if Line Q < Line P), (Fail if Line Q > Line P) ..............

18,000
¥16,500
¥16,500
1,500
8,340
340
....................

Workpaper.
Workpaper.
Workpaper.

Non-Affiliate Capacity
E ...........
F ...........
G ..........
H ...........
I ............
J ...........
K ...........
Load
L ...........
M ..........
N ...........
O ..........
P ...........
Q ..........

Note: The following appendices will not be
published in the Code of Federal
Regulations.
Appendix C to Order No. 697–A

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Required Provisions of the Market-Based
Rate Tariff
Compliance With Commission Regulations
Seller shall comply with the provisions of
18 CFR part 35, Subpart H, as applicable, and
with any conditions the Commission imposes
in its orders concerning seller’s market-based
rate authority, including orders in which the
Commission authorizes seller to engage in
affiliate sales under this tariff or otherwise
restricts or limits the seller’s market-based
rate authority. Failure to comply with the
applicable provisions of 18 CFR part 35,
Subpart H, and with any orders of the
Commission concerning seller’s market-based
rate authority, will constitute a violation of
this tariff.
Limitations and Exemptions Regarding
Market-Based Rate Authority
[Seller should list all limitations (including
markets where seller does not have market-

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based rate authority) on its market-based rate
authority and any exemptions from or
waivers granted of Commission regulations
and include relevant cites to Commission
orders].
Seller Category
Seller Category: Seller is a [insert Category
1 or Category 2] seller, as defined in 18 CFR
35.36(a).
Include All of the Following Provisions That
Are Applicable
Mitigated Sales
Sales of energy and capacity are
permissible under this tariff in all balancing
authority areas where the Seller has been
granted market-based rate authority. Sales of
energy and capacity under this tariff are also
permissible at the metered boundary between
the Seller’s mitigated balancing authority
area and a balancing authority area where the
Seller has been granted market-based rate
authority provided: (i) Legal title of the
power sold transfers at the metered boundary
of the balancing authority area; (ii) the
mitigated seller and its affiliates do not sell
the same power back into the balancing

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PASS.

authority area where the seller is mitigated.
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

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
to others that are self-supplying ancillary
services to the CAISO.
Third Party Provider
Third-party ancillary services: Seller offers
[include all of the following that the seller is
offering: Regulation Service, Energy
Imbalance Service, Spinning Reserves, and
Supplemental Reserves]. Sales will not
include the following: (1) Sales to an RTO or
an ISO, i.e., where that entity has no ability
to self-supply ancillary services but instead
depends on third parties; (2) sales to a
traditional, franchised public utility affiliated
with the third-party supplier, or sales where

the underlying transmission service is on the
system of the public utility affiliated with the
third-party supplier; and (3) sales to a public
utility that is purchasing ancillary services to
satisfy its own open access transmission tariff
requirements to offer ancillary services to its
own customers.
Appendix D to Order No. 697–A
Regions and Schedule for Regional Market
Power Update Process
The six regions are combinations of NERC
regions; RTOs and ISOs and are depicted in
the map that follows.

Appendix D–1

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ER07MY08.010

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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

Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations

25915

SCHEDULE FOR TRANSMISSION OWNING UTILITIES WITH MARKET-BASED RATE AUTHORITY AND THEIR AFFILIATES IN THE
SAME REGION
Entities required to file

Filing period (anytime
during the month)

Northeast Transmission Owners ......................................
Southeast Transmission Owners ......................................
Central Transmission Owners ..........................................
SPP Transmission Owners ...............................................
Southwest Transmission Owners .....................................
Northwest Transmission Owners ......................................
Northeast Transmission Owners ......................................
Southeast Transmission Owners ......................................
Central Transmission Owners ..........................................
SPP Transmission Owners ...............................................
Southwest Transmission Owners .....................................
Northwest Transmission Owners ......................................

December, 2007 .................
June, 2008 .........................
December, 2008 .................
June, 2009 .........................
December, 2009 .................
June, 2010 .........................
December, 2010 .................
June, 2011 .........................
December, 2011 .................
June, 2012 .........................
December, 2012 .................
June, 2013 .........................

Study period
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.
Dec.

1,
1,
1,
1,
1,
1,
1,
1,
1,
1,
1,
1,

2005–Nov.
2005–Nov.
2006–Nov.
2006–Nov.
2007–Nov.
2007–Nov.
2008–Nov.
2008–Nov.
2009–Nov.
2009–Nov.
2010–Nov.
2010–Nov.

30,
30,
30,
30,
30,
30,
30,
30,
30,
30,
30,
30,

2006.
2006.
2007.
2007.
2008.
2008.
2009.
2009.
2010.
2010.
2011.
2011.

Appendix D–2

SCHEDULE FOR ALL OTHER ENTITIES
Filing period
(anytime during
the month)

Entities required to file
All others in Northeast that did not file in December including all power marketers
that sold in the Northeast.
All others in Southeast that did not file in June including all power marketers that sold
in the Southeast and have not already been found to be Category 1 sellers.
All others in Central that did not file in December including all power marketers that
sold in the Central and have not already been found to be Category 1 sellers.
All others in SPP that did not file in June including all power marketers that sold in
SPP and have not already been found to be Category 1 sellers.
Others in Northeast that did not file in December and have not been found to be Category 1 sellers.
Others in Southeast that did not file in June and have not been found to be Category
1 sellers.
Others in Central that did not file in December and have not been found to be Category 1 sellers.
Others in SPP that did not file in June and have not been found to be Category 1
sellers.
Others in Southwest that did not file in December and have not been found to be
Category 1 sellers.
Others in Northwest that did not file in June and have not been found to be Category
1 sellers.

Study period

June, 2008 ...............

Dec. 1, 2005–Nov. 30, 2006.

December, 2008 ......

Dec. 1, 2005–Nov. 30, 2006.

June, 2009 ...............

Dec. 1, 2006–Nov. 30, 2007.

December, 2009 ......

Dec. 1, 2006–Nov. 30, 2007.

June, 2011 ...............

Dec. 1, 2008–Nov. 30, 2009.

December, 2011 ......

Dec. 1, 2008–Nov. 30, 2009.

June, 2012 ...............

Dec. 1, 2009–Nov. 30, 2010.

December, 2012 ......

Dec. 1, 2009–Nov. 30, 2010.

June, 2013 ...............

Dec. 1, 2010–Nov. 30, 2011.

December, 2013 ......

Dec. 1, 2010–Nov. 30, 2011.

Appendix E to Order No. 697–A

PETITIONER ACRONYMS
Abbreviation

Petitioner names

Ameren .................................
APPA/TAPS .........................
Attorneys General of Connecticut and Illinois.
Consumer Advocates ...........

Ameren Services Company.
American Public Power Association/Transmission Access Policy Study Group.
Richard Blumenthal, Attorney General for the State of Connecticut and the People of the State of Illinois, by and
through the Illinois Attorney General Lisa Madigan.
Attorneys General of New Mexico and Rhode Island, Colorado Office of Consumer Counsel, Utah Committee of
Consumer Services, Public Utility Law Project of NY, and Public Citizen, Inc.
Edison Electric Institute.
El Paso E&P Company, L.P.
FirstEnergy Service Company.
Florida Power & Light Company and FPL Energy, LLC.
Coalition of Midwest Transmission Customers, PJM Industrial Customer Coalition, NEPOOL Industrial Customer
Coalition, Industrial Energy Users of Ohio, Industrial Energy Consumers of PA, Southeast Electricity Consumers Association, West Virginia Energy Users Group, and Southwest Industrial Customer Coalition.
Long-Term Sellers.
MidAmerican Energy Company and Cordova Energy Company LLC.
Montana Consumer Counsel.
Morgan Stanley Capital Group Inc.
National Association of State Utility Consumer Advocates.

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EEI ........................................
El Paso E&P ........................
FirstEnergy ...........................
FP&L ....................................
Industrial Customers ............
LT Sellers .............................
MidAmerican ........................
Montana Counsel .................
Morgan Stanley ....................
NASUCA ..............................

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Federal Register / Vol. 73, No. 89 / Wednesday, May 7, 2008 / Rules and Regulations
PETITIONER ACRONYMS—Continued

Abbreviation
NRECA .................................
NYISO ..................................
NRG .....................................
Occidental ............................
OG&E ...................................
Pinnacle ................................
PPM ......................................
PSEG Companies ................
Reliant ..................................
Southern ...............................
TDU Systems .......................
Wisconsin Electric ................

Petitioner names
National Rural Electric Cooperative Association.
New York Independent System Operator, Inc.
NRG Energy, Inc.
Occidental Power Marketing, L.P.
Oklahoma Gas and Electric Company and OGE Energy Resources, Inc.
Pinnacle West Companies.
PPM Energy, Inc.
Public Service Electric and Gas Company, PSEG Power LLC, and PSEG Energy Resources & Trade LLC.
Reliant Energy, Inc.
Southern Company Services, Inc.
Transmission Dependent Utilities Systems.
Wisconsin Electric Power Company.

UNITED STATES OF AMERICA

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FEDERAL ENERGY REGULATORY
COMMISSION
18 CFR Part 35
[Docket No. RM04–7–001; Order No. 697–A]
Market-Based Rates for Wholesale Sales of
Electric Energy, Capacity and Ancillary
Services by Public Utilities
(Issued April 21, 2008)
KELLY, Commissioner, concurring:
Among other decisions in Order No. 697–
A, the Commission has, on rehearing,
determined that it will entertain applications
that permit a mitigated seller to sell under a
long-term contract at market-based rates.
Specifically, we will allow a mitigated seller
to demonstrate, on a case-by-case basis, that
it does not have market power with respect
to a specific long-term contract. I believe that
if executed properly, allowing a mitigated
seller the opportunity to demonstrate that,
with respect to a specific contract, it does not
have market power could be a useful and

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productive means for spurring competition
and long-term contracting.
Ideally, I believe the Commission should
apply an ordered, transparent and
predictable test to each mitigated seller’s
application. Such a test should include an
examination of barriers to entry, structural or
otherwise. New entrants bring new capacity
that, in theory at least, should exert
downward pressure on prices. Our decision
here hinges on the hypothesis that, absent
barriers to new entrants, long-term markets
may be presumed to be competitive.
Ultimately, I would like to see the
Commission confirm that hypothesis using
the aforementioned test on a case-by-case
basis.
Until such time as we have developed such
a test, however, we have decided that the
case-by-case approach described in this order
allows the Commission to examine these
applications with the appropriate rigor. The
mitigated seller will have to show that a
buyer under a long-term contract has viable
alternatives, including the entry of third-

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party newly-constructed resources during the
relevant future period as an alternative to
purchasing under the contract at issue. I
would prefer that mitigated sellers, in their
applications, include an identified buyer. I
believe the presence of an identified buyer
will ensure that any assessment of the
application is confined to a set of
circumstances specific to the transaction,
thereby avoiding the potential for granting a
more general market-based rate authority to
a mitigated seller for a particular area and
period of time. I do not believe that such an
outcome would be helpful to or consistent
with our goals of promoting competition.
As the Commission moves forward, I
anticipate relying on the views and expertise
of interested parties in developing a specific
test to apply to each case.
For these reasons, I respectfully concur
with this order.
Suedeen G. Kelly.
[FR Doc. E8–9073 Filed 5–6–08; 8:45 am]
BILLING CODE 6717–01–C

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