[Federal Register Volume 73, Number 89 (Wednesday, May 7, 2008)]
[Rules and Regulations]
[Pages 25832-25916]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E8-9073]



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Part II





Department of Energy





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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

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

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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.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Order on Rehearing and Clarification.

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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.

DATES: 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: 

Table of Contents

 
                                                               Paragraph
                                                                numbers
 
I. Introduction.............................................           1
II. Discussion..............................................          16
    A. Horizontal Market Power..............................          16
        1. Whether to Retain the Indicative Screens.........          16
        2. Indicative Market Share Screen Threshold Levels..          31
        3. DPT Criteria.....................................          42
        4. Other Products and Models........................          52
        5. Native Load Deduction............................          60
        6. Relevant Geographic Market.......................          68
        7. Use of Historical Data...........................         116
        8. Transmission Imports.............................         132
        9. Further Guidance Regarding Control and Commitment         147
         of Capacity........................................
    B. Vertical Market Power................................         151
        1. OATT Violations and Market-Based Rate Revocation.         151
        2. Treatment of FTRs................................         163
        3. Other Barriers to Entry..........................         166
    C. Affiliate Abuse......................................         181
        1. General Affiliate Terms & Conditions.............         182
        2. Power Sales Restrictions.........................         223
        3. Market-Based Rate Affiliate Restrictions.........         233
    D. Mitigation...........................................         260
        1. Cost-Based Rate Methodology......................         260
        2. Protecting Markets With Mitigated Sellers........         294
    E. Implementation Process...............................         341
        1. Category 1 and 2 Sellers.........................         343
        2. Regional Review and Schedule.....................         363
        3. Clarifications on Implementation Process.........         373
        4. Market-Based Rate Tariff Clarifications..........         383
    F. Legal Authority......................................         395
        1. Whether Market-Based Rates Can Satisfy the Just           395
         and Reasonable Standard Under the FPA..............
        2. Consistency of Market-Based Rate Program with FPA         435
         Filing Requirements................................
        3. Whether Existing Tariffs Must Be Found To Be              497
         Unjust and Unreasonable, and Whether the Commission
         Must Establish a Refund Effective Date.............
    G. Miscellaneous........................................         501
        1. Change in Status.................................         501
        2. Third Party Providers of Ancillary Services......         516
        3. Requesting Market-Based Rate Authority for QFs...         524
    H. Clarifications of the Commission's Regulations.......         528
III. Information Collection Statement.......................         535
IV. Document Availability...................................         536
V. Effective Date...........................................         539
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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Before Commissioners: Joseph T. Kelliher, Chairman; Suedeen G. Kelly, 
Marc Spitzer, Philip D. Moeller, and Jon Wellinghoff.

I. Introduction

    1. On June 21, 2007, the Federal Energy Regulatory Commission 
(Commission) issued Order No. 697,\1\ codifying and, in certain 
respects, revising its standards for obtaining and retaining market-
based rates for public utilities. In order to accomplish this, as well 
as streamline the administration of the market-based rate program, the 
Commission modified its regulations at 18 CFR part 35, subpart H, 
governing market-based rate authorization. The Commission explained 
that there are three major aspects of its market-based regulatory 
regime: (1) Market power analyses of sellers and associated conditions 
and filing requirements; (2) market rules imposed on sellers that 
participate in Regional Transmission Organization (RTO) and Independent 
System Operator (ISO) organized markets; and (3) ongoing oversight and 
enforcement activities. The Final Rule focused on the first of the 
three features to ensure that market-based rates charged by public 
utilities are just and reasonable. Order No. 697 became effective on 
September 18, 2007.
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    \1\ Market-Based Rates for Wholesale Sales of Electric Energy, 
Capacity and Ancillary Services by Public Utilities, Order No. 697, 
72 FR 39,904 (Jul. 20, 2007), FERC Stats. & Regs. ] 31,252 (2007) 
(Final Rule).
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    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 
market-based rate tariffs in addition to the standard provisions listed 
in Appendix C to Order No. 697. The Commission also extended the 
deadline for sellers to file the first set of regional triennial 
studies that were directed in Order No. 697 from December 2007 to 30 
days after the date of issuance of the Clarification Order.
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    \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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    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 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 case-by-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 (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.
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    \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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    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

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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 market-based 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 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\
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    \4\ Order No. 697 at P 62.
    \5\ Id. P 33, 35.
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    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\
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    \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, 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.
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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\
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    \7\ Id. P 41.
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    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 off-peak periods.'' \9\ Additionally, the

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Commission noted that the contestable load analysis fails to consider 
the relative price of the competing supplies and thus whether the 
available non-applicant supply is competitively priced and, hence, in 
the market.\10\
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    \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.
    \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.
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Requests for Rehearing
    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 sellers, and are incapable of providing substantial evidence 
of market power.
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    \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); Hunt-Wesson 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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    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\
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    \15\ Id. at 11.
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    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 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.
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    \16\ Id. 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.
    \20\ Id. at 15 and Frame affidavit at ] 25, referring to Order 
No. 697 at P 66-67.
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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

[[Page 25836]]

Commission is not unlawfully shifting the burden of proof to the seller 
that fails one of the screens.
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    \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 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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    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 market-based 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 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.
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    \22\ See Order No. 697 at P 65.
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    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 market-based 
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.
---------------------------------------------------------------------------

    \23\ Id. P 62.
    \24\ Id. P 71.
---------------------------------------------------------------------------

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

    \25\ Id. P 135.
    \26\ Id. P 137.
---------------------------------------------------------------------------

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

    \27\ Southern Rehearing Request at 11.
---------------------------------------------------------------------------

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

    \28\ We further address Southern's arguments with regard to the 
DPT analysis below.
---------------------------------------------------------------------------

    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

[[Page 25837]]

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

    \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.
    \32\ Id. P 66.
    \33\ Id.
---------------------------------------------------------------------------

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

    \34\ Id. P 89.

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

    \35\ Id. P 91.
---------------------------------------------------------------------------

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

    \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 (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.
---------------------------------------------------------------------------

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

    \38\ The Final Rule cited section 4.134, stating ``[t]he 20 
percent threshold is consistent with Sec.  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.
---------------------------------------------------------------------------

    35. Southern also argues on rehearing that section 2 of the Sherman 
Antitrust Act, which prohibits not only actual

[[Page 25838]]

monopolization but also attempted monopolization and conspiracy to 
monopolize, has spawned a well-established 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\
---------------------------------------------------------------------------

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

    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. 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 long-term 
energy sales at rates indexed to spot market prices.
---------------------------------------------------------------------------

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

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

    \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).
    \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 Meta-
analysis of Residential Electricity Demand Elasticities,'' Journal 
of Agricultural and Applied Economics, 36:1, at 65-81 (April 2004).
---------------------------------------------------------------------------

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

    \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 Merger Guidelines, reprinted in Trade Reg. 
Rep. ] 13,103 (CCH 1988) (footnote omitted).


[[Page 25839]]


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

    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 Non-Horizontal 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\
---------------------------------------------------------------------------

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

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

    \51\ Southern Rehearing Request at 22-23.
    \52\ See supra n.46.
---------------------------------------------------------------------------

    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\ 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 non-existent. 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.
---------------------------------------------------------------------------

    \53\ ``If collective action is necessary for the exercise of 
market power, as the number of firms 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).
---------------------------------------------------------------------------

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

    \54\ Order No. 697 at P 13, 104, 106.
    \55\ Id. P 113.
---------------------------------------------------------------------------

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

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

    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

[[Page 25840]]

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

    \58\ TDU Systems state that ``The Final Rule fails to explain 
how the adoption of an 1,800 Herfindahl-Hirschman 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.
    \59\ Id. at 12-13 (citing Order No. 697 at P 2).
---------------------------------------------------------------------------

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

    \60\ April 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).
---------------------------------------------------------------------------

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

    \63\ Id. at 13.
---------------------------------------------------------------------------

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

    \64\ Southern Rehearing Request at 3-4, 11-16 and Frame 
Affidavit at ] 5, 21-22.
---------------------------------------------------------------------------

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

    \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.
    \68\ April 14 Order, 107 FERC ] 61,018 at P 111.
    \69\ Order No. 697 at P 113; July 8 Order, 108 FERC ] 61,026 at 
P 95-97; NOPR at P 41.
---------------------------------------------------------------------------

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

    \70\ Order No. 697 at P 66.
    \71\ Id. P 65-66.
---------------------------------------------------------------------------

    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

[[Page 25841]]

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

    \72\ Id. P 67.
---------------------------------------------------------------------------

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

    \73\ Id. P 122.

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

    \74\ Id. P 124.
---------------------------------------------------------------------------

Requests for Rehearing
    54. NASUCA argues that the Commission must investigate whether 
sellers are able to raise electricity auction market rates to higher 
non-competitive 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 Commission-approved auction markets through non-collusive 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\
---------------------------------------------------------------------------

    \75\ NASUCA Rehearing Request at 5.
    \76\ Id. at 2.
    \77\ Id. at 6.
---------------------------------------------------------------------------

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

    \78\ Id. at 7 (citing Order No. 697 at P 121, 124).
    \79\ Id. at 7 (citing Order No. 697 at P 124).
---------------------------------------------------------------------------

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

    \80\ Id. (citing Electrical Dist. No. 1 v. FERC, 774 F.2d 490, 
492-93 (D.C. Cir. 1984)).
---------------------------------------------------------------------------

    57. APPA/TAPS argue that, in addition to the existing indicative 
screens, the Commission should require 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 long-term 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 non-firm 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\
---------------------------------------------------------------------------

    \81\ APPA/TAPS Rehearing Request at 13.
    \82\ Id.
    \83\ Id. at 16.
    \84\ Id. at 17.
---------------------------------------------------------------------------

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 
Commission-approved 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

[[Page 25842]]

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 well-functioning 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\
---------------------------------------------------------------------------

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

    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 long-term 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.
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\
---------------------------------------------------------------------------

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

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

    \89\ Id. at 7.
    \90\ Id. at 8, 18.
---------------------------------------------------------------------------

    64. TDU Systems point out the Commission's explanation that the 
virtue of having the two indicative screens is that they each measure 
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\
---------------------------------------------------------------------------

    \91\ April 14 Order, 107 FERC ] 61,018 at P 90 (2004).
    \92\ TDU Systems Rehearing Request at 20.
---------------------------------------------------------------------------

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

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

    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

[[Page 25843]]

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

    \95\ Id. P 108.
    \96\ See id. P 150 (citing 18 CFR 33.3(d)(4)(i)).
---------------------------------------------------------------------------

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

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

    69. With respect to traditional (non-RTO/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\
---------------------------------------------------------------------------

    \100\ Id. P 231-32.
---------------------------------------------------------------------------

    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 PJM-East and Northern PSEG are sub-markets 
within PJM Interconnection (PJM).
---------------------------------------------------------------------------

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

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

    \102\ Id. P 238.
---------------------------------------------------------------------------

    72. The Commission stated that sellers may incorporate the 
mitigation they are subject to in RTO/ISO markets or submarkets with 
Commission-approved 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 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 market-based rate study purposes, and its existing In-City 
mitigation will be used to assess whether any concerns over market 
power are already mitigated.\104\
---------------------------------------------------------------------------

    \103\ Id. P 241.
    \104\ Id. P 242.
---------------------------------------------------------------------------

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

    \105\ TDU 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)).
---------------------------------------------------------------------------

    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

[[Page 25844]]

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

    \108\ TDU Systems Rehearing Request at 15.
---------------------------------------------------------------------------

    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 well-known 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\
---------------------------------------------------------------------------

    \109\ NRECA 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 far-
flung 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.
---------------------------------------------------------------------------

    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 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 sub-region 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 provided in Appendix D of the Final Rule.\116\
---------------------------------------------------------------------------

    \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 
* * *'')).
    \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.
    \116\ Id. at 9.
---------------------------------------------------------------------------

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

    \117\ Reliant Rehearing Request at 5-6.
---------------------------------------------------------------------------

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

    \118\ PSEG 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)).
---------------------------------------------------------------------------

    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

[[Page 25845]]

mitigation programs in place in conjunction with a regional 
transmission expansion planning program.
---------------------------------------------------------------------------

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

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

    \121\ PSEG Rehearing Request at 10, referring to Exelon Corp., 
112 FERC ] 61,011, order on reh'g, 113 FERC ] 61,299 (2005).
---------------------------------------------------------------------------

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 
physically located and, second, the markets directly interconnected to 
the seller's balancing authority area (first-tier 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 first-tier 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.
---------------------------------------------------------------------------

    \122\ Order No. 697 at P 231-232.
    \123\ Id. P 268.
---------------------------------------------------------------------------

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

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

    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 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 market-based 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

[[Page 25846]]

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

    \126\ Keystone, 151 F.3d 1096 at 1100.
    \127\ See 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 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).
---------------------------------------------------------------------------

    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 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, ``well-known'' 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.
---------------------------------------------------------------------------

    \129\ Id. P 236.
    \130\ Id.
    \131\ Id. P 267-278.
    \132\ See Pinnacle West Capital Corp., 122 FERC ] 61,035 (2008).
---------------------------------------------------------------------------

    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, 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 
market-based rate proceedings.
---------------------------------------------------------------------------

    \133\ Order No. 697 at P 238.
    \134\ NOPR at P 61; Order No. 697 at P 215.
---------------------------------------------------------------------------

    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 Exelon-PSEG 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\
---------------------------------------------------------------------------

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

    91. With regard to PJM East, however, we note that in proceedings 
other than the Exelon/PSEG merger, the

[[Page 25847]]

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

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

    92. We reject PSEG's argument that the Commission's policy 
discriminates against some market participants. In particular, PSEG 
contends that a market-based 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.
---------------------------------------------------------------------------

    \137\ Id. P 234.
---------------------------------------------------------------------------

    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 
particular, the Commission has consistently stated that the Commission-
approved 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.
---------------------------------------------------------------------------

    \138\ See Order No. 697 at P 290.
---------------------------------------------------------------------------

    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 day-ahead 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 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\
---------------------------------------------------------------------------

    \139\ See AEP Power Marketing, Inc., 97 FERC ] 61,219 (2001).
    \140\ Id. P 290.
---------------------------------------------------------------------------

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

[[Page 25848]]

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 Commission-approved 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.
---------------------------------------------------------------------------

    \141\ Reliant Rehearing Request at 2-3.
---------------------------------------------------------------------------

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

    \142\ Id. 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.
---------------------------------------------------------------------------

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

    \144\ PSEG Rehearing Request at 11-12.
---------------------------------------------------------------------------

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

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

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

    \147\ EEI Rehearing Request at 4-5.
---------------------------------------------------------------------------

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

    \148\ NRG Rehearing Request at 2.
    \149\ Id. at 3.
---------------------------------------------------------------------------

    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 state-sanctioned competitive 
procurement programs, which typically require binding bids which cannot 
be conditioned on obtaining subsequent Commission approval.\151\
---------------------------------------------------------------------------

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

    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-

[[Page 25849]]

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

    \152\  Id. at 16.
---------------------------------------------------------------------------

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

    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 burdens if revenue caps are imposed rather 
than bid caps.\156\
---------------------------------------------------------------------------

    \155\ Id. at 2, 3, 5.
    \156\ Id. at 7.
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    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 long-term transactions, including those 
negotiated on a bilateral basis, and that RTO/ISO mitigation is often 
far less protective than the Commission's cost-based 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\
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    \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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Commission Determination
    109. The Commission denies the requests of PSEG and Reliant to 
reconsider its decision to require sellers located in markets with 
Commission-approved market monitoring and mitigation to submit 
horizontal market power analyses. As we explained in Order No. 697, 
while the Commission-approved market monitoring and mitigation in RTO/
ISO markets provides protection against a seller's ability to exercise 
market power, it cannot replace 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.

[[Page 25850]]

    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 indicative screens and the DPT analysis, we will 
not impose default cost-based rate mitigation (which is used in non-
RTO/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.
---------------------------------------------------------------------------

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

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 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 market-based 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

[[Page 25851]]

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

    \160\ Montana Counsel Rehearing Request at 7.
    \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).
---------------------------------------------------------------------------

    119. Montana Counsel notes that the Final Rule distinguishes the 
market-based 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\
---------------------------------------------------------------------------

    \162\ Id. at 8-9.
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    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\
---------------------------------------------------------------------------

    \163\ Id. at 9 (citing Order No. 697 at P 25, 63 n.46).
    \164\ Id.
---------------------------------------------------------------------------

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

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

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

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

    \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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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.

[[Page 25852]]

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

    \172\ Order No. 697 at P 299.
---------------------------------------------------------------------------

    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 market-based 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 re-sold 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 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.
---------------------------------------------------------------------------

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

    128. In addition, as explained above, future changes are not 
necessarily known and measurable since a long-term 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 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\
---------------------------------------------------------------------------

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

    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

[[Page 25853]]

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

    \176\ Order No. 697 at P 354.
    \177\ 110 FERC ] 61,127 (2005).
    \178\ Order No. 697 at P 354 (internal citations omitted).
    \179\ Id. P 355.
---------------------------------------------------------------------------

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

    \180\ Id. P 364.
---------------------------------------------------------------------------

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

    \181\ Id. P 368.
---------------------------------------------------------------------------

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

    \182\ Id. P 356.
    \183\ Id. P 361.
---------------------------------------------------------------------------

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

    \184\ Id. P 384.
    \185\ Id. P 386.
---------------------------------------------------------------------------

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 double-
counted 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\
---------------------------------------------------------------------------

    \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).
    \188\ Id.
    \189\ Order No. 697 at P 364.
    \190\ APPA/TAPS Rehearing Request at 28-29.
    \191\ Id. at 29.
    \192\ Id.
---------------------------------------------------------------------------

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

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

    139. Southern argues that the Commission's ``after-the-fact'' 
examination of short-term transmission reservations to see how many 
were more

[[Page 25854]]

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 short-term 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\
---------------------------------------------------------------------------

    \197\ Id. at 33.
    \198\ Id. 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.
---------------------------------------------------------------------------

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

    \200\ Id. at 31.
    \201\ Id.
---------------------------------------------------------------------------

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

    \202\ Id. at 35.
---------------------------------------------------------------------------

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

    \203\ Order No. 697 at P 369.
    \204\ APPA/TAPS Rehearing Request at 28.
    \205\ Order No. 697 at P 364.
    \206\ APPA/TAPS Rehearing Request at 28-29.
    \207\ Id. at 29.
---------------------------------------------------------------------------

    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\

[[Page 25855]]

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-by-case basis.
---------------------------------------------------------------------------

    \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'' 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.
---------------------------------------------------------------------------

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

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

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

    \211\ Id. P 355.
---------------------------------------------------------------------------

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 fact-specific 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\
---------------------------------------------------------------------------

    \212\ Order No. 697 at P 174.
---------------------------------------------------------------------------

    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 fact-specific 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\
---------------------------------------------------------------------------

    \213\ Id. P 175.
---------------------------------------------------------------------------

    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

[[Page 25856]]

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

    \214\ Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat. 
594 (2005).
---------------------------------------------------------------------------

B. Vertical Market Power

1. OATT Violations and Market-Based Rate Revocation
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\
---------------------------------------------------------------------------

    \215\ Order No. 697 at P 417.
    \216\ Enforcement of Statutes, Orders, Rules and Regulations, 
113 FERC ] 61,068 (2005) (Enforcement Policy Statement).
    \217\ Order No. 697 at P 417.
---------------------------------------------------------------------------

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

    \218\ Id. P 418.
    \219\ Id. P 421.
---------------------------------------------------------------------------

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

    \220\ Id. P 419.
---------------------------------------------------------------------------

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 market-based 
rate authority is arbitrary, capricious, contrary to law, and in excess 
of statutory authority. NRECA also argues that the Final Rule does not 
provide clear guidance as to what would constitute a sufficient 
nexus.\221\
---------------------------------------------------------------------------

    \221\ NRECA Rehearing Request at 28 (citing Order No. 697 at P 
418).
---------------------------------------------------------------------------

    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 
market-based rate authorization of the provider or its affiliates, and 
reconsider its decision to determine what constitutes a sufficient 
factual nexus on a case-by-case 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\
---------------------------------------------------------------------------

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

    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

[[Page 25857]]

provider's conduct, i.e., whether it is anticompetitive or reflects the 
exercise of market power.\228 \
---------------------------------------------------------------------------

    \227\ Id. at 22.
    \228\ Id.
---------------------------------------------------------------------------

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

    \229\ NRECA Rehearing Request at 3, 27-29; TDU Systems Rehearing 
Request at 3-4, 20.
---------------------------------------------------------------------------

    158. NRECA asserts that when a public utility violates its OATT, 
one of the preconditions to the grant of market-based 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\
---------------------------------------------------------------------------

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

Commission Determination
    159. The Commission denies rehearing of the decision to require a 
factual nexus between a substantial OATT violation and the entity's 
market-based 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 market-based rate 
authority since the violation may have no relation to the market-based 
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 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 planning-related 
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-by-case basis if a particular 
violation puts that company at an advantage vis-[aacute]-vis its 
market-based rate authority.\233\
---------------------------------------------------------------------------

    \233\ See Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 
1037.
---------------------------------------------------------------------------

    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 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 market-based 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

[[Page 25858]]

resale of FTRs and virtual transactions, and no separate authorization 
is required under the FPA.
---------------------------------------------------------------------------

    \234\ Order No. 697 at P 920.
---------------------------------------------------------------------------

Requests for Rehearing
    164. Morgan Stanley states that, when assessing whether a potential 
market-based 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 \
---------------------------------------------------------------------------

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

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

    \238\ Order No. 697 at P 440.
---------------------------------------------------------------------------

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

    \239\ Id. P 441.
---------------------------------------------------------------------------

    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 
operate pursuant to the open and non-discriminatory 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\
---------------------------------------------------------------------------

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

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

    \244\ Id. P 444 (quoting 49 App. U.S.C. 1(4)).
---------------------------------------------------------------------------

    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

[[Page 25859]]

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

    \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.
    \246\ Id. P 446.
---------------------------------------------------------------------------

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

    \247\ Id. P 447.
---------------------------------------------------------------------------

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

    \248\ Id. P 448.
---------------------------------------------------------------------------

    173. The Commission also modified the change in status reporting 
requirement in Sec.  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 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.
---------------------------------------------------------------------------

    \249\ Southern Rehearing Request at 41 (citing Order No. 697 at 
P 1016).
    \250\ Id. at 41 (citing Order No. 697 at P 446).
---------------------------------------------------------------------------

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

    \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.
    \253\ Id. (quoting Order No. 697 at P 445).
    \254\ Id. (quoting Order No. 697 at P 449).
---------------------------------------------------------------------------

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 Sec.  35.36(a)(4) as 
follows: ``intrastate natural gas transportation, intrastate natural 
gas storage or distribution facilities; sites for new generation 
capacity development; physical coal supply sources and ownership of or 
control over who may access transportation of coal supplies.''
    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 non-discriminatory requirements of Part 284 of the 
Commission's regulations; \256\

[[Page 25860]]

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

    \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).
    \257\ Id. P 444 (quoting 49 App. U.S.C. 1(4)).
---------------------------------------------------------------------------

    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 non-
discriminatory 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 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 market-regulated 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.
---------------------------------------------------------------------------

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

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

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

    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 Sec.  35.43(a)(1) of the 
Commission's regulations. Accordingly, as discussed herein, we will 
codify the definition of affiliate in our market-based rate regulations 
at Sec.  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 Sec.  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

[[Page 25861]]

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

    \264\ Id. at P 549.
    \265\ Id. at P 467.
    \266\ Id. at P 490.
---------------------------------------------------------------------------

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

    \267\ Occidental Rehearing Request at 2.
    \268\ Id.
    \269\ Id. at 5.
---------------------------------------------------------------------------

    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 market-based rate 
activities at the expense of its captive regulated customers simply by 
collapsing its regulated and market-based 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.
---------------------------------------------------------------------------

    \270\ Id. at 4.
---------------------------------------------------------------------------

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

    \271\ Id. at 8.
    \272\ Id.
---------------------------------------------------------------------------

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

    \273\ Order No. 697 at P 513.
---------------------------------------------------------------------------

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

    \274\ See, 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 
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).
---------------------------------------------------------------------------

    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 market-
regulated 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.
---------------------------------------------------------------------------

    \275\ Order No. 697 at P 478 (to be codified at 18 CFR 
35.36(a)(6)).
---------------------------------------------------------------------------

    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

[[Page 25862]]

No. 890 protect transmission customers from the exercise of vertical 
market power.
---------------------------------------------------------------------------

    \276\ Order No. 697 at P 480.
---------------------------------------------------------------------------

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 cost-based 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 cost-
based 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.
---------------------------------------------------------------------------

    \277\ Occidental Rehearing Request at 9.
    \278\ Id.
---------------------------------------------------------------------------

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 
``cost-based 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 non-utility affiliates \279\ of the franchised 
public utility or otherwise being financially harmed as a result of 
affiliate transactions and activities. In other 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 market-based 
regulation as opposed to cost-based 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.
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    \279\ We note that the affiliate restrictions adopted in Order 
No. 697 apply to power sales and non-power 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.
    \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.
---------------------------------------------------------------------------

    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 ``non-regulated'' activities of its 
market-regulated 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, 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-by-case 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.
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    \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.
---------------------------------------------------------------------------

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

    \282\ Order No. 697 at P 480.
---------------------------------------------------------------------------

    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

[[Page 25863]]

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

    \283\ Affiliate Transactions Final Rule at P 45.
---------------------------------------------------------------------------

d. Electric Cooperatives
Final Rule
    204. The Commission declined to subject to the affiliate 
restrictions and regulations in Sec.  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\
---------------------------------------------------------------------------

    \284\ Order 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)).
---------------------------------------------------------------------------

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 
residential and commercial customers.\287\
---------------------------------------------------------------------------

    \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)).
    \287\ Id. at 6, 12.
---------------------------------------------------------------------------

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

    \288\ Id. at 6.
    \289\ Id. at 11.
---------------------------------------------------------------------------

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

    \290\ Id. at 12-13.
---------------------------------------------------------------------------

    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 non-cooperative sellers.\291\ El Paso E&P takes 
the position that, if the Commission permits cooperatives to charge 
market-based rates, then the Commission is obligated to ensure that all 
captive customers are protected from any abuse or excessive rates 
resulting from those market-based rates.\292\
---------------------------------------------------------------------------

    \291\ Id. at 14.
    \292\ Id. at 8.
---------------------------------------------------------------------------

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

    \293\ Id. 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.
---------------------------------------------------------------------------

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 
Sec.  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

[[Page 25864]]

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

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

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

    \298\ Order No. 697 at P 527.
---------------------------------------------------------------------------

    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 Sec.  35.39 because there is no 
danger of affiliate abuse through self-dealing.
e. Public Utility Holding Company Act of 2005 as a ``Commission Rule or 
Order'' Permitting At-Cost Pricing
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 non-power 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, 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\
---------------------------------------------------------------------------

    \299\ Id. at P 597; 18 CFR 35.39(e).
    \300\ Id.
---------------------------------------------------------------------------

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 at-cost 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\
---------------------------------------------------------------------------

    \301\ EEI Rehearing Request at 2.
    \302\ Repeal 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.
---------------------------------------------------------------------------

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

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

    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 Sec.  366.5 of the 
Commission's regulations, Order No. 667 constitutes a ``Commission rule 
or order'' generally authorizing use of at-cost 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 non-power 
goods or services by a franchised public utility with captive customers 
to a market-regulated power sales affiliate are to be at the higher of 
cost or market price, unless otherwise authorized by the Commission. 
The Commission also codified the requirement that sales of any non-
power goods or services by a market-regulated power sales affiliate to 
an affiliated franchised public utility with captive customers will not 
be at a price above market, unless otherwise authorized by the 
Commission.\307\
---------------------------------------------------------------------------

    \307\ Order No. 697 at P 597 (to be codified at 18 CFR 
35.39(e)).
---------------------------------------------------------------------------

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

[[Page 25865]]

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 non-power goods 
and services, and those services are comparable to those provided by a 
centralized service company, then those non-power goods and services 
may be provided at fully-loaded cost as a reasonable proxy for market 
price.\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 inter-affiliate transactions involving non-power goods 
and services are comparable to those provided by a centralized service 
company.
---------------------------------------------------------------------------

    \308\ FP&L March 24, 2008 Request for Clarification at 4.
---------------------------------------------------------------------------

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

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

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 market-regulated power sales affiliates without first receiving 
Commission authorization for the transaction under section 205 of the 
FPA.\310\
---------------------------------------------------------------------------

    \310\ Order No. 697 at P 467.
---------------------------------------------------------------------------

    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 market-regulated 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\
---------------------------------------------------------------------------

    \311\ Id. P 492.
---------------------------------------------------------------------------

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 Sec.  35.39(h) of the new regulations, 
which provides:

    \312\ Ameren Rehearing Request at 5.
---------------------------------------------------------------------------

    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\

    \313\ Emphasis added.
---------------------------------------------------------------------------

    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 
authorization of power sales between affiliated franchised public 
utilities is not required and therefore Sec.  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\
---------------------------------------------------------------------------

    \314\ Id. at 6.
---------------------------------------------------------------------------

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, 
market-regulated 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 Market-Regulated Power Sales Affiliates
Final Rule
    229. The Commission explained in Order No. 697 that the market-
based rate affiliate restrictions codified in Sec.  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.

[[Page 25866]]

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 market-regulated 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\
---------------------------------------------------------------------------

    \315\ FP&L Rehearing Request at 11.
    \316\ Id. at 10, 12.
    \317\ Id. at 12.
---------------------------------------------------------------------------

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 market-based rates sells to an affiliate company in ERCOT (which 
would be a non-public 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 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\
---------------------------------------------------------------------------

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

a. Two-Way Information Sharing Restriction
Final Rule
    234. The Commission adopted a two-way information sharing 
restriction in Sec.  35.39(d) prohibiting a franchised public utility 
with captive customers from sharing information with a market-regulated 
power sales affiliate, and vice-versa.\319\
---------------------------------------------------------------------------

    \319\ Id. P 583.
---------------------------------------------------------------------------

Requests for Rehearing
    235. Southern argues the Commission erred in Order No. 697 by 
adopting a two-way information restriction (Sec.  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 market-
regulated 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 Sec.  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 
Commission-approved generation pooling arrangements. Southern argues 
that the 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\
---------------------------------------------------------------------------

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

    237. Southern believes that the two-way 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 two-way 
restriction.\323\
---------------------------------------------------------------------------

    \321\ Id. at 37.
    \322\ Order No. 697 at P 1133.
    \323\ Southern Rehearing Request at 36, 39.
---------------------------------------------------------------------------

    239. To the extent the Commission maintains the restriction, in any 
form, Southern requests that the Commission clarify the scope of Sec.  
35.39(d) and limit the types of information that are

[[Page 25867]]

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 
market-regulated power sales affiliates sufficient time to assess their 
organizations and technology infrastructures and implement the measures 
necessary to ensure compliance.\325\
---------------------------------------------------------------------------

    \324\ Id. at 39.
    \325\ Id. at 40-41.
---------------------------------------------------------------------------

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 market-regulated 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\
---------------------------------------------------------------------------

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

    \327\ Id. at P 924.
---------------------------------------------------------------------------

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

    \328\ Ameren Rehearing Request at 7.
---------------------------------------------------------------------------

Commission Determination
    245. The Commission clarifies that the new affiliate restriction 
regulations promulgated in Order No. 697 and codified in Sec.  35.39 
supersede the codes of conduct approved by the Commission prior to 
Order No. 697's effective date.\329\ The affiliate restrictions in 
Sec.  35.39 now govern the relationship between a franchised public 
utility with captive customers and its market-regulated 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\
---------------------------------------------------------------------------

    \329\ Clarification Order, 121 FERC ] 61,260 at P 5.
    \330\ See id. P 592.
---------------------------------------------------------------------------

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

    \331\ Id. P 561-63, 565; 18 CFR 35.39(c)(2)(ii).
---------------------------------------------------------------------------

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

[[Page 25868]]

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

    \332\ FP&L Rehearing Request at 2, 4.
    \333\ Id. at 3, 6-7.
    \334\ Id. at 6.
---------------------------------------------------------------------------

    249. Additionally, FP&L urges that the Commission clarify that 
``field and maintenance employees'' include non-commercial 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\
---------------------------------------------------------------------------

    \335\ Id. at 7.
    \336\ Id.
---------------------------------------------------------------------------

    250. EEI notes that Order No. 697 allows franchised public 
utilities with captive customers and their market-regulated 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\
---------------------------------------------------------------------------

    \337\ EEI Rehearing Request at 5 (citing Order No. 697 at P 
565).
    \338\ EEI Rehearing Request at 3-4 and 5-6.
---------------------------------------------------------------------------

Commission Determination
    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.
    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\
---------------------------------------------------------------------------

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

    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 
permissibly-shared 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.
d. Risk Management Employees Under the No-Conduit Rule
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 
restrictions.\340\ Otherwise, Order No. 697 did not specifically 
address the sharing of risk management employees.
---------------------------------------------------------------------------

    \340\ Order No. 697 (to be codified at 18 CFR 35.39(g)).
---------------------------------------------------------------------------

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 Sec.  35.39(c)(2)(ii), Order No. 697 has created 
confusion.\342\
---------------------------------------------------------------------------

    \341\ FP&L Rehearing Request at 8.
    \342\ Id. at 10.
---------------------------------------------------------------------------

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 no-conduit rule 
and may not pass market information to marketing function 
employees.\343\
---------------------------------------------------------------------------

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

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

    \344\ Order No. 697 at P 591 (to be codified at 18 CFR 
35.36(a)(8)).
    \345\ Id. P 593.
---------------------------------------------------------------------------

Requests for Rehearing
    258. Ameren argues that, in introducing its new definition of 
``market information,'' for purposes of the restrictions on affiliates 
sharing

[[Page 25869]]

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

    \346\ 75 FERC ] 61,168 (1996) (UtiliCorp).
    \347\ Ameren Rehearing Request at 8.
---------------------------------------------------------------------------

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

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

D. Mitigation

1. Cost-Based Rate Methodology
a. Selecting the Particular Units that Form the Basis of the ``Up To'' 
Rate
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 Final Rule also 
reiterated that any seller proposing an alternative mitigation 
methodology carries the burden of justifying its proposal.\349\
---------------------------------------------------------------------------

    \349\ Id. P 649.
---------------------------------------------------------------------------

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 mid-term 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 cost-based 
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 high-variable-
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.
---------------------------------------------------------------------------

    \350\ NRECA 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.
---------------------------------------------------------------------------

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

    \355\ Id. at 25-26.
---------------------------------------------------------------------------

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

    \356\ Id. 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)).
---------------------------------------------------------------------------

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

[[Page 25870]]

stacking analysis to determine the seller's generation unit(s) likely 
to provide the service.\360\ In addition, the Commission analyzes the 
cost-justifications 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.
---------------------------------------------------------------------------

    \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 off-
system sale.
---------------------------------------------------------------------------

    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 using a cost-based rate differently than any 
other cost-based rate sellers.
---------------------------------------------------------------------------

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

    266. NRECA also complains that without a reporting procedure for 
mid-term 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\
---------------------------------------------------------------------------

    \362\ 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).
---------------------------------------------------------------------------

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 
long-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.
---------------------------------------------------------------------------

    \368\ Id. P 659 (citing April 14 Order, 107 FERC ] 61,018 at P 
151, 155).
---------------------------------------------------------------------------

    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 short-term and long-term 
sales.
---------------------------------------------------------------------------

    \369\ Id. P 122.
---------------------------------------------------------------------------

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

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

    270. They put forth the following arguments and rationale in 
support of

[[Page 25871]]

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

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

    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 
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.\377\
---------------------------------------------------------------------------

    \376\ Id. at 21.
    \377\ Id. at 10-11.
---------------------------------------------------------------------------

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

    \378\ LT Sellers Rehearing Request at 11, 24-27.
---------------------------------------------------------------------------

    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 market-based 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 market-based 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 where market power concerns generally are not present, 
irrespective of whether a seller ultimately passes the Final Rule's 
criteria for blanket authority.\381\
---------------------------------------------------------------------------

    \379\ Southern Rehearing Request at 29-30; Ameren Rehearing 
Request at 10; OG&E Rehearing Request at 11.
    \380\ Southern Rehearing Request at 29.
    \381\ Id. at 30.
---------------------------------------------------------------------------

    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 case-specific basis.\382\
---------------------------------------------------------------------------

    \382\ APPA/TAPS Rehearing Request at 12-13.
---------------------------------------------------------------------------

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

    \383\ Id. 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)).
---------------------------------------------------------------------------

    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 newly-built 
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

[[Page 25872]]

seller in fact has market power, it will be allowing unjust and 
unreasonable rates.\385\
---------------------------------------------------------------------------

    \385\ Montana Counsel Rehearing Request at 5 (citing FPA 
sections 205-206; Gulf States Utils. Co. v. FPC, 411 U.S. 747 
(1973)).
---------------------------------------------------------------------------

    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 cost-based 
rates.
---------------------------------------------------------------------------

    \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/SynapseLMPElectricityMarketExecSumm013107.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).
---------------------------------------------------------------------------

    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 to 
demonstrate the absence of barriers to entry, i.e., the existence of a 
competitive market for long-term power supply.
---------------------------------------------------------------------------

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

Commission Determination
    279. As discussed below, we will grant rehearing in part and modify 
our policy regarding the mitigation of long-term 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.
---------------------------------------------------------------------------

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

    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 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 long-term 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 long- and 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 
market-based 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

[[Page 25873]]

entry of an appropriate amount of third-party 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 third-party 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.
---------------------------------------------------------------------------

    \391\ LT Sellers Rehearing Request at 11.
---------------------------------------------------------------------------

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

    \392\ 18 CFR 35.3(a).
    \393\ Order No. 697 at P 449.
---------------------------------------------------------------------------

    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 cost-based mitigation be imposed on long-term 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 would-be 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 
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\
---------------------------------------------------------------------------

    \394\ Id. P 667.
---------------------------------------------------------------------------

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

    \395\ Id.
---------------------------------------------------------------------------

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

    \396\ Id. P 673-74.
---------------------------------------------------------------------------

    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 WSPP-wide ``up-to'' demand 
charge as a ceiling rate unless the seller can justify the costs of 
that charge based on its own costs.
---------------------------------------------------------------------------

    \397\ Western Systems Power Pool, 122 FERC ] 61,139 (2008).
---------------------------------------------------------------------------

    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

[[Page 25874]]

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

    \398\ Order No. 697 at P 693.
---------------------------------------------------------------------------

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

    \399\ APPA/TAPS 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)).
---------------------------------------------------------------------------

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-by-case basis based on their particular circumstances.
---------------------------------------------------------------------------

    \402\ April 14 Order, 107 FERC ] 61,018 at n.142; see also, 
Order No. 697 at n.46 and P 698.
---------------------------------------------------------------------------

    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
a. Must Offer
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\
---------------------------------------------------------------------------

    \403\ See, e.g., id. P 732.
    \404\ Id. P 759-60.
    \405\ Id. P 763.
---------------------------------------------------------------------------

    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 market-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\
---------------------------------------------------------------------------

    \406\ Id. P 764.
---------------------------------------------------------------------------

    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 across-the-board 
requirement.\407\
---------------------------------------------------------------------------

    \407\ Id. P 771.
---------------------------------------------------------------------------

Requests for Rehearing
    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\
---------------------------------------------------------------------------

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

    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 pre-determined 
that it will set the bar for a must offer requirement to the standard 
of total monopoly because it is

[[Page 25875]]

inconsistent with the standards adopted in the Final Rule.
---------------------------------------------------------------------------

    \410\ NRECA Rehearing Request at 30 (citing Open Meeting Tr. at 
61 (June 21, 2007)).
---------------------------------------------------------------------------

    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 total-monopoly 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\
---------------------------------------------------------------------------

    \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 pre-granted 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'')).
---------------------------------------------------------------------------

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

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

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

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

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

    \421\ Id. at 9, 26.
    \422\ Id. at 24.
---------------------------------------------------------------------------

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

    \423\ Id. at 25.
    \424\ Id. at 26.
---------------------------------------------------------------------------

    304. Finally, TDU Systems argue that the Commission has been aware 
that relying upon the rights of individual customers to file complaints 
after the fact is often not enough to assure overall achievement of FPA 
mandates.\425\
---------------------------------------------------------------------------

    \425\ Id. at 25.
---------------------------------------------------------------------------

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

[[Page 25876]]

applicable to all sellers. To do otherwise would introduce needless 
regulatory uncertainty.
---------------------------------------------------------------------------

    \426\ 18 CFR 35.38(a).
---------------------------------------------------------------------------

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

    \427\ Order No. 697 at P 790.
---------------------------------------------------------------------------

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

    \428\ APPA/TAPS Rehearing Request at 4 (citing Niagara Mohawk 
Power Corp. v. FPC, 379 F.2d 153 (D.C. Cir. 1967)).
---------------------------------------------------------------------------

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

    \429\ Id. at 20.
    \430\ Order No. 697 at P 791.
    \431\ Id. at 4, 20-21.
---------------------------------------------------------------------------

Commission Determination
    313. The Commission allows market-based 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\
---------------------------------------------------------------------------

    \432\ Id. P 819.
---------------------------------------------------------------------------

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

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

    316. The Final Rule determined that allowing market-based rate 
sales by a seller that has been 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.\435\
---------------------------------------------------------------------------

    \435\ Order No. 697 at P 819.
---------------------------------------------------------------------------

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 non-mitigated 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 market-based 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\
---------------------------------------------------------------------------

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

    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

[[Page 25877]]

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

    \440\ Id.
    \441\ Id. at 6.
    \442\ Id. at 6-7.
---------------------------------------------------------------------------

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

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

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 non-mitigated 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\
---------------------------------------------------------------------------

    \447\ Order No. 697 at P 818.
---------------------------------------------------------------------------

    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 market-based 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 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

[[Page 25878]]

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

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

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:
---------------------------------------------------------------------------

    \451\ Order No. 697 at P 830.

    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; (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.
---------------------------------------------------------------------------

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

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

    \454\ Morgan Stanley Rehearing Request at 3.
    \455\ Id. at 2-3.
---------------------------------------------------------------------------

    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 real-time 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

[[Page 25879]]

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

    \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.
    \457\ Pinnacle Rehearing Request at 7-8.
    \458\ Id.
---------------------------------------------------------------------------

    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 real-
time 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 does not provide the regulatory 
certainty necessary to accurately implement the requirements.\460\
---------------------------------------------------------------------------

    \459\ Pinnacle Rehearing Request at 8.
    \460\ Id. at 8-9.
---------------------------------------------------------------------------

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

    \461\ OG&E Rehearing Request at 9.
    \462\ Id. at 10.
    \463\ Id.
---------------------------------------------------------------------------

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 eliminating the intent requirement, we need not address issues 
raised regarding documentation necessary to demonstrate the mitigated 
seller's intent.
---------------------------------------------------------------------------

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

    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 market-based rate sales at the metered boundary or 
limit such sales to sales to end users of the power, thereby 
eliminating the danger that they will violate their tariff by re-
selling the power back into a balancing authority in which they are 
mitigated.
    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

[[Page 25880]]

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):

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

    \465\ 18 CFR 35.36(a)(2) (citations omitted).
    \466\ See 18 CFR 35.42.
---------------------------------------------------------------------------

    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 pre-
determined 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 corporate family sell 
power during the time period specified for that region.
---------------------------------------------------------------------------

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


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

    \469\ NASUCA Rehearing Request at 12-13.
---------------------------------------------------------------------------

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

    \470\ Id. at 13.
---------------------------------------------------------------------------

    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

[[Page 25881]]

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 non-evidentiary 
proceeding.
---------------------------------------------------------------------------

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

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

    \473\ Id. at 14.
    \474\ Id. (citing FPC v. Texaco, 417 U.S. at 397).
    \475\ Id. at 15 (quoting FPC v. Texaco, 417 U.S. at 397).
---------------------------------------------------------------------------

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

    \476\ Id.
---------------------------------------------------------------------------

    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 before 
adopting an evidence-based standard.
---------------------------------------------------------------------------

    \477\ Id. at 16.
---------------------------------------------------------------------------

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

    \478\ Order No. 697 at P 848.
---------------------------------------------------------------------------

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

    \479\ Id. P 854.
    \480\ Lockyer, 383 F.3d 1006, 1013.
---------------------------------------------------------------------------

    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 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 non-evidentiary 
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.
---------------------------------------------------------------------------

    \481\ NASUCA Rehearing Request at 14.
    \482\ A 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.
---------------------------------------------------------------------------

    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 Sec.  
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 Sec.  35.27(a) exemption.\484\ 
The

[[Page 25882]]

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

    \484\ The Commission was responding to NASUCA's concern that 
sellers that initially 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.
---------------------------------------------------------------------------

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

    \485\ See Order No. 697 at P 864.
    \486\ Id. P 853.
---------------------------------------------------------------------------

    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 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 Commission-enforced 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

[[Page 25883]]

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

    \487\ PPM Rehearing Request at 2-3.
---------------------------------------------------------------------------

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

    \488\ Id. at 4.
    \489\ Id. (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).
---------------------------------------------------------------------------

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

    \491\ Order No. 697 at P 865.
    \492\ Id. P 868.
---------------------------------------------------------------------------

    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 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

[[Page 25884]]

seller to file an updated market power analysis would be minimal.
---------------------------------------------------------------------------

    \493\ Id. P 867.
    \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.
---------------------------------------------------------------------------

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

    \495\ FirstEnergy Rehearing Request at 3.
    \496\ Id. at 5.
---------------------------------------------------------------------------

    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, all-encompassing, 
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\
---------------------------------------------------------------------------

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

    365. MidAmerican seeks a filing schedule that permits it to submit 
a single market power analysis reflecting the generating facilities 
within its own 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.
---------------------------------------------------------------------------

    \499\ MidAmerican Rehearing Request at 2.
---------------------------------------------------------------------------

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

    \500\ Id. at 4.
---------------------------------------------------------------------------

    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 requesting permission to make a single 
filing for its entire corporate family.\503\
---------------------------------------------------------------------------

    \501\ Id. at 10.
    \502\ Id. at 10-11.
    \503\ Id. at 3-4.
---------------------------------------------------------------------------

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

    \504\ Order No. 697 at P 883.
---------------------------------------------------------------------------

    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

[[Page 25885]]

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 additional guidance.
    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.
---------------------------------------------------------------------------

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

    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 transmission-owning 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.
---------------------------------------------------------------------------

    \507\ Order No. 697 at P 889.
    \508\ Clarification Order, 121 FERC ] 61,260 at P 9.
---------------------------------------------------------------------------

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

    \509\ See id. P 868.
---------------------------------------------------------------------------

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

    \510\ Id. 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.'')
---------------------------------------------------------------------------

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

    \512\ Id. at Appendix D.
---------------------------------------------------------------------------

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

    \513\ Order No. 697 at P 895.

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

[[Page 25886]]

    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   Asset name and       Owned by        Controlled by     Date control                        Geographic          Size
          affiliates                  use                                               transferred       Balancing       region (per
                                                                                                        authority area    Appendix D)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ABC Corp.....................  Combined 500kV    ABC Corp........  ABC Corp........  NA..............  New York ISO     Northeast and    Approx. 305
                                Lines.                                                                  and Tucson BA.   Southwest.       combined
                                                                                                                                          miles.
ABC Corp.....................  Combined 500kV    ABC Corp........  XYZ Inc.........  Jan. 1, 2000....  Tucson BA......  Southwest......  185 combined
                                Lines.                                                                                                    miles.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    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 market-based rate tariffs 
identifying all limitations on their market based rate authority 
(including markets where the seller does not have market-based rate 
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.
---------------------------------------------------------------------------

    \514\ Order No. 697 at P 916.
---------------------------------------------------------------------------

    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 market-based rate tariff, i.e., including ``not 
applicable,'' or ``N/A.'' \515\
---------------------------------------------------------------------------

    \515\ See Niagara Mohawk Power Corp., 121 FERC ] 61,275 at P11 
(2007) (Niagara Mohawk).
---------------------------------------------------------------------------

    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 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

[[Page 25887]]

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

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

    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:
---------------------------------------------------------------------------

    \518\ See Order No. 697 at P 917-18.

    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.

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

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

    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 seller-specific 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 market-based 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 by the affiliate restrictions in Sec.  35.39), any 
language prohibiting affiliate sales without first receiving Commission 
authorization (which is codified in Sec.  35.39(b)), market behavior 
rules (which are codified in Sec.  35.41), and the change in status 
reporting requirement (which is codified in Sec.  35.42).
---------------------------------------------------------------------------

    \521\ Order No. 697 at P 919-22.
    \522\ Clarification Order, 121 FERC ] 61,260 at P15.
---------------------------------------------------------------------------

    389. We remind sellers that, consistent with Sec.  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\
---------------------------------------------------------------------------

    \523\ Id. at P 5.
    \524\ See Clarification Order, 121 FERC ] 61,260 at P 5.
---------------------------------------------------------------------------

    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

[[Page 25888]]

Commission pursuant to FPA section 205.
---------------------------------------------------------------------------

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

    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:
---------------------------------------------------------------------------

    \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.

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

    \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)).
    \528\ Id. P 953-954.
    \529\ Id. P 952.
    \530\ Id.
---------------------------------------------------------------------------

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

    \531\ Id. P 954-955.
    \532\ Id. P 955.
---------------------------------------------------------------------------

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

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

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

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

    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

[[Page 25889]]

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

    \540\ Id. P 948.
    \541\ Id. P 949-950.
    \542\ Id. P 951 (citing LEPA, 141 F.3d at 365).
---------------------------------------------------------------------------

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

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

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

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

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

    \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.
    \553\ Id. at 18.
    \554\ Id. (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)).
---------------------------------------------------------------------------

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

    \557\ Id. (citing Order No. 697 at P 943, n. 1068).
    \558\ Id. (citing Order No. 697 at P 946, n. 1070).
    \559\ Id.
---------------------------------------------------------------------------

    403. Consumer Advocates argue that the incentive provided by the 
market-based 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\
---------------------------------------------------------------------------

    \560\ Id. at 20.
    \561\ Id.
    \562\ Id. at 21.
---------------------------------------------------------------------------

    404. Industrial Customers argue that a finding that competitive 
markets exist is a prerequisite to relying upon market-

[[Page 25890]]

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 market-based 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 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.
---------------------------------------------------------------------------

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

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

    \570\ Id. at 9 (citing Southwest Power Pool, Inc., 116 FERC ] 
61,289, at P 30 (2006)).
    \571\ Id.
---------------------------------------------------------------------------

    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 ISO,\575\ Southwest Power Pool,\576\ and 
ISO New England.\577\
---------------------------------------------------------------------------

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

Commission Determination
    407. In the Final Rule, the Commission fully addressed the 
arguments raised by commenters challenging the Commission's market-
based 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\

[[Page 25891]]

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

    \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, 692-93 (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.
---------------------------------------------------------------------------

    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 market-based 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 regarding whether sellers 
lack market power.
---------------------------------------------------------------------------

    \587\ Elizabethtown Gas, 10 F.3d at 870. See also Tejas Power, 
908 F.2d at 1004; LEPA, 141 F.3d at 365.
---------------------------------------------------------------------------

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

    \588\ Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080; 
see also LEPA, 141 F.3d at 370.
---------------------------------------------------------------------------

    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 Commission-approved 
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 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, regularly-scheduled 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 market-
based 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

[[Page 25892]]

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

    \589\ Lockyer, 383 F.3d at 1013.
    \590\ Id. 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.'').
    \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.
---------------------------------------------------------------------------

    412. Accordingly, we find to be without merit the arguments raised 
on rehearing that the Commission lacks authority to continue to permit 
market-based 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 
market-based 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 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 post-approval oversight through 
reporting requirements and ongoing monitoring.
---------------------------------------------------------------------------

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

    415. Additionally, with respect to Consumer Advocates' argument 
that the Commission has overlooked the economic fact that wholesale 
buyers/re-sellers 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 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\
---------------------------------------------------------------------------

    \595\ Id. at 10.
    \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).
---------------------------------------------------------------------------

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

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

    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

[[Page 25893]]

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

    \599\ Consumer Advocates cite several court cases in support of 
their argument in this regard. We address these cases in detail 
below.
    \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).
---------------------------------------------------------------------------

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

    \603\ Id. P 943-955.
    \604\ Lockyer, 383 F.3d at 1013.
    \605\ Snohomish, 471 F.3d at 1080.
---------------------------------------------------------------------------

    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 oft-changing 
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 market-based 
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.''
---------------------------------------------------------------------------

    \606\ Consumer Advocates Rehearing Request at 13.
    \607\ See, e.g., Order No. 697 at P 62-79.
---------------------------------------------------------------------------

    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 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 market-based 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.
---------------------------------------------------------------------------

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

    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 Arkansas-Louisiana 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

[[Page 25894]]

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 market-based 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.
---------------------------------------------------------------------------

    \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).
    \616\ Order No. 697 at P 952.
---------------------------------------------------------------------------

    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 cross-check 
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\
---------------------------------------------------------------------------

    \617\ Id. P 34 (citing April 14 Order, 107 FERC ] 61,018 at P 
100).
    \618\ Id. P 35.
---------------------------------------------------------------------------

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

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

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

    \621\ 18 CFR 35.42.
---------------------------------------------------------------------------

    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 public interests may appropriately include non-
cost factors, such as the need to stimulate additional investment.\625\ 
In permitting market-based 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\
---------------------------------------------------------------------------

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

    426. The Commission has previously considered a similar argument 
(that the Commission must find that a market is competitive before it 
can permit market-based 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

[[Page 25895]]

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\

    \627\ Midwest Independent Transmission System Operator, Inc., 
120 FERC ] 61,202 at P 9, 12 (2007).
---------------------------------------------------------------------------

    427. As we explained in the Final Rule, we retained our approach to 
determining whether a seller should receive authorization to charge 
market-based 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\
---------------------------------------------------------------------------

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

    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 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:
---------------------------------------------------------------------------

    \629\ Industrial Customers Rehearing Request at 7.
    \630\ Farmers Union, 734 F.2d at 1501.
    \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).

    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\

    \636\ Id. at 1510.
---------------------------------------------------------------------------

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 properly taken into account.'' \638\ The court nonetheless concluded 
that `` `non-cost' 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\
---------------------------------------------------------------------------

    \637\ Id. at 1508 (footnote omitted).
    \638\ Id. at n. 50.
    \639\ Id. at 1503.
    \640\ Id. at 1510.
---------------------------------------------------------------------------

    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 market-based 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 market-based 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

[[Page 25896]]

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

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

    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 market-based 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.
---------------------------------------------------------------------------

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

    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 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 market-
based rate tariff, with its appurtenant conditions and requirement for 
filing transaction-specific data in EQRs, is the filed rate.\650\
---------------------------------------------------------------------------

    \647\ Order No. 697 at P 959.
    \648\ Id. (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)).
---------------------------------------------------------------------------

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

    \651\ Id. P 963 (citing Southwestern Electric Cooperative, Inc. 
v. FERC, 347 F.3d 975, 981 (D.C. Cir. 2003)).
    \652\ Id. (citing Lockyer, 383 F.3d at 1012-13; Tejas Power 
Corp. v. FERC, 980 F.2d 998, 1004 (D.C. Cir. 1990)).
---------------------------------------------------------------------------

    436. In the Final Rule, the Commission disagreed with Consumer 
Advocates' argument that the market-based 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 market-based 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\
---------------------------------------------------------------------------

    \653\ Id. P 962.
    \654\ Id.
    \655\ Id.
    \656\ Id.
    \657\ Id. P 964.
---------------------------------------------------------------------------

Requests for Rehearing
    437. Consumer Advocates contend in their request for rehearing that 
the Final

[[Page 25897]]

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 
market-based rate or service.\659\ Consumer Advocates assert that the 
Final Rule relies on buyers to negotiate non-excessive rates, and if 
the buyer is an affiliate or a competitor, the rationale supporting the 
idea that disinterested sellers and buyers will negotiate non-
discriminatory 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.
---------------------------------------------------------------------------

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

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

    \664\ Id.
    \665\ Id.
    \666\ Id.
    \667\ Id.
---------------------------------------------------------------------------

    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 market-based 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 FPA-mandated 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 Commission-created 
`` `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\
---------------------------------------------------------------------------

    \668\ Id. at 23 (citing Order No. 697 at P 960; 962-63).
    \669\ Id.
---------------------------------------------------------------------------

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

    \670\ Id. at 23-24.
    \671\ Id. 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.
    \672\ Id. at 24-25.
---------------------------------------------------------------------------

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

    \673\ Consumer 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)).
---------------------------------------------------------------------------

    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

[[Page 25898]]

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

    \678\ NASUCA Rehearing Request at 17.
    \679\ Id. (citing Order No. 697 at P 953-954).
    \680\ Id. at n.16.
    \681\ Id. at 17.
    \682\ Id. at 18.
    \683\ Id. (citing Order No. 697 at P 958-59).
---------------------------------------------------------------------------

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

    \684\ Id. at 32-33.
    \685\ Id. at 32.
    \686\ Id. (citing MCI; Southwestern Bell).
    \687\ Id. at 33-34.
---------------------------------------------------------------------------

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

    \688\ Id. at 33.
    \689\ Id. (citing 97 FERC ] 61,220 (2001); 105 FERC ] 61,218 
(2003); 107 FERC ] 61,175 (2004)).
---------------------------------------------------------------------------

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

    \690\ Id. at 34.
    \691\ Id. at 36 (citing MCI, 512 U.S. at 231 n.4).
    \692\ Id.
    \693\ Id. at 35.
---------------------------------------------------------------------------

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

    \694\ Id. at 34 (citing Order No. 697 at P 948).
    \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.
---------------------------------------------------------------------------

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

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

    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

[[Page 25899]]

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

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

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

    \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)
---------------------------------------------------------------------------

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

    \709\ Id. at 29 (citing Regular Common Carrier Conference v. 
United States, 793 F.2d 376, 379 (D.C. Cir. 1986) (Regular Common 
Carrier)).
    \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 market-
based rate filing requirements or overall market-based 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)).
---------------------------------------------------------------------------

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

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

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

    \716 \ NASUCA Rehearing Request at 18.
    \717\ Id.
    \718\ Id.
---------------------------------------------------------------------------

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

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

    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

[[Page 25900]]

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

    \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).
    \723\ Lockyer, 383 F.3d at 1013.
    \724\ Order 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).
---------------------------------------------------------------------------

    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 an updated market power analysis and direct 
them at that time to submit one.
    456. We also disagree with Consumer Advocates' argument that the 
market-based 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 market-based 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 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 market-
based 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.
---------------------------------------------------------------------------

    \726\ Id.; see also 18 CFR Part 35 (filing requirements and 
procedures).
---------------------------------------------------------------------------

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

    \727\ Id. (citing Lockyer, 383 F.3d at 1016).
    \728\ Id. 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.
---------------------------------------------------------------------------

    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 post-

[[Page 25901]]

transaction quarterly reporting filing requirements that were in place 
during the time period at issue in Lockyer.\731\
---------------------------------------------------------------------------

    \729\ Lockyer, 383 F.3d at 1013.
    \730\ Id. at 1015.
    \731\ Order No. 697 at n.1105.
---------------------------------------------------------------------------

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

    \732\ Lockyer, 383 F.3d at 1013.
    \733\ See Order No. 697 at P 953.
    \734\ Snohomish, 471 F.3d at 1080-81.
---------------------------------------------------------------------------

    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 cannot take place without first 
filing notice with the Commission.'' \738\
---------------------------------------------------------------------------

    \735\ United Gas Pipe Line, 350 U.S. at 339 (emphasis in 
original).
    \736\ Sierra, 350 U.S. at 353.
    \737\ Id. at 355.
    \738\ City of Piqua, 610 F.2d at 953.
---------------------------------------------------------------------------

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

    \739\ Order No. 697 at P 962; see also 18 CFR Part 35 (filing 
requirements and procedures).
---------------------------------------------------------------------------

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

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

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

    \743\ 43 F.3d at 1517.
    \744\ Id.
    \745\ Id. at 1521.
---------------------------------------------------------------------------

    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 market-based rate 
program requires quarterly filings providing details of all 
transactions.
---------------------------------------------------------------------------

    \746\ Regular Common Carrier, 793 F.2d at 377-78.
    \747\ Id. at 380.
    \748\ See id. at 379.
---------------------------------------------------------------------------

    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 filed-rate 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 publicly-noticed 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 market-based rate authority is 
granted, affected persons can file complaints, or the

[[Page 25902]]

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 market-based rates otherwise are unjust, unreasonable, or unduly 
discriminatory or preferential or to question whether a seller has 
market power.
---------------------------------------------------------------------------

    \749\ 497 U.S. 116, 132-33 (1990).
    \750\ Id. at 127.
---------------------------------------------------------------------------

    466. Consumer Advocates' reliance on MCI is similarly misplaced. 
MCI rejected an FCC policy that relieved all non-dominant 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\
---------------------------------------------------------------------------

    \751\ 512 U.S. 218, 231-32 (1994).
    \752\ Id. at 234.
---------------------------------------------------------------------------

    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 market-based 
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 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 market-power and sufficient post-approval 
reporting requirements as complying with the requirements of the 
FPA.\756\
---------------------------------------------------------------------------

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

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

    \757\ Order No. 697 at P 969 (citing 18 CFR 35.1(g)).
    \758\ Id. P 969-970.
    \759\ Id. P 970.
---------------------------------------------------------------------------

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

    \760\ See supra P 344-47.
---------------------------------------------------------------------------

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

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

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

[[Page 25903]]

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

    \762\ Consumer Advocates Rehearing Request at 31-32.
    \763\ Id. at 32 (citing MCI; Southwestern Bell).
    \764\ Id.
    \765\ Id. (citing Blumenthal, 117 FERC ] 61,038 at P 57).
---------------------------------------------------------------------------

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

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

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

    \769\ Id. at 8 (citing Order No. 697 at P 62, 71, 74, 89).
---------------------------------------------------------------------------

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

    \770\ Id. at 10-11 (citing Order No. 697 at P 33, 75).
---------------------------------------------------------------------------

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

    \771\ Id. at 11.
    \772\ Id.
---------------------------------------------------------------------------

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

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

    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

[[Page 25904]]

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

    \775\ Order No. 697 at P 967, n.1112.
    \776\ Id.
---------------------------------------------------------------------------

Requests for Rehearing
    480. Consumer Advocates argue that the Final Rule erred in 
asserting 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.\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\
---------------------------------------------------------------------------

    \777\ 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)).
---------------------------------------------------------------------------

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

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

    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 Market-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\
---------------------------------------------------------------------------

    \783\ Id. at 40.
    \784\ Id. (citing Colorado Office of Consumer Counsel v. FERC, 
490 F.3d 954 (D.C. Cir. 2007)).
    \785\ Id.
---------------------------------------------------------------------------

Commission Determination
    483. Consumer Advocates' attack on a sentence in a footnote stating 
that ``Commenters' failure to raise this concern [regarding the filing 
of market-based 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

[[Page 25905]]

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

    \786\ Order No. 697 at n.1112.
    \787\ Order No. 2001, FERC Stats. & Regs. ] 31,127 at P 31.
    \788\ Order No. 697 at P 943-955, 959-968.
---------------------------------------------------------------------------

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

    \789\ Id. P 971.
---------------------------------------------------------------------------

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

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

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

    \794\ Id.
    \795\ Id.
    \796\ Id. at 10 (citing 426 U.S. 271 (1976)).
---------------------------------------------------------------------------

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

    \797\ Id. (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)).
    \801\ Id. (citing NSTAR, 481 F.3d 794).
---------------------------------------------------------------------------

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

    \802\ Id. at 12 (citing Order No. 697 at section 35.38).
    \803\ Id. (quoting Electrical District, 774 F.2d at 492-93).
    \804\ Id.
---------------------------------------------------------------------------

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

[[Page 25906]]

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 cost-
based 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 cost-support, 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\
---------------------------------------------------------------------------

    \805\ Order No. 697 at P 630.
    \806\ Id. P 629.
    \807\ Id. 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)).
---------------------------------------------------------------------------

    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 
Commission, the seller must file an accompanying tariff.
---------------------------------------------------------------------------

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

    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 cost-based 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\
---------------------------------------------------------------------------

    \811\ Order No. 697 at P 629.
    \812\ Id.
    \813\ Id. P 650.
    \814\ Id. 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).
---------------------------------------------------------------------------

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

    \816\ 426 U.S. 271, 279-80 (1976).
    \817\ Order No. 697 at P 630.
---------------------------------------------------------------------------

    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

[[Page 25907]]

examine the proposed rates on a case-by-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.
---------------------------------------------------------------------------

    \818\ 818 112 FERC ] 61,057 (2005), reversed in part, NSTAR, 481 
F.3d 794.
    \819\ NSTAR, 481 F.3d 794.
    \820\ Order No. 697 at P 630.
---------------------------------------------------------------------------

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

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

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

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

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

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

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 
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 market-based rate 
regime. Consumer Advocates assert that the Commission has no authority, 
even to implement policy, unless the statute confers it.\833\
---------------------------------------------------------------------------

    \831\ Id. at 16 (citing United Gas Pipe Line; Sierra).
    \832\ Id. (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)).
---------------------------------------------------------------------------

Commission Determination
    498. We disagree with Consumer Advocates' contentions that the 
Commission must find existing market-based 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

[[Page 25908]]

reiterate that this proceeding is not an adjudicatory investigation of 
public utilities' existing market-based rate tariffs for which refunds 
will be required.\836\
---------------------------------------------------------------------------

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

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

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

G. Miscellaneous

1. Change in Status
a. Reporting
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 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.
---------------------------------------------------------------------------

    \840\ Order No. 697 at P 1009-1045 (codifying the requirement, 
as amended, at 18 CFR 35.42).
---------------------------------------------------------------------------

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

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

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 analysis may be 
required from any sellers, Category 1 or 2, at any time.
---------------------------------------------------------------------------

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

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

    \845\ Id. at 4-5 (citing K N Energy, Inc. v. FERC, 968 F.2d 
1295, 1303 (D.C. Cir. 1991)).
---------------------------------------------------------------------------

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

    \846\ Order No. 697 at P 853-854.
---------------------------------------------------------------------------

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

    \847\ Order No. 652, FERC Stats. & Regs. ] 31,175 at P 94-95.
---------------------------------------------------------------------------

    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

[[Page 25909]]

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

    \848\ Order No. 697 at P 856-857.
---------------------------------------------------------------------------

b. Transmission Outages
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 long-term 
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\
---------------------------------------------------------------------------

    \849\ Order No. 697 at P 1025.
---------------------------------------------------------------------------

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

    \850\ Wisconsin Electric at 4-5.
---------------------------------------------------------------------------

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 non-transmission 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 long-term transmission outage 
causes the seller to fail one or more of the indicative screens).
---------------------------------------------------------------------------

    \851\ Order 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.
---------------------------------------------------------------------------

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

    \854\ Id. at P 68.
---------------------------------------------------------------------------

    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 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 market-based 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

[[Page 25910]]

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

    \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/docs-filing/eqr.asp for more 
information on EQR filings).
---------------------------------------------------------------------------

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

    \857\ The Avista policy applies to the following four ancillary 
services: Regulation Service, Energy Imbalance Service, Spinning 
Reserves, and Supplemental Reserves.
    \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.
---------------------------------------------------------------------------

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 subsequently applied the Avista 
requirements.\863\
---------------------------------------------------------------------------

    \861\ Wisconsin Electric Rehearing Request at 3.
    \862\ Id. at 4 (citing Wisconsin Electric Power Co., 93 FERC ] 
61,302 (2000)).
    \863\ Id.
---------------------------------------------------------------------------

    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 physically-settled 
bilateral ancillary services markets, not a market for financially-
settled products that are beyond the Commission's jurisdiction.\864\
---------------------------------------------------------------------------

    \864\ Morgan Stanley Rehearing Request at 1, 4.
---------------------------------------------------------------------------

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

    \865\ Id. at 5.
---------------------------------------------------------------------------

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

    \866\ Avista II, 89 FERC ] 61,136 at 61,392.
    \867\ Wisconsin Electric Power Co., 93 FERC ] 61,302 (2000).
---------------------------------------------------------------------------

    521. Therefore, because Dynamic Energy and Capacity Service, as

[[Page 25911]]

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

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

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

    \869\ In the context of PURPA, the term energy includes 
capacity, energy and ancillary services.
    \870\ See 18 CFR 292.601(c)(1).
---------------------------------------------------------------------------

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

    \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 market-
based rate authority from QFs that are exempt from section 205. See, 
e.g., SP Newsprint, 103 FERC ] 61,186 (2003).
---------------------------------------------------------------------------

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

    \874\ Order No. 697 at P 916-17.
---------------------------------------------------------------------------

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 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 Sec.  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, Sec.  35.42 specifies that a change in status includes, but 
is not limited to, ownership or control of generation capacity that 
results in net increases of 100 MW or more.
    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 long-term 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\
---------------------------------------------------------------------------

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

    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, Sec.  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,

[[Page 25912]]

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 Sec.  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 Sec.  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.

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 market-based 
rate program, it does not add to these requirements. Accordingly, a 
copy of this order will be sent to OMB for informational purposes only.
---------------------------------------------------------------------------

    \877\ 5 CFR 1320.11.
---------------------------------------------------------------------------

IV. Document Availability

    535. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's 
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m. 
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    536. From FERC's Home Page on the Internet, this information is 
available on eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    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 
[email protected], or the Public Reference Room at (202) 502-
8371, TTY (202) 502-8659. E-mail the Public Reference Room at 
[email protected].

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.

0
In consideration of the foregoing, the Commission amends part 35, 
Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 
U.S.C. 7101-7152.


0
2. In Sec.  35.36, paragraphs (a)(4) and (a)(6) are revised and 
paragraph (a)(9) is added to read as follows:


Sec.  35.36  Generally.

    (a) * * *
    (4) Inputs to electric power production means intrastate natural 
gas transportation, intrastate natural gas storage or distribution 
facilities; sites for generation capacity development; physical coal 
supply sources and ownership of or control over who may access 
transportation of coal supplies.
* * * * *
    (6) Captive customers means any wholesale or retail electric energy 
customers served by a franchised public utility under cost-based 
regulation.
* * * * *
    (9) Affiliate of a specified company means:
    (i) For any person other than an exempt wholesale generator:
    (A) Any person that directly or indirectly owns, controls, or holds 
with power to vote, 10 percent or more of the outstanding voting 
securities of the specified company;
    (B) Any company 10 percent or more of whose outstanding voting 
securities are owned, controlled, or held with power to vote, directly 
or indirectly, by the specified company;
    (C) Any person or class of persons that the Commission determines, 
after appropriate notice and opportunity for hearing, to stand in such 
relation to the specified company that there is liable to be an absence 
of arm's-length bargaining in transactions between them as to make it 
necessary or appropriate in the public interest or for the protection 
of investors or consumers that the person be treated as an affiliate; 
and
    (D) Any person that is under common control with the specified 
company.
    (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 Sec.  
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.
* * * * *

0
3. In Sec.  35.39, paragraphs (b) and (d)(1) are revised to read as 
follows:


Sec.  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

[[Page 25913]]

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.
* * * * *

0
4. In Sec.  35.42, paragraph (a)(1) is revised to read as follows:


Sec.  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
* * * * *

0
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.............  Installed Capacity.....       19,500  Workpaper.
B.............  Long-Term Firm                   500  Workpaper.
                 Purchases.
C.............  Long-Term Firm Sales...       -1,000  Workpaper.
D.............  Imported Power.........            0  Workpaper.
------------------------------------------------------------------------
Non-Affiliate Capacity
------------------------------------------------------------------------
E.............  Installed Capacity.....        8,000  Workpaper.
F.............  Long-Term Firm                   500  Workpaper.
                 Purchases.
G.............  Long-Term Firm Sales...       -2,500  Workpaper.
H.............  Imported Power.........        3,500  Workpaper.
I.............  Balancing Authority           -2,160  Workpaper.
                 Area Reserve
                 Requirement.
J.............  Amount of Line I              -2,160  Workpaper.
                 Attributable to
                 Seller, if any.
K.............  Total Uncommitted              9,840
                 Supply (SUM
                 A,B,C,D,E,F,G,H,I,M).
------------------------------------------------------------------------
Load
------------------------------------------------------------------------
L.............  Balancing Authority           18,000  Workpaper.
                 Area Annual Peak Load.
M.............  Average Daily Peak           -16,500  Workpaper.
                 Native Load in Peak
                 Month.
N.............  Amount of Line M             -16,500  Workpaper.
                 Attributable to
                 Seller, if any.
O.............  Wholesale Load (SUM            1,500
                 L,M).
P.............  Net Uncommitted Supply         8,340
                 (K-O).
Q.............  Seller's Uncommitted             340
                 Capacity (SUM
                 A,B,C,D,J,N).
                Result of Pivotal        ...........  PASS.
                 Supplier Screen (Pass
                 if Line Q < Line P),
                 (Fail if Line Q > Line
                 P).
------------------------------------------------------------------------


    Note: The following appendices will not be published in the Code 
of Federal Regulations.

Appendix C to Order No. 697-A

Required Provisions of the Market-Based Rate Tariff

Compliance With Commission Regulations

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

Limitations and Exemptions Regarding Market-Based Rate Authority

    [Seller should list all limitations (including markets where 
seller does not have market-based rate authority) on its market-
based rate authority and any exemptions from or waivers granted of 
Commission regulations and include relevant cites to Commission 
orders].

Seller Category

    Seller Category: Seller is a [insert Category 1 or Category 2] 
seller, as defined in 18 CFR 35.36(a).

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 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

[[Page 25914]]

purchasers in the market administered by the New York Independent 
System Operator, Inc.
    New England: Seller offers regulation and frequency response 
service (automatic generator control), operating reserve service 
(which includes 10-minute spinning reserve, 10-minute non-spinning 
reserve, and 30-minute operating reserve service) to purchasers 
within the markets administered by the ISO New England, Inc.
    California: Seller offers regulation service, spinning reserve 
service, and non-spinning reserve service to the California 
Independent System Operator Corporation (``CAISO'') and to others 
that are self-supplying ancillary services to the CAISO.

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.
[GRAPHIC] [TIFF OMITTED] TR07MY08.010

Appendix D-1

[[Page 25915]]



    Schedule for Transmission Owning Utilities With Market-Based Rate
            Authority and Their Affiliates in the Same Region
------------------------------------------------------------------------
                                  Filing period
   Entities required to file     (anytime  during       Study period
                                    the month)
------------------------------------------------------------------------
Northeast Transmission Owners.  December, 2007...  Dec. 1, 2005-Nov. 30,
                                                    2006.
Southeast Transmission Owners.  June, 2008.......  Dec. 1, 2005-Nov. 30,
                                                    2006.
Central Transmission Owners...  December, 2008...  Dec. 1, 2006-Nov. 30,
                                                    2007.
SPP Transmission Owners.......  June, 2009.......  Dec. 1, 2006-Nov. 30,
                                                    2007.
Southwest Transmission Owners.  December, 2009...  Dec. 1, 2007-Nov. 30,
                                                    2008.
Northwest Transmission Owners.  June, 2010.......  Dec. 1, 2007-Nov. 30,
                                                    2008.
Northeast Transmission Owners.  December, 2010...  Dec. 1, 2008-Nov. 30,
                                                    2009.
Southeast Transmission Owners.  June, 2011.......  Dec. 1, 2008-Nov. 30,
                                                    2009.
Central Transmission Owners...  December, 2011...  Dec. 1, 2009-Nov. 30,
                                                    2010.
SPP Transmission Owners.......  June, 2012.......  Dec. 1, 2009-Nov. 30,
                                                    2010.
Southwest Transmission Owners.  December, 2012...  Dec. 1, 2010-Nov. 30,
                                                    2011.
Northwest Transmission Owners.  June, 2013.......  Dec. 1, 2010-Nov. 30,
                                                    2011.
------------------------------------------------------------------------

Appendix D-2

                                         Schedule for All Other Entities
----------------------------------------------------------------------------------------------------------------
                                        Filing period (anytime
      Entities required to file           during the month)                       Study period
----------------------------------------------------------------------------------------------------------------
All others in Northeast that did not   June, 2008.............  Dec. 1, 2005-Nov. 30, 2006.
 file in December including all power
 marketers that sold in the Northeast.
All others in Southeast that did not   December, 2008.........  Dec. 1, 2005-Nov. 30, 2006.
 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     June, 2009.............  Dec. 1, 2006-Nov. 30, 2007.
 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    December, 2009.........  Dec. 1, 2006-Nov. 30, 2007.
 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  June, 2011.............  Dec. 1, 2008-Nov. 30, 2009.
 in December and have not been found
 to be Category 1 sellers.
Others in Southeast that did not file  December, 2011.........  Dec. 1, 2008-Nov. 30, 2009.
 in June and have not been found to
 be Category 1 sellers.
Others in Central that did not file    June, 2012.............  Dec. 1, 2009-Nov. 30, 2010.
 in December and have not been found
 to be Category 1 sellers.
Others in SPP that did not file in     December, 2012.........  Dec. 1, 2009-Nov. 30, 2010.
 June and have not been found to be
 Category 1 sellers.
Others in Southwest that did not file  June, 2013.............  Dec. 1, 2010-Nov. 30, 2011.
 in December and have not been found
 to be Category 1 sellers.
Others in Northwest that did not file  December, 2013.........  Dec. 1, 2010-Nov. 30, 2011.
 in June and have not been found to
 be Category 1 sellers.
----------------------------------------------------------------------------------------------------------------

Appendix E to Order No. 697-A

                           Petitioner Acronyms
------------------------------------------------------------------------
         Abbreviation                       Petitioner names
------------------------------------------------------------------------
Ameren.......................  Ameren Services Company.
APPA/TAPS....................  American Public Power Association/
                                Transmission Access Policy Study Group.
Attorneys General of           Richard Blumenthal, Attorney General for
 Connecticut and Illinois.      the State of Connecticut and the People
                                of the State of Illinois, by and through
                                the Illinois Attorney General Lisa
                                Madigan.
Consumer Advocates...........  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.
EEI..........................  Edison Electric Institute.
El Paso E&P..................  El Paso E&P Company, L.P.
FirstEnergy..................  FirstEnergy Service Company.
FP&L.........................  Florida Power & Light Company and FPL
                                Energy, LLC.
Industrial Customers.........  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.
LT Sellers...................  Long-Term Sellers.
MidAmerican..................  MidAmerican Energy Company and Cordova
                                Energy Company LLC.
Montana Counsel..............  Montana Consumer Counsel.
Morgan Stanley...............  Morgan Stanley Capital Group Inc.
NASUCA.......................  National Association of State Utility
                                Consumer Advocates.

[[Page 25916]]

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

UNITED STATES OF AMERICA

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 
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-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