[Federal Register Volume 70, Number 33 (Friday, February 18, 2005)]
[Rules and Regulations]
[Pages 8253-8269]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 05-3040]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 35

[Docket No. RM04-14-000; Order No. 652; 110 FERC ] 61,097]


Reporting Requirement for Changes in Status for Public Utilities 
With Market-Based Rate Authority

Issued February 10, 2005.
AGENCY: Federal Energy Regulatory Commission, DOE.

ACTION: Final rule.

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SUMMARY: In this Final Rule, the Federal Energy Regulatory Commission 
(Commission) is amending its regulations to establish a reporting 
obligation for changes in status that apply to public utilities 
authorized to make wholesale power sales in interstate commerce at 
market-based rates. The Commission is amending its regulations to 
establish guidelines concerning the types of events that trigger this 
reporting obligation and modifying the market-based rate authority of 
current market-based rate sellers to ensure that all such events are 
timely reported to the Commission by eliminating the option to delay 
reporting of such events until submission of a market-based rate 
seller's updated market power analysis. This reporting requirement will 
be incorporated into the market-based rate tariff of each entity that 
is currently authorized to make sales at market-based rates, as well as 
that of all future applicants.

DATES: Effective Date: This Final Rule will become effective on March 
21, 2005.

FOR FURTHER INFORMATION CONTACT:
Brandon Johnson, Federal Energy Regulatory Commission, 888 First 
Street, NE., Washington, DC 20426, (202) 502-6143
Michelle Barnaby, Federal Energy Regulatory Commission, 888 First 
Street, NE., Washington, DC 20426, (202) 502-8407

SUPPLEMENTARY INFORMATION:

Table of Contents / Paragraph

    Introduction--1
    Background--7
    Discussion--11
    General Issues--11
     Comments--11
     Commission Conclusion--15
     Triggering Events--18
     Triggering Events Generally--19
     Comments--19
     Commission Conclusion--25
     Exemptions--28
     Comments--28
     Commission Conclusion--34
     Control/Ownership--42
     Comments--42
     Commission Conclusion--47
     Affiliation--49
     Comments--49
     Commission Conclusion--51
    Inputs to Electric Power Production--52
     Comments--53
     Commission Conclusion--58
    Materiality Threshold--60
     Comments--61
     Commission Conclusion--68
    Transmission Outages--71
     Comments--72
     Commission Conclusion--75
    Other Reportable Arrangements--76
     Comments--77
     Commission Conclusion--82
    Form and Content of Reports--84
     Comments--85
     Commission Conclusion--93
    Inclusion of Reporting Requirement in Market-based Rate 
Tariffs--96
     Comments--97
     Commission Conclusion--98
    Reporting Period/Timing--99
     Comments--100
     Commission Conclusion--105
    Other Procedural Issues--108

Before Commissioners: Pat Wood, III, Chairman; Nora Mead Brownell, 
Joseph T. Kelliher, and Suedeen G. Kelly.

Introduction

    1. On October 6, 2004, the Commission issued a Notice of Proposed 
Rulemaking (NOPR) that proposed to standardize and clarify market-based 
rate sellers' reporting requirement for changes in status. The 
Commission proposed to impose uniform standards on all market-based 
rate sellers by eliminating the option to delay reporting changes in 
status until submission of the triennial review, or to file a triennial 
review in lieu of reporting changes in status as they occur. Acting 
pursuant to section 206 of the FPA, the Commission proposed to amend 
its regulations and to modify the market-based rate authority of 
current market-based rate sellers to include the requirement 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. The Commission proposed that this 
reporting requirement be incorporated into the market-based rate tariff 
of each entity that is currently authorized to make sales at market-
based rates, as well as that of all future applicants. The Commission 
proposed that notice of such changes in status be filed no later than 
30 days after the change in status occurs.
    2. As discussed more fully below, in this Final Rule, the 
Commission, among other things: Imposes uniform standards on all 
market-based rate sellers by eliminating the option to delay reporting 
changes in status until submission of the triennial review or to file a 
triennial review in lieu of reporting changes in status as they occur; 
specifically refers to ``control'' of generation or transmission 
facilities as a trigger which could result in the obligation to make a 
change in status filing; provides guidance as to the 
``characteristics'' the Commission relies on in evaluating whether to 
grant market-based rate authority; provides guidance as to the form, 
content, and timing of a change in status filing; and incorporates into 
all market-based rate tariffs the standards discussed herein.
    3. In doing so, the Commission has adopted many of the 
recommendations suggested by commenters. In this regard, the Commission 
clarifies that a change in status filing is one of the tools the 
Commission uses to ensure that wholesale electric rates remain just and 
reasonable. In particular, a change in status filing informs the 
Commission of changes that may occur from time to time that relate to 
the four-part analysis (generation market power, transmission market 
power, other barriers to entry, and affiliate abuse and reciprocal 
dealing) the Commission relies on for granting market-based rate 
authority. At the same time, however, the Commission finds that some of 
the recommendations made by commenters are more appropriately addressed 
in the market-based rate rulemaking proceeding that the Commission has 
initiated in Docket No. RM04-7-000.
    4. As discussed below, the Commission finds that a number of issues 
regarding the Commission's analysis under the four-part test (e.g., 
what constitutes control of an asset, how to treat long-term contracts, 
how to evaluate whether an applicant has transmission market power) are 
more appropriately addressed in the market-based rate rulemaking, in 
which numerous technical conferences have been held and comments filed. 
It is in that proceeding that the Commission will examine the 
recommendations of commenters and address the adequacy of the current 
four-part analysis, including whether and how it should be modified to 
assure that electric market-

[[Page 8254]]

based rates are just and reasonable under the FPA.
    5. With respect to change in status filings, in this Final Rule 
applicants are reminded that the baseline determination of whether a 
filing is required is whether the change in status in question would 
have been reportable in an initial application for market-based rate 
authority under the Commission's four-part analysis, as it may change 
from time to time. To the extent that the change in status in question 
would have been reportable in an initial request for market-based rate 
authority, a change in status filing is required. For example, if an 
applicant acquires additional uncommitted capacity, a change in status 
filing is required.
    6. The Commission provides this guidance to enable applicants to 
better determine when they must report a change in status. The electric 
industry is a dynamic industry and no bright-line standard is possible 
to encompass all relevant factors and possibilities that may occur. The 
Commission believes that sufficient guidance has been provided in this 
Final Rule and reminds applicants that they have the right to make a 
change in status filing under section 205 of the Commission's 
regulations at any time. With this safeguard, the Commission is certain 
that applicants have the means to fully comply with the change in 
status requirement and with the standards adopted herein can do so 
efficiently and with no additional burden.

Background

    7. As the Commission explained in the NOPR, it has a statutory duty 
under the FPA to ensure that rates charged by public utilities 
authorized to make wholesale sales in interstate commerce at market-
based rates are just and reasonable.\1\-\2\ The Commission 
uses a four-part test to determine whether to grant market-based rate 
authority. That test examines whether the applicant or its affiliates 
possess the potential to exercise market power by considering 
generation market power, transmission market power, barriers to entry, 
and the potential for affiliate abuse or reciprocal dealing. Sellers 
authorized to make sales at market-based rates are then required to 
file electric quarterly reports containing a summary of the contractual 
terms and conditions in every effective service agreement for market-
based power sales and transaction information for their market-based 
rate sales during the most recent calendar quarter.\3\
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    \1\-\2\ 16 U.S.C. 824d(a) (2000).
    \3\ Revised Public Utility Filing Requirements, Order No. 2001, 
67 FR 31,043 (May 8, 2002), FERC Stats. & Regs. ] 31,127 (Apr. 25, 
2002). The required data sets for contractual and transaction 
information are described in Attachments B and C of Order No. 2001.
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    8. The Commission has also required that market-based rate sellers 
report any changes in status that would reflect a departure from the 
characteristics the Commission relied upon in its existing grant of 
market-based rate authority. When the Commission first granted market-
based rate authorizations, it required traditional utilities that 
satisfied the Commission's initial market power review to file an 
updated market power analysis every three years to allow the Commission 
to monitor competitive conditions and to determine whether the 
applicants still satisfied our market power concerns.\4\ Power 
marketers, on the other hand, were required to promptly notify the 
Commission of changes in status.\5\ Subsequently, the Commission has 
allowed market-based-rate sellers to choose between promptly reporting 
changes in status, filing a three-year update in lieu of reporting 
changes in status as they occurred,\6\ or reporting such changes in 
conjunction with the updated market analysis.\7\ The Commission 
reserved the right to require such an analysis at any time and, in the 
NOPR, proposed to continue to reserve this right.
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    \4\ See, e.g., Entergy Services, Inc., 58 FERC ] 61,234 (1992); 
Louisville Gas & Electric, 62 FERC ] 61,016 (1993).
    \5\ See, e.g., Citizens Power & Light Corp., 48 FERC ] 61,210 
(1989); Enron Power Marketing, 65 FERC ] 61,305 (1993); InterCoast 
Power Marketing Co., 68 FERC ] 61,248 (1994).
    \6\ See, e.g., Morgan Stanley Capital Group, Inc., 69 FERC ] 
61,175 (1994).
    \7\ See, e.g., AEP Power Marketing, Inc., 76 FERC ] 61,307 at 
62,516 (1996); Montaup Electric Co., 85 FERC ] 61,313 at 62,232 
(1998); Sithe/Independence Power Partners, 101 FERC ] 61,210 at 
61,907 (2002).
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    9. To carry out its statutory duty under the FPA to ensure that 
market-based rates are just and reasonable, the Commission must rely on 
market-based rate sellers to provide accurate, up-to-date information 
regarding any relevant changes in status, such as ownership or control 
of generation or transmission facilities and affiliate relationships. 
In contrast to when the Commission first began to authorize market-
based rate sales, as markets have expanded and developed, both the 
number and types of market-based rate sellers have increased (e.g., 
independent power producers, power marketers, affiliated generators) 
and the complexity of wholesale markets has increased. Furthermore, 
market structure is rapidly evolving due to restructuring, corporate 
realignments and new types of contractual and subcontracting 
arrangements, in which utilities increasingly grant other firms control 
over managing various aspects of their business such as power 
marketing. In light of these structural changes, the Commission has 
concluded that more timely reporting of changes in status is necessary.
    10. Therefore, the Commission proposed in the NOPR to eliminate the 
option to delay reporting changes in status until the next triennial 
review, or to file a triennial review in lieu of promptly reporting 
changes in status, and to standardize the change in status reporting 
requirement. Accordingly, the proposed regulations would require that, 
as a condition of obtaining and retaining market-based rate authority, 
all sellers will be required 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.

Discussion

General Issues

Comments

    11. With only a few exceptions, the commenters support the 
Commission's proposal to standardize market-based rate sellers' 
reporting requirement. Nearly all of the comments received urge the 
Commission to more clearly define market-based rate sellers' reporting 
obligation and to do so in a manner that does not impose an excessive 
reporting burden.
    12. Mayflower LP (Mayflower) argues that the Commission's entire 
approach of attempting to develop market power tests is misguided 
because the variables involved are too complex to describe effectively 
in a regulation. Mayflower contends that the Commission should instead 
prioritize its resources to mitigating the obvious cases of market 
power, in particular by utilizing section 205(f) of the FPA \8\ to end 
market power abuses through fuel adjustment clauses, which allow 
utilities to pass through the costs of operating dirty and inefficient 
gas and boiler generation, while cleaner, cheaper-to-run combined cycle 
generation sits idle.\9\
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    \8\ 16 U.S.C. 824d(f) (2000).
    \9\ Mayflower at 2, 8.
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    13. Tractebel North America, Inc. (Tractebel), citing the 
Commission's recent order disclaiming jurisdiction under section 203 
for a generation-only

[[Page 8255]]

facility in Perryville Energy Partners,\10\ argues that the review of 
transactions in the context of market-based rate authority is an 
inadequate substitute for Commission review of a public utility's 
acquisition of an asset under section 203. Accordingly, in cases where 
the Commission lacks jurisdiction under section 203, Tractebel urges 
the Commission to review acquisitions of generation not only in the 
context of a notice of change in status, but also in related filings, 
such as any rate filing for transmission interconnection service over 
assets that will continue to be owned by the seller and filings related 
to exempt wholesale generator (EWG) status.\11\
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    \10\ 109 FERC ] 61,019 (2004) (Perryville).
    \11\ Tractebel at 3-4.
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    14. Finally, Pacific Gas & Electric Company (PG&E) argues that the 
reporting requirement proposed in the NOPR should apply to energy 
marketers but not to investor-owned utilities that are serving native 
load customers and are members of an independent system operator (ISO) 
or regional transmission organization (RTO). According to PG&E, there 
are legitimate differences between energy marketers (who, as net 
sellers, engage in electric trades for profit and can influence the 
market relatively rapidly) and traditional utilities such as PG&E (who 
are net buyers and do not speculate).\12\
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    \12\ PG&E at 4-6.
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Commission Conclusion

    15. We decline to adopt Mayflower's proposal to address alleged 
market power abuses through fuel adjustment clauses because it goes 
beyond the scope of the instant rulemaking. Section 205(f) requires the 
Commission to review practices under public utility automatic 
adjustment clauses to ensure efficient use of resources under such 
clauses. If a party believes that this is not being done, the 
Commission encourages the filing of a complaint to remedy the matter. 
Proposals such as Mayflower's, which urge the Commission to adopt a new 
approach toward the mitigation of market power, are more appropriately 
addressed in the generic rulemaking in Docket No. RM04-7-000.
    16. In response to Tractebel's comments, the acquisition of a 
generating facility by a utility with market-based rate authority such 
as occurred in Perryville is an event that would trigger the filing of 
a change in status report consistent with this rule. Whether it would 
trigger other jurisdictional filings such as a rate filing for 
transmission interconnection service or filing related to EWG status, 
as Tractebel suggests, would depend on the facts of the particular 
case. As the Commission stated in the Perryville case, the Commission 
will consider the effect of the addition of the Perryville capacity as 
part of the Commission's review of Entergy's updated market power 
analysis in Docket No. ER91-569-023, et al.\13\
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    \13\ Perryville, 109 FERC ] 61,019 at P 20, 22.
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    17. We will also reject PG&E's suggestion to exempt investor-owned 
utilities such as PG&E from the reporting requirement. Adopting PG&E's 
proposal could result in allowing large vertical utilities to increase 
their market share or otherwise obtain market power without notifying 
the Commission of changed circumstances. Under PG&E's proposal, a 
vertical utility could have changed circumstances that would result in 
that utility no longer satisfying one or more prongs of the four-part 
test that the Commission uses to determine whether to grant market-
based rate authorization. With no notification to the Commission in 
that regard such a proposal provides little or no protection to 
customers in the market between review periods, (i.e., triennial 
review). To the extent that PG&E assumes an RTO's mitigation warrants 
an exemption, we have rejected such an exemption in the previous 
orders.\14\
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    \14\ See AEP Power Marketing, Inc., 107 FERC ] 61,018 at P 186 
(2004) (April 14 Order), order on reh'g, 108 FERC ] 61,026 at P 175 
(2004) (July 8 Order).
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Triggering Events

    18. With respect to the types of events that should trigger the 
reporting obligation, the Commission proposed in the NOPR that, as an 
initial matter, the following events would qualify as changes in 
status: (1) Ownership or control of generation or transmission 
facilities or inputs to electric power production; or (2) affiliation 
with any entity not disclosed in the filing that owns or controls 
generation or transmission facilities or inputs to electric power 
production or affiliation with any entity that has a franchised service 
area.\15\ The Commission noted that, although the change in status 
provision has not specifically referenced ``control'' of assets, the 
Commission has historically taken into account all of the assets that a 
market-based rate seller controls in our four-part test for granting 
market-based rate authority. In order to eliminate any market 
uncertainty, the Commission proposed that the regulations specifically 
reference ``control'' as well as ownership as a factor relied upon by 
the Commission. As we noted in the NOPR, the Commission's early orders 
granting market-based rate authority acknowledged that sellers may 
exercise market power through contractual arrangements granting them 
control of generation or transmission facilities just as effectively as 
they could through ownership.\16\ Similarly, the Commission's 
guidelines for the assessment of mergers and its generation market 
power analysis for market-based rate authority provide that, for the 
purposes of the market power analysis, the capacity associated with 
contracts that confer operational control of a given facility to an 
entity other than the owner must be assigned to the entity exercising 
control over that facility, rather than to the entity that is the legal 
owner of the facility.\17\ In addition, with respect to notifications 
of changes in status, the Commission has found that an entity controls 
the facilities of another when it controls the decision-making 
authority over sales of electric energy, including discretion as to 
how, when and to whom it could sell power generated by these 
facilities.\18\
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    \15\ The Commission's regulations define ``affiliated 
companies'' as ``companies or persons that directly, or indirectly 
through one or more intermediaries, control, or are controlled by, 
or are under common control with, the [subject] company.'' 18 CFR 
part 101 (2004). See also 18 CFR 161.2 (2004); Morgan Stanley 
Capital Group, 72 FERC ] 61,082 (1995).
    \16\ See, e.g., Citizens Power, 48 FERC ] 61,210 at 61,777 
(``Usually, the source of market power is dominant or exclusive 
ownership of the facilities. However, market power also may be 
gained without ownership. Contracts can confer the same rights of 
control. Entities with contractual control over transmission 
facilities can withhold supply and extract monopoly prices just as 
effectively as those who control facilities through ownership.'').
    \17\ See April 14 Order, 107 FERC ] 61,018 at P 95; 108 FERC ] 
61,026 at P 65; Inquiry Concerning the Commission's Merger Policy 
Under the Federal Power Act: Policy Statement, Order No. 592, 61 FR 
68,595 (1996), FERC Stats. & Regs. ] 31,044 (1996), recons. denied, 
Order No. 592-A, 62 FR 33,341 (1997), 79 FERC ] 61,321 (1997) 
(Merger Policy Statement); see also Revised Filing Requirements 
Under Part 33 of the Commission's Regulations, Order 642, 65 FR 
70,983 (2000), FERC Stats. & Regs. ] 31,111 (2000), order on reh'g, 
Order No. 642-A, 66 FR 16,121 (2001), 94 FERC ] 61,289 (2001).
    \18\ El Paso Electric Power Co., 108 FERC ] 61,107 at P 14 
(2004), reh'g pending.
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Triggering Events Generally

Comments
    19. Several commenters assert that the definitions of triggering 
events are vague or unclear and request that the Commission clarify 
these elements of the proposed regulations.\19\ Some commenters request 
that the Commission clarify these terms by issuing a supplemental NOPR 
offering a detailed description of the specific

[[Page 8256]]

information it needs \20\ or by setting forth clear ``rules of the 
road'' to provide market-based rate sellers guidance as to whether they 
are in compliance with the Commission's requirements.\21\ Cinergy 
Services, Inc. (Cinergy) urges the Commission to limit the scope of the 
present rulemaking to reviewing reporting requirements for changes in 
status relevant to the Commission's current four-part analysis for 
market-based rate authority and to defer consideration of new issues or 
modifications to the current market-based rate tests for the parallel 
rulemaking in Docket No. RM04-7-000.\22\
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    \19\ See, e.g., Xcel Energy Services (Xcel) at 4-5.
    \20\ Barclays Bank PLC, DB Energy Trading, LLC, Aron & Company, 
Merrill Lynch Commodities, Inc., Morgan Stanley Capital Group Inc. 
(Bank Power Marketers) at 13-14; FirstEnergy Service Company 
(FirstEnergy) at 5.
    \21\ Powerex Corporation (Powerex) at 5; Electric Power Supply 
Association (EPSA) at 2.
    \22\ Cinergy at 6.
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    20. Commenters were divided as to whether the Commission should 
include an illustrative list of triggering events. Calpine Corporation 
(Calpine) and Transmission Access Policy Study Group (TAPS) argue that 
the Commission should adopt bright-line standards for what constitutes 
a reportable event and suggest specific events that should trigger the 
reporting requirement, which are discussed further below.\23\ National 
Rural Electric Cooperatives Association (NRECA) argues that the 
Commission should clearly define when the reporting obligation is 
triggered because failure to comply could potentially result in 
retroactive refunds pursuant to the Ninth Circuit's decision in 
California ex rel. Lockyer v. FERC \24\ and/or suspension or revocation 
of market-based rate authority.\25\
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    \23\ Calpine at 4-11; TAPS at 2 and 15.
    \24\ 383 F.3d 1006 (9th Cir. 2004).
    \25\ NRECA at 5.
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    21. On the other hand, the Bank Power Marketers and Industrial 
Energy Users--Ohio and PJM Industrial Customers Coalition (IEU--Ohio/
PJMICC) argue that the Commission should not rely on a laundry list of 
transaction types \26\ or an illustrative list of reporting 
triggers.\27\
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    \26\ Bank Power Marketers at 14.
    \27\ IEU--Ohio/PJMICC at 10-12.
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    22. American Public Power Association (APPA) comments that the 
reporting requirement should provide for the reporting of changes that 
``could affect the public utility's eligibility for [market-based rate] 
authority,'' based on current standards for authorization of market-
based rates, rather than requiring reporting of only those events that 
``would reflect a departure from the characteristics the Commission 
relied upon in granting market-based rate authority.'' \28\
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    \28\ APPA at 7.
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    23. EEI, supported by Pacificorp, argues that the reporting 
obligation should extend only to changes in circumstances within the 
applicant's control. According to EEI, an applicant should not be 
required to report a change of circumstances based on an action taken 
by a competitor (such as a decision to retire a generation unit or take 
transmission capacity out of service) or natural events (such as a high 
hydro-year, higher wind generation or load disruptions due to adverse 
weather conditions) that might change the result of the interim 
screens.\29\
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    \29\ EEI at 10-11; Pacificorp at 7.
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    24. Finally, commenters suggest the following additional triggering 
events: The acquisition of Financial Transmission Right (FTR) positions 
into constrained load pockets that exceed a seller's load obligations 
in the load pocket,\30\ any changes in ISO or RTO status for the 
relevant market; or any changes in state regulations relative to load-
serving obligations in the relevant market; \31\ changes in market 
definition, e.g., due to transmission outages or the change in size of 
a load pocket, provided that such changes are confirmed by the 
independent and published judgment of an ISO or RTO overseeing local 
market power issues pursuant to a Commission tariff.\32\
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    \30\ TAPS at 2 and 15.
    \31\ IEU--Ohio/PJMICC at 10-12.
    \32\ SoCal Edison at 9-10.
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Commission Conclusion
    25. After careful consideration of the comments, the Commission 
rejects commenters' proposals to clarify the reporting requirement by 
including an illustrative list of triggering events or to otherwise 
expand the list of triggering events beyond those contained in the 
NOPR. We reject this suggestion, first, because we believe that the 
definition of triggering events contained in the Commission regulations 
adopted here, offers market-based rate sellers sufficient notice of and 
guidance concerning the scope of their reporting requirement. The 
reporting requirement we adopt herein ensures that the Commission 
retains the discretion and flexibility to protect customers in light of 
future, unforeseen changes in wholesale electricity markets that may 
allow market-based rate sellers to exercise market power. Consequently, 
the Commission does not believe that commenters have provided 
sufficient support for their contention that the inclusion of an 
illustrative list would in fact increase regulatory certainty.
    26. In response to the request of Cinergy, we clarify that the 
reporting requirement is limited to reviewing changes in status 
relevant to the Commission's current four-part analysis for market-
based rate authority and that the Commission will not consider any new 
tests or modifications of its current four-part test in this docket. 
APPA has argued that the Commission should change its existing 
reporting requirement--which obligates market-based rate sellers to 
report changes that ``would reflect a departure from the 
characteristics the Commission relied upon in granting market-based 
rate authority''--to require reporting of changes that ``could affect 
the public utility's eligibility for [market-based rate] authority,'' 
based on current standards for authorization of market-based rate 
authority. We clarify that the ``characteristics'' refer to the 
Commission's four-part test and our analysis thereof. The Commission 
evaluates any request to obtain or retain market-based rate authority 
under its currently applicable standards for each of the four prongs; 
similarly, a notice of change in status is required in circumstances 
where the factors the Commission relied upon in evaluating the four-
part test as it applies to an applicant change. Under these 
circumstances, the Commission will apply the currently applicable 
standard in its assessment of whether that entity may continue to make 
sales at market-based rates. Second, APPA's proposal to require 
reporting of changes that ``could affect the public utility's 
eligibility for [market-based rate] authority'' appears to be more 
subjective than our current standard and could result in sellers 
reporting information that the Commission would not consider relevant. 
We believe that we have given sufficiently clear guidance regarding 
triggering events to limit market-based rate sellers' discretion to 
avoid reporting changes in status that would confer or enhance market 
power.
    27. We agree with EEI that the reporting obligation should extend 
only to changes in circumstances within the knowledge and control of 
the applicant. Accordingly, an applicant should not be required to 
report a change in circumstances based on an action taken by a 
competitor (such as a decision to retire a generation unit or take 
transmission capacity out of service) or natural events (such as hydro-
year, higher wind generation or load disruptions due to adverse weather 
conditions). While we will not expand

[[Page 8257]]

the triggering events as proposed in the NOPR in this Final Rule, 
interested persons can pursue these matters in the course of the 
generic rulemaking we have established in Docket No. RM04-7-000, which 
will address proposed modifications to the Commission's current four-
part test for granting market-based rate authority.

Exemptions

Comments
    28. Commenters suggest a number of events that should be exempted 
from the reporting requirement. BP Energy Company (BP Energy), Cinergy, 
Duke Energy Corporation (Duke), EPSA, FirstEnergy, and Edison Electric 
Institute and Alliance of Energy Suppliers (EEI) contend that the 
reporting requirement should not apply to events covered by section 203 
applications.\33\
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    \33\ BP Energy at 4-5; Cinergy at 16-17; Duke at 11-12; EPSA at 
8-9; EEI at 4-5; FirstEnergy at 17-18.
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    29. Bank Power Marketers and Westar Energy, Inc. (Westar) oppose 
the proposals contained in the NOPR on the ground that the proposed 
reporting requirement would be both excessive and duplicative, given 
that the Commission already receives the same information through 
existing reporting requirements, e.g., section 203 applications, 
triennial updates, Electric Quarterly Reports (EQR), Form 3-Q, etc.\34\
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    \34\ Bank Power Marketers at 6-12; Westar at 2-4.
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    30. EEI and PacifiCorp argue that long-term contracts should not be 
reportable.\35\ National Grid USA (National Grid) argues that market-
based rate sellers should not be required to report long-term contracts 
that were entered into either to satisfy their ``provider of last 
resort'' (POLR) obligations or through state-regulated competitive 
solicitation processes that are consistent with the Commission's 
standards for inter-affiliate transactions.\36\ National Grid and IEU--
Ohio/PJMICC also support the exemption of purchases from qualified 
facilities mandated by the Public Utility Regulatory Policies Act of 
1978 (PURPA).\37\
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    \35\ EEI at 4, 9-11; PacifiCorp at 5-7.
    \36\ National Grid at 4-5.
    \37\ 16 U.S.C. 1601 et seq. (2000); National Grid at 3-4; IEU--
Ohio/PJMICC at 7.
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    31. Duke suggests that the following events should be exempt: (i) 
Transactions outside market-based rate sellers' home or first-tier 
control area markets; (ii) affiliate transactions subject to other 
reporting requirements; (iii) transactions involving post-1996 
generation facilities; and (iv) intra-corporate reorganizations that do 
not involve the acquisition of additional assets and thus do not affect 
market share or concentration.\38\ Cinergy argues that the reporting 
obligation should not apply to transactions that do not increase 
ownership or control, specifically: (i) Intra-corporate transactions 
between affiliates within one holding company system or transactions 
that are simply a change in corporate form; (ii) purely financial 
transactions such as futures, swaps and derivatives that do not have a 
physical component; and (iii) construction of new generation otherwise 
exempt under Commission regulations.\39\ Tucson Electric Power Company 
(Tucson Electric) urges the Commission to exempt entities subject to 
oversight by an Independent Market Monitor (IMM) because the IMM will 
investigate and report to the Commission any anticompetitive 
behavior.\40\
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    \38\ Duke at 11-13.
    \39\ Cinergy at 12-17 (citing 18 CFR 35.27(a) (2004)).
    \40\ Tucson Electric at 3-4.
---------------------------------------------------------------------------

    32. Finally, Cinergy and Tractebel urge the Commission to clarify 
that the Commission is only concerned with changes in status that may 
increase market power, but not those that decrease it, so, for example, 
the purchase of generation might trigger the reporting requirement, but 
a sale should not.\41\ Similarly, Calpine argues that a public 
utility's decrease in generation capacity cannot increase its 
generation market power over what the Commission assumed when it 
granted market-based rate authority, so it would be a waste of 
resources to require such reporting.\42\
---------------------------------------------------------------------------

    \41\ Cinergy at 14-15; Tractebel at 6. Other commenters, in 
contrast, urge the Commission to treat the retirement or 
deactivation of generation as a triggering event. See, e.g., 
California Electricity Oversight Board (California EOB) at 2; IEU--
Ohio/PJM ICC at 12.
    \42\ Calpine at 4-5.
---------------------------------------------------------------------------

    33. With respect to changes in ownership or control of transmission 
facilities, EEI, FirstEnergy and National Grid argue that, given the 
existence of the open access transmission tariff (OATT) requirement, 
which constrains the exercise of vertical market power, there should be 
no reporting requirement for changes in status regarding transmission 
facilities covered by an OATT.\43\ National Grid urges the Commission 
to defer the establishment of reporting requirements associated with 
changes in transmission market power status until it has developed, in 
the context of Docket No. RM04-7-000, more of an understanding of what 
transmission market power is and how it might be abused.\44\ EEI, 
FirstEnergy, and National Grid all argue that, since any transfer of 
ownership or control of transmission facilities would be covered by a 
section 203 application, a separate reporting requirement in the 
context of market-based rate authority is unnecessary and 
duplicative.\45\ National Grid argues that such a reporting requirement 
might discourage transmission providers from transferring their 
transmission facilities to Independent Transmission Companies 
(ITCs).\46\ Finally, National Grid contends that construction 
activities undertaken pursuant to a Commission-approved regional 
planning process should not be reportable because additional 
transmission capacity improves competition among resources.\47\
---------------------------------------------------------------------------

    \43\ EEI at 7-8; FirstEnergy at 16-18; National Grid at 7.
    \44\ National Grid at 6. See also EEI at 13-14 (urging the 
Commission to consolidate the generic market-based rate rulemaking 
in Docket No. RM04-7-000 with the changes in status rulemaking in 
Docket No. RM04-14-000).
    \45\ EEI at 7-8; FirstEnergy at 16-18; National Grid at 6-7.
    \46\ National Grid at 8-9.
    \47\ National Grid at 10-11.
---------------------------------------------------------------------------

Commission Conclusion
    34. In order to avoid unnecessary duplication of effort, we clarify 
that a market-based rate seller may incorporate by reference in its 
notice of change in status any filings regarding the change in status 
made pursuant to other reporting requirements. Furthermore, intra-
corporate reorganizations that do not otherwise have an impact on our 
four-part test and are not otherwise reportable need not be reported as 
a change in status.
    35. We reject commenters' proposal to exempt from the reporting 
requirement transactions that are subject to other reporting 
requirements, such as dispositions of jurisdictional facilities covered 
by section 203 applications and long-term contracts or affiliate 
transactions that are filed pursuant to section 205. The Commission can 
best exercise its statutory duty to ensure just and reasonable rates by 
imposing an enforceable post-approval reporting requirement regarding 
changes in status.\48\ Appropriate market monitoring cannot be 
satisfied simply by ensuring that public utilities are complying with 
other provisions of the FPA. Moreover, as discussed below, the time and 
effort required to prepare the notice of a change in status--consisting 
of a

[[Page 8258]]

transmittal sheet and a brief narrative statement--will be de minimis 
and will constitute a fraction of that required to submit the section 
203 application or section 205 filing. Furthermore, the information 
required to comply with the reporting requirement would normally be 
collected by the market-based rate seller in the ordinary course of 
preparing the underlying filing.
---------------------------------------------------------------------------

    \48\ See, e.g., Elizabethtown Gas Co. v. FERC, 10 F.3d 866, 870 
(DC Cir. 1993) Louisiana Energy and Power Authority v. FERC, 141 
F.3d 365, 369-370 (DC Cir. 1998).
---------------------------------------------------------------------------

    36. We also reject Tucson Electric's proposal to exempt 
transactions involving entities subject to oversight by an IMM. 
Consistent with our decision not to allow an exemption from the 
generation market power analysis for sales into an ISO/RTO with 
Commission-approved market monitoring and mitigation, we will not 
exempt from the change in status reporting requirement entities subject 
to oversight by an IMM. The Commission has an independent statutory 
duty to ensure that rates are just and reasonable, and we cannot 
delegate this responsibility in these circumstances to an IMM.
    37. Commenters also propose to exempt transactions outside the 
applicant's home or first-tier control area markets and to exempt new 
construction. These commenters have not presented any persuasive 
evidence that these transactions--to the extent that they are covered 
by the Commission regulations adopted herein and satisfy the 
materiality threshold set forth below--should be treated differently.
    38. As a general matter, we reject Duke's suggestion that 
acquisitions of post-1996 generation be exempt from the reporting 
requirement. Section 35.27 merely adopts a rebuttable presumption that 
post-1996 generation cannot exercise market power,\49\ and the 
Commission considers post-1996 generation in initial applications for 
and triennial reviews of market-based rate authority under appropriate 
circumstances.\50\ However, we clarify that to the extent that the 
generation owned or controlled by an applicant [in the relevant market] 
and its affiliates is post-1996, and the applicant or an affiliate 
acquires through purchase or acquisition additional post-1996 
generation, no change in status filing is required. The Commission has 
found that in circumstances where construction of all of an applicant's 
generation commenced after July 9, 1996, no interim generation market 
power analysis need be performed.\51\ On the other hand, in the above 
example, if the applicant owned pre-1996 generation a change in status 
filing may be required since the Commission has stated that if an 
applicant sites generation in an area where it or its affiliates own or 
control other generation assets, the applicant must study whether its 
new capacity, when added to the existing capacity, raises generation 
market power concerns.\52\ Finally, we note that the generic rulemaking 
in Docket No. RM04-7-000 will address whether the Commission should 
retain the exemption for post-1996 generation in section 35.27 of the 
Commission's regulations.
---------------------------------------------------------------------------

    \49\ 18 CFR 35.27 (2004)
    \50\ April 14 Order, 107 FERC ] 61,018 at P 116.
    \51\ July 8 Order, 108 FERC ] 61,026 at P 110.
    \52\ See e.g., LG&E Capital Trimble County LLC, 98 FERC at 
62,034-35.
---------------------------------------------------------------------------

    39. In response to Cinergy's request, we clarify that purely 
financial transactions involving future swaps and derivatives that do 
not provide for physical delivery are exempt from the reporting 
requirement for the same reason that such contracts need not be 
reported in Electric Quarterly Reports (EQRs).\53\
---------------------------------------------------------------------------

    \53\ Revised Public Utility Reporting Requirements, Order No. 
2001-F, 106 FERC ] 61,060 at P 15 (2004).
---------------------------------------------------------------------------

    40. The Commission accepts the proposal submitted by Calpine, 
Cinergy and Tractebel that a decrease in ownership or control due to 
dispositions of generation, transmission or inputs to production should 
not be reportable to the extent such transaction decreases the 
applicant's generation market power as measured by the indicative 
screens.
    41. Finally, we reject National Grid's arguments that long-term 
contracts that were entered into by a utility to satisfy its POLR 
obligations or pursuant to a state-regulated competitive solicitation 
process should be exempted from the reporting requirement. To the 
extent that an applicant acquires additional capacity that impacts the 
Commission's analysis of one or more prongs of the four-part test used 
in evaluating whether to grant market-based rate authority, a change in 
status filing is required.

Control/Ownership

Comments
    42. Several commenters express support for the inclusion of 
``control'' as a triggering event. In supporting the inclusion of 
control as a triggering event, the California EOB argues that the 
concept of control should be used to expand the scope of the triggering 
requirements, not narrow them.\54\
---------------------------------------------------------------------------

    \54\ California EOB at 3.
---------------------------------------------------------------------------

    43. Other commenters argue that the definition of control is vague 
and overly broad and note, for example, that it could be interpreted to 
cover individual power purchase transactions.\55\ These commenters 
argue that the Commission should narrowly define control by identifying 
the specific decision-making authority that the purchaser or reseller 
must have in order to constitute control. PG&E argues that control 
should only cover cases where the purchaser has operational control of 
the resource, i.e., the ability to determine when it is available for 
operation, and should not apply to an entity who has contracted for the 
first right, or even the exclusive right, to call or dispatch the 
resource when it is needed.\56\ FirstEnergy contends that market-based 
rate sellers should only be required to report long-term contracts that 
transfer to the purchaser or reseller the authority over dispatch of 
the unit and preclude the generation owner from dispatching the unit 
without the consent of the purchaser or reseller.\57\ Similarly, Duke 
Energy Corporation (Duke) argues that the Commission should apply 
general principles of agency as developed by Commission precedent, 
whereby the Commission has found that a purchaser has control if it 
possesses decisionmaking authority over key operations, such as 
decisions to commit or de-commit a generator or to make or not make 
sales.\58\ EPSA agrees that control over an asset is a key 
consideration in a market power analysis. However, EPSA states that the 
use of the term ``operational control'' creates uncertainty and 
suggests that the Commission drop all references to ``operational 
control'' and replace it with ``scheduling and dispatch control'' or 
clarify that operational control refers to a contractual right to 
control the output of a plant.\59\ The Bank Power Marketers suggest 
that the factors indicating control include definitive authority to: 
Require a plant to run or to shut down; declare unscheduled outages; or 
establish output levels when running (i.e., to ramp-up or down).\60\
---------------------------------------------------------------------------

    \55\ See, e.g., Powerex at 8.
    \56\ PG&E at 9.
    \57\ FirstEnergy at 11-12.
    \58\ Duke at 3-7. Duke proposes that the analysis should thus 
focus on whether the arrangement shifts to a third party the 
economic decisionmaking authority regarding such matters as whether 
to buy and sell power, what products should be offered and what 
market should be bid into, which parties to transact with, or the 
prices and terms for service.
    \59\ EPSA at 6-7.
    \60\ Bank Power Marketers at 14.
---------------------------------------------------------------------------

    44. Calpine suggests that the test for control should be whether 
the purchaser has the authority to make available to the market and 
withhold from the market generation products associated

[[Page 8259]]

with generation capacity.\61\ For example, Calpine submits that a 
tolling agreement should be reportable if it permits a public utility 
to operate a plant that gives it the authority to generate or not 
generate from that plant.\62\ Cinergy argues that control should be 
defined in a manner that is more directly linked to standard measures 
of market power as used by the Commission and the antitrust agencies, 
i.e., whether a new contractual arrangement provides an applicant with 
the ability to economically or physically withhold from the market, or 
erect a barrier to entry.\63\ For the same reasons, TAPS urges the 
Commission to require reporting of long-term maintenance agreements 
between market-based rate sellers or their affiliates that grant the 
entity providing the maintenance services the ability to decide when 
such maintenance is performed. TAPS contends that, if the entity 
providing maintenance also operates facilities in the same market (or 
has an affiliate that does so), its decisions about when to perform the 
maintenance (thereby possibly requiring an outage) could be influenced 
by its (or its affiliate's) sales activities in the market.\64\
---------------------------------------------------------------------------

    \61\ Calpine at 5.
    \62\ Calpine at 6-7. See also APPA at 19; TAPS at 19 (discussing 
tolling agreements).
    \63\ Cinergy at 7.
    \64\ TAPS at 19-20.
---------------------------------------------------------------------------

    45. SoCal Edison requests that the Commission identify the duration 
of the change in control necessary to trigger the reporting 
requirement. According to SoCal Edison, very short-term transactions 
may temporarily convey control over a resource, but it is doubtful that 
requiring reporting of such transactions 30 days after their conclusion 
will provide meaningful or useful information to the Commission. SoCal 
Edison suggests that the appropriate minimum duration would be at least 
a 32-day transaction involving change in control.\65\ SoCal Edison also 
argues that the Commission should consider focusing primarily on net 
changes in control of uncommitted generation.\66\
---------------------------------------------------------------------------

    \65\ SoCal Edison at 4.
    \66\ SoCal Edison at 6.
---------------------------------------------------------------------------

    46. BP Energy urges the Commission to clarify that the reporting 
requirement is limited to ownership or contractual control equivalent 
to ownership, rather than ``influence'', which is vague and subject to 
conflicting interpretations.\67\ FirstEnergy argues that market-based 
rate sellers should only be required to report changes in ownership 
that result in a change in control. FirstEnergy states that the 
Commission has previously recognized that certain passive owners of 
generation assets do not have control over such assets, and therefore 
do not constitute regulated public utilities. According to FirstEnergy, 
even if a public utility acquires or increases its ownership interest 
in a generation or transmission facility, it would not be appropriate 
to attribute the capacity in that facility to the utility, unless the 
utility had decisionmaking authority over sales of electric energy from 
the facility. FirstEnergy asserts that it is essential that the 
Commission define more precisely when a change in ownership or control 
conveying the requisite decisionmaking authority is deemed to have 
occurred. It notes that the Commission has previously ruled that a 
voting interest of 10 percent or more creates a rebuttable presumption 
of control over a utility that is not an EWG and that a voting interest 
of five percent or more is used in the case of a utility that is an 
EWG.\68\ FirstEnergy submits that, as a practical matter, it is 
unlikely that a voting interest that is less than or equal to these 
thresholds, without more, will convey decisionmaking authority over 
sales of electric energy. FirstEnergy thus suggests that the Commission 
should adopt a higher threshold of asset ownership of at least 33.3 
percent before a potentially reportable change in control is deemed to 
have occurred.\69\ FirstEnergy adds that even a 33.3 percent voting 
interest should not be deemed to have transferred decisionmaking 
control if another entity (either individually or in conjunction with 
affiliated interests) owns a larger voting interest.
---------------------------------------------------------------------------

    \67\ BP Energy at 2, 5-6. BP Energy submits, for example, that 
if a public utility has a first call option on the output of a given 
generator but no control over the operation of that facility, the 
public utility seller should not be subject to the reporting 
requirement.
    \68\ FirstEnergy at 11 (citing Morgan Stanley Capital Group, 
Inc., 72 FERC ] 61,082 (1995)).
    \69\ FirstEnergy at 11.
---------------------------------------------------------------------------

Commission Conclusion
    47. We will adopt the inclusion of control as one of the factors 
that could result in a change of status filing. We have previously 
stated that ``control'' refers to arrangements, contractual or 
otherwise, granting control of generation or transmission facilities, 
just as effectively as they could through ownership.\70\ In short, if 
an applicant has control over certain capacity such that the applicant 
can affect the ability of the capacity to reach the relevant market, 
then that capacity should be attributed to the applicant when 
performing the generation market power screens.\71\ As the Commission's 
guidelines for the assessment of mergers and its generation market 
power analysis for market-based rate authority provide, for the 
purposes of the market power analysis, the capacity associated with 
contracts that confer operational control of a given facility to an 
entity other than the owner must be assigned to the entity exercising 
control over that facility, rather than to the entity that is the legal 
owner of the facility. We believe that the Commission has given 
adequate specificity as to what constitutes control and the Commission 
will not, in this docket, further define or narrow the definition. 
Control of assets is a concept that this industry has dealt with for 
many years. The Commission is reluctant to provide a laundry list of 
agreements that may or may not constitute control of an asset. It is 
not possible to predict every contractual agreement that could result 
in a change of control of an asset. However, to the extent parties wish 
to propose specific definitions or clarifications to the Commission's 
historical definition of control, they may do so in the course of the 
market-based rate rulemaking in Docket No. RM04-7-000.
---------------------------------------------------------------------------

    \70\ Citizens Power, 48 FERC ] 61,210 at 61,777.
    \71\ July 8 Order, 108 FERC ] 61,026 at P 65.
---------------------------------------------------------------------------

    48. In response to SoCal Edison's request that the Commission 
identify the duration of the change in control necessary to trigger the 
reporting requirement, we clarify that long-term contracts with a 
duration of a year or more must be reported, which is consistent with 
our treatment of long-term contracts in the April 14 Order.\72\
---------------------------------------------------------------------------

    \72\ April 14 Order, 107 FERC ] 61,018 at P 155.
---------------------------------------------------------------------------

Affiliation

Comments
    49. Commenters also request clarification as to the scope of 
affiliate-related reporting requirements.\73\ BP Energy states that, as 
proposed, the reporting obligation appears to attach to affiliation 
with any entity not disclosed in the original application that owns or 
controls generation or transmission facilities or inputs to electric 
power production, or any entity with a franchised service territory. BP 
Energy requests clarification that the reporting requirement does not 
require a public utility with market-based rates to file a notice of a 
change in status if an affiliated generator identified in the original 
application increases the amount of generation it owns, so long as the 
public utility with market-based

[[Page 8260]]

rates does not own or control the newly-acquired generation.\74\
---------------------------------------------------------------------------

    \73\ BP Energy at 2, 7-8.
    \74\ BP Energy at 7-8 and Sempra 10-11.
---------------------------------------------------------------------------

    50. Sempra Energy Global Enterprises (Sempra) seeks a similar 
clarification that, when updating information regarding activities of 
affiliates, a market-based rate seller is only required to report new 
affiliations and would not be required to report changes in status on 
behalf of other affiliates whose existence has already been disclosed 
to the Commission. Sempra adds that a market-based rate seller should 
only be required to provide information that relates to a new 
affiliation in markets where the seller's relevant operations or assets 
overlap with those of the new affiliate.\75\
---------------------------------------------------------------------------

    \75\ Sempra at 10-11.
---------------------------------------------------------------------------

Commission Conclusion
    51. With respect to BP Energy's and Sempra's request for 
clarification, as noted above, the reporting requirement applies to 
changes in status relevant to the Commission's current four-part 
analysis for market-based rate authority. To the extent that an 
affiliate experiences a change in status, such change in status must be 
reported to the extent that it impacts the factors the Commission 
relied upon in evaluating the four-part test as it applies to the 
applicant and granting the applicant market-based rate authority. To 
avoid any unnecessary duplication, we clarify that the various 
affiliates within a corporate family may submit a single notice for the 
corporate family as a whole for each reportable change in status that 
occurs listing all affiliated companies holding market-based rate 
authority in such notice.

Inputs to Electric Power Production

    52. We noted in the NOPR that the Commission's general practice has 
been to require notifications of changes in status when the market-
based rate applicant obtained ownership of new inputs to electric power 
production, other than fuel supplies. However, since the Commission is 
interested in being informed of significant acquisitions of ownership 
or control of any inputs to electric power production, we proposed to 
require a reporting obligation to this effect and sought comments on 
this proposal.

Comments

    53. A number of commenters request clarification of the term 
``inputs to electric power production'' and urge the Commission to 
define this term to include or exclude certain inputs. APPA, EPSA, 
Powerex and TAPS submit that fuel supplies should not be considered 
inputs to electric power production.\76\
---------------------------------------------------------------------------

    \76\ APPA at 15; EPSA at 4; Powerex at 9; TAPS at 15.
---------------------------------------------------------------------------

    54. Cinergy argues against a reporting obligation for fuel supplies 
because, according to Cinergy, the Commission has found the markets for 
natural gas and coal to be workably competitive. Cinergy asserts that 
information regarding fuel supplies is typically not required for the 
initial application for market-based rate authority and therefore 
should not be presumed to be relevant to the question of continued 
eligibility for market-based rate authority. Thus, in light of the lack 
of benefits to be obtained from the reporting of fuel supply 
arrangements, Cinergy contends that reporting would be unduly 
burdensome. Cinergy also contends that the only conceivable relevance 
of fuel supplies in authorizing market-based rates is in demonstrating 
that no barriers to entry or vertical market power concerns are 
present. To the extent that the Commission wishes to extend its 
consideration of barriers to entry to fuel supplies, Cinergy argues 
that the appropriate context to do so is not in the current rulemaking, 
but rather in the generic rulemaking proceeding in Docket No. RM04-7-
000.\77\
---------------------------------------------------------------------------

    \77\ Cinergy at 8-10.
---------------------------------------------------------------------------

    55. APPA, Calpine, the National Association of State Utility 
Consumer Advocates (NASUCA) and TAPS, however, support the inclusion of 
fuel supplies within the list of triggers for reporting changes in 
status. NASUCA states that electric utilities, power brokers, and other 
sellers of energy at market-based rates can acquire substantial control 
over natural gas supplies or other sources of fuel for generating units 
and effectively dominate the fuel supplies in the markets in which they 
also sell electricity. According to NASUCA, including fuel supplies 
within the category of changes that warrant a reporting requirement 
properly reflects the convergence of the electricity and natural gas 
industries and the potential for exercising market power that can 
result from the acquisition of critical supplies of fuel.\78\ Calpine 
similarly asserts that the ability to control the transportation of 
inputs such as fuel may be just as important as controlling the input 
itself.\79\
---------------------------------------------------------------------------

    \78\ NASUCA at 9-10.
    \79\ Calpine at 8-9. See also at 15; TAPS at 15. APPA and TAPS 
argue that affiliation or control over companies that produce or 
deliver fuel and long-term contracts for fuel transportation or 
storage should be reportable.
---------------------------------------------------------------------------

    56. With respect to pipeline capacity, EPSA argues that increased 
pipeline capacity holdings should not be reportable because firm 
capacity is obtained through Commission-authorized programs and is 
posted on the pipeline's bulletin board.\80\ FirstEnergy, by contrast, 
argues that changes in status relating to ownership or control of 
interstate natural gas pipelines or local distribution companies should 
be reportable because control over natural gas supplies are the 
principal input to electric power production may enable an entity with 
market-based rate authority to erect barriers to entry by competitors, 
especially if the seller is a combination electricity/natural gas 
utility. FirstEnergy asserts that the acquisition of other inputs, 
e.g., generation plant sites, construction or engineering companies or 
fuel production resources, should not be reportable.\81\
---------------------------------------------------------------------------

    \80\ Powerex at 9 and EPSA, 4.
    \81\ FirstEnergy at 19-21.
---------------------------------------------------------------------------

    57. Other commenters also argue that the Commission's inquiry 
should be focused on the potential for market-based rate sellers to 
erect barriers to entry. Bank Power Marketers argue that the Commission 
should issue a supplementary NOPR to provide additional guidance on 
what level of ownership or control of inputs to electric power 
production is ``significant'' enough to warrant disclosure and submits 
that, in order to be ``significant'', the acquisition of an input must 
be of the type that gives the acquirer vertical market power; 
otherwise, such acquisitions should not be reportable.\82\ Similarly, 
Sempra argues that the Commission has never clearly defined the scope 
of what constitutes ``inputs to electric power production'' and that it 
should either be deleted or, alternatively, the Commission should 
implement a ``timeout'' with regard to enforcement of the reporting 
requirement for such inputs until it has completed its consideration of 
the barriers to entry prong of its market-based rate analysis in the 
Docket No. RM04-7-000 proceeding.\83\ BP Energy contends that the 
disclosures should be limited to only the information necessary to 
identify the type and the source of potential barriers to entry.\84\ BP 
Energy states that the Commission should identify specifically what the 
relevant ``inputs to electric power production'' are, and it should 
state clarify whether

[[Page 8261]]

such inputs include items other than those specified in previous 
orders, i.e., ownership or control of new generation sites, fuel 
supplies (natural gas, oil or coal), transportation of fuel supplies or 
whether the affiliate is a supplier of electric equipment.\85\ Duke 
argues that an arrangement regarding inputs to electric power 
production should only be reportable if it conveys to the market-based 
rate seller the decisional control sufficient to enable it to erect 
barriers to entry. Under this approach, Duke contends that natural gas, 
oil or coal transportation or storage contracts and fuel purchase 
contracts should not be reportable.\86\
---------------------------------------------------------------------------

    \82\ Bank Power Marketers at 14-16.
    \83\ Sempra at 4-6.
    \84\ BP Energy at 8-9 (citing Vermont Electric Coop., 108 FERC ] 
61,223, at P 12 (2004).
    \85\ BP Energy at 8-9 (citing Vermont Electric Coop., 108 FERF ] 
61,223, at p 12 (2004)).
    \86\ Duke at 5.
---------------------------------------------------------------------------

Commission Conclusion

    58. As we stated in the NOPR, the Commission's general practice has 
been to require notification of changes in status when the market-based 
rate applicant obtained ownership of new inputs to electric power 
production, other than fuel supplies. However, we proposed in the NOPR 
to include fuel supplies as an input to electric power production and 
sought comments on this proposal. After careful consideration of the 
comments, including the arguments raised by commenters that this issue 
in any event is more appropriately raised in the proceeding in Docket 
No. RM04-7-000 as part of the Commission's consideration of the 
barriers to entry prong of the market-based rate analysis, we have 
decided not to make any changes to our precedent at this time as to 
what constitutes an input to electric power production, including 
expanding the definition to include fuel supplies. As a result, the 
regulations we adopt in this rule will require the reporting of 
ownership or control of inputs to electrical power production, other 
than fuel supplies. Nevertheless, we will provide interested persons an 
opportunity to propose modifications to this approach in the course of 
the generic rulemaking proceeding in Docket No. RM04-7-000.
    59. Further, we clarify that an arrangement regarding inputs to 
electric power production, other than fuel supplies, is reportable to 
the extent that the factors the Commission relied on in evaluating the 
four-part market-based rate test as it applies to the applicant change.

Materiality Threshold

    60. We recognized in the NOPR that the language in the proposed 
regulations may be susceptible to different interpretations among 
market-based rate sellers concerning the scope of their reporting 
requirement. Accordingly, we sought public comment as to whether and 
how this language should be modified to ensure that the types of 
changes in status that could impact the continued basis of a grant of 
market-based rate authority are identified and timely reported to the 
Commission. For example, we asked whether there should be a threshold 
level of increases in generation (such as through acquisition, self-
build, long-term power purchases, re-powering) that would trigger the 
reporting requirement. If so, we asked what amount of increase in 
generation should trigger the reporting requirement.

Comments

    61. Several commenters suggest specific materiality thresholds by 
designating a particular amount or percentage of increase in generation 
capacity as the trigger for the reporting requirement, while others 
urge the Commission to clearly define the threshold without suggesting 
a particular amount.\87\ For example, APPA, TAPS, and Tractebel suggest 
a threshold of 100 MW.\88\ APPA and TAPS further suggest that 
acquisitions of 100 MW or more should be promptly reported with all 
capacity changes (increases or decreases) identified as part of the 
market-based rate sellers' Order No. 2001 quarterly transactions 
reports.\89\ Powerex argues that the materiality threshold should be no 
less than a 250 MW change increase in the ownership or control of 
generation capacity from the last triennial review or the last notice 
of a change in status.\90\ EEI, supported by Xcel, proposes that the 
reporting threshold should be an increase in net excess generation 
capacity (i.e., an increase in the applicant's generation capacity 
above its forecasted native load growth requirements, reliability 
requirements and contractual obligations) that is equal to the greater 
of: (i) 250 MW, (ii) 10 percent of installed nameplate generation 
capacity, or (iii) five percent of the capacity in the control area 
market.\91\ FirstEnergy suggests that an increase in generation 
capacity should trigger the reporting requirement if it exceeds the 
greater of either 250 MW or a 10 percent increase in the market-based 
rate seller's uncommitted generation capacity.\92\
---------------------------------------------------------------------------

    \87\ NRECA at 5; Sempra at 9-10.
    \88\ APPA at 2; TAPS at 2; Tractebel at 7.
    \89\ APPA at 2 and 17, TAPS at 2.
    \90\ Powerex at 5.
    \91\ EEI at 6-7.
    \92\ FirstEnergy at 22-23.
---------------------------------------------------------------------------

    62. BP Energy and EPSA both contend that the materiality threshold 
should take into account the increase in the market-based rate seller's 
market share and its impact on the relevant geographic market, as well 
as the absolute amount of the increase in generation capacity. EPSA 
suggests that the materiality threshold should be in the range of 250-
500 MW or one to two percent of the installed capacity in a market 
area.\93\ BP Energy proposes a materiality threshold for ownership or 
control of generation that would be the greater of a net positive 
change of 300 MW or one to two percent of the installed capacity in the 
relevant market (determined by ISO/RTO or NERC region or control 
area).\94\ ELCON proposes that the final rule should include a 
materiality threshold for large, end-use corporations for changes in 
generation at its production sites, e.g., a 300 MW increase in 
generation, or alternatively, an increase in generation equal to one or 
two percent of installed capacity in a region market; to the extent 
that the increase in generation is less than this threshold, the 30-day 
reporting requirement should be waived.\95\
---------------------------------------------------------------------------

    \93\ EPSA at 7.
    \94\ BP Energy at 5.
    \95\ ELCON at 3-4.
---------------------------------------------------------------------------

    63. SoCal Edison argues that EEI's proposal should be modified to 
provide that only the 10 percent threshold for increases in generation 
capacity should apply for load-serving entities because such entities 
may add 250 MW or more in the normal course of business--in order to 
meet resource adequacy requirements or in response to normal load 
growth--without effecting any material change in its ability to 
exercise market power.\96\ SoCal Edison proposes that the materiality 
threshold for a change in status other than an increase in generation 
capacity should be a net increase of 10 percent from the data that the 
Commission relied upon in granting market-based rate authority.\97\
---------------------------------------------------------------------------

    \96\ SoCal Edison at 8-9.
    \97\ SoCal Edison at 2-3.
---------------------------------------------------------------------------

    64. Cinergy proposes that a transaction should not be considered 
material if, first, it involves the acquisition of generation that is 
not in the same relevant geographic market as the applicant's existing 
generation. Alternatively, a transaction would not be material if: (i) 
It increases the applicant's generation in the relevant geographic 
market by two percent or less; (ii) the applicant's existing

[[Page 8262]]

generation in the market is low (e.g., less than 1000 MW), and the 
increase is less than 10 percent of the total market; or (iii) the 
acquired generation is in an RTO that has restructured its market.\98\
---------------------------------------------------------------------------

    \98\ Cinergy at 20.
---------------------------------------------------------------------------

    65. PacifiCorp urges the Commission to permit market-based rate 
sellers to rely on forecasts of load growth in determining whether an 
acquisition of new generation resources constitutes a material change 
in the conditions in the market.\99\ According to Pacificorp, a utility 
should be required to report a material change only when it increases 
its net generating capacity by acquiring additional resources in excess 
of its forecasts for native load growth. Avista Corporation (Avista) 
suggests that, for a utility the size of Avista, the threshold level of 
increase in generation before triggering the reporting requirement 
should be not less than 10 percent of the utility's retail and 
wholesale peak load obligations.\100\
---------------------------------------------------------------------------

    \99\ PacifiCorp at 4.
    \100\ Avista at 1-2.
---------------------------------------------------------------------------

    66. NASUCA opposes the establishment of a materiality threshold for 
reporting a change in status, but suggests instead that the Commission 
could exempt from the rule changes in status that do not stem from 
changes in ownership or control of generation, fuel, transmission or 
power supply assets such as a change in corporate name unrelated to a 
merger or acquisition.\101\ According to NASUCA, establishing triggers 
for determining when reporting of a change in status is necessary may 
lead to under-reporting due to varying interpretations of what types of 
assets should be considered. NASUCA asserts that requiring all changes, 
however small, to be reported will permit Commission review and ensure 
that a change in status will not allow a seller with market-based rate 
authority to exercise market power.
---------------------------------------------------------------------------

    \101\ NASUCA at 12.
---------------------------------------------------------------------------

    67. PG&E, as discussed above, opposes the imposition of a uniform 
reporting requirement that imposes identical reporting obligations on 
energy marketers and traditional utilities. PG&E urges the Commission 
to establish, for traditional utilities, a threshold for an increase in 
wholesale sales or revenues from wholesale sales that the Commission 
concludes is statistically relevant or has the potential to influence 
the overall market. Under PG&E's proposal, if a traditional utility's 
quarterly report shows an increase in wholesale sales or revenues from 
wholesale sales that exceeded this threshold, the utility would be 
obligated to provide--in the same quarterly report--additional 
information about the transactions that caused the increase. PG&E 
contends that this proposal, if adopted would ensure that the 
Commission received targeted information, while reducing the burden on 
both utilities and the Commission.\102\

Commission Conclusion
---------------------------------------------------------------------------

    \102\ PG&E at 10-11.
---------------------------------------------------------------------------

    68. After careful consideration of the comments received, the 
Commission has concluded that small increases in generation of less 
than 100 MW need not be immediately reported. However, market-based 
rate sellers must report as a change in status each cumulative increase 
in generation of 100 MW or more that has occurred since the most recent 
notice of a change in status filed by that seller, (i.e. multiple 
increases in generation that individually do not exceed the 100 MW 
threshold must all be reported once the aggregate amount of such 
increases reaches 100 MW or more). The Commission's market power 
analysis, which is performed at the time of an initial application and 
every three years thereafter, considers all relevant generation 
capacity to assess whether a seller lacks, or has adequately mitigated, 
generation market power. In light of these periodic reports, we believe 
that a minimum reporting threshold for generation increases during the 
interim period is appropriate. We believe that this approach strikes 
the proper balance between the Commission's duty to ensure that market-
based rates are just and reasonable and the Commission's desire not to 
impose an undue regulatory burden on market-based rate sellers.
    69. Finally, we believe that the definition of control (i.e., 
arrangements, contractual or otherwise, that grant to a purchaser or 
reseller or to another third party who is not the legal owner of the 
facilities in question operational control over the facility) that we 
discuss earlier in this order already contains within it a materiality 
threshold. Changes in status that do not comprise control (and that do 
not otherwise trigger the reporting requirement) need not be reported.
    70. Likewise, we reject PG&E's proposal to treat traditional 
utilities in this regard differently than other market-based rate 
applicants. PG&E's suggestion that the Commission link the change in 
status reporting requirement to increases in wholesale sales or 
revenues is inconsistent with the market-based rate four-part test 
which evaluates, among other things, whether an applicant is a pivotal 
supplier and the applicant's size in relation to the market. However, 
to the extent an applicant has historical wholesale sales and 
transmission data it believes is relevant, the Commission encourages 
the inclusion of such data in the applicant's submittal, and the 
Commission will consider such data in its analysis.

Transmission Outages

    71. In the NOPR, the Commission also asked whether the applicant 
should have a reporting requirement if portions of the applicant's 
transmission system are taken out of service for a significant period 
of time (thus potentially affecting the scope of the relevant 
geographic market). If so, we sought comments on what criteria should 
trigger this reporting requirement.

Comments

    72. A number of commenters support the extension of the reporting 
requirement to cover transmission outages and propose specific 
thresholds for triggering the reporting requirement. The California 
Public Utilities Commission (California Commission) states that the 
Commission should require reporting (and provide guidelines regarding 
when such reporting is required) when a transmission facility remains 
congested over a specified period of time such that market power could 
result.\103\ Powerex supports the imposition of a reporting requirement 
for transmission outages that last for a significant period of time, 
but requests that the Commission clarify that the reporting requirement 
applies only to the market-based rate seller that owns or controls the 
transmission facilities suffering an outage and not to its 
affiliates.\104\ Powerex notes that, in any case, information on 
transmission outages typically is otherwise available on the 
transmission owner's Open Access Same-Time Information System 
(OASIS).\105\ Calpine submits that the transmission providers' 
reporting requirement should cover instances where a transmission 
outage that lasts 10 days or more results in a decrease of 10 percent 
or more in the amount of total transmission capacity on transmission 
facilities operated by the transmission provider within the control 
area in which the public utility owns or controls generating capacity, 
or in facilities connecting to an adjacent control area.\106\ APPA and 
TAPS propose that transmission providers be required to report all non-
public,

[[Page 8263]]

extended transmission outages to the Commission's Office of Market 
Oversight and Investigation for monitoring and to publicly report 
extended outages of certain designated critical facilities.\107\ NASUCA 
contends that all entities with market-based rate authority affected by 
an extended outage should be required to report such outages regardless 
of whether they own the affected transmission assets.\108\
---------------------------------------------------------------------------

    \103\ California Commission at 3; Powerex at 6.
    \104\ Powerex at 6.
    \105\ Powerex at 6.
    \106\ Calpine at 10.
    \107\ APPA at 2; TAPS at 14.
    \108\ NASUCA p10.
---------------------------------------------------------------------------

    73. Certain investor-owned utilities such as FirstEnergy and Xcel 
oppose a reporting requirement for transmission outages, arguing that 
it is unnecessary because such outages are reported on a transmission 
provider's OASIS.\109\ National Grid argues that transmission outages 
should not be reportable where such outages are administered by 
independent entities such as an ISO or an RTO.\110\
---------------------------------------------------------------------------

    \109\ Xcel at 7-8 and FirstEnergy at 23-24.
    \110\ National Grid at 10.
---------------------------------------------------------------------------

    74. Other investor-owned utilities such as Avista and Cinergy 
support the reporting requirement for major transmission outages that 
last longer than one year.\111\ Duke also agrees that transmission 
outages should be reportable provided that they are expected to last 6 
months or more and that they reduce available transmission capacity on 
the path or flowgate in question by 20 percent of the posted total 
transmission capability of that path.\112\ Cinergy further suggests 
that, for transmission outages that occur within an RTO-operated 
market, the filing of the change in status should be made by the RTO, 
in consultation with the transmission owner.\113\
---------------------------------------------------------------------------

    \111\ Avista at 3; Cinergy at 17-18.
    \112\ Duke at 8.
    \113\ Cinergy at 18.
---------------------------------------------------------------------------

Commission Conclusion

    75. After careful consideration of the comments, we are not 
prepared at this time to require the reporting of transmission outages 
per se as a change in status. However, to the extent a transmission 
outage affects one or more of the factors of the four-part market-based 
rate test (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 of 
status filing would be required. Because such instances would occur on 
a company-specific basis, a minimum threshold (e.g., 10 percent 
reduction in capacity) is not workable. We will consider this matter 
further in the context of the generic rulemaking in Docket No. RM04-7-
000 in which we are addressing, among other things, issues associated 
with transmission market power.

Other Reportable Arrangements

    76. Beyond ownership or control of generation or transmission 
facilities or inputs to electric power production and affiliation with 
any entity not disclosed in the filing that owns or controls generation 
or transmission facilities or inputs to electric power production or 
affiliation with any entity that has a franchised service area, we 
sought comment as to whether there are other arrangements, contractual 
or otherwise, that should be promptly reported to the Commission. For 
example, we posed the following questions:
     What types of arrangements, contractual or otherwise, do 
market-based rate sellers enter into that could cause a need for the 
Commission to revisit the continuing basis of the grant of market-based 
rate authority for such sellers?
     What threshold of materiality, if any, of such 
arrangements should be met before such arrangements need be reported to 
the Commission?
     Should marketing alliances, brokering arrangements, 
tolling agreements or other sales-oriented arrangements be reported?

Comments

    77. APPA, NASUCA and TAPS support the imposition of the reporting 
requirement for such sales-oriented arrangements and request that the 
Commission consider subjecting a wider range of arrangements to the 
reporting requirement.\114\ NASUCA recommends that financial 
transactions including, but not limited to, the above types of sales-
oriented arrangements should be covered by the reporting obligation, 
because such transactions provide the same type of control over power 
sales as ownership of physical assets would.\115\ TAPS recommends that 
the Commission consider long-term maintenance agreements that grant a 
market-based rate seller the ability to decide when such maintenance is 
performed because, if the entity providing maintenance also operates 
facilities in the same market or has an affiliate that does so, its 
decisions about when to perform the maintenance (thereby possibly 
requiring an outage) could be influenced by its or its affiliate's 
sales activities in the market.\116\ APPA, Powerex, and TAPS support an 
approach of listing the specific types of arrangements that the 
Commission expects to be reported to provide clarity to power 
sellers.\117\
---------------------------------------------------------------------------

    \114\ TAPS at 19; APPA at 18.
    \115\ NASUCA at 11.
    \116\ TAPS at 19.
    \117\ APPA at 18; Powerex at 7; TAPS at 19.
---------------------------------------------------------------------------

    78. BP Energy, however, questions whether brokering agreements can 
be subjected to the reporting requirement. BP Energy asserts that it is 
not presently clear whether brokering activities and agreements are 
subject to the Commission's jurisdiction under the FPA.\118\ BP Energy 
requests that, if the Commission intends to require reporting of 
brokering agreements, the Commission should identify the basis and 
scope of its claimed jurisdiction. Tractebel also questions the 
Commission's jurisdiction over such arrangements and argues that 
brokering arrangements should not be reportable, given that information 
on such arrangements need not be reported as part of an application for 
market-based rate authority or a triennial review.\119\
---------------------------------------------------------------------------

    \118\ BP Energy at 6-7 (citing, e.g., Energy East South Glen 
Falls, 86 FERC ] 61,254, at 61,915 (1999); Citizens Energy Corp., 35 
FERC ] 61,198 (1986); APX, Inc., 82 FERC ] 61,287 (1998)).
    \119\ Tractebel at 5.
---------------------------------------------------------------------------

    79. Cinergy, EEI and Sempra argue that the Commission's suggestion 
to require reporting of specific types of contracts would elevate the 
form of the agreement over the substance. Cinergy opposes the 
Commission's proposal in the NOPR regarding other reportable 
arrangements, which it characterizes as a ``label-based'' approach, 
because there is little standardization or uniformity in the industry 
as to the content of such agreements. Cinergy urges the Commission to 
instead focus on the attributes of the agreement in question, i.e., 
what degree of control over generation or transmission it conveys.\120\ 
EEI similarly argues that the reporting requirement should be limited 
to those arrangements in which the seller acquires control over 
generation or transmission facilities, franchised distribution service 
facilities or production inputs exceeding the thresholds established by 
the Commission.\121\
---------------------------------------------------------------------------

    \120\ Cinergy at 10-11.
    \121\ EEI at 13.
---------------------------------------------------------------------------

    80. Sempra opposes as unnecessary the proposal in the NOPR to 
require reporting of specific types of contracts, arguing that the 
Commission's existing requirement that a notice of a change in status 
must be filed when an applicant acquires, or gains control of, 
additional generation or transmission assets already captures a 
transaction like that described in the El Paso Electric Power

[[Page 8264]]

Co. case.\122\ Sempra further argues that to require market-based rate 
sellers to file updates for a broad, ill-defined list of commercial 
arrangements would unfairly place the burden on the market-based rate 
seller to guess which commercial relationships to report, in violation 
of the Commission's decision in Morgan Stanley Capital Group, Inc., 
where the Commission concluded that entities with market-based rate 
authority no longer needed to report ``business and financial 
arrangements between power marketers and their customers and 
transmission providers.\123\
---------------------------------------------------------------------------

    \122\ Sempra at 6-7 (citing 108 FERC ] 61,071 (2004), reh'g 
pending).
    \123\ Id. at 8 (citing 72 FERC ] 61,082 at 61,435 (1995).
---------------------------------------------------------------------------

    81. APPA, Powerex, and TAPS, on the other hand, support an approach 
of listing the specific types of arrangements that it expects to be 
reported because this approach provides clarity to sellers.\124\ For 
example, APPA and TAPS argue that these arrangements should be reported 
because they may provide a market-based rate seller with the means to 
determine whether capacity is offered into a market or whether a 
competitor can or will enter a market and may create opportunities for 
sellers to coordinate their behavior with other competitors. APPA and 
TAPS further emphasize that tolling agreements should be reported 
because they allow a fuel supplier to control the plants' production of 
energy for sale, thus affecting market outcomes, even if the fuel 
supplier does not operate the plant.\125\
---------------------------------------------------------------------------

    \124\ APPA at 18; Powerex at 7; TAPS at 19.
    \125\ APPA at 18-19; TAPS at 19.
---------------------------------------------------------------------------

Commission Conclusion

    82. Based on our review of the comments received, we find that 
contracts or arrangements that convey ownership or control over 
generation, transmission or other inputs to electric power production, 
other than fuel supplies, should be reported as a change in status. 
This is consistent with the four-part test the Commission relies upon 
in determining whether to grant market-based rate authority. 
Specifically, the April 14 Order requires an applicant to include in 
its analysis all capacity owned or controlled by the applicant or its 
affiliates.\126\
---------------------------------------------------------------------------

    \126\ April 14 Order, 107 FERC ] 61,018 at P 95, 100.
---------------------------------------------------------------------------

    83. We agree in principle with the comments submitted by Cinergy, 
EEI and Sempra, which stated that the label placed on a specific 
contract does not determine whether it constitutes a reportable change 
in status. Instead, it is the manner in which the specific terms and 
conditions of the contract or arrangement convey ownership or control 
of the generation, transmission or other inputs to electric power 
production. Nevertheless, we believe that providing a non-exclusive, 
illustrative list of other reportable arrangements will assist market-
based rate sellers in complying with their reporting obligations. 
Therefore, we clarify that agreements that relate to operation 
(including scheduling and dispatch), maintenance, fuel supply, risk 
management, and marketing that transfer the control of jurisdictional 
assets are subject to the change in status reporting requirement. These 
types of arrangements have been referred to as energy management 
agreements, asset management agreements, tolling agreements, and 
scheduling and dispatching agreements.

Form and Content of Reports

    84. With respect to the form and content of change in status 
reports, the NOPR proposed that the market-based rate seller be 
required to submit a transmittal letter including a description of the 
change in status and a narrative explaining whether (and, if so, how) 
this change in status reflects a departure from the characteristics 
relied upon by the Commission in originally granting the seller market-
based rate authority, in particular, whether the change in status 
affects the results of any of the prongs of the four-part test that the 
Commission uses to determine whether a public utility qualifies for 
market-based rate authority. If the 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, we proposed that it 
should clearly state the reasons on which it bases this conclusion.

Comments

    85. BP Energy, California EOB, Calpine, EPSA, and Powerex agree 
that market-based rate sellers should provide a narrative explaining 
the manner in which changes in status reflect a departure from the 
characteristics relied upon for market-based rate authorization.\127\ 
EPSA submits that a short transmittal letter explaining the transaction 
should suffice to put the parties and the Commission on notice of any 
possible change in status. According to EPSA, requiring more of 
applicants would be administratively burdensome, costly and 
unnecessary. EPSA contends that that Commission's goal should be to 
adopt a cost-effective approach to protecting customers from the 
exercise of market power, while at the same time minimizing the costs 
and uncertainty associated with a change in status, and that a short 
transmittal letter would accomplish that goal.\128\
---------------------------------------------------------------------------

    \127\ California EOB at 4; BP Energy at 10; Calpine at 11; 
Powerex at 9; EPSA at 7.
    \128\ EPSA at 7.
---------------------------------------------------------------------------

    86. BP Energy, Calpine, and Powerex argue that the report should 
consist of a narrative only and should not include an updated market 
analysis such as that which is required by the triennial review.\129\ 
Similarly, SoCal Edison supports the timely provision of a narrative 
that includes germane information, including a recitation of the key 
dimensions of the transaction, but opposes a requirement to make an 
extensive showing to justify retention of market-based rate 
authority.\130\
---------------------------------------------------------------------------

    \129\ BP Energy at 9-10; Calpine at 11; Powerex at 9.
    \130\ SoCal Edison at 4-6.
---------------------------------------------------------------------------

    87. With respect to contractual arrangements, the United States 
Department of Justice (DOJ) opposes a reporting requirement that might 
call for a full-blown competitive analysis for every reportable 
transaction and instead suggests that market-based rate sellers simply 
file a copy of the contract concerned along with a summary of its key 
attributes that have an effect on the parties' incentive or ability to 
exercise market power.\131\ DOJ also suggests that Commission limit the 
obligation of applicants to disclose confidential, ``business 
sensitive'' information, which may discourage utilities from entering 
into otherwise efficient agreements, and customer-specific transaction 
data, which may reduce competition by facilitating collusion among 
competitors in oligopolistic markets.\132\
---------------------------------------------------------------------------

    \131\ DOJ at 11-12. DOJ asserts that the most important data are 
the names of the parties to the contract, the location of the 
generating assets under contract, and the location of any other 
generating assets owned or otherwise controlled by either 
counterparty, which would allow the Commission to quickly determine 
whether there is any geographic overlap among generating assets 
controlled by the parties. Other pertinent information includes 
information regarding any ownership interests parties have in 
common, the compensation scheme established between them, and 
agreement execution and start dates. DOJ at 8-9.
    \132\ DOJ at 313.
---------------------------------------------------------------------------

    88. Cinergy proposes that the Commission adopt a two-tiered 
approach to reporting, depending on whether the event to be reported is 
material or not. In cases where an applicant concludes in good faith 
that the change is non-material, the applicant would submit a short 
letter describing the event and briefly informing the Commission why 
the applicant believes the event is non-material. For material changes 
in status,

[[Page 8265]]

the applicant would describe with greater particularity the basis for a 
continued grant of market-based rate authority, including an updated 
market analysis where appropriate.\133\
---------------------------------------------------------------------------

    \133\ Cinergy at 19.
---------------------------------------------------------------------------

    89. NRECA urges the Commission to minimize the reporting 
requirement for smaller market participants. NRECA suggests that the 
Commission could do so by including in the final rule a provision for 
waiver of the reporting requirement for small market participants that 
can show that the likelihood that the changes in status in question 
could affect the competitiveness of those markets is de minimis. 
Alternatively, the Commission could clarify that the report for small 
market participants may be as simple as a two-sentence letter 
describing the change and averring that they have not acquired market 
power as a result.\134\
---------------------------------------------------------------------------

    \134\ NRECA at 3-5.
---------------------------------------------------------------------------

    90. Some commenters contend that the change in status report should 
include some form of market power analysis. NASUCA contends that the 
report should include a revised triennial rate review filing and an 
updated market power analysis.\135\ Powerex and EPSA urge the 
Commission to affirmatively state that market participants may submit, 
in addition to the narrative explanation, the summary pages of their 
original pivotal supplier and market share analyses, modified to 
reflect the changed circumstances.\136\
---------------------------------------------------------------------------

    \135\ NASUCA at 13.
    \136\ Powerex at 9; EPSA at 9.
---------------------------------------------------------------------------

    91. Finally, EEI and FirstEnergy argue that even the submission of 
a narrative only would be unduly burdensome and superfluous. According 
to EEI, a narrative filing requirement would be problematic because 
market-based rate sellers would not always know the complete scope and 
nature of the characteristics relied upon by the Commission or any 
changes in the ownership or control of other market participants in the 
market area and because the Commission has not yet adopted final 
generation market power screens or articulated the screens and tests 
for the remaining three prongs. EEI proposes that, instead, market-
based rate sellers should be required to provide the Commission only 
with a description of the transaction and that such sellers should only 
be required to examine the implications of a change in status (as a 
supplement to the notice of a change in status) if the Commission or a 
market participant raises a concern.\137\
---------------------------------------------------------------------------

    \137\ EEI at 14-15.
---------------------------------------------------------------------------

    92. FirstEnergy objects to the narrative requirement, first, on the 
ground that it is superfluous: the only changes in status for which a 
report may be required are changes in status that reflect a departure 
from the characteristics that the Commission relied upon in granting 
market-based rate authority; however, if a change in status does not 
affect the relevant characteristics, no report is required. FirstEnergy 
further contends that the narrative requirement unreasonably imposes on 
each seller an affirmative obligation to justify the continuation of 
their market-based rate authority every time it engages in a 
transaction that constitutes a reportable change in status, which would 
be costly and time-consuming. FirstEnergy also argues that there is no 
reason to believe that generation suppliers are uniquely situated to 
provide the kind of information that the Commission may need to 
evaluate whether a change in status might affect the continuation of a 
supplier's market-based rate authority, e.g., information concerning 
the size of the market or the availability of transmission import 
capacity into the market, which is equally available to the supplier 
and its competitors. FirstEnergy therefore suggests that, in the 
absence of a demonstration that legitimate concerns exist, the supplier 
should not be required to spend the time and resources that may be 
required to defend the continuation of its market-based rate authority 
between its triennial market power updates.\138\
---------------------------------------------------------------------------

    \138\ FirstEnergy at 12-15.
---------------------------------------------------------------------------

Commission Conclusion

    93. We will adopt the proposal in the NOPR that the market-based 
rate seller submit a transmittal letter, including a description of the 
change in status and a narrative explaining whether (and, if so, how) 
this change in status reflects a departure from the characteristics 
relied upon by the Commission in originally granting the seller market-
based rate authority.
    94. After careful consideration of the comments received, we will 
not specify a uniform length for the narrative that an entity must file 
to explain whether a given change in its status reflects a departure 
from the characteristics relied upon by the Commission for the original 
and continued grant of market-based rate authority. The nature of the 
change that triggers the reporting requirement will necessarily 
determine the length and quality of the narrative, as well as whether 
additional documents and analysis is needed. It is incumbent upon the 
applicant to decide whether the change in status is a material change 
and to provide adequate support and analysis. This is consistent with 
our approach to new applications for market-based rate authority, where 
it is the applicant's responsibility to determine what to report and 
the degree of support and analysis to include.
    95. Further, we will not require entities affected by a change in 
status to automatically file an updated market analysis, such as that 
required by the triennial review. However, an entity may provide such 
an analysis if it chooses. The Commission reserves the right to require 
additional information, including an updated market power analysis, if 
necessary to determine the effect of an entity's change in status on 
its market-based rate authority.

Inclusion of Reporting Requirement in Market-Based Rate Tariffs

    96. In addition to including this reporting requirement in the 
Commission's regulations, we proposed that this reporting requirement 
be incorporated into the market-based rate tariff of each entity that 
is currently authorized to make sales at market-based rates, as well as 
that of all future applicants. Market-based rate sellers would be 
required to submit a conforming provision to their market-based rate 
tariffs at the time that they file any amendment to their tariffs or 
(if earlier) when they apply for continued authorization to sell at 
market-based rates (e.g., in their three-year updated market power 
analysis). However, the Commission proposed that the obligation to 
report be effective at the time that the Final Rule becomes effective.

Comments

    97. Most commenters support the inclusion of the reporting 
requirement into the market-based rate tariff of each seller. No 
substantive opposition was expressed by commenters.

Commission Conclusion

    98. We will adopt the proposal in the NOPR and require that the 
reporting requirement be incorporated in the market-based rate tariffs 
of each entity that is currently authorized to make sales at market-
based rates, as well as that of all future applicants. Market-based 
rate sellers will be required to include the reporting requirement in 
their market-based rate tariffs either at the time that they file any 
amendment to their tariffs, when they report a change in status under 
this Final Rule, or when they file their three-year updated market 
power analysis, whichever occurs first. However, regardless of the date 
on which the seller amends its market-based rate tariff

[[Page 8266]]

to include the reporting requirement, such reporting requirement will 
be considered part of the seller's market-based rate tariff as of 30 
days after the date of publication of this Final Rule in the Federal 
Register.

Reporting Period/Timing

    99. With respect to the procedures for reporting a change in 
status, we proposed in the NOPR that such notifications be filed no 
later than 30 days after the occurrence of the triggering event. We 
sought comment as to whether this proposed time period is appropriate.

Comments

    100. Calpine and NRECA support the proposed 30-day reporting 
period.\139\ Calpine urges the Commission to clarify the event that 
marks the change in status and starts the 30-day clock running. Calpine 
proposes that it should be based on the legal effective date of the 
triggering event. For an increase in ownership or control of generation 
capacity, Calpine states that this would be the date that the public 
utility legally assumes ownership or control over the asset. For a 
self-build or repowering event, it could be the date of commercial 
operation.\140\ NRECA rejects arguments that the 30-day reporting 
period is burdensome, noting that events constituting a change in 
status such as the acquisition or disposition of generation assets, 
require advance planning in excess of 30 days and that the reporting 
requirement can be built into the planning process for such 
transactions.
---------------------------------------------------------------------------

    \139\ NRECA at 4.
    \140\ Calpine at 12.
---------------------------------------------------------------------------

    101. ELCON asks the Commission to modify the 30-day reporting 
requirement to reduce the potential burden on entities that cannot 
exercise market power such as large industrial users that own and 
operate a growing amount of behind-the-meter customer generation. ELCON 
suggests that, first, the final rule keep the 30-day initial notice 
period that would alert the Commission that a potential change in 
status may have occurred, but it should then allow the respondent an 
additional 60 days thereafter to file additional documentation as 
necessary.
    102. APPA, BP Energy and TAPS suggest the Commission permit 
prospective reporting, to the extent possible, of known or expected 
changes in status.\141\ IEU-Ohio/PJMICC would go further and require 
prospective reporting at least 60 days before the circumstances 
affecting market-based rate authority actually occur, to the maximum 
extent possible.\142\ Similarly, NASUCA urges the Commission to require 
that the report be submitted no later than the effective date of the 
change in status.\143\ In contrast, Avista argues that the time period 
for reporting should not begin to run until after the date of 
commercial operation and/or control over the asset is reached.\144\ 
Tractebel requests the Commission to consider pre-authorizing certain 
changes in status, as it does, for example in the context of changes in 
status regarding qualifying facilities under PURPA.\145\
---------------------------------------------------------------------------

    \141\ APPA at 4; BP Energy at 10; TAPS at 4.
    \142\ PJMICC/IEU-Ohio at 14.
    \143\ NASUCA at 6.
    \144\ Avista at 4.
    \145\ Tractebel at 6 (citing 18 CFR 292.207 (2004)).
---------------------------------------------------------------------------

    103. Other commenters, however, argue that the 30-day period is too 
short. EPSA, Xcel, and Powerex propose that change in status reports 
should be submitted on a quarterly basis, for example, concurrently 
with EQRs or Form 3-Qs.\146\ Duke suggests that the reporting period 
should be extended to six months,\147\ while Avista recommends a period 
of 60 days after initial delivery under a long-term contract 
begins.\148\
---------------------------------------------------------------------------

    \146\ EEI at 16-17; EPSA at 4; Powerex at 7; Xcel at 9-10.
    \147\ Duke at 9-10.
    \148\ Avista at 4.
---------------------------------------------------------------------------

    104. Calpine and EPSA request clarification of the procedures for 
filing and responding to change in status reports to avoid uncertainty. 
EPSA proposes that such clarification should occur in a supplemental 
NOPR whereby the comments in this NOPR and in the supplemental NOPR can 
be considered by the Commission. Further, EPSA suggests that this 
reporting requirement be an interim requirement pending final issuance 
of a comprehensive market-based rate authority framework in Docket No. 
RM04-7-000 or another comprehensive proceeding.\149\ Calpine requests 
clarification of whether the reports should be filed in the same docket 
that originally granted market based-rate authority, whether the 
reports would be publicly noticed, and whether the Commission intends 
to respond to the reports if they raise no concerns.\150\
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    \149\ EPSA at 10.
    \150\ Calpine at 11.
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Commission Conclusion

    105. We are not persuaded by the suggestions to increase the 30-day 
period to a longer period of time, whether 60 days, quarterly, or six 
months. Thirty days appropriately balances the amount of time the 
applicant needs to prepare its filing against our need for timely 
information regarding changes in status that may affect prices and 
markets. The Commission finds the 30-day time period an appropriate one 
in which to receive information about a change in status so as to 
enable the Commission to effectively carry out our statutory 
responsibility to oversee competitive conditions in wholesale 
electricity markets. For this reason, we are not persuaded by the 
suggestion that we require entities to file changes in status 
concurrently with their EQRs. As discussed above, quarterly reporting 
would not provide the Commission with information on market 
developments in a sufficiently timely manner to perform our statutory 
duties. Furthermore, contrary to the suggestions of some commenters, 
combining the change in status reporting requirement with other 
reporting requirements, e.g., EQRs, would not create any efficiencies 
or reduce the burden on either the Commission or market-based rate 
sellers. In particular, the Commission has developed a specific 
electronic format for reporting transactions in EQRs \151\ that would 
not accommodate the range of events that constitute changes in status.
---------------------------------------------------------------------------

    \151\ Revised Public Utility Filing Requirements, Order No. 
2001, 67 FR 31,043 (May 8, 2002), FERC Stats. & Regs. ] 31,127 (Apr. 
25, 2002).
---------------------------------------------------------------------------

    106. We clarify that reports of changes in status must be filed no 
later than 30 days after the legal or effective date of the change in 
status, including a change in ownership or control, whichever is 
earlier. Parties are free to file reports of prospective changes, but 
that filing must contain the same information it would if it had filed 
after the change in status. We note that when performing the 
Commission's generation market power screens, applicants are prohibited 
from making forward-looking adjustments.
    107. In response to a request for additional information about the 
processing of these reports, we clarify that the report should be filed 
in the same docket in which market-based rate authority was granted, 
and it should be served on the service list for that docket. The report 
will be noticed, and a comment period will be established.

Other Procedural Issues

Comments

    108. BP Energy, EEI, EPSA and FirstEnergy request that the 
Commission clarify that change in status reports are purely 
informational and that any revisions or revocations to an entity's 
market-based rate authority will be made pursuant to section 206

[[Page 8267]]

proceedings.\152\ With respect to the burden of proof, Calpine 
recommends that the public utility should have the burden to 
demonstrate that it is still entitled to market-based rates after the 
change in status occurs and that if the Commission or any party 
believes that a report indicates that the basis for a public utility's 
market-based rates has been undermined by the change in status, there 
should also be a remedy through a section 206 action.\153\
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    \152\ BP Energy at 3-4; EEI at 15; EPSA at 9; FirstEnergy at 15-
16.
    \153\ Calpine at 12.
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    109. Powerex and SoCal Edison note that the NOPR failed to address 
the treatment of confidential and commercially sensitive information, 
and SoCal Edison requests that the Commission clarify that it requires 
only the minimal reasonable information necessary.\154\
    110. With respect to the procedural rights of third parties, APPA 
and TAPS argue that third parties should be permitted to report known 
or expected changes in status and that the Commission should permit 
them the opportunity to submit comments on change in status reports. 
Those reports meriting closer attention should result in the 
Commission's issuing a show cause order asking the seller to justify 
continuation of market-based rate authority.\155\
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    \154\ Powerex at 10.
    \155\ APPA and TAPS at 2.
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    111. Finally, Tractebel argues that the Commission should provide 
the opportunity for market-based rate sellers that comply with the 
reporting requirement, as well for protesters and intervenors, to 
obtain a timely ``redetermination'' or ``reaffirmation'' of their 
market-based rate authority.\156\
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    \156\ Tractebel at 7.
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    112. Cinergy proposes that, for purposes of regulatory certainty, 
the Commission should commit to issue orders on notices of changes in 
status within 60 days of filing. Where an order accepts for filing a 
change in status report, such acceptance would be deemed an 
acknowledgement by the Commission that the reported event does not 
affect the applicant's market-based rate authorization. Similarly, if 
the Commission does not issue an order within 60 days, any reported 
transaction undertaken after such a 60-day period that conforms 
materially to the description of the transaction in the notice should 
fall within a safe-harbor and not trigger penalties, refunds or loss of 
market-based rates.\157\
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    \157\ Cinergy at 21.
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Commission Conclusion

    113. In response to the requests above, we will clarify the legal 
effect of a notice of a change in status and the procedures that the 
Commission will follow in acting on notices of changes in status. 
First, a notice of a change in status, like the triennial update filing 
requirement, is a filing made in compliance with the terms and 
conditions under which the Commission has granted market-based rate 
authority. As discussed above, we will require that the reporting 
requirement be incorporated in the market-based rate tariffs of each 
market-based rate seller. Thus, a notice of change in status is an 
integral part of the market-based tariff, compliance with which is a 
condition for the retention of market-based rate authority. Consistent 
with the Commission's current practice, the Commission will continue 
the same procedures it has followed in processing filings of changes in 
status. Namely, the Commission will issue a notice of the filing to 
provide an opportunity for public comment. The filing will receive a 
subdocket under the docket number in which the seller originally 
received market-based-rate authority. The Commission, where 
appropriate, may request additional information from the market-based 
rate seller, institute a section 206 investigation or inform the 
parties that the Commission does not intend to take any further action 
regarding the change in status filing.
    114. We further note that because a notice of a change in status, 
like a triennial update, is a compliance filing, rather than a rate 
filing under section 205 of the FPA, the Commission is not required to 
take action within 60 days. Consequently, we will reject Cinergy's 
proposal to commit to issuing an order on notices of a change in status 
within 60 days and to establish a safe harbor where the Commission has 
not acted on the filing within 60 days after receipt. Further, the 
filing alone may not provide sufficient information for the Commission 
to make a definitive finding regarding the impact of the change in 
status on the filing entity's market-based rate authority, and the 
Commission may require more than 60 days to gather the necessary 
information. However, it is the Commission's intention to act on these 
filings as expeditiously as possible.
    115. With respect to the requests of BP Energy, EEI and FirstEnergy 
that the Commission clarify that it will only revoke or revise market-
based rate authority pursuant to a section 206 proceeding, we note that 
the Commission's long-standing policy, in conformance with the FPA, has 
been to do so pursuant to a section 206 proceeding,\158\ and we will 
not change that policy here. In section 206 proceedings, the 
complainant or the Commission bears the burden of proof. Accordingly, 
we cannot change the statutory burden in response to Calpine's 
request.\159\
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    \158\ See, e.g., Enron Power Marketing, Inc., 103 FERC ] 61,343 
(2003), reh'g denied, 106 FERC ] 61,024 (2004); April 14 Order, 107 
FERC ] 61,018 at P 201, 209.
    \159\ In addition, we note that we did not attempt to alter this 
statutory allocation of the burden of proof in the April 14 Order, 
as Calpine has previously argued. In the April 14 Order, we stated 
that failure of one of the generation market power screens would 
establish a rebuttable presumption of market power in the resulting 
section 206 proceeding. April 14 Order, 107 FERC ] 61,018 at P 201. 
In the July 8 Order, we explicitly rejected Calpine's allegation 
there that we had inappropriately shifted the statutory burden and 
clarified that an applicant's screen failure satisfied the 
Commission's initial burden of going forward with evidence in the 
section 206 proceeding. July 8 Order, 108 FERC ] 61,026 at P 29-30.
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    116. Commission regulations set forth the procedures for requesting 
special treatment for confidential and commercially sensitive 
information to prevent public disclosure,\160\ and we do not find it 
necessary to establish additional procedures for such information 
contained in a notice of a change in status in response to the requests 
of Powerex and SoCal Edison.
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    \160\ 18 CFR 388.112 (2004).
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    117. With respect to APPA's and TAPS' concerns about the rights of 
third parties, we clarify that nothing in this final rule or the 
Commission regulations adopted herein changes the rights of third 
parties to file in response to a notice of change in status or to file 
a complaint pursuant to section 206.

Information Collection Statement

    118. Office of Management and Budget (OMB) regulations require OMB 
to approve certain information collection requirements imposed by 
agency rule.\161\ The Commission solicited comments on the Commission's 
need for this information, whether the information will have practical 
utility, the accuracy of provided burden estimates, ways to enhance the 
quality, utility and clarity of the information to be collected, and 
any suggested methods for minimizing respondents' burden, including the 
use of automated information techniques.
---------------------------------------------------------------------------

    \161\ 5 CFR 1320.11 (2004).
---------------------------------------------------------------------------

    119. Estimated Annual Burden to satisfy the reporting requirement, 
the Commission expects respondents to submit a transmittal letter 
including a description of the change in status and a narrative 
explaining whether (and, if so, how) this change in status reflects a 
departure from the characteristics relied

[[Page 8268]]

upon by the Commission in originally granting the seller market-based 
rate authority. The Commission estimates that, on average, it will take 
respondents six hours per response and that approximately 25 percent of 
current market-based rate sellers would experience a change in status 
in any given year.

----------------------------------------------------------------------------------------------------------------
                                                         Number of     Number of     Number of     Total annual
                   Data collection                      respondents      hours       responses        hours
----------------------------------------------------------------------------------------------------------------
FERC-516.............................................        1,238             6           .20            1,486
----------------------------------------------------------------------------------------------------------------

    Title: Electric Rate Schedules and Filings, Reporting Requirement 
for Changes in Status For Public Utilities With Market-Based Rate 
Authority (FERC-516).
    Action: Proposed collection.
    OMB Control No.: 1902-0096.
    Respondents: Businesses or other for profit.
    Frequency of Responses: On occasion.
    Necessity of Information: The proposed regulations will revise 
market-based rate sellers' reporting obligation and are intended to 
ensure that rates and terms of service offered by market-based rate 
sellers remain just and reasonable.
    Internal Review: The Commission has reviewed the proposed amendment 
to its regulations to establish a reporting obligation for changes in 
status and has determined that these regulations are necessary to 
ensure just and reasonable rates. These regulations, moreover, conform 
to the Commission's plan for efficient information collection, 
communication, and management within the electric utility industry. The 
Commission has assured itself, by means of internal review, that there 
is specific, objective support for the burden estimates associated with 
the information/data retention requirements.
    120. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426, Attention: Michael Miller, 
Office of the Executive Director, phone: (202) 502-8415, fax: (202) 
273-0873, e-mail: [email protected]. Comments on the proposed 
requirements of the subject rule may also be sent to the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
Washington, DC 20503, Attention: Desk Officer for the Federal Energy 
Regulatory Commission, phone: (202) 395-4650.

Comments

    121. DOJ contends that the preparation of the transmittal letter 
may take more than six hours to prepare and may impose significant 
costs on applicants.\162\
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    \162\ US DOJ at 11-12.
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Commission Conclusion

    122. The estimate contained in the NOPR of the time necessary to 
comply with the reporting requirement is an average. While such a 
letter may take more than six hours in some cases, we believe that in 
most cases compliance will take substantially less time. As we explain 
above, the more significant events triggering the reporting requirement 
will also trigger other reporting requirements, e.g., a section 203 
application. In such a case, market-based rate sellers may incorporate 
by reference the related filing, and compliance with the change in 
status reporting requirement accordingly would require a minimal amount 
of time to prepare.

Environmental Analysis

    123. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\163\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment. Included in the exclusion are rules that are clarifying, 
corrective, or procedural or that do not substantially change the 
effect of the regulations being amended.\164\ Thus, we affirm the 
finding we made in the NOPR that this final rule is procedural in 
nature and therefore falls under this exception; consequently, no 
environmental consideration would be necessary.
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    \163\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47,897 (Dec. 17, 1987), FERC Stats. & 
Regs. ] 30,783 (Dec. 10, 1987).
    \164\ 18 CFR 380.4(a)(2)(ii)(2004).
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Regulatory Flexibility Act Certification

    124. The Regulatory Flexibility Act of 1980 (RFA) \165\ generally 
requires a description and analysis of final rules that will have 
significant economic impact on a substantial number of small 
entities.\166\ The Commission is not required to make such analyses if 
a rule would not have such an effect.
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    \165\ 5 U.S.C. 601-612 (2000).
    \166\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business which is independently 
owned and operated and which is not dominant in its field of 
operation. 15 U.S.C. 632 (2000). The Small Business Size Standards 
component of the North American Industry Classification System 
defines a small electric utility as one that, including its 
affiliates, is primarily engaged in the generation, transmission, 
and/or distribution of electric energy for sale and whose total 
electric output for the preceding fiscal years did not exceed 4 
million MWh. 13 CFR 121.201 (Section 22, Utilities, North American 
Industry Classification System, NAICS) (2004).
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    125. The Commission concludes that the final rule would not have 
such an impact on small entities. Based on past experience, most of the 
sellers having changes in status that would likely trigger a filing 
under the proposed regulations would be entities that do not meet the 
RFA's definition of a small entity. Therefore, the Commission certifies 
that this final rule will not have a significant economic impact on a 
substantial number of small entities.

Document Availability

    126. 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.
    127. From FERC's Home Page on the Internet, this information is 
available in the Commission's document management system, 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.
    128. User assistance is available for eLibrary and the FERC's Web 
site during normal business hours. For assistance, please contact FERC 
Online Support at 1-866-208-3676 (toll free) or 202-502-

[[Page 8269]]

6652 (e-mail at [email protected]), or the Public Reference 
Room at 202-502-8371, TTY 202-502-8659 (e-mail at 
[email protected]).

Effective Date and Congressional Notificiation

    This Final Rule will take effect March 21, 2005. The Commission has 
determined with the concurrence of the Administrator of the Office of 
Information and Regulatory Affairs of the Office of Management and 
Budget, that this rule is not a major rule within the meaning of 
section 251 of the Small Business Regulatory Enforcement Fairness Act 
of 1996.\167\ The Commission will submit the Final Rule to both houses 
of Congress and the General Accounting Office.\168\
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    \167\ See 5 U.S.C. 804(2) (2000).
    \168\ See 5 U.S.C. 801(a)(1)(A) (2000).
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List of Subjects in 18 CFR Part 35

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

    By the Commission.
Linda Mitry,
Deputy Secretary.

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

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

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

0
2. In Sec.  35.27, paragraph (c) is added to read as follows:


Sec.  35.27  Power sales at market-based rates.

* * * * *
    (c) Reporting requirement. Any public utility with the authority to 
engage in sales for resale of electric energy in interstate commerce at 
market-based rates shall be subject to the following:
    (1) As a condition of obtaining and retaining market-based rate 
authority, a public utility with market-based rate authority 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. A change in status includes, but 
is not limited to, each of the following:
    (i) Ownership or control of generation or transmission facilities 
or inputs to electric power production other than fuel supplies, or
    (ii) 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, or 
affiliation with any entity that has a franchised service area.
    (2) Any change in status subject to paragraph (c)(1) of this 
section must be filed no later than 30 days after the change in status 
occurs.

[FR Doc. 05-3040 Filed 2-17-05; 8:45 am]
BILLING CODE 6717-01-P