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    \104\ See Edgar, 55 FERC ] 61,382 at 62,167.
    \105\ With regard to reciprocal dealing, we believe that any
concerns as to a seller's ability to engage in reciprocal dealing
are addressed by the affiliate abuse provisions we propose to
include in the Commission's regulations as well as the Commission's
final rule prohibiting energy market manipulation. See Prohibition
of Energy Market Manipulation, Order No. 670, 71 FR 4244 (January
26, 2006), FERC Stats. & Regs. ] 31,202 (2006), order on reh'g,
Order No. 670-A, 114 FERC ] 61,300 (2006).
    \106\ In this regard, the Commission protects captive customers
by ensuring that wholesale rates are just and reasonable.
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    109. Consistent with the foregoing, we propose to amend the
Commission's regulations to include a provision expressly prohibiting
power sales between a franchised public utility and any of its non-
regulated affiliates without first receiving authorization of the
transaction under section 205 of the FPA. Further, we propose that, as
a condition of receiving market-based rate authority, sellers must
adopt the MBR tariff (included as Appendix A to this NOPR) which
includes a provision requiring the seller to comply with, among other
things, the affiliate provisions in the regulations. We note that
failure to satisfy the conditions set forth in the affiliate provisions
will constitute a tariff violation. We seek comments on this proposal.
    110. Sellers seeking authorization to engage in affiliate
transactions will continue to be obligated to provide evidence to
support a determination as to whether there are captive customers that
would trigger the application of our standards for affiliate power
sales.\107\ If the Commission finds, based on the evidence provided by
the seller, that the seller has no captive customers, the affiliate
provisions in the regulations would not apply. However, if the record
does not support a finding of no captive customers, the seller must
abide by all affiliate restrictions contained in the regulations in
order to obtain and retain market-based rate authority. In the
Commission's Final Rule on transactions subject to section 203, the

Commission defined the term ``captive customers'' to mean ``any
wholesale or retail electric energy customers served under cost-based
regulation.'' \108\ We seek comment on whether the same definition
should be used for purposes of this rule.
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    \107\ Sellers that have already received authorization to make
sales to affiliates would retain that authorization unless the
Commission institutes a section 206 investigation to examine whether
the seller's current circumstances continue to satisfy our affiliate
abuse concerns and subsequently revokes such authorization.
    \108\ Transactions Subject to FPA section 203, Order No. 669-A,
71 FR 28422 (May 16, 2006), FERC Stats. & Regs. ] 31,097 (2006). See
also Repeal of the Public Utility Holding Company Act of 1935 and
Enactment of the Public Utility Holding Company Act of 2005, Order
No. 667-A, 71 FR 28446 (May 16, 2006), FERC Stats. & Regs. ] 31,096
(2006).
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    111. We propose to continue our past approach for determining what
types of affiliate transactions are permissible and the criteria that
should be used to make those decisions. When affiliates participate in
a competitive solicitation process, application of the Allegheny
criteria would constitute safe harbor criteria that the affiliate abuse
condition is satisfied in a transaction between a franchised public
utility and its affiliate. The Commission will consider competitive
solicitations, on a case-by-case basis. However, we emphasize that
using a competitive solicitation is not the only way an affiliate
transaction can address our concerns that the transaction does not pose
affiliate abuse concerns.
    112. In Edgar, two alternatives to competitive solicitation
evidence were found to be acceptable evidence of a market price. These
alternatives included prices non-affiliates are willing to pay for
similar service and benchmark evidence. However, Edgar also noted the
difficulty of finding such truly comparable alternative evidence.\109\
This difficulty in finding adequate comparable evidence increases the
likelihood that applications submitted with such evidence could raise
issues of material fact and thus could be set for hearing.
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    \109\ See Edgar, 55 FERC ] 61,382 at 62,169.
---------------------------------------------------------------------------

    113. We continue to believe that tying the price of an affiliate
transaction to an established, relevant market price or index such as
in an RTO or ISO is acceptable benchmark evidence and mitigates
affiliate abuse concerns so long as that benchmark price or index
reflects the market price where the affiliate transaction occurs (i.e.,
is a relevant index).\110\ The Commission has stated its belief that
the added protections in structured markets with central commitment and
dispatch and market monitoring and mitigation (such as RTOs/ISOs)
generally result in a market where prices are transparent.\111\
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    \110\ Brownsville, 111 FERC ] 61,398 at P10. See also Portland
General Elec. Co., 96 FERC ] 61,093 at 61,378 (2001); FirstEnergy
Trading, 88 FERC ] 61,067 at 61,156 (1999).
    \111\ April 14 Order, 107 FERC ] 61,018 at P 189.
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    114. Although the Commission has found in the past that certain
non-RTO price indices are acceptable indicators of market prices, we
recognize that price indices at thinly traded points can be subject to
manipulation and are otherwise not good measures of market prices, as
discussed in the Price Index Policy Statement \112\ and November 19
Price Index Order.\113\ Accordingly, we propose to allow affiliate
transactions based on a non-RTO price index only if the index fulfills
the requirements of the November 19 Price Index Order for eligibility
for use in jurisdictional tariffs.\114\ The requirements include the
criteria found in the Price Index Policy Statement, including but not
limited to \115\ reporting of prices by those not involved in trading,
and a process for resolving reporting errors, as well as those specific
to jurisdictional tariffs: (1) Providing the volume and number of
transaction data on which the index value is based (or clearly
indicating when no such data is available); (2) confirming that the
Commission can have access to relevant data in the event of an
investigation of possible false price reporting or manipulation; and
(3) establishing minimum criteria to determine whether there is
adequate liquidity for daily, weekly, and monthly electricity indices.
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    \112\ Policy Statement On Natural Gas And Electric Price Indices
104 FERC ] 61,121 (2003) (Price Index Policy Statement).
    \113\ Order Regarding Future Monitoring Of Voluntary Price
Formation, Use Of Price Indices In Jurisdictional Tariffs, And
Closing Certain Tariff Docket 109 FERC ] 61, 184 (2004) (November 19
Price Index Order).
    \114\ November 19 Price Index Order, 109 FERC ] 61,184 at P 40-
69.
    \115\ Price Index Policy Statement, 104 FERC ] 61,121 at P 34.
---------------------------------------------------------------------------

    115. The Commission seeks comment on whether evidence other than
competitive solicitations, RTO price or non-RTO price indices, or
benchmarks described above, should be accepted in an application for
authority to engage in affiliate power sales.
    116. With regard to merging companies the Commission has stated
that for the purposes of affiliate abuse, merging companies will be
considered affiliates under the market-based rate tariff while their
merger is pending.\116\ We seek comments regarding at what point the
Commission should consider two non-affiliates as merging partners: the
date the merger is announced, the date the section 203 application is
filed with the Commission, or another time? The Commission proposes to
use the date a merger is announced as the triggering event, but we seek
comment on this issue.
---------------------------------------------------------------------------

    \116\ Cinergy, Inc., 74 FERC ] 61,281 (1996); Consolidated
Edison Energy, Inc., 83 FERC ] 61,236 at 62,034 (1998); Central and
South West Services, Inc., 82 FERC ] 61,101 at 61,103 (1998);
Delmarva Power & Light Company, 76 FERC ] 61,331 at 62,582 (1996)
(``[T]he self-interest of two merger partners converge sufficiently,
even before they complete the merger, to compromise the market
discipline inherent in arm's-length bargaining that serves as the
primary protection against reciprocal dealing.'').
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    117. The Commission also proposes that entities that engage in
energy/asset management of generation on behalf of a franchised public
utility be treated as affiliates of that franchised public utility in a
manner similar to that of non-regulated affiliates and be subject to
the affiliate provisions we propose herein. The Commission also
proposes that entities that engage in energy/asset management of
generation on behalf of non-regulated affiliates of a franchised public
utility be treated in a similar manner as the non-regulated affiliates.
We seek comment on this proposal.
    118. The Commission currently requires that sales made under
market-based rate tariffs, including those made to affiliates, be
reported in an EQR.\117\ The Commission affirms that its role with
regard to market-based rates, and specifically affiliate transactions,
will be to either grant or deny authorization to make affiliate sales.
Additionally, the Commission reiterates that, once authorized, all such
sales should be reported in an EQR.
---------------------------------------------------------------------------

    \117\ Revised Public Utility Filing Requirements, Order No.
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs., Regulations
Preambles January 2001-December 2005 ] 31,127 (2002).
---------------------------------------------------------------------------

    119. Although, at one time, the Commission's policy was to require
certain market-based rate sellers to file their long-term market-based
rate power sales service agreements with the Commission,\118\ since the
issuance of Order No. 2001, the Commission's policy has been to require
that such agreements not be filed with the Commission. Notwithstanding
this policy, the Commission on occasion may have accepted long-term
service agreements for filing. At this time, the Commission reaffirms
that long-term affiliate sales contracts under the seller's market-
based rate tariff that are authorized by the Commission shall not be
filed with the Commission.\119\ However, the seller must make a section
205 filing with the Commission to obtain authorization to engage in an

affiliate transaction, and may not engage in such transaction without
first receiving such authorization.
---------------------------------------------------------------------------

    \118\ See Southern Company Services, Inc., 99 FERC ] 61,103
(2002).
    \119\ 18 CFR 35.1(g) (2005) (``[A]ny market-based rate agreement
pursuant to a tariff shall not be filed with the Commission'').
---------------------------------------------------------------------------

2. Market-Based Rate Code of Conduct for Affiliate Transactions
Involving Power Sales and Brokering, Non-Power Goods and Services and
Information Sharing
    a. Current Policy.
    120. The Commission requires affiliates of franchised public
utilities that request market-based rate authority to submit a market-
based rate code of conduct to govern the relationship between the
franchised public utility and its affiliates. Historically, the purpose
of the market-based rate code of conduct \120\ has been to safeguard
against affiliate abuse by protecting against the possible diversion of
benefits or profits from franchised public utilities (i.e., traditional
public utilities with captive ratepayers) to an affiliated entity for
the benefit of shareholders. Just as the Commission has expressed
concern about the potential for affiliate abuse in connection with
power sales between affiliates, it also has recognized that there may
be a potential for affiliate abuse through other means, such as the
pricing of non-power goods and services or the sharing of market
information between affiliates.\121\ The market-based rate code of
conduct was designed to address these concerns. The Commission has
waived the market-based rate code of conduct requirement in cases where
there are no captive customers, and thus no potential for affiliate
abuse, or where the Commission finds that such customers are adequately
protected against affiliate abuse.\122\ In such cases, however, the
Commission directed the utilities to notify the Commission should they
obtain captive customers in the future and expressly reserved the right
to reimpose the market-based rate code of conduct requirement. In the
Order No. 2004 Standards of Conduct rulemaking proceeding, the
Commission solicited comment on whether to reform the market-based rate
code of conduct but determined that such reform should take place in a
separate proceeding.\123\
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    \120\ The market-based rate code of conduct has at times been
confused with the Commission's Standards of Conduct. The electric
Standards of Conduct, originally issued in Order No. 889 et seq.,
were established to govern the relationship between a public
utility's transmission function and its wholesale merchant function
(including affiliated power marketers) to ensure that all
transmission customers have equal access to transmission
information. See Open Access Same-Time Information System and
Standards of Conduct, Order No. 889, 61 FR 21737 (1996), FERC Stats.
& Regs., Regulations Preambles July 1996-December 2000 ] 31,035
(1996), order on reh'g, Order No. 889-A, 62 FR 12484 (1997), FERC
Stats. & Regs., Regulations Preambles July 1996-December 2000 ]
31,049 (1997), reh'g denied, Order No. 889-B, 81 FERC ] 61,253
(1997), order on reh'g, Order No. 889-C, 82 FERC ] 61,046 (1998),
aff'd in relevant part sub nom. Transmission Access Policy Study
Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000). The Standards of
Conduct were recently updated by the Commission. See Standards of
Conduct for Transmission Providers, Order No. 2004, 68 FR 69134
(Dec. 11, 2003), III FERC Stats. & Regs., Regulations Preambles
January 2001-December 2005 ] 31,155 (Nov. 25, 2003), order on reh'g,
Order No. 2004-A, 69 FR 23562, (Apr. 29, 2004), III FERC Stats. &
Regs., Regulations Preambles January 2001-December 2005 ] 31,161
(April 16, 2004), order on reh'g, Order No. 2004-B, 69 FR 48371
(Aug. 10, 2004), III FERC Stats. & Regs., Regulations Preambles
January 2001-December 2005 ] 31,166 (Aug. 2, 2004), order on reh'g,
Order No. 2004-C, 70 FR 284 (Jan 4., 2005), III FERC Stats. & Regs.,
Regulations Preambles January 2001-December 2005 ] 31,172 (Dec. 21,
2004), order on reh'g, Order No. 2004-D, 110 FERC ] 61,320 (March
23, 2005), appeal docketed sub nom., Natural Gas Fuel Supply Corp.
v. FERC, No. 04-1183 (D.C. Circuit).
    \121\ See, e.g., Potomac Electric Power Company, 93 FERC ]
61,240 at 61,782 (2000); Heartland, 68 FERC ] 61,223 at 62,062-63.
    \122\ See, e.g., CMS Marketing, Services and Trading Co., 95
FERC ] 61,308 at 62,051 (2001) (granting request for cancellation of
code of conduct where wholesale contracts, as amended, ``cannot be
used as a vehicle for cross-subsidization of affiliate power sales
or sales of non-power goods and services''); Alcoa, Inc., 88 FERC
]61,045 at 61,119 (1999) (waiving code of conduct requirement where
there were no captive customers); Green Power Partners 1 LLC, 88
FERC ] 61,005 at 61,010-11 (1999) (waiving code of conduct
requirement where there are no captive wholesale customers and
retail customers may choose alternative power suppliers under retail
access program).
    \123\ Order No. 2004, at 30,853. The following entities
submitted comments in the Standards of Conduct rulemaking proceeding
in Docket No. RM01-10-000 relating to the concept of codifying the
code of conduct: Cinergy (codification not needed); Entergy (if
codified, the code of conduct should reflect established codes);
NEPOOL Industrial Customer Coalition (codification needed); LG&E
Energy Corporation (separate code of conduct policy issues should be
treated in a separate rulemaking); PanCanadian Energy Services, Inc.
(codification unnecessary).
---------------------------------------------------------------------------

    121. The market-based rate code of conduct requirements have
evolved through market-based rate orders.\124\ Beginning with orders
issued in 1999, the Commission informed sellers that if an applicant
submitted a market-based rate code of conduct that was inconsistent
with the market-based rate code of conduct attached to those orders,
the Commission would reject it and designate the attachment as the
applicable code.\125\ The Commission's market-based rate code of
conduct provisions state:
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    \124\ Seminal early Commission decisions discussing the purposes
of the code of conduct requirements include Heartland and LG&E Power
Marketing, Inc., 68 FERC ] 61,247 at 62,121-24 (1994).
    \125\ See, e.g., Northeast Utilities Service Company, 87 FERC ]
61,063 (1999) (requiring market-based rate applicants to submit
codes of conduct consistent with an attached code of conduct and
imposing the attached code in the event of inconsistency).

Statement of Policy and Code of Conduct With Respect to the
Relationship Between (Power Marketer/Power Producer) and [Public
Utility]

Marketing of Power

    1. To the maximum extent practical, the employees of [Power
Marketer/Power Producer] will operate separately from the employees
of [Public Utility].
    2. All market information shared between [Public Utility] and
[Power Marketer/Power Producer] will be disclosed simultaneously to
the public. This includes all market information, including but not
limited to, any communication concerning power or transmission
business, present or future, positive or negative, concrete or
potential. Shared employees in a support role are not bound by this
provision, but they may not serve as an improper conduit of
information to non-support personnel.
    3. Sales of any non-power goods or services by [Public Utility],
including sales made through its affiliated EWGs or QFs, to [Power
Marketer/Power Producer] will be at the higher of cost or market
price.
    4. Sales of any non-power goods or services by the [Power
Marketer/Power Producer] to [Public Utility] will not be at a price
above market.

Brokering of Power

    To the extent [Power Marketer/Power Producer] seeks to broker
power for [Public Utility]:
    5. [Power Marketer/Power Producer] will offer [Public Utility's]
power first.
    6. The arrangement between [Power Marketer/Power Producer] and
[Public Utility] is non-exclusive.
    7. [Power Marketer/Power Producer] will not accept any fees in
conjunction with any Brokering services it performs for [Public
Utility].

    122. The Commission has also accepted the inclusion of an
additional provision to govern brokering activities where a franchised
public utility brokers for one of its affiliates.\126\
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    \126\ See MEP Investments, LLC, 87 FERC ] 61,209 at 61,828
(1999) (``CP&L has taken the brokering rules established by the
Commission for the opposite situation (when the marketer is
brokering for the utility), and modified them to apply to its
situation. Specifically, instead of the no-fee rule when a marketer
brokers for its affiliate, for brokering service CP&L provides to
Monroe, CP&L will charge Monroe the higher of CP&L's costs for that
service or the market rate for such services. CP&L will also market
its own power first, simultaneously make public any information
shared with Monroe during brokering, and post on its Internet site
the actual brokering changes imposed. This addition to CP&L's code
of conduct is accepted.'').
---------------------------------------------------------------------------

    123. Numerous significant changes have taken place in the electric
industry relevant to the market-based rate code of conduct requirement
since the Commission approved the first market-based rate codes of
conduct in the mid-1990s. The Commission has required open access
transmission service in Order No. 888; there has been an increase in
the number of power marketers and power producers

authorized to transact under market-based rates, as well as an
increased market for available transmission capacity, an increased
number of power transactions, and new and different uses for the
transmission grid.\127\ The Commission has found that the nature of
electric market participants is also changing, with the rise of power
marketers and generation facilities that are affiliated with
traditional regulated entities, as well as unaffiliated entities.\128\
---------------------------------------------------------------------------

    \127\ Standards of Conduct for Transmission Providers, Order No.
2004, 68 FR 69134, FERC Stats. & Regs., ] 31,155, Regulations
Preambles January 2001-December 2005.
    \128\ Id. As of April 1, 2006, approximately 1170 entities have
market-based rate authority granted by the Commission. They include
approximately 390 independent power marketers, 70 traditional
utilities with market-based rate authority, 100 affiliated power
marketers, 400 affiliated power producers, 180 independent power
producers and 30 financial institutions.
---------------------------------------------------------------------------

    124. There also has been an increased range of activities engaged
in by asset or energy managers.\129\ Although asset managers can
provide valuable services and thereby benefit consumers and the
marketplace, such relationships also could result in transactions
harmful to captive customers. We note that, as the consequence of one
Commission investigation, there was a settlement agreement pursuant to
which a company's market-based rate codes of conduct were revised to
expand (a) the range of affiliates to which they applied and (b) the
regulation of conduct between affiliates, including the asset
manager.\130\
---------------------------------------------------------------------------

    \129\ Kevin Heslin, A few thoughts on the industry: Ideas from
session at Globalcon, Energy User News, July 1, 2002, at 12 (Noting
that prior to deregulation, ``an energy manager had relatively
straightforward tasks: understanding applicable tariffs, evaluating
the possible installation of energy conservation measures (ECMs),
and considering whether to install on-site generation'' but that
``now, an energy manager has to be conversant with a far greater
number of issues'' such as complex legal issues and financial
instruments like derivatives.)
    \130\ In 2003, as part of a Settlement Agreement with the
Commission, Cleco Corp. agreed to an expansion of its codes of
conduct governing relations between its various affiliates that
Enforcement staff alleged had participated in power sales and
related conduct in violation of the Standards of Conduct and Cleco's
previous codes of conduct. Cleco Corp., 104 FERC ] 61,125 (2003).
Pursuant to the terms of the resulting settlement agreement, Cleco
submitted revised codes that governed information sharing and
independent functioning between Cleco's three exempt wholesale
generators (with market-based rate authority), its power marketer
that in essence acted as an asset manager for the three, and its
captive ratepayer utility, rather than merely code provisions
governing relations between, on the one hand, the captive ratepayer
utility, and, on the other, the marketing and generation affiliates.
---------------------------------------------------------------------------

    125. While the Commission has required that entities comply with
the provisions of the market-based rate code of conduct, the market-
based rate code of conduct has not been codified in the Commission's
regulations. Further, some applicants for market-based rate authority
have requested and received variations from the market-based rate code
of conduct. Such variations, while reasonable in individual
circumstances, may over time become inconsistent with the Commission's
goals of protecting captive customers and fostering transparent and
consistent regulation of the market. Likewise, some corporate families
have filed several different market-based rate codes of conduct for
their affiliates while others have filed only one or have received a
waiver of the market-based rate code of conduct requirement.
    126. An example of inconsistent market-based rate codes of conduct
was revealed in Commission staff's audit of Progress Energy, Inc. In
that proceeding, there were eight different codes with differing
provisions for different Progress affiliates.\131\
---------------------------------------------------------------------------

    \131\ See Florida Power Corp., 111 FERC ] 61,243 (2005),
attached staff Audit Report at 6.
---------------------------------------------------------------------------

    b. Proposal.
    127. The Commission continues to believe that a code of conduct is
necessary to protect captive customers from the potential for affiliate
abuse. Further, in light of the repeal of the Public Utility Holding
Company Act of 1935 and the fact that holding company systems may have
franchised public utility members with captive customers as well as
numerous ``non-regulated'' power sales affiliates that engage in non-
power goods and services transactions with each other, it is important
that the Commission have in place restrictions to preclude transferring
captive customer benefits to stockholders through a company's ``non-
regulated'' power sales business. We therefore believe it is
appropriate to condition all market-based rate authorizations,
including authorizations for sellers within holding companies, on the
seller abiding by a code of conduct for sales of non-power goods and
services between power sales affiliates.
    128. We also believe that greater uniformity and consistency in the
codes of conduct is appropriate. With the experience gained over the
years in approving various codes of conduct, including our standard
code of conduct, we are proposing to adopt a uniform code of conduct to
govern the relationship between franchised public utilities with
captive customers and their ``non-regulated'' affiliates, i.e.,
affiliates whose power sales are not regulated on a cost basis under
the FPA. We therefore propose to codify such affiliate provisions in
section 35.39(b)-(e) of our regulations and to require that, as a
condition of receiving market-based rate authority, sellers comply with
these provisions. Failure to satisfy the conditions set forth in the
affiliate provisions will constitute a tariff violation. This
uniformity will help ensure that captive customers are protected and
that affiliate provisions are applied and administered in an even-
handed manner in harmony with legitimate current industry practices. We
seek comment on this proposal and on whether the specific affiliate
provisions proposed in this NOPR are sufficient to protect captive
customers. In particular, what changes, if any, should the Commission
adopt? Additionally, as previously noted, we seek comment on the
definition of ``captive customer.''
    129. The proposed provisions are the same as those in the standard
code of conduct that exists today with the following exceptions. First,
the proposed regulations use the term ``non-regulated'' affiliates
instead of power marketer/power producer to make it clear that the
provisions apply to the relationship between a franchised public
utility and any of its affiliates that are not regulated under cost-
based regulation. This includes affiliate power marketers and affiliate
power producers, such as EWGs and QFs.
    130. Second, in the case of companies that are acting on behalf of
and for the benefit of franchised public utilities with captive
customers, the proposed affiliate provisions treat such companies, for
purposes of the affiliate provisions, as the franchised public utility.
For example, if a company has been created to manage generation assets
for the franchised public utility, such entity is subject to the same
information sharing provision as the franchised public utility with
regard to information shared with non-regulated affiliates, such as
power marketers and power producers.
    131. Likewise, in the case of non-regulated affiliates, the
proposed affiliate provisions treat companies that are acting on behalf
of and for the benefit of non-regulated affiliates, for purposes of the
affiliate provisions, as the non-regulated affiliates. For example,
asset managers of a non-regulated affiliate's generation assets are
treated as the non-regulated affiliate with regard to, for example, the
information sharing provision. We seek comment on this proposal.
    132. The Commission invites comments proposing other additions,
substitutions, or eliminations to the proposed affiliate provisions.

D. Mitigation

1. Current Policy
    133. The Commission began accepting applications for market-based
power sales in the late 1980s as a means to provide greater flexibility
to transactions in emerging competitive wholesale power markets. The
analysis for horizontal market power at that time was the ``hub and
spoke'' methodology, and under that methodology most sellers received
market-based rate approval. If, however, a seller failed the hub and
spoke analysis for a particular market, as a general matter, no
specific mitigation was imposed. Rather, the seller could continue to
sell power under existing cost-based rate schedules on file with the
Commission in that area.
    134. The Commission began providing greater flexibility in setting
cost-based rates for coordination sales during this period as well.
Historically, utilities had set the rate for coordination sales on a
``split the savings'' formula \132\ or on the incremental cost of the
units participating in the sale (plus an adder). In the late 1980s,
however, the Commission began to approve a variety of ``up to'' rates
under which the applicant could charge a rate that was anywhere between
a ``floor'' of incremental cost and a ``ceiling'' of variable energy
costs plus an embedded cost demand charge. Examples of this more
flexible approach were the Western Systems Power Pool, Inc. agreement,
under which all sellers in the Western Interconnect could transact
under a common ceiling rate. The Commission also provided significant
flexibility to individual sellers, such as by allowing them to cap
rates at the cost of the most recently installed unit, even if that
unit was a high-cost baseload unit.
---------------------------------------------------------------------------

    \132\ A seller's incremental cost (the out-of-pocket cost of
producing an additional MW) is compared with a buyer's decremental
cost (the cost of not producing the last MW). The average of the
incremental and decremental cost is the ``split the savings'' rate.
---------------------------------------------------------------------------

    135. This more flexible approach to wholesale power sales continued
largely unchanged until 2001 when the Commission adopted the supply
margin assessment (SMA) test.\133\ The SMA sought to strengthen the
horizontal market power test in several significant ways, such as
considering transmission capability to limit the amount of competitive
supplies that could get into the relevant market. Although not imposing
a cost-based rate for longer term transactions, the SMA developed a
``must offer'' requirement and a ``split the savings'' formula in the
event that a seller failed the generation market power test, which was
the traditional cost-based ratemaking model used for spot market energy
sales.
---------------------------------------------------------------------------

    \133\ See AEP Power Marketing, Inc., 97 FERC ] 61,219 (2001)
(SMA Order).
---------------------------------------------------------------------------

    136. In the April 14 and July 8 Orders, the Commission replaced the
SMA test with two indicative screens for assessing horizontal market
power, the pivotal supplier screen and the wholesale market share
screen, and modified the Commission's approach to cost-based
mitigation.
    137. In the April 14 Order, the Commission adopted default
mitigation tailored to three distinct products: (1) Sales of power of
one week or less will be priced at the seller's incremental cost plus a
10 percent adder; (2) sales of power of more than one week but less
than one year will be priced at an embedded cost ``up-to'' rate
reflecting the costs of the unit(s) expected to provide the service;
and (3) sales of power for one year or more will be priced at an
embedded cost of service basis and each such contract will be filed
with the Commission for review and approved prior to the commencement
of service. The Commission determined that sellers that are found to
have market power (i.e., after the Commission has ruled on the DPT
analysis), or that accept a presumption of market power, may either
accept the Commission's default cost-based mitigation measures or
propose their own case-specific measures tailored to their particular
circumstances that eliminate their ability to exercise market power,
including adopting existing cost-based rates, but did not provide
guidance as to which departures from the default mitigation would be
approved.\134\
---------------------------------------------------------------------------

    \134\ April 14 Order, 107 FERC ] 61,018 at P 147, 148 & n. 142,
150 & n. 144.
---------------------------------------------------------------------------

2. Proposal
    138. We seek comment on whether the default mitigation set forth in
the April 14 Order is appropriate as currently structured. In
particular, certain recurring issues have arisen in implementing the
cost-based mitigation and we seek comment on these issues.
Specifically, we seek comment, as discussed further below, on four
issues of recurring significance: (i) The rate methodology for
designing cost-based mitigation; (ii) discounting; (iii) protecting
customers in mitigated markets; and (iv) sales by mitigated sellers
that ``sink'' in unmitigated markets.
    a. Cost-Based Rate Methodology.
    139. We first seek comment on issues associated with the rate
methodology for designing cost-based mitigation. There are two
principal issues concerning rate methodology that have arisen in
implementing the April 14 Order. The first relates to the requirement
that sales of less than one week be made at incremental cost plus 10
percent. Sellers have argued that this is a departure from the
Commission's historical acceptance of ``up to'' rates for short-term
energy sales, including sales of less than one week. We seek comment on
whether to continue to apply a default rate for sales of less than one
week that is tied to incremental cost plus 10 percent. Are there
problems associated with using ``up to'' rates for shorter-term sales
and, if so, what are they? Does the current approach provide utilities
a disincentive to offer their power to wholesale customers in their
local control area for short-term sales? Would an ``up to'' rate
adequately mitigate market power for such sales?
    140. The second rate methodology issue relates to the design of an
``up to'' cost-based rate. In the past, the Commission has allowed
significant flexibility in designing ``up to'' rates. Is that
flexibility still warranted? For example, there are often disputes over
which units are ``most likely to participate'' or ``could participate''
in coordination sales. Should the Commission continue to allow
utilities flexibility in selecting the particular units that form the
basis of the ``up to'' rate? If not, what units should an ``up to''
rate be based upon, and how should that rate be calculated? Should the
Commission prescribe a standard methodology that would allow an
applicant to avoid a hearing on rate methodology? Would a methodology
that is based on average costs (both variable and embedded) allow an
applicant to avoid a hearing because it eliminates the seller's
discretion in designating particular units as ``likely to
participate''? Are there other approaches that would accomplish a
similar objective?
    141. In the April 14 and July 8 Orders, the Commission stated that
sellers that are found to have market power (i.e., after the Commission
has ruled on a DPT analysis) or that accept a presumption of market
power can either accept the Commission's default cost-based mitigation
measures or propose alternative methods of mitigation. With regard to
alternative methods of mitigation, should the Commission allow as a
means of mitigating market power the use of agreements that are not
tied to the cost of any particular seller but rather to a group of
sellers? Would

the use of such agreements as a mitigation measure satisfy the just and
reasonable standard of the FPA?
    142. Finally, the Commission notes that if a mitigated seller is
returning to existing cost-based rates, the Commission would have the
obligation to consider whether those rates are sufficient for that
purpose, and would have the authority to institute a proceeding under
FPA section 206 to investigate their justness and reasonableness.
    b. Discounting.
    143. A seller that has authorization to sell under an ``up to''
cost-based rate has an incentive to discount its sales price when the
market price in the seller's local area is lower than the cost-based
ceiling rate. During these periods, a rational seller will discount its
sales to maximize revenue. In the past the Commission has encouraged
discounting as an efficient practice that can maximize revenues to
reduce the revenue requirements borne by customers.
    144. The primary issue in this area is whether a seller can
``selectively'' discount, i.e., offer different prices to different
purchasers of the same product during the same time period. We seek
comment on whether selective discounting should be allowed for sellers
that are found to have market power or have accepted a presumption of
market power and are offering power under cost-based rates. If we do
allow selective discounting, what mechanisms (reporting or otherwise),
if any, are necessary to protect against undue discrimination? By
contrast, if we do not allow selective discounting, should we require
the utility to post discounts to ensure that they are available to all
similarly situated customers?
    c. Protecting Mitigated Markets.
    145. Under our current policy, if a seller loses market-based rate
authority in its home control area, any sales in that control area must
be pursuant to cost-based rates; however, there is no requirement that
the seller offer its available power to customers in that home control
area. Instead, the seller is free to market all its available power to
purchasers outside that control area if, for example, market prices
outside its control area exceed the cost-based caps. Wholesale
customers have argued that default cost-based mitigation of this kind
is of little value if a mitigated seller can simply market its excess
capacity at market-based rates in other control areas.\135\ To address
this concern, commenters have suggested that the Commission either
revoke a mitigated seller's market-based rate authority in all control
areas or impose some type of mitigation that protects wholesale
customers in those areas where a seller has been found to have market
power or has accepted the presumption of market power.
---------------------------------------------------------------------------

    \135\ See, e.g., Carolina Power and Light Company, 113 FERC ]
61,130 at P 16 & n.21 (2005).
---------------------------------------------------------------------------

    146. The Commission seeks comment on whether its current policy is
appropriate and, if not, what further restrictions are necessary. In
particular, we seek comment on the following:
    a. Is it appropriate to continue to allow sellers that are subject
to mitigation in their home control area to sell power at market-based
rates outside their control area? Does this represent undue
discrimination or otherwise constitute ``withholding'' in the home
control area that is inconsistent with the FPA's mandate that rates be
just, reasonable and not unduly discriminatory? Or, does this reflect
economically efficient behavior and encourage necessary trading within
and across regions, particularly in peak periods when marginal prices
rise above average embedded costs?
    b. Should the Commission adopt a form of ``must offer'' requirement
in mitigated markets to ensure that available capacity (i.e., above
that needed to serve firm and native load customers) is not withheld?
If so, should the must offer requirement be limited to sales of a
certain period to help ensure that wholesale customers use that power
to serve their own needs, rather than simply remarketing that power
outside the control area and profiting? For example, should there be an
annual open season under which the mitigated seller offers its
available capacity to local customers for the following year at the
cost-based ceiling rate and, if customers do not commit to purchase
that capacity, then the seller is free to sell the remaining capacity
at market-based rates where it has authority to do so? If we adopt such
a must offer requirement, what rules should there be to define
``available'' capacity to avoid case-by-case disputes over this issue?
    c. As an alternative, should the Commission find that any seller
that has lost market-based rate authority in its home control area
should not be able to sell power at market-based rates in adjacent
(first tier) control areas?
    Would this be appropriate mitigation and easier to implement than a
must offer requirement? Or, would such mitigation unnecessarily
discourage trading and flexibility in markets for which the seller has
been found not to have market power?
    d. Sales that Sink in Unmitigated Markets.
    147. The Commission has stated that its role is to assure customers
that sellers who are authorized to sell at market-based rates do not
have market power or have adequately mitigated the potential exercise
of market power.\136\ Further, the Commission's recent orders accepting
mitigation proposals are clear that the mitigation is to apply to sales
in the geographic market where an applicant is found (or presumed) to
have market power (mitigated market), not only sales to end users in
the control area.\137\ In order to put in place adequate mitigation
that eliminates the ability to exercise market power and ensure that
rates are just and reasonable,\138\ all market-based rate sales in a
mitigated market where an applicant is found or presumed to have the
ability to exercise market power must be subject to mitigation approved
by the Commission.
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    \136\ July 8 Order, 108 FERC ] 61,026 at P 146.
    \137\ See Oklahoma Gas and Electric Company and OGW Energy
Resources, Inc., 114 FERC ] 61,297 (2006), reh'g pending; Carolina
Power and Light Company, 114 FERC ] 61,294 (2006) (CP&L); Duke
Energy Trading and Marketing, L.L.C., 114 FERC ] 61,056 (2006).
    \138\ See April 14 Order at P 144, 147.
---------------------------------------------------------------------------

    148. Some companies have proposed limiting mitigation to sales that
``sink in'' the mitigated market, that is, so that mitigation would
only apply to end users in the mitigated market.\139\ However, in
MidAmerican Energy Company,\140\ the Commission stated that limiting
mitigation to sales that ``sink in'' the mitigated market would
improperly limit mitigation to certain sales, namely, only to sales to
those buyers that serve end-use customers in the mitigated market.
Limiting mitigation in this manner would improperly allow market-based
rate sales within the mitigated market to entities that do not serve
end-use customers in the mitigated market. Such a limitation would not
mitigate the seller's ability to attempt to exercise market power over
sales in the mitigated market and is inconsistent with our direction in
the April 14 and July 8 Orders. For example, on rehearing of the April
14 Order, it was argued that access to power sold under mitigated
prices should be restricted to buyers serving end-use customers within
the relevant geographic market in which the applicant has been found to
have market power. In particular, arguments were made that an applicant
should not be required to make sales at mitigated prices to power
marketers or brokers

without end-use customers in the relevant market. In the July 8 Order,
the Commission rejected the suggestion that we restrict mitigated
applicants to selling power only to buyers serving end-use
customers,\141\ and has since rejected tariff language that proposes to
do so.\142\
---------------------------------------------------------------------------

    \139\ The Commission has recently clarified that mitigation
applies to all sales in a mitigated market. See, e.g., CP&L, 114
FERC ] 61,294 at P 9 (2006).
    \140\ 114 FERC ] 61,280 (2006), reh'g pending (MidAmerican).
    \141\ See July 8 Order, 108 FERC ] 61,026 at P 134.
    \142\ See, e.g., MidAmerican, 114 FERC ] 61,280 at P 33.
---------------------------------------------------------------------------

    149. The Commission seeks comment on whether it should modify or
revise its current policy and, if so, how. In particular, we seek
comment on the following:
    a. Should the Commission allow market-based rate sales by a
mitigated seller within a mitigated market if those sales do not
``sink'' in that control area? If so, under what circumstances should
the Commission allow such sales and how would the Commission ensure
that such sales do indeed ``sink'' in an unmitigated control area? How
does the Commission distinguish possible permissible sales to the
border of the restricted control area from sales that are not permitted
within the restricted control area?
    b. Under such a policy, what opportunities, if any, are presented
to ``game'' the mitigation? If it is determined that a mitigated
seller's sales in fact do not ``sink'' outside the restricted control
area, what penalties should the Commission consider?
    c. If the Commission retains its current policy of prohibiting all
market-based rate sales by a mitigated seller in a mitigated market
what effect, if any, does such a policy have on existing contractual
arrangements? With regard to existing transmission rights a buyer may
have in a mitigated market, how easily could existing market-based rate
agreements between that buyer and the mitigated seller be amended to
provide for delivery of power in an unmitigated market under the same
economic terms as exists today?

E. Implementation Process

1. Current Practice
    150. The Commission's current practice is a case-by-case analysis
of new applications for market-based rate authorization as well as
updated market power analyses. In addition, to date the Commission has
allowed sellers to propose their own individualized tariffs.
2. Proposal
    151. The Commission proposes to put in place a structured,
systematic review to assist the Commission in analyzing sellers based
on a coherent and consistent set of data for relevant geographic
markets. In addition, some corporate families have many subsidiaries
with market-based rate authorization, each with its own separate
tariff. This has led to confusion, inconsistencies between the tariffs
of a single corporate family, and difficulty in coordinating changes to
the tariffs. To remedy these concerns, the Commission proposes to
streamline the administrative process associated with the filing and
review of market-based rate updated market power analyses and to
consolidate market-based rate authorizations into a single tariff.
    152. The Commission proposes to continue to require sellers to
submit updated market power analyses for all relevant geographic
markets (default or proposed alternative markets, as discussed
previously) in which they own or control generation. However, the
Commission proposes to modify this filing requirement in two ways.
First, the Commission proposes to establish two categories of sellers
with market-based rate authorization. The first category (Category 1)
would include power marketers and power producers that own or control
500 MW or less of generating capacity in aggregate and that are not
affiliated with a public utility with a franchised service territory.
In addition, Category 1 sellers must not own or control transmission
facilities other than limited equipment necessary to connect individual
generating facilities to the transmission grid (or must have been
granted waiver of the requirements of Order No. 888 because such
facilities are limited and discrete and do not constitute an integrated
grid \143\), and must present no other vertical market power issues.
Rather than requiring Category 1 sellers to file a regularly scheduled
triennial review, the Commission would monitor any market power
concerns through the change in status reporting requirement and through
ongoing monitoring by the Commission's Office of Enforcement.\144\ All
sellers with market-based rate authority are required to make a filing
with the Commission regarding any change in status that reflects a
departure from the characteristics that the Commission relied upon in
granting market-based rate authority. Failure to timely file a change
in status report would constitute a violation of the Commission's
regulations and the seller's MBR tariff.\145\ A seller would be subject
to disgorgement of profits and/or civil penalties from the date on
which the tariff violation occurred. Such seller may also be subject to
suspension or revocation of its authority to sell at market-based rates
(or other appropriate non-monetary remedies). In addition, the
Commission would retain the right to initiate a section 206 proceeding
if circumstances warranted. A seller that no longer satisfies the
Category 1 criteria would be required to submit a change in status
notification and would be subject to the updated market power analysis
filing required of Category 2 sellers.
---------------------------------------------------------------------------

    \143\ See, e.g., Black Creek Hydro, Inc., 77 FERC ] 61,232
(1996).
    \144\ Order No. 652, FERC Stats. & Regs., ] 31,175.
    \145\ Id. at P 113.
---------------------------------------------------------------------------

    153. The second category (Category 2) would include all sellers
that do not qualify for Category 1. Category 2 sellers, in addition to
the requirement to file change in status reports, would be required to
file regularly scheduled triennial reviews. Category 2 sellers are the
larger sellers with more of a presence in the market and are more
likely to either fail one or more of the indicative screens or pass by
a smaller margin than Category 1 sellers.
    154. To ensure greater consistency in the data used to evaluate
Category 2 sellers, the Commission proposes to require each seller to
file updated market power analyses for its relevant geographic markets
(default and any proposed alternative markets) on a schedule that will
allow examination of the individual seller at the same time the
Commission examines other sellers in these relevant markets and
contiguous markets within a region from which power could be
imported.\146\ The regional reviews would rotate by geographic region
with three regions reviewed per year. Appendix B provides a schedule
for the proposed regional review process. The Commission proposes to
continue to make findings on an individual seller basis, but will have
before it a complete picture of the uncommitted capacity and
simultaneous import capability into the relevant geographic markets
under review.
---------------------------------------------------------------------------

    \146\ Sellers would be deemed to be assigned to a region based
on the control area in which they own or control generation. Nine
regions will be examined using the regions specified in the 2004
State of the Markets Report, excluding ERCOT, as shown in the map
attached as part of Appendix B. Those regions are: Northwest,
California, Southwest, Midwest, SPP, Southeast, PJM, New York, and
New England.
---------------------------------------------------------------------------

    155. The Commission proposes to codify in its regulations the
obligation for Category 2 sellers to timely file a triennial review. As
a result, failure to timely file a triennial review would constitute a
violation of the Commission's regulations and the seller's MBR tariff
and could result in disgorgement of profits and/or civil

penalties from the date on which the seller violated its tariff.\147\ A
seller may also be subject to suspension or revocation of its authority
to sell at market-based rates (or other appropriate non-monetary
remedies). If a seller files a timely triennial review, its market-
based rate authority would continue unless the Commission institutes a
section 206 proceeding because the seller fails one of the indicative
screens and the Commission subsequently makes a definitive finding of
market power and revokes its market-based authority, or the seller
accepts the presumption of market power and adopts the default cost-
based mitigation or proposes other cost-based mitigation or tailored
mitigation.
---------------------------------------------------------------------------

    \147\ Currently, the requirement to file triennial reviews is
contained in our orders, but not in the tariffs or in our
regulations.
---------------------------------------------------------------------------

    156. Some corporate families own or control generation in multiple
control areas and different regions. For example, a corporate family
may own generation facilities on the east coast as well as in
California. In this instance, the corporate family would be required to
file a current triennial review for each region in which members of the
corporate family sell power during the time period specified for that
region. To the extent a new subsidiary is formed and a new request for
market-based rate authority is submitted, triennial reviews will be due
at the regularly scheduled time for review of the markets in the region
in which the new applicant owns or controls generation. We seek comment
on this proposal.
    157. In addition, the Commission proposes to require that all
triennial review filings and all new applications for market-based rate
authority include an appendix listing all generation assets owned or
controlled by the corporate family by control area and listing the in-
service date and nameplate and/or seasonal ratings by unit. The
appendix should also reflect all electric transmission and natural gas
intrastate pipelines and/or gas storage facilities owned or controlled
by the corporate family and the location of such facilities.
    158. Triennial reviews should reflect the most recently available
historical data from the calendar year prior to the year of filing.
    159. We seek comments on the proposal to adopt these filing
requirements.

F. Market-Based Rate Tariff (MBR Tariff)

    160. Historically the Commission has not required the filing of a
market-based rate tariff of general applicability. However, many
sellers have submitted one or more umbrella market-based rate tariffs
that set forth the conditions of market-based rate approval and the
general terms applicable to all transactions, with individual
transactions being negotiated through service agreements, letter
confirmations, or other documentation that sets forth the rates and any
individualized terms and conditions. This general practice has afforded
flexibility to sellers as markets and the industry evolved and as new
products and services were sold under market-based rate tariffs.
However, this flexible approach has sometimes resulted in inconsistency
in the tariffs filed within the same corporate family, which can create
confusion for customers and compliance problems, and it also has
resulted in inconsistencies in memorializing the conditions of market-
based rate approval in such tariffs.
    161. As part of our effort to streamline and simplify the market-
based rate program in general, while at the same time maintaining a
high degree of transparency and oversight, we propose to adopt a
market-based rate tariff of general applicability that all sellers
authorized to sell wholesale electric power at market-based rates will
be required to file as a condition of market-based rate authority.\148\
The MBR tariff would require the seller to comply with the applicable
provisions of the market-based rate regulations which this NOPR
proposes to codify in 18 CFR Part 35, Subpart H. These provisions
reflect the Commission's two decades of experience with market-based
rate power sales and should serve to reduce the burden on customers of
managing multiple tariffs. In addition, the seller would be required to
list on the MBR tariff the docket numbers and case citations, where
applicable, of the proceedings, if any, in which the seller received
Commission authorization to make sales of energy between affiliates or
where its market-based rate authority was otherwise restricted or
limited. A copy of the proposed MBR tariff is attached as Appendix A.
---------------------------------------------------------------------------

    \148\ Order No. 614 guidelines for designating rate schedules
must be observed.
---------------------------------------------------------------------------

    162. Not all of the provisions of the proposed regulations may be
applicable to all sellers. For example, a seller may not wish to offer
ancillary services under the tariff. The Commission seeks comments on
whether a placeholder should be reserved in the MBR tariff for the
seller to indicate those parts of the regulations that are not
applicable to that seller.
    163. In proposing the adoption of the MBR tariff, our purpose is
not to direct the terms and conditions of a particular power sale or to
otherwise reduce the flexibility afforded to market-based rate sellers
in fashioning the terms of individual transactions. Rather, sellers
would continue to negotiate the terms and conditions of sales entered
into under their MBR tariff, and the terms and conditions of those
underlying agreements and the transaction data would be reflected in
the quarterly EQRs. Further, if sellers wish to offer or require
certain ``generic'' terms and conditions that in the past were
contained in their market-based rate tariff, they may place customers
on notice of such requirements by including such information on a
company website and include any related provisions in individual
transaction agreements. Our purpose in requiring a MBR tariff of
general applicability is to ensure that the MBR tariff on file with the
Commission for each seller reflects, in a consistent manner, only those
matters that are required to be on file, namely, the identity of the
seller(s), the docket number(s) of the market-based rate authorization,
the seller's requirement to follow the conditions of market-based rate
authorization contained in our proposed regulations, and that the
rates, terms and conditions of any particular sale will be negotiated
between the seller and individual purchasers. We do not believe any
useful purpose is served in having on file the commercial terms
preferred by particular applicants, given that the purpose of market-
based rate authorization is to provide flexibility in such terms and
conditions. Furthermore, our standards for approval of market-based
rates do not include a review of such individualized commercial terms
and thus, such submissions are unnecessary.
    164. Further, the Commission proposes that, rather than each entity
having its own MBR tariff, which can result in dozens of tariffs for
each corporate family with conflicting provisions, each corporate
family has only one tariff on file, with all affiliates with market-
based rate authority separately identified in the tariff. This will
allow for better transparency with regard to what sellers each
corporate family has, and a more customer-friendly tariff. The
requirement to have a single MBR tariff does not mean that all members
of a corporate family would be counterparties on every sale under the
tariff; rather, individual transactions would continue to be
consummated

with individual sellers within the corporate family, as they are today.
    165. We seek comments on this proposal.
    166. Regarding the specifics of filing the MBR tariffs, we note
that the Commission has initiated a rulemaking proceeding to require
the filing of electronic tariffs.\149\ We propose that the timing of
filing and format for the MBR tariffs be consistent with the
requirements of the final rule issued in that proceeding.
---------------------------------------------------------------------------

    \149\ See Electronic Tariff Filings, Notice of Proposed
Rulemaking, 69 FR 43929 (July 23, 2004), FERC Stats. & Regs.,
Proposed Regulations ] 32,575 (July 8, 2004).
---------------------------------------------------------------------------

G. Miscellaneous Issues

1. Waivers
    167. Certain entities with market-based rate authority have
typically been granted waiver of the Commission's Uniform System of
Accounts, and thus have not been subject to specified accounting rules.
For instance, Parts 41, 101, and 141 of the Commission's regulations
prescribe certain informational requirements that focus on the assets
that a public utility owns.\150\ For market-based rate applications,
the Commission has taken the position that, because a power marketer
does not own any electric power generation or transmission facilities,
its jurisdictional facilities would be only corporate and documentary,
its costs would be determined by utilities that sell power to it, and
its earnings would not be defined and regulated in terms of an
authorized return on invested capital; accordingly, the Commission has
granted waivers to power marketers of the requirements of these Parts.
The Commission also has granted other market-based rate sellers, such
as independent or affiliated power producers, waiver of the
requirements of these Parts.
---------------------------------------------------------------------------

    \150\ Part 41 pertains to adjustments of accounts and reports;
Part 101 contains the Uniform System of Accounts; Part 141 describes
required forms and reports.
---------------------------------------------------------------------------

    168. The Commission has also granted power marketers' and others'
requests for blanket approval under Part 34 of the Commission's
regulations for all future issuances of securities and assumptions of
liability, assuming that no party objects to such treatment during a
notice period which the Commission provides.\151\ The purpose of
section 204 of the FPA, which Part 34 implements, is to ensure the
financial viability of public utilities obligated to serve electric
consumers. The Commission has granted blanket approval under Part 34
for future issuances of securities and assumptions of liability where
the entity seeking market-based rate authority, such as a power
marketer or power producer, is not a public service franchise providing
electricity to consumers dependent upon its service.\152\
---------------------------------------------------------------------------

    \151\ We note that the Commission's jurisdiction over issuances
of securities and assumptions of liabilities under section 204 of
the FPA applies only to entities that are public utilities as
defined in the FPA and only where the public utilities' security
issues are not regulated by a State commission (see FPA section
204(f)).
    \152\ See, e.g., St. Joe Minerals Corp., 21 FERC ] 61,323
(1982); Cliffs Electric Service Company, 32 FERC ] 61,372 (1985);
Citizens Energy Corp., 35 FERC ] 61,198 (1986); Howell Gas
Management Company, 40 FERC ] 61,336 (1987); and Nevada Sun-Peak
Limited Partnership, 86 FERC ] 61,243 (1999).
---------------------------------------------------------------------------

    169. As the development of competitive wholesale power markets
continues, independent and affiliated power marketers and power
producers are playing more significant roles in the electric power
industry. In light of the evolving nature of the electric power
industry, the Commission seeks comment on the extent to which these
entities should be required to follow the Uniform System of Accounts,
what financial information, if any, should be reported by these
entities, and how frequently it should be reported, and whether the
Part 34 blanket authorizations continue to be appropriate.
    170. The Commission announced in the April 14 Order that, where an
applicant is found to have market power (or where the applicant accepts
a presumption of market power), the applicant will be required to adopt
some form of cost-based rates or other mitigation the applicant
proposes and the Commission accepts. Under these circumstances, the
Commission found that it is essential that appropriate accounting
records be maintained consistent with the Commission's regulations.
Accordingly, the Commission indicated it will no longer waive the
otherwise applicable accounting regulations (e.g. Parts 41, 101, and
141 of the Commission's regulations).\153\ Thus, the Commission would
revoke the accounting waivers for a mitigated seller, and for any of
its affiliates with market-based rates in the mitigated control area.
Further, the Commission stated that it will not grant blanket approval
for issuances of securities or assumptions of liability pursuant to
Part 34 of the Commission's regulation for the mitigated seller and its
affiliates.\154\ In the case of any affiliates, this would entail
rescission of these blanket authorizations in all geographic areas, not
just the mitigated control area.
---------------------------------------------------------------------------

    \153\ April 14 Order, 107 FERC ] 61,018 at P 150.
    \154\ Id.
---------------------------------------------------------------------------

    171. We note that some sellers have had their market-based rate
authority revoked, or have elected to relinquish their market-based
rate authority after a presumption of market power, and have begun or
resumed selling power at cost-based rates. Consistent with the April 14
Order, any waivers previously granted in connection with those sellers'
market-based rate authority are no longer applicable. We propose that
such revocation of waivers become effective 60 days from the date of an
order revoking such waivers in order to provide the affected utility
with time to make the necessary filings with the Commission and allow
for an orderly transition from selling under market-based rates to
cost-based rates. We seek comment in this regard. The Commission seeks
input regarding any difficulties sellers may have when transitioning to
cost-based rates and whether a prior waiver of the accounting
regulations would leave them without adequate data to come into
conformance with the accounting rules.
2. Foreign Sellers
    172. Under existing policy, a foreign entity selling in the United
States (and each of its affiliates) must not have, or must have
mitigated, market power in generation and transmission and not control
other barriers to entry. In addition, the Commission considers whether
there is evidence of affiliate abuse or reciprocal dealing. However,
for foreign sellers, the Commission allows a modified approach to the
four prongs.
    173. With regard to generation market power, should a foreign
seller or any of its affiliates own or control any generation in the
United States, or should one of its first-tier markets include a United
States market, it should perform the market power screens in the
appropriate control area(s).
    174. With regard to transmission market power, the Commission
requires a foreign seller seeking market-based rate authority to
demonstrate that its transmission-owning affiliate offers non-
discriminatory access to its transmission system that can be used by
competitors of the foreign seller to reach United States markets.\155\
However, if foreign transmission facilities meet the criteria

for waiver of Order No. 888, such a demonstration would not be
required.\156\
---------------------------------------------------------------------------

    \155\ See TransAlta Enterprises Corp., 75 FERC ] 61,268 at
61,875 (1996), and Energy Alliance Partnership, 73 FERC ] 61,019 at
61,030-31 (1995) (Energy Alliance).
    \156\ Canadian Niagara Power Company, 87 FERC ] 61,070 (1999).
---------------------------------------------------------------------------

    175. For purposes of market-based rate authorization, the
Commission does not consider transmission and generation facilities
that are located exclusively outside of the United States and that are
not directly interconnected to the United States. However, the
Commission would consider transmission facilities that are exclusively
outside the United States but nevertheless interconnected to an
affiliate's transmission system that is directly interconnected to the
United States.\157\
---------------------------------------------------------------------------

    \157\ Fortis Ontario, Inc. and Fortis U.S. Energy Corp., 115
FERC ] 61,110 (2006).
---------------------------------------------------------------------------

    176. Regarding other potential barriers to entry, a foreign seller
should inform the Commission of any potential barriers to entry that
can be exercised by either it or its affiliates in the same manner as a
seller located within the United States.
    177. Finally, regarding affiliate abuse, the Commission typically
requires a power marketer with market-based rate authorization to file
for approval under section 205 of the FPA before selling power to or
purchasing power from any utility affiliate. However, this general
requirement does not apply to situations involving sales of power to or
from a foreign utility outside of the Commission's jurisdiction.\158\
---------------------------------------------------------------------------

    \158\ Energy Alliance, 73 FERC ] 61,019 at 61,031; TransAlta, 75
FERC ] 61,268 at 61,876.
---------------------------------------------------------------------------

    178. The Commission proposes to retain its current policy when
reviewing a foreign seller's application for market-based rate
authorization consistent with our overall approach discussed herein.
The Commission seeks comments regarding whether this current policy is
adequate to grant market-based rate authorization to such sellers.
3. Change in Status
    179. In early 2005, the Commission clarified and standardized
market-based rate sellers' reporting requirement for any change in
status that departed from the characteristics the Commission relied on
in initially authorizing sales at market-based rates. In Order No.
652,\159\ the Commission required, as a condition of obtaining and
retaining market-base rate authority, that sellers file notices of such
changes no later than 30 days after the change in status occurs. The
rule provided that a change in status includes, but is not limited to:
(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.\160\ A
seller's experiencing one of these changes would trigger the
notification requirement.\161\
---------------------------------------------------------------------------

    \159\ Order No. 652 at P 47.
    \160\ See 18 CFR 35.27(c) (2005).
    \161\ If a seller ceases to do business, or, in the event of its
dissolution, such seller should file a notice of cancellation of its
rate schedule.
---------------------------------------------------------------------------

    180. The Commission has provided further guidance on change in
status filings in several cases. In Calpine Energy Services, L.P.,\162\
the Commission clarified that sellers making a change in status filing
to report an energy management agreement are required to make an
affirmative statement regarding whether the agreement transfers control
of any assets and whether it results in any material effect on the
conditions the Commission relied on when granting market-based rates.
The Commission also clarified that:
---------------------------------------------------------------------------

    \162\ 113 FERC ] 61,158 at P 13 (2005).

A seller making a change in status filing is required to state
whether it has made a filing pursuant to section 203 of the Federal
Power Act. To the extent the seller has made a section 203 filing
that it submits is being made out of an abundance of caution and
thus has voluntarily consented to the Commission's section 203
jurisdiction, the seller will be required to incorporate this same
assumption in its market-based rate change in status filing (e.g.,
if the seller assumes that it will control a jurisdictional facility
in a section 203 filing, it should make that same assumption in its
market-based rate change in status filing and, on that basis, inform
the Commission as to whether there is any material effect on its
market-based rate authority).[\163\]
---------------------------------------------------------------------------

    \163\ Id. at P 14 (footnotes omitted).

    181. In addition, 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 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).\164\ 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.\165\
---------------------------------------------------------------------------

    \164\ See Order No. 652, FERC Stats. & Regs. ] 31,175 at P 68.
The reporting requirement is triggered only by net, rather than
gross, increases in generation capacity of 100 MW or more. For
example, capacity decreases associated with changes in generation
capacity or expiration of capacity under long-term purchase
contracts should be netted against generation capacity increases to
determine whether the 100 MW materiality threshold has been reached.
The Commission has adopted a netting approach in determining whether
the materiality threshold has been reached, subject to the
cumulative 100 MW threshold. See Order No. 652-A, 111 FERC ] 61,413
at P 24-25.
    \165\ Order No. 652 at P 95.
---------------------------------------------------------------------------

    182. In Order No. 652, the Commission identified a number of issues
that could be pursued in the instant rulemaking proceeding. The
Commission had proposed in that rulemaking proceeding to include fuel
supplies as an input to electric power production the acquisition of
which would be a reportable change in status. However, in the final
rule, the Commission determined that this issue would be more
appropriately raised in the instant rulemaking proceeding, and stated
that the Commission would provide opportunity for interested persons to
propose modifications to the existing approach in this proceeding.\166\
Accordingly, the Commission solicits comments on whether ownership of
any new inputs to electric power production, including fuel supplies,
should be reportable. To the extent that any such information is deemed
reportable, the Commission proposes to align this reporting requirement
to reflect the consideration of other barriers to entry as part of the
vertical market power analysis, and commenters should refer to the
discussion of other barriers to entry herein where the Commission
proposes to clarify what constitutes an input to electric power
production as part of the Commission's review of vertical market power.
---------------------------------------------------------------------------

    \166\ Id. at P 58.
---------------------------------------------------------------------------

    183. In Order No. 652, the Commission clarified that the reporting
of transmission outages per se as a change in status was not required.
However, to the extent a transmission outage affects, on a long-term
basis (e.g., an extended outage of a circuit or substation), whether
the seller satisfies the Commission's concerns regarding horizontal or
vertical market power (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. The Commission also stated
that it would consider this matter further in the context of this
rulemaking in the transmission market power part of the market power
analysis.\167\ We propose,

consistent with Order No. 652, not to require the reporting of
transmission outages per se as a change in status. We seek comment on
this proposal.
---------------------------------------------------------------------------

    \167\ Id. at P 75.
---------------------------------------------------------------------------

    184. The Commission declined in Order No. 652 to narrow or
delineate the definition of control. The Commission noted that,
historically, if a seller has control over certain capacity such that
it can affect the ability of the capacity to reach the relevant market,
then that capacity should be attributed to the seller when performing
the generation market power screens. Further, the capacity associated
with contracts that confer operational control of a facility to an
entity other than the owner must be assigned to the entity exercising
control over that facility. The Commission concluded that it is not
possible to predict every contractual agreement that could result in a
change of control of an asset. However, the Commission indicated that
to the extent that 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 instant rulemaking.\168\ As
discussed above, the horizontal market power section herein seeks
comment on a number of issues concerning control and commitment of
generation.
---------------------------------------------------------------------------

    \168\ Id. at P 47.
---------------------------------------------------------------------------

    185. In Order No. 652 we did not expand the triggering events for a
change in status filing to include actions 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 level, higher
wind generation, or load disruptions due to adverse weather
conditions). In Order No. 652, we concluded that the reporting
obligation should extend only to changes in circumstances within the
knowledge and control of the seller. However, in Order No. 652, we
stated that interested persons could pursue in the instant rulemaking
whether the Commission should expand the triggering events for a change
in status filing. Accordingly, we invite comments generally on whether
the Commission should expand the triggering events beyond ownership or
control of facilities or inputs and affiliation with entities that own
or control facilities or inputs or that have a franchised service
territory, as adopted in Order No. 652.
4. Third-Party Providers of Ancillary Services
    186. In Order No. 888, the Commission required transmission
providers to offer certain ancillary services at cost-based rates as
part of their open access commitment but also contemplated that third
parties (parties other than the transmission provider in a particular
transaction) would also provide ancillary services.\169\ The Commission
also left open the door that ancillary services could be provided on
other than a cost-of-service basis. In Order No. 888, Commission stated
that it would entertain requests for market-based pricing related to
ancillary services on a case-by-case basis if supported by analyses
that demonstrate that the seller lacks market power in these discrete
services.\170\ In Ocean Vista Power Generation, L.L.C. (Ocean
Vista),\171\ the Commission explained that as a general matter a study
of ancillary service markets should address the nature and
characteristics of each ancillary service, as well as the nature and
characteristics of generation capable of supplying each service, and
that the study should develop market shares for each service. The
Commission also noted that it would entertain alternative explanations
and approaches.
---------------------------------------------------------------------------

    \169\ See Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,720-
21.
    \170\ Id.; Order No. 888-A, FERC Stats. & Regs. ] 31,048 at
30,237-38.
    \171\ 82 FERC ] 61,114 at 61,406-07.
---------------------------------------------------------------------------

    187. In Ocean Vista, the Commission also offered more detailed
guidance for what a market power study for ancillary services markets
should include: (1) Defining a relevant product market for each
ancillary service, which should include the applicant's product,
together with other products that, from the buyer's perspective, are
good substitutes; (2) identifying the relevant geographic market, which
could include all potential suppliers of the product from whom the
buyer could obtain the service, taking into account relevant factors
which may include the other suppliers' locations, the physical
capability of the delivery system and the cost of such delivery, and
important technical characteristics of the suppliers' facilities; (3)
establishing market shares for all suppliers of the ancillary services
in the relevant geographic markets; and (4) examining other barriers to
entry.
    188. The guidance offered by the Commission in Order No. 888 and
Ocean Vista was designed for two purposes: to ensure that sellers of
ancillary services do not exercise market power and to further the goal
of promoting competition in ancillary service markets.
    189. However, in Avista Corporation,\172\ the Commission stated
that there remained two problems hindering the development of ancillary
service markets. First, access to critical data may preclude many
potential sellers of ancillary services from performing reliable market
analyses. Second, without an alternative means of regulating ancillary
service rates at an early stage in the development of competitive
wholesale power markets, the Commission may not be able to encourage
sufficient market entry of third-party providers of ancillary services.
---------------------------------------------------------------------------

    \172\ 87 FERC ] 61,223, order on reh'g, 89 FERC ] 61,136 (1999)
(Avista).
---------------------------------------------------------------------------

    190. Accordingly, the Commission adopted a policy wherein third-
party ancillary service providers that cannot perform a market power
study would be allowed to sell ancillary services at market-based
rates, but only in conjunction with a requirement that such third
parties establish an Internet-based OASIS-like site for providing
information about and transacting ancillary services.
    191. In this regard, the Commission stated that it will apply this
policy only to applicants who are authorized to sell power and energy
at market-based rates. In addition, the Commission stated that it will
not apply this approach to sales of ancillary services by a third-party
supplier in the following situations: (1) The approach will not apply
to sales to a regional transmission organization (RTO) or an
independent system operator (ISO), i.e., where that entity has no
ability to self-supply ancillary services but instead depends on third
parties (the Commission stated that its experience to date indicates
that the data problems associated with market analysis involving sales
to an ISO, for example, should not be insurmountable and an appropriate
showing of a lack of market power can be made); \173\ (2) to address
affiliate abuse concerns, the approach will not apply to sales to a
traditional, franchised public utility affiliated with the third-party
supplier,

or to sales where the underlying transmission service is on the system
of the public utility affiliated with the third-party supplier; and (3)
the approach will not apply to sales to a public utility who is
purchasing ancillary services to satisfy its own open access
transmission tariff requirements to offer ancillary services to its own
customers (the Commission indicated that it is open, however, to
considering requests for market-based rates in such circumstances on a
case-by-case basis).\174\
---------------------------------------------------------------------------

    \173\ With the formation of RTOs and ISOs, several RTO/ISOs
performed market analyses to demonstrate whether various ancillary
services are competitive. The result has been as follows: California
Independent System Operator: Regulation, Spinning Reserve, and Non-
Spinning Reserve. ISO New England: Regulation and Frequency
(Automatic Generation Control), Operating Reserve--Ten-Minute
Spinning, Operating Reserve--Ten-Minute Non-Spinning, and Operating
Reserve--Thirty Minute. New York Independent System Operator:
Regulation and Frequency Response Service, Operating Reserve Service
(including Spinning Reserve, 10-Minute Non-Synchronized Reserves and
30-Minute Reserves). PJM Independent System Operator: Regulation and
Frequency Response, Energy Imbalance, Operating Reserve--Spinning,
and Operating Reserve--Supplemental. Thus, in markets where the
demonstration has been made, sellers are afforded the opportunity to
sell at market-based rates subject to any other conditions in those
markets.
    \174\ Avista, 87 FERC at 61,883 n. 12.
---------------------------------------------------------------------------

    192. The Commission based its policy as announced in Avista on the
expectation that, as entry into ancillary service markets occurs,
prices will decrease from the level established by the transmission
provider's cost-based rate. Under these circumstances, customers will
pay prices for ancillary services that are no higher than and will very
likely be lower than the transmission provider's cost-based rate.\175\
The Commission explained that the ancillary services customer is
protected in part by the availability of the same ancillary services at
cost-based rates from the transmission provider. The backstop of cost-
based ancillary services from the transmission provider provides, in
effect, a limit on the price at which customers are willing to buy
ancillary services. The Commission stated that it believes that this
protection, in conjunction with the Internet-based site requirement,
will provide an appropriate and effective safeguard against potential
anticompetitive behavior.
---------------------------------------------------------------------------

    \175\ The Commission stated that it is cognizant of, but will
address separately and at the appropriate time, situations in which
it becomes apparent that, due to changes in ancillary services
markets, competitive prices would be higher than the transmission
provider's cost-based rate, were it not for the transmission
provider's obligation to meet all demand for ancillary services at
such a rate.
---------------------------------------------------------------------------

    193. The information contained in the Internet-based site would
include service availability, prices, and requests granted and denied.
To further monitor development of market entry, the Commission required
third-party suppliers to file with the Commission one year after their
Internet-based site is operational (and at least every three years
thereafter \176\) a report detailing their activities in the ancillary
services market.
---------------------------------------------------------------------------

    \176\ The Commission reserves the right to require that such a
report be filed at any time.
---------------------------------------------------------------------------

    194. In particular, the Commission stated that:

[i]f the applicant cannot perform a study showing that it lacks
market power in the provision of ancillary services, it may receive
flexible rates provided it safeguards against potential
anticompetitive behavior by establishing an Internet-based site for
providing information regarding, and conducting, ancillary services
transactions. The site would include postings of offers of services
available and their offering prices and would provide customers with
the ability to request services and make bids for these services.
The site would also contain information about accepted and denied
requests and the reasons for denial. The site should conform to the
applicable OASIS Standards and Communications Protocols (Version
1.3).[\177\]

    \177\ Avista, 87 FERC at 61,884. We note that section 37.6(d)(5)
of the Commission's regulations states: ``Any entity offering an
ancillary service shall have the right to post the offering of that
service on the OATT if the service is one required to be offered by
the Transmission Provider under the pro-forma tariff prescribed by
part 35 of this chapter. Any entity may also post any other
interconnected operations service voluntarily offered by the
Transmission Provider. Postings by customers and third parties must
be on the same page, and in the same format, as posting of the
Transmission Provider.''
---------------------------------------------------------------------------

    195. We propose to retain our current approach in this regard. We
seek comment on whether we should modify or revise our current approach
and, if so, how. Also, we seek comment on whether our current
conditions such as the requirement to establish an Internet-based site
continue to be necessary.

Proposed Revisions To Regulations

I. Section 35.27 [Currently] Power Sales at Market-Based Rates
    196. Subsections (a) and (b) of this section were added by Order
No. 888 in order to implement the post-1996 exemption for new
generation and to clarify the authority of state commissions
respectively. Order No. 652 later added subsection (c) to implement the
change in status reporting requirement.
    197. This NOPR proposes to eliminate the post-1996 exemption, and
thus the proposed regulatory text deletes subsection (a). Subsection
(c) is proposed to move to subpart H section 35.43, and thus the
proposed text deletes section 35.27(c). This leaves only current
subsection (b) in 35.27. The proposed regulatory text does not revise
the language in any way and merely renumbers current subsection (b) to
reflect the absence of the other subsections.
    198. With the changes proposed herein, the current section heading,
``Power Sales at Market-Based Rates,'' will no longer be pertinent. The
Commission proposes to amend the heading to ``Authority of State
Commissions'' to reflect the content of the remaining provision.
II. Section 35.36 Generally
    199. This section is proposed to define certain terms specific to
Subpart H and to explain the applicability of Subpart H.\178\ Some of
these terms were put in place recently when the Commission codified
certain market behavior rules in Order No. 674.\179\ Subsection (a)(1)
explains that ``seller'' refers to a public utility with authority to,
or seeking authority to, engage in sales for resale of electric energy,
capacity or ancillary services at market-based rates to make clear that
Subpart H deals exclusively with market-based rate power and ancillary
services sales. The proposed regulations define Category 1 sellers and
Category 2 sellers to assist in understanding the parameters of the
updated market power analysis requirement. Subsection (a)(4) defines
inputs to electric power production in order to simplify section
35.37(e) regarding other barriers to entry. Subsection (a)(5) indicates
that where the term franchised public utility is used, it is meant to
include only those public utilities with a franchised service territory
that have captive customers. Last, subsection (a)(6) provides a
definition for non-regulated affiliated entities, which appears in
several places in the proposed regulations.
---------------------------------------------------------------------------

    \178\ We note that we also proposed to change the title of
Subpart H from `Wholesale Sales of Electricity at Market-Based
Rates' to `Wholesale Sales of Electric Energy, Capacity and
Ancillary Services at Market-Based Rates.'
    \179\ Conditions for Public Utility Market-Based Rate
Authorization Holders, Order No. 764, FERC Stats. & Regs.
31,208, 114 FERC ] 61,163 (2006).
---------------------------------------------------------------------------

    200. Subsection (b) is intended to leave room for certain
provisions that do not apply to a particular seller should the
Commission make a finding, for instance, that a franchised public
utility has no captive customers and hence section 35.39(b) is not
applicable.
    201. We solicit comments on whether further or different language
than that proposed here should be incorporated in our regulations.
III. Section 35.37 Market Power Analysis Required
    202. This section describes the market power analysis the
Commission employs, as discussed in the preamble, and when sellers must
file one. It is intended to identify the key aspects of the analysis
without providing too much detail. The Commission is cognizant that the
finer points of the market power analysis change over time as
individual orders consider new facts and as precedent shifts to follow
the evolution of the power industry; the proposed regulations should
not be so

detailed as to require revision from time to time to follow these
changes.
    203. We solicit comments on the scope of the language that should
be incorporated in the regulations.
IV. Section 35.38 Mitigation
    204. The NOPR raises questions concerning the current approach and
seeks comments regarding any changes the Commission should adopt. In
addition, we propose to characterize the informal term ``up to'' cost-
based rates as ``priced at no higher than a cost-based ceiling
reflecting the cost of the units expected to provide service.'' We seek
comments on whether further or different language than that proposed
here should be incorporated in our regulations.
V. Section 35.39 Affiliate Provisions
    205. This section governs affiliate transactions and affiliate
relationships and establishes affiliate conditions that a seller must
satisfy as a condition of its market-based rate authority. Subsection
(a) includes a provision expressly prohibiting sales between a
franchised public utility and any of its non-regulated power sales
affiliates without first receiving authorization of the transaction
under section 205 of the FPA. This subsection requires that, where the
Commission grants a seller authority to engage in affiliate sales under
its MBR tariff, any and all such authorizations must be listed in the
seller's tariff. We seek comments on the proposal to include this
provision in the Commission's regulations.
    206. Subsections (b)-(e) contain the market-based rate code of
conduct provisions governing the relationship between a franchised
public utility and its non-regulated power sales and power brokering
affiliates. The provisions of this subsection apply to all franchised
public utilities with captive customers. This subsection includes
provisions governing the separation of employees, the sharing of market
information, sales of non-power goods or services, and power brokering.
It proposes that, for purposes of applying the provisions of this
section, entities acting on behalf of and for the benefit of a
franchised public utility (such as service companies and entities
managing the generation assets of the franchised public utility) are
considered to be part of the franchised public utility, and entities
acting on behalf of and for the benefit of a non-regulated affiliate of
a franchised public utility (such as affiliated power marketers and
power producers and entities managing the generation assets of the
affiliated power marketers and producers) are considered to be part of
the non-regulated affiliates. This section is an integral part of the
Commission's conditions regarding affiliate abuse where captive
customers are concerned. We seek comments on the proposal to include
the affiliate provisions in the regulations.
VI. Section 35.40 Ancillary Services
    207. This provision restricts sales of ancillary services to those
specific geographic markets for which the Commission has authorized
market-based rate sales of such. In addition, this section lays out the
limitations on third-party ancillary services sales provided in Avista
Corporation.\180\
---------------------------------------------------------------------------

    \180\ Avista Corporation, 87 FERC ] 61,223, order on reh'g, 89
FERC ] 61,136 (1999).
---------------------------------------------------------------------------

VII. Section 35.41 Market Behavior Rules
    208. Recently, the Commission rescinded two of its market behavior
rules and codified the remainder in section 35.37 of new Subpart H.
Also, in a Final Rule issued concurrently with this NOPR, the
Commission is revising the record retention period from three years to
five years. In this NOPR, we propose to move these market behavior
rules, unchanged, from Sec.  35.37 to Sec.  35.41.
VIII. Section 35.42 Market-Based Rate Tariff
    209. This proposed provision imposes the requirement that each
seller (or its corporate parent) have on file with the Commission the
market-based rate tariff that is appended hereto at Appendix A.
IX. Section 35.43 Change in Status Reporting Requirement
    210. This section incorporates the provision currently found at
subsection 35.27(c), which was codified by Order No. 652. No
modifications to the existing language are proposed. We seek comment on
whether any changes are warranted.
X. Information Collection Statement
    211. The Office of Management and Budget (OMB) regulations require
approval of certain information collection and data retention
requirements imposed by agency rules.\181\ Upon approval of a
collection of information and data retention, OMB will assign an OMB
control number and an expiration date. Respondents subject to the
filing requirements of this rule will not be penalized for failing to
respond to these collections of information unless the collections of
information display a valid OMB control number. As discussed herein,
the Commission proposes amending its regulations to codify its
requirements for obtaining and retaining market-based rate
authorization, implementing a market-based rate tariff, and
incorporating the change in status reporting requirement for sellers
seeking market-based rate authority.
---------------------------------------------------------------------------

    \181\ 5 CFR 1320.11 (2005).
---------------------------------------------------------------------------

    212. The Commission has previously required utilities seeking
market-based rate authority to file a market power analysis with the
Commission; the Commission now proposes to codify that requirement in
the Commission's regulations. This proposal reflects the Commission's
existing practice and will not impose any additional burden, with the
following exception.
    213. Section 35.27(a) of the Commission's regulations currently
provides that any public utility seeking market-based rate authority
shall not be required to submit a generation market power analysis with
respect to sales from capacity for which construction commenced on or
after July 9, 1996. Under current procedures, if all the generation
owned or controlled by an applicant for market-based rate authority and
its affiliates in the relevant control area is post-July 9, 1996
generation, such applicant is not required to submit a generation
market power analysis. In this NOPR, the Commission proposes to
eliminate the express exemption provided in section 35.27(a). This
proposal would require that all new applicants seeking market-based
rate authority on or after the effective date of the final rule issued
in this proceeding, whether or not all of their and their affiliates'
generation was built or acquired after July 9, 1996, must provide a
market power analysis of their generation to support their application
for market-based rate authority. Because the Commission allows an
applicant to make simplifying assumptions, where appropriate, and
therefore to submit a streamlined analysis, any burden of document
preparation occasioned by the proposed elimination of section 35.27(a)
should be minimal. Moreover, any burden of document preparation caused
by the proposed elimination of section 35.27(a) should apply for the
most part only with regard to generation market power analyses required
to support an initial application for market-based rate authority.
    214. The second filing requirement proposed in this NOPR is that
all market-based rate sellers file one market-based rate tariff per
corporate family. The MBR tariff proposed by the Commission is appended
to this NOPR. The proposed tariff, coupled with the proposed
regulations, will simplify the

content of MBR tariffs filed with the Commission and decrease the
burden of document preparation by providing a clearly defined statement
of the information sought by the Commission. Utilities will only be
required to fill in the company-specific information, which lessens the
burden of drafting documentation. A tariff of general applicability
will also give the Commission consistency on review and clarity
regarding the connections between parent and affiliate utilities in its
analysis. Although the requirement to file the specified MBR tariff may
cause a minimal burden of document preparation and organization for
existing market-based rate sellers, long-term benefits will be realized
for utilities as well as the Commission.
    215. To retain market-based rate authority, the Commission
currently requires that sellers file a triennial review. In this NOPR,
the Commission proposes to codify the requirement that certain sellers
with market-based rate authority file a triennial review with the
Commission to retain that authority. However, the Commission proposes
that certain smaller utilities, Category 1 sellers, be relieved of
their existing duty to file the triennial review. Thus, larger sellers
will not face a greater burden to provide the Commission with the
information required for a triennial review, and the burden of
supplying the updated analysis may be eliminated for certain smaller
entities seeking to retain market-based rate authority.
    216. The Commission's regulations, in 18 CFR part 35, specify those
reporting requirements that must be followed in conjunction with the
filing of rate schedules under the FPA. The information provided to the
Commission under part 35 is identified for information collection and
records retention purposes as FERC-516. Data collection FERC-516
applies to all reporting requirements covered in 18 CFR part 35
including: electric rate schedule filings, market power analyses,
tariff submissions, triennial reviews, and reporting requirements for
changes in status for public utilities with market-based rate
authority.
    217. The Commission is submitting these reporting and records
retention requirements to OMB for its review and approval under section
3507(d) of the Paperwork Reduction Act.\182\ Comments are solicited 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 the respondent's
burden, including the use of automated information techniques.
---------------------------------------------------------------------------

    \182\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------

    Burden Estimate: The Public Reporting and records retention burden
for all four proposed reporting requirements and the records retention
requirement is as follows.\183\
---------------------------------------------------------------------------

    \183\ These burden estimates apply only to this NOPR and do not
reflect upon all of FERC-516.
---------------------------------------------------------------------------

    Title: Electric Rate Schedule Filings (FERC-516).\\ \\
    Action: Revised Collection.\\
    OMB Control No: 1902-0096.\\
---------------------------------------------------------------------------

    \184\ The number of respondents for market-based rate tariffs is
expected to be 650. The figure 217 represents 650 respondents, per
year, over the course of 3 years. Also, the 650 figure takes into
account that parent companies will file for their affiliates.
    \185\ Category 1 Sellers are power marketers and power producers
that own or control 500 MW or less of generating capacity in
aggregate and that are not affiliated with a public utility with a
franchised service territory. In addition, Category 1 sellers must
not own or control transmission facilities, and must present no
other vertical market power issues. The zero in this section
represents that Category 1 Sellers are not responsible for filing
triennial updates.
    \186\ Category 2 Sellers are any sellers not in Category 1.
    \187\ To determine the number of responses, the number of
respondents (600) has been divided by 3 because the responses will
be submitted to the Commission on a staggered basis over the course
of a three year period.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
Initial Market Power Analysis...................             120             120             130          15,600
Market-Based Rate Tariff........................       \184\ 650             217               6           3,900
Triennial Review Category 1 \185\...............               0               0               0               0
Triennial Review Category 2 \186\...............             600       \187\ 200             250          50,000
----------------------------------------------------------------------------------------------------------------

    Total Annual hours for Collection: (Reporting + record retention,
(if appropriate) = hours.
    Information Collection Costs: The total annual cost for Initial
Market Power Analysis is estimated to be $2,340,000. Total annual cost
for market-based rate tariffs is projected to be $195,300. Total annual
cost for Triennial Reviews Category 2 is projected to be $7,500,000.
The hourly rate of $150 includes attorney fees, engineering
consultation fees and administrative support. There are 2080 total work
hours in a year. There are no filing fees associated with applications
for market-based rate authority.
    Respondents (Market Power Analysis; MBR Tariff; Triennial Review):
Businesses or other for profit.
    Frequency of Responses: Market Power Analyses: Occasionally;
consistent with current practice, a market power analysis must be filed
for each utility seeking market-based rate authority.
    MBR Tariff: An MBR tariff for each corporate family with all
current sellers to be filed with the Commission after the final rule is
effective. In the future, an MBR tariff will be filed occasionally by
each utility newly seeking market-based rate authority.
    Triennial Review: Updated market power analysis filed every three
years for Category 2 sellers seeking to retain market-based rate
authority.\188\
---------------------------------------------------------------------------

    \188\ Certain smaller entities (Category 1 sellers) are proposed
to be exempted from this requirement.
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    Necessity of the Information: Market Power Analyses: Consistent
with current practices, the market power analysis aids the Commission
in determining whether an entity seeking market-based rate authority
lacks market power and permits a determination that sales by that
entity will be just and reasonable.
    MBR Tariff: A market-based rate tariff filed for each corporate
family, with all affiliates with market-based rate authority separately
identified in the tariff, would improve the efficiency of the
Commission in its analysis and determination of market-based rate
authority. The MBR Tariff would allow the Commission to have a clear
definition of the relationships between parent and affiliate utilities
in assessing market-based rate authority and/or the investigation
thereof. This will allow for better transparency with regard to what
sellers each corporate family has, and a more customer friendly tariff.
A tariff of general applicability will also reduce document preparation
time overall and provide utilities with the clearly defined
expectations of the Commission.
    Triennial Review: The triennial review allows the Commission to
monitor market-based rate authority to

detect changes in market power or potential abuses of market power. The
updated market power analysis permits the Commission to determine that
continued market-based rate authority will still yield rates that are
just and reasonable.
    Internal review: The Commission has conducted an internal review of
the public reporting burden associated with the collection of
information and assured itself, by means of internal review, that there
is specific, objective support for this information burden estimate.
Moreover, the Commission has reviewed the collections of information
proposed by this NOPR and has determined that these collections of
information are necessary and conform to the Commission's plans, as
described in this order, for the collection, efficient management, and
use of the required information.\189\
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    \189\ See 44 U.S.C. 3506(c) (2004).
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    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:<PHONE_NUMBER>, fax: (202)
273-0873, e-mail<EMAIL_ADDRESS>Comments on the requirements
of the proposed 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].
XI. Environmental Analysis
    218. 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.\190\ The
Commission has categorically excluded certain actions from this
requirement as not having a significant effect on the human
environment.\191\ The actions proposed here fall within the categorical
exclusions in the Commission's regulations for rules that are
clarifying, corrective, or procedural, or do not substantially change
the effect of legislation or regulations being amended.\192\ In
addition, the proposed rule is categorically excluded as an electric
rate filing submitted by a public utility under sections 205 and 206 of
the FPA.\193\ As explained above, this proposed rule addressing the
issue of electric rate filings submitted by public utilities for
market-based rate authority is clarifying in nature. Accordingly, no
environmental assessment is necessary and none has been prepared in
this NOPR.
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    \190\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles July 1996-December 2000 ] 30,783
(1987).
    \191\ 18 CFR 380.4 (2005).
    \192\ See 18 CFR 380.4(a)(2)(ii).
    \193\ See 18 CFR 380.4(a)(15).
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XII. Regulatory Flexibility Act Analysis
    219. The Regulatory Flexibility Act of 1980 (RFA) \194\ generally
requires a description and analysis of rules that will have significant
economic impact on a substantial number of small entities.\195\ The
proposed rule will be applicable to all public utilities seeking and
currently possessing market-based rate authority. The Commission finds
that the regulations proposed here should not have a significant impact
on small businesses.
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    \194\ 5 U.S.C. 601-12 (2000).
    \195\ 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 that is independently owned
and operated and that 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 year did not exceed 4 million MWh. 13 CFR 121.201
(2004) (section 22, Utilities, North American Industry
Classification System, NAICS).
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    220. The submission of a market power analysis is currently
required of all entities seeking authority to sell at market-based
rates, and the proposed rule does not alter which entities will be
required to file these analyses. The proposed rule does not create a
new reporting requirement. It does, however, propose to expand the
scope of the analysis that must be submitted for those entities that
previously were exempted from preparing a generation market power
analysis by virtue of 18 CFR 35.27(a). The Commission is concerned that
the continued use of the section 35.27(a) exemption, in time, would
encompass all market participants as all pre-July 9, 1996 generation is
retired. Nevertheless, because the Commission allows an applicant to
make simplifying assumptions, where appropriate, and therefore to
submit a streamlined analysis, the Commission believes that any
additional burden imposed by the proposed elimination of the section
35.27(a) exemption will be minimal. Thus, public utilities are
currently prepared to submit market power analyses and this requirement
does not pose a greater burden.
    221. The proposed rule requires that each corporate family have on
file one MBR tariff of general applicability, with all affiliates with
market-based rate authority separately identified in the tariff.
Although this may initially increase the burden of document preparation
and organization for parent utilities, long-term benefits will be
realized that reduce burdens on utilities and the Commission. A tariff
of general applicability will decrease document preparation by
providing a clearly defined statement of the information sought by the
Commission. Moreover, a single tariff for each corporate family will
reduce the filing burden on utilities. Small entities affiliated with a
parent utility need not prepare a separate tariff; rather, they will
merely add their company name to their parent utility's tariff. Thus,
the burden is decreased.
    222. The triennial review submissions that provide updated market
power analyses are required for the retention of market-based rate
authority. Category 2 utilities shall continue to submit this analysis,
which poses no greater burden than that already in place. However, the
proposed regulations would result in fewer filings with the Commission
than currently required for qualified smaller utilities' (Category 1)
retention of market-based rate authority. Those who do have to file are
able to use short cuts described above (i.e., simplifying assumptions).
Thus, the proposed rule would be less burdensome economically and
reduce the frequency of document preparation for market-based rate
authority retention for qualified smaller utilities.
XIII. Comment Procedures
    223. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due August 7, 2006. Reply comments
are due September 6, 2006. Comments and reply comments must refer to
Docket No. RM04-7-000, and must include the commenter's name, the
organization they represent, if applicable, and their address in their
comments. Comments and reply comments may be filed either in electronic
or paper format.
    224. Comments and reply comments may be filed electronically via
the eFiling link on the Commission's Web site at http://www.ferc.gov.

The Commission accepts most standard word processing formats, and
commenters may attach additional files with supporting information in
certain

other file formats. Documents created electronically using word
processing software should be filed in the native application or print-
to-PDF format and not in a scanned format. This will enhance document
retrieval for both the Commission and the public. Attachments that
exist only in paper form may be scanned. Commenters filing
electronically should not make a paper filing. Service of rulemaking
comments is not required. Commenters that are not able to file comments
and reply comments electronically must send an original and 14 copies
of their comments to: Federal Energy Regulatory Commission, Office of
the Secretary, 888 First Street, NE., Washington, DC 20426.
    225. All comments and reply comments will be placed in the
Commission's public files and may be viewed, printed, or downloaded
remotely as described in the Document Availability section below.
Commenters on this proposal are not required to serve copies of their
comments and reply comments on other commenters.
XIV. Document Availability
    226. 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 the Commission's Home Page (http://www.ferc.gov) and

in the Commission'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.
    227. From the Commission'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.
    228. User assistance is available for eLibrary and the Commission's
Web site during normal business hours. For assistance, please contact
FERC Online Support at 1-866-208-3676 (toll free) or<PHONE_NUMBER> (e-
mail at FERCOnlineSupport@FERC.gov), or the Public Reference Room at
(202) 502-8371, TTY<PHONE_NUMBER> (e-mail at
public.referenceroom@ferc.gov).

List of Subjects in 18 CFR Part 35

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

    By direction of the Commission.
Magalie R. Salas,
Secretary.
    In consideration of the foregoing, the Commission proposes to amend
part 35, Chapter I, Title 18, Code of Federal Regulations, as follows:
    1. The authority citation for part 35 continues to read as follows:

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

    2. Section 35.27 is revised as follows:

Sec.  35.27  Authority of State Commissions.

    Nothing in this part--
    (a) Shall be construed as preempting or affecting any jurisdiction
a state commission or other state authority may have under applicable
state and federal law, or
    (b) Limits the authority of a state commission in accordance with
state and federal law to establish:
    (1) Competitive procedures for the acquisition of electric energy,
including demand-side management, purchased at wholesale, or
    (2) Non-discriminatory fees for the distribution of such electric
energy to retail consumers for purposes established in accordance with
state law.
    3. Subpart H is revised to read as follows:

Subpart H--Wholesale Sales of Electric Energy, Capacity and
Ancillary Services at Market-Based Rates

Sec.
35.36 Generally.
35.37 Market power analysis required.
35.38 Mitigation.
35.39 Affiliate restrictions.
35.40 Ancillary services.
35.41 Market behavior rules.
35.42 Market-based rate tariff.
35.43 Change in status reporting requirement.
Appendix A to Subpart H--Proposed Market-Based Rate Tariff

Sec.  35.36  Generally.

    (a) For purposes of this subpart:
    (1) Seller means any person that has authorization to or seeks
authorization to engage in sales for resale of electric energy at
market-based rates under section 205 of the Federal Power Act.
    (2) Category 1 Sellers means wholesale power marketers and
wholesale power producers that own or control 500 MW or less of
generation; that do not own or control transmission facilities (or have
been granted waiver of the requirements of Order No. 888, FERC Stats. &
Regs. ] 31,036); that are not affiliated with anyone that owns or
controls transmission facilities; that are not affiliated with a public
utility with a franchised service territory; and that do not raise
other vertical market power issues.
    (3) Category 2 Sellers means any Sellers not in Category 1.
    (4) Inputs to electric power production means sites for development
of generation, fuel inputs such as coal facilities, and the
transportation or distribution of inputs to electric power production
such as gas storage, intrastate gas transportation and distribution
systems, and rail cars/barges for the transportation of coal.
    (5) Franchised public utility means a public utility with a
franchised service obligation under state law and that has captive
customers.
    (6) Non-regulated power sales affiliate means any non-traditional
power seller affiliate, including a power marketer, exempt wholesale
generator, qualifying facility or other power seller affiliate, whose
power sales are not regulated on a cost basis under the FPA.
    (b) The provisions of this subpart apply to all sellers authorized,
or seeking authorization, to make sales for resale of electric energy,
capacity or ancillary services at market-based rates unless otherwise
ordered by the Commission.

Sec.  35.37  Market power analysis required.

    (a) In addition to other requirements in subparts A and B, a Seller
must submit a market power analysis in the following circumstances:
when seeking market-based rate authority; for Category 2 Sellers, every
three years, according to the schedule contained in Order No. ----,
FERC Stats. & Regs. ] 31, ----; or any other time the Commission
directs a Seller to submit one. Failure to timely file an updated
market power analysis will constitute a violation of Seller's market-
based rate tariff.
    (b) A market power analysis must address whether a Seller has
horizontal and vertical market power.
    (c) There will be a rebuttable presumption that a Seller lacks