with a far greater number of issues'' such as complex legal issues
and financial instruments like derivatives.)
    \506\ Id.
    \507\ Id. at P 124 (citing Cleco Corp., 104 FERC 61,125 (2003)
(Cleco)).
    \508\ NOPR at P 130.
    \509\ Id. at P 131.
---------------------------------------------------------------------------

Comments
    504. Morgan Stanley comments that unaffiliated asset and energy
managers should not be treated as affiliates of owners of the managed
portfolios and that it would be overly inclusive for the Commission to
adopt a presumption of control that would treat the energy manager as a
franchised utility for purposes of the affiliate abuse rules.\510\
Financial Companies argue that the Commission should not apply the
affiliate abuse restrictions generically to all unaffiliated energy
managers that provide management services to a franchised utility or
its affiliates. Rather, the Commission should evaluate applicability of
the affiliate abuse restrictions on a case-by-case basis.\511\
---------------------------------------------------------------------------

    \510\ Morgan Stanley at 9.
    \511\ Financial Companies at 11-12.
---------------------------------------------------------------------------

    505. Allegheny claims that the Commission failed to consider the
costs to customers, which are likely to be substantial through the loss
of efficiencies by treating asset managers as affiliates.\512\
Allegheny claims that there will be higher costs because: (1) The
affiliated asset manager will need to pass added costs on to the
franchised utility; (2) if the affiliated asset manager cannot pass on
costs, it may no longer provide the service and the utility may need to
set up duplicative asset management capability, resulting in higher
costs; or (3) the franchised utility will need to hire a third-party
asset manager, presumably more expensive.\513\ Constellation makes a
similar argument about the substantial costs and reduction of
efficiencies by discouraging energy/asset management agreements.\514\
---------------------------------------------------------------------------

    \512\ Allegheny at 14-15.
    \513\ Allegheny at 15.
    \514\ Constellation at 6.
---------------------------------------------------------------------------

    506. EPSA states that it opposes the Commission's proposal to treat
asset managers as affiliates. It submits that asset managers are not
legally affiliates of the companies with which they have a contract. If
the basis for the proposal to treat asset managers as affiliates is for
transparency purposes, EPSA says that all such contracts and
transactions with asset managers are already reportable under the
change in status final rule.\515\
---------------------------------------------------------------------------

    \515\ EPSA at 28-32.
---------------------------------------------------------------------------

    507. Alliance Power Marketing argues that by imposing affiliate
abuse restrictions on entities acting on behalf of a regulated public
utility or its non-regulated affiliates, the Commission seeks to alter
the fundamental principle of responsibility and liability of the
regulated entity by making the third-party also directly accountable,
thus blurring the lines of accountability. Furthermore, a critical
element in applying affiliate abuse restrictions to entities' action on
behalf of generation owners lies in having a stake in the outcome
rather than just considering some direct or indirect control. Alliance
Power Marketing asserts that evaluating control over the outcome as the
threshold for asset managers could sweep up many entities, such as
RTOs/ISOs, governmental and cooperative entities, that could have
jurisdictional and practical ramifications.\516\
---------------------------------------------------------------------------

    \516\ Alliance Power Marketing at 17-37.
---------------------------------------------------------------------------

    508. A number of other commenters oppose the Commission's proposal
to treat unaffiliated energy/asset managers as part of the franchised
public utility. They argue that the current code of conduct already
provides the protections sought by such a proposal and the Commission
fails to explain the need for such expanded regulation.\517\
Furthermore, they submit that such proposal does not consider the
additional costs to consumers through lost efficiencies.\518\
---------------------------------------------------------------------------

    \517\ Allegheny Energy Companies at 10-16; PG&E at 14-21.
    \518\ Allegheny Energy Companies at 10-16.
---------------------------------------------------------------------------

    509. PG&E argues that the Commission proposal to consider
``entities acting on behalf of and for the benefit of [the utility/
affiliate]'' as part of the utility/affiliate itself is unnecessary and
overly broad.\519\
---------------------------------------------------------------------------

    \519\ PG&E at 14-21.
---------------------------------------------------------------------------

    510. Indianapolis P&L does not oppose the Commission's proposal to
treat asset managers as affiliates for the limited purposes of the code
of conduct, standards of conduct or inter-affiliate transaction issues,
but it states that the Commission should not treat unaffiliated asset
managers as affiliates when determining how much generating

capacity should be attributed to a generation asset owner.\520\
---------------------------------------------------------------------------

    \520\ Indianapolis P&L at 7-10.
---------------------------------------------------------------------------

    511. Financial Companies and Morgan Stanley both state in their
reply comments that the Commission should not impose affiliate
restrictions on unaffiliated energy managers, as the Commission
provides no basis for such requirement \521\ and no evidence that
energy managers can engage in cross-subsidization of unregulated
affiliates.\522\
---------------------------------------------------------------------------

    \521\ Morgan Stanley reply comments at 14.
    \522\ Financial Companies reply comments at 6.
---------------------------------------------------------------------------

Commission Determination
    512. From the various comments submitted it is apparent that our
proposal has created confusion as to our intent with regard to the
treatment of energy/asset managers under the proposed affiliate
restrictions. Accordingly, we clarify and simplify our approach, as
discussed below.
    513. The Commission is concerned that there exists the potential
for a franchised public utility with captive customers to interact with
a market-regulated power sales affiliate in ways that transfer benefits
to the affiliate and its stockholders to the detriment of the captive
customers. Therefore, the Commission has adopted certain affiliate
restrictions to protect the captive customers and, in this Final Rule,
is codifying those restrictions in our regulations. To that end, we
make clear that such utilities may not use anyone, including energy/
asset managers, to circumvent the affiliate restrictions (e.g.,
independent functioning and information sharing prohibitions).
Accordingly, we adopt and codify in our regulations at Sec.
35.39(c)(1) and 35.39(g) an explicit prohibition on using third-party
entities to circumvent otherwise applicable affiliate restrictions.
    514. We note that energy/asset managers provide a variety of
services for franchised public utilities and market-regulated power
sales affiliates, including, but not limited to, operating generation
plants (sometimes under tolling agreements), acting as billing agents,
bundling transmission and power for customers, and scheduling
transactions. However, regardless of the relationships and duties of an
energy/asset manager to a franchised public utility or its non-
regulated affiliate, the energy/asset manager may not act as a conduit
to circumvent the affiliate restrictions.\523\
---------------------------------------------------------------------------

    \523\ The Commission is adopting 18 CFR 35.39(g) which prohibits
a franchised public utility with captive customers and a market-
regulated power sales affiliate from using anyone as a conduit to
circumvent any of the affiliate restrictions, including the
affiliate sales restriction and the information sharing provision.
---------------------------------------------------------------------------

    515. This approach is consistent with past Commission orders that
have identified the potential that affiliated exempt wholesale
generators or qualifying facilities could serve as a conduit for
providing below-cost services to an affiliated power marketer at the
expense of captive customers of the public utility operating companies
and imposed restrictions to prevent this.\524\
---------------------------------------------------------------------------

    \524\ Southern Company Services, Inc., 72 FERC ] 61,324 at
62,408 (1995).
---------------------------------------------------------------------------

    516. Although several commenters assert that the costs of asset
management will increase as a result of requiring asset managers to
observe the affiliate restrictions, they did not provide any examples
of why the costs would increase. The Commission notes that under this
Final Rule, all asset managers are not required to observe the
affiliate restrictions, only those asset managers which control or
market generation of the franchised public utility with captive
customers or a market-regulated power sales affiliate of a franchised
public utility with captive customers. In those instances, the need to
protect captive customers outweighs any generalized assertions of
increased cost.
    517. We note that to the extent that a franchised public utility
with captive customers and one or more of its non-regulated marketing
affiliates obtains the services of the same energy/asset manager, such
an arrangement would create opportunities to harm captive customers
depending on how the energy/asset manager is structured. For example,
without internal separation between the energy/asset managers'
regulated and non-regulated businesses, there would exist opportunities
to harm captive customers.
g. Cooperatives
Comments
    518. Suez/Chevron asks the Commission to clarify that
jurisdictional utilities organized as cooperatives are not exempt from
the affiliate abuse rules and that all jurisdictional public utilities
with captive customers, including utilities organized as cooperatives,
must comply with the affiliate abuse rules.\525\
---------------------------------------------------------------------------

    \525\ Suez/Chevron at 10-12.
---------------------------------------------------------------------------

    519. El Paso E&P argues that it would appear that the proposed
affiliate restrictions would apply to power sales at market-based rates
made by G&T cooperatives to their State-regulated member distribution
cooperatives. It states that based on the definition of a ``franchised
public utility'' as ``a public utility with a franchised service
obligation under State law and that has captive customers,''
distribution cooperatives that are granted franchised service
territories by State regulatory agencies would be included in this
definition. El Paso E&P asserts that a G&T cooperative with authority
to sell power at market-based rates would be defined as a non-regulated
power seller and, accordingly, sales made by a G&T cooperative at
market-based rates to its affiliated member distribution cooperatives
would, under the proposed regulations, be required to comply with the
requirements of the rule. \526\
---------------------------------------------------------------------------

    \526\ El Paso E&P at 4-9.
---------------------------------------------------------------------------

    520. However, El Paso E&P argues that the Commission has previously
stated that affiliate abuse is not a concern for cooperatives owned by
other cooperatives because the cooperatives' ratepayers are its
members. El Paso E&P alleges that the Commission has never sufficiently
explained the basis for its prior statements. According to El Paso E&P,
the Commission's prior statements are based on the findings in Hinson
Power \527\ that lack of concern with the potential for affiliate abuse
is premised on the absence of captive customers that would be subject
to the exercise of market power. El Paso submits that the fact that
ratepayers of the distribution cooperative are also members of such
cooperatives should not alleviate the Commission's concern about
potential affiliate abuse issues. El Paso E&P claims that industrial
customers of distribution cooperatives with franchised service
territories are captive to service from the generation and transmission
and distribution cooperatives that serve them and are in need of
protection from the Commission to ensure that they are charged just and
reasonable rates.\528\
---------------------------------------------------------------------------

    \527\ Hinson Power Company, 72 FERC ] 61,190 (1995).
    \528\ El Paso E&P at 4-9.
---------------------------------------------------------------------------

    521. NRECA submits that El Paso misreads the proposed regulations
by classifying distribution cooperatives as a ``public utility Seller''
under the proposed regulations and NRECA comments that it is not aware
of any distribution cooperatives that would be classified as ``public
utility Sellers'' thus triggering the restriction on affiliate sales
without first receiving Commission approval. NRECA states that nearly
all distribution cooperatives are not regulated as public utilities
under the FPA because they either have Rural Electrification Act (REA)
financing or sell less than 4 million

MWh per year and thus do not qualify as a ``public utility'' under
section 201(f) of the FPA. Furthermore, NRECA comments that very few
distribution cooperatives sell any electricity for resale. Thus, they
would not need to obtain market-based rate authority under section 205
even if they were not relieved of that obligation by section
201(f).\529\ NRECA also comments that the Commission has explained the
reasoning behind not requiring cooperatives to comply with the
affiliate abuse requirements by stating that ``in the case of a
cooperative, the cooperative's members are both the ratepayers and the
shareholders, and thus there is no potential danger of shifting
benefits from one to another.'' \530\
---------------------------------------------------------------------------

    \529\ NRECA supplemental reply comments at 5-6.
    \530\ NRECA supplemental reply comments at 9.
---------------------------------------------------------------------------

    522. El Paso E&P responds that NRECA incorrectly interprets the
scope of the proposed affiliate restriction and that NRECA ignores the
definition of ``franchised public utility'' as ``a public utility with
a franchised service obligation under State law and that has captive
customers.'' El Paso E&P submits that this definition clearly includes
distribution cooperatives. El Paso E&P further replies that the fact
that distribution cooperatives are not ``public utilities'' regulated
by the Commission is irrelevant because the Commission is not proposing
to regulate sales by such distribution cooperatives. Rather, it is
proposing to regulate wholesale sales by the generation and
transmission cooperatives to their member distribution cooperatives.
Therefore, El Paso E&P argues, the Commission should clarify the
regulations to ensure that generation and transmission cooperatives are
covered under the affiliate restrictions.\531\
---------------------------------------------------------------------------

    \531\ El Paso E&P answer to reply comments at 2-3.
---------------------------------------------------------------------------

    523. El Paso E&P also responds that NRECA's attempt to divorce a
generation and transmission cooperative's market-based rate sales to
its distribution cooperative members from the distribution
cooperative's sales to captive customers ignores the cooperative
structure. It states that a generation and transmission cooperative is
comprised of its member distribution cooperatives and both the
generation and transmission and distribution cooperatives act in
concert in connection with sales to industrial customers.\532\ El Paso
E&P also submits that NRECA's argument suggests that the Commission has
no jurisdiction over sales to State-regulated franchised public
utilities that are not cooperatives.\533\ According to El Paso E&P, the
captive customers of distribution cooperatives are in need of the same
protection from the Commission notwithstanding that the distribution
cooperatives are regulated by the states.\534\
---------------------------------------------------------------------------

    \532\ Id. at 3.
    \533\ Id.
    \534\ Id. at 4.
---------------------------------------------------------------------------

    524. El Paso E&P also states that wholesale electric sales approved
by the Commission must be passed through at the retail level. Thus, El
Paso E&P states that it is not sufficient to suggest that the
Commission need not be concerned because the distribution cooperatives'
rates are subject to State regulation.\535\ Finally, El Paso E&P
responds that NRECA cannot seek the protection of this Commission when
its members are purchasers of power, and then claim its members should
be exempt from scrutiny when they are sellers to captive customers such
as El Paso E&P. It asserts that captive customers of generation and
transmission and their member distribution cooperatives are in need of
protection.\536\
---------------------------------------------------------------------------

    \535\ Id.
    \536\ Id. at 5.
---------------------------------------------------------------------------

Commission Determination
    525. FPA section 201(f) specifically exempts from the Commission's
regulation under Part II of the FPA, except as specifically provided,
electric cooperatives that receive REA financing or sell less than 4
million megawatt hours of electricity per year.\537\ Thus, such
electric cooperatives are not considered public utilities under the FPA
and our market-based rate regulations do not apply to those electric
cooperatives. Further, with respect to distribution-only cooperatives,
they either do not meet the ``public utility'' definition because they
do not own or operate facilities used for wholesale sales or
transmission in interstate commerce or, if they do own or operate such
facilities, they are exempted from Part II regulation by virtue of FPA
section 201(f). In this regard, we note that NRECA states that it is
unaware of any distribution cooperatives in the United States that
would be ``public utility Sellers'' under the proposed
regulations.\538\ Such a cooperative would not be subject to the
affiliate restrictions in the proposed regulations at Sec.  35.39.
---------------------------------------------------------------------------

    \537\ 16 U.S.C. 824(e)-(f) (2006).
    \538\ NRECA reply comments at 5.
---------------------------------------------------------------------------

    526. For electric cooperatives that are public utility sellers and
not exempted from public utility regulation by FPA section 201(f), as
discussed above, the Commission will continue to treat such electric
cooperatives as not subject to the Commission's affiliate abuse
restrictions, based on a finding that transactions of an electric
cooperative with its members do not present dangers of affiliate abuse
through self-dealing. Even if an electric cooperative is not
statutorily exempted from our regulation under Part II of the FPA, we
conclude that a waiver of Sec.  35.39 is appropriate. As the Commission
has previously explained, ``affiliate abuse takes place when the
affiliated public utility and the affiliated power marketer transact in
ways that result in a transfer of benefits from the affiliated public
utility (and its ratepayers) to the affiliated power marketer (and its
shareholders).'' \539\ However, as the Commission has previously stated
in many market-based rate orders over the years,\540\ where a
cooperative is involved, the cooperative's members are both the
ratepayers and the shareholders. Any profits earned by the cooperative
will enure to the benefit of the cooperative's ratepayers. Therefore,
we have found that there is no potential danger of shifting benefits
from the ratepayers to the shareholders.\541\
---------------------------------------------------------------------------

    \539\ Heartland Energy Services, Inc., 68 FERC ] 61,223 at
62,062 (1994).
    \540\ Hinson Power Company, 72 FERC ] 61,190 (1995). See also,
e.g., People's Electric Corp., 84 FERC ] 61,215 at 62,042 (1998)
(application raised no issues of affiliate abuse because the seller
was operated by a cooperative whose ratepayers were also its
owners); Old Dominion Electric Cooperative, 81 FERC ] 61,044 at
61,236 (1997).
    \541\ Old Dominion Electric Cooperative, 81 FERC ] 61,044 at
61,236 (1997).
---------------------------------------------------------------------------

    527. Finally, we agree with NRECA's argument that the issue that El
Paso E&P discusses in its comments is not a concern that can be
addressed through affiliate restrictions in market-based rates, but is
rather more of a concern of discrimination in the allocation of
benefits and burdens among retail ratepayers. The Commission does not
possess jurisdiction to review a distribution cooperative's retail
rates; that issue falls under State law. Moreover, El Paso E&P's
argument that wholesale electric sales approved by the Commission must
be passed through at the retail level is misplaced. As the courts have
previously held, State commissions are not precluded from reviewing the
prudence of a company's purchasing decisions, and may disallow pass-
through of wholesale purchase costs unless the purchaser had no legal
right to refuse to make a particular purchase.\542\
---------------------------------------------------------------------------

    \542\ Arkansas Power & Light Co. v. Missouri Public Service
Commission, 829 F.2d 1444 at 1451-52 (8th Cir. 1987). See also Pike
County Light & Power v. Pennsylvania Public Utility Commission, 465
A.2d 735 at 737-78 (1983); Nantahala Power & Light Co. v. Thornburg,
476 U.S. 953 at 965-67 (1986); Mississippi Power & Light Co. v.
Mississippi ex rel. Moore, 487 U.S. 354 at 369 (1988).

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

    528. Therefore, for the reasons stated above, the Commission will
continue to follow its current precedent and find that electric
cooperatives that are public utility sellers and not exempted from
public utility regulation by FPA Sec.  201(f) are not subject to the
Commission's affiliate abuse requirements.
2. Power Sales Restrictions
Commission Proposal
    529. In the NOPR the Commission proposed to continue the policy of
reviewing power sales transactions between regulated and ``non-
regulated'' affiliates under section 205 of the FPA. This policy means,
among other things, that a general grant of market-based rate authority
does not apply to affiliate sales between a regulated and a non-
regulated affiliate, absent express authorization by the Commission.
    530. The Commission proposed to amend the regulations to include a
provision expressly prohibiting power sales between a franchised public
utility \543\ and any of its non-regulated power sales affiliates
without first receiving authorization for the transaction under section
205 of the FPA.
---------------------------------------------------------------------------

    \543\ As proposed in the NOPR, the term ``franchised public
utility'' was defined as ``a public utility with a franchised
service obligation under state law and that has captive customers.''
As set forth below, to avoid confusion between references to a
franchised public utility with captive customers and one without, we
revise the proposed regulations to delete the reference to customers
in the definition and to specifically use the term ``franchised
public utility with captive customers'' to clarify when the
affiliate restrictions apply.
---------------------------------------------------------------------------

    531. Additionally, although it did not propose to codify the
requirement in the regulatory text, the Commission proposed that
sellers seeking authorization to engage in affiliate transactions will
continue to be obligated to provide evidence as to whether there are
captive customers that would trigger the application of the affiliate
restrictions. The Commission stated that if the Commission finds, based
on the evidence provided by the seller, that the seller has no captive
customers, the affiliate restrictions in the regulations would not
apply.
    532. The Commission proposed to continue its prior approach for
determining what types of affiliate sales transactions are permissible
and the criteria that should be used to make those decisions, including
evaluation of the Allegheny and Edgar criteria.\544\ Although it did
not propose to codify a safe harbor provision in the regulations, the
Commission noted that when affiliates participate in a competitive
solicitation process, application of the Allegheny criteria would
constitute a safe harbor that affiliate abuse conditions are satisfied
in a transaction between a franchised public utility and its
affiliates. The Commission emphasized, however, that using a
competitive solicitation is not the only way to address concerns that
an affiliate transaction does not pose undue preference concerns.\545\
---------------------------------------------------------------------------

    \544\ Boston Edison Company Re: Edgar Electric Energy Co., 55
FERC ] 61,382 (1991) (Edgar), describing three types of evidence
that can be used to show that an affiliate power sales transaction
is above suspicion ensuring that the market is not distorted and
captive ratepayers are protected: (1) Evidence of direct head-to-
head competition between the affiliate and competing unaffiliated
suppliers in a formal solicitation or informal negotiation process;
(2) evidence of the prices non-affiliated buyers were willing to pay
for similar services from the affiliate; or (3) benchmark evidence
that shows the prices, terms, and conditions of sales made by non-
affiliated sellers. Allegheny Energy Supply Company, LLC, 108 FERC ]
61,082 (2004) (Allegheny), stating four guidelines that help the
Commission determine if a competitive solicitation process satisfies
the Edgar criteria: (1) It is transparent; (2) products are well
defined; (3) bids are evaluated comparably with no advantage to
affiliates; and (4) it is designed and evaluated by an independent
entity.
    \545\ Although our focus and discussion in this rule is
affiliate abuse with respect to affiliates that sell at market-based
rates, affiliate concerns also arise with respect to affiliate sales
at cost-based rates. See, e.g., Duke Energy Corp. and Cinergy Corp.,
113 FERC ] 61,297 at P 113-116 (2005), reh'g denied, 118 FERC ]
61,077 (2007).
---------------------------------------------------------------------------

    533. The Commission said it continues 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. The Commission proposed 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 \546\ for
eligibility for use in jurisdictional tariffs. The Commission sought
comment on whether evidence other than competitive solicitations, RTO
price or non-RTO price indices, or benchmarks described in the NOPR
should be accepted in an application for authority to engage in market-
based affiliate power sales. In addition, the Commission proposed to
consider two merging partners as affiliates as of the date a merger is
announced, and sought comments on this proposal (or whether to use the
date the Sec.  203 application is filed with the Commission, or another
time). The Commission also proposed that unaffiliated entities that
engage in energy/asset management of generation on behalf of a
franchised public utility or non-regulated utility be bound to comply
with the same affiliate restrictions as those imposed on the franchised
public utility and the non-regulated power sales affiliate.
---------------------------------------------------------------------------

    \546\ Order Regarding Future Monitoring of Voluntary Price
Formation, Use of Price Indices In Jurisdictional Tariffs, and
Closing Certain Tariff Dockets, 109 FERC ] 61,184 (2004) (November
19 Price Index Order).
---------------------------------------------------------------------------

    534. The Commission said it continues 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. The Commission proposed 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 \547\ for
eligibility for use in jurisdictional tariffs. The Commission sought
comment on whether evidence other than competitive solicitations, RTO
price or non-RTO price indices, or benchmarks described in the NOPR
should be accepted in an application for authority to engage in market-
based affiliate power sales. In addition, the Commission proposed to
consider two merging partners as affiliates as of the date a merger is
announced, and sought comments on this proposal (or whether to use the
date the Sec.  203 application is filed with the Commission, or another
time). The Commission also proposed that unaffiliated entities that
engage in energy/asset management of generation on behalf of a
franchised public utility or non-regulated utility be bound to comply
with the same affiliate restrictions as those imposed on the franchised
public utility and the non-regulated power sales affiliate.
---------------------------------------------------------------------------

    \547\ Id.
---------------------------------------------------------------------------

Comments
    535. Industrial Customers urge the Commission to recognize that
when an affiliate transaction has been subject to a State-approved
process, separate section 205 approvals for such transactions should
not be required. If, however, the Commission does maintain the section
205 approval, ``the imprimatur of State commission approval should
create a rebuttable presumption that the transaction is just and
reasonable.'' \548\ NASUCA comments that the Commission should not
assume the reasonableness of all affiliate sales under contracts with

prices linked to spot markets or other auction results.\549\
---------------------------------------------------------------------------

    \548\ Industrial Customers at 16-18.
    \549\ NASUCA at 20-29.
---------------------------------------------------------------------------

    536. Other commenters urge the Commission to clarify that, while
requests for proposals consistent with the Allegheny and Edgar
standards and affiliate sales based on market index prices constitute a
safe harbor for affiliate abuse, those should not be the only safe
harbors.\550\ The Commission should state it is willing to consider
other information and evidence, including affiliate sales reviewed and
authorized by a State regulatory agency, as safe harbors as well.\551\
---------------------------------------------------------------------------

    \550\ Indianapolis P&L at 7-10.
    \551\ FirstEnergy at 12-27.
---------------------------------------------------------------------------

    537. New Jersey Board disagrees with comments that the Commission
should consider State approval of affiliate sales as a safe harbor and
responds that the Commission should assure that affiliate abuse does
not take place and not ignore affiliate sales based on actions and
oversight by State commissions.\552\
---------------------------------------------------------------------------

    \552\ New Jersey Board reply comments at 6.
---------------------------------------------------------------------------

    538. State AGs and Advocates oppose the Commission's proposal to
find affiliate sales of wholesale power just and reasonable if such
sales are made through an auction that reflects certain guidelines such
as those set forth in Edgar and Allegheny. Instead, State AGs and
Consumer Advocates state that the Commission should develop behavioral
market power tests that apply to all market structures and that each
auction should be assessed separately and evaluated on the merits of
the proposal.\553\
---------------------------------------------------------------------------

    \553\ State AGs and Advocates reply comments at 12-13.
---------------------------------------------------------------------------

    539. Industrial Customers oppose the Commission's proposal to rely
on an RTO/ISO benchmark price or index to mitigate affiliate abuse
concerns and argues that tying an affiliate transaction to a price
index should not allow utilities to escape scrutiny.\554\
---------------------------------------------------------------------------

    \554\ Industrial Customers at 16-18.
---------------------------------------------------------------------------

Commission Determination
    540. The Commission adopts the proposal to continue its approach
for determining what types of affiliate transactions are permissible
and the criteria used to make those decisions. Although we are not
codifying a safe harbor in our regulations, when affiliates participate
in a competitive solicitation process for power sales, we will consider
proper application of the Allegheny guidelines to constitute a safe
harbor that the affiliate abuse concerns are satisfied in a transaction
between a franchised public utility with captive customers and its non-
regulated power sales affiliate. The Commission will consider proposed
competitive solicitations on a case-by-case basis. We again emphasize
that using a competitive solicitation by applying the Allegheny and
Edgar guidelines is not the only way an affiliate transaction can
address our concerns that the transaction does not pose undue
preference concerns. We will consider other approaches on a case-by-
case basis. Also, to the extent a seller is not bound by the affiliate
restrictions because neither the seller nor the buyer has captive
customers, we find that the Edgar principles do not apply and the
seller does not need to make a filing with regard to a proposed
competitive solicitation.\555\
---------------------------------------------------------------------------

    \555\ Southern California Edison Co., 109 FERC ] 61,086 at P 35
(2004) (noting that Commission's concern in cases involving sales to
affiliates has been the potential for cross-subsidization at the
expense of the public utility's captive customers).
---------------------------------------------------------------------------

    541. A number of commenters urge the Commission to find that a
State-approved solicitation process creates a rebuttable presumption
that an affiliate transaction satisfies the Commission's affiliate
abuse concerns. The Commission will consider a State-approved process
as evidence in its consideration as to whether our affiliate abuse
concerns have been adequately addressed, but the Commission will not
treat a State-approved process as creating a rebuttable presumption
that our affiliate abuse concerns have been addressed. In this regard,
the Commission has a responsibility under section 205 of the FPA to
ensure that all jurisdictional rates charged are just and reasonable
and not unduly discriminatory or preferential. While a State-approved
solicitation process may provide evidence that the wholesale rates
proposed as a result of that process are just and reasonable and do not
involve any undue discrimination or preference, we do not believe it is
appropriate to create a rebuttable presumption.
    542. Further, the Commission will continue to allow an established,
relevant market price or index such as in an RTO or ISO to be used as a
benchmark for the reasonableness of the price of an affiliate
transaction. In this regard, we disagree with commenters that relying
on such prices or indices allows utilities to escape Commission
scrutiny. Such an index 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).\556\ The Commission previously stated 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.\557\
---------------------------------------------------------------------------

    \556\ Brownsville, 111 FERC ] 61,398 at P 10 (2005). See also
Portland General Elec. Co., 96 FERC ] 61,093 at 61,378 (2001);
FirstEnergy Trading, 88 FERC ] 61,067 at 61,156 (1999).
    \557\ April 14 Order, 107 FERC ] 61,018 at P 189.
---------------------------------------------------------------------------

    543. In addition, while the Commission has found in the past that
certain non-RTO price indices are acceptable indicators of market
prices, we continue to 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 \558\ and November 19 Price Index Order. Therefore, the
Commission will 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 and
reflects the market price where the affiliate transaction occurs (i.e.,
is a relevant index).\559\
---------------------------------------------------------------------------

    \558\ Policy Statement on Natural Gas and Electric Price
Indices, 104 FERC ] 61,121 (2003) (Price Index Policy Statement).
    \559\ November 19 Price Index Order, 109 FERC ] 61,184 at P 40-
69.
---------------------------------------------------------------------------

3. Market-Based Rate Affiliate Restrictions (Formerly Code of Conduct)
for Affiliate Transactions Involving Power Sales and Brokering, Non-
Power Goods and Services and Information Sharing
Commission Proposal
    544. The Commission stated in the NOPR that it continues to believe
that a code of conduct is necessary to protect captive customers from
the potential for affiliate abuse. In light of the repeal of the Public
Utility Holding Company Act of 1935 \560\ 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,
the Commission stated that it is important to have in place
restrictions that preclude transferring captive customer benefits to
stockholders through a company's non-regulated power sales business.
Therefore, the Commission stated its belief that 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 and services
between power sales affiliates. In addition, the Commission stated that
greater uniformity and consistency in the codes of conduct is
appropriate and, therefore, proposed 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. The Commission proposed to codify such affiliate restrictions
in the regulations and to require that, as a condition of receiving
market-based rate authority, franchised public utility sellers with
captive customers comply with these restrictions. The Commission
proposed that the failure to satisfy the conditions set forth in the
affiliate restrictions will constitute a tariff violation.
---------------------------------------------------------------------------

    \560\ Repeal of the Public Utility Holding Company Act of 1935
and Enactment of the Public Utility Holding Company Act of 2005,
Order No. 667, 70 FR 75592 (Dec. 20, 2005), FERC Stats. & Regs.
Regulations Preambles 2001-2005 ] 31,197 (2005).
---------------------------------------------------------------------------

    545. The Commission sought comments on this proposal and on whether
the specific affiliate restrictions proposed in the NOPR are sufficient
to protect captive customers. In particular, the Commission sought
comments on what changes, if any, should be adopted.
a. Uniform Code of Conduct/Affiliate Restrictions--Generally
Comments
    546. Some commenters support codifying the code of conduct
affiliate restrictions in the regulations and comment that it will lead
to consistent codes of conduct across all sellers, thus creating
greater transparency, and will aid the Commission's enforcement
efforts.\561\ ELCON argues that the ability of large utility holding
companies with one foot in ``competition'' and one foot in
``regulation'' creates a myriad of potential problems.\562\ Several
State agencies and consumer commenters generally support the proposal
to codify uniform code of conduct restrictions in the Commission's
regulations.\563\ NASUCA comments that the separation of function
requirements should apply to any affiliate with retail customers, not
just to affiliates who are franchised public utilities.\564\
---------------------------------------------------------------------------

    \561\ ELCON and EPSA support codifying a uniform code of
conduct. ELCON at 2 and EPSA at 28.
    \562\ ELCON at 3.
    \563\ Id. at 6-10, New Jersey Board at 2, and NRECA at 11.
    \564\ NASUCA at 20-29.
---------------------------------------------------------------------------

    547. FP&L, however, does not believe it is unduly preferential to
have different codes of conduct.\565\ Indianapolis P&L argues that a
single tariff/code of conduct does not make sense for diversified
energy companies with geographically widespread operations.\566\
---------------------------------------------------------------------------

    \565\ FP&L at 3.
    \566\ Indianapolis P&L at 12.
---------------------------------------------------------------------------

    548. FP&L states that the Commission should include in the
regulatory text the statement that the affiliate restrictions are
waived where a seller demonstrates that there are no captive
customers.\567\ EEI states that utilities already found not to have
captive customers because of retail choice should be grandfathered and
should not have to request waiver of the code of conduct again.\568\
---------------------------------------------------------------------------

    \567\ FP&L at 5-6.
    \568\ EEI at 43; EEI reply comments at 35.
---------------------------------------------------------------------------

Commission Determination
    549. The Commission will adopt the proposed affiliate restrictions
with certain modifications and clarifications. These restrictions
govern the separation of functions, the sharing of market information,
sales of non-power goods or services, and power brokering. The
Commission will require that, as a condition of receiving and retaining
market-based rate authority, sellers comply with these affiliate
restrictions unless otherwise permitted by Commission rule or order. As
discussed herein, these affiliate restrictions govern the relationship
between franchised public utilities with captive customers and their
``market-regulated'' affiliates, i.e., affiliates whose power sales are
regulated in whole or in part on a market-based rate basis.
    550. Failure to satisfy the conditions set forth in the affiliate
restrictions will constitute a violation of the market-based rate
tariff. As discussed in greater detail below, the Commission agrees
with many of the commenters that the requirements and exceptions in the
affiliate restrictions should follow those requirements and exceptions
codified in the standards of conduct, where applicable.\569\ The
Commission believes that modeling these restrictions and the exceptions
to those restrictions on the standards of conduct will lead to greater
consistency and transparency and a greater understanding of permissible
activities.
---------------------------------------------------------------------------

    \569\ On November 17, 2006, the D.C. Circuit vacated the Order
No. 2004 standards of conduct orders as they related to natural gas
pipelines and remanded the orders to the Commission. National Fuel
Gas Supply Corporation v. FERC, 468 F.3d 831 (D.C. Cir. 2006). The
court found that the rulemaking record did not support the
Commission's attempt to extend the standards of conduct beyond
pipelines' relationships with their marketing affiliates to also
govern pipelines' relationships with numerous non-marketing
affiliates, such as producers, gatherers, and local distribution
companies (which Order No. 2004 defined as ``energy affiliates'').
In response to this decision, the Commission issued an interim rule
on January 9, 2007 reinstating those provisions of Order No. 2004
that were not specifically appealed to the D.C. Circuit. Standards
of Conduct for Transmission Providers, Order No. 690, 72 FR 2427
(Jan. 19, 2007); FERC Stats. & Regs. ] 31,237 (Jan. 9, 2007); order
on reh'g, Standards of Conduct for Transmission Providers, Order No.
690-A, 72 FR 14235 (Mar. 27, 2007); FERC Stats. & Regs. ] 31,243
(2007). On January 18, 2007, the Commission issued a Notice of
Proposed Rulemaking proposing to make the changes in the Interim
Rule permanent and seeking comment on whether the restrictions
covering relationships between electric transmission providers and
non-marketing affiliates that are engaged in energy transactions
should be retained. Standards of Conduct for Transmission Providers,
Notice of Proposed Rulemaking, 72 FR 3958 (Jan. 29, 2007), FERC
Stats. & Regs. ] 32,611 (2007).
---------------------------------------------------------------------------

    551. The Commission clarifies that any sellers that have previously
demonstrated and been found not to have captive customers, and
therefore have received a waiver of the market-based rate code of
conduct requirement in whole or in part, will not be required to
request another waiver of the associated affiliate restrictions.
However, those sellers are still under the obligation to report to the
Commission any changes in status that may affect the basis on which the
Commission relied in granting their waiver, consistent with the
requirements of Order No. 652.\570\ Additionally, those sellers also
will be required to meet the requirements necessary to maintain their
market-based rate authority when they file their regularly scheduled
updated market power analyses. As a result, they will be required to
demonstrate that they continue to lack captive customers in order to
support a continued waiver of the affiliate restrictions in the
regulations. Sellers will also need to explain why any wholesale
customers are not captive, as explained above.
---------------------------------------------------------------------------

    \570\ Reporting Requirement For Changes in Status For Public
Utilities with Market-Based Rate Authority, Order No. 652, 70 FR
8253 (Feb. 18, 2005), FERC Stats. & Regs., Regulations Preambles
January 2001-December 2005 ] 31,175, order on reh'g, Order No. 652-
A, 111 FERC ] 61,413 (2005).
---------------------------------------------------------------------------

    552. In response to FP&L and EEI, because we clarify in this Final
Rule that, where a seller demonstrates and the Commission agrees that
it has no captive customers, the affiliate restrictions will not apply,
the Commission does not believe it is necessary to include in the
regulatory text a provision stating that the affiliate restrictions are
waived where a seller demonstrates and the Commission agrees that it
has no captive customers.

b. Exceptions to the Independent Functioning Requirement
Commission Proposal Regarding Separation of Employees and Shared
Employees
    553. In the NOPR, the Commission proposed regulatory language in
Sec.  35.39(b)(2) (now Sec.  35.39(c)(2)) codifying the independent
functioning requirement. Specifically, the Commission stated, to the
maximum extent practical, the employees of a non-regulated power sales
affiliate will operate separately from the employees of any affiliated
franchised public utility.
    554. The Commission did not propose to include any exceptions to
the independent functioning requirements. However, the Commission
invited commenters to propose additions to, substitutions for or
elimination of the proposed affiliate restrictions.\571\
---------------------------------------------------------------------------

    \571\ NOPR at P 132.
---------------------------------------------------------------------------

Comments
    555. A number of commenters request that the Commission modify the
affiliate restrictions to adopt some of the requirements and exceptions
consistent with those codified in Order No. 2004, such as allowing the
sharing of senior officers and members of the board of directors, field
and maintenance employees and support employees. According to EPSA, the
affiliate restrictions should provide specifically for permissible
sharing of officers (not just sharing of support personnel) between a
franchised public utility and a non-regulated power sales affiliate.
EPSA notes that Order No. 2004 allows for shared officers as long as
they do not direct, organize or execute day-to-day business
transactions.\572\
---------------------------------------------------------------------------

    \572\ EPSA at 31.
---------------------------------------------------------------------------

    556. Duke comments that treatment of shared employees under the
affiliate restrictions should follow the obligations adopted in the
standards of conduct. For example, Duke urges the Commission to allow
the sharing of officers and directors.\573\ Additionally, Avista states
that the proposed affiliate restrictions should distinguish between
operational and non-operational employees.\574\
---------------------------------------------------------------------------

    \573\ Duke at 43. See also EPSA at 31; FirstEnergy at 26.
    \574\ Avista at 7-10.
---------------------------------------------------------------------------

    557. PG&E urges the Commission to clarify which employees cannot be
shared. PG&E states that prohibiting employees involved in general
operation of generation facilities, who lack control over generation
availability, from being shared would be overly broad and unduly
restrictive.\575\ PPL similarly requests clarification of which
employees would be deemed ``shared employees'' under the affiliate
restrictions.\576\
---------------------------------------------------------------------------

    \575\ PG&E at 14-21.
    \576\ PPL reply comments at 21-22.
---------------------------------------------------------------------------

    558. NiSource requests that the Commission create an exception to
allow the sharing between operational employees of the franchised
public utility and its non-regulated sales affiliates of any
information necessary to maintain the safe and reliable operation of
the bulk power system, similar to the exception in the standards of
conduct at Sec.  358.5(b)(8) of the Commission's regulations.\577\
---------------------------------------------------------------------------

    \577\ NiSource at 1.
---------------------------------------------------------------------------

    559. EEI and FirstEnergy also request that the independent
functioning requirement and information sharing restrictions in the
proposed affiliate restrictions should have an exception for sharing
employees and market information for emergency circumstances affecting
system reliability.\578\
---------------------------------------------------------------------------

    \578\ EEI at 44; FirstEnergy at 22.
---------------------------------------------------------------------------

    560. On the other hand, Morgan Stanley urges the Commission not to
adopt a blanket exception to the affiliate restrictions for emergency
situations because the commenters' proposal regarding what constitutes
an ``emergency'' is vague and leaves too much discretion to the
individual sellers. Additionally, Morgan Stanley explains that
communications with an affiliate during an emergency may not adequately
address an emergency; sharing information with all sellers in the
market would provide a better foundation to deal with any
emergency.\579\
---------------------------------------------------------------------------

    \579\ Morgan Stanley reply comments at 7-8.
---------------------------------------------------------------------------

Commission Determination
    561. The Commission will revise the independent functioning
requirement of the affiliate restrictions to include exceptions
relating to permissibly shared senior officers and members of boards of
directors, shared support personnel, and shared field and maintenance
personnel. With regard to permissibly shared individuals, the
Commission will impose a ``no-conduit rule'' similar to that in the
standards of conduct.\580\ Under the no conduit rule, to be codified at
Sec.  35.39(g), a permissibly shared employee is prohibited from acting
as a conduit for disclosing market information to employees, officers
or directors that are not shared.
---------------------------------------------------------------------------

    \580\ 18 CFR 358.4(a)(5) (shared senior officers and directors);
18 CFR 358.5(b)(7) (general ``no conduit'' rule covering employees).
---------------------------------------------------------------------------

    562. The Commission agrees that a franchised public utility with
captive customers and its market-regulated power sales affiliates
should be permitted to share senior officers and members of the board
of directors to conduct corporate governance functions, and to take
advantage of the efficiencies of corporate integration.\581\ Therefore,
the Commission is adopting an exception at Sec.  35.39(c)(2)(d) that
permits a franchised public utility with captive customers and its
market-regulated power sales affiliate to share senior officers and
members of the board of directors. Specifically, a franchised public
utility with captive customers and its market-regulated power sales
affiliate may share senior officers and members of boards of directors
provided that these individuals do not participate in directing,
operating or executing generation or market functions.\582\ In
addition, to prevent permissibly shared senior officers or members of
the board of directors from using their preferential access to market
information to harm captive customers, consistent with the no-conduit
rule codified at Sec.  35.39(g), the permissibly shared senior officers
and directors may not act as a conduit to provide market information to
non-shared employees of the franchised public utility with captive
customers or its market-regulated power sales affiliates.
---------------------------------------------------------------------------

    \581\ Order No. 2004-A at P 134.
    \582\ See 18 CFR 358.4(a)(5).
---------------------------------------------------------------------------

    563. The Commission also agrees that it is appropriate to codify an
exception that permits the sharing of support employees between the
franchised public utility with captive customers and its market-
regulated power sales affiliates comparable to the standards of conduct
exception, likewise subject to the no-conduit rule.\583\
---------------------------------------------------------------------------

    \583\ Order No. 2004 at P 99-101.
---------------------------------------------------------------------------

    564. The Commission rejects Duke's request that the Commission
include a non-exhaustive list of examples of permissible shared support
employees within the body of Sec.  35.39. However, we clarify that the
types of permissibly shared support employees under the standards of
conduct are the types of permissibly shared support employees that will
be allowed under the affiliate restrictions in Sec.  35.39(c)(2)(c).
Such employees include those in legal, accounting, human resources,
travel and information technology.\584\ Because permissibly shared
employees may have access to market information, they are

prohibited from acting as a conduit to provide market information to
employees of the franchised public utility with captive customers and
the market-regulated power sales affiliates that are not permitted to
be shared.
---------------------------------------------------------------------------

    \584\ Id. at P 96.
---------------------------------------------------------------------------

    565. The Commission also agrees to codify an exception to the
independent functioning requirement to allow franchised public
utilities with captive customers and their market-regulated power sales
affiliates to share field and maintenance employees. Field and
maintenance employees perform purely manual, technical or mechanical
duties that are supportive in nature and do not have planning or direct
operational responsibilities. Such employees would likely be part of
shared work crews to do repair or maintenance work on facilities or
equipment. Examples of activities that may be performed by shared field
and maintenance employees are reading meters, replacing parts in
generators, restringing transmission lines, snow removal or maintaining
roadways. The key is that these employees do not also perform
operational duties.\585\ A field or maintenance employee cannot be
shared if that employee also engages in marketing activities, makes
decisions that would affect marketing activities, or controls
generation. We also consider the immediate supervisors of field and
maintenance employees as permissibly shared employees so long as they
cannot control operations, e.g. restrict or shut down generation
facilities.\586\
---------------------------------------------------------------------------

    \585\ Id. at P 145-146.
    \586\ See id. at P 145-46. As discussed later, such actions
would be permitted in emergency circumstance affecting system
reliability.
---------------------------------------------------------------------------

    566. The Commission agrees with commenters that allowing the
sharing of field and maintenance employees between a franchised public
utility with captive customers and its market-regulated power sales
affiliates is unlikely to harm captive customers, provided that those
shared employees do not act as a conduit for sharing market information
with employees of the franchised public utility with captive customers
or market-regulated power sales affiliates. The permissibly shared
field and maintenance employees are required to observe the no-conduit
rule.
    567. The Commission disagrees with NiSource that a broad exception
to the independent functioning and information sharing requirement is
needed for the reliable operation of the bulk power system. Such an
exception would be so broad that it would swallow the rule and create
too many opportunities for shared employees to take actions to harm
captive customers based upon their decision making authority and
control over the bulk power system. The Commission will consider
requests for waiver of the affiliate restriction requirements to
address the specific circumstances of the operation of a bulk power
system and notes that, subsequent to NiSource's comments, the
Commission granted a partial waiver of the code of conduct requirements
for the situation described in NiSource's comments.\587\
---------------------------------------------------------------------------

    \587\ Northern Indiana Public Service Company and Whiting Clean
Energy, Inc., 116 FERC ] 61,248 (2006). Northern Indiana Public
Service Company (NIPSCO) sought a waiver of the code of conduct so
that it could perform its duties as a balancing authority.
Specifically, NIPSCO wanted the ability to have access to real-time
information regarding the amount of energy being delivered to NIPSCO
from its affiliate, Whiting Clean Energy, Inc., (Whiting). The
Commission granted a partial waiver limited to Whiting providing
NIPSCO with the real-time information NIPSCO needed to carry out its
responsibilities as a balancing authority in accordance with the
requirements of the North American Electric Reliability Council
(NERC), NERC approved regional reliability organization and the
Midwest Independent Transmission System Operator, Inc. Id. at P 13.
The Commission also reminded NIPSCO that its employees were
prohibited from being a conduit for improperly sharing Whiting's
generation information. Id.
---------------------------------------------------------------------------

    568. While the Commission does not agree with NiSource's proposal
for a broad exception to the affiliate restrictions for everyday
operations of the bulk power system, the Commission does agree with EEI
and FirstEnergy that the affiliate restrictions should contain an
exception related to emergency circumstances affecting system
reliability. As such, the Commission will adopt an exception to the
independent functioning requirement and the information sharing
restrictions for emergency circumstances affecting system reliability
comparable to the exception in the standards of conduct.\588\ The
exception will apply to both the independent functioning requirements
and the information sharing restrictions. The Commission will modify
proposed Sec.  35.39(d) (to be codified at Sec.  35.39(c)(2)(b)) to add
a provision that states that, notwithstanding any other restrictions in
this section, in emergency circumstances affecting system reliability,
a market-regulated power sales affiliate and the franchised public
utility with captive customers may take the necessary steps to keep the
bulk power system in operation. The relaxation of the requirements
during system emergencies is intended to ensure that the franchised
public utility with captive customers and market-regulated power sales
affiliate(s) can maintain reliability of the power grid. However, the
market-regulated power sales affiliate or the franchised public utility
must report to the Commission and disclose to the public on its Web
site each emergency that resulted in any deviation from the
restrictions of Sec.  35.39(c)(2)(b), within 24 hours of such
deviation. Reports to the Commission of emergency deviations under the
affiliate restrictions in Sec.  35.39(c)(2)(b) will be made using the
``EY'' docket prefix.
---------------------------------------------------------------------------

    \588\ 18 CFR 358.4(a)(2).
---------------------------------------------------------------------------

    569. The Commission and the public will be able to monitor the
frequency of these emergency deviations through the reporting
requirement. Members of the public can seek redress from the Commission
if they feel that the exception has been abused or used improperly.
c. Information Sharing Restrictions
Commission Proposal
    570. In the NOPR, the Commission proposed regulatory language to
codify the information sharing restrictions. Specifically, the
Commission proposed that the regulations provide that all market
information sharing between a franchised public utility and a non-
regulated power sales affiliate will be disclosed simultaneously to the
public. This includes, but is not limited to any communication
concerning power or transmission business, present or future, positive
or negative, concrete or potential.\589\
---------------------------------------------------------------------------

    \589\ See NOPR at P 121, 129.
---------------------------------------------------------------------------

Comments
    571. Ameren supports codification of the information sharing
restrictions, but recommends that proposed Sec.  35.39(c) be revised to
allow permissibly shared senior officers and directors to receive
market information so long as they do not act as a conduit to
improperly share such information, akin to the standards of conduct.
    572. Avista argues that the Commission should allow officers to be
shared by affiliates, subject to the no-conduit rule.\590\ EEI argues
that for corporate governance and accountability purposes, there should
be an exception to the information sharing prohibitions for shared
senior officers, subject to the no conduit rule.\591\
---------------------------------------------------------------------------

    \590\ Avista at 2.
    \591\ EEI at 44.
---------------------------------------------------------------------------

    573. EPSA also asks the Commission to provide a specific time
period for the length of time that posted information needs to remain
on the Web site.\592 \
---------------------------------------------------------------------------

    \592\ EPSA at 31-32.
---------------------------------------------------------------------------

    574. PPL comments that the Commission should clarify which
situations would permit deviations from the code of conduct regarding

information sharing. Specifically, it suggests that the Commission
adopt, for the affiliate restrictions, the standards of conduct
exception that permits the sharing of information to comply with
Nuclear Regulatory Commission (NRC) requirements.\593\
---------------------------------------------------------------------------

    \593\ PPL reply comments at 21-22 citing Interpretive Order
Relating to the Standards of Conduct, 114 FERC ] 61,155 (2006),
order on request for additional clarification, 115 FERC ] 61,202
(2006).
---------------------------------------------------------------------------

    575. A number of commenters argue that the Commission should not
adopt the two-way information sharing prohibition in the uniform code
of conduct because they disagree that a communication from the non-
regulated power sales affiliate to the franchised public utility could
potentially harm captive customers.\594 \
---------------------------------------------------------------------------

    \594\ Allegheny Energy Companies' Comments at 3; Duke at 37-40;
PG&E at 20, FirstEnergy at 23 and FP&L at 4.
---------------------------------------------------------------------------

    576. Duke notes that while the two-way restriction is consistent
with the default code of conduct that the Commission has used since
1999, the Commission has approved many codes of conduct that contain
one-way restrictions (i.e., codes that restrict a franchised public
utility from sharing marketing information with its non-regulated power
sales affiliates, but do not place a similar restriction on a non-
regulated power marketer from sharing market information with its
affiliated franchised utility). Duke says the Commission has failed to
explain the elimination of previously-approved one-way
restrictions.\595\ It submits that the one-way code of conduct is
sufficient to address affiliate abuse concerns and that the two-way
code of conduct requirement will impose substantial costs on market-
based rate sellers with no discernible benefits.\596\ According to
Duke, a number of market participants have made important
organizational and commercial decisions based on current policies and
precedents allowing one-way communications. In the absence of any basis
for reversing that policy, Duke submits that the Commission should
reconsider its proposal to mandate two-way information sharing
restrictions.
---------------------------------------------------------------------------

    \595\ Duke at 38.
    \596\ Duke reply comments at 20-21.
---------------------------------------------------------------------------

    577. In addition, Duke argues that only two commenters, EPSA and
ELCON, expressed even generalized support for a standardized code of
conduct containing the two-way code restriction, but did not address
the underlying policy issues of why or how a traditional utility's
regulated customers could be harmed if their unregulated affiliate were
to share market information with the utility.\597 \
---------------------------------------------------------------------------

    \597\ Id. at 20.
---------------------------------------------------------------------------

    578. According to FP&L, the proposed two-way information sharing
restriction does not provide any additional protection for captive
customers. Rather, such a restriction may place artificial and
unnecessary barriers on a company's ability to conduct business.\598\
According to FP&L, the two-way restriction proposed in Sec.  35.39(c)
(to be codified at Sec.  35.39(d)) concerning the communication of all
market information between a franchised public utility and its non-
regulated power sales affiliates is unnecessary if sales of capacity
and energy between those entities are prohibited under the specific
terms of the market-based rate tariff. It submits that, if the
Commission nevertheless concludes that a two-way restriction on
communications should be adopted, then the final regulations should
provide an exception if, in the market-based rate tariff, the non-
regulated power sales affiliates have restricted sales to, and
purchases from, their franchised public utility affiliate without
having received advance Commission approval pursuant to a separate
filing under section 205 of the FPA.\599 \
---------------------------------------------------------------------------

    \598\ FP&L at 4.
    \599\ Id. at 4-5.
---------------------------------------------------------------------------

    579. Similarly, EEI argues that the Commission has not explained
how the two-way information sharing prohibition protects captive
customers.\600 \
---------------------------------------------------------------------------

    \600\ EEI at 45.
---------------------------------------------------------------------------

Commission Determination
    580. The Commission will revise the information sharing
prohibitions to adopt certain exceptions. As discussed earlier with
regard to the independent functioning requirement, we are creating
exceptions to permit shared senior officers and members of a board of
directors, as well as to permit shared field and maintenance employees.
Permissibly shared employees may share all types of market information.
However, the information sharing provision, like all the affiliate
restrictions, is subject to the ``no-conduit'' rule that we codify in
the regulations. The no-conduit rule allows permissibly shared
employees to receive market information so long as they are not
conduits for sharing that information with employees that are not
permissibly shared. In addition, as also discussed earlier in the
independent functioning section, market information may be shared to
address emergency circumstances affecting system reliability in order
to keep the bulk power system in operation, provided that the
subsequent reporting provisions are followed.
    581. In response to PPL Companies' concern as to communications
relating to nuclear power plants, the Commission clarifies that the
types of communications permitted under the standards of conduct for
nuclear safety and regulatory requirements are also permitted under the
affiliate restrictions.\601\ Specifically, the Commission permitted
transmission providers to communicate with affiliated and nonaffiliated
nuclear power plants to enable the nuclear power plants to comply with
the requirements of the NRC as described in the NRC's February 1, 2006
Generic Letter 2006-002, Grid Reliability and the Impact on Plant Risk
and the Operability of Offsite Power.\602\
---------------------------------------------------------------------------

    \601\ Interpretive Order Relating to the Standards of Conduct,
114 FERC ] 61,155 (2006), order on request for additional
clarification, 115 FERC ] 61,202 (2006).
    \602\ Nuclear Regulatory Commission's Generic Letter 2006-002,
Grid Reliability and the Impact on Plant Risk and the Operability of
Offsite Power. February 1, 2006. OMB Control No.: 3150-0011.
Transmission providers may share with affiliates information to
operate and maintain the transmission system and information
required to maintain interconnected facilities. However,
transmission providers may not share transmission or marketing
information that would give a transmission provider's marketing or
energy affiliates undue preference over a transmission provider's
non-affiliated customers in energy markets. 114 FERC ] 61,155
(2006).
---------------------------------------------------------------------------

    582. In response to EPSA's request regarding the specific time
period that posted material needs to remain on the Web site, the
Commission concludes that it is appropriate to use the requirements set
forth regarding OASIS postings in 18 CFR 37.7(b). Specifically, the
material must be posted for 90 days and then be retained and made
available upon request for download for five years from the date when
first posted. The archived material must be available in the same
electronic form used as when it was originally posted.
    583. The Commission will adopt the two-way information sharing
restriction in proposed Sec.  35.39(c) (now Sec.  35.39(d)). The
purpose of the affiliate restrictions in Sec.  35.39 is to ensure that
franchised public utility sellers with captive customers will not be
able to engage in affiliate abuse to the detriment of those captive
customers. One way the Commission achieves this is by restricting the
sharing of information between a franchised public utility with captive
customers and a market-regulated power sales affiliate. The Commission
has long required a seller

to address any potential affiliate abuse concerns before receiving
Commission authorization to sell at market-based rates. The Commission
has previously held that ``[t]here are many ways for the affiliated
public utility and the affiliated power marketer to exchange
information that would exacerbate affiliate abuse concerns.'' \603\
Therefore, the Commission required that the sellers ``ensure that
market information is not shared among affiliates.'' \604\
---------------------------------------------------------------------------

    \603\ Heartland Energy Services, Inc., 68 FERC ] 61,223 (1994).
    \604\ Id.
---------------------------------------------------------------------------

    584. The Commission later reaffirmed this in stating the general
standards under which it reviews applications for market-based rate
authority, including a demonstration by an affiliate that ``there are
adequate procedures in place to ensure that market information is not
shared between it and the affiliate public utility.'' \605\
---------------------------------------------------------------------------

    \605\ LG&E Power Marketing, Inc., 68 FERC ] 61,247 (1994).
---------------------------------------------------------------------------

    585. With regard to Duke's suggestion that we have failed to
explain the elimination of the one-way restriction, we will provide the
following example of our concern in this regard.
    586. One example of how of improper sharing of information could
harm captive customers is a circumstance where both a franchised public
utility and its market-regulated power sales affiliate are considering
whether to bid into an RFP to provide power. If the market-regulated
power sales affiliate has absolute freedom to inform its franchised
public utility affiliate that it intends to bid into the RFP, including
but not limited to the price and quantity it intends to offer, the
franchised public utility affiliate has the ability and incentive to
use that information to benefit its stockholders at the expense of its
captive customers (e.g., by either not bidding into the RFP or doing so
at a price above that of its affiliate).
    587. While we recognize that some sellers may need to adjust their
activities to comply with the two-way information restriction, we do
not believe that such adjustments will impose significant costs upon
those sellers. Furthermore, as explained above, we believe that the
two-way information sharing restriction will provide captive customers
a more complete protection from affiliate abuse. We find that any
potential cost to sellers is outweighed by the increased protection a
two-way information sharing restriction provides to captive customers.
    588. Therefore, to ensure that all captive customers are protected
from the potential for affiliate abuse, the Commission will adopt the
proposed two-way information restriction in Sec.  35.39(d). Any sellers
whose activities are currently governed by a code of conduct with a
one-way information restriction will be deemed to have adopted a two-
way information restriction as of the effective date of this Final
Rule.
    589. The Commission restates that the affiliate restrictions only
apply when captive customers exist; therefore, if the Commission has
found that there are no captive customers, then, consistent with Sec.
35.39(b) through (g), the affiliate restrictions, including the
prohibition on information sharing, will not apply.
d. Definition of ``Market Information''
Comments
    590. Progress Energy urges the Commission to clarify the definition
of the term ``market information'' which it argues is arbitrarily broad
and may include public as well as non-public market information.\606\
SoCal Edison states that the Commission should only prohibit the
sharing of non-public market information among a utility and its
market-regulated power sales affiliates, as outlined in the standards
of conduct.\607\ EPSA also asserts that the Commission should clarify
that the simultaneous posting requirement should apply to the
communication of all non-public market information (not all market
information). It notes that Order No. 2004 specifically applies to non-
public transmission information, not all transmission information.
---------------------------------------------------------------------------

    \606\ Progress Energy at 36-37.
    \607\ SoCal Edison at 3-6.
---------------------------------------------------------------------------

Commission Determination
    591. The Commission previously explained that ``market
information'' includes information on sales or purchases that will not
be made (as well as purchases and sales that will be made), as well as
any information concerning a utility's power or transmission business--
broker-related or not, past, present or future, positive or negative,
concrete or potential, significant or slight.\608\ In an effort to
provide additional clarity and regulatory certainty, we will provide
further guidance and adopt and codify in Sec.  35.36(a)(8) the
following definition of market information: ``market information means
non-public information related to the electric energy and power
business including, but not limited to, information regarding sales,
cost of production, generator outages, generator heat rates,
unconsummated transactions, or historical generator volumes. Market
information includes information from either affiliates or non-
affiliates.''
---------------------------------------------------------------------------

    \608\ UtiliCorp United, Inc., 75 FERC ] 61,168 (1996).
---------------------------------------------------------------------------

    592. The Commission clarifies that the definition does not prohibit
the disclosure of publicly available information. We find that, because
of its very nature of being publicly available to all entities,
restrictions on sharing publicly available information are unnecessary.
In addition, the definition does not prohibit the sharing of
transmission information. The standards of conduct already prevent
improper disclosures of non-public transmission information by a
transmission provider to its marketing and energy affiliates, which
would include both the franchised public utility with captive customers
and the market-regulated power sales affiliate.\609\
---------------------------------------------------------------------------

    \609\ 18 CFR 358.5(a) and (b) (2006).
---------------------------------------------------------------------------

    593. Further, as we have indicated, a principal purpose of the
affiliate restrictions is to ensure that the interaction between a
franchised public utility and its market-regulated affiliate does not
result in harm to the franchised public utility's captive customers.
Therefore, we clarify that, as a general matter, the definition of
``market information'' includes information that, if shared between a
franchised public utility and a market-regulated affiliate, may result
in a detriment to the franchised public utility's captive customers.
Therefore, market information includes, but is not limited to,
information concerning sales and purchases that will not be made such
as in circumstances where parties have discussed a potential contract
but no agreement has been reached. In contrast, market information does
not include information that would not result in an advantage to the
recipient that could be used to the detriment of the franchised public
utility's captive customers. For example, a franchised public utility
with captive customers and its market-regulated power sales affiliate
may share information related to the relocation of the franchised
public utility's headquarters, business opportunities outside the
United States, general turbine safety information and internal
procedures for general maintenance activities (other than scheduling).
We clarify that the definition of ``market information'' includes, but
is not limited to, written, printed, verbal, audiovisual, or graphic
information.
    594. We are adding language to the information sharing restriction
of Sec.  35.39(d)(1) to make clear that disclosures of market
information are

prohibited, unless simultaneously disclosed to the public, if the
information could be used to the detriment of captive customers. For
example, if a franchised public utility with captive customers conducts
negotiations with an unaffiliated generator to acquire power, but does
not reach an agreement, the franchised public utility with captive
customers is prohibited from sharing with its market-regulated power
sales affiliate any non-public information it acquired through the
unsuccessful negotiations unless such information is simultaneously
disclosed to the public. Information relating to any other entities'
electric energy or power business is also subject to the sharing of
market information restriction if such information could be used to the
detriment of captive customers. Also subject to the information sharing
restriction is information regarding brokering activities, past sales
and purchase activities, and the availability or price of inputs to
generation such as natural gas supply if such information could be used
to the detriment of captive customers. For example, a franchised public
utility with captive customers is restricted from disclosing to its
market-regulated power sales affiliate any non-public information about
a non-affiliated generator's upcoming maintenance or outage schedules
or information about the non-affiliated generator's historical
generation volumes, unless such information is simultaneously disclosed
to the public. In addition, neither the franchised public utility with
captive customers nor its market-regulated power sales affiliate may
tell the other that it intends to sell power to a third party,
including but not limited to the price and quantity it intends to
offer, unless such information is simultaneously disclosed to the
public. Similarly, a market-regulated power sales affiliate is likewise
restricted from telling its franchised public utility affiliate with
captive customers about any other business opportunity that it is
considering or is undertaking, unless such information is
simultaneously disclosed to the public.
e. Sales of Non-Power Goods or Services
Commission Proposal
    595. In the NOPR, the Commission proposed regulatory language to
codify the requirements governing sales of non-power goods or services.
The Commission proposed that sales of any non-power goods or services
by a franchised public utility to a market-regulated power sales
affiliates will be at the higher of cost or market price, and that
sales of any non-power goods or services by a market-regulated power
sales affiliate to an affiliated franchised public utility will not be
at a price above market.
Comments
    596. PG&E argues that, while charging the high of cost or market
price may be appropriate for sales of goods, it is ``inoperable and
inappropriate'' for sales of services because market prices for sales
of service by a third party may be hard to ascertain due to limited
providers and that prices from a third party provider will not take
into account efficiencies resulting from a utility and its affiliate
sharing services.\610\ PG&E further comments that charging the higher
of cost or market, as proposed, may increase costs for both the utility
and the affiliate by discouraging the efficient sharing of services.
Therefore, PG&E proposes that instead of charging the higher of cost or
market price for non-power services, the Commission should allow a
proxy for the market price such as the fully-loaded cost plus a
reasonable profit, e.g., five percent.\611\
---------------------------------------------------------------------------

    \610\ PG&E at 20-21.
    \611\ Id. at 21.
---------------------------------------------------------------------------

Commission Determination
    597. The Commission will adopt the NOPR proposal to codify the
requirement that sales of non-power goods and services by a franchised
public utility with captive customers to a market-regulated power sales
affiliate be at the higher of cost or market price, unless otherwise
authorized by the Commission. This requirement, along with other
requirements in the affiliate restrictions, protect a franchised public
utility's captive customers against inappropriate cross-subsidization
of market-regulated power sales affiliates by ensuring that the utility
with captive customers does not recover too little for goods and
services that the utility provides to a market-regulated power sales
affiliate.\612\ We also adopt the NOPR proposal to codify the
requirement that sales of any non-power goods or services by a market-
regulated power sales affiliate to an affiliated franchised public
utility with captive customers will not be at a price above market,
unless otherwise authorized by the Commission. This requirement
protects a utility's captive customers against inappropriate cross-
subsidization of market-regulated power sales affiliates by ensuring
that the utility with captive customers does not pay too much for goods
and services that the utility receives from a market-regulated power
sales affiliate.
---------------------------------------------------------------------------

    \612\ See generally National Grid plc and Keyspan Corp., 117
FERC ] 61,080 at P 65-66 (2006), reh'g pending.
---------------------------------------------------------------------------

    598. We note that PG&E fails to provide the Commission with any
specific examples of non-power services for which there is no
corresponding third-party provider. Therefore, we are not persuaded by
PG&E that there is a need or a benefit to changing our precedent on
this issue. We will adopt the affiliate restrictions as proposed and
require that sales of non-power goods or services by a franchised
public utility with captive customers to a market-regulated power sales
affiliate be at the higher of cost or market price. Nevertheless, we
will address on a case-by-case basis arguments that charging the higher
of cost or market for certain sales of non-power services may not be
appropriate in a particular case.
f. Service Companies or Parent Companies Acting on Behalf of and for
the Benefit of a Franchised Public Utility
Commission Proposal
    599. The Commission proposed in the NOPR to treat companies that
are acting on behalf of and for the benefit of franchised public
utilities with captive customers, for purposes of the affiliate
provisions, as that franchised public utility. 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.\613 \
---------------------------------------------------------------------------

    \613\ NOPR at 83-84.
---------------------------------------------------------------------------

Comments
    600. EEI asks the Commission to clarify that the code of conduct
(affiliate restrictions) provisions to be codified in the regulations
do not preclude the use of service companies that manage assets for
both regulated and unregulated affiliates.\614\ EEI submits that the
language of proposed Sec.  35.39(b) (now Sec.  35.39(c)) uses
``entities acting on behalf of and for the benefit of a franchised
pubic utility (such as entities managing the electric generation assets
of the franchised public utility)'' whereas the NOPR text reads
``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 pubic utility).'' EEI argues that
the treatment of service companies as part of the franchised public
utility in the preamble to the NOPR is different from the language in
the proposed

regulation and makes the Commission's intent unclear. It submits that
many companies use service companies to provide support activities to
the franchised utility and non-regulated affiliates consistent with the
no-conduit rule. EEI asks the Commission to clarify that the
standardization of the code of conduct is not intended to change this
practice. PG&E claims that under a plain reading of the proposed
regulation, a parent company that acts on behalf of either the utility
or the affiliate will be considered a part of the utility or affiliate,
and communication with either entity will be restricted under proposed
Sec.  35.39(c) (now Sec.  35.39(d)).\615\ It argues that the Commission
should only consider a holding company or parent company as an
affiliate subject to the information sharing prohibitions if it engages
in energy transactions on its own behalf.\616\
---------------------------------------------------------------------------

    \614\ EEI at 45-46.
    \615\ PG&E at 16-17.
    \616\ PG&E at 17.
---------------------------------------------------------------------------

    601. Southern states that it is unclear how the Commission intends
to address and apply the requirements of separation of functions and
information sharing in the context of public utility holding companies
that have system pooling agreements.\617\ Southern recommends the
Commission refine the definition of ``non-regulated power sales
affiliate'' at least insofar as that term is used in the proposed
separation of functions and information sharing provisions to exclude
pooled system affiliates of traditional franchised utilities where
affiliate interactions and sharing of benefits and burdens of pooled
operations are addressed under an arrangement filed and approved under
section 205.\618\
---------------------------------------------------------------------------

    \617\ Southern at 49.
    \618\ Southern at 50.
---------------------------------------------------------------------------

    602. EEI requests that the Commission clarify that, in
circumstances where sales between affiliates have been made in
connection with an approved system agreement, such agreements continue
to govern.\619\ Southern requests that the Final Rule clarify that
affiliated operating companies may continue to operate on a pooled
basis.\620\ Southern states that traditional centralized service
company affiliates providing system pooling support services under
filed and approved system agreements should not be treated as non-
regulated power sales affiliates.\621\
---------------------------------------------------------------------------

    \619\ EEI at 46-49.
    \620\ Southern at 44-52. Southern also asks that the Commission
revise the affiliate abuse regulations to include a definition of
``pooled system affiliates'' and clarify that the definition of non-
regulated power sales affiliate excludes ``pooled system
affiliates'' of traditional franchised utilities. Southern states
that any definition of ``pooled system affiliates'' should address
both existing arrangements (that have been reviewed and approved by
the Commission) and prospective arrangements.
    \621\ Southern at 48-52.
---------------------------------------------------------------------------

Commission Determination
    603. The Commission clarifies that it did not intend to include
service companies as ``entities acting on behalf of and for the benefit
of a franchised public utility'' for purposes of the separation of
functions provision in Sec.  35.39(b) (now Sec.  35.39(c)) to the
extent that such service companies do not engage in generation or
marketing activities.\622\ Although service companies not engaged in
generation or marketing activities are not included in the coverage of
Sec.  35.39(e), they may not act as a conduit for providing non-public
market information between a franchised public utility and a market-
regulated power sales affiliate. However, unless otherwise permitted by
Commission rule or order, service companies cannot be used to direct,
organize or execute generation or marketing activities for both the
franchised public utility and the market-regulated power sales
affiliate(s). In response to Southern's and EEI's request to clarify
that affiliated operating companies may continue to operate as a pool
or pursuant to an approved system agreement, nothing in this Final Rule
precludes pool operation pursuant to filed tariffs or agreements
approved by the Commission and nothing in this rule changes filed
system agreements approved by the Commission. To the extent that
individual companies enter into new pooling or system agreements, the
Commission will continue to review those agreements on a case-by-case
basis to ensure that, among other things, affiliate transactions meet
the requirements of section 205 of the FPA and otherwise satisfy our
affiliate abuse concerns.
---------------------------------------------------------------------------

    \622\ As proposed in the NOPR, the separation of functions
provision provided that ``entities acting on behalf of and for the
benefit of a franchised public utility (such as entities managing
the generation assets of the franchised public utility) are
considered part of the franchised public utility.'' In this Final
Rule, we modify the parenthetical in that provision to state:
``(such as entities controlling or marketing power from the
electrical generation assets of the franchised public utility).''
See 18 CFR 35.39(c)(1).
---------------------------------------------------------------------------

D. Mitigation

    604. In the NOPR, the Commission sought comment on whether the
default mitigation adopted in the April 14 Order is appropriate as
currently structured. The Commission's current default mitigation rates
are as follows: (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 (sometimes referred
to as ``mid-term sales'') will be priced at an embedded cost ``up to''
rate reflecting the costs of the unit or units expected to provide the
service; and (3) new contracts for sales of power for one year or more
will be priced at a rate not to exceed the embedded cost of service,
and the contract will be filed with the Commission for review and
approved prior to the commencement of service.\623\
---------------------------------------------------------------------------

    \623\ April 14 Order, 107 FERC ] 61,018 at P 151; see also NOPR
at P 22, 137.
---------------------------------------------------------------------------

    605. In the NOPR, the Commission sought comment on the following
four issues that have arisen in implementing cost-based mitigation: (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.
1. Cost-Based Rate Methodology
a. Sales of One Week or Less
Commission Proposal
    606. The Commission noted that two principal issues concerning rate
methodology have arisen in implementing the April 14 Order. The first
relates to power sales of one week or less being made at incremental
cost plus 10 percent.\624\ The Commission noted that 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 one week or less, and sought comment on whether to continue to
apply a default rate for such sales that is tied to incremental cost
plus 10 percent. The Commission sought comment as to: (i) Whether there
are problems associated with using ``up to'' rates for shorter-term
sales and, if so, what are they; (ii) whether the current approach
provides utilities a disincentive to offer their power to wholesale
customers in their local control area for short-term sales; and (iii)
whether an ``up to'' rate adequately mitigates market power for such
sales.
---------------------------------------------------------------------------

    \624\ In a number of instances, the NOPR referred to these sales
as ``sales of less than one week,'' and a number of commenters
likewise used ``sales of less than one week'' in their comments. We
clarify that the reference in the NOPR should have been to ``sales
of one week or less,'' consistent with the April 14 and July 8
Orders. Accordingly, for purposes of this Final Rule, we use ``sales
of one week or less'' even if the commenters used ``sales of less
than one week.''

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

Comments
    607. While not opposing the default rate, APPA/TAPS state that as
an alternative, sales of one week or less could occur under the
traditional ``split the savings'' methodology.\625\ APPA/TAPS submit
that both of these methods are consistent with the Commission's
observation that ``[a]bsent market power, a generator would typically
run if it had excess power and could cover its incremental costs plus
some return.'' \626\
---------------------------------------------------------------------------

    \625\ APPA/TAPS at 45-46.
    \626\ Id. (quoting April 14 Order, 107 FERC ] 61,018 at P 152).
---------------------------------------------------------------------------

    608. While the Carolina Agencies claim that sales of one week or
less should not carry a capacity charge, they concede that a reasonable
contribution to the mitigated supplier's fixed costs may be appropriate
(e.g., by including a modest adder over the supplier's incremental cost
of energy).\627\
---------------------------------------------------------------------------

    \627\ Carolina Agencies at 11.
---------------------------------------------------------------------------

    609. NRECA and AARP ask the Commission to retain the incremental
cost plus 10 percent methodology for mitigating sales of one week or
less.\628\ NRECA expresses a concern that the Commission's default
cost-based rates (for all three products--sales of one week or less;
sales of more than one week but less than one year; and sales of one
year or longer) may be subject to gaming by larger public utilities,
especially because the sellers hold all of the critical data. It
asserts that if sellers have too much leeway in choosing which units
they will use to calculate their incremental or embedded costs, the
default cost-based rates will not provide an effective rate ceiling,
and the purpose of the default mitigation will be undermined. NRECA
proposes that the Commission require sellers subject to default cost-
based rates to submit both pre- and post-approval filings supporting
the mitigated cost-based rates for short- and mid-term sales. NRECA
suggests that the seller justify its mitigated rates beforehand by
demonstrating its incremental costs or embedded costs, as appropriate,
and then file after-the-fact quarterly reports of the actual sales and
the actual incremental or embedded costs incurred in making these
sales.\629\ NRECA suggests that this approach would subject mitigated
cost-based rate sales to a cost-based formula rate, and therefore to
refund, upon Commission review of the quarterly compliance filing.\630\
---------------------------------------------------------------------------

    \628\ NRECA at 30; AARP at 8.
    \629\ Suez/Chevron voice a similar concern, adding that a true-
up provision would also help improve transparency with regard to the
cost of mitigated sales for the benefit of state commissions. Suez/
Chevron at 13-14.
    \630\ NRECA at 30-32.
---------------------------------------------------------------------------

    610. NASUCA urges the Commission to require that all mitigated
rates, and any rate discounts, whether for more or less than one year
in duration, must be filed and made subject to public scrutiny and
Commission review under section 205 of the FPA.\631\ NASUCA is
concerned that under the NOPR, only rates to be in effect for more than
one year are required to be filed publicly in advance and subject to
protest, intervention, prior Commission review and revision. It argues,
however, that section 205 contains no exception from the filing
requirement for sales of less than one year.\632\ Given that all new
rate schedules and contracts affecting rates must be publicly filed,
NASUCA asks the Commission not to reduce section 205's procedural
safeguards for sales of less than one year at cost-based rates (i.e.,
by not requiring that they be subject to prior notice and review).\633\
---------------------------------------------------------------------------

    \631\ NASUCA at 18-19; NASUCA reply comments at 16-18.
    \632\ NASUCA at 18 (citing NOPR at P 22).
    \633\ Id. at 18-19.
---------------------------------------------------------------------------

    611. Some commenters oppose the incremental cost plus 10 percent
default rate, with several alleging that it deviates from prior
Commission precedent without sufficient justification and fails to
adequately compensate sellers.\634\ Some commenters also allege that
such an approach will deter new entry and gives sellers the incentive
to sell outside the mitigated market.
---------------------------------------------------------------------------

    \634\ MidAmerican at 9-11, Westar at 24.
---------------------------------------------------------------------------

    612. For example, Westar states that the Commission's reasoning in
the July 8 Order which explained that the cost plus 10 percent default
rate represents a ``conservative proxy for a reasonable margin
available in a competitive market,'' \635\ suffers from two fatal
flaws. First, the Commission failed to distinguish or even mention
Terra Comfort wherein, Westar and Duke submit, the Commission found
that 10 percent adders provide no contribution to fixed costs, and it
rejected the argument that ``utilities routinely forego these margins
and sell at 110 percent of incremental cost.'' \636\ Second, according
to Westar, in adopting this default rate the Commission relied heavily
upon an order that applied the formula in an RTO under entirely
different circumstances.\637\
---------------------------------------------------------------------------

    \635\ July 8 Order, 108 FERC ] 61,026 at P 155.
    \636\ Westar at 24 (quoting Terra Comfort Corp., 52 FERC ]
61,241 at 61,839-40 (1990)); Duke at 8-9, n.9.
    \637\ Westar at 25 (citing PJM Interconnection, L.L.C., 107 FERC
] 61,112, at 61,366 (2004), order on reh'g, PJM Interconnection,
L.L.C., 110 FERC ] 61,053 (2005)).
---------------------------------------------------------------------------

    613. MidAmerican and Westar note that, in support of the default
rate, in the April 14 Order the Commission cited a PJM tariff provision
pursuant to which generators dispatched out of economic merit have
their bids mitigated to incremental costs plus 10 percent to prevent
them from exercising market power and, at the same time, providing
revenues which include a margin.\638\ MidAmerican and Westar contend
that this is merely an example of a mitigation mechanism, not a
rationale for a broad-scale default mitigation scheme that ignores
years of precedent.\639\ They submit that the PJM tariff mitigates bids
for a select set of generators. They state that, regardless of the
level of their bids, those generators are still paid the market
clearing price because only the offer is capped. Further, because PJM's
methodology applied this offer cap only to a limited number of hours,
MidAmerican and Westar state that sellers were also free to bid above
the cap in the majority of the hours of the year.\640\ In contrast,
MidAmerican and Westar claim that the incremental cost plus 10 percent
default rate is an absolute cap on revenues that would apply to all
sales of one week or less in length.\641\
---------------------------------------------------------------------------

    \638\ April 14 Order, 107 FERC ] 61,018 at P 152, n.146.
    \639\ MidAmerican at 10; Westar at 25.
    \640\ Id.
    \641\ Id.
---------------------------------------------------------------------------

    614. Although the July 8 Order explained that incremental cost plus
10 percent was a backstop, default rate, and that entities were free to
propose alternative mitigation schemes, MidAmerican asserts that this
ignores the fact that the Commission has routinely accepted alternative
cost-based rates for sales of one week or less. As such, MidAmerican
maintains that there is no reason why ``split the savings'' rates, or
rates reflecting a demand charge, could not be used as a default rate
for mitigated sales of one week or less.\642\
---------------------------------------------------------------------------

    \642\ MidAmerican at 13.
---------------------------------------------------------------------------

    615. Several commenters also argue that the energy-only incremental
cost plus 10 percent methodology does not allow for proper recovery of
capacity-based costs on sales of one week or less thereby artificially
depressing the prices of these short-term sales and possibly deterring
new entry.\643\ These commenters state that sellers should be

allowed to recover a contribution to their fixed/capacity costs.
---------------------------------------------------------------------------

    \643\ Pinnacle at 10; Ameren at 15; Duke at 8; MidAmerican at 9-
11; Westar at 24; Drs. Broehm and Fox-Penner at 15-16; Xcel at 9;
Progress Energy at 9; PPL reply comments at 17-18; EEI at 29; NRG at
5, 11.
---------------------------------------------------------------------------

    616. Some commenters contend that the default cost-based rates
create an incentive to sell outside the mitigated market because they
recover less than cost-based rates historically accepted that included
a demand charge. However, they assert that setting rates that require
buyers to make a reasonable contribution to the seller's fixed costs
for the use of the capacity would create an incentive for the seller to
make sales within its mitigated control area.\644\ Duke and the Oregon
Commission add that allowing recovery of capacity-based costs also
ensures that wholesale customers bear their fair share of system
costs.\645\
---------------------------------------------------------------------------

    \644\ See, e.g., Duke at 9.
    \645\ Id. at 10; Oregon Commission reply comments at 2.
---------------------------------------------------------------------------

    617. Several commenters also claim that by artificially depressing
short-term sales prices, the default rate transfers wealth from the
supplier's retail customers to wholesale customers.\646\ Such retail
customers, these commenters state, have paid the fully-allocated costs
of the system and obtain revenue credits to their costs from the
supplier's short-term sales. Where short-term sales are made on a non-
interruptible basis, and the incremental cost plus 10 percent rate
prices them only at incremental running cost, Progress Energy contends
that wholesale purchasers are receiving the benefits of capacity
without cost.\647\ Progress Energy and EEI submit that retail native
load customers, as a result, lose the economic benefits that would
otherwise accrue to them through revenue credits from short-term
wholesale sales.\648\ Wholesale customers charged through an embedded
cost-of-service are also harmed, Progress Energy adds, because they
lose the economic benefits that would otherwise accrue to them through
revenue credits from short-term wholesale sales.\649\
---------------------------------------------------------------------------

    \646\ Westar at 16; Progress Energy at 9; EEI at 33-34; Pinnacle
at 10; MidAmerican at 9.
    \647\ Progress Energy at 9-10.
    \648\ Id. at 10, n.13; EEI at 29.
    \649\ Progress Energy at 10, n.13.
---------------------------------------------------------------------------

    618. Progress Energy and Duke instead favor an ``up to'' cost-based
default rate for sales of one week or less.\650\ For such sales,
Progress Energy supports an ``up to'' rate design flexible enough to
allow rates as low as the mitigated seller's incremental costs and as
high as 100 percent of the seller's capacity and energy costs.
According to Progress Energy, a mitigated seller could choose to make
sales as low as its incremental cost when either (1) The unmitigated
market price of competing sellers dictates that price, or (2) the
mitigated seller needs to sell its excess generation at that price to
maintain a minimum generation control margin. Given that there is a
short-term market for capacity, Progress Energy asks that the default
cost-based rates include a price structure that allows pricing of
capacity-only sales.\651\
---------------------------------------------------------------------------

    \650\ Progress Energy at 10; Duke at 8.
    \651\ Progress Energy at 10.
---------------------------------------------------------------------------

    619. Xcel suggests that the Commission should allow for an even
higher emergency price in situations where purchasers need to make a
purchase not simply to achieve economic benefits but where the
purchaser is capacity deficient. Xcel submits that in such instances, a
purchaser plainly obtains a capacity benefit from the purchase of such
power. Historically, the Commission has allowed an emergency rate of
$100 per MWh for emergency service. Given that gas prices have
dramatically increased since that standard rate began to be utilized,
Xcel claims that an emergency rate of the higher of cost plus 10
percent or $1,000 per MWh would be appropriate in the present
environment.\652\
---------------------------------------------------------------------------

    \652\ Xcel at 10.
---------------------------------------------------------------------------

Commission Determination
    620. The Commission will retain the incremental cost plus 10
percent methodology as the default mitigation for sales of one week or
less, while continuing to allow sellers to propose alternative cost-
based methods of mitigation tailored to their particular circumstances.
As discussed more fully below, we clarify that in retaining the
incremental cost plus 10 percent methodology as the default mitigation
for sales of one week or less we do not otherwise limit a seller's
ability to propose different cost-based rates for sales of one week or
less.\653\
---------------------------------------------------------------------------

    \653\ For that matter, we also do not limit a seller's ability
to propose and support different cost-based rates for any of the
default cost-based rates.
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    621. Although a number of commenters suggest that the Commission
should adopt a different default cost-based ratemaking methodology for
sales of one week or less, they have failed to persuade us that the
existing default rate is inappropriate. As the Commission has
previously stated, an incremental cost rate that allows a fair recovery
of the incremental cost of generating with a 10 percent adder to
provide for a margin over incremental cost is reasonable.\654\
Incremental costs plus 10 percent represents a conservative proxy for a
reasonable rate available in a competitive market.\655\ On this basis,
we find incremental cost plus 10 percent to be an appropriate default
rate. Moreover, we allow sellers the opportunity to design, support,
and propose other cost-based rates that they believe are more
appropriate for their particular circumstances.
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    \654\ April 14 Order, 107 FERC ] 61,018 at P 152.
    \655\ July 8 Order, 108 FERC ] 61,026 at P 155.
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    622. Several commenters note that the Commission has permitted
various cost-based rate methodologies prior to the April 14 Order,
including a split-the-savings formula. These entities express concern
that the use of the incremental cost plus 10 percent methodology as the
default mitigation rate for sales of one week or less forecloses the
possibility of other cost-based pricing methodologies. However, this is
not the case. Rather than precluding alternative mitigation proposals,
the April 14 Order allows sellers to propose case-specific tailored
mitigation, or adopt the default cost-based rate. The April 14 Order
described the default mitigation rate as ``a backstop measure''
intended to ensure a just and reasonable rate.\656\ The Commission re-
emphasized this in its July 8 Order explaining: ``In the instant case,
the 10 percent adder is to be used only as a backstop or default
measure in the event that an applicant does not opt to propose its own
mitigation.'' \657\
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    \656\ April 14 Order, 107 FERC ] 61,018 at P 148.
    \657\ July 8 Order, 108 FERC ] 61,026 at P 157 (emphasis added).
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    623. As such, the incremental cost plus 10 percent rate represents
a default, cost-based rate to protect customers from the potential
exercise of market power and provide sellers regulatory rate certainty
by establishing a ``safe harbor.'' Any proposal for alternative cost-
based rates will be considered on a case-by-case basis.
    624. Further, with regard to including capacity charges in rates
for one week or less, a seller may propose to recover such charges and
the Commission will consider these charges based on the specific facts
and circumstances presented. Rather than ignoring alternative forms of
cost-based rates, as some commenters claim, the Commission's policy
offers sellers the opportunity to propose such alternatives.
    625. Use of the default rate as set forth in the April 14 and July
8 Orders also is not inconsistent with Terra Comfort, as some
commenters claim. As explained above, contrary to some commenters'
allegations, the Commission does not confine mitigated sellers to rates
that forego a contribution to fixed/capacity costs. In Terra Comfort,
the Commission explained that

``most utilities maintain on file for all services flexible demand
charge ceilings designed to reflect a 100-percent contribution to the
fixed costs of their facilities.'' \658\ The Commission then added that
utilities are not obligated to ``forego these margins and sell at 110
percent of incremental costs.'' \659\ In the April 14 Order, the
Commission, consistent with its holding in Terra Comfort, explained
that ``as a backstop measure, we will also provide `default' rates to
ensure that wholesale rates do not go into effect, or remain in effect,
without assurance that they are just and reasonable.'' \660\ Contrary
to Duke's assertion that this default rate suggests that sellers do not
have economic justification (or need) to recover a share of their
fixed/capacity costs in the prices charged for such transactions,\661\
the Commission's policy allows ``applicants to propose case-specific
mitigation tailored to their particular circumstances that eliminates
the ability to exercise market power, or adopt cost-based rates such as
the default rates herein.'' \662\ The Commission explained in the April
14 Order that ``[p]roposals for alternative mitigation in these
circumstances could include cost-based rates or other mitigation that
the Commission may deem appropriate.'' \663\ Consistent with industry
practice and Commission precedent, therefore, where mitigated sellers
can properly justify such contributions, they may propose to recover
contributions to fixed/capacity costs under the Commission's mitigation
policy.
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    \658\ Terra Comfort Corp., 52 FERC at 61,839.
    \659\ Id.
    \660\ April 14 Order, 107 FERC ] 61,018 at P 148.
    \661\ Duke at 9 (citing Terra Comfort, 52 FERC at 61,839).
    \662\ April 14 Order, 107 FERC ] 61,018 at P 147.
    \663\ 663 April 14 Order, 107 FERC ] 61,018 at n.142.
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    626. Such alternative mitigation has been proposed and accepted.
For example, Progress Energy correctly notes that one of its
subsidiaries proposed as mitigation--and the Commission approved--a
cost-based ``up-to'' capacity charge and a cost-based energy charge for
the subsidiary's power sales of less than one year, including sales of
one week or less, in the mitigated control area.\664\ Progress Energy
is correct in observing that this decision was consistent with the
Commission's long-standing policy of permitting the pricing of short-
term sales at cost-based ``up-to'' capacity charges and cost-based
energy charges.\665\ Rather than artificially depressing the prices of
short-term sales, exacting a wealth transfer, or limiting a seller's
ability to respond to market conditions, as Progress suggests, the
default cost-based rate for sales of one week or less provides a
backstop measure intended to protect customers by ensuring that, in the
event a seller loses or relinquishes its market-based rate authority,
there is a readily available cost-based rate under which such sellers
may choose to transact, and the mitigated seller by establishing a
refund floor that provides it with rate certainty.
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    \664\ Carolina Power & Light, 113 FERC ] 61,130 at P 23-24
(2005) (citing Detroit Edison Co., 78 FERC ] 61,149 (1997)
(approving a demand charge for power sales for periods of an hour up
to one year); Illinois Power Co., 57 FERC ] 61,213, at 61,699-700
(1991) (permitting utilities to include in their rates an amount
above incremental costs to provide a contribution to fixed costs)).
    \665\ Progress Energy at 8-9.
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    627. As to some commenters' suggestion that the incremental cost
plus 10 percent methodology, and cost-based rates in general, adversely
affect retail rates because they exact a wealth transfer from the
supplier's retail customers to wholesale customers, the July 8 Order
rejected such claims on the ground that they were ``unsupported and
speculative.'' \666\ Not only do these claims remain unsupported but
they suggest that the Commission should allow wholesale rates in excess
of a just and reasonable rate. This result would not be just and
reasonable. As the Commission stated in the July 8 Order, ``our rate
making policy is designed to provide for recovery of prudently incurred
costs plus a reasonable return on investment.'' \667\ Moreover, the
Commission explained that ``the opportunity for the applicants to
propose alternative, tailored mitigation measures should allow adequate
consideration of the effect on investment and customers.'' \668\
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    \666\ July 8 Order, 108 FERC ] 61,026 at P 140, 154.
    \667\ Id. at P 152.
    \668\ Id. at P 154
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    628. We will not adopt Progress Energy's request that the default
rate be modified to include a price structure allowing pricing of
capacity-only sales. Progress Energy fails to provide adequate
justification to provide for such a rate in our default cost-based
rates. For example, Progress Energy states that there is a short-term
market for capacity-only sales but fails to explain how this market is
a power sales market (for which our default cost-based rates apply)
rather than an ancillary services market which is not contemplated in
the default cost-based power sales rates. Nevertheless, as noted above,
a mitigated seller has the opportunity to propose and justify an
alternative to the default rate.
    629. Similarly, in response to NASUCA's request that the Commission
require all mitigated rates and discounts to be filed under section 205
of the FPA, we note that all mitigation proposals must be filed with
the Commission for review. These filings are noticed and interested
parties are given an opportunity to intervene, comment, or protest the
submittal. With regard to discounts, as we explain in the discounting
section of this Final Rule, discounts made to customers, like all other
rates, are required to be reported in the seller's EQRs.
    630. We also note that the Commission stated in the April 14 Order
that where a seller proposes to adopt the default cost-based rates (or
where it proposes other cost-based rates), it must provide cost support
for such rates.\669\ The Commission will examine the proposed rates on
a case-by-case basis. With regard to sales of one week or less, where
the seller fails to provide sufficient cost support, the Commission
will direct the seller to submit a compliance filing to provide the
formulas and methodology according to which it intends to calculate
incremental costs.\670\ We note here that, to the extent a seller
proposes a cost-based rate formula, we will require the rate formula
used be provided for Commission review and such formula included in the
cost-based rate tariff including formulas used in calculating
incremental cost.
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    \669\ April 14 Order, 107 FERC ] 61,018 at P 208. See Entergy
Services, Inc., 115 FERC ] 61,260 at P 49 (2006) (accepting cost-
based rates based on incremental cost plus 10 percent, noting that
filing included the formula and methodology according to which
seller intends to calculate incremental costs).
    \670\ See, e.g., Aquila, Inc., 112 FERC ] 61,307 at P 26 (2005);
Oklahoma Gas and Electric Co., 114 FERC ] 61,297 at P 19 (2006).
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    631. The Commission also has set proposed default cost-based rates
for hearing when appropriate.\671\ We believe that this case-by-case
review of proposed default cost-based rates adequately addresses
NRECA's and Suez/Chevron's concerns. Moreover, to the extent that an
entity contends that a mitigated seller is flowing inappropriate costs
through its formula rate, section 206 of the FPA provides a process for
filing a complaint.
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    \671\ AEP Power Marketing, Inc., 112 FERC ] 61,047 at P 28
(2005).
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b. Sales of More Than One Week But Less Than One Year
Commission Proposal
    632. In the NOPR, the Commission sought comment on issues related
to the design of an ``up to'' cost-based rate. The Commission noted in
the NOPR