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

    750. According to Duke and others, when a mitigated supplier sells
excess generation at market-based rates outside of the mitigated
control area, it is exhibiting economic behavior.\858\ Such behavior
encourages trading within and across regions, making markets more
competitive. Similarly, Westar contends that a ``must offer''
requirement prevents markets from allocating scarce resources to
customers who value them the most, hindering optimal resource
allocation.\859\ Westar states that this is inefficient because ``the
highest cost generation may not be displaced by the seller's lower cost
energy.'' \860\
---------------------------------------------------------------------------

    \858\ Duke at 11; Xcel at 6; Southern at 56-57; EEI reply
comments at 11.
    \859\ Westar at 13 (citing Pacific Gas and Electric Company, 38
FERC ] 61,242 at 61,790 (1987)).
    \860\ Id. (quoting Pacific Gas and Electric Company, 38 FERC at
61,790, n.19).
---------------------------------------------------------------------------

    751. EEI, Progress Energy, and others also claim that a ``must
offer'' requirement would effectively take economic benefits away from
the mitigated utility's retail native load and transfer them to
wholesale customers in the mitigated control area.\861\ Some of these
commenters claim that a ``must offer'' requirement may result in a
windfall for the wholesale customer originally seeking protection from
the seller's market power at the expense of the mitigated utility and
its native load customers.\862\ PNM/Tucson adds that sales made by a
utility pursuant to a ``must offer'' requirement could affect
reliability by making capacity unavailable to meet State-established
reserve margins.\863\
---------------------------------------------------------------------------

    \861 \ See, e.g., EEI at 33; Progress Energy at 14, 16; Entergy
at 2; Westar at 16; see also Dr. Pace at 24-25.
    \862\ PPL reply comments at 14; Duke reply comments at 2, 7-8;
Progress Energy at 16; E.ON U.S. at 13-14; Duke at 12-13;
MidAmerican at 27.
    \863\ PNM/Tucson at 18.
---------------------------------------------------------------------------

    752. Xcel and Duke point out that a ``must offer'' requirement at
cost-based rates may result in a lost opportunity cost to the
seller.\864\ A number of commenters assert that mitigation is intended
to assure that selling utilities do not benefit from the exercise of
market power; it is not to guarantee preferential treatment for
particular customers to obtain below-market generation through an
obligation to serve.\865\
---------------------------------------------------------------------------

    \864\ Xcel at 8; Duke reply comments at 3, n.4.
    \865\ Xcel at 5; EEI reply comments at 10, 12; Progress Energy
at 14.
---------------------------------------------------------------------------

    753. Some commenters further contend that a ``must offer''
requirement would create significant wealth transfers from mitigated
sellers as a result of arbitrage opportunities. For example, wholesale
customers would accept the mitigated offer any time the ``must offer''
price was below the market price, either in or outside of the mitigated
region.\866\ E.ON U.S. is concerned that a ``must offer'' requirement
giving a buyer the option to buy power at mitigated prices will
inevitably result in external third parties negotiating with such a
buyer to obtain longer-term access to the mitigated power.\867\
---------------------------------------------------------------------------

    \866\ Progress Energy at 16; Westar at 16.
    \867\ E.ON U.S. at 13.
---------------------------------------------------------------------------

    754. In addition, EEI and others argue that a ``must offer''
requirement would reduce competition and stifle development by
providing a disincentive for sellers to develop new generation
resources.\868\ New entrants would be deterred from building generation
due to the disparity between cost-based and market-based rates; \869\
other sellers in the mitigated region effectively would be mitigated
because they would not be selected by buyers unless their price is
below the mitigated price of the ``must offer'' requirement.\870\ At
the same time, EEI asserts that the mitigated seller would perpetuate
its market power by increasing its capacity in the mitigated control
area.\871\
---------------------------------------------------------------------------

    \868\ EEI at 37; Progress Energy at 16; MidAmerican at 22. APPA/
TAPS responds that it is in fact the mitigated seller's constrained
transmission system that keeps LSEs captive and prevents new entry
that could reduce the seller's market power. APPA/TAPS reply
comments at 9.
    \869\ EEI reply comments at 10.
    \870\ MidAmerican reply comments at 8.
    \871\ EEI reply comments at 10.
---------------------------------------------------------------------------

    755. Progress Energy and MidAmerican add that a ``must offer''
requirement would impede a mitigated seller's ability to fulfill its
retail crediting obligations and to provide adequate and reliable
service to its native load retail customers, which bear, through their
retail rates, the fixed costs of the generation to serve them.\872\
---------------------------------------------------------------------------

    \872\ See, e.g., Progress Energy at 14-15; E.ON U.S. at 12-13;
PNM Tucson at 18; MidAmerican at 21.
---------------------------------------------------------------------------

    756. Southern, Duke and others further suggest that a ``must
offer'' requirement could undermine the required planning and
operations processes of utility systems purchasing the ``must offer''
output.\873\ They argue that a ``must offer'' requirement could bias
shorter-term operating decisions where, for example, an LSE has the
opportunity to purchase peak supply in real time at less than market
prices, thereby avoiding incurring any fixed costs on a day-ahead basis
to ensure peak supply availability.\874\ They contend that this would
eliminate incentives for the LSEs to plan to meet their resource needs
and shift planning obligations at the expense of a mitigated utility's
native load customers.\875\
---------------------------------------------------------------------------

    \873\ Southern at 61; Progress Energy at 16; Duke reply comments
at 9-10; EEI reply comments at 10-11.
    \874\ Southern at 63.
    \875\ Duke reply comments at 8-11. APPA/TAPS counters that where
a ``must offer'' requirement would not, by its own terms, obligate a
seller to build, an LSE that relied exclusively on ``must offer''
sales would be taking risks that capacity to support those sales
might no longer be available. APPA/TAPS reply comments at 9.
---------------------------------------------------------------------------

    757. Another commenter is also wary of a ``must offer''
requirement, reasoning that such a requirement is normally designed to
mitigate physical withholding. This commenter states that it may work
well in an organized power market where an independent operator ensures
that the power is used to serve the local needs caused by reliability
or local resource deficiency. However, without an independent operator,
a ``must offer'' requirement may be more difficult to administer.\876\
In advocating for separate market policies and tests for short- and
long-term markets, this commenter prefers a price cap for short-term
products rather than a ``must offer'' requirement, asserting that a
price cap for short-term products is preferable to a ``must offer''
approach because it is more economically efficient, fair, and easier to
administer.\877\ For long-term products, this commenter takes the
position that, ``[i]n situations where a lack of long-term transmission
and/or a lack of long-term supply alternatives exist, it is difficult
to think of an

alternative to full cost-of-service rates.'' \878\ They add that these
cost-based rates should offer both fair prices and adequate investment
returns to suppliers in the destination market with rate-of-return
levels that fully enable incumbent suppliers to make appropriate
investments to meet such cost-based obligations.\879\
---------------------------------------------------------------------------

    \876\ Drs. Broehm and Fox-Penner at 16-17.
    \877\ Drs. Broehm and Fox-Penner supplemental comments at 3.
Drs. Broehm and Fox-Penner advocate other approaches, such as use of
a proxy price when transmission constraints are not binding and use
of default cost-based rates when they are binding.
    \878\ Id.
    \879\ Id.
---------------------------------------------------------------------------

    758. Entergy raises a concern that in the NOPR the Commission erred
by failing to define what constitutes available capacity. It asserts
that there is difficulty in calculating available capacity because of
uncertainty regarding: (1) Loads; (2) qualifying facility puts; (3)
unit performance; and (4) fuel arrangements and prices.\880\
---------------------------------------------------------------------------

    \880\ Entergy at 2-3.
---------------------------------------------------------------------------

Commission Determination
    759. After careful consideration of the arguments raised by
commenters, we will not impose an across-the-board ``must offer''
requirement for mitigated sellers. While wholesale customer commenters
have raised concerns relating to their ability to access needed power,
we conclude that there is insufficient record evidence to support
instituting a generic ``must offer'' requirement.
    760. As discussed above, some commenters argue that undue
discrimination occurs if a mitigated seller refuses to sell power to
customers in the mitigated balancing authority area and instead sells
that power at market-based rates to customers outside the mitigated
balancing authority area. Some commenters also contend that it is
unduly discriminatory for a mitigated seller to make market-based rate
sales to competitive markets outside the mitigated balancing authority
area when constraints on that seller's own transmission system prevent
embedded customers from similarly accessing those markets as buyers.
However, these commenters have not provided any evidence of specific
instances in which the harms they identify have, or are, occurring.
Without such evidence, we decline to impose a generic remedy such as a
``must offer'' requirement.
    761. In National Fuel, the D.C. Circuit vacated a final rule of the
Commission, Order No. 2004, as applicable to natural gas pipelines
because of the expansion of the standards of conduct to include a new
definition of energy affiliates. The court explained that the
Commission relied on both theoretical grounds and on record evidence to
justify this expansion. The court concluded that the Commission's
record evidence did not withstand scrutiny and, thus, concluded the
expansion was arbitrary and capricious in violation of the
Administrative Procedure Act.\881\ While the court left open the
possibility of the Commission relying solely on a theoretical threat of
abuse, it cautioned that if the Commission chooses to take that
approach, ``it will need to explain how the potential danger * * *
unsupported by a record of abuse, justifies such costly prophylactic
rules.'' \882\ In addition, the court said the Commission would need to
explain why individual complaint procedures were insufficient to ensure
against abuse.\883\
---------------------------------------------------------------------------

    \881\ National Fuel, 468 F.3d at 844.
    \882\ Id.
    \883\ Id.
---------------------------------------------------------------------------

    762. We find here that, although wholesale customer commenters have
raised theoretical concerns that they will be unable to access power
absent a ``must offer'' requirement, they have not provided any
concrete examples of harm nor explained how the potential harm
justifies the generic remedy they seek. Given the lack of evidence in
the record that wholesale customers in mitigated markets will be unable
to obtain power supplies at reasonable rates, we conclude that there is
insufficient basis for instituting a generic ``must offer''
requirement. Indeed, the record includes evidence of utilities
continuing to make cost-based sales after loss or surrender of market-
based rate authority.\884\
---------------------------------------------------------------------------

    \884\ See Duke reply comments at 7 and n.10; Progress Energy
reply comments at 9-11; Duke/Progress Energy supplemental comments
at 17 and n.7.
---------------------------------------------------------------------------

    763. In addition, consistent with the guidance provided in National
Fuel, commenters advocating a generic ``must offer'' have not
demonstrated that existing procedures and remedies under the FPA are
inadequate to deal with specific cases that may arise. To the contrary,
we find that there are potential remedies available on a case-by-case
basis to a wholesale customer alleging undue discrimination or other
unlawful behavior on the part of a mitigated seller. For example, a
wholesale customer can file a complaint pursuant to section 206 of the
FPA. It also can bring an action under section 202(b) of the FPA.\885\
In addition, it can bring an action pursuant to the statutory
prohibition in section 222 of the FPA against market manipulation.
---------------------------------------------------------------------------

    \885\ See, e.g, City of Las Cruces, New Mexico v. El Paso
Electric Co., 87 FERC ] 61,220 (1999) (``In our view, section 202(b)
allows the Commission to direct a public utility to take three
separate actions: (1) Establish a physical connection of its
transmission facilities with the facilities of one or more eligible
persons; (2) sell energy to eligible persons; or (3) exchange energy
with eligible persons.'')
---------------------------------------------------------------------------

    764. While we do not impose a generic ``must offer'' requirement in
this Final Rule, we do not rule out the possibility that we might find
the imposition of a ``must offer'' requirement, or some other condition
on the seller's market-based rate authority, to be an appropriate
remedy in a particular case depending on the facts and circumstances,
as we have done in the past.\886\ We note that the Commission has
previously imposed a ``must offer'' requirement as a condition of
market-based rate authority for sellers in the California markets.\887\
There, the record demonstrated a problem in a limited geographic area
that warranted a ``must offer'' remedy to prevent unjust and
unreasonable rates from being charged during certain times and under
certain conditions. If a wholesale customer were to present specific
evidence documenting that a transmission provider either denied the
customer's request for transmission service, in violation of the OATT,
or was unreasonably delaying responding to a request for transmission
service, in violation of the OATT, we might find the imposition of a
``must offer'' requirement on a transmission provider to be an
appropriate remedy.\888\ As the Commission recently explained in Order
No. 890, transmission providers must process requests for transmission
service ``as soon as reasonably practicable after receipt'' of such
requests \889\ and must post performance metrics that are intended ``to
enhance the transparency of the study process and shed light on whether
transmission providers are processing request studies in a non-
discriminatory manner.'' \890\ Order No. 890 explained that ``the
revised pro forma OATT will greatly enhance our oversight and
enforcement capabilities by increasing the transparency of many
critical functions

under the pro forma OATT, such as ATC calculation and transmission
planning.'' \891\ Here too, we reiterate that the Commission ``intends
to use its enforcement powers with respect to the OATT in a fair and
even-handed manner, pursuant to the principles set forth in the Policy
Statement on Enforcement.'' \892\
---------------------------------------------------------------------------

    \886\ If an intervenor believes a ``must-offer'' requirement is
the only way to mitigate market power, it may present evidence to
that effect in a particular proceeding.
    \887\ See San Diego Gas & Elec. Co., 95 FERC ] 61,418 at 62,557
(2001) (``After carefully considering the record, the Commission
reaffirmed its general finding that, as a result of the seriously
flawed electric market structure and rules for wholesale sales of
electric energy in California, unjust and unreasonable rates were
charged and could continue to be charged during certain times and
under certain conditions, unless certain targeted remedies were
implemented.'')
    \888\ We are not prejudging here that such facts warrant
imposition of a ``must offer'' requirement.
    \889\ Preventing Undue Discrimination and Preference in
Transmission Service, Order No. 890, FERC Stats. & Regs. ] 31,241 at
P 1296 (2007) (Order No. 890).
    \890\ Id. at P 1308.
    \891\ Id. at P 1721.
    \892\ Id. at P 1714.
---------------------------------------------------------------------------

    765. In addition to our conclusion that there is not sufficient
record evidence to support the imposition of a generic ``must offer''
requirement, we are also concerned that adoption of a ``must offer''
requirement would present a number of difficult implementation and
logistical problems.\893\
---------------------------------------------------------------------------

    \893\ Because we have decided not to impose a generic ``must
offer'' requirement in this Final Rule, we do not address the merits
of the particular must-offer proposals made by commenters.
---------------------------------------------------------------------------

    766. For example, given the difficulties associated with
calculations of available transfer capability,\894\ we foresee similar
disputes over the calculation of available generation capacity were we
to impose a generic ``must offer'' obligation. For instance, how far in
advance should such calculations occur--one hour, one day, one month,
or some other time frame? Would such calculations be derived on a
generator specific basis or on a system basis (and how is transmission
factored in)? Would the Commission or the industry need to develop a
standard method of calculating available generation capacity? How would
available generation capacity be allocated to potential purchasers?
---------------------------------------------------------------------------

    \894\ OATT Reform NOPR at PP 37-41 (outlining problems that
result from inconsistent available transfer capacity calculation,
including missed opportunities for transactions, frequent errors,
and undue discrimination).
---------------------------------------------------------------------------

    767. We also are concerned that adopting a ``must offer''
requirement could harm other markets. For example, if a mitigated
seller is required to offer its available power first to customers in
the mitigated market, such a requirement may effectively preclude the
mitigated seller from participating in adjoining markets particularly
at times when additional supply is most needed (i.e., when prices in
the adjoining market are high). Such a policy may serve to assist one
set of customers at the expense of other customers that see their
supply options reduced.
    768. Parties have asserted that imposing a must offer requirement
may discourage long-term planning, while others have disagreed with
those arguments. Given that we do not impose any must offer obligation
in this rule, we need not and do not address these arguments. If the
Commission considers imposing a ``must offer'' requirement in an
individual case, affected parties can raise these arguments at that
time.
    769. Though APPA/TAPS and the Carolina Agencies are correct that
the Commission has previously imposed a ``must offer'' requirement as a
condition of market-based rate authority for sellers in the California
markets, as discussed above, that holding supports our approach here.
There, the record demonstrated a problem in a limited geographic area
that warranted a ``must offer'' remedy to prevent unjust and
unreasonable rates from being charged during certain times and under
certain conditions. By contrast, here APPA/TAPS and the Carolina
Agencies urge us to impose a generic remedy on all mitigated sellers in
all markets without a showing that there is a concrete problem
justifying imposition of a ``must offer'' requirement in all markets.
    770. Given that we have not adopted a ``must offer'' requirement in
this Final Rule, we need not, and do not, address arguments asserting
that we lack legal authority to do so. If the Commission should adopt
any such requirement in an individual case, affected parties can raise
any related legal arguments at that time and nothing in this rule
precludes them from doing so.
    771. For many of the same reasons that we decline to impose a
``must offer'' requirement, we also decline to adopt the ``right of
first refusal'' requirement proposed by NRECA. Under this approach, a
wholesale customer in the mitigated market would be given a right of
refusal to purchase, at the market price, power that the mitigated
seller proposes to sell outside the mitigated market. For the reasons
provided above, there is insufficient record evidence to support
imposition of such an across-the-board requirement.
    772. A ``right of first refusal'' also would carry significant
administrative burdens. Such an approach would invite disputes about
what constitutes a legitimate offer by a third party to purchase power
which establishes the basis for the offered rate. There also may be
disputes if more than one wholesale customer wants to purchase the
power in question. We are also concerned about the long-term viability
of a rate setting that is based on mitigated sellers repeatedly
negotiating tentative power sale arrangements with would-be buyers in
first-tier markets only to have those offers withdrawn so the sale
could be made to another buyer. Under such a regime, buyers from
outside the mitigated market may be disinclined to invest resources to
negotiate tentative contracts knowing that there is a significant
chance that another buyer from within the mitigated market will usurp
their position and instead get the sale.
    773. There are also administrative concerns with how the Commission
or third parties could be certain what the actual price and conditions
of service would be for the sale in the first-tier market unless the
contract was actually executed.
    774. In response to NRECA's suggestion that an enforceable
commitment to provide sufficient additional transmission import
capacity to mitigate generation market power be considered as an
alternative, the Commission notes that, consistent with the April 14
Order, a seller that fails one of the generation market power screens
is allowed to propose alternative mitigation that the Commission may
deem appropriate.\895\ As a result, a mitigated seller could propose,
as alternative mitigation, to provide additional transmission capacity
by, for example, committing to relinquish transmission reservations or
to physically upgrade the transmission grid.\896\ The Commission would
consider such proposals on a case-by-case basis. Moreover, a primary
purpose of Order No. 890 is to ``increase the ability of customers to
access new generating resources and promote efficient utilization of
transmission by requiring an open, transparent, and coordinated
transmission planning process.'' \897\
---------------------------------------------------------------------------

    \895\ April 14 Order, 107 FERC ] 61,018 at P 147, 148 n.142.
    \896\ See, e.g., Westar Energy, Inc., 115 FERC ] 61,228, order
on reh'g, 117 FERC ] 61,011 (2006), order on further reh'g, 118 FERC
] 61,237 (2007) (concerning such mitigation proposed in the context
of a disposition of jurisdictional facilities).
    \897\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 3.
---------------------------------------------------------------------------

    775. In particular, we believe recent actions we took in Order No.
890 address the Carolina Agencies' proposal that mitigated utilities be
required to investigate and report on transmission expansion or other
actions that could remove structural impediments exacerbating market
power. In Order No. 890, the Commission adopted a number of reforms
designed to mitigate transmission market power, including a requirement
that all transmission providers develop a coordinated, open and
transparent transmission planning process that would, among other
things, enable customers to request studies evaluating potential
upgrades or other investments that could reduce congestion or integrate
new resources and loads.\898\ The requests for these

economic planning studies and the responses will be posted on the
transmission provider's OASIS site, subject to confidentiality
requirements.\899\ We believe these steps may assist in reducing
structural impediments that contribute to market power.
---------------------------------------------------------------------------

    \898\ Id. at P 544.
    \899\ Id. at P 546 (to be codified at 18 CFR 37.6(b)(2)(iii)).
---------------------------------------------------------------------------

b. First-Tier Markets
Commission Proposal
    776. In the NOPR, the Commission sought comment on whether it is
appropriate to continue to allow sellers that are subject to mitigation
in their home control area to sell power at market-based rates outside
their control area. The Commission asked if this represents undue
discrimination or otherwise constitutes ``withholding'' in the home
control area that is inconsistent with the FPA's mandate that rates be
just, reasonable and not unduly discriminatory, or, instead, if this
reflects economically efficient behavior and encourages necessary
trading within and across regions, particularly in peak periods when
marginal prices rise above average embedded costs.
    777. The Commission also asked if it should find that any seller
that has lost market-based rate authority in its home control area
should be precluded from selling power at market-based rates in
adjacent (first tier) control areas.
Comments
    778. A number of commenters state that there is no basis for
prohibiting a mitigated seller from selling excess power at market-
based rates in adjacent control areas, as the Commission will have
determined that the seller does not have the ability to exercise market
power in any of those adjacent control areas.\900\ Some commenters also
claim that prohibiting these sales would limit market activity and
constrain the benefits of competitive pricing by excluding sellers from
markets in which they do not possess market power.\901\
---------------------------------------------------------------------------

    \900\ Ameren at 18-19; see also Duke at 12 (citing Florida Power
Corp., 113 FERC ] 61,131 at P 24 (2005)); Southern at 56; PNM/Tucson
at 19-20 ; Xcel at 5-6; EEI at 33; and PPL reply comments at 15-16.
    \901\ MidAmerican at 22-23; PPL at 24-25; EEI at 28.
---------------------------------------------------------------------------

    779. PNM/Tucson contends that prohibiting sales of available
capacity at market-based rates in adjacent control areas where the
seller does not possess market power would be a disproportionate
response that would render the Commission's market-by-market analysis
meaningless.\902\ Moreover, PNM/Tucson and MidAmerican warn that
independent power producers have no incentive to invest in new
resources in markets where prices are effectively constrained to the
level of another entity's embedded costs.\903\
---------------------------------------------------------------------------

    \902\ PNM/Tucson at 19-20.
    \903\ MidAmerican at 22, PNM/Tucson at 17.
---------------------------------------------------------------------------

    780. Southern asks the Commission not to impose mitigation that
will create flaws in markets that may have periods of genuine temporary
scarcity but where the seller does not possess market power.\904\
Southern states that prohibiting a mitigated seller from responding to
price signals in neighboring markets will adversely affect efficient
resource development and contradicts the Commission's desire to promote
competitive markets and resource adequacy.\905\ Further, foreclosing
markets otherwise accessible to resources nominally dedicated to native
load service may impair the optimization of those resources by
impairing a full response to price signals. This, Southern adds, would
harm native load customers because the mitigated utility would be
unable to optimize surplus resources, as mandated through State retail
credit obligations, thereby depriving retail customers of the benefits
of system optimization.\906\
---------------------------------------------------------------------------

    \904\ Southern at 64-65.
    \905\ Id. at 57.
    \906\ Id.
---------------------------------------------------------------------------

    781. Another commenter agrees that a mitigated seller should be
allowed to sell available capacity at market-based rates in markets
where that seller does not possess market power, provided that this
does not raise prices in the mitigated region.\907\ This commenter
asserts that such sales facilitate regional trading and market
efficiency in developing competitive markets.\908\ Another commenter
contends that unless ``costs'' are defined in a way that effectively
allows competitive market rates to be charged, revoking a seller's
market-based rate authority in markets where the seller does not
possess market power would reduce the mitigated seller's incentive to
supply available power to the market, deprive the mitigated seller and
its customers of legitimate economic rent, subsidize those buyers with
access to the mitigated rates, and create a rationing problem among
buyers with access to the mitigated-rate power.\909\
---------------------------------------------------------------------------

    \907\ Drs. Broehm and Fox-Penner at 16. The NYISO also supports
market-based rate sales in competitive markets where the mitigated
seller does not possess market power. According to the NYISO, with
regard to the NYISO, PJM Interconnection, LLC and ISO-New England,
the Commission can ensure that sellers respond to market price
signals by designing market power mitigation in a manner that will
permit even mitigated sellers to receive the applicable market
clearing price. For example, any cost-based rate mitigation imposed
could limit the maximum bids that the seller may submit without
limiting the revenues that the mitigated seller may receive. NYISO
at 10.
    \908\ Drs. Broehm and Fox-Penner at 16. See also PPL at 24;
MidAmerican at 17; E.ON U.S. at 12-13; EEI at 28; Duke at 11.
    \909\ Dr. Pace at 21.
---------------------------------------------------------------------------

    782. MidAmerican states that, if the Commission were to eliminate a
seller's market-based rate authority in all regions, the mitigated
prices should only apply prospectively. MidAmerican reasons that
existing transactions negotiated in the absence of market power should
not be altered, since these previously-negotiated transactions would
have no impact on a seller's willingness to make future sales to
customers in the home control area.\910\
---------------------------------------------------------------------------

    \910\ MidAmerican at 23.
---------------------------------------------------------------------------

    783. Other commenters oppose allowing mitigated sellers to sell at
market-based rates outside the home control area on the basis that it
encourages and provides incentives for the seller to engage in physical
or economic withholding of its generation output in the home control
area. These commenters indicate that their concerns in this regard
would be addressed if mitigation is combined with a requirement that
the mitigated seller make power available to customers within the
mitigated control area. APPA/TAPS state that, absent a ``must offer''
requirement, it is not clear that prohibiting mitigated sellers from
making market-based sales outside their home control areas would
necessarily prompt the mitigated seller to sell power in its home
control area.\911\
---------------------------------------------------------------------------

    \911\ APPA/TAPS at 43.
---------------------------------------------------------------------------

    784. However, APPA/TAPS ask the Commission not to rule out across-
the-board revocation of market-based rate authority as it may be
necessary to motivate mitigated sellers to undertake the kind of
structural measures needed to mitigate market power on a long-term
basis. If the Commission adopts a policy to revoke or condition market-
based rate authority beyond the home control area, APPA/TAPS state that
the policy should not be limited to just the first-tier control area.
Rather, the revocation or conditions should apply to any market where
the seller can use generation located in or originally delivered to its
control area to sell outside that mitigated area.\912\
---------------------------------------------------------------------------

    \912\ APPA/TAPS at 43-44.
---------------------------------------------------------------------------

    785. The Carolina Agencies state that a generic prohibition on
market-based rate sales outside the mitigated market

appears likely to inhibit regional trade to a greater extent than is
necessary to protect the interests of embedded LSEs.\913\ Both the
Carolina Agencies and NC Towns state that there is no clear need to
prohibit mitigated sellers from making market-based sales outside their
home control areas if a ``must offer'' requirement is adopted.\914\
According to the Carolina Agencies, a mitigated seller should be free
to engage in market-based rate sales in other control areas as long as
that utility has provided embedded LSEs a reasonable opportunity to
purchase capacity and/or energy.
---------------------------------------------------------------------------

    \913\ Carolina Agencies at 19.
    \914\ Id. at 18-19; NC Towns at 7.
---------------------------------------------------------------------------

    786. As to any claim that it would be unduly discriminatory for the
Commission to deny or condition the market-based rate authority of a
utility that passes the screens in markets beyond its mitigated home
control area, APPA/TAPS and the Carolina Agencies submit that mitigated
sellers are not similarly-situated to the other utilities selling at
market-based rates in those other competitive markets. They assert that
other sellers' market-based rate sales do not implicate those sellers'
ability to withhold supply from disfavored wholesale customers in a
mitigated control area. Moreover, they argue that it elevates the
importance of the screens above the FPA to argue that granting
unconditioned market-based rate authority to one seller who passes the
screens obligates the Commission to grant unconditioned authority to
all who pass the screens. In their view, the Commission would be
failing its duty under the FPA if it permitted physical withholding by
a dominant utility, as such actions would be unjust, unreasonable, and
unduly discriminatory.\915\
---------------------------------------------------------------------------

    \915\ APPA/TAPS and Carolina Agencies supplemental comments at
36-37. NRECA adds that ``the FPA does not bar--as unduly
discriminatory--Commission imposition of remedies in a non-
discriminatory fashion, including banning sales outside the
mitigated market: the statute protects buyers, not sellers, from
undue discrimination.'' NRECA reply comments at 41; see also
Carolina Agencies at 16 (citing the OATT Reform NOPR at P 210 and
n.203).
---------------------------------------------------------------------------

    787. ELCON advocates suspending any mitigated seller's market-based
rates in all markets it can access. Short of this long-term fix, ELCON
asserts that other proposals such as ``must offer'' requirements will
be prone to fail because of likely unintended consequences.\916\
---------------------------------------------------------------------------

    \916\ ELCON at 11.
---------------------------------------------------------------------------

    788. Morgan Stanley favors requiring mitigated sellers to post the
mitigated price and other material terms on a publicly-available Web
site for all sales to be made from the units that are part of the
portfolio covered by the Commission's market power finding, regardless
of where the actual sale sinks.\917\ Morgan Stanley asserts that
effective mitigation can only occur if it is imposed on all sales from
a mitigated supplier's generation portfolio and urges the Commission
not to focus on who the purchaser is or where the power sinks.\918\ If
a mitigated seller chooses to offer its excess power only outside the
mitigated region and simply refuses to sell inside its home market,
Morgan Stanley is concerned that the market in the ``home'' territory
would be even less competitive than if the seller were allowed to sell
there on an unmitigated basis.\919\
---------------------------------------------------------------------------

    \917\ Morgan Stanley at 7; Morgan Stanley reply comments at 6.
    \918\ Morgan Stanley reply comments at 6. The Oregon Commission
responds that such broad mitigation would not benefit wholesale
customers in the mitigated region and would harm the supplier's
native retail load by transferring wealth to marketers like Morgan
Stanley. Oregon Commission reply comments at 4; see also MidAmerican
reply comments at 13-14 (arguing that Morgan Stanley's proposal
would be an arbitrary and capricious redistribution of income and
allow windfall arbitrage profits).
    \919\ Morgan Stanley at 6.
---------------------------------------------------------------------------

    789. CAISO states that, where a competitive supply of imports into
a mitigated control area does not exist, market power mitigation
mechanisms or other incentive schemes will be necessary to ensure that
the local supplier makes all of its capacity available to supply energy
and ancillary services to the home control area.\920\ CAISO asks the
Commission to provide greater clarity on the extent to which the
antifraud and anti-manipulation rules adopted in Order No. 670 prohibit
economic and physical withholding of resources. In particular, CAISO
asks the Commission to provide greater clarity on the deceptive conduct
criteria it would use to determine whether a particular case of
physical or economic withholding would be a violation of the new Part
47 regulations. CAISO explains that greater clarity in this area will
help ISO and RTO market monitors in developing effective RTO/ISO market
power mitigation rules tailored for the types of physical and economic
withholding that are not addressed under Part 47 regulations.
---------------------------------------------------------------------------

    \920\ CAISO at 16.
---------------------------------------------------------------------------

Commission Determination
    790. After careful consideration of the arguments raised by
commenters, we will retain our current policy and limit mitigation to
the market in which the seller has been found to possess, or chosen not
to rebut the presumption of, market power. We will not place
limitations on a mitigated seller's ability to sell at market-based
rates in balancing authority areas in which the seller has not been
found to have market power.
    791. The Commission authorizes sales of electric energy at market-
based rates if the seller and its affiliates do not have, or have
adequately mitigated, horizontal and vertical market power in
generation and transmission, and cannot erect other barriers to entry.
As the Commission has explained, ``The consideration of market power is
important in determining if customers have genuine alternatives to
buying the seller's product.'' \921\ Commenters favoring revocation of
a mitigated seller's market-based rate authority in markets where there
has been no finding of market power, as well as those supporting
broadening mitigation to first-tier markets, have not provided a
sufficient legal basis for such a policy. Where the record demonstrates
that a seller does not have market power in a market, or has adequately
mitigated any market power, the Commission has authorized such a seller
to transact under market-based rates.\922\ As the April 14 Order
explained, ``Market-based rates will not be revoked and cost-based
rates will not be imposed until there has been a Commission order
making a definitive finding that the applicant has market power * * *''
\923\
---------------------------------------------------------------------------

    \921\ Louisville Gas & Elec. Co., 62 FERC at 61,144.
    \922\ Florida Power Corp., 113 FERC ] 61,131 at P 24.
    \923\ April 14 Order, 107 FERC ] 61.018 at P 149.
---------------------------------------------------------------------------

    792. We recognize that wholesale customer commenters are generally
concerned that allowing mitigated sellers to sell outside their
mitigated markets at market-based rates could encourage such sellers
not to offer generation for sale within the mitigated market. However,
we agree with the Carolina Agencies that a generic prohibition against
such sales could inhibit regional trade to a greater extent than
necessary to protect captive LSEs. We note that even some wholesale
customer commenters acknowledge that it is not clear that prohibiting
mitigated sellers from making market-based sales beyond their mitigated
region would prompt the mitigated seller to sell power in the mitigated
market. For these reasons, we limit mitigation to the areas in which
the seller has market power.
    793. For the reasons stated above, we disagree with Morgan
Stanley's assertion that effective mitigation can only occur if it is
imposed on all sales from a mitigated seller's generation portfolio. In
addition, though we appreciate CAISO's request for greater clarity on
the criteria the Commission

will use to determine whether economic and physical withholding has
occurred, such a determination must be made on a case-by-case basis.
c. Sales That Sink in Unmitigated Markets
Commission Proposal
    794. In the NOPR, the Commission stated that some companies have
proposed limiting mitigation to sales that ``sink in'' the mitigated
market, that is, so that mitigation would only apply to end users in
the mitigated market. However, in MidAmerican Energy Company,\924\ the
Commission stated that limiting mitigation to sales that ``sink in''
the mitigated market would improperly limit mitigation to certain
sales, namely, only to sales to buyers that serve end-use customers in
the mitigated market. The Commission reasoned that limiting mitigation
in this manner would improperly allow market-based rate sales within
the mitigated market to entities that do not serve end-use customers in
the mitigated market.\925\ The Commission stated that such a limitation
would not mitigate the seller's ability to attempt to exercise market
power over sales in the mitigated market and is inconsistent with the
Commission's direction in the April 14 and July 8 Orders. On rehearing
of the April 14 Order, it was argued that access to power sold under
mitigated prices should be restricted to buyers serving end-use
customers within the relevant geographic market in which the seller has
been found to have market power. In particular, arguments were made
that a seller should not be required to make sales at mitigated prices
to power marketers or brokers without end-use customers in the relevant
market. In the July 8 Order, the Commission rejected the suggestion
that mitigated sellers be restricted to selling power only to buyers
serving end-use customers, and has since rejected tariff language that
proposes to do so.
---------------------------------------------------------------------------

    \924\ 114 FERC ] 61,280 at P 29-33 (2006), reh'g pending
(MidAmerican).
    \925\ Id. at P 31.
---------------------------------------------------------------------------

    795. In the NOPR, the Commission sought comment on whether it
should modify or revise its current policy. The Commission sought
comment on whether and, if so, how it should allow market-based rate
sales by a mitigated seller within a mitigated market if those sales do
not ``sink'' in that control area.
Comments
    796. While some commenters generally seek to allow a mitigated
seller to make sales at market-based rates if those sales do not
``sink'' in the mitigated market, other commenters support the current
policy of requiring all of a mitigated supplier's sales in the
mitigated market to be cost-based. The State AGs and Advocates go even
further and encourage the Commission to apply its mitigation policy to
all wholesale sales that sink in the mitigated market, regardless of
the seller, arguing that the impact of market power on price is market-
wide in scope.\926\
---------------------------------------------------------------------------

    \926\ State AGs and Advocates at 43-44.
---------------------------------------------------------------------------

    797. APPA/TAPS support the current policy of requiring cost-based
rate mitigation for all sales in the mitigated market regardless of
whether the sales ultimately sink in an unmitigated market. APPA/TAPS
argue that allowing market-based rate sales in a mitigated market would
yield unlawful rates because the mitigated seller would be making
market-based rate sales in a market where it has, or is presumed to
have, market power.\927\
---------------------------------------------------------------------------

    \927\ APPA/TAPS at 47-48. To limit marketers' arbitrage
opportunities, APPA/TAPS suggest limiting any ``must offer''
obligation to sales that sink in the seller's control area. The
seller could make additional sales in its control area at the cost-
based rate, but would not be obligated to do so because purchasers
for loads outside of the seller's control area would presumably have
other power supply options.
---------------------------------------------------------------------------

    798. The NYISO agrees that mitigation should not be limited to
sales that ``sink in'' the mitigated market, at least in clearing price
auctions such as those administered by the NYISO. The clearing prices
are established by the interaction of all eligible buyers and sellers,
and the NYISO reasons that there would be no practical basis, nor
economic justification, for carving out marketers or brokers who may
export their purchases.\928 \
---------------------------------------------------------------------------

    \928\ NYISO at 8-10. The NYISO suggests that the Commission can
avoid concerns regarding exports to neighboring markets by applying
any cost-based mitigation it imposes to limit the maximum bids that
the seller may submit, without limiting the revenues that the
mitigated seller may receive. Id.
---------------------------------------------------------------------------

    799. The Carolina Agencies express concern that limiting mitigation
to sales that sink in a mitigated market would reduce supply options
for LSEs embedded in that mitigated market. They contend that
unrestricted exports from a mitigated market increase the prices
charged by other sellers due to scarcity. Even when a sale sinks
outside the mitigated market, the Carolina Agencies claim that round-
trip gaming will continue, and they question the Commission's ability
to effectively detect and stop such gaming by attempting to trace
megawatts via NERC tag data or other means. However, the Carolina
Agencies submit that with a properly structured ``must offer''
requirement in place, there is no reason to bar market-based rate sales
based on the location of the point of sale or even the identified
sink.\929\
---------------------------------------------------------------------------

    \929\ Carolina Agencies at 20.
---------------------------------------------------------------------------

    800. Other commenters support allowing sales of power within a
mitigated market that nonetheless sink in unmitigated markets (i.e.,
markets where the seller does not possess market power) to be made at
market-based rates.\930\ As discussed below, they offer various
proposals on what factors should determine whether a sale should be
priced at market-based rates.
---------------------------------------------------------------------------

    \930\ See, e.g., PPL reply comments at 16.
---------------------------------------------------------------------------

    801. Several commenters state that the relevant inquiry should be
whether the power serves load (sinks) in a control area where
generation market power is an issue. MidAmerican and the Oregon
Commission submit that there is no reason to mitigate sales over which
the seller is unable to exercise market power.\931\ Rather, MidAmerican
asks the Commission to refocus on whether a seller could exercise
market power, not on the physical location where a change in ownership
of energy occurs. MidAmerican argues that if a mitigated seller cannot
exercise market power over sales made directly in an outside
competitive market, such seller cannot exercise market power over sales
made in its home control area that are for export to that outside
competitive market.\932\ Rather than protecting the ultimate buyers,
these commenters submit that mitigating such sales would transfer
wealth from the mitigated seller to subsequent entities that can charge
market prices in later transactions.\933\
---------------------------------------------------------------------------

    \931\ MidAmerican at 26; Oregon Commission reply comments at 5;
see also Westar at 20.
    \932\ MidAmerican at 25-26; see also Dr. Pace at 18-20.
    \933\ MidAmerican at 26; Oregon Commission reply comments at 5.
---------------------------------------------------------------------------

    802. MidAmerican and the Oregon Commission claim that if the
Commission requires mitigated sellers to mitigate all their sales in
the mitigated market such an outcome would encourage gaming, such as
round-trip or ricochet transactions.\934\ MidAmerican maintains that
such gaming can be eliminated when mitigation applies only to sales
sinking within the mitigated control area.\935\
---------------------------------------------------------------------------

    \934\ MidAmerican at 26-27; Oregon Commission reply comments at
6.
    \935\ MidAmerican at 27.
---------------------------------------------------------------------------

    803. Duke, E.ON U.S., Westar, Mid-American, Ameren, and Xcel all
assert that the availability of supply alternatives to wholesale
purchasers should be a determining factor when deciding whether to
permit market-based rates for sales that sink in

unmitigated markets.\936\ E.ON U.S. points out that the Commission in
the April 14 Order noted that the foundation of the market power
analysis under the Delivered Price Test is the ``destination market.''
As such, E.ON U.S. asserts that a relevant factor in determining
whether to permit a sale at market-based rates should be the level of
choice in supply available to the purchaser, not where the product
originates.\937\
---------------------------------------------------------------------------

    \936\ Duke at 13; E.ON U.S. at 6; Westar at 20; MidAmerican at
25; Ameren at 19-20; and Xcel at 13.
    \937\ E.ON U.S. at 6.
---------------------------------------------------------------------------

    804. Westar contends that when the buyer is purchasing to serve
load in control areas where the seller lacks market power, the buyer
presumably has access to other competitive alternatives and has
voluntarily entered into the agreement. Therefore, the Commission
should not second guess the buyer's decision.\938\ Westar adds that
prohibiting all sales in the mitigated control area elevates form over
substance because parties can simply alter the implementing details of
their transaction to accomplish the same result.\939\
---------------------------------------------------------------------------

    \938\ Westar at 20.
    \939\ Id. at 21.
---------------------------------------------------------------------------

    805. Westar argues that the Commission's stated concern in
MidAmerican with a seller's ``ability to attempt to exercise market
power over sales in its control area'' is misplaced; the Commission's
traditional market power analysis is only concerned with the
``incentive'' and ``ability'' to exercise market power, not with
``attempts'' to do so.\940\ As such, it is ``ability'' and not
``attempts'' to exercise market power that is a key determinant of
whether an actual market power problem exists.
---------------------------------------------------------------------------

    \940\ Id. at 21 (citing MidAmerican Energy Company, 114 FERC ]
61,280 (2006), reh'g pending; Exelon Corp., 112 FERC ] 61,011, at P
134 (``As we have said in numerous contexts, we are concerned about
a merger's effect on the merged firm's ability and incentive to harm
competition.''), order on reh'g, 113 FERC ] 61,299 (2005); Oklahoma
Gas and Electric Company, 105 FERC ] 61,297, at P 35 (2003) (``Both
the ability and incentive to raise prices by restricting access are
necessary for a vertical market power problem to exist.''); NiSource
Inc., 92 FERC ] 61,068, at 61,239 (2000) (``Because the merged
company must have both the ability and incentive to adversely affect
electricity prices or output, and the merged company will lack the
former, no further findings are necessary.'')).
---------------------------------------------------------------------------

    806. Westar further claims that the Commission is not bound by
precedent to prohibit all market-based rate sales in a mitigated
control area, pointing out that the Commission has accepted four
proposals after the July 8 Order that limit mitigation to sales that
sink in the mitigated control areas.\941\ Moreover, Westar claims that
the July 8 Order appears to address the question of who may buy power
from a mitigated seller, not where mitigated sales can occur. This
leads Westar to conclude that the Commission did not originally intend
to preclude mitigated sellers from making market-based sales to buyers
over which the seller lacks generation market power, regardless of
where the sales occur. Westar urges the Commission to return to this
principle.\942\
---------------------------------------------------------------------------

    \941\ Id. at 22 (citing American Electric Power Service Corp.,
Docket Nos. ER96-2495-026, et al. (Jan. 13, 2006) (letter order
accepting uncontested settlement applying mitigation to sales that
sink in the mitigated control area); AEP Power Marketing, Inc., 112
FERC ] 61,320 (2005) (dismissing rehearing requests as moot because
of utility's commitment to mitigate sales ``that sink within AEP-
SPP''); South Carolina Electric and Gas Company, 114 FERC ] 61,143
(2006) (order accepting utility's commitment to mitigate sales that
``sink'' in its home control area, subject to a compliance filing);
LG&E Energy Marketing, Inc., 113 FERC ] 61,229 (2005) (ordering the
utility to apply the proposed mitigation to sales that sink in the
mitigated control area)).
    \942\ Westar at 22-23.
---------------------------------------------------------------------------

    807. Xcel urges the Commission to focus on the parties' intent and
whether alternative supply options are available to the purchaser at
the time of contracting, rather than focusing on where energy purchased
in the transaction actually sinks in real time. At the time of the
transaction, if the purchaser can confirm: (i) It intends to use the
power outside of the mitigated control area, and (ii) there are
existing transmission arrangements to actually use the power elsewhere,
Xcel maintains that it should not matter what the purchaser
subsequently does with the power in real time.\943\ Xcel and
MidAmerican also favor adopting market-index or proxy based mitigation
as a way to reduce the concern about where sales actually sink when
trying to ensure proper mitigation.\944\
---------------------------------------------------------------------------

    \943\ Xcel at 13. While MidAmerican does not object to Xcel's
proposal, it submits that its own proposal regarding use of market-
based indices would provide additional assurance that a seller would
not manipulate prices by arranging round-trip transactions into a
mitigated control area. MidAmerican reply comments at 19-20.
    \944\ Xcel at 11-138; MidAmerican reply comments at 4.
---------------------------------------------------------------------------

    808. EEI, PPL, PNM/Tucson, and Pinnacle take the position that the
Commission should consider point of delivery when deciding whether to
permit market-based rate sales.\945\ EEI asks the Commission to allow
mitigated sellers to make market-based rate sales if the delivery point
in the contract or sale confirmation is outside the mitigated market,
or if the buyer has transmission service to take the power outside the
mitigated market. In other words, buyers who choose delivery points
inside the mitigated market and do not move the power out will pay
mitigated rates, but buyers who choose delivery points inside the
mitigated market but move the power outside the mitigated market will
pay market-based rates.\946\
---------------------------------------------------------------------------

    \945\ EEI at 38; PPL at 25 (supporting EEI's comments); Pinnacle
at 9; PNM/Tucson at 14-15.
    \946\ EEI at 38.
---------------------------------------------------------------------------

    809. EEI asserts that its proposal is consistent with the
Commission policy that the mitigation must focus on the geographic
market that is mitigated, not the type of customer purchasing the
power. EEI concludes that the proposal will minimize the impacts on
competitive transactions as well as avoid a remedy that will have a
negative impact on the liquidity of the competitive market.\947\
---------------------------------------------------------------------------

    \947\ EEI at 41.
---------------------------------------------------------------------------

    810. PNM/Tucson agree that the Commission should use the point of
delivery as a determining factor. They contend that transmission tags
alone--which they explain are a reliability tool to ensure systems
balance from a transmission perspective--are inadequate to monitor
market transactions or ensure that sales sink outside a mitigated
control area.\948\
---------------------------------------------------------------------------

    \948\ PNM/Tucson at 14-15.
---------------------------------------------------------------------------

    811. PNM/Tucson, Pinnacle, E.ON U.S., MidAmerican and PPL all
generally argue that sales at or beyond the transmission interface of a
mitigated control area should not be mitigated if the seller lacks
market power in the adjacent control area.\949\ MidAmerican asserts
that the Commission's market power analyses demonstrate that the seller
has no market power over sales at the border (sales requiring no
additional transmission to exit the mitigated region).\950\ PNM/Tucson,
Pinnacle and E.ON U.S. maintain that prohibiting market-based rate
sales at these transmission interfaces would prevent cross border sales
at these unique locations and reduce market liquidity in markets where
the seller does not possess market power.\951\
---------------------------------------------------------------------------

    \949\ PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 5-8;
MidAmerican at 29-30; PPL reply comments at 16.
    \950\ MidAmerican at 29-30.
    \951\ PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 8.
---------------------------------------------------------------------------

    812. E.ON U.S. and MidAmerican urge the Commission to view
interface/border transactions as fundamentally different from sales in,
or sinking in, a control area. These commenters reason that, at
transmission interfaces, a buyer has competitive choices from sellers
in both control areas that abut the interface, as well as from any
seller that can transmit power to that interface from any control area.
As a result, buyers taking title to power at a

transmission interface for delivery outside the mitigated control area
have competitive choices that do not require transacting with the
supplier found to have market power within the mitigated control
area(s).\952\ Moreover, E.ON U.S. claims that mitigating transactions
at control area interfaces could reduce a utility's profits from off-
system sales, thereby affecting retail ratepayers by reducing offsets
that affect the costs of their retail rates.\953\
---------------------------------------------------------------------------

    \952\ E.ON U.S. at 6; MidAmerican reply comments at 22-23.
    \953\ E.ON U.S. at 8.
---------------------------------------------------------------------------

    813. PNM/Tucson, Pinnacle, E.ON U.S., and MidAmerican note that the
Commission indicated in LG&E that sales at the border need not be
mitigated along with sales ``wholly in'' a control area.\954\ PNM/
Tucson and MidAmerican urge the Commission to codify in the Final Rule
LG&E's holding that sales at the transmission interface of a mitigated
control area are not ``in'' the control area, and therefore need not be
mitigated.\955\ E.ON U.S. similarly asks the Commission to define sales
``in'' a control area as those where title to power transfers at a
physical location wholly within such control area, and should not
include sales where title transfers at a transmission interface.\956\
---------------------------------------------------------------------------

    \954\ PNM/Tucson at 16; Pinnacle at 8-9; E.ON U.S. at 8;
MidAmerican reply comments at 23.
    \955\ PNM/Tucson at 16; MidAmerican reply comments at 23.
    \956\ E.ON U.S. at 5.
---------------------------------------------------------------------------

    814. Xcel, in comparison, argues that any buyer purchasing power at
a generator bus or elsewhere in a mitigated control area for purposes
of moving that power out of the mitigated market should be treated no
differently than a buyer who takes delivery of purchased power outside
of the mitigated region. According to Xcel, mitigation to discipline
market power is unnecessary in either of these cases and the location
of the delivery point does not matter.\957\
---------------------------------------------------------------------------

    \957\ Xcel at 12.
---------------------------------------------------------------------------

    815. Both Dalton Utilities and the Carolina Agencies state that it
would be wrong to assume that every contract involving a mitigated
supplier is unjust and unreasonable and must be abrogated to protect
consumers.\958\ Dalton Utilities urge the Commission to clearly state
in the final rule that it does not generically abrogate existing long-
term market-based rate wholesale requirements and transmission
contracts, nor is it requiring such abrogation in subsequent
proceedings that revoke the market-based rate authority of a public
utility found to possess market power.\959\ Dalton Utilities asks the
Commission to grandfather existing long-term market-based wholesale
contracts in the final rule.\960\
---------------------------------------------------------------------------

    \958\ Dalton Utilities reply comments at 4-9; Carolina Agencies
at 22-23.
    \959\ Dalton Utilities reply comments at 6, 9.
    \960\ Id. at 6-7. Duke notes its support for the Commission's
current policy of not reforming or abrogating contracts that were
negotiated prior to the time of any finding of market power. Duke
reply comments at 8, n.12.
---------------------------------------------------------------------------

    816. The Carolina Agencies add that the effect on existing
contracts of a decision to retain the current mitigation policy of
prohibiting sales at market-based rates in a mitigated market should be
determined on a case-by-case basis. These entities reason that simply
because market power may exist (or a presumption that it exists has not
been rebutted) does not in every instance mean that the seller actually
abused its market position to extract unreasonable terms from its
purchaser. The circumstances of each contract must be examined to
determine whether its terms reflect the exercise of market power. The
Carolina Agencies and Dalton Utilities conclude that generic abrogation
or reformation of existing agreements is neither warranted nor
consistent with the Commission's manner of resolving other claims of
broad-based discrimination.\961\
---------------------------------------------------------------------------

    \961\ Carolina Agencies at 23; Dalton Utilities reply comments
at 7-9.
---------------------------------------------------------------------------

Commission Determination
    817. In order to protect customers from market power concerns, we
will continue to apply mitigation to all sales in the balancing
authority area in which a seller is found, or presumed, to have market
power. However, as discussed below we will allow mitigated sellers to
make market-based rate sales at the metered boundary \962\ between a
mitigated balancing authority area and a balancing authority area in
which the seller has market-based rate authority under certain
circumstances.
---------------------------------------------------------------------------

    \962\ North American Electric Reliability Corporation. Glossary
of Terms Used in Reliability Standards at 2 (2007), available at
ftp://www.nerc.com/pub/sys/all_updl/standards/rs/Glossary_02May07.pdf
.

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

    818. Commenters advocating allowing market-based rate sales in a
mitigated market provided the power is intended for an unmitigated
market (e.g., applying mitigation only to sales that sink in the
mitigated market) have failed to adequately explain how customers in
the mitigated market would be protected from the potential exercise of
market power. In addition, commenters have failed to adequately address
how the Commission could effectively monitor such sales to ensure that
improper sales were not being made. Indeed, several commenters have
noted the complex administrative problems that would be associated with
trying to monitor compliance with such a policy.\963\
---------------------------------------------------------------------------

    \963\ For example, PNM/Tucson note that transmission tags alone
are inadequate to monitor market transactions. PNM/Tucson at 14-15.
---------------------------------------------------------------------------

    819. Allowing market-based rate sales by a seller that has been
found to have market power, or has so conceded, in the very market in
which market power is a concern is inconsistent with the Commission's
responsibility under the FPA to ensure that rates are just and
reasonable and not unduly discriminatory. While we generally agree that
it is desirable to allow market-based rate sales into markets where the
seller has not been found to have market power, we do not agree that it
is reasonable to allow a mitigated seller to make market-based rate
sales anywhere within a mitigated market. It is unrealistic to believe
that sales made anywhere in a balancing authority area can be traced to
ensure that no improper sales are taking place. Such an approach would
also place customers and competitors at an unreasonable disadvantage
because the mitigated seller has dominance in the very market in which
it is making market-based rate sales.
    820. However, we do recognize that sales made at the metered
boundary for export do lend themselves to being monitored for
compliance, and the nature of these types of sales do not unduly
disadvantage customers or competitors. Prohibiting market-based rate
sales at these metered boundaries of the balancing authority area could
prevent or adversely impact cross border sales at these unique
locations and reduce market liquidity in markets where the seller does
not possess market power. Buyers taking title to power at a metered
boundary for delivery to serve load in a balancing authority area where
the seller has market-based rate authority have competitive choices and
therefore are not required to transact with the seller found to have
market power within the mitigated balancing authority area(s).
    821. Accordingly, we will allow such sales to be made at market-
based rates. Mitigated sellers making such sales must maintain for a
period of five years from the date of the sale all data and information
related to the sale that demonstrates that the sale was made at the
metered boundary between the mitigated balancing authority area and a
balancing authority area in which the seller has market-based rate
authority, that the sale is not intended to serve load in the seller's
mitigated market,

and that no affiliate of the mitigated seller will sell the same power
back into the mitigated seller's mitigated market.
    822. Such an approach properly balances commenters' concerns that
when a buyer purchases power to serve load in markets where the
mitigated seller lacks market power the buyer has access to competitive
alternatives with the Commission's obligation under the FPA to ensure
that rates are just and reasonable. Further, we find that our approach
in this regard does not place an unreasonable burden on the customer,
mitigated seller, or competitors. We also emphasize that the mitigation
we adopt herein is prospective only. In response to Dalton's concern,
we clarify that such mitigation does not modify, abrogate, or otherwise
affect existing contractual agreements.\964\
---------------------------------------------------------------------------

    \964\ See South Carolina Electric and Gas Co., 114 FERC ] 61,143
at P 18 (2006) (accepting mitigation on a prospective basis;
existing long-term agreements remain in effect until terminated
pursuant to their terms); see also April 14 Order, 107 FERC ] 61,018
at P 154; July 8 Order, 108 FERC ] 61,026 at P 145.
---------------------------------------------------------------------------

    823. Further, we disagree with the Carolina Agencies' contention
that short of a ``must-offer'' provision unrestricted exports from a
mitigated market increase the prices charged by other suppliers due to
scarcity. Carolina Agencies' argument would only apply when the market
prices in the first-tier markets are higher than the seller's cost-
based rate in the mitigated market. This situation is not necessarily
always the case and, therefore, the Carolina Agencies' concern may be
based on an unrealistic assumption.
    824. We disagree with MidAmerican and the Oregon Commission's claim
that if the Commission requires mitigated sellers to mitigate all their
sales in the mitigated market this would encourage gaming, such as
round-trip or ricochet transactions. While the Commission issued an
order rescinding Market Behavior Rules 2 and 6,\965\ Order No. 670
finalized regulations prohibiting energy market manipulation pursuant
to the Commission's new Energy Policy Act of 2005 authority. The
Commission emphasized in Order No. 670 that ``the specific prohibitions
of Market Behavior Rule 2 (wash trades, transactions predicated on
submitting false information, transactions creating and relieving
artificial congestion, and collusion for the purpose of market
manipulation), * * * are examples of prohibited manipulation, all of
which are manipulative or deceptive devices or contrivances, and are
therefore prohibited activities under this Final Rule, subject to
punitive and remedial action.'' \966\ Such fraud and manipulative
conduct therefore remains prohibited and subject to the Commission's
anti-manipulation and civil penalty authority.
---------------------------------------------------------------------------

    \965\ Investigation of Terms and Conditions of Public Utility
Market-Based Rate Authorizations, 114 FERC ] 61,165 (2006).
    \966\ Prohibition of Energy Market Manipulation, Order No. 670,
114 ] FERC 61,047 at P 59 (2006).
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d. Proposed Tariff Language
Comments
    825. Several commenters have proposed specific tariff language in
the event the Commission allows market-based rate sales in the
mitigated market or at the border. For example, PNM/Tucson would
require a sale to ``have a contractual point of delivery at or beyond
the transmission interface of the mitigated control area (assuming that
the point of delivery is not in another control area where the seller
is also mitigated).'' \967\ They would also require the seller's
market-based rate tariff to explicitly prohibit efforts to collude with
a third party to sell to customers in the mitigated control area at
market-based rates.\968\
---------------------------------------------------------------------------

    \967\ PNM/Tucson at 15.
    \968\ Id.
---------------------------------------------------------------------------

    826. PNM/Tucson point out that their proposal contains a
significant concession. Under their proposed language, a sale by a
mitigated seller at the generation bus in the mitigated control area
must be made at mitigated rates. They believe this concession is fair
if the Commission insists that market-based rate sales for mitigated
sellers are based on contractual points of delivery at or beyond the
transmission interface of the mitigated control area. In these
companies' view, such an approach would provide needed certainty
through a bright line rule and limit factual disputes and
investigations.\969\
---------------------------------------------------------------------------

    \969\ Id. at 16-17; MidAmerican submits that its proposal would
also provide the ``bright-line'' regulatory certainty sought by PNM/
Tucson. MidAmerican reply comments at 16-18.
---------------------------------------------------------------------------

    827. MidAmerican and Ameren also support using tariff or agreement
language to ensure power sinks outside of the mitigated market.\970\
MidAmerican favors using tariff safeguards and confirmation/oversight
procedures to mitigate a seller's ability to exercise generation market
power, prevent gaming, and protect wholesale customers in the mitigated
region. MidAmerican submits that it has developed and filed market-
based rate tariff provisions and verification and oversight procedures
that can ensure that export transactions sink outside the mitigated
seller's control area.\971\ MidAmerican argues that its approach
correctly focuses on whether the mitigated seller could exercise market
power over transactions that affect entities that purchase on behalf
of, or for re-sale to, loads within the market subject to mitigation,
rather than the geographical location where customers may take
responsibility for transmitting the power to a final destination.
Moreover, MidAmerican claims that its proposal would allow the market
to work efficiently in areas where the mitigated seller's ability to
exercise market power is not an issue. MidAmerican supports a
Commission technical conference to further explore this concept with
interested parties.\972\
---------------------------------------------------------------------------

    \970\ MidAmerican at 28; Ameren at 19-20.
    \971\ Under MidAmerican's proposed tariff revisions: (i)
Counterparties would be required to affirmatively confirm that the
energy sold within MidAmerican's control area will not stay inside
that control area; (ii) MidAmerican energy schedulers will review
NERC tags associated with in-control area sales on a daily basis to
ensure transactions indeed sink outside the mitigated control area;
(iii) if a review of the NERC tags shows that a transaction will
sink inside the mitigated control area, the sale will be
renegotiated at cost-based rates; and (iv) if required by the
Commission, MidAmerican would submit the NERC tag data to the
appropriate market monitor. MidAmerican at 28-29.
    \972\ MidAmerican at 28-29.
---------------------------------------------------------------------------

    828. Several commenters further propose that mitigated sellers be
required to add language to their market-based rate tariffs or to
specific market-based rate contracts to restrict re-sales from sinking
in the mitigated control area.\973\ FP&L argues that requiring such
language would reinforce the idea that re-sales into mitigated control
areas are violations of a Commission-approved tariff that also,
depending on the facts, might violate the Commission's market
manipulation regulations.\974\
---------------------------------------------------------------------------

    \973\ FP&L at 6 (proposing the following tariff language:
``Purchasers are hereby on notice that the sink for any energy or
capacity sale under this Tariff shall not be in the Seller's control
area.''); E.ON U.S. at 10 (proposing ``a simple tariff commitment by
sellers that power sold at a point of delivery within their
mitigated control area will, to the best of their knowledge, sink
elsewhere.''); Ameren at 20 (proposing that agreements governing
market-based rate sales in mitigated markets explicitly state that
the subject power will sink outside the mitigated region, and that
the seller be required to report such sales in its EQR).
    \974\ FP&L at 6.
---------------------------------------------------------------------------

    829. Another commenter agrees that restrictive language in the
market-based rate tariff could prevent re-sales into the mitigated
control area by helping to ensure that any power purchased at market-
based rates within a mitigated control area is exclusively for export
to serve loads beyond the mitigated market. Where the Commission is
concerned that gaming could lead to the

exercise of market power over wholesale customers in the home control
area, this commenter suggests that the Commission reemphasize that
efforts to loop power through an adjacent market area in order to raise
prices to wholesale customers in mitigated areas above competitive
levels is a violation of market-based rate tariffs. Further, this
commenter submits that the Commission may require buyers to confirm
that power purchased at market-based rates in a mitigated control area
is for export, use NERC tag data and transmission scheduling
information to verify when purchased power is being exported from the
home control area, and require oversight by independent market
monitors.\975\
---------------------------------------------------------------------------

    \975\ Dr. Pace at 20-21.
---------------------------------------------------------------------------

Commission Determination
    830. Consistent with our decision above, mitigated sellers choosing
to make market-based rate sales at the metered boundary between a
mitigated balancing authority area and a balancing authority area in
which the seller has market-based rate authority will be required to
commit and maintain sufficient documentation to demonstrate \976\ that:
(1) Legal title of the power sold transfers at the metered boundary
between a mitigated balancing authority area and one in which the
mitigated entity has market-based rate authorization; and (2) any power
sold is not intended to serve load in the seller's mitigated market and
(3) no affiliate of the mitigated seller will sell the same power back
into the mitigated seller's mitigated market. To accomplish these
requirements, mitigated sellers seeking to make market-based rate sales
at the metered boundary between their mitigated balancing authority
area and a balancing authority area in which the sellers have market-
based rate authority must adopt the following tariff provision:

    Sales of energy and capacity are permissible under this tariff
in all balancing authority areas where the Seller has been granted
market-based rate authority. Sales of energy and capacity under this
tariff are also permissible at the metered boundary between the
Seller's mitigated balancing authority area and a balancing
authority area where the Seller has been granted market-based rate
authority provided: (i) Legal title of the power sold transfers at
the metered boundary of the balancing authority area where the
seller has market-based rate authority; (ii) any power sold
hereunder is not intended to serve load in the seller's mitigated
market; and (iii) no affiliate of the mitigated seller will sell the
same power back into the mitigated seller's mitigated market. Seller
must retain, for a period of five years from the date of the sale,
all data and information related to the sale that demonstrates
compliance with items (i), (ii) and (iii) above.

    \976\ Reliance solely on NERC tag data as documentation for such
sales will likely be deemed insufficient as such an approach has not
yet been shown to be either workable or effective.
---------------------------------------------------------------------------

    831. This approach affords necessary protection from market power
abuse for customers in the mitigated markets. Such language reminds all
sellers that gaming resulting in re-sales of any sort by an affiliate
of the mitigated seller into their mitigated balancing authority
area(s) (i.e., by looping power through adjacent markets) are
violations of a Commission-approved tariff that may also, depending on
the facts, violate the Commission's market manipulation regulations.
Such violations may result in penalties being imposed under the market
manipulation regulations and/or the revocation of a mitigated seller's
market-based authority in all markets.

E. Implementation Process

Commission Proposal
    832. In the NOPR, the Commission put forth several proposals to
streamline the administration of the market-based rate program while
maintaining a high degree of oversight. The Commission proposed to
modify the practice of requiring an updated market power analysis to be
submitted within three years of any order granting a seller market-
based rate authority and every three years thereafter by, instead,
putting in place a structured, systematic review based on a coherent
and consistent set of data. First, the Commission proposed to establish
two categories of sellers with market-based rate authorization. Sellers
in the first category, Category 1,\977\ would not be required to file a
regularly scheduled updated market power analysis. The Commission
proposed instead to monitor any market power concerns for Category 1
sellers through the change in status reporting requirement and through
ongoing monitoring by the Commission's Office of Enforcement. In this
regard, the Commission noted that failure to timely file a change in
status report would constitute a violation of the Commission's
regulations and the seller's market-based rate tariff.
---------------------------------------------------------------------------

    \977\ Category 1 sellers would include power marketers and power
producers that own or control 500 MW or less of generating capacity
in aggregate and that are not affiliated with a public utility with
a franchised service territory. Category 1 sellers also must not own
or control transmission facilities other than limited equipment
necessary to connect individual generating facilities to the
transmission grid (or must have been granted waiver of the
requirements of Order No. 888 because the facilities are limited and
discrete and do not constitute an integrated grid), and they must
not present other vertical market power issues. NOPR at P 152.
---------------------------------------------------------------------------

    833. Sellers in Category 2, consisting of all sellers that do not
qualify for Category 1, would be required to file regularly scheduled
updated market power analyses in addition to change in status reports.
The Commission proposed to codify this requirement in its regulations.
Failure to timely file an updated market power analysis would
constitute a violation of the Commission's regulations and the seller's
market-based rate tariff.
    834. Second, to ensure greater consistency in the data used to
evaluate Category 2 sellers, the Commission proposed that the required
updated market power analyses be filed for each seller's relevant
geographic market(s) on a schedule allowing examination of the
individual seller at the same time that the Commission examines other
sellers in the relevant markets and contiguous markets within a region
from which power could be imported. The Commission appended a proposed
schedule for the regional review process, rotating by geographic region
with three regions being reviewed per year. For corporate families that
own or control generation in multiple control areas and different
regions, the Commission proposed that the corporate family would be
required to file an update for each region in which members of the
corporate family sell power during the time period specified for that
region.
    835. Finally, the Commission proposed to require that all updated
market power analyses and all new applications for market-based rate
authority include an appendix listing all generation assets owned or
controlled by the corporate family by control area, listing the in-
service date and nameplate and/or seasonal ratings by unit, and all
electric transmission and natural gas intrastate pipelines and/or gas
storage facilities owned or controlled by the corporate family and
their location.
1. Category 1 and 2 Sellers
Comments
a. Establishment of Category 1 and 2 Sellers
    836. A variety of commenters fully support the Commission's
proposed categorization of sellers into two categories and the
boundaries of those categories. ELCON comments that the Commission's
limited resources should be focused on the dominant players and not
treat every seller as a potential threat. NRECA commends the Commission
for its attempt to

[[Continued on page 40003]]

]

[[pp. 40003-40046]] Market-Based Rates for Wholesale Sales of Electric Energy,
Capacity and Ancillary Services by Public Utilities

[[Continued from page 40002]]

streamline the process.\978\ APPA/TAPS support the proposed categories
but suggest that the Commission clarify that it retains the ability to
determine that a Category 1 seller must still adhere to the triennial
update requirements if, for example, it is dominant in a particular
load pocket. Explaining that its generation and power marketing
activities are only incidental to its mining operations, and that its
market share will likely decline over time, Newmont states that filing
an updated market analysis every three years would be an unnecessary
burden to prepare and a waste of the Commission's time to review.
Newmont finds the 500 MW cutoff a clear, bright line that would be easy
to administer. If the Commission determines it necessary to adjust the
threshold, however, Newmont suggests retaining the 500 MW cutoff with a
further requirement that no more than 250-300 MW be located in any one
control area. Alternatively, there could be some sliding scale
delineation between Categories 1 and 2 based on the size of a control
area, in terms of load, unaffiliated capacity, or both.
---------------------------------------------------------------------------

    \978\ See also EPSA reply comments at 3, 13-14.
---------------------------------------------------------------------------

    837. Financial Companies and Morgan Stanley request that the
Commission release a list of all sellers in each category and the
region in which the Commission believes each seller belongs to help
ensure that sellers have notice of their status and related filing
obligations. These parties also suggest that the Commission hold a
technical conference on commenters' proposals about how to organize the
categories.
    838. FirstEnergy opposes the concept of exempting Category 1
sellers from triennial reporting while continuing the requirement for
Category 2 sellers. FirstEnergy states that there is no reason for the
Commission to require any public utility authorized to sell at market-
based rates to file an updated market power analysis. According to
FirstEnergy, the showing made in the initial market-based rate
proceeding and the change in status rules are adequate, and relieving
Category 1 sellers from filing without abolishing the requirement
entirely would be unduly discriminatory.
    839. On the other hand, the California Commission believes that all
sellers should have to continue filing updated market power analyses;
it states that the assumption that Category 1 sellers do not need the
same level of scrutiny as larger sellers is erroneous, and argues that
the NOPR provides no legitimate justification for creating a disparity
between Category 1 and 2 sellers. The California Commission continues
by stating that reliance solely on market monitoring would not
necessarily be effective in California. It notes that in markets
utilizing LMP, there is a great potential for sellers to exert
``local'' market power, especially in load pockets. In such load pocket
areas, it contends that there is no guarantee that a small seller could
not have market power. Further, it states that a Category 1 seller
could suddenly gain market power due to another seller's withdrawal
from the market and asserts that ``given the number of markets and the
Commission's limited resources, it would seem an enormous task of
monitoring without requiring regular updated market power analyses from
all market participants.'' \979\
---------------------------------------------------------------------------

    \979\ California Commission at 4.
---------------------------------------------------------------------------

    840. Similarly, NASUCA states that there is no basis in the record
to assume that Category 1 sellers would lack market power at all times
and offers examples of when Category 1 sellers could pose a
problem.\980\ NASUCA also warns that there is no apparent limit on the
total amount of exempt generation that could be owned by entities other
than those affiliated with a franchised utility. Specifically, NASUCA
argues that:
---------------------------------------------------------------------------

    \980\ For example, NASUCA asserts that there appears to be a
possibility that a seller with a fleet of newer power plants that
were initially exempted from review would be totally exempt from
subsequent review based on the size of the power plants. These
sellers might at times have market power with respect to ancillary
services. NASUCA further submits that changed circumstances, such as
declining reserve margins, might create opportunities for seemingly
small sellers to exercise market power.

    [U]nder the [Category 1] definition and [change of status]
notice obligations, a ``Category 1'' seller could qualify for
exemption from triennial market power reviews even if its holding
company affiliates--other power marketing and generation entities
that also have ``Category 1'' status--collectively have a share of
generation far larger than 500 MW, and even if the seller has a
retail affiliate without a franchised service territory. Examples
might include a group of ``Category 1'' peaker plant owners in a
constrained area, each owned by a separate entity affiliated with
the same holding company; owners of a fleet of small hydro
facilities, each a separate entity within a holding company
structure; or an assemblage of generation control [sic] by numerous
power marketing subsidiaries, each of which controls less than 500
MW of generation.\981\
---------------------------------------------------------------------------

    \981\ NASUCA at 12. See also NASUCA reply comments at 9-11
(stating that neither the 500 MW exemption, nor the expansion to a
1000 MW exemption, nor the elimination of a horizontal market power
test, should be adopted).

    841. Thus, NASUCA argues that the regulations should be modified or
clarified to prevent this scenario. If the Commission proceeds with its
proposal, NASUCA states that the Commission should consider a much
lower threshold, such as 75 MW.
    842. State AGs and Advocates state that exempting entities, no
matter how small, would conflict with the concept that all sellers
contribute in varying degrees to the existence of market power in a
market.\982\
---------------------------------------------------------------------------

    \982\ State AGs and Advocates reply comments at 14.
---------------------------------------------------------------------------

    843. NASUCA and the California Commission argue that none of the
proponents of an exempt category of sellers have shown how the
exemption meets the Commission's legal requirements.\983\ NASUCA
expresses concern that the blanket exemption for Category 1 sellers
from filing updated market power reviews is inconsistent with the
justification the Commission has previously made to the courts in
support of market-based rates, namely, that the Commission makes a
discrete finding or determination as to each seller's market power, and
periodically reviews it. The California Commission similarly disputes
that the exemption meets the underlying principle found in Lockyer. It
states that the Ninth Circuit in that case noted that the Commission's
authority to grant market-based rates is rooted in the integral nature
of the reporting requirements. The California Commission asserts that
the proposed requirement for Category 1 sellers to make a filing only
upon a change in status is inconsistent with the rationale laid out in
Lockyer. It further contends that delegation of ongoing monitoring to
the Commission's Office of Enforcement is vague and contrary to the
underlying principle found in Lockyer. According to the California
Commission, the assumptions underlying the proposed Category 1
exemption (that since Category 1 sellers are smaller in size they do
not need to be subject to the same requirements and scrutiny as larger
sellers of energy, and that `` `Category 2 sellers are the larger
sellers with more of a presence in the market and are more likely to
fail one or more of the indicative screens or pass by a smaller margin
than Category 1 sellers'' ') are insufficient to justify a departure
from the Lockyer rationale.\984\
---------------------------------------------------------------------------

    \983\ NASUCA reply comments at 9-11, California Commission reply
comments at 1-4.
    \984\ California Commission reply comments at 3-4 (quoting NOPR
at P 153).
---------------------------------------------------------------------------

    844. PPM refutes the California Commission's arguments. First, PPM
asserts that the California Commission is wrong in its generalization
that a seller that controls less than 500 MW in a market that utilizes
LMP could exert

local market power. PPM argues that the existence of an LMP market does
not increase the potential for a small generator or marketer to possess
market power; LMP is intended to reduce the ability of a party to
exercise local market power.\985\ Second, PPM states that the
California Commission is wrong when it asserts that Lockyer requires
the Commission to require all sellers to file updated market power
analyses. According to PPM, in Lockyer, the Court found that if the
Commission is going to grant parties the authority to charge market-
based rates, the Commission must continue to monitor and ensure that
the rates charged are just and reasonable. PPM submits that creating a
categorical exemption to reduce the burden on smaller generators and
marketers does not mean that the Commission is eliminating its ability
to effectively monitor the wholesale electric market. It states that
the Commission retains the tools necessary to ensure that all rates are
just and reasonable: all entities with market-based rate authority must
submit electric quarterly reports to the Commission regarding their
transactions; all parties have the right to ask the Commission for
relief under section 206 of the FPA if they believe that rates are
improper or unjust; the Commission may take up an independent review of
any markets which are displaying abnormal characteristics; and finally,
the Commission may require certain parties to file updated market power
analyses if the seller is found to have market power even if the seller
meets the threshold for Category 1 exemption.
---------------------------------------------------------------------------

    \985\ PPM reply comments at 1-3.
---------------------------------------------------------------------------

b. Threshold for Category 1 Sellers and Other Proposed Modifications
    845. While the majority of commenters support the concept of
exempting smaller, Category 1 sellers from filing updated market power
analyses, many seek clarification or modification of the proposal. A
number of commenters propose a threshold other than ownership or
control of 500 MW or less in aggregate. Suggested thresholds include:
500 MW or less of uncommitted capacity (therefore including only that
which is available for sale into markets during peak periods); \986\
500 MW within a particular control area; \987\ 500 MW within a
geographic market; \988\ 500 MW within a particular region; \989\ up to
1000 MW; \990\ less than 1 percent of the installed capacity in a
regional market or 1000 MW in that regional market (whichever is
higher); \991\ or some other formula.\992\ Several commenters urge the
Commission to consider the size of a particular control area or
geographic region or market and whether the geographic market is served
by an RTO/ISO,\993\ and to take into account the difference between
thermal generating capacity and intermittent or non-dispatchable
generation for their ability to impact the competitiveness of a
market.\994\
---------------------------------------------------------------------------

    \986\ See Ormet at 9.
    \987\ See, e.g., PPM at 3-4; AWEA at 3-4.
    \988\ See Constellation at 8-9 (noting that this would be
consistent with the Commission's indicative screen analysis and
regional approach to updated market power analyses).
    \989\ EPSA at 36-37; AWEA at 3-4; Suez/Chevron at 5-10.
    \990\ See Morgan Stanley at 10-13; Financial Companies at 13-14;
Financial Companies reply comments at 7-8. See also Mirant at 12
(recommending 1000 MW per geographic market if the Commission hopes
to have a minimal impact on sellers' compliance costs caused by
eliminating the 18 CFR 35.27(a) exemption).
    \991\ EPSA at 36-37.
    \992\ Constellation at 9-11 (supports changing threshold from
500 MW to the greater of 500 MW or 2 percent of the total generation
capacity in the relevant geographic market; where the geographic
market is an RTO or ISO, change threshold to the greater of 1,000 MW
or 2 percent of the total generation capacity in that market);
Ameren at 21 (supports exempting a company that owns or controls
more than 500 MW but owns or controls less than 20 percent of the
total uncommitted capacity in the relevant geographic market and
also is not affiliated with an entity that owns transmission
facilities in that market).
    \993\ Drs. Broehm and Fox-Penner at 13; Constellation at 9; PPM
at 3-4.
    \994\ AWEA at 3-4 (asserting that companies owning or
controlling thermal generating capacity have a greater opportunity
for impacting the competitiveness of a market than those that own or
control non-dispatchable generation, such as wind power facilities,
that rarely achieve production at nameplate capacity levels); PPM at
4 (same); Financial Companies reply comments at 8-9.
---------------------------------------------------------------------------

    846. PPM argues that without certain modifications to the
Commission's definition of a Category 1 seller, which PPM believes is
too narrowly defined, many generators and marketers may needlessly have
to submit an updated market power analysis. According to PPM, the
Commission should not eliminate the exemption for new generation
(pursuant to 18 CFR 35.27(a)) without expanding the group of generators
and marketers eligible for Category 1 status.\995\ Several commenters
also urge the Commission to allow fact-specific requests for exemption
from filing requirements for those sellers who otherwise would qualify
as Category 2 sellers \996\ or other particular exemptions.\997\
---------------------------------------------------------------------------

    \995\ PPM at 3-5.
    \996\ See Morgan Stanley; Financial Companies.
    \997\ See, e.g., Ormet at 7-11 (exemption for self use/supply,
i.e., capacity used to self supply a corporate affiliate and
presumptively unavailable for sale into markets); TXU at 4-5 (case-
by-case determination of whether a seller's affiliation with an
entity that owns or controls Commission-jurisdictional transmission
presents the possibility of vertical market power concerns).
---------------------------------------------------------------------------

    847. In addition, Constellation proposes specific modifications to
the proposal. First, Constellation requests that the Commission change
the affiliation standard in the definition of Category 1 sellers to be
consistent with other definitions set forth in the NOPR. Because the
proposed language would exclude from the definition of Category 1
sellers any affiliate of a public utility with a franchised service
territory regardless of whether it has captive customers, Constellation
suggests using the defined term ``franchised public utility'' \998\
instead of ``public utility with a franchised service territory.''
Constellation states that the exclusion should only apply to affiliates
of public utilities with captive customers. Second, Constellation
argues that a company should be considered to be a Category 1 seller so
long as it is not affiliated with a ``franchised public utility'' in
the same geographic region. It explains that, with this change, a
company would qualify as a Category 1 seller in California despite the
fact that it is affiliated with a franchised public utility in New
England because any concerns about affiliate abuse would exist only in
the New England market and not in California.\999\ Third, Constellation
suggests that, if operational control over transmission facilities has
been transferred to an RTO/ISO, then a seller's affiliation with the
owner of such transmission facilities should not exclude the seller
from qualifying as a Category 1 seller. Further, Constellation seeks
clarification that the exclusions for owners of transmission facilities
that are simply interconnection facilities, are under operational
control of an RTO/ISO, or are subject to waiver of Order No. 888 and
889, will also apply to affiliates of those transmission owners.
---------------------------------------------------------------------------

    \998\ Proposed 18 CFR 35.36(a)(5) defines a franchised public
utility as ``a public utility with a franchised service obligation
under state law and that has captive customers.''
    \999\ Similarly, Constellation contends that, if a seller and
its affiliates own more than 500 MW of generation capacity in only
one region and less in others, then the seller should be required to
file updated market power analyses in only the region(s) where its
affiliated generation exceeds the threshold.
---------------------------------------------------------------------------

Commission Determination
Adoption of Category 1/Category 2
    848. We adopt the NOPR proposal to create a category of sellers
that are exempt from the requirement to automatically submit updated
market power analyses, with certain modifications. As discussed further

below, this finding is fully consistent with our statutory obligation
to ensure just and reasonable rates and with court decisions construing
that obligation. Moreover, it will streamline the administration of the
market-based rate program by focusing the Commission's resources on
sellers that have a significant presence in the market. It also is
supported by the majority of commenters in this proceeding.
    849. The Commission agrees with Financial Companies and Morgan
Stanley that sellers should have notice of their status and related
filing obligations. However, we believe the criteria we adopt herein
are sufficiently clear so that the vast majority of sellers can easily
determine in which category they fall. Accordingly, the Commission will
not initially compile and release a list of sellers in each category.
Rather, we will require all sellers that believe they fall into
Category 1 to make a filing with the Commission at the time that
updated market power analyses for the seller's relevant market would
otherwise be due (based on the regional schedule for updated market
power analyses adopted in this Final Rule). That filing should explain
why the seller meets the Category 1 criteria\1000\ and should include a
list of all generation assets (including nameplate or seasonal capacity
amounts) owned or controlled by the seller and its affiliates grouped
by balancing authority area.\1001\ The Commission will notice these
filings and provide an opportunity for comment. The Commission will
then act on the seller's filing, either acknowledging that the seller
falls within Category 1 or, if it finds that the seller does not
qualify as a Category 1 seller, directing the seller to file an updated
market power analysis. Subsequently, all Category 1 sellers will not be
required to file regularly scheduled updated market power analyses.
---------------------------------------------------------------------------

    \1000\ These criteria, as modified in this Final Rule, include
wholesale power marketers and wholesale power producers that own or
control 500 MW or less of generation in aggregate per region; that
do not own, operate or control transmission facilities other than
limited equipment necessary to connect individual generating
facilities to the transmission grid (or have been granted waiver of
the requirements of Order No. 888); that are not affiliated with
anyone that owns, operates or controls transmission facilities in
the same region as the seller's generation assets; that are not
affiliated with a franchised public utility in the same region as
the seller's generation assets; and that do not raise other vertical
market power issues.
    \1001\ In the section titled ``Regional Review and Schedule'' we
discuss further how we implement this approach.
---------------------------------------------------------------------------

    850. With regard to sellers that fall into Category 2, these
sellers will be required to file an updated market power analysis based
on the schedule in Appendix D. In our orders acting on the updated
market power analyses, the Commission will make a finding that the
seller is a Category 2 seller, as appropriate.
    851. In addition, with regard to new applications for market-based
rate authority, we also will make a finding regarding the category in
which the seller falls. However, all sellers submitting initial
applications for market-based rate authority must submit the indicative
screens, or accept a presumption of market power in generation, and
must submit a vertical market power analysis.
    852. We reject FirstEnergy's argument that there should be no
requirement for any seller to file an updated market power analysis.
Competitiveness of markets is continuing to change and, therefore, we
are reluctant to rely only on initial market power analyses, change in
status filings, and section 206 complaints in all cases. The burden on
Category 2 sellers is small compared to their market presence and
activities, and is outweighed by the fact that submission of periodic
updated market power analyses enhances Commission oversight and public
confidence in the regulatory process. Thus, we will require the
submittal of regularly scheduled updated market power analyses by those
sellers that have more of a presence in the market and are more likely
to either fail one or more of the indicative screens or pass by a
smaller margin than those that will qualify as Category 1 sellers, or
that may present circumstances that could pose vertical market power
issues, i.e., Category 2 sellers. Through regularly scheduled updated
market power analyses for Category 2 sellers, the Commission is better
able to evaluate the ongoing reasonableness of those sellers' charges
and to provide for an ongoing assessment of their ability to exercise
market power. In the absence of regularly scheduled updated market
power analyses from the Category 2 sellers, it would be more difficult
for the Commission to fulfill its statutory duty to ensure that market-
based rates are just and reasonable and that market-based rate sellers
continue to lack the potential to exercise market power so that market
forces are indeed determining the price.
    853. Because Category 1 and 2 sellers occupy different postures in
terms of their presence in the market, it is not unduly discriminatory
to eliminate the requirement to file a regularly scheduled updated
market power analysis for Category 1 sellers but not Category 2
sellers. Category 1 sellers have been carefully defined by the
Commission to have attributes that are not likely to present market
power concerns: ownership or control of relatively small amounts of
generation capacity; no affiliation with an entity with a franchised
service territory in the same region as the seller's generation
facility; little or no ownership or control of transmission facilities
and no affiliation with an entity that owns or controls transmission in
the same region as the seller's generation facility; and no indication
of an ability to exercise vertical market power. Further, based on a
review of past Commission orders, we are aware of no entity that would
have qualified as a Category 1 seller under this Final Rule but would
nevertheless have failed our indicative screens necessitating a more
thorough analysis. Thus, the Commission has provided a reasoned basis
to distinguish Category 1 sellers from Category 2 sellers. Moreover,
the EQR reporting requirements and change in status filings required
for Category 2 market-based rate sellers will also apply to Category 1
sellers. This will ensure adequate oversight of Category 1 sellers,
even without regularly scheduled updated market power analyses.
Further, we will continue to reserve the right to require an updated
market power analysis from any market-based rate seller at any time,
including for those sellers that fall within Category 1.
    854. In this regard, we agree with PPM that the Commission retains
the tools necessary to ensure that all rates are just and reasonable,
including initial market power evaluations, and ongoing monitoring by
the Commission. For example, as noted above, all sellers with market-
based rates must file electronically with the Commission an EQR of
transactions no later than 30 days after the end of the reporting
quarter and must comply with the change in status reporting
requirement. We note that the reporting requirement relied upon by the
court in Lockyer is the transaction-specific data found in EQRs, which
we continue to require of all sellers, and not updated market power
analyses. Thus, exempting Category 1 sellers from routinely filing
updated market power analyses does not run counter to Lockyer.
    855. With respect to EQR filings, the Commission enhanced and
updated the post-transaction filing requirements from what they were
during the period at issue in the Lockyer case, now requiring
electronic reporting of, among

other things: \1002\ (1) A summary of the contractual terms and
conditions in every effective service agreement for market-based power
sales; and (2) transaction information for effective short-term (less
than one year) and long-term (one year or greater) market-based power
sales during the most recent calendar quarter. We also note that the
Commission has revoked the market-based rate authority of sellers that
have failed to comply with the EQR filing requirements.\1003\ Further,
the Commission has utilized EQR data in determinations relating to
market power. For example, the Commission relied in part on EQR data in
reaching its determination that an ``alternative'' market power
analysis submitted by Duke Power was unpersuasive.\1004\
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    \1002\ Revised Public Utility Filing Requirements, Order No.
2001, 67 FR 31043 (May 8, 2002), FERC Stats. & Regs. ] 31,127
(2002). Required data sets for contractual and transaction
information are described in Attachments B and C of Order No. 2001.
The EQR must be submitted to the Commission using the EQR Submission
System Software, which may be downloaded from the Commission's Web
site at http://www.ferc.gov/docs-filing/eqr.asp. The exact dates for

these reports are prescribed in 18 CFR 35.10b. Failure to file an
EQR (without an appropriate request for extension), or failure to
report an agreement in an EQR, may result in forfeiture of market-
based rate authority, requiring filing of a new application for
market-based rate authority if the seller wishes to resume making
sales at market-based rates.
    \1003\ See Electric Quarterly Reports, 115 FERC ] 61,073 (2006);
Electric Quarterly Reports, 114 FERC ] 61,171 (2006); Electric
Quarterly Reports, 69 FR 57679 (Sept. 27, 2004); Electric Quarterly
Reports, 105 FERC ] 61,219 (2003).
    \1004\ Duke Power, a Division of Duke Energy Corporation, 111
FERC ] 61,506 at P 48, 55 (2005).
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    856. With respect to notices of change in status, in a related
rulemaking proceeding in early 2005, the Commission clarified and
standardized market-based rate sellers' reporting requirement for any
change in status that departs from the characteristics the Commission
relied on in initially authorizing sales at market-based rates.\1005\
In Order No. 652, the Commission required that, as a condition of
obtaining and retaining market-based rate authority, sellers must file
notices of such changes no later than 30 days after the change in
status occurs.\1006\ These requirements are codified in our
regulations, and failure of a market-based rate seller to timely file a
change in status report constitutes a tariff violation. If such a
violation occurs, the Commission has the tools available to impose
remedies, as necessary and appropriate, from the date on which the
tariff violation occurred. Such remedies could include disgorgement of
profits, civil penalties or other remedies the Commission finds
appropriate based on the specific facts and circumstances.
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    \1005\ Order No. 652 at P 47.
    \1006\ As discussed below in the Change in Status section, the
Commission is modifying its regulations to provide that, in the case
of power sales contracts with future delivery, such contracts are
reportable 30 days after the physical delivery has begun.
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    857. We note that any new market-based rate seller must conduct a
horizontal market power analysis for our review. Furthermore, we
reiterate that the Commission retains the ability to require an updated
market power analysis from any seller, Category 1 or 2, at any time.
    858. We also reject those arguments made by the California
Commission, NASUCA, and State AGs and Advocates that all sellers should
continue to be required to file regularly scheduled updated market
power analyses. For the reasons stated above, assertions that the
Commission will be unable to monitor market-based rate sellers without
requiring all sellers to file regularly scheduled updated market power
analyses are unfounded.
    859. In response to the comments of NASUCA and Constellation, we
make the following clarifications. We clarify that, subject to other
conditions discussed below, Category 1 sellers include power marketers
and power producers with 500 MW or less of generation capacity owned or
controlled by the seller and its affiliates in aggregate per region.
Our use of the term ``region'' is intended to be as delineated in the
Regional Review and Schedule attached as Appendix D.
    860. We further clarify that a seller that owns, operates or
controls, or is affiliated with an entity that owns, operates or
controls, transmission facilities in the same region as the seller's
generation assets does not qualify as a Category 1 seller in that
region. This standard applies regardless of whether the total
generation capacity owned or controlled by the seller and its
affiliates is below 500 MW in the region.
    861. Regarding Constellation's point that a company should be
considered Category 1 so long as it is not affiliated with a franchised
public utility in the same region (and meets the other requirements for
Category 1), we concur. Hence, a seller that is affiliated with a
franchised public utility that is not in the same region in which the
seller owns or controls generation assets may qualify as a Category 1
seller for that region if it meets the other Category 1 criteria.
Likewise, a seller that does not own, operate or control, and is not
affiliated with an entity that owns, operates or controls, transmission
in the same region in which the seller owns or controls generation
assets may qualify as a Category 1 seller for that region.
    862. We do not adopt Constellation's proposal that we carve out an
exemption for sellers affiliated with a franchised public utility
without captive customers nor do we adopt the proposal to exempt those
that are affiliated with transmission owners that have given
operational control of their transmission facilities to RTOs/
ISOs.\1007\ Constellation has failed to adequately demonstrate that
sellers affiliated with a franchised public utility without captive
customers and those that are affiliated with transmission owners that
have given operational control of their transmission facilities to
RTOs/ISOs necessarily lack market power in generation.
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    \1007\ We do, however, replace the term ``public utility with a
franchised service territory'' with the defined term ``franchised
public utility.''
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    863. In addition, we will revise the definition of Category 1
sellers in the regulations to include those that own, operate or
control only transmission facilities that are ``limited equipment
necessary to connect individual generating facilities to the
transmission grid.'' While the NOPR included this language in the
preamble, conforming language was inadvertently excluded from the
definition of Category 1 sellers in Sec.  35.36(a)(2) of the proposed
regulations.
Threshold for Category 1
    864. After considering all of the comments regarding the proposed
cutoff between Categories 1 and 2, we believe that 500 MW or less of
generating capacity per region is an appropriate threshold. We will use
this value as a cutoff because, during our 15 years of experience
administering the market-based rate program, there have only rarely
been allegations that sellers with capacity of 500 MW or less had
market power, and when those claims have been raised the Commission's
review has either found no evidence of market power or found that the
market power identified was adequately mitigated by Commission-enforced
market power mitigation rules.\1008\ While some commenters urge the
Commission to adopt either a higher or lower threshold, the Commission
believes that a 500 MW threshold is both a reasonable balance as well
as conservative enough to ensure that those unlikely to possess market
power will be granted market-based rate authority. Moreover, as Newmont
asserts, 500 MW is a clear, bright line that will be easy to
administer.
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    \1008\ Moreover, as noted above, the Commission's indicative
screens are set at conservative levels.

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    865. In addition and in response to commenter requests, we clarify
that the 500 MW threshold is determined by adding all the generation
capacity owned or controlled by the seller and its affiliates within
the same region (as delineated in the Regional Review and Schedule
attached as Appendix D). In keeping with our conservative approach with
regard to which entities qualify for Category 1, we find that aggregate
capacity in a given region best meets our goal of ensuring that we do
not create regulatory barriers to small sellers seeking to compete in
the market while maintaining an ample degree of monitoring and
oversight that such sellers do not obtain market power. In this regard,
we also clarify that although we will use aggregate capacity owned or
controlled in a region to determine which sellers are required to file
regularly scheduled updated market power analyses, we will continue to
evaluate the balancing authority area in which the seller is located
when performing our indicative screens, absent evidence to the
contrary.\1009\
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    \1009\ As we have stated above, where a generator is
interconnecting to a non-affiliate owned or controlled transmission
system, there is only one relevant market (i.e., the balancing
authority area in which the generator is located).
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    866. While we recognize the appeal of a test that takes into
account the size of each geographic market, such as using a percentage
of all capacity (as opposed to a stated MW) cutoff and the use of
uncommitted capacity rather than installed capacity, these
methodologies are inconsistent with a straightforward, conservative
means of screening sellers and consequently would lead to regulatory
uncertainty. As markets and market participants can fluctuate, a
determination of the number of MWs constituting a particular percentage
of capacity in a regional market would have to be constantly
recalculated and the assumptions underlying a determination could lead
to potential challenges. Such an approach would run counter to our
intention to provide certainty to market participants and to streamline
the administration of the program.
    867. The Commission rejects as unnecessary suggestions by AWEA and
PPM that we take into account the differences among generation,
including that classified as intermittent or non-dispatchable, when
calculating the generation capacity of a seller. We believe that many
sellers with wind and other non-thermal capacity will fall below the
500 MW threshold; those that do not may take advantage of simplifying
assumptions and other means to minimize the burden of filing an updated
market power analysis.
    868. With respect to several commenters' desire for fact-specific
exemptions for sellers who otherwise may qualify for Category 2, we
note that the Commission will determine on a case-by-case basis the
category status of each seller with market-based rate authorization. In
our attempt to keep the Category 1 criteria as simple and
straightforward as possible, we may have swept under Category 2
particular sellers whose circumstances make it unlikely that they could
ever exercise market power. As a result, we will entertain and evaluate
individual requests for exemption from Category 2 and make a finding on
the category status of each company. However, if a seller wishes to
request exemption from Category 2, it must make a filing seeking such
an exemption no later than 120 days before its next updated market
power analysis is due. We also will consider any arguments from
intervenors that a particular seller that contends that it qualifies
for Category 1 status based on our definition should nevertheless be
treated as a Category 2 seller and thus be required to continue filing
updated market power analyses.
2. Regional Review and Schedule
Commission Proposal
    869. To ensure greater consistency in the data used to evaluate
Category 2 sellers, the Commission proposed to require ongoing updated
market power analyses to be filed for each seller's relevant geographic
market on a pre-determined schedule. Such a process would allow
examination of the individual seller at the same time that the
Commission examines other sellers in the relevant market and contiguous
markets within a region from which power could be imported. The
Commission appended to the NOPR a proposed schedule for the regional
review process, rotating by geographic region with three regions being
reviewed per year. For corporate families that own or control