that it has allowed significant flexibility in designing ``up to''
rates in the past, and invited comments on whether such flexibility is
still warranted. In particular, the Commission noted that there are
often disputes over which units are ``most likely to participate'' or
``could participate'' in coordinated sales, and asked if it should
continue to allow utilities flexibility in selecting the particular
units that form the basis of the ``up to'' rate. If not, the Commission
asked which units should form the basis of an ``up to'' rate, and how
such a rate should be calculated. In addition, parties were invited to
comment on whether a standard rate methodology should be prescribed
that would allow a seller to avoid a hearing on this issue. The
Commission asked whether a methodology that is based on average costs
(both variable and embedded) would allow a seller to avoid a hearing
because it eliminates the seller's discretion in designating particular
units as ``likely to participate.'' The Commission also inquired as to
whether there are other approaches that would accomplish a similar
objective.
Comments
i. Selecting the Particular Units That Form the Basis of the ``Up to''
Rate
    633. Regarding whether the Commission should continue to allow
utilities flexibility in selecting the particular units that form the
basis of the ``up to'' rate, EEI argues for flexibility because
selection of generating units for these short-terms sales is made with
the goal of minimizing the cost-of-service to the utility's native load
customers.\672\ Several commenters note that the Commission has the
ability to verify the validity of the seller's analysis through an
audit of the company's records to monitor transactions made under the
``up to'' rates.\673\
---------------------------------------------------------------------------

    \672\ EEI at 30-31.
    \673\ MidAmerican at 12; Duke reply comments at 14; EEI reply
comments at 20.
---------------------------------------------------------------------------

    634. Pinnacle asks the Commission to establish a stacking
methodology that determines default units most likely to run while
allowing utilities to propose a different stack based on historical
operational sales data. Pinnacle also urges the Commission to clarify
that the variable cost for the unit can be defined as the system
incremental cost.\674\
---------------------------------------------------------------------------

    \674\ Pinnacle at 11.
---------------------------------------------------------------------------

    635. Other commenters raise concerns with respect to the discretion
given to utilities to choose units used to calculate the ceiling.\675\
They submit that taking only a small snapshot of certain generating
plants to develop cost-based rates will subject buyers to the
discretion of sellers possessing market power.
---------------------------------------------------------------------------

    \675\ See, e.g., NC Towns at 4-5; NRECA at 30-32 (utilities with
a portfolio of generation units of various vintages and operating
characteristics could manipulate the rate ceiling and undermine
mitigation).
---------------------------------------------------------------------------

    636. APPA/TAPS, the Carolina Agencies and AARP oppose allowing
mitigated sellers too much flexibility in designing mitigation methods
on the grounds that such an approach would result in market-based rates
disguised as cost-based mitigated rates.\676\ For mid-term sales, APPA/
TAPS and AARP urge the Commission to require a well-supported analysis
of the units most likely to provide the service.\677\
---------------------------------------------------------------------------

    \676\ APPA/TAPS at 44-45; Carolina Agencies at 24-25; AARP at 8.
    \677\ APPA/TAPS at 46; AARP at 8. Alternatively, both APPA/TAPS
and the Carolina Agencies agree that the Commission's proposal to
use an average embedded cost basis for mid-term sales would be
acceptable and would avoid the need to make determinations about
units most likely to run. APPA/TAPS at 4, 44-47; Carolina Agencies
at 24.
---------------------------------------------------------------------------

    637. The Carolina Agencies ask the Commission to consider whether
pricing service based on the costs of units ``likely to participate''
is sufficiently rigorous to meet the operative statutory standards.
They oppose the ``units most likely to participate'' method on the
basis that the cost and dispatch assumptions used in the underlying
analyses are subjective and difficult to verify. The Carolina Agencies
state that the identified ``likely to participate'' units often wind up
being those units on the system with the highest fixed costs,
regardless of whether the units are of a type that one might expect to
be cycled or ramped for short-term sales. If mitigated utilities are
allowed to continue using this method, the Carolina Agencies urge the
Commission to develop a set of generic guidelines that will yield more
rigorous, less subjective analyses.\678\
---------------------------------------------------------------------------

    \678\ Carolina Agencies at 24.
---------------------------------------------------------------------------

ii. Standard Default Rate Methodology To Allow a Seller To Avoid a
Hearing
    638. With regard to whether a standard methodology should be
prescribed that would allow a seller to avoid a hearing on rate
methodology (e.g., a methodology that is based on average costs (both
variable and embedded)), many commenters urge the Commission to
continue to allow flexibility rather than imposing a standard
methodology based on average costs.\679\
---------------------------------------------------------------------------

    \679\ See, e.g., Westar at 14; MidAmerican at 11; PPL reply
comments at 17-18; Southern at 66-67; Duke at 10; Progress Energy at
10-12; Xcel at 10; EEI at 30-31.
---------------------------------------------------------------------------

    639. Westar argues that the use of a standard methodology based on
average costs would constitute a radical departure from long-settled
Commission policy. Westar states that in Opinion No. 203, the
Commission found that cost-based pricing cannot keep pace with
fluctuating markets,\680\ and that imposing average cost pricing would
only exacerbate the market inefficiencies that result under cost-based
rate making by eliminating pricing flexibility and lowering ceiling
rates.\681\
---------------------------------------------------------------------------

    \680\ Similarly, Southern states that the use of an ``up to''
rate design protects customers against unreasonably high prices (the
purpose of mitigation in the first place), while giving mitigated
sellers the ability to respond to pricing and market dynamics.
Southern at 66; see also EEI reply comments at 19-20; Xcel at 10.
    \681\ Westar at 14, 23.
---------------------------------------------------------------------------

    640. Westar adds that public utilities have the statutory right
under section 205 to propose and file their rates, and that the
Commission lacks the power to impose rates upon public utilities.\682\
Westar therefore opposes standardizing cost-based rates in any manner
that would curb a mitigated seller's section 205 discretion to select a
pricing methodology.\683\ Westar contends that the Commission's section
206 authority to require rate changes is limited to instances where the
Commission finds that the utility's presumptively just and reasonable
existing rate is unjust and unreasonable, and that the Commission's
proposed alternative is just and reasonable.\684\ According to Westar,
the NOPR offers no support for a finding that the wide variety of
previously approved cost-based rate methodologies are no longer just
and reasonable, and must be replaced with a standardized rate
method.\685\
---------------------------------------------------------------------------

    \682\ Id. at 17-18, 23-24 (citing Atlantic City Electric Company
v. FERC, 295 F.3d 1, 9 (D.C. Cir. 2002)).
    \683\ See Westar at 14, n.26 (claiming that an average cost
methodology would eliminate the seller's discretion in designating
particular units as ``likely to participate'' in cost-based sales
and conflicts with utilities' fundamental rights under section 205
of the FPA, and long-standing precedent under the ``units most
likely'' methodology.)
    \684\ Id. at 18 (citing Tennessee Gas Pipeline Company v. FERC,
860 F.2d 446, 456 (D.C. Cir. 1988)); see also id. at 23-24. See also
MidAmerican reply comments at 22.
    \685\ Westar at 24.
---------------------------------------------------------------------------

    641. Duke and PPL support ``up to'' rates \686\ based on the
embedded costs of

the units most likely to provide the service.\687\ According to Duke,
the average costs of all units in a utility's installed generating
capacity base could be quite different than the costs of the specific
units most likely to participate in the short-term wholesale
market.\688\ As such, Duke claims that a system-average cost approach
could force the mitigated seller to charge non-native load customers
less than the cost actually incurred for generating power whenever
incremental costs are greater than average costs, thereby creating a
disincentive for the mitigated seller to market wholesale power in a
control area where it does not have market-based rate authority.\689\
---------------------------------------------------------------------------

    \686\ Drs. Broehm and Fox-Penner also support the use of an ``up
to'' rate because it offers flexibility in conducting transactions.
However, they suggest a methodology that reflects the incremental
cost of new entry to encourage new investment and allow sellers a
reasonable opportunity to earn a fair return on their investment.
According to Drs. Broehm and Fox-Penner, the weakness of setting a
price cap based on embedded cost stems from disputes that arise over
which units are selected as the basis for the price cap. Because the
cost of new entry methodology would allow the price cap to be
formulaic and generic based on the estimate of the annualized total
cost of building a new combustion turbine peaking facility, they
suggest that this approach would minimize discretion in determining
the foundation of a cost-based rate. Drs. Broehm and Fox-Penner at
16.
    \687\ Duke at 10; Duke reply comments at 13-14; PPL reply
comments at 17-18.
    \688\ Duke at 10; see also MidAmerican at 9-11; PPL reply
comments at 17-18; Southern at 66-67.
    \689\ Duke at 10; Duke reply comments at 14.
---------------------------------------------------------------------------

    642. Progress Energy states that it opposes a standardized
methodology because it will not send appropriate price signals to
customers or appropriately compensate the seller for costs where the
seller's generating units or the customer's usage deviates materially
from the standardized methodology. Rather than adopting a ``units most
likely'' approach, Progress Energy prefers a methodology that
identifies units based on load conditions that are more closely
associated with typical market clearing opportunities, between the
average of monthly minimum loads and the average of monthly peak loads.
Such an approach, Progress Energy argues, better represents conditions
where sales occur.\690\
---------------------------------------------------------------------------

    \690\ Progress Energy at 11-12.
---------------------------------------------------------------------------

    643. While supporting flexibility in the design of up-to
rates,\691\ Ameren urges the Commission to prescribe a standard
methodology that sellers could opt to use to avoid prolonged and costly
factual disputes. Ameren asserts that a formula rate based on
information from FERC Form No. 1, where available, and incorporating
the AEP Methodology \692\ could easily form the basis of such a
standard methodology.\693\
---------------------------------------------------------------------------

    \691\ Ameren maintains that allowing mitigated sellers to sell
at cost-based ``up to'' rates from which the seller may discount
adequately mitigates the seller's market power while still allowing
that entity to participate in competitive markets. Ameren states
that ``up to'' rates thus can benefit customers by resulting in a
more robust market. Ameren at 15.
    \692\ American Electric Power Company, 88 FERC ] 61,141 at
61,453-54 (1999). Under this methodology, Ameren explains that a
seller must develop a cost-based annual rate, which then is divided
by 52 to derive a weekly rate, which then is divided by 5 to derive
a daily peak rate, which then is divided by 16 to derive an hourly
peak rate. Ameren at 15.
    \693\ Ameren at 16.
---------------------------------------------------------------------------

    644. Because of concerns with regard to the discretion given to
sellers to choose units used to calculate the cost-based rate, the NC
Towns assert that a standard, system-average ratemaking methodology
would provide a certainty beneficial to both utilities and wholesale
customers, as well as help reduce protracted negotiations and
litigation surrounding parties' concepts of a cost-based rate.\694\
---------------------------------------------------------------------------

    \694\ NC Towns at 4-5.
---------------------------------------------------------------------------

    645. For mid-term sales that carry a capacity charge, the Carolina
Agencies contend that charge should be based on the utility's fully
allocated system-wide cost of capacity. The Carolina Agencies state
that energy associated with the purchased capacity also should be
priced on a system average basis, in order to adhere to the principle
that capacity and energy charges be developed on a consistent
basis.\695\ For these mid-term sales, the Carolina Agencies also
support giving Load Serving Entities (LSEs) located within the
mitigated utility's control area an option between: (1) Locking-in
their price for capacity and/or energy in advance of delivery, at the
mitigated utility's forecasted cost of energy and its cost-based tariff
rate for capacity; or (2) having their charges determined through a
formula rate that would charge purchasers an annually-updated price
reflecting the utility's actual system-wide average costs.\696\
---------------------------------------------------------------------------

    \695\ Carolina Agencies at 11; see also APPA/TAPS at 46-47, n.50
(citing Florida Power & Light Co., 66 FERC ] 61,227 at 61,532
(1994)).
    \696\ Carolina Agencies at 11.
---------------------------------------------------------------------------

    646. The Carolina Agencies add that any change in the Commission's
pricing policy that would yield more reasonable cost-based rates must
be coupled with a ``must-offer'' requirement. Lower cost-based rates
without a concurrent ``must-offer'' requirement, they argue, will only
provide the mitigated utility with an even greater incentive to sell
all its available power beyond the mitigated region, thereby
exacerbating the problems of depleted supply and profiteering by
remaining suppliers.\697\
---------------------------------------------------------------------------

    \697\ Carolina Agencies at 25.
---------------------------------------------------------------------------

    647. For mid-term sales, NRECA asks the Commission to enforce a
matching or consistency principle. Here, NRECA advocates using the same
generating units ``as the basis for the fixed and variable costs in
determining the default embedded-cost rate. In no case should a seller
be allowed to mix high-fixed-cost units with high-variable-cost units
to artificially inflate the embedded-cost rate. If a seller can show
that a portfolio of generating units is likely to be used to provide
service, then the seller might be permitted to use a weighted average
of the fixed and variable costs of the portfolio.'' \698\
---------------------------------------------------------------------------

    \698\ NRECA at 32.
---------------------------------------------------------------------------

Commission Determination
    648. Under the Commission's current policy, the default mitigation
rate for mid-term sales (sales of more than one week but less than one
year) is priced at an embedded cost ``up to'' rate reflecting the costs
of the unit(s) expected to provide the service. The Commission will
retain this approach as the default mitigation for mid-term sales. As
is the case with sales for one week or less, sellers may choose to
adopt the default cost-based rate or propose alternative cost-based
rates.
Selecting the Particular Units That Form the Basis of the ``Up to''
Rate
    649. When a seller adopts the default cost-based mid-term rate or
otherwise proposes a cost-based rate designed on the unit or units
expected to run, the Commission will continue to allow the seller
flexibility in selecting the particular units that form the basis of
the ``up to'' rate. Entities that included various proposals for ``up
to'' cost-based rate methodologies in their comments may propose those
or other methodologies as alternatives to the default cost-based rates,
and the Commission will consider any such proposal on a case-by-case
basis. Any seller proposing an alternative mitigation methodology,
including a cost-based methodology with demand or capacity charges,
carries the burden of justifying its proposal.
    650. We agree with commenters that the Commission has the ability
to verify the validity of the seller's analysis and will continue to do
so in our review of proposed cost-based rates. We will continue to
conduct our own analysis of whether a proposed cost-based rate is just
and reasonable and, if warranted, will set such a proposed rate for
evidentiary hearing where there are issues of material fact.
    651. In response to the concerns raised by some commenters
regarding the discretion given to sellers in the design of ``up-to''
rates, as noted above, the Commission considers all evidence when
reviewing a cost-based rate proposal and, if a company has not
justified selection of certain generating

units, we will not accept the proposed rate. Under the FPA, we have the
authority to accept, reject, or modify a proposed rate based on an
analysis of the specific facts and circumstances.
    652. Further, we find that the approach we adopt in this regard
allowing sellers flexibility in designing ``up to'' rates for purposes
of mitigation, subject to Commission review and approval, is consistent
with the Commission's historical approach to the pricing of cost-based
rates. Because the Commission will have the opportunity to review a
seller's proposed ``up to'' rates, we find that allowing mitigated
sellers flexibility in choosing which units are used to calculate the
proposed cost-based rate will not result in market-based rates being
disguised as cost-based mitigated rates.
    653. In response to Pinnacle's suggestion that the Commission make
available a stacking methodology to be used to determine which units
are most likely to run, we will do so for informational purposes and
will make the methodology available on the FERC Internet site. We also
note, however, that sellers may propose to use their own stacking
methodology.
    654. With regard to the Carolina Agencies' question of whether
pricing service based on the costs of units ``likely to participate''
is sufficiently rigorous to meet the operative statutory standards, we
find that it is. Historically, the Commission has allowed such an
approach and the Carolina Agencies have failed to convince us that,
whether or not the underlying analysis is difficult to verify, the
approach does not result in just and reasonable rates. In addition,
with regard to Carolina Agencies' position with regard to a ``must-
offer'' provision, we discuss proposals for a ``must-offer'' provision
below in the section on protecting mitigated markets.
Standard Default Rate Methodology To Allow a Seller To Avoid a Hearing
    655. Regarding a standard default rate methodology that would allow
a seller to avoid a hearing on rate methodology (e.g., a methodology
that is based on average costs (both variable and embedded)), we note
that the Commission has approved various rate methodologies in the
past. Rather than adopting a specific default rate methodology in this
Final Rule, we affirm that, to the extent the Commission has previously
accepted a particular rate methodology, that methodology is presumed to
be just and reasonable until the Commission makes a contrary
finding.\699\
---------------------------------------------------------------------------

    \699\ In response to Westar, as discussed herein, Commission
precedent supports flexibility in designing cost-based rates and we
are not proposing to standardize cost-based rates here. Upon loss or
surrender of market-based rate authority a seller has a number of
options on how to make wholesale power sales. It can revert to a
cost-based rate tariff on file with the Commission, file a new
proposed cost-based rate tariff, or propose other mitigation. While
we provide a default cost-based rate methodology, we also allow a
seller to submit its own cost-based mitigation. On this basis, a
seller's filing rights under section 205 of the FPA are not eroded
and we are not finding methodologies different from the default
methodology necessarily to be unjust and unreasonable.
---------------------------------------------------------------------------

    656. The Commission will continue to allow sellers flexibility in
designing ``up to'' cost-based rate proposals as alternatives to the
default methodology. Entities that included various proposals for ``up
to'' cost-based rate methodologies in their comments may propose those
or other methodologies as alternatives to the default cost-based rates,
and the Commission will consider any such proposal on a case-by-case
basis.\700\ Any seller proposing an alternative mitigation methodology
carries the burden of justifying its proposal.
---------------------------------------------------------------------------

    \700\ In response to Pinnacle's request for clarification that
the variable cost for the unit can be defined as the system
incremental cost, a mitigated seller can make that argument in
support of an alternative cost-based mitigation methodology.
---------------------------------------------------------------------------

    657. We acknowledge that a standard default rate methodology may
provide, as several commenters suggest, some level of certainty and
avoid prolonged factual disputes. However, we are persuaded by the
concerns expressed by others that designing a standard default rate
methodology based, for example, on average costs may not account for
the actual costs of the units making the sales, and thus may not allow
the seller to recover its costs.
c. Sales of One Year or Greater
Comments
    658. While the NOPR did not propose changes to the default pricing
for long-term sales (sales of one year or more), several entities filed
comments on that issue. APPA/TAPS and AARP reiterate their support for
pricing such sales on an embedded cost basis.\701\ They submit that the
Commission should not depart from its default cost-based mitigation
policy with regard to long-term sales. The NC Towns also favor using
system average costs in a rate base, rate of return model for
determining long term cost-based rates.\702\ Similarly, the Carolina
Agencies assert that long-term sales to embedded LSEs should be priced
at the mitigated utility's fully allocated average embedded cost of
capacity and system average energy costs. As with short-term sales, the
Carolina Agencies urge the Commission to allow the embedded LSEs the
choice between: (1) Locking-in their price at the mitigated utility's
embedded cost rates; or (2) agreeing to have their charges determined
through an annually updated formula rate that reflects the utility's
actual system-wide average costs.\703\
---------------------------------------------------------------------------

    \701\ APPA/TAPS at 47; AARP at 8.
    \702\ NC Towns at 4.
    \703\ Carolina Agencies at 12-13.
---------------------------------------------------------------------------

Commission Determination
    659. We will retain our existing policy for sales of one year or
more (long-term) sales. Specifically, we will continue to require
mitigated sellers to price long-term sales on an embedded cost of
service basis and to file each such contract with the Commission for
review and approval prior to the commencement of service.\704\ We
discuss below the Carolina Agencies' request for a ``must offer''
requirement.
---------------------------------------------------------------------------

    \704\ April 14 Order, 107 FERC ] 61,018 at P 151, 155.
---------------------------------------------------------------------------

d. Alternative Methods of Mitigation
Commission Proposal
    660. In the NOPR, the Commission noted that sellers that are found
to have market power (i.e., after the Commission has ruled on a DPT
analysis), or that accept a presumption of market power, can either
accept the Commission's default cost-based mitigation measures or
propose alternative methods of mitigation. With regard to alternative
methods of mitigation, the Commission asked in the NOPR whether it
should allow as a means of mitigating market power the use of
agreements that are not tied to the cost of any particular seller but
rather to a group of sellers. The Commission asked whether the use of
such agreements as a mitigation measure would satisfy the just and
reasonable standard of the FPA.
Comments
    661. Many commenters favor allowing alternative mitigation methods
tied to the costs of a group of sellers, in particular the Western
Systems Power Pool Agreement (WSPP Agreement),\705\ or transparent
competitive market prices in regional markets. Xcel asserts that the
FPA does not require a mitigated rate to reflect a utility's own cost-
of-service.\706\
---------------------------------------------------------------------------

    \705\ Westar at 26-27; Pinnacle at 10; Ameren at 16-17; PG&E at
22; MidAmerican at 12; Xcel at 8; PPL reply comments at 18; and PNM/
Tucson reply comments at 2-3.
    \706\ Xcel reply comments at 7.
---------------------------------------------------------------------------

    662. E.ON U.S. supports mitigation that sets prices at competitive
market

levels. It claims that cost-based rate mitigation eliminates the
potential for new competition in a mitigated area. In this regard, E.ON
U.S. argues that profits are available only when market prices are
below the mitigated utility's cost-based rates, which reduces the
incentive for investment in new generation as long as buyers can obtain
below market-price energy from generation facilities of the mitigated
utility's ratepayers.\707\ E.ON U.S. adds that mitigation reflective of
competitive prices results in mitigated sellers that are indifferent as
to the buyer's location and competitive price signals to which buyers
can respond accordingly.\708\
---------------------------------------------------------------------------

    \707\ E.ON U.S. reply comments at 3; see also EPSA at 13.
    \708\ E.ON U.S. reply comments at 3.
---------------------------------------------------------------------------

Use of the WSPP Agreement Rate To Mitigate Market Power
    663. Several entities suggest that the rates under the WSPP
Agreement may be an appropriate alternative mitigation method.\709\
Westar asserts that the purpose of the cost-based rate schedules under
the WSPP Agreement is to mitigate perceived market power,\710\ and
notes that the Commission has also accepted use of the WSPP Agreement
to mitigate market power in various contexts.\711\ Westar contends that
parties to the WSPP Agreement may sell under the cost-based rate
schedules of the WSPP Agreement regardless of whether they have a
separate tariff and authorization from the Commission.\712\ Thus,
Westar claims that the NOPR's implicit question whether additional
authorization is needed to make mitigated sales is misplaced since the
WSPP Agreement, as an accepted tariff/rate schedule, establishes the
lawful filed rate.
---------------------------------------------------------------------------

    \709\ See, e.g., Westar at 26 (``The Commission developed and
approved the rates under Schedules A and C of the WSPP Agreement as
`rates that are within the zone of reasonableness and that are just
and reasonable under the [Federal Power Act]''' (citing Western
Systems Power Pool, 55 FERC ] 61,099, at 61,321 (WSPP), order on
reh'g, Western Systems Power Pool, 55 FERC ] 61,495 (1990), aff'd in
relevant part and remanded in part sub nom. Environmental Action and
Consumer Federation of America v. FERC, 996 F.2d 401 (D.C. Cir.
1992), order on remand, 66 FERC ] 61,201 (1994)); Pinnacle at 10;
PG&E at 22.
    \710\ Westar at 26 (citing Pacific Gas and Electric Company, 38
FERC ] 61,242 (1987) (accepting WSPP Agreement on experimental
basis); Pacific Gas and Electric Company, 50 FERC ] 61,339 (1990)
(reducing the ceiling price on economy energy and capacity service
under Schedules A, B and C from $245/MWh to $124/MWh); WSPP; Western
Systems Power Pool, 83 FERC ] 61,099 (1998) (order accepting
amendments); Western Systems Power Pool, 85 FERC ] 61,363 (1998)
(Letter Order accepting revised WSPP Agreement); Western Systems
Power Pool, Inc., 95 FERC ] 61,483 (2001) (order accepting
amendments)).
    \711\ Id. (citing, among other cases, Western Resources, Inc.,
94 FERC ] 61,050, at 61,247 (2001) (accepting WSPP Agreement to
mitigate potential affiliate preference concerns between prospective
merger partners)).
    \712\ Id. at 27 (citing NorthPoint Energy Solutions, Inc., 107
FERC ] 61,181 (2004) (rejecting wholesale cost-based rate tariff as
unnecessary in light of seller's intent to make sales under the WSPP
Agreement)).
---------------------------------------------------------------------------

    664. Pinnacle notes that the WSPP Agreement's price caps were
established based on a system-wide average cost and serve to put
entities without market-based rate authority on a similar footing. In
Pinnacle's view, such agreements enhance liquidity in the regional
markets and facilitate transactions due to the commonality of terms and
conditions.\713\
---------------------------------------------------------------------------

    \713\ Pinnacle at 10.
---------------------------------------------------------------------------

    665. PG&E adds that the WSPP Agreement is the most commonly used
standardized power sales contract in the electric industry. PG&E states
that the WSPP membership continuously updates the WSPP Agreement to
ensure that it represents up-to-date terms for power sales contracts
and notes that the process of updating its terms involves a
diversified, experienced group of market participants focused on
developing an appropriate rate for short-term sales. PG&E concludes
that the terms of the WSPP tariff should be an accepted alternative
rate to the default rate determined by the Commission.\714\
---------------------------------------------------------------------------

    \714\ PG&E at 22.
---------------------------------------------------------------------------

    666. In contrast, APPA/TAPS and AARP oppose alternative mitigation
methods tied to the costs of a group of sellers because there is no
assurance that the group rate would reflect the costs of the seller
subject to mitigation.\715\ Further, APPA/TAPS have concerns that
selecting the appropriate group and obtaining the necessary cost
information could be extremely difficult and controversial.\716\
---------------------------------------------------------------------------

    \715\ APPA/TAPS at 47; AARP at 8.
    \716\ APPA/TAPS at 41.
---------------------------------------------------------------------------

Commission Determination
    667. We will address on a case-by-case basis whether the use of an
agreement that is not tied to the cost of any particular seller but
rather to a group of sellers is an appropriate mitigation measure.
    668. With regard to the WSPP Agreement, as discussed below, we
conclude that use of the WSPP Agreement may be unjust, unreasonable or
unduly discriminatory or preferential for certain sellers. Therefore,
in an order being issued concurrently with this Final Rule, the
Commission is instituting a proceeding under section 206 of the FPA to
investigate whether, for sellers found to have market power or presumed
to have market power in a particular market, the WSPP Agreement rate
for coordination energy sales is just and reasonable in such market.
    669. The WSPP Agreement was initially accepted by the Commission on
a non-experimental basis in 1991,\717\ providing for flexible pricing
for coordination sales and transmission services. Currently, there are
over 300 members of the WSPP Agreement located from coast to coast in
the United States and Canada, including private, public and
governmental entities, financial institutions and aggregators, and
wholesale and retail customers. The WSPP Agreement as it exists today
permits sellers of electric energy to charge either an uncapped market-
based rate (for public utility sellers, they must have obtained
separate market-based rate authorization from the Commission to do
this), or an ``up to'' cost-based ceiling rate. For sellers without
market-based rate authority, the cost-based ceiling rate under the WSPP
Agreement consists of an individual seller's forecasted incremental
cost plus an ``up-to'' demand charge based on the costs of a sub-set
(eighteen sellers) of the original WSPP Agreement members, not
necessarily the costs of any one seller. The up-to demand charge is
based on the average fixed costs of the generating facilities of that
sub-set of WSPP Agreement members; it was designed to reflect the costs
of a hypothetical average utility member in 1989. The only limitations
are: (1) That the trades by Commission-regulated public utilities must
be short-term (lasting one year or less), and (2) that they be priced
at or below the ceilings for sellers without market-based rate
authority.
---------------------------------------------------------------------------

    \717\ WSPP, 55 FERC ] 61,099 (1991). Prior to 1991, the WSPP
Agreement was used for three years on an experimental basis. See
Western Sys. Power Pool, 50 FERC ] 61,339 (1990) (extending the
initial two-year period for an additional year).
---------------------------------------------------------------------------

    670. In a number of recent orders, the Commission accepted the use
of the WSPP Agreement as a mitigation measure subject to the outcome of
the instant proceeding and any determinations that the Commission makes
regarding mitigation in this proceeding. In those cases, we explained
that the WSPP Agreement contains a Commission-approved cost-based rate
schedule that has been found to be just and reasonable. Further, we
noted that parties to the WSPP Agreement have ``the option of
transacting under the WSPP Agreement and thus can make sales under the
WSPP Agreement without any further authorization from the Commission.''
\718\
---------------------------------------------------------------------------

    \718\ Westar Energy, Inc., 116 FERC ] 61,219 at P 33 (2006); The
Empire Dist. Elec. Co., 116 FERC ] 61,150 at P 12 (2006); Xcel
Energy Services, Inc., 117 FERC ] 61,180 at P 49 (2006). However, we
note that a review of EQR data indicates that of 65 sellers
reporting contracts under the WSPP Agreement, 56 sellers reported
sales under that agreement in 2006. Fifty-five of these sellers
reported sales that were identified as market-based rate sales.

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

    671. Though the Commission has allowed sellers to charge flexible
cost-based ceiling rates that are not necessarily based on a particular
seller's own costs (such as the WSPP Agreement ceiling rate), we are
concerned that the evolution and use of the WSPP Agreement ceiling rate
and the evolution of competitive markets have resulted in circumstances
in which the WSPP rate may no longer be just and reasonable for sellers
that are found to have market power or are presumed to have market
power in a particular market, i.e., sellers under the WSPP Agreement
that do not have market-based rate authority or that lose or relinquish
market-based rate authority.
    672. We recognize that the ceiling rate under the WSPP Agreement
has been found to be a just and reasonable cost-based rate by this
Commission as well as by the U.S. Court of Appeals for the D.C.
Circuit,\719\ and that it has been in use for over 15 years by sellers
irrespective of whether they have market power. Nevertheless, the WSPP
Agreement ceiling rate contains extensive pricing flexibility and
relies in part on market forces to set the rate at or below the demand
charge cap, and we believe the WSPP Agreement rate needs to be
revisited in light of its widespread use and changes in electric
markets since 1991. When originally approved by the Commission in 1991,
there were 40 members under the WSPP Agreement; now there are over 300
members. Additionally, the WSPP Agreement is now used by entities not
only in the Western Interconnection, but throughout the continental
United States. Further, the demand charge component of the WSPP
Agreement ceiling rate is based on the costs of only 18 of the original
WSPP members in 1991 (utilizing 1989 data) and does not reflect the
costs of the members that joined the agreement since 1991.
---------------------------------------------------------------------------

    \719\ Environmental Action and Consumer Federation of America v.
FERC, 996 F.2d 401 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    673. For these reasons, concurrently with issuance of this Final
Rule, we are instituting in Docket No. EL07-69-000 a proceeding under
section 206 of the FPA to investigate whether the WSPP Agreement
ceiling rate is just and reasonable for a public utility seller in a
market in which such seller has been found to have market power or is
presumed to have market power. All interested entities will have an
opportunity to address this issue through a paper hearing.
    674. As noted above, the Commission has accepted, subject to the
outcome of this rulemaking proceeding, the use of the WSPP Agreement
ceiling rate as mitigation by a number of sellers. These sellers may
continue to use the WSPP Agreement ceiling rate as mitigation, subject
to refund (and the refund effective date established in Docket No.
EL07-69-000) and subject to the outcome of the section 206 proceeding.
Market-Based Proposals for Mitigation
Comments
    675. Commenters are generally concerned that where the Commission's
current mitigation approach focuses on a seller's own cost of service,
it imposes cost-based rates on a mitigated utility in the home control
area regardless of whether the prices of alternative sources of supply
in the mitigated market exceed the mitigated seller's cost-based
rates.\720\ Rather than relying on cost-based price caps that may bear
no relationship to market conditions, several commenters support
allowing mitigation methods based on transparent competitive market
prices in regional markets.\721\ Commenters suggest various market
indicia that the Commission could use as price proxies in market-based
mitigation alternatives.\722\
---------------------------------------------------------------------------

    \720\ See, e.g., Xcel at 7-9.
    \721\ Duke at 3, 13-14; Drs. Broehm and Fox-Penner at 16-17;
MidAmerican at 12-13; E.ON U.S. at 10-12; Southern at 65, n. 104,
66; Ameren at 14; Xcel at 8-9; PNM/Tucson at 12,14; EEI at 26-29;
Dr. Pace at 23; PPL reply comments at 17-18; and Oregon Commission
reply comments at 2-3.
    \722\ For example, Duke (prices from an adjoining LMP market
that are transparent and contemporaneously available); MidAmerican
(reference prices for the region or from neighboring LMP markets,
published index prices reported by public subscription services, or
prices capped at levels reported in the Commission's Electric
Quarterly Report for sales in neighboring markets); Xcel (proximate
price indexes where available, the WSPP Agreement, a utility's own
sales in areas where it does not possess market power, competitive
solicitations with a sufficient amount of bidders or opportunity
cost pricing); EEI (published index prices at liquid regional
trading hubs or LMP nodal prices for adjacent Day 2 RTOs); the
Oregon Commission (price at a frequently traded energy hub or an LMP
determined by an adjoining RTO would be appropriate price indexes).
If an appropriate and valid price index is not available, the Oregon
Commission would require the seller to make mitigated sales at cost-
based rates.
---------------------------------------------------------------------------

    676. Because different markets may be uncompetitive for different
reasons, and the same mitigation measure is not necessarily equivalent
in all situations, several commenters urge the Commission to consider
more tailored, market-based rate approaches to mitigation on a case-by-
case basis.\723\ MidAmerican suggests that any specific index chosen
could be reflected in the tariff of mitigated sellers (for sales up to
one year) or in agreements filed with the Commission (for sales of one
year or longer).\724\
---------------------------------------------------------------------------

    \723\ MidAmerican at 14; NYISO at 8; Duke at 13-14; Drs. Broehm
and Fox-Penner at 15.
    \724\ MidAmerican reply comments at 5.
---------------------------------------------------------------------------

    677. Duke explains that market-based rate mitigation alternatives
could be applied to mitigated sellers whose control area markets are
adjacent to a Commission-approved market. If the proxy prices are
established in markets that the Commission has found to be functionally
competitive, Duke contends that the price will by definition be just
and reasonable. Duke submits that the Commission approved similar
mitigation for sales by the LG&E Parties sinking in the Big Rivers
control area capped at the Midwest ISO's LMP at the Big Rivers control
area interface.\725\
---------------------------------------------------------------------------

    \725\ Duke at 14 (citing LG&E Energy Marketing Inc., 113 FERC ]
61,229 at P 30 (2005)).
---------------------------------------------------------------------------

    678. E.ON U.S. argues that allowing index-based price caps as a
mitigation option is just and reasonable because such sales are either
subject to the market monitoring provisions of an RTO, or in the case
of price indices, are structured according to the Commission's
instructions with regard to market price reporting. They add that
index-based price caps are efficient because: (a) They can be used to
address pricing requirements for varying time commitments; (b) they
meet the Commission's criteria for accurate and timely reporting; and
(c) they do not require the administrative overhead and complexity
associated with calculating and reporting cost-based rates.\726 \
---------------------------------------------------------------------------

    \726\ E.ON U.S. at 12.
---------------------------------------------------------------------------

    679. MidAmerican and the Oregon Commission submit that using an
appropriate price index as a proxy could ensure that prices are derived
from competitive conditions and do not reflect the market power of the
mitigated seller (or, for that matter, of any seller).\727\ Duke,
MidAmerican, and the Oregon Commission reason that allowing a published
price index would effectively make the mitigated seller a price taker
rather than a price setter.\728\ E.ON U.S., PNM/Tucson, and
Indianapolis P&L also suggest that requiring cost-based mitigation may
result in sellers giving up their market-based rate authority in
mitigated areas

due to the significant time and expense of developing a cost-of-service
filing.\729\ Where sellers opt to give up market-based rate authority,
these commenters conclude that buyers will be harmed by a reduction in
the number of competitive options available to them in mitigated
markets.
---------------------------------------------------------------------------

    \727\ MidAmerican at 13; Oregon Commission reply comments at 2;
see also PPL reply comments at 17-18.
    \728\ Duke at 14; MidAmerican at 13-14; Oregon Commission reply
comments at 2.
    \729\ Indianapolis P&L at 11; E.ON U.S. at 11; PNM/Tucson at 13.
---------------------------------------------------------------------------

    680. MidAmerican claims that using price indices would (a)
Eliminate the incentive for round-trip transactions; (b) alleviate the
need to determine whether the need for mitigation should be based on
the point of delivery, the sink location, or some other determinant;
and (c) reduce contention over how to calculate cost-based rates.\730\
EEI and the Oregon Commission conclude that allowing mitigated rates to
be based on competitive market prices would: (1) Maintain supply
choices for captive customers by encouraging mitigated suppliers to
participate actively in the mitigated markets; (2) avoid the unintended
consequences of cost-based rate mitigation (e.g., incentive to sell
outside the mitigated region); (3) help to ensure that buyers continue
to receive accurate price signals and not inappropriately lean on cost-
based rates in times of peak demand; and (4) be consistent with the
Commission's goal of encouraging competitive market solutions.\731\
---------------------------------------------------------------------------

    \730\ MidAmerican reply comments at 3-4, 20.
    \731\ EEI reply comments at 12; Oregon Commission reply comments
at 3.
---------------------------------------------------------------------------

    681. APPA/TAPS reject this reasoning, arguing that a dominant
supplier has other incentives not to sell to captive customers beyond
just the availability of a higher price elsewhere, including the desire
to disadvantage competing suppliers within its control area. Therefore,
even if a market price index is used as a mitigation alternative, APPA/
TAPS submit that a ``must offer'' obligation remains necessary.\732\
---------------------------------------------------------------------------

    \732\ APPA/TAPS reply comments at 15.
---------------------------------------------------------------------------

    682. According to some commenters, capping mitigated prices at the
levels of relevant price indices would also reduce the market
distortions that exist under dual price systems.\733\ E.ON U.S., Xcel,
PNM/Tucson, Duke, EEI, MidAmerican and the Oregon Commission generally
contend that allowing market-based rate mitigation methods would reduce
the incentive, arising from price disparities in dual-price systems (a
regime where a seller has market-based rate authority in some markets
but is limited to cost-based sales in other market(s)), for mitigated
sellers to seek market-based rate sales beyond the mitigated
market.\734\ This, in turn, would obviate the need for a ``must offer''
requirement or mitigation of sales outside the mitigated region.
Somewhat similarly, EEI warns that if the Commission implements a
``must offer'' obligation, suppliers may not apply for market-based
rate authorization in markets where they are likely to fail any of the
market power screens.\735\
---------------------------------------------------------------------------

    \733\ PNM/Tuscon at 13-14; MidAmerican at 14; EEI at 26; see
also, CAISO at 6.
    \734\ E.ON U.S. at 10-11; Xcel at 8-9; PNM/Tucson at 13; Duke at
9; EEI at 28; MidAmerican at 14; Oregon Commission reply comments at
3.
    \735\ EEI reply comments at 18.
---------------------------------------------------------------------------

    683. Some commenters add that the Commission surrenders nothing in
terms of consumer protection by allowing market-based price caps as a
mitigation option. In their view, permitting such mitigation will
likely increase the willingness of sellers to engage in market
transactions in mitigated areas and result in buyers paying no more
than what is already recognized as a just and reasonable competitive
market price.\736\
---------------------------------------------------------------------------

    \736\ Duke at 14; APPA/TAPS at 64; MidAmerican at 13.
---------------------------------------------------------------------------

    684. MidAmerican, E.ON U.S., PNM/Tucson, and Indianapolis P&L all
note that the Commission (1) Has found that inter-affiliate sales are
permissible at RTO price indices, and (2) proposes in the NOPR (at P
113-14) to extend this policy to market indices satisfying the November
19 Price Index Order.\737\ These commenters argue that if sales at a
meaningful market index are per se just and reasonable for affiliate
transactions, there is no reason why such sales are not per se just and
reasonable for non-affiliate transactions.\738\ PNM/Tucson add that
even in regions without organized RTO/ISO markets, sellers with market-
based rate authority have established highly liquid trading hubs (e.g.,
Four Corners or Palo Verde) that also produce market prices that are
readily available, transparent, can serve as an appropriate proxy, and
satisfy the Commission's index pricing standards.\739\
---------------------------------------------------------------------------

    \737\ MidAmerican at 13; E.ON U.S. at 11; PNM/Tucson at 12;
Indianapolis P&L at 7.
    \738\ E.ON U.S. at 11; Indianapolis P&L at 11; MidAmerican reply
comments at 5.
    \739\ PNM/Tucson at 13.
---------------------------------------------------------------------------

    685. Another commenter supports the adoption of more market-
oriented approaches to mitigation. For daily and hourly transactions,
this commenter asks the Commission to be receptive to rates tied to an
acceptable price index at a liquid trading point. For long term
transactions, rather than focusing on average embedded costs, which
this commenter claims are likely to be a poor proxy for market rates,
the Commission should consider capacity and associated energy rates
that provide a competitive rate of return on new generation units built
in the region. Where transmission constraints bind only occasionally
and the seller does not have market power absent such constraints, this
commenter reasons that it is rational to only apply mitigated rates to
sales made at the time such constraints are binding. Similarly, where
indicative screens or the DPT analysis point to the existence of a
market power problem in a well-defined seasonal or peak period, this
commenter favors confining rate mitigation to sales made in the
relevant market during that period.\740\
---------------------------------------------------------------------------

    \740\ Dr. Pace at 23-24.
---------------------------------------------------------------------------

    686. APPA/TAPS acknowledge that cost-based rates do not achieve
competitive wholesale markets.\741\ Ideally, wholesale customers should
have a meaningful choice of suppliers whose costs are disciplined by
competitive forces and remedies focused on fostering structurally
competitive markets will help to ensure that future consumers have
choices. Until such structural remedies are fully implemented, APPA/
TAPS maintain that mitigated sellers should sell at cost-based
rates.\742\
---------------------------------------------------------------------------

    \741\ APPA/TAPS at 48.
    \742\ Id. at 48-49.
---------------------------------------------------------------------------

    687. APPA/TAPS and Morgan Stanley do not categorically oppose the
use of price indices as a mitigation alternative that could be
justified with substantial evidence, but urge caution and ask the
Commission not to assume that the index relied upon is a just and
reasonable, and comparable, proxy for the mitigated market.\743\ Morgan
Stanley explains that given the price variation among transmission
nodes, it is not possible to generically find that any one index-based
price would be an adequate proxy for another node(s). APPA/TAPS explain
that a thinly traded market, or one separated by transmission
constraints, could create volatility or arbitrage possibilities that
would leave captive customers worse-off than a cost-based mitigated
rate. They add that appropriate price proxies may not be available for
all products, and that RTO-administered real-time or day-ahead markets
would not generally provide acceptable proxies for price mitigation in
markets for weekly, monthly or annual sales. APPA/TAPS also note that
the Southeast has no real liquid trading hubs.\744\ While urging the
Commission to continue requiring cost-based mitigation, Morgan Stanley
does not oppose allowing mitigated sellers to

justify an index-based mitigation approach as appropriate for their
specific circumstances. According to Morgan Stanley, such an approach
may prove justifiable where a viable, liquid index exists within or
adjacent to the territory in which a finding of market power
exists.\745\
---------------------------------------------------------------------------

    \743\ APPA/TAPS reply comments at 13; Morgan Stanley reply
comments at 2, 8-10.
    \744\ APPA/TAPS reply comments at 14-15.
    \745\ Morgan Stanley reply comments at 9-10.
---------------------------------------------------------------------------

    688. NRECA likewise is concerned that there is no assurance that
(1) The external market price would be a competitive price; (2)
external markets are a reasonable proxy for non-existent competitive
market prices in the mitigated market; and (3) there are sufficient
monitoring and enforcement mechanisms to ensure these first two
conditions are continually being met.\746\ Unless these three concerns
are addressed, NRECA asserts that the Commission may not lawfully rely
on an external market price as a proxy in a mitigated market,
particularly where the FPA is clear that the Commission may not approve
market-based rates absent ``empirical proof'' that ``existing
competition would ensure that the actual price is just and
reasonable.''\747\ Moreover, where ``Congress could not have assumed
that `just and reasonable' rates could conclusively be determined by
reference to market price,'' \748\ NRECA argues that the Commission may
not rely exclusively on market prices but rather must have a regulatory
``escape hatch'' or ``safeguard'' mechanism \749\ if actual competitive
pressures alone cannot keep rates just and reasonable. NRECA, similar
to APPA/TAPS, is concerned that proxy indices are irrelevant oftentimes
because they are too far removed from the mitigated market to be
adequately representative. While NRECA admits that such indices may be
adequate in some instances, it takes the position that, at most, the
Commission could entertain proxy index proposals from mitigated sellers
on a case-by-case basis.\750\
---------------------------------------------------------------------------

    \746\ NRECA reply comments at 31-33.
    \747\ Id. at 32 (quoting Farmers Union Cent. Exch., Inc. v.
FERC, 734 F.2d 1486, 1510 (D.C. Cir. 1984)).
    \748\ Id. (quoting FPC v. Texaco, 417 U.S. 380, 399 (1974)).
    \749\ Id. (quoting Louisiana Energy & Power Auth. v. FERC, 141
F.3d 364, 370-71 (D.C. Cir. 1998)).
    \750\ Id. at 33.
---------------------------------------------------------------------------

    689. The Carolina Agencies are similarly concerned that market-
based indices based on LMPs from adjacent markets in many hours will
reflect transmission congestion that may not be representative of
congestion patterns in the mitigated market, and therefore must not be
deemed a just and reasonable proxy for an entirely different market.
Moreover, LSEs in RTOs with Day 2 markets have some ability to limit
their exposure to LMP spikes through the use of hedging tools (i.e.
Auction Revenue Rights and Financial Transmission Rights). However, the
Carolina Agencies argue, LSEs in mitigated markets would face these LMP
gyrations from adjacent markets as proxy prices without any hedging
protections. These agencies further claim that there are no other
sources of non-LMP price information in their region that are reliable
enough to serve as proxy prices.\751\ In the Carolina Agencies' view,
because price information from non-LMP markets is mostly illiquid, non-
transparent and easily manipulated due to the low volume of
transactions, such reference prices are unlikely to be an accurate and
reasonable proxy for competitive prices in the mitigated control area.
They state that, as the Commission has reported, ``some electric power
markets are almost entirely opaque both to regulators and to price
takers. In these markets (such as electricity in the Southeast), so
little information is available that price indices either do not
develop or have little value in price discovery.'' \752\ The Carolina
Agencies also wonder how a meaningful proxy could be determined for a
market price in a control area where a dominant supplier has market
power.\753\
---------------------------------------------------------------------------

    \751\ Carolina Agencies reply comments at 2-3, 10, 14-18.
    \752\ Id. at 18, n. 11 (citing Federal Energy Regulatory
Commission--Office of Market Oversight and Investigations, 2004
State of the Market Report (June 2005)).
    \753\ Id. at 15, n. 9.
---------------------------------------------------------------------------

    690. The Carolina Agencies and NASUCA oppose providing mitigated
utilities with the option of filing cost-based rates or choosing the
market rates of a neighboring control area.\754\ NASUCA adds that
commenters articulate no legal theory by which mitigated sellers should
be allowed any market rate or how the Commission has power to grant any
waiver of the rate filing and review requirements of section 205 of the
FPA.\755\ Rather than allowing mitigated rates to be determined by
market prices in adjacent market areas, NASUCA urges the Commission to
deny any form of market rates to mitigated utilities and require such
suppliers to comply with section 205 of the FPA by filing their rates
subject to the traditional review to ensure just and reasonable
rates.\756 \
---------------------------------------------------------------------------

    \754\ Id. at 18-19; NASUCA reply comments at 18-19.
    \755\ NASUCA reply comments at 18-19.
    \756\ Id.
---------------------------------------------------------------------------

    691. If the presence of transmission constraints in a dominant
transmission provider's control area allow it to charge supra-
competitive market-based rates there, APPA/TAPS submit that the
Commission must require these constraints to be addressed.\757\ These
commenters ask the Commission to impose mitigating conditions on
market-based rate authority to increase access to existing transmission
facilities as well as to expand their transmission access through
rolled-in upgrades. For example, APPA/TAPS,\758\ and the Carolina
Agencies \759\ suggest that the Commission could condition the market-
based rate authority of a mitigated seller on the demonstrated
willingness of vertically-integrated transmission owners to jointly
plan and construct new generation projects with market participants,
and/or to participate with them in collaborative, open regional
transmission planning processes.
---------------------------------------------------------------------------

    \757\ APPA/TAPS at 50.
    \758\ Id. at 40-41, 49, 50-51.
    \759\ Carolina Agencies at 12, n.10.
---------------------------------------------------------------------------

    692. Xcel responds that, aside from such a requirement being
impractical, the Commission has no legal authority to impose a
condition requiring joint planning of new facilities nor jurisdiction
over the construction of new facilities.\760\ Xcel states that the FPA
does not provide the Commission with certificate jurisdiction over
generation facilities or otherwise, nor does the Commission have the
authority to order utilities to enter into such a contract.\761\
---------------------------------------------------------------------------

    \760\ Xcel reply comments on 9-10.
    \761\ Id. at 10. Duke likewise opposes any proposal granting an
automatic entitlement to participate in new generation planned by
the mitigated utility, arguing that the commercial terms of any
joint ownership arrangements must be negotiated by the parties. Duke
reply comments at 11; see also, EEI reply comments at 8-9.
---------------------------------------------------------------------------

Commission Determination
    693. The Commission continues to believe that proposed alternative
methods of mitigation should be cost-based. However, as discussed
below, while we will not allow the use of alternative ``market-based''
mitigation on a generic basis, we will permit sellers to submit
alternative non-cost-based mitigation proposals for Commission
consideration on a case-by-case basis.
    694. A variety of suggestions have been made such as basing
mitigated prices on: Prices from an adjoining LMP market that are
transparent and contemporaneously available; published index prices;
prices capped at levels reported in the Electric Quarterly Reports for
sales in neighboring markets; a utility's own sales in areas where it
does not possess market power;

and competitive solicitations with a sufficient amount of bidders or
opportunity cost pricing. However, while some commenters suggest that
market-based rate mitigation may cure several of the cost-based
mitigation regime's alleged ailments, they fail to convincingly address
a fundamental concern with such mitigation. That is, why a market-based
price from one market would be a relevant and appropriate proxy price
to mitigate market power found in a different market.
    695. Specifically, we reject Duke's argument that we should allow
market-based rate mitigation alternatives to be used by mitigated
sellers whose control area markets are adjacent to a Commission-
approved market because if the proxy prices are established in markets
that the Commission has found to be functionally competitive, the price
will by definition be just and reasonable. Although Duke is correct
that a price in a market may be presumed to be just and reasonable in
the market in which it has been approved, Duke's claim fails because
that price has not been shown to be just and reasonable for other
markets with differing competitive circumstances.\762\ Duke's argument
also fails to recognize that the Commission does not certify markets as
competitive; rather, we make determinations on whether individual
sellers in a market have market power. In addition, contrary to Duke's
view, the Commission's acceptance of proposed mitigation in the Big
Rivers control area does not support Duke's proposal in this regard. In
LG&E Energy Marketing Inc.,\763\ the Commission accepted a proposal
that capped--at the Midwest ISO's LMP price at the Big Rivers control
area interface--all market-based sales by LG&E sinking in the Big
Rivers control area not sold pursuant to contractual agreements already
in existence. However, Duke fails to point out that, when LG&E proposed
to mitigate its sales into the Big Rivers control area, LG&E was a
member of the Midwest ISO and, accordingly, capping LG&E's sales price
at the Midwest ISO LMP at the Big Rivers interface was appropriate.
---------------------------------------------------------------------------

    \762\ E.ON U.S.' proposal that the use of index-based price caps
subject to the market monitoring provisions of an RTO is a just and
reasonable mitigation option equally fails to address whether the
index-based price is relevant to the market in which the sale is
made.
    \763\ 113 FERC ] 61,229 (2005).
---------------------------------------------------------------------------

    696. Commenters raise many reasons why allowing the use of an index
could be beneficial such as: Using an appropriate price index as a
proxy could ensure that prices are derived from competitive conditions
and do not reflect the market power of the mitigated seller; allowing a
published price index would effectively make the mitigated seller a
price taker rather than a price setter; use of an index price would
eliminate the incentive for round-trip transactions and alleviate the
need to determine whether the need for mitigation should be based on
the point of delivery, the sink location, or some other determinant;
would maintain supply choices for captive customers by encouraging
mitigated suppliers to participate actively in the mitigated markets;
would help to ensure that buyers continue to receive accurate price
signals and not inappropriately lean on cost-based rates in times of
peak demand; and, would be consistent with the Commission's goal of
encouraging competitive market solutions.
    697. However, we agree with Morgan Stanley and others that, given
price variations among transmission nodes, we should not generically
find that one index-based price is necessarily an adequate proxy for
another node. Commenters urging the Commission to consider such
alternatives on a case-by-case basis acknowledge that different markets
may be uncompetitive for different reasons.\764\ While commenters speak
of ``relevant price indexes,'' their comments contain little more than
undeveloped proposals and limited discussion as to how such an index
would be chosen, and why it would be an appropriate proxy for the
mitigated market. For example, commenters fail to explain how a proxy
price based on existing competition from one market with distinct
traits such as transmission congestion ensures a just and reasonable
price in another market that has its own unique traits and
circumstances. Deriving prices from competitive conditions, making a
mitigated seller a price taker rather than a price setter, and reducing
market distortions are all goals commenters claim market-based
mitigation can help achieve. Nonetheless, the use of an external market
price to establish the just and reasonable price in the mitigated
market has not yet been shown to be appropriate.
---------------------------------------------------------------------------

    \764\ MidAmerican at 14; NYISO at 8; Duke at 13-14; Drs. Broehm
and Fox-Penner at 15.
---------------------------------------------------------------------------

    698. While we will not allow the use of ``market-based'' mitigation
on a generic basis, we nevertheless will permit sellers to submit non-
cost-based mitigation proposals, such as the use of an index or an LMP
proxy, for Commission consideration on a case-by-case basis based on
their particular circumstances. Sellers choosing to propose such
alternative mitigation will carry the burden of showing why and how the
proposed index-based price is relevant, appropriate and a just and
reasonable price for the mitigated market. While several commenters
also seek to have the Commission make market-based rate authorization
of mitigated sellers contingent upon their pledging to jointly plan and
construct future generation projects with market participants, or
pursue other structural conditions, they have not justified imposing
such a burden. For those sellers that are affected with a market power
concern, we discuss elsewhere in this Final Rule the means by which we
will require adequate mitigation. Moreover, we believe that we have
adequately addressed these concerns related to planning in our recent
Order No. 890, where we require all jurisdictional transmission owners
to engage in transmission planning with other market participants.
Therefore, we find no reason to mandate a mitigated seller's
participation in such arrangements.
2. Discounting
Commission Proposal
    699. In the NOPR, the Commission explained that a supplier
authorized to sell under an ``up to'' cost-based rate has an incentive
to discount its sales price when the market price in the supplier's
local area is lower than the cost-based ceiling rate. During these
periods, a rational seller will discount its sales to maximize revenue.
In the past, the Commission has encouraged discounting as an efficient
practice that can maximize revenues to reduce the revenue requirements
borne by requirements customers.
    700. Here, the primary issue is whether a seller can
``selectively'' discount, i.e., offer different prices to different
purchasers of the same product during the same time period. The
Commission invited comment on whether selective discounting should be
allowed for sellers that are found to have market power or have
accepted a presumption of market power and are offering power under
cost-based rates. If so, the Commission sought comment on what
mechanisms (reporting or otherwise), if any, are necessary to protect
against undue discrimination. By contrast, were it to forbid selective
discounting, the Commission asked for comment on whether it should
require the utility to post discounts to ensure that they are available
to all similarly-situated customers.

Comments
    701. Some commenters favor selective discounting because it
provides an opportunity to meet competition where necessary to retain
and attract business. They add that the contracting flexibility
afforded by selective discounting allows sellers to modify rates and
tailor sales based on customer-specific factors such as load
characteristics and credit ratings. They argue that such flexibility
maximizes liquidity and available capacity and energy.\765\
---------------------------------------------------------------------------

    \765\ See, e.g., Indianapolis P&L at 10; MidAmerican at 15-16;
Duke at 10-11; EEI at 34; PG&E at 23; Progress Energy at 12.
---------------------------------------------------------------------------

    702. MidAmerican and Indianapolis P&L both state that section 206
of the FPA already prohibits undue discrimination and provides well-
established procedures for entities that have been subjected to undue
discrimination.\766\ Westar notes that the Commission's long-standing
policy is to allow selective discounting and asserts that discounting
to customers who have competitive alternatives is not unduly
discriminatory.\767\
---------------------------------------------------------------------------

    \766\ MidAmerican at 15; Indianapolis P&L at 10.
    \767\ Westar at 26 (citing Town of Norwood v. FERC, 587 F.2d
1306, 1312 & n.17 (D.C. Cir. 1978) (rate disparity may be justified
by, inter alia, differences in the customers' level of risk aversion
and bargaining power)); see Policy for Selective Discounting by
Natural Gas Pipelines, 111 FERC ] 61,309, reh'g denied, 113 FERC ]
61,173 (2005) (affirming Commission's 16-year policy to allow
selective discounting by interstate natural gas pipelines when
necessary to meet competition).
---------------------------------------------------------------------------

    703. PG&E maintains that it is just and reasonable for a seller to
offer a discount below its cost-based mitigated rate if the seller will
gain other (non-market power) advantages such as repeat customers or
lower transaction costs. PG&E also suggests that principles of
efficiency and competition support providing selective discounts to
entities with larger needs.\768 \
---------------------------------------------------------------------------

    \768\ PG&E at 23.
---------------------------------------------------------------------------

    704. Duke contends that sales arising from selective discounting
spread fixed costs over more units of service, thereby reducing the
``up to'' rate.\769\ Moreover, without the ability to selectively
discount, Duke submits that utilities will not have the opportunity to
compete for many wholesale transactions in the mitigated control
area.\770\
---------------------------------------------------------------------------

    \769\ Duke at 11.
    \770\ Id.
---------------------------------------------------------------------------

    705. Southern asserts that if selective discounting were
eliminated, then the resulting loss of a low-cost source of supply
would harm the customers. In Southern's view, captive customers also
lose because of foregone opportunities to optimize capacity nominally
dedicated to native load service.\771\ EEI adds that where a mitigated
seller is already precluded from making market-based rate sales within
mitigated areas, selective discounting does not give rise to conditions
that support the potential exercise of market power.\772\
---------------------------------------------------------------------------

    \771\ Southern at 67.
    \772\ EEI at 31; see also PG&E at 23.
---------------------------------------------------------------------------

    706. Other commenters generally oppose allowing mitigated sellers
to selectively discount sales. For example, TDU Systems claim that
selective discounting is unnecessary because a seller subject to cost-
based mitigation in its home control area would not face competition by
definition. They also contend that selective discounting would allow
mitigated sellers to engage in price discrimination in a non-
competitive market, thereby permitting the seller to exercise market
power by economically or physically withholding capacity to increase
the posited market price. Thus, in the TDU Systems' view, a rule
allowing selective discounting would effectively grant market-based
rate authority in a non-competitive market, in contravention of the
requirements of the FPA.\773\
---------------------------------------------------------------------------

    \773\ TDU Systems at 19-21.
---------------------------------------------------------------------------

    707. While NC Towns generally encourage discounts to cost-based
rates, they oppose selective discounting because they do not believe
that the size of a load should be a factor when determining whether to
give a buyer a discount.\774\
---------------------------------------------------------------------------

    \774\ NC Towns at 5.
---------------------------------------------------------------------------

    708. APPA/TAPS question why a dominant seller would offer discounts
to captive customers with no other viable supply options. They add that
there is no evidence that local, competing generation exists or that
there is available transmission capacity that could support significant
imports. In order to avoid discrimination, APPA/TAPS advocate requiring
a mitigated supplier to offer captive customers any discounts that it
offers to other purchasers.\775\ Factors such as a customer's capacity
factor, credit rating or fuel costs may justify adjustments to seller-
specific cost-based rates, but such factors, argue APPA/TAPS, should be
reflected in the seller's cost-based rates rather than through
selective discounting.\776\
---------------------------------------------------------------------------

    \775\ APPA/TAPS reply comments at 15-16; APPA/TAPS at 44-48.
    \776\ APPA/TAPS reply comments at 16.
---------------------------------------------------------------------------

    709. If selective discounting is permitted, TDU Systems and NRECA
urge the Commission to require sellers to file reports of the discounts
offered, and encourage the Commission to vigorously enforce its market
manipulation and affiliate transactions rules.\777\
---------------------------------------------------------------------------

    \777\ TDU Systems at 24; NRECA at 32.
---------------------------------------------------------------------------

    710. Suez/Chevron urges the Commission to require selective
discounts to be contemporaneously offered to similarly-situated buyers,
and separately identified in the mitigated seller's EQR.\778\ To
minimize the potential for market power abuse when a mitigated seller
selectively discounts to an affiliate,\779\ Suez/Chevron supports
requiring a presumption that nonaffiliated buyers are similarly-
situated, and therefore entitled to the same discount as a mitigated
seller offers to its affiliate.\780\
---------------------------------------------------------------------------

    \778\ NC Towns and Morgan Stanley state that any discount the
seller wishes to offer should be required to be posted with
sufficient time for other interested parties to take advantage of
the offer. NC Towns at 5-6; Morgan Stanley at 7.
    \779\ Suez/Chevron states that sellers should be required to
post any affiliate discounts on their OASIS. Suez/Chevron at 13.
    \780\ Suez/Chevron at 12-13.
---------------------------------------------------------------------------

    711. PG&E, in contrast, opposes requiring the seller to make
discounts available to all similarly-situated entities. According to
PG&E, it would be difficult to determine which entities are in fact
similarly-situated because the seller would have to consider multiple
factors, such as quantity of load, timing, flexibility, credit rating,
and purchases history.\781\
---------------------------------------------------------------------------

    \781\ PG&E at 24.
---------------------------------------------------------------------------

    712. Ameren disagrees with a posting requirement, arguing that the
Commission's requirements for separate filings and advance approval of
affiliate power sales provide the appropriate oversight and mechanisms
necessary to police discounting concerns regarding selective discounts
favoring affiliates. Ameren concludes that a requirement to post
discounts is unduly burdensome given that the only discounts of concern
are in the affiliate sales, which are subject to separate filing
requirements.\782\ PG&E, in turn, notes that the affiliate restrictions
also provide protection against the use of selective discounts to
benefit affiliates.\783\
---------------------------------------------------------------------------

    \782\ Ameren at 17-18.
    \783\ PG&E at 23.
---------------------------------------------------------------------------

Commission Determination
    713. We will continue our practice of allowing discounting from the
default cost-based mitigated rates for short- and mid-term sales and
will permit selective discounting by mitigated sellers provided that
the sellers do not use such discounting to unduly discriminate or give
undue preference. We believe that selective discounting that does not
constitute undue discrimination can improve liquidity, available
capacity and energy, and customer supply

options. In other words, non-discriminatory discounting can provide
benefits to the market.
    714. APPA/TAPS question why a dominant seller would offer discounts
to captive customers with no other viable supply options, and the TDU
Systems comment that selective discounting is unnecessary because a
mitigated seller by definition would not face competition in its home
control area. However, in times when there are viable alternatives, a
seller under an ``up to'' cost-based rate has an incentive to discount
its sales price when the market price in the seller's mitigated market
is lower than the cost-based ceiling rate. Allowing a mitigated seller
to non-discriminatorily discount the rate when there are viable
alternatives in the market benefits customers by providing more supply
options in such instances.
    715. Discounting also can maximize revenue by optimizing capacity
nominally dedicated to native load service, allowing the supplier to
spread fixed costs over more units of service. Maximizing revenue in
this manner can help reduce the ``up to'' rate, and therefore the
revenue requirements borne by captive customers. The Commission has
previously determined that requiring a mitigated entity to limit sales
to its ceiling rates ``is at odds with the long-standing policy of
allowing `up to' cost-based rates.'' \784\
---------------------------------------------------------------------------

    \784\ Duke Power, 113 FERC ] 61,192 at P 17 (2005).
---------------------------------------------------------------------------

    716. The FPA requires that all rates charged by public utilities
for the sale or resale of electric energy be ``just and reasonable.''
\785\ If a seller's cost-based rate has been found to be just and
reasonable by the Commission, it follows that discounted rates below
such a cost-based rate are also just and reasonable.\786\ However, a
seller may not lawfully discount to gain, or profit from, market power
advantages. We emphasize that section 205 of the FPA prohibits public
utilities, in any power sale subject to the Commission's jurisdiction,
from granting any undue preference or advantage to any person \787\ and
also prohibits undue discrimination.\788\
---------------------------------------------------------------------------

    \785\ 16 U.S.C. 824d(a).
    \786\ Public Service Company of Oklahoma, 54 FERC ] 61,021, at
61,032 and fn. 8 (1991) (``If PSO's rates set at full cost are
reasonable in the presence of market power, it follows that PSO's
rates reflecting less than a 100-percent contribution to fixed costs
are also reasonable in the presence of market power.'').
    \787\ 16 U.S.C. 824d(b).
    \788\ 16 U.S.C. 824e(a).
---------------------------------------------------------------------------

    717. With regard to comments that the Commission establish a
reporting mechanism, under the Commission's existing reporting
requirements entities making power sales must submit EQRs containing: A
summary of the contractual terms and conditions in every effective
service agreement for all jurisdictional services, including market-
based and cost-based power sales and transmission services; and,
transaction information for effective short-term (less than one year)
and long-term (one year or greater) power sales during the most recent
calendar quarter.\789\ Through this reporting requirement, the
Commission monitors the rates charged by mitigated sellers.
---------------------------------------------------------------------------

    \789\ 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.
---------------------------------------------------------------------------

    718. Several commenters also seek to have the Commission require
selective discounts to be posted and contemporaneously offered to
similarly-situated buyers. Some seek a presumption that nonaffiliated
buyers are similarly situated whenever a mitigated seller offers an
affiliate a discount. The Commission will not require mitigated sellers
to contemporaneously post in a public forum all discounts provided for
cost-based sales (i.e., where the sale is made at a price below the
maximum up-to cost-based rate approved by the Commission in that tariff
or rate schedule). Proponents of a posting requirement have not
justified nor demonstrated how the Commission's EQR requirement fails
to provide an adequate means by which to monitor such discounts. In
addition, many sales are made below the cost-based cap, and the
commenters' proposals would place an undue burden on sellers that would
be required to contemporaneously post rates that the Commission has
already deemed to be just and reasonable. Accordingly, the Commission
will not require the contemporaneous posting of discounted cost-based
rates. Finally, commenters have provided no basis to conclude that
nonaffiliated buyers are similarly situated whenever a mitigated seller
offers an affiliate a discount, and we will not adopt the proposed
presumption in this regard. Thus, sellers may selectively discount only
if they do so in a manner that is not unduly discriminatory or
preferential.
    719. Further, we agree with MidAmerican that identifying
discriminatory selective discounting requires fact-specific
evaluations. Because individual proceedings are the best instrument
available to the Commission for such efforts, allegations of undue
discrimination arising from selective discounting are best addressed on
a case-by-case basis.
3. Protecting Mitigated Markets
a. Must Offer
Commission Proposal
    720. Under the Commission's current mitigation policy, a seller
that loses market-based rate authority in its home control area is
limited to charging cost-based rates in that control area; however,
there is no requirement that the seller offer its available power to
customers in that home control area. Instead, the seller is free to
market all of its available power to purchasers outside that control
area if it chooses to do so. If, for example, market prices outside the
mitigated seller's control area exceed the cost-based caps within the
mitigated control area, then the seller will, other things being equal,
have an incentive to sell outside. As noted in the NOPR, wholesale
customers have argued that default cost-based mitigation of this kind
is of little value if a seller can market its excess capacity at
market-based rates in other control areas. In the NOPR, the Commission
sought comment on whether its current policy is appropriate, and if
not, what further restrictions are needed. The Commission asked whether
it should adopt a form of ``must offer'' requirement in mitigated
markets to ensure that available capacity (i.e., above that needed to
serve firm and native load customers) is not withheld. If so, the
Commission asked if such a ``must offer'' requirement should be limited
to sales of a certain period to help ensure that wholesale customers
use that power to serve their own needs, rather than simply remarketing
that power outside the control area and profiting. \790\ If it were to
adopt such a ``must offer'' requirement, the Commission asked what
rules there should be to define the ``available'' capacity that must be
offered , in order to avoid case-by-case disputes over this issue.
---------------------------------------------------------------------------

    \790\ In this regard, the Commission asked if there should be an
annual open season under which the mitigated seller offers its
available capacity to local customers for the following year at the
cost-based ceiling rate and, if customers do not commit to purchase
that capacity, then the seller would be free to sell the remaining
capacity at market-based rates where it has authority to do so.
---------------------------------------------------------------------------

Comments
    721. Wholesale customers generally support a ``must offer''
requirement,'' stating that it is needed to ensure that power is
available for purchase in the mitigated market and to protect them from
incurring higher costs to serve

load.\791\ They argue that the existence of a dual price system (a
regime where a seller has market-based rate authority in some markets
but is limited to cost-based sales in other market(s)) creates an
incentive for a mitigated seller to sell its power outside of the
mitigated market whenever market prices in the outside market are above
the mitigated seller's cost-based price. They are concerned
particularly with the situation where a wholesale customer faces few or
no alternatives in the mitigated market due to transmission
constraints.
---------------------------------------------------------------------------

    \791\ See, e.g., APPA/TAPS at 40-42 (also urging the Commission
to apply any ``must offer'' requirement to captive customers in the
seller's transmission service area); Carolina Agencies at 10-13;
NRECA at 35; Montana Counsel at 19; TDU Systems at 19; NC Towns at
6-8 (asking the Commission to require mitigated utilities to serve
wholesale customers in the mitigated control area at long-term
system average cost-based rates in order to maintain reliability).
See also MidAmerican reply comments at 9-12 (arguing that the APPA/
TAPS and Carolina Agencies proposals suffer from significant policy
flaws).
---------------------------------------------------------------------------

    722. APPA/TAPS, the Carolina Agencies and NRECA claim that the
Commission has both the authority and obligation to remedy undue
discrimination in wholesale sales, which are clearly set forth in
sections 205 and 206 of the FPA.\792\ They specifically argue that a
``must offer'' condition is within the Commission's authority as a
remedy for the unjust and unreasonable rates and undue discrimination
(refusal to sell in the mitigated control area) that are a consequence
of the mitigated seller's accumulation of market power.\793\ Several
commenters reason that, similar to imposing reporting requirements and
other conditions on a grant of market-based rate authority, where a
seller no longer has market-based rate authority in its home control
area, the Commission may impose a ``must offer'' condition on the
continuation of market-based rate authorization outside a mitigated
seller's control area.\794\ APPA/TAPS and the Carolina Agencies argue
that the Commission already imposed a must-offer obligation on the
continued availability of market-based rate authority for sellers in
the California markets.\795\
---------------------------------------------------------------------------

    \792\ APPA/TAPS and Carolina Agencies supplemental comments at
4, 9-18 (citing, among others, 16 U.S.C. 824d(a), 824d(b), 824e(a);
Associated Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir.
1987)).
    \793\ NRECA reply comments at 41 (citing New York v. FERC, 535
U.S. 1, 27 (2002); Transmission Access Policy Study Group v. FERC,
225 F.3d 667, 683-88 (D.C. Cir. 2000), aff'd sub nom. New York v.
FERC, 535 U.S. 1 (2002)); Carolina Agencies at 4-5; Carolina
Agencies reply comments at 2. See also Montana Counsel at 19 (citing
Atlantic Ref. Co. v. Public Serv. Comm'n of N.Y., 360 U.S. 378
(1959) and United Gas Improvement Co. v. Callery Properties, Inc.,
382 U.S. 223 (1965), two cases in which the Montana Counsel claim
that the Supreme Court, in recognition of the market power of
natural gas producers and the public interest provisions of the NGA,
``virtually ordered'' the Commission to exercise its jurisdiction to
condition producer natural gas certificates and rate orders to limit
gas prices); APPA/TAPS and Carolina Agencies supplemental comments
at 2, 18-30; NRECA supplemental comments at 6-7.
    \794\ APPA/TAPS at 37-38; APPA/TAPS reply comments at 8; Montana
Counsel at 21-22; Carolina Agencies at 4-5; Carolina Agencies reply
comments at 3-4.
    \795\ APPA/TAPS and Carolina Agencies supplemental comments at
27 (citing San Diego Gas & Elec. Co. v. Sellers of Energy and
Ancillary Servs. Into Mkts. Operated by the Cal. Ind. Sys. Operator
and the Cal. Power Exch., 93 FERC ] 61,294, at 62,010-11 (2000)
(extended-refund-period condition), order on rehearing and
clarification, 97 FERC 61,275, at 62,243-44 (2001), order on
rehearing and clarification, 99 FERC ] 61,160 (2002), on rehearing
and clarification, 105 FERC ] 61,065 (2003), petitions for rev.
granted in part sub nom. Bonneville Power Auth. v. FERC, 422 F.3d
908 (9th Cir. 2005) and Public Utils. Comm'n of Cal. v. FERC, 462
F.3d 1027, 1043 (9th Cir. 2006) (discussing must-offer condition)).
---------------------------------------------------------------------------

    723. APPA/TAPS also assert that while Order No. 888 rejected a
generic obligation that would have required sellers to continue
wholesale sales past the expiration of the contract(s) in question in
that proceeding, Order No. 888 explained that the Commission can impose
an obligation to continue service on a case-by-case basis.\796\
---------------------------------------------------------------------------

    \796\ APPA/TAPS at 39 (citing Order No. 888--``we continue to
believe that the extent to which a customer could demonstrate a
reasonable expectation of continued service at the existing contract
rate (or at a cost-based rate, if that was the customer's
expectation) is best addressed on a case-by-case basis''); see also
Order No. 888, FERC Stats. & Regs. ] 31,036, at 31,805 & n.652
(1996) (explaining that although the Commission determined ``not to
impose a regulatory obligation on wholesale requirements suppliers
to continue to serve their existing requirements customers,'' ``any
party claiming to be aggrieved by a utility's alleged abuse of
generation market power under a wholesale requirements contract can
file a complaint with the Commission under Section 206''); see also
Montana Counsel at 22.
---------------------------------------------------------------------------

    724. APPA/TAPS and the Carolina Agencies argue that a dominant
public utility's physical withholding of generation in the mitigated
market in order to make market-based sales elsewhere results in undue
discrimination that the Commission has an obligation to remedy. They
assert that because wholesale customers in the mitigated market are
harmed through decreased supply, increased market concentration, and
increased prices, these customers are exposed to the type of injury
against which the FPA was designed to protect.\797\ The Carolina
Agencies also maintain that, whether or not exporting behavior can be
considered economically efficient, such behavior results in undue
discrimination between (i) The mitigated utility's native load and (ii)
LSEs located within the mitigated utility's home control area.\798\
This outcome, the Carolina Agencies continue, violates the FPA's
mandate that rates be just, reasonable and not unduly discriminatory
regardless of whether the mitigated utility's decision to export power
is a conscious ``withholding'' for anticompetitive ends.\799\ APPA/TAPS
and Carolina Agencies add that vertically-integrated utilities with
substantial generation in their home control areas frequently have the
ability and incentive to discriminate against their wholesale
customers, who compete against them on both the wholesale and retail
level.\800\
---------------------------------------------------------------------------

    \797\ APPA/TAPS and Carolina Agencies supplemental comments at
19.
    \798\ Carolina Agencies at 6.
    \799\ Id. at 9.
    \800\ APPA/TAPS and Carolina Agencies supplemental comments at
16 (citing FPC v. Conway Corp., 426 U.S. 271, 278 (1976) to further
argue that the Commission can and must take account of competition
at retail when determining whether such discrimination exists.)
---------------------------------------------------------------------------

    725. APPA/TAPS and Carolina Agencies maintain that undue
discrimination occurs if a dominant public utility unjustifiably
disadvantages a class of market participants. They cite case law that
the D.C. Circuit found ``upholds the power of the Commission to subject
approval of a set of voluntary transactions to a condition that
providers open up the class of permissible users.'' \801\ Absent
relevant circumstances that render two sets of customers differently
situated, they assert that it is unduly discriminatory for a public
utility to sell wholesale power to one set of customers (at market-
based rates) while denying service to another set (to whom sales, if
made, would need to be priced at cost-based rates). They contend there
is no justification for disparate treatment in such a case and,
therefore, the Commission is obligated under sections 205 and 206 to
remedy such undue discrimination by either denying or conditioning the
grant of market-based rate authority outside of the mitigated home
control area. A ``must offer'' condition, they claim, would satisfy
this obligation by preventing undue discrimination.\802\
---------------------------------------------------------------------------

    \801\ Id. at 13 (citing Central Iowa Power Coop. v. FERC, 606
F.2d 1156, 1172 (D.C. Cir. 1979); and quoting Associated Gas
Distributors v. FERC, 824 F.2d 981, 999 (D.C. Cir. 1987)). APPA/TAPS
and Carolina Agencies claim that in this case, a must offer
requirement would expand the class of buyers of the mitigated
seller's wholesale services to include customers from the mitigated
utility's home control area.
    \802\ Id. at 15-16.
---------------------------------------------------------------------------

    726. APPA/TAPS and the Carolina Agencies further allege that, while
it may not be unduly discriminatory for a utility to elect to sell to
the wholesale

customer who will pay the highest price, it is unduly discriminatory if
the price differential is based upon mitigation required as a result of
the seller's market power.\803\ Where sellers claim a right to seek the
highest prices, APPA/TAPS and the Carolina Agencies counter that this
profit maximization impulse can neither justify the exercise of market
power nor insulate it from correction.\804\
---------------------------------------------------------------------------

    \803\ Id. at 30.
    \804\ Id. at 31.
---------------------------------------------------------------------------

    727. According to APPA/TAPS and the Carolina Agencies, it is also
unduly discriminatory for a mitigated seller to make market-based rate
sales outside its home control area when constraints on that entity's
own transmission system prevent embedded customers from similarly
accessing those markets as buyers. They argue that refusal to sell
wholesale power supplies to embedded LSE customers at fully-
compensatory cost-based rates effectively compounds the de facto denial
of access by exacerbating both the discrimination and the resulting
harm.\805\ According to APPA/TAPS and the Carolina Agencies, the claim
that mitigated sellers are merely engaging in economically efficient
behavior ignores the market power that the sellers possess.\806\ They
state that when captive customers have few or no supply alternatives in
the mitigated market and are constrained from accessing opportunities
in the broader market (even with open access tariffs), and the dominant
supplier sells its excess capacity beyond the mitigated market, the
resulting reduction in output in the mitigated market is not addressed
simply by prohibiting the mitigated seller from selling at unmitigated
prices in the mitigated region.\807\ They conclude that it would be
unjust and unreasonable to permit or facilitate such withholding by
allowing unconditioned sales at market-based rates outside a mitigated
supplier's home control area; this would reserve the benefits of
competitive markets exclusively to dominant public utility
sellers.\808\
---------------------------------------------------------------------------

    \805\ Id. at 30-31.
    \806\ APPA/TAPS at 6-7; Carolina Agencies reply comments at 6.
    \807\ APPA/TAPS reply comments at 6-7.
    \808\ APPA/TAPS supplemental comments at 30-31.
---------------------------------------------------------------------------

    728. A number of commenters claim that a ``must offer'' requirement
is necessary due to their lack of viable options in mitigated control
areas. For example, Fayetteville submits that it finds itself without
transmission access to make short-term energy purchases to displace its
higher cost generation.\809\ Fayetteville contends that Progress
Energy's dominant position, as well as Fayetteville's inability to
access alternative suppliers due to the inadequacy of Progress Energy's
transmission system, gives Progress Energy unmitigated market
power.\810\
---------------------------------------------------------------------------

    \809\ Fayetteville reply comments at 5.
    \810\ Id. at 6. See also Montana Counsel at 15-23 (where market
power is found, sellers should be required to offer power to meet
the requirements of dependent customers at cost).
---------------------------------------------------------------------------

    729. The Carolina Agencies add that, while economic efficiency is a
worthy goal in structurally sound markets where participants have ready
and equal access to meaningful choices, the idea of economic efficiency
cannot justify a mitigated supplier's behavior in a control area where
its market power arises from import limitations or other factors that
deprive captive LSEs of viable options. Nor can, they claim, the goal
of economic efficiency trump the Commission's clear duty to protect
customers by ensuring that rates are just, reasonable, and not unduly
discriminatory.\811\
---------------------------------------------------------------------------

    \811\ Carolina Agencies reply comments at 9.
---------------------------------------------------------------------------

    730. The Carolina Agencies dispute the claim that there is no need
for a ``must offer'' requirement given the Commission's authority to
penalize market manipulation. They question whether refusal to sell in
the mitigated market would be actionable under the anti-manipulation
rules if there is no obligation to offer power to embedded LSEs.\812\
---------------------------------------------------------------------------

    \812\ Carolina Agencies reply comments at 10-11.
---------------------------------------------------------------------------

    731. NRECA and others ask the Commission to reject the claim that a
``must offer'' requirement would impede a mitigated seller's ability to
fulfill its retail crediting obligations.\813\ NRECA responds that
retail customers can sometimes benefit from cost-based rates; if
competition reduces the market price to a seller's marginal cost, no
contribution to fixed costs would be recovered. Commenters note that
not all utilities are subject to rules requiring the sharing of profits
from off-system sales.\814\ NRECA argues that a utility's authority to
make off-system sales at market-based rates is a privilege granted by
the Commission; if the Commission restricts or conditions that
privilege, any obligation the public utility has under State law or
regulation to sell excess energy or capacity is pre-empted by the
requirements of Federal regulation.\815\ The Carolina Agencies and
NRECA add that a ``must offer'' requirement would serve the intended
purpose of the Commission's mitigation policy, which is to protect
wholesale customers from the exercise of actual and potential market
power, not to preserve a utility's ability to reduce retail rates nor
its ability to engage in a certain volume of off-system power
sales.\816\
---------------------------------------------------------------------------

    \813\ See, e.g., NRECA reply comments at 37-39; Carolina
Agencies at 17 (citing April 14 Order, 107 FERC ] 61,018 at P 140,
154, where they claim that the Commission rejected arguments that
cost-based mitigation rates adversely affect retail rates, because
such rates provide for the recovery of the mitigated utility's
longer-term costs, and because the adverse impact claims were
``unsupported and speculative.''); Fayetteville reply comments at 7,
9-10.
    \814\ NRECA reply comments at 38; Carolina Agencies at 8.
    \815\ NRECA reply comments at 38-39 (citing Entergy La., Inc.,
v. La. Pub. Serv. Comm'n, 539 U.S. 39 (2003); Miss. Power & Light
Co. v. Mississippi ex rel. Moore, 487 U. S. 354 (1988); Nantahala
Power & Light Co. v. Thornburg, 476 U. S. 953 (1986)); see also
Carolina Agencies reply comments at 7-8 (where a utility is
satisfying a countervailing regulatory mandate (such as a ``must
offer'' obligation, it cannot be held to be violating the cost
minimization duty)).
    \816\ Carolina Agencies at 17; Carolina Agencies reply comments
at 7-8; NRECA reply comments at 35.
---------------------------------------------------------------------------

    732. NRECA, APPA/TAPS and the Carolina Agencies all set forth
proposals in their comments for implementing a ``must offer''
requirement.\817\ NRECA suggests requiring a mitigated seller to hold
an annual open season to offer long-term service (one year or more), as
well as requiring a mitigated seller to offer shorter-term capacity and
energy.\818\ While not favoring an annual open season, APPA/TAPS and
the Carolina Agencies each propose ``must-offer'' parameters to govern
short- and long-term sales.\819\ For both short- and long-term sales,
the Carolina Agencies would offer captive customers an option between
(1) Locking-in their price at the mitigated utility's embedded cost
rates or (2) agreeing to have their charges determined through an
annually updated formula rate that reflects the mitigated utility's
actual system-wide average costs.\820\ The APPA/TAPS proposal also
includes an obligation to offer captive customers participation on
proposed generation projects.\821\ Both APPA/TAPS and the Carolina
Agencies would limit any ``must-offer'' to loads actually located in
the mitigated control area.
---------------------------------------------------------------------------

    \817\ NRECA at 35; APPA/TAPS at 40-42; Carolina Agencies at 10-
13.
    \818\ NRECA at 35-36.
    \819\ APPA/TAPS at 40-42; Carolina Agencies at 10-13.
    \820\ Carolina Agencies at 12-13.
    \821\ APPA/TAPS at 41.
---------------------------------------------------------------------------

    733. NRECA also proposes two alternatives to a ``must offer''
requirement. First, NRECA suggests that the Commission give captive
wholesale customers a right of first refusal to purchase at a market
price energy or capacity that the mitigated seller proposes to sell
outside the mitigated

market.\822\ The weakness of this approach, NRECA acknowledges, is that
it would allow the mitigated seller to charge wholesale customers a
supra-competitive price in the mitigated market given that the market-
based rate outside the control area would be higher than the cost-based
rate in the seller's control area.\823\
---------------------------------------------------------------------------

    \822\ NRECA reply comments at 36-37.
    \823\ NRECA at 36-37. MidAmerican disagrees, arguing that
market-based prices are not by definition always higher than cost-
based prices in the mitigated region. Rather, the Commission has
encouraged open access transmission and market competition because
economically efficient market-based rates can be lower than cost-
based rates. At the same time, where a price index at a trading hub
may be lower than the seller's incremental cost, MidAmerican argues
that a seller should never be required to sell at rates below its
incremental cost. MidAmerican reply comments at 21.
---------------------------------------------------------------------------

    734. NRECA also suggests as an alternative an enforceable
commitment to provide sufficient additional transmission import
capacity to mitigate the generation market power. It states that such a
commitment could be implemented by re-dispatching resources,
relinquishing transmission reservations, or physically upgrading the
transmission grid. This would allow additional suppliers to make sales
in the mitigated region, thereby mitigating the seller's generation
market power. NRECA contends that this approach would directly address
the larger issue of the need to eliminate transmission bottlenecks and
load pockets that give rise to generation market power.\824\
---------------------------------------------------------------------------

    \824\ NRECA at 37.
---------------------------------------------------------------------------

    735. The Carolina Agencies also propose that mitigated utilities be
required to investigate and report on transmission expansion or other
actions that could remove structural impediments causing market power.
The Carolina Agencies claim that such a requirement is consistent with
the Commission's affirmative duty to remedy undue discrimination, an
area in which the Commission has broad authority to craft
remedies.\825\
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    \825\ Carolina Agencies at 16 (citing the OATT Reform NOPR at P
210 and n.203).
---------------------------------------------------------------------------

    736. Other commenters argue against imposition of a ``must offer''
requirement, stating that it would encourage inefficiencies, undermine
competition, discourage investment, and perpetuate market power. They
also assert that such a requirement goes beyond any cost-of-service
requirement that the Commission has ever adopted.\826\ They question
the need for a ``must offer'' requirement, claiming that existing
Commission statutory authority, regulations, and enforcement mechanisms
already sufficiently guard against the market power abuse and market
manipulation concerns that ``must offer'' proponents claim such a
provision is needed to prevent.\827\
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    \826\ See, e.g., Xcel at 5; Progress Energy reply comments at 5.
APPA/TAPS and NRECA respond that as long as the rate is cost-
compensatory, and therefore just and reasonable, it provides an
adequate return and the mitigated supplier is not disadvantaged by
making such sale. APPA/TAPS reply comments at 9; NRECA reply
comments at 31, 35, 38.
    \827\ See, e.g., EEI at 36; Progress Energy at 17.
---------------------------------------------------------------------------

    737. EEI and Progress Energy claim that when the Commission
establishes a cost-based rate in a mitigated market, it ensures that
the rate meets the just and reasonable and not unduly discriminatory
requirements of sections 205 and 206 of the FPA, and thus there is no
further Commission action that is required to mitigate the indicated
market power.\828 \
---------------------------------------------------------------------------

    \828\ EEI at 37; Progress Energy at 13.
---------------------------------------------------------------------------

    738. Several commenters that argue against imposition of a ``must
offer'' requirement state that wholesale customers have not presented
sufficient evidence to justify the generic imposition of such a
requirement. They state that there have been no specific instances
cited where a wholesale customer in a mitigated market was unable to
obtain service, much less evidence that such instances are commonplace.
    739. Duke/Progress Energy argue that the Commission must make a
finding that rates or practices are unjust, unreasonable, or unduly
discriminatory as a predicate to taking action, and that in the case of
a generic rulemaking, ``the Commission'' cannot rely solely on
``unsupported or abstract allegations.''' \829\ They cite National Fuel
Gas Supply Corp. v. FERC,\830\ where the D.C. Circuit, describing
Tenneco Gas v. FERC,\831\ stated ``[t]he court [in Tenneco] `upheld
Order 497 in relevant part because FERC presented an adequate
justification--by advancing both (i) A plausible theoretical threat of
anti-competitive information-sharing between pipelines and their
marketing affiliates and (ii) vast record evidence of abuse.' ''\832\
They note that the D.C. Circuit contrasted Tenneco with Order No. 2004
(at issue in National Fuel), where `` `FERC has cited no complaints and
provided zero evidence of actual abuse between pipelines and their non-
marketing affiliates.' '' They assert that the D.C. Circuit concluded
that `` `[p]rofessing that an order ameliorates a real industry problem
but then citing no evidence demonstrating that there is in fact an
industry problem is not reasoned decisionmaking.'' ' \833\
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    \829\ Duke/Progress Energy supplemental coments at 21 (quoting
Transmission Access Policy Study Group v. FERC, 225 F.3d 667, 688
(D.C. Cir. 2000) (TAPS)).
    \830\ 468 F.3d 831, 840 (D.C. Cir. 2006) (National Fuel).
    \831\ 969 F.2d 1187 (D.C. Cir. 1992) (Tenneco).
    \832\ Duke/Progress Energy supplemental comments at 22 (quoting
National Fuel, 468 F.3d at 840).
    \833\ National Fuel, 468 F.3d at 843-44.
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    740. According to Duke/Progress Energy, the commenters favoring a
``must offer'' requirement ``have presented no evidence whatsoever to
support the conclusion that any systemic discrimination is occurring or
that any party is suffering any actual harm under the discrimination
theory they have posited.'' \834\ Duke/Progress Energy offer several
examples where they have sold power to LSEs within their control areas
after the Commission imposed cost-based mitigation for those sales as
evidence that there is no basis for expecting mitigated utilities to
abandon long-standing customers and ``decades of intersystem
coordination and mutual assistance, whereby utilities take whatever
measures are possible * * * to help their neighbors maintain
reliability.'' \835\
---------------------------------------------------------------------------

    \834\ Duke/Progress Energy supplemental comments at 23 (citing
TAPS, 225 F.3d at 688, (emphasis in original)); see also Xcel reply
comments at 6-7 (parties have not provided any supporting rationale
that would justify a ``must offer'' requirement over other potential
purchasers); EEI supplemental comments at 3 (commenters have failed
to demonstrate that there is discrimination warranting generic
action).
    \835\ Duke/Progress Energy supplemental comments at 17 and n.7.
---------------------------------------------------------------------------

    741. A number of commenters assert that the Commission's statutory
authority to require wholesale sales under section 202(b) and 202(c) of
the FPA is limited and cannot justify the imposition of a ``must
offer'' requirement in this context.\836\ Southern explains that the
Commission has forced power sales by a jurisdictional public utility to
wholesale customers under section 202(b) of the FPA only if such
customers have proven they lack service alternatives. Southern states
that it would be unreasonable to impose a generic obligation to serve
at wholesale by means of a ``must offer'' requirement, absent
particularized findings based on a properly developed record that
wholesale customers lack reasonable alternatives.\837\
---------------------------------------------------------------------------

    \836\ See, e.g., Pinnacle at 8; EEI at 35-36; Progress Energy
reply comments at 5, n.5; Duke reply comments at 6.
    \837\ Southern at 60.
---------------------------------------------------------------------------

    742. EEI agrees that the Commission's section 202(b) authority is
clearly aimed at individual transactions where a wholesale customer
cannot access supply, with ample due process safeguards to ensure that
a requirement to sell is truly warranted and will not

harm the seller.\838\ EEI states that the Commission cannot turn such a
provision into a blanket regulatory requirement without violating the
intent of Congress and inappropriately bypassing these safeguards, nor
is such a blanket requirement warranted.\839\
---------------------------------------------------------------------------

    \838\ EEI reply comments at 16.
    \839\ EEI at 35-36 (citing El Paso Electric Co. v. FERC, 201
FERC F.3d 667 (5th Cir. 2000)).
---------------------------------------------------------------------------

    743. Several commenters question the legal support for a ``must
offer'' requirement, arguing that the FPA does not contain an express
obligation to serve wholesale customers,\840\ and that neither section
205 nor section 206 of the FPA authorize the Commission to mandate or
prohibit sales, as long as they are made at just, reasonable, and non-
discriminatory rates approved by the Commission.\841\
---------------------------------------------------------------------------

    \840\ MidAmerican at 18-19; EEI at 33; Southern at 59; Westar at
17; Duke at 12; E.ON U.S. reply comments at 1-2; Progress at 13.
    \841\ EEI at 35; Progress Energy at 13-14; E.ON U.S. reply
comments at 1-2; Duke reply comments at 5-6.
---------------------------------------------------------------------------

    744. Many commenters also contest claims that sales outside the
mitigated control area at market-based rates constitute withholding or
undue discrimination. Westar and others suggest that offering
generation for sale outside of the mitigated control area at the
prevailing market price to serve demand does not constitute
withholding. They state that withholding generally refers to either
physical withholding (not offering to sell) or economic withholding
(offering to sell only at inflated prices), which in either case is
intended to raise prices.\842\ Duke/Progress Energy claim that ``the
Commission has confirmed that it is `legitimate economically rational'
behavior for a market participant to export power in order to sell at
higher prices outside a control area rather than to sell at lower
capped prices within a control area.'' \843\ Westar similarly argues
that, absent evidence of manipulation or fraud, a `` `seller of a
commodity is acting quite rationally and legally to withhold his supply
from the market if he believes that in the future the commodity will
command a higher price--assuming, of course, the seller is under no
legal duty to sell.' '' \844\ Westar and E.ON U.S. reason that the
Commission's market behavior rules already address economic withholding
concerns.\845\
---------------------------------------------------------------------------

    \842\ EEI reply at 2; Duke/Progress Energy at 15.
    \843\ Duke/Progress Energy at supplemental comments 16 (quoting
San Diego Gas & Elec. Co., 103 FERC ] 61,345 at P 63 (2003)).
    \844\ See Westar at 11, n.23 (quoting United States v. Reliant
Energy Services Co., 420 F. Supp. 2d 1043, 1059 (N.D. Cal. 2006));
see also EEI at 36.
    \845\ Westar at 12; E.ON U.S. reply comments at 7. In adopting
those rules, Westar submits that the Commission specifically
rejected arguments that ``withholding for an anti-competitive
purpose can only be remedied by way of a generic ``must offer''
obligation,'' stating that ``[i]n fact, where a seller intentionally
withholds capacity for the purpose of manipulating market prices,
market conditions, or markets rules for electric energy or
electricity products, it has done so without a legitimate business
purpose in violation of Market Behavior Rule 2.'' Westar at 12
(quoting Investigation of Terms and Conditions of Public Utility
Market-Based Rate Authorizations, 107 FERC ] 61,175 at P 27 (2004)
(emphasis added)).
---------------------------------------------------------------------------

    745. MidAmerican adds that in the limited instances where a
wholesale customer cannot obtain service, and where an obligation to
serve exists, the Commission can address the issue in fact-specific
proceedings of individual sellers.\846\ Duke suggests that the ``must
offer'' proponents have failed to demonstrate why ``self-supply,''
including new construction and supply from external resources, is not a
viable option in at least some instances.\847\ Duke states, for
example, that the Carolina Agencies submit that LSEs will have few if
any practical supply options if a mitigated supplier is not subject to
a must offer requirement. However in Duke's view, the Carolina Agencies
fail to demonstrate why ``self-supply,'' including construction of
local generation by their members, is not a viable option in at least
some instances. Nor do they demonstrate lack of ability to secure
supply from resources external to the control area. Duke submits that
even where construction of new generation may not be cost-effective,
``self-supply'' includes purchasing as well as self-build. Duke argues
that lack of an economic self-build option at a given time does not
relieve an LSE of its obligation to acquire generation resources
through alternate means such as long-term purchases.\848\
---------------------------------------------------------------------------

    \846\ MidAmerican at 19.
    \847\ Duke reply comments at 10. APPA/TAPS responds that the
Commission has recognized that not all LSEs can build their own
generation. APPA/TAPS reply comments at 9 (citing April 14 Order,
107 FERC ] 61,018 at P 155).
    \848\ Duke reply comments at 10.
---------------------------------------------------------------------------

    746. Several commenters similarly challenge the claim that choosing
to make sales outside the mitigated control area at market-based rates
is discriminatory. EEI notes that not all rate distinctions are
prohibited by section 205(b) of the FPA. It states that only undue
discrimination between customers of the same class that is not
justified by cost of service differences, operating conditions, or
other considerations is forbidden.\849\ In this proceeding, Duke/
Progress Energy claim that wholesale customers are seeking a superior
product to that offered to other customers outside the mitigated
control area: ``a Commission-enforced right to a free and unilateral
call option to buy any available energy generated by [m]itigated
[u]tility assets at cost-based prices, exercisable during peak periods
when market prices are high.'' \850\
---------------------------------------------------------------------------

    \849\ EEI reply comments at 13-14 (citations, including
Wisconsin Michigan Power Co., 31 FPC 1445 (1964); CED Rock Springs
LLC, 116 FERC ] 61,163 at P 39 (2006) (In examining potential undue
discrimination, the Commission properly focuses on whether ``there
are any similarly situated projects that have been treated
differently.''); see also Badger Power Marketing Authority, 116 FERC
] 61,200 at P 10 (2006) (approving a rate that is essentially the
same as the rate charged another similarly-situated customer)).
    \850\ Duke/Progress Energy supplemental comments at 9.
---------------------------------------------------------------------------

    747. EEI adds that the courts also recognize that the just and
reasonable standard allows--and can even require--rate differences to
reflect different locations and classes of customers.\851\ EEI and
Progress Energy therefore contend that, once the Commission has
determined whether a seller may sell at market-based rates or must use
mitigated rates in various markets, the seller must be allowed to sell
electricity at the just and reasonable rates approved for the different
markets.\852\
---------------------------------------------------------------------------

    \851\ EEI reply comments at 14-15 (citing Town of Norwood,
Massachusetts v. FERC, 202 F.3d 392 at 402 (1st Cir. 2000)
(``[D]ifferential treatment does not necessarily amount to undue
preference where the difference in treatment can be explained by
some factor deemed acceptable by the regulators (and the
courts).''); City of Vernon, California v. FERC, 983 F.2d 1089 at
1093 (D.C. Cir. 1993)).
    \852\ Id. at 15; Progress Energy at 13.
---------------------------------------------------------------------------

    748. MidAmerican claims that customer concerns that a mitigated
seller will unduly discriminate between the seller's native load and
wholesale customers in the mitigated region are baseless because the
Commission's jurisdiction does not extend to a comparison of retail and
wholesale rates. MidAmerican states that while a seller typically has
an obligation to serve retail customers in a franchised service area,
that obligation does not extend to wholesale customers. Therefore,
MidAmerican states there is no issue of undue discrimination between
retail and wholesale rates that either requires or allows a ``must
offer'' requirement.\853\
---------------------------------------------------------------------------

    \853\ MidAmerican reply comments at 7; see also, Duke reply
comments at 6. Compare APPA/TAPS reply comments at 3 (``The
Commission is not called upon to decide a struggle between wholesale
and retail ratepayers, but to set a just and reasonable wholesale
rate, which a Commission-approved cost-based rate surely is.'').
---------------------------------------------------------------------------

    749. Xcel and others submit that wholesale customers are seeking a
preference or entitlement through a ``must offer'' requirement and are
in fact calling for discrimination by asserting a preference to power
available for sale by a mitigated seller over all other

purchasers, even those who value it more highly,\854\ and have provided
no evidence to justify such a preference or entitlement over other
potential purchasers.\855\ Duke/Progress Energy state that customer
claims that ``they are victims of market power and therefore need some
specially tailored remedy'' is erroneous, and that ``[b]y imposing
cost-based rates * * * within their control area, the Commission has
fully mitigated any market power concerns.'' \856\ Xcel and others also
note that the LSEs have no reciprocal obligation to purchase power if a
``must offer'' requirement were imposed upon mitigated sellers.\857\
---------------------------------------------------------------------------

    \854\ Xcel reply at 6-7; EEI supplemental comments at 4-5.
    \855\ Xcel reply comments at 6-7; Progress Energy reply comments
at 2, 4, 7-11; Duke reply comments at 7, n.10.
    \856\ Duke/Progress Energy supplemental comments at 13 (citing
Duke Power, 113 FERC ] 61,192 at P 22).
    \857\ Xcel reply comments at 7; Progress Energy reply comments
at 6; MidAmerican reply comments at 9.