that incorporate the seller's proposal for mitigation. As the
Commission stated in the April 14 Order, where a seller proposes to
adopt the default cost-based rates (or where it proposes other cost-
based rates), it must provide cost support for such rates. The
Commission will examine the proposed rates on a case-by-case
basis.\807\ With regard to sales of one week or less, where the seller
fails to provide sufficient cost-support, the Commission will direct
the seller to submit a compliance filing to provide the formulas and
methodology according to which it intends to calculate incremental
costs.\808\
---------------------------------------------------------------------------

    \805\ Order No. 697 at P 630.
    \806\ Id. P 629.
    \807\ Id. P 630 (citing April 14 Order, 107 FERC ] 61,018 at P
208; Entergy Services, Inc., 115 FERC 61,260 at P 49 (2006)
(accepting cost-based rates based on incremental cost plus 10
percent, noting that filing included the formula and methodology
according to which seller intends to calculate incremental costs)).
    \808\ Id. P 630 (citing Aquila, Inc., 112 FERC ] 61,307, at P 26
(2005); Oklahoma Gas and Electric Co., 114 FERC ] 61,297, at P 19
(2006)).
---------------------------------------------------------------------------

    490. With regard to sales of greater than one week but less than
one year, the Commission similarly requires that the seller submit a
cost-based rate tariff for filing that identifies the methodology to be
used to calculate the rate. When a seller adopts the default cost-based
rate for mid-term sales (which is based on the unit or units expected
to run), or otherwise proposes a cost-based rate designed on the unit
or units expected to run, the Commission stated that it will continue
to allow the seller flexibility in selecting the particular units that
form the basis of the ``up to'' rate. However, as the Commission also
stated in the Final Rule, it considers all evidence when reviewing a
cost-based rate proposal and, if a company has not justified selection
of certain generation units, the Commission will not accept the
proposed rate.\809\ Nevertheless, as with all cost-based mitigation
proposals, the seller must file a cost-based rate tariff with the
Commission and must provide cost support for such rates.\810\
Accordingly, we clarify in response to NASUCA's request that when a
mitigated seller files a cost-based mitigation proposal with the
Commission, the seller must file an accompanying tariff.
---------------------------------------------------------------------------

    \809\ Id. P 649, 651.
    \810\ As explained in the Final Rule, upon loss or surrender of
market-based rate authority a seller has a number of options of 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. See Order No. 697 at
n.699.
---------------------------------------------------------------------------

    491. We reject NASUCA's argument that there is no opportunity for
public notice, or protest and Commission review of rates for mitigated
sellers, and no opportunity for refund of unreasonable rates charged by
sellers with market power for sales of up to one year's duration. As
noted above and as discussed in the Final Rule, all mitigation
proposals must be filed with the Commission for review.\811\ These
filings are noticed and interested parties are given an opportunity to
intervene, comment or protest the submittal.\812\ As the Commission
stated in the Final Rule, it will continue to conduct its 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.\813\ Under the FPA, the Commission
has the authority to accept, reject, or modify a proposed rate based on
the analysis of the specific facts and circumstances.\814\ Contrary to
NASUCA's contention that the Commission provides no opportunity for
review of, and for refund of, rates charged by mitigated sellers for
sales of up to one year's duration, the Commission has accepted,
subject to refund, suspended and set for hearing cost-based mitigation
proposals.\815\
---------------------------------------------------------------------------

    \811\ Order No. 697 at P 629.
    \812\ Id.
    \813\ Id. P 650.
    \814\ Id. P 651.
    \815\ See Id. P 631 (citing AEP Power Marketing, Inc., 112 FERC
] 61,047, at P 28 (2005) (accepting, subject to refund, and setting
for hearing, AEP's proposed rate for sales of power of more than one
week but less than one year upon finding that AEP did not provide
sufficient cost support for the rate levels proposed). See also,
Duke Power, 113 FERC ] 61,192, at P 38 (2005).
---------------------------------------------------------------------------

    492. We find NASUCA's reliance on FPC v. Conway to support its
argument that the Commission should not grant mitigated sellers the
flexibility to propose rates between marginal cost and embedded cost to
be misplaced. In FPC v. Conway, the Supreme Court held that a utility
could not set low retail rates to attract retail industrial customers
from other utilities and set wholesale rates at prices higher than the
retail rate so that its wholesale competitors could not compete in the
retail market. The Court also held that, although the FPC lacked the
authority to fix retail rates, it may take those rates into account
when it fixes the rates for interstate wholesale sales that are subject
to its jurisdiction.\816\ As explained above, the Final Rule requires
that the seller submit a cost-based rate tariff for filing that
identifies the methodology to be used to calculate the rate for mid-
term sales. Further, the Final Rule requires that, to the extent a
seller proposes a cost-based rate formula, the rate formula to be used
must be provided for Commission review and such formula must be
included in the cost-based rate tariff, including formulas used in
calculating incremental cost.\817\ As the Final Rule explains, the
Commission examines the proposed rate formulas of mitigated sellers on
a case-by-case basis, and in doing so, fulfills its FPA mandate to
ensure that rates are just and reasonable and not unduly
discriminatory. Because the Final Rule requires sellers to submit a
cost-based rate tariff for filing that identifies the methodology to be
used to calculate the rate, and thereby does not permit sellers with
market power to ``set rates at will,'' NASUCA's contention that
allowing sellers with market power ``to set rates at will between
marginal cost and embedded cost * * * could give the utility with
wholesale market power the opportunity to extend it into retail
markets'' is without merit. Thus, NASUCA's claim that a scenario
resulting in potentially discriminatory or predatory conduct could
occur is speculative and unsupported by the facts in the record.
---------------------------------------------------------------------------

    \816\ 426 U.S. 271, 279-80 (1976).
    \817\ Order No. 697 at P 630.
---------------------------------------------------------------------------

    493. We reject NASUCA's argument that allowing mitigated sellers to
make sales for less than one year without filing them is a
subdelegation to private parties of the duties conferred upon the
Commission by Congress. NASUCA relies on ISO New England, Inc.\818\ to
support its argument in this regard. In ISO New England, Inc., the
Commission preauthorized ISO New England to enter into mitigation
agreements intended to mitigate generation resources that ran out-of-
economic merit order during periods of transmission constraints, and
concluded that all such agreements were just and reasonable. On appeal,
the D.C. Circuit remanded to the Commission the issue concerning
whether the rates adopted in mitigation agreements were just and
reasonable because the Commission had not reviewed data concerning
generator costs for the rates in the mitigation agreements.\819\
Contrary to NASUCA's argument, and unlike the situation in ISO New
England, Inc., the Final Rule states that ``where a seller proposes to
adopt the default cost-based rates (or where it proposes other cost-
based rates), it must provide cost support for such rates. The
Commission will

examine the proposed rates on a case-by-case basis.'' \820\ Here, the
Commission has not neglected to review a mitigation proposal, or the
cost support for such a proposal. Rather, it is promulgating a rule
which provides for Commission examination of rates proposed by
mitigated sellers, and that requires cost support for such rates. Thus,
NASUCA's argument in this regard is without merit.
---------------------------------------------------------------------------

    \818\ 818 112 FERC ] 61,057 (2005), reversed in part, NSTAR, 481
F.3d 794.
    \819\ NSTAR, 481 F.3d 794.
    \820\ Order No. 697 at P 630.
---------------------------------------------------------------------------

    494. Further, as explained above, the Final Rule retained the
Commission's current policy of pricing sales of more than one week but
less than one year at an embedded cost ``up to'' rate reflecting the
costs of the generating unit(s) expected to provide the service.\821\
Although this approach allows sellers flexibility in designing ``up
to'' rates for purposes of mitigation for sales of more than one week
but less than one year, such rates are still subject to Commission
review and approval.\822\ 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.\823\ NASUCA relies on U.S. Telecomm. Ass'n v.
FCC,\824\ and Chairman Kelliher's dissent in ISO New England Inc. to
support its contention that the Commission may not delegate its
authority to private parties. As we explain above, however, because the
Final Rule provides for Commission review of a seller's proposed rates,
and because the Commission will not accept the proposed rate if a
company has not justified selection of certain generating units, the
Final Rule is not subdelegating the Commission's duties.\825\
---------------------------------------------------------------------------

    \821\ Order No. 697 at P 648.
    \822\ Id. P 652.
    \823\ Id. P 651.
    \824\ 359 F.3d 554 (D.C. Cir. 2004) (finding that a federal
agency may not delegate its authority to outside entities).
    \825\ See Order No. 697 at P 629, 651.
---------------------------------------------------------------------------

    495. We also reject NASUCA's argument that under the Final Rule,
rates of mitigated sellers rely on private parties to negotiate and
charge reasonable rates and thereby are in contravention of the
holdings of MCI and Electrical District. In MCI, the Supreme Court
rejected an FCC policy that relieved all non-dominant carriers of any
requirement to file any of their rates with the agency. Electrical
District holds that the Commission cannot, in a proceeding under
section 206, ``announce some formula and later reveal that formula was
to govern from the date of announcement.''\826\ Both of these cases are
distinguishable from the mitigation scheme set forth in the Final Rule.
Because the Final Rule explains that ``all mitigation proposals must be
filed with the Commission for review'' and states that ``[t]hese
filings will be noticed and interested parties will be given an
opportunity to intervene, comment, or protest the submittal'' \827\ the
Final Rule does not rely on private parties to negotiate and charge
reasonable rates and does not contravene the holdings in MCI and
Electrical District.
---------------------------------------------------------------------------

    \826\ Transwestern Pipeline Co. v. FERC, 897 F.2d 570, 578 (D.C.
Cir. 1990). See supra P 453.
    \827\ Order No. 697 at P 629.
---------------------------------------------------------------------------

3. Whether Existing Tariffs Must Be Found To Be Unjust and
Unreasonable, and Whether the Commission Must Establish a Refund
Effective Date
Final Rule
    496. The Final Rule determined that the Commission was not required
to establish a refund effective date and concluded that continuing to
allow basic inconsistencies in the market-based rate tariffs on file
with the Commission is unjust and unreasonable.\828\ The Commission
found that even if section 206 were read to require the establishment
of a refund effective date in rulemakings initiated under section 206,
rather than only in case-specific section 206 investigations initiated
by complaints or sua sponte by the Commission, the Commission has broad
discretion to adopt a generic policy or make generic findings through
either rulemaking or adjudication.\829\ The Commission concluded that
``[t]his proceeding is not an adjudicatory investigation of public
utilities' existing market-based rate tariffs for which refunds will be
required. Rather, we are modifying existing market-based rate tariffs
prospectively only through this rulemaking. Accordingly, the
establishment of a refund effective date in this rulemaking would be
meaningless.'' \830\
---------------------------------------------------------------------------

    \828\ Id. P 974.
    \829\ Id. P 975 (citing Lockyer).
    \830\ Id. (citing Wisconsin Gas Co. v. FERC, 770 F.2d 1144, 1166
(D.C. Cir. 1985); SEC v. Chenery, 332 U.S. 194, 202-03, reh'g
denied, 332 U.S. 747 (1947) (emphasis in original).
---------------------------------------------------------------------------

Requests for Rehearing
    497. Consumer Advocates contend that the Final Rule points to no
specific legal authority under either section 205 or 206 that supports
the Commission's action. They state that the Commission claims it is
not ``adjudicating'' in the Final Rule, but fails to recognize that the
Commission's authority to issue rules under sections 205 and 206 is
narrowly constrained because the Commission has no independent
ratemaking power under the FPA.\831\ Consumer Advocates state that
pursuant to United Gas Pipe Line and Sierra, the Commission has
authority under section 206(a) to review initial rates and contracts
filed by utility sellers, or ongoing, previously effective rates.
Consumer Advocates contend that before the Commission can act under
section 206(a), it must find existing rates to be unlawful, and also
must find market-based rates as modified by the rulemaking to be just
and reasonable and not unduly preferential or discriminatory going
forward. They submit that although the Final Rule purports to make the
first finding that existing rates without the new rules are unjust and
unreasonable, it fails to make the second finding that market-based
rates that adhere to the Final Rule are just and reasonable.\832\
Consumer Advocates contend that the Final Rule pointed to no legal
authority under section 205 or 206 that supports the actions taken, but
instead points only to policy choices regarding the market-based rate
regime. Consumer Advocates assert that the Commission has no authority,
even to implement policy, unless the statute confers it.\833\
---------------------------------------------------------------------------

    \831\ Id. at 16 (citing United Gas Pipe Line; Sierra).
    \832\ Id. (citing United Gas Pipe Line; Sierra).
    \833\ Id. at 17 (citing Atlantic City Electric Co. v. FERC, 295
F.3d 1, 8 (D.C. Cir. 2002) (Atlantic City)).
---------------------------------------------------------------------------

Commission Determination
    498. We disagree with Consumer Advocates' contentions that the
Commission must find existing market-based rates to be unlawful and
must set new lawful rates going forward and that the Commission has no
authority to implement the policies in this rulemaking. We have broad
discretion to adopt generic policy or make generic findings through
either rulemaking or adjudication,\834\ and we have discretion over
whether to order refunds.\835\ We

reiterate that this proceeding is not an adjudicatory investigation of
public utilities' existing market-based rate tariffs for which refunds
will be required.\836\
---------------------------------------------------------------------------

    \834\ An agency enjoys broad discretion to determine its own
procedures, including whether to act by a generic rulemaking or by
case-by-case adjudication. Mobil Oil Exploration & Producing
Southeast, Inc. v. United Distrib. Cos., 498 U.S. 211, 230 (1991);
NLRB v. Bell Aerospace Co., 416 U.S. 267, 293 (1974); Interstate
Natural Gas Association of America v. FERC, 285 F.3d 18, 57-58 (D.C.
Cir. 2001).
    \835\ See e.g., Lockyer, 383 F.3d at 1016. Consumer Advocates
rely on Atlantic City for support for their argument that the
Commission has no authority to implement policy unless a statute
confers it. In Atlantic City, the court held that the Commission did
not have authority to require utilities to give up their right to
file rate changes or authority to mandate that withdrawal from an
ISO could only become effective upon Commission approval. However,
because the courts have repeatedly upheld the Commission's authority
to adopt market-based rates, Consumer Advocates' reliance on
Atlantic City for support for their argument in this regard is
misplaced. See, e.g., LEPA, 141 F.3d 364; Lockyer, 383 F.3d 1006;
Snohomish, 471 F.3d 1053.
    \836\ Order No. 697 at P 975.
---------------------------------------------------------------------------

    499. We also reject Consumer Advocates' assertion that the instant
rulemaking is in contravention of United Gas Pipe Line and Sierra
because the Final Rule did not make the finding that market-based rates
that adhere to the Final Rule are just and reasonable. In United Gas
Pipe Line, the Supreme Court interpreted provisions of the NGA that
parallel the FPA, and it stated that section 4(d) of the NGA says only
that ``a change in the filed rate cannot be made without proper notice
to the Commission.'' \837\ The Supreme Court held in Sierra that the
FPA does not authorize unilateral contract changes and held that the
Federal Power Commission could not declare a rate set by a contract to
be ``unreasonable solely because it yields less than a fair return on
the next invested capital.'' \838\ Unlike United Gas Pipe Line and
Sierra, this rulemaking proceeding is not an adjudicatory investigation
of a public utility's existing rates for which refunds will be
required. Rather, in the Final Rule the Commission revised and codified
its market-based rate policy for public utilities on a generic basis.
Contrary to Consumer Advocates' argument that the Commission did not
specify ``exactly what it is doing in the Final Rule,'' the Commission
clearly stated that it is ``modifying existing market-based rate
tariffs prospectively only through this rulemaking.'' \839\
---------------------------------------------------------------------------

    \837\ United Gas Pipe Line, 350 U.S. at 339 (emphasis in
original).
    \838\ Sierra, 350 U.S. at 355.
    \839\ Order No. 697 at P 975 (citing Wisconsin Gas Co. v. FERC,
770 F.2d 1144, 1166 (D.C. Cir. 1985); SEC v. Chenery, 332 U.S. 194,
202-03, reh'g denied, 332 U.S. 747 (1947) (emphasis in original)).
---------------------------------------------------------------------------

G. Miscellaneous

1. Change in Status
a. Reporting
Final Rule
    500. In Order No. 697, the Commission continued its requirement for
sellers to report any change in status that departs from the
characteristics relied upon by the Commission in authorizing sales at
market-based rates.\840\ Events that constitute a change in status
include, among other things, ownership or control of generation
capacity that result in net increases of 100 MW or more, and change in
upstream ownership. Notification of any such changes in status must be
filed no later than 30 days after the change occurs.
---------------------------------------------------------------------------

    \840\ Order No. 697 at P 1009-1045 (codifying the requirement,
as amended, at 18 CFR 35.42).
---------------------------------------------------------------------------

    501. Also in Order No. 697, the Commission created a category of
market-based rate sellers that are exempt from the requirement to
submit regularly scheduled updated market power analyses. These
Category 1 sellers have been carefully defined by the Commission to
have attributes that are not likely to present market power
concerns.\841\ Market power concerns for Category 1 sellers are
monitored by the Commission through the change in status reporting
requirement and through ongoing monitoring by the Commission's Office
of Enforcement. All other sellers, Category 2 sellers, are, in
addition, required to continue to file regularly scheduled updated
market power analyses.\842\
---------------------------------------------------------------------------

    \841\ Id. at P 853.
    \842\ Previously, updated market power analyses were submitted
within three years of any order granting a seller market-based rate
authority, and every three years thereafter.
---------------------------------------------------------------------------

Requests for Rehearing
    502. TDU Systems assert that to protect consumers more adequately,
the Commission should require a Category 2 seller to submit an updated
market power analysis in each instance in which a seller's generation
increases by a predetermined percentage or an absolute amount.\843\ TDU
Systems state that under the Commission's present rules, a public
utility that builds or acquires new generation capacity or merges with
another company is not required to submit a new horizontal market power
analysis. It is required only to file a change in status report for any
net increase of 100 MW or more. TDU Systems references a proposal made
by another commenter in response to the NOPR asking the Commission to
require an updated market power analysis in each instance in which a
seller's generation increases by a predetermined percentage or absolute
amount. According to TDU Systems, the Commission did not directly
address this proposal in the Final Rule,\844\ but indirectly touched on
the issue by stating that an updated market power analysis may be
required from any sellers, Category 1 or 2, at any time.
---------------------------------------------------------------------------

    \843\ TDU Systems at 28 (citing NRECA NOPR comments at 24. NRECA
gives examples of predetermined thresholds as a certain percentage
increase over the current amount, or any increase over some absolute
amount).
    \844\ TDU Systems indicate that NRECA suggested this proposal.
TDU Systems at 27-28 (citing NRECA NOPR comments at 23-25).
---------------------------------------------------------------------------

    503. TDU Systems assert that the Commission erred in failing to
address the merits of this proposal in the Final Rule.\845\ They
contend that the Commission should not burden itself with deciding when
major additions to generation, revealed in a change in status report,
are likely to alter the results of its market power tests. They submit
that it would not be an unreasonable burden on Category 2 sellers to
prepare updated analyses within a reasonable time from the acquisition
of additional generation.
---------------------------------------------------------------------------

    \845\ Id. at 4-5 (citing K N Energy, Inc. v. FERC, 968 F.2d
1295, 1303 (D.C. Cir. 1991)).
---------------------------------------------------------------------------

Commission Determination
    504. In the Final Rule, the Commission stated that it retains the
tools necessary to ensure that all rates are just and reasonable, with
initial market power evaluations, ongoing monitoring by the Commission,
change in status reporting requirements, and scheduled updated market
power analyses for Category 2 sellers.\846\ We continue to believe that
these requirements provide the Commission with the tools it needs to
ensure that rates remain just and reasonable.
---------------------------------------------------------------------------

    \846\ Order No. 697 at P 853-854.
---------------------------------------------------------------------------

    In Order No. 652, the Commission clarified and standardized market-
based rate sellers' reporting requirement for changes in status and the
Commission considered and rejected the idea that change in status
filings include an updated market power analysis. The Commission
explained that it is incumbent on an applicant to decide whether a
change in status is a material change and that an applicant should
provide adequate support and analysis, including an updated market
power analysis if it chooses.\847\ Thus, if a market-based rate seller
believes that a change in status does not affect the continuing basis
of the Commission's grant of market-based rate authority, it should
clearly state the reasons on which it bases this conclusion, including
an updated market power analysis if it so chooses.
---------------------------------------------------------------------------

    \847\ Order No. 652, FERC Stats. & Regs. ] 31,175 at P 94-95.
---------------------------------------------------------------------------

    505. While we appreciate TDU Systems' proposal and agree that it
would not necessarily be an unreasonable burden to require Category 2
sellers to prepare updated analyses within a reasonable time from the
acquisition of additional generation, we are not persuaded that our
current approach is not adequate. The existing reporting requirement
provides the

Commission a sufficient tool to allow it to assess whether there is a
potential market power concern and, if so, the Commission reserves the
right to require the seller to submit a market power study. In
addition, the seller is required to provide an affirmative statement as
to what effect, if any, the added generation has on its market power.
For a seller to make such an affirmative statement, it must determine
what effect the added generation has on the market power analysis. To
the extent the seller makes an affirmative statement that there is no
effect on its market power, it is bound to that statement and faces
remedial action, including civil penalties, if it has misrepresented
the effect.
    506. Therefore, we will not require entities to automatically file
an updated market power analysis with their change in status filings,
such as that required by a triennial review. However, an entity may
provide such an analysis if it chooses. Furthermore, regardless of the
seller's representation, if the Commission has concerns with a change
in status filing (for example, market shares are below 20 percent, but
are relatively high nonetheless), the Commission retains the right to
require an updated market power analysis at any time.\848\
---------------------------------------------------------------------------

    \848\ Order No. 697 at P 856-857.
---------------------------------------------------------------------------

b. Transmission Outages
Final Rule
    507. The Final Rule adopted the NOPR proposal not to require the
reporting of transmission outages per se as a change in status. The
Commission explained that the reporting of all transmission outages,
including the most routine, would be an excessive burden on sellers
with no apparent countervailing benefit. However, the Final Rule stated
that, consistent with Order No. 652, to the extent that a long-term
transmission outage affects one or more of the factors of the
Commission's market-based rate analysis (e.g., if it reduces imports of
capacity by competitors that, if reflected in the generation market
power screens, would change the results of the screens from a ``pass''
to a ``fail''), a change in status filing is required.\849\
---------------------------------------------------------------------------

    \849\ Order No. 697 at P 1025.
---------------------------------------------------------------------------

Requests for Rehearing
    508. Wisconsin Electric requests that the Commission clarify which
entity is responsible for reporting long-term transmission outages as a
change in status. Wisconsin Electric explains that companies such as
itself that do not own transmission may not be in the position of
knowing the details of transmission outages and the effects of an
outage on their market power analyses. Therefore, Wisconsin Electric
requests that the Commission clarify that non-transmission owning
entities such as itself need not report long-term outages.\850\
---------------------------------------------------------------------------

    \850\ Wisconsin Electric at 4-5.
---------------------------------------------------------------------------

Commission Determination
    509. The Final Rule did not expand the events that trigger a change
in status filing to include actions taken by a competitor (such as a
decision to take transmission capacity out of service), beyond those
adopted in Order No. 652. Furthermore, the Commission found that it is
not reasonable to routinely require sellers to make a showing regarding
potential barriers to entry that others might erect or are beyond the
seller's control.\851\ Thus, as a general matter, a transmission outage
that occurs beyond a seller's control does not necessarily trigger a
change in status filing.\852\ In certain circumstances, however, a
seller, including a non-transmission owning entity, will be required to
submit a change in status filing, as stated above,\853\ when it or its
affiliate know that a long-term transmission outage has an effect on
its market power analysis (e.g., the long-term transmission outage
causes the seller to fail one or more of the indicative screens).
---------------------------------------------------------------------------

    \851\ Order No. 697 at P 1035.
    \852\ We clarify that, to the extent the Commission becomes
aware of a possible barrier to entry such as a long-term
transmission outage, the Commission reserves the right to require
any market-based rate seller to demonstrate what effect, if any,
that barrier to entry has on its ability to exercise market power.
    \853\ Order No. 652, FERC Stats. & Regs. ] 31,175 at P 75.
---------------------------------------------------------------------------

c. Other Clarifications
    510. Below we provide a number of other clarifications regarding
the change in status reporting requirement. Although no clarifications
or rehearing requests were submitted on these particular issues, the
Commission is aware of some confusion in the industry and accordingly
provides clarification.
Change in Status Reporting by Market
    511. As codified in Sec.  35.42 of the Commission's regulations,
events that constitute a change in status include, among other things,
changes in ownership or control of generation capacity that result in
net increases of 100 MW or more.\854\
---------------------------------------------------------------------------

    \854\ Id. at P 68.
---------------------------------------------------------------------------

    512. We clarify that a change in status should be filed to reflect
a change in the ownership or control of generation capacity that
results in a net increase of 100 MW or more in the geographic market
that was the subject of the horizontal market power analysis on which
the Commission relied in granting the seller market-based rate
authority. For example, if the Commission relied on a seller's default
geographic market in granting the seller market-based rate authority,
the seller would be required to submit a change in status filing for a
net increase of 100 MW or more of generation capacity in that
geographic market. Similarly, if the Commission relied upon an
alternative geographic market in granting a seller market-based rate
authority, any net increase of 100 MW or more of generation capacity in
the alternative geographic market would require the seller to submit a
change in status filing. On the other hand, if a seller has a net
increase of 50 MW in the geographic market on which the Commission
relied in granting the seller market-based rate authority and a 50 MW
increase in a different geographic market that is in the same region as
defined by Appendix D of Order No 697, the 100 MW or more threshold
would not be met because the increase in generation capacity is less
than 50 MW in each generation market and, accordingly, a change in
status filing would not be required.
Change in Status Reporting Cumulatively
    513. A seller must submit an initial application to receive market-
based rate authority and file change in status filings in compliance
with its market-based rate authority, such as an increase of 100 MW or
more in a geographic market. However, in the course of processing
change in status filings made by sellers, the Commission believes that
it has not been clear to some sellers that increases in generation
should be reported cumulatively. For example, some sellers have
submitted a series of change in status reports that consider only the
additional capacity on a standalone basis rather than considering the
total effect of each generation capacity increase since the seller's
last market power analysis. When a seller submits a change in status
filing to report an increase of 100 MW or more of generation capacity
in a geographic market, rather than treating each increase in
generation capacity on a standalone basis, the seller should consider
the cumulative effect of all increases in generation capacity since its
most recently approved market power analysis.
    514. For example, if a seller acquires generation capacity
resulting in a net increase of 100 MW in a market in January, it is
required to submit a change in status filing reflecting this net

increase. However, if the seller adds an additional 100 MW of
generation in the same market in February, the seller must account for
a cumulative total of 200 MW in that market when submitting its change
in status filing for the February addition of generation capacity. This
cumulative net increase since a seller's most recently approved market
power analysis must be the basis of the seller's change in status to
reflect that it does or does not depart from the characteristics the
Commission relied on in authorizing sales at market-based rates.
2. Third Party Providers of Ancillary Services
Final Rule
    515. In the Final Rule, the Commission modified its approach for
third-party sellers of ancillary services at market-based rates as
announced in Avista.\855\ The Commission noted that the posting and
reporting requirements imposed in Avista may be hindering the
development of ancillary services markets, particularly by third-party
providers. Thus, the Commission concluded that the EQR filing
requirement provides an adequate means to monitor ancillary services
sales by third parties such that the posting and reporting requirements
established in Avista are no longer necessary.\856\
---------------------------------------------------------------------------

    \855\ Order No. 697 at P 1058. See Avista Corporation, 87 FERC ]
61,223 (Avista), order on reh'g, 89 FERC ] 61,136 (Avista II)
(1999).
    \856\ With this modification adopted in the Final Rule of
eliminating the specific posting and reporting requirements
established in Avista for third-party sellers of ancillary services,
the Commission expects to monitor ancillary services sales by third
parties through the EQR. In a notice seeking comments on proposed
revisions to the EQR Data Dictionary, Revised Public Utility Filing
Requirements for Electric Quarterly Reports, 122 FERC ] 61,194
(2008), the Commission is seeking comment on proposed changes that
would clarify that the ancillary services discussed in Avista must
be reported whenever those services are provided. Under the proposed
revisions, when a seller makes third-party sales of ancillary
services, that seller would be required to file, in its EQR,
transaction information including (but not limited to) the
purchaser, the ancillary service provided, and the price of the
service. (See http://www.ferc.gov/docs-filing/eqr.asp for more
information on EQR filings).
---------------------------------------------------------------------------

    516. In the Final Rule, the Commission stated that all sellers that
seek authority to sell ancillary services at market-based rates
pursuant to Avista \857\ must make a filing with the Commission to
request that authority and must include language in their market-based
rate tariffs identifying the ancillary services that they offer.\858\
Moreover, the Final Rule retained the Commission's current policy of
not allowing sales of ancillary services by a third-party supplier in
the following situations: (1) Sales to an RTO or an ISO, i.e., where
that entity has no ability to self-supply ancillary services but
instead depends on third parties; (2) sales to a traditional,
franchised public utility affiliated with the third-party supplier, or
sales where the underlying transmission service is on the system of the
public utility affiliated with the third-party supplier; and (3) sales
to a public utility that is purchasing ancillary services to satisfy
its own open access transmission tariff requirements to offer ancillary
services to its own customers.\859\ Standard applicable tariff
provisions to this affect appear in Appendix C of the Final Rule and
must be included in the tariffs of any entities that sell ancillary
services at market-based rates. The Commission reiterated that it is
open to considering requests for market-based rate authorization to
make such sales on a case-by-case basis.\860\
---------------------------------------------------------------------------

    \857\ The Avista policy applies to the following four ancillary
services: Regulation Service, Energy Imbalance Service, Spinning
Reserves, and Supplemental Reserves.
    \858\ Order No. 697 at P 1060. Sellers that have been granted
authority to provide third-party ancillary services need not reapply
because their authority continues.
    \859\ Order No. 697 at P 1061 (citing Avista, 87 FERC ] 61,223
at 61,883, n. 12).
    \860\ Id.
---------------------------------------------------------------------------

Requests for Rehearing
    517. Wisconsin Electric requests that the Commission clarify that
its decision to eliminate the posting and reporting requirements of
Avista extends to providers of ancillary services that provide
ancillary services other than the four services addressed in
Avista.\861\ Wisconsin Electric states that it is a third-party
provider of ancillary services and received Commission authorization to
offer the four services addressed in Avista, but it also received the
authorization to offer Dynamic Capacity and Energy Service as an
ancillary service, conditioned upon the requirements in Avista to
establish and maintain an Internet-based site and to file periodic
reports describing the company's activities in the ancillary services
markets.\862\ Wisconsin Electric requests that the Commission clarify
that the decision to remove the Avista posting and reporting
requirements pertains not only to the four ancillary services
specifically mentioned in Avista, but also to the other ancillary
services to which the Commission subsequently applied the Avista
requirements.\863\
---------------------------------------------------------------------------

    \861\ Wisconsin Electric Rehearing Request at 3.
    \862\ Id. at 4 (citing Wisconsin Electric Power Co., 93 FERC ]
61,302 (2000)).
    \863\ Id.
---------------------------------------------------------------------------

    518. Morgan Stanley seeks to clarify its own request to the
Commission to identify ways to encourage more robust ancillary services
markets outside of RTO/ISO control areas. Morgan Stanley states that
its request was intended to support the creation of physically-settled
bilateral ancillary services markets, not a market for financially-
settled products that are beyond the Commission's jurisdiction.\864\
---------------------------------------------------------------------------

    \864\ Morgan Stanley Rehearing Request at 1, 4.
---------------------------------------------------------------------------

    519. Furthermore, Morgan Stanley clarifies that it continues to
regard the creation of a robust bilateral market for physically-settled
ancillary services, particularly outside of ISOs and RTOs, as the next
step to facilitating greater competition in the wholesale energy
markets overall. It did not, however, provide details for specific
ancillary services proposals, other than the elimination of the Avista
posting requirement, because its comments were intended solely to show
support for a policy position. Thus, Morgan Stanley reaffirms its prior
request that the Commission continue to look for opportunities to jump-
start competition in the physical ancillary services markets throughout
the United States.\865\
---------------------------------------------------------------------------

    \865\ Id. at 5.
---------------------------------------------------------------------------

Commission Determination
    520. We will grant Wisconsin Electric's request for clarification.
As the Commission stated in the Final Rule, the ancillary services
addressed in Avista are Regulation Service, Energy Imbalance Service,
Spinning Reserves, and Supplemental Reserves. In Avista however, the
Commission also characterized Dynamic Capacity and Energy Service as an
ancillary service stating it is a combination of two ancillary
services, Regulation Service and Energy Imbalance Service, and is
intended to satisfy the transmission provider's option to allow
customers to supply ancillary services to the system directly. As such,
Dynamic Capacity and Energy Service is an approved ancillary service
conditioned upon the requirements and limitations of Avista.\866\
Similarly, in Wisconsin Electric Power Co., the Commission authorized
Wisconsin Electric to provide Dynamic Capacity and Energy Service as an
ancillary service conditioned upon Avista.\867\
---------------------------------------------------------------------------

    \866\ Avista II, 89 FERC ] 61,136 at 61,392.
    \867\ Wisconsin Electric Power Co., 93 FERC ] 61,302 (2000).
---------------------------------------------------------------------------

    521. Therefore, because Dynamic Energy and Capacity Service, as

described in Avista, was authorized by the Commission as an ancillary
service pursuant to the Avista policy, consistent with the Final Rule,
such sellers may continue to sell this ancillary service at market-
based rates and are no longer required to meet the Avista posting and
reporting requirements with regard to this service. The current EQR
Data Dictionary does not include Dynamic Energy and Capacity Service in
the standard list of products because this service is only offered by a
few companies. However, the Commission invited comments on adding new
ancillary service names in Docket No. RM01-8-009.\868\ Absent the
addition of a specific EQR Product Name, sellers offering this service
must report it as an ``Other'' product in both the contract and
transaction sections of their EQR.
---------------------------------------------------------------------------

    \868\ Revised Public Utility Filing Requirements for Electric
Quarterly Reports, 73 FR 12983 (Mar. 11, 2008), FERC Stats. & Regs.
] 35,557 (Mar. 3, 2008) (seeking comments on proposed revisions to
EQR Data Dictionary).
---------------------------------------------------------------------------

    522. We appreciate Morgan Stanley's clarification of its intent to
support the creation of physically-settled bilateral ancillary services
markets but the formation of such markets is beyond the scope of this
proceeding.
3. Requesting Market-Based Rate Authority for QFs
    523. The Final Rule amended the Commission's regulations governing
market-based rate authorizations for wholesale sales of electric
energy, capacity and ancillary services by public utilities. Although
the Final Rule did not address the specific applicability of market-
based rate authority to QFs, below we address sales by QFs at market-
based rates that are subject to the Commission's jurisdiction.
    524. QFs making certain sales of energy,\869\ as defined below, are
exempt from sections 205 and 206 of the FPA. These QF exemptions are
applicable to some sales at market-based rates.\870\ Therefore, sales
of a QF that meet specific criteria are exempt from section 205 and a
QF is authorized to make those sales at market-based rates without
making a section 205 filing.
---------------------------------------------------------------------------

    \869\ In the context of PURPA, the term energy includes
capacity, energy and ancillary services.
    \870\ See 18 CFR 292.601(c)(1).
---------------------------------------------------------------------------

    525. All sales of energy or capacity made by QFs 20 MW or smaller
are exempt from section 205. Sales from a QF larger than 20 MW are
exempt from section 205 only if those sales are made pursuant to a
state regulatory authority's implementation of PURPA, or if those sales
are made pursuant to a contract executed on or before March 17, 2006
\871\ (unless the sale is from a qualifying small power production
facility with a power production capacity which exceeds 30 MW, if such
facility uses any primary energy source other than geothermal
resources, in which case the sale is not exempt).\872\ If a QF's sales
are not exempt from section 205, but the QF would like to make sales at
market-based rates, the QF is required to request market-based rate
authority.\873\
---------------------------------------------------------------------------

    \871\ Id.
    \872\ 18 CFR 292.601(b). However, a qualifying facility that is
an eligible solar, wind, waste, or geothermal facility, as defined
by section 3(17)(E) of the Federal Power Act, is not subject to the
30 MW size limitation imposed by 18 CFR 292.601(b). See Cambria
Cogen Company, 53 FERC ] 61,459 (1990).
    \873\ We note that the Commission has previously granted market-
based rate authority to QFs that are larger than 20 MW for sales of
excess power. The Commission has also rejected requests for market-
based rate authority from QFs that are exempt from section 205. See,
e.g., SP Newsprint, 103 FERC ] 61,186 (2003).
---------------------------------------------------------------------------

    526. When a QF submits an application for market-based rate
authority, its application must fulfill the requirements in Order No.
697, as required by all applicants. A QF, however, must also inform the
Commission in its market-based rate application of its QF status and
explain its request to transact under market-based rates. For example,
a QF must explain whether any of its sales meet the requirements for
the exemption from section 205 contained in 18 CFR 292.601(c)(1).
Furthermore, if a QF desires to make certain energy sales at market-
based rates, while making other sales exempt from section 205, the QF
must list its limitations on sales at market-based rates in its market-
based rate tariff (i.e., sales under Seller's contract (Contract X),
which was executed on March 17, 2006, are exempt from section 205 and
sales outside of Contract X would be under market-based rates) and cite
to the Commission orders certifying or recertifying its QF status, and/
or to the docket numbers in which it self-certified or self-recertified
its QF status, as explained in Order No. 697.\874\
---------------------------------------------------------------------------

    \874\ Order No. 697 at P 916-17.
---------------------------------------------------------------------------

H. Clarifications of the Commission's Regulations

    527. The Commission finds, based on its further consideration of
the regulations, that several provisions should be changed to provide
additional clarity.
    528. First, one of the affiliate restrictions codified in the Final
Rule contained some minor omissions. Section 35.39(b) restricts sales
between a franchised public utility with captive customers and a
market-regulated power sales affiliate unless the seller first receives
Commission authorization for the transaction under section 205 of the
FPA. Upon further review, the Commission notes that the phrase ``or
capacity'' should be added to the term ``wholesale sales of electric
energy'' to ensure that the provision covers the appropriate scope of
affiliate sales. Therefore, we will amend Sec.  35.39(b) accordingly.
    529. Second, in the Final Rule, the Commission adopted a regulation
requiring sellers to timely report to the Commission any change in
status that would reflect a departure from the characteristics the
Commission relied upon in granting market-based rate authority. In
particular, Sec.  35.42 specifies that a change in status includes, but
is not limited to, ownership or control of generation capacity that
results in net increases of 100 MW or more.
    530. Upon further consideration, the Commission recognizes that
this provision deserves additional clarity. We take this opportunity to
clarify that a change in status also includes long-term firm capacity
purchases that result in net increases of 100 MW or more. This is
consistent with a seller's obligation to include long-term firm
capacity purchases in determining uncommitted capacity, which is used
in the indicative screens.\875\ We believe that revision to the
regulation is appropriate because the Commission's April 14 Order,
reaffirmed in Order No. 697, stated that uncommitted capacity is
determined ``by adding the total nameplate or seasonal capacity of
generation owned or controlled through contract and firm purchases,
less operating reserves, native load commitments and long-term firm
sales.'' \876\
---------------------------------------------------------------------------

    \875\ See April 14 Order, 107 FERC ] 61,018 at P 95, 100.
    \876\ See Order No. 697 at P 38 (emphasis added; footnote
omitted).
---------------------------------------------------------------------------

    531. Thus, long-term firm capacity purchases that result in net
increases of 100 MW or more are a ``departure from the characteristics
the Commission relied upon in granting market-based rate authority.''
Accordingly, Sec.  35.42(a)(1) is revised so that a change in status
includes, but is not limited to, ownership or control of generation
capacity and long-term firm purchases of generation capacity that
result in net increases of 100 MW or more. Because sellers may not have
been on notice that this was the Commission's intent, we will not hold
any sellers responsible for failure to report such changes in status
prior to the effective date of this order,

which will be 30 days after issuance in the Federal Register.
    532. Third, as explained earlier in the affiliate abuse section of
this order, we are revising the definition of captive customers and
adding a definition for affiliate. We will revise the definition of
captive customers in Sec.  35.36(a)(6) to mean any wholesale or retail
electric energy customers served by a franchised public utility under
cost-based regulation, to be consistent with the discussion in the
Affiliate Transactions Final Rule and the definition of captive
customers adopted in that rule at 18 CFR 35.42(a)(2). The definition of
affiliate as that term is used in the Affiliate Transactions Final Rule
will be codified at paragraph 35.36(a)(9).
    533. Fourth, we are revising Sec.  35.39(d)(1) to reflect the
determination to adopt a one-way information sharing restriction.
Finally, as discussed in the vertical market power section of this
order, we are revising the definition of inputs to electric power
production to clarify the types of coal supply that are intended to be
included in the definition.

III. Information Collection Statement

    534. The Office of Management and Budget (OMB) regulations require
that OMB approve certain information collection requirements imposed by
an agency.\877\ The Final Rule's revisions to the information
collection requirements for market-based rate sellers were approved
under OMB Control Nos. 1902-0234. While this order clarifies aspects of
the existing information collection requirements for the market-based
rate program, it does not add to these requirements. Accordingly, a
copy of this order will be sent to OMB for informational purposes only.
---------------------------------------------------------------------------

    \877\ 5 CFR 1320.11.
---------------------------------------------------------------------------

IV. Document Availability

    535. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    536. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    537. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
V. Effective Date

    538. Changes to Order No. 697 adopted in this order on rehearing
will become effective June 6, 2008.

List of Subjects in 18 CFR Part 35

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

    By the Commission. Commissioner Kelly concurring with a separate
statement attached.
Nathaniel J. Davis, Sr.,
 Deputy Secretary.

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

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

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

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 7101-7152.

0
2. In Sec.  35.36, paragraphs (a)(4) and (a)(6) are revised and
paragraph (a)(9) is added to read as follows:

Sec.  35.36  Generally.

    (a) * * *
    (4) Inputs to electric power production means intrastate natural
gas transportation, intrastate natural gas storage or distribution
facilities; sites for generation capacity development; physical coal
supply sources and ownership of or control over who may access
transportation of coal supplies.
* * * * *
    (6) Captive customers means any wholesale or retail electric energy
customers served by a franchised public utility under cost-based
regulation.
* * * * *
    (9) Affiliate of a specified company means:
    (i) For any person other than an exempt wholesale generator:
    (A) Any person that directly or indirectly owns, controls, or holds
with power to vote, 10 percent or more of the outstanding voting
securities of the specified company;
    (B) Any company 10 percent or more of whose outstanding voting
securities are owned, controlled, or held with power to vote, directly
or indirectly, by the specified company;
    (C) Any person or class of persons that the Commission determines,
after appropriate notice and opportunity for hearing, to stand in such
relation to the specified company that there is liable to be an absence
of arm's-length bargaining in transactions between them as to make it
necessary or appropriate in the public interest or for the protection
of investors or consumers that the person be treated as an affiliate;
and
    (D) Any person that is under common control with the specified
company.
    (E) For purposes of paragraph (a)(9)(i), owning, controlling or
holding with power to vote, less than 10 percent of the outstanding
voting securities of a specified company creates a rebuttable
presumption of lack of control.
    (ii) For any exempt wholesale generator (as defined under Sec.
366.1 of this chapter):
    (A) Any person that directly or indirectly owns, controls, or holds
with power to vote, 5 percent or more of the outstanding voting
securities of the specified company;
    (B) Any company 5 percent or more of whose outstanding voting
securities are owned, controlled, or held with power to vote, directly
or indirectly, by the specified company;
    (C) Any individual who is an officer or director of the specified
company, or of any company which is an affiliate thereof under
paragraph (a)(9)(ii)(A); and
    (D) Any person or class of persons that the Commission determines,
after appropriate notice and opportunity for hearing, to stand in such
relation to the specified company that there is liable to be an absence
of arm's-length bargaining in transactions between them as to make it
necessary or appropriate in the public interest or for the protection
of investors or consumers that the person be treated as an affiliate.
* * * * *

0
3. In Sec.  35.39, paragraphs (b) and (d)(1) are revised to read as
follows:

Sec.  35.39  Affiliate restrictions.

* * * * *
    (b) Restriction on affiliate sales of electric energy or capacity.
As a condition of obtaining and retaining market-based rate authority,
no wholesale sale of electric energy or capacity may be made between a
franchised public utility with captive customers and a market-regulated
power sales affiliate without first receiving

Commission authorization for the transaction under section 205 of the
Federal Power Act. All authorizations to engage in affiliate wholesale
sales of electric energy or capacity must be listed in a Seller's
market-based rate tariff.
* * * * *
    (d) Information sharing.
    (1) A franchised public utility with captive customers may not
share market information with a market-regulated power sales affiliate
if the sharing could be used to the detriment of captive customers,
unless simultaneously disclosed to the public.
* * * * *

0
4. In Sec.  35.42, paragraph (a)(1) is revised to read as follows:

Sec.  35.42  Change in status reporting requirement.

    (a) * * *
    (1) Ownership or control of generation capacity and long-term firm
purchases of generation capacity that result in net increases of 100 MW
or more, or of inputs to electric power production, or ownership,
operation or control of transmission facilities, or
* * * * *

0
5. Appendix A of subpart H is revised to read as follows:

Appendix A to Subpart H

Appendix A

Standard Screen Format

(Data provided for Illustrative Purposes only)

                   Part I.--Pivotal Supplier Analysis
------------------------------------------------------------------------
      Row              Generation             MW           Reference
------------------------------------------------------------------------
Seller and Affiliate Capacity
------------------------------------------------------------------------
A.............  Installed Capacity.....       19,500  Workpaper.
B.............  Long-Term Firm                   500  Workpaper.
                 Purchases.
C.............  Long-Term Firm Sales...       -1,000  Workpaper.
D.............  Imported Power.........            0  Workpaper.
------------------------------------------------------------------------
Non-Affiliate Capacity
------------------------------------------------------------------------
E.............  Installed Capacity.....        8,000  Workpaper.
F.............  Long-Term Firm                   500  Workpaper.
                 Purchases.
G.............  Long-Term Firm Sales...       -2,500  Workpaper.
H.............  Imported Power.........        3,500  Workpaper.
I.............  Balancing Authority           -2,160  Workpaper.
                 Area Reserve
                 Requirement.
J.............  Amount of Line I              -2,160  Workpaper.
                 Attributable to
                 Seller, if any.
K.............  Total Uncommitted              9,840
                 Supply (SUM
                 A,B,C,D,E,F,G,H,I,M).
------------------------------------------------------------------------
Load
------------------------------------------------------------------------
L.............  Balancing Authority           18,000  Workpaper.
                 Area Annual Peak Load.
M.............  Average Daily Peak           -16,500  Workpaper.
                 Native Load in Peak
                 Month.
N.............  Amount of Line M             -16,500  Workpaper.
                 Attributable to
                 Seller, if any.
O.............  Wholesale Load (SUM            1,500
                 L,M).
P.............  Net Uncommitted Supply         8,340
                 (K-O).
Q.............  Seller's Uncommitted             340
                 Capacity (SUM
                 A,B,C,D,J,N).
                Result of Pivotal        ...........  PASS.
                 Supplier Screen (Pass
                 if Line Q < Line P),
                 (Fail if Line Q > Line
                 P).
------------------------------------------------------------------------

    Note: The following appendices will not be published in the Code
of Federal Regulations.

Appendix C to Order No. 697-A

Required Provisions of the Market-Based Rate Tariff

Compliance With Commission Regulations

    Seller shall comply with the provisions of 18 CFR part 35,
Subpart H, as applicable, and with any conditions the Commission
imposes in its orders concerning seller's market-based rate
authority, including orders in which the Commission authorizes
seller to engage in affiliate sales under this tariff or otherwise
restricts or limits the seller's market-based rate authority.
Failure to comply with the applicable provisions of 18 CFR part 35,
Subpart H, and with any orders of the Commission concerning seller's
market-based rate authority, will constitute a violation of this
tariff.

Limitations and Exemptions Regarding Market-Based Rate Authority

    [Seller should list all limitations (including markets where
seller does not have market-based rate authority) on its market-
based rate authority and any exemptions from or waivers granted of
Commission regulations and include relevant cites to Commission
orders].

Seller Category

    Seller Category: Seller is a [insert Category 1 or Category 2]
seller, as defined in 18 CFR 35.36(a).

Include All of the Following Provisions That Are Applicable

Mitigated Sales

    Sales of energy and capacity are permissible under this tariff
in all balancing authority areas where the Seller has been granted
market-based rate authority. Sales of energy and capacity under this
tariff are also permissible at the metered boundary between the
Seller's mitigated balancing authority area and a balancing
authority area where the Seller has been granted market-based rate
authority provided: (i) Legal title of the power sold transfers at
the metered boundary of the balancing authority area; (ii) the
mitigated seller and its affiliates do not sell the same power back
into the balancing authority area where the seller is mitigated.
Seller must retain, for a period of five years from the date of the
sale, all data and information related to the sale that demonstrates
compliance with items (i) and (ii) above.

Ancillary Services

RTO/ISO Specific--Include All Services the Seller Is Offering

    PJM: Seller offers regulation and frequency response service,
energy imbalance service, and operating reserve service (which
includes spinning, 10-minute, and 30-minute reserves) for sale into
the market administered by PJM Interconnection, L.L.C. (``PJM'')
and, where the PJM Open Access Transmission Tariff permits, the
self-supply of these services to purchasers for a bilateral sale
that is used to satisfy the ancillary services requirements of the
PJM Office of Interconnection.
    New York: Seller offers regulation and frequency response
service, and operating reserve service (which include 10-minute non-
synchronous, 30-minute operating reserves, 10-minute spinning
reserves, and 10-minute non-spinning reserves) for sale to

purchasers in the market administered by the New York Independent
System Operator, Inc.
    New England: Seller offers regulation and frequency response
service (automatic generator control), operating reserve service
(which includes 10-minute spinning reserve, 10-minute non-spinning
reserve, and 30-minute operating reserve service) to purchasers
within the markets administered by the ISO New England, Inc.
    California: Seller offers regulation service, spinning reserve
service, and non-spinning reserve service to the California
Independent System Operator Corporation (``CAISO'') and to others
that are self-supplying ancillary services to the CAISO.

Third Party Provider

    Third-party ancillary services: Seller offers [include all of
the following that the seller is offering: Regulation Service,
Energy Imbalance Service, Spinning Reserves, and Supplemental
Reserves]. Sales will not include the following: (1) Sales to an RTO
or an ISO, i.e., where that entity has no ability to self-supply
ancillary services but instead depends on third parties; (2) sales
to a traditional, franchised public utility affiliated with the
third-party supplier, or sales where the underlying transmission
service is on the system of the public utility affiliated with the
third-party supplier; and (3) sales to a public utility that is
purchasing ancillary services to satisfy its own open access
transmission tariff requirements to offer ancillary services to its
own customers.

Appendix D to Order No. 697-A

Regions and Schedule for Regional Market Power Update Process

    The six regions are combinations of NERC regions; RTOs and ISOs
and are depicted in the map that follows.
[GRAPHIC] [TIFF OMITTED] TR07MY08.010

Appendix D-1

    Schedule for Transmission Owning Utilities With Market-Based Rate
            Authority and Their Affiliates in the Same Region
------------------------------------------------------------------------
                                  Filing period
   Entities required to file     (anytime  during       Study period
                                    the month)
------------------------------------------------------------------------
Northeast Transmission Owners.  December, 2007...  Dec. 1, 2005-Nov. 30,
                                                    2006.
Southeast Transmission Owners.  June, 2008.......  Dec. 1, 2005-Nov. 30,
                                                    2006.
Central Transmission Owners...  December, 2008...  Dec. 1, 2006-Nov. 30,
                                                    2007.
SPP Transmission Owners.......  June, 2009.......  Dec. 1, 2006-Nov. 30,
                                                    2007.
Southwest Transmission Owners.  December, 2009...  Dec. 1, 2007-Nov. 30,
                                                    2008.
Northwest Transmission Owners.  June, 2010.......  Dec. 1, 2007-Nov. 30,
                                                    2008.
Northeast Transmission Owners.  December, 2010...  Dec. 1, 2008-Nov. 30,
                                                    2009.
Southeast Transmission Owners.  June, 2011.......  Dec. 1, 2008-Nov. 30,
                                                    2009.
Central Transmission Owners...  December, 2011...  Dec. 1, 2009-Nov. 30,
                                                    2010.
SPP Transmission Owners.......  June, 2012.......  Dec. 1, 2009-Nov. 30,
                                                    2010.
Southwest Transmission Owners.  December, 2012...  Dec. 1, 2010-Nov. 30,
                                                    2011.
Northwest Transmission Owners.  June, 2013.......  Dec. 1, 2010-Nov. 30,
                                                    2011.
------------------------------------------------------------------------

Appendix D-2

                                         Schedule for All Other Entities
----------------------------------------------------------------------------------------------------------------
                                        Filing period (anytime
      Entities required to file           during the month)                       Study period
----------------------------------------------------------------------------------------------------------------
All others in Northeast that did not   June, 2008.............  Dec. 1, 2005-Nov. 30, 2006.
 file in December including all power
 marketers that sold in the Northeast.
All others in Southeast that did not   December, 2008.........  Dec. 1, 2005-Nov. 30, 2006.
 file in June including all power
 marketers that sold in the Southeast
 and have not already been found to
 be Category 1 sellers.
All others in Central that did not     June, 2009.............  Dec. 1, 2006-Nov. 30, 2007.
 file in December including all power
 marketers that sold in the Central
 and have not already been found to
 be Category 1 sellers.
All others in SPP that did not file    December, 2009.........  Dec. 1, 2006-Nov. 30, 2007.
 in June including all power
 marketers that sold in SPP and have
 not already been found to be
 Category 1 sellers.
Others in Northeast that did not file  June, 2011.............  Dec. 1, 2008-Nov. 30, 2009.
 in December and have not been found
 to be Category 1 sellers.
Others in Southeast that did not file  December, 2011.........  Dec. 1, 2008-Nov. 30, 2009.
 in June and have not been found to
 be Category 1 sellers.
Others in Central that did not file    June, 2012.............  Dec. 1, 2009-Nov. 30, 2010.
 in December and have not been found
 to be Category 1 sellers.
Others in SPP that did not file in     December, 2012.........  Dec. 1, 2009-Nov. 30, 2010.
 June and have not been found to be
 Category 1 sellers.
Others in Southwest that did not file  June, 2013.............  Dec. 1, 2010-Nov. 30, 2011.
 in December and have not been found
 to be Category 1 sellers.
Others in Northwest that did not file  December, 2013.........  Dec. 1, 2010-Nov. 30, 2011.
 in June and have not been found to
 be Category 1 sellers.
----------------------------------------------------------------------------------------------------------------

Appendix E to Order No. 697-A

                           Petitioner Acronyms
------------------------------------------------------------------------
         Abbreviation                       Petitioner names
------------------------------------------------------------------------
Ameren.......................  Ameren Services Company.
APPA/TAPS....................  American Public Power Association/
                                Transmission Access Policy Study Group.
Attorneys General of           Richard Blumenthal, Attorney General for
 Connecticut and Illinois.      the State of Connecticut and the People
                                of the State of Illinois, by and through
                                the Illinois Attorney General Lisa
                                Madigan.
Consumer Advocates...........  Attorneys General of New Mexico and Rhode
                                Island, Colorado Office of Consumer
                                Counsel, Utah Committee of Consumer
                                Services, Public Utility Law Project of
                                NY, and Public Citizen, Inc.
EEI..........................  Edison Electric Institute.
El Paso E&P..................  El Paso E&P Company, L.P.
FirstEnergy..................  FirstEnergy Service Company.
FP&L.........................  Florida Power & Light Company and FPL
                                Energy, LLC.
Industrial Customers.........  Coalition of Midwest Transmission
                                Customers, PJM Industrial Customer
                                Coalition, NEPOOL Industrial Customer
                                Coalition, Industrial Energy Users of
                                Ohio, Industrial Energy Consumers of PA,
                                Southeast Electricity Consumers
                                Association, West Virginia Energy Users
                                Group, and Southwest Industrial Customer
                                Coalition.
LT Sellers...................  Long-Term Sellers.
MidAmerican..................  MidAmerican Energy Company and Cordova
                                Energy Company LLC.
Montana Counsel..............  Montana Consumer Counsel.
Morgan Stanley...............  Morgan Stanley Capital Group Inc.
NASUCA.......................  National Association of State Utility
                                Consumer Advocates.

NRECA........................  National Rural Electric Cooperative
                                Association.
NYISO........................  New York Independent System Operator,
                                Inc.
NRG..........................  NRG Energy, Inc.
Occidental...................  Occidental Power Marketing, L.P.
OG&E.........................  Oklahoma Gas and Electric Company and OGE
                                Energy Resources, Inc.
Pinnacle.....................  Pinnacle West Companies.
PPM..........................  PPM Energy, Inc.
PSEG Companies...............  Public Service Electric and Gas Company,
                                PSEG Power LLC, and PSEG Energy
                                Resources & Trade LLC.
Reliant......................  Reliant Energy, Inc.
Southern.....................  Southern Company Services, Inc.
TDU Systems..................  Transmission Dependent Utilities Systems.
Wisconsin Electric...........  Wisconsin Electric Power Company.
------------------------------------------------------------------------

UNITED STATES OF AMERICA

FEDERAL ENERGY REGULATORY COMMISSION

18 CFR Part 35

[Docket No. RM04-7-001; Order No. 697-A]

Market-Based Rates for Wholesale Sales of Electric Energy, Capacity and
Ancillary Services by Public Utilities

(Issued April 21, 2008)

KELLY, Commissioner, concurring:

    Among other decisions in Order No. 697-A, the Commission has, on
rehearing, determined that it will entertain applications that
permit a mitigated seller to sell under a long-term contract at
market-based rates. Specifically, we will allow a mitigated seller
to demonstrate, on a case-by-case basis, that it does not have
market power with respect to a specific long-term contract. I
believe that if executed properly, allowing a mitigated seller the
opportunity to demonstrate that, with respect to a specific
contract, it does not have market power could be a useful and
productive means for spurring competition and long-term contracting.
    Ideally, I believe the Commission should apply an ordered,
transparent and predictable test to each mitigated seller's
application. Such a test should include an examination of barriers
to entry, structural or otherwise. New entrants bring new capacity
that, in theory at least, should exert downward pressure on prices.
Our decision here hinges on the hypothesis that, absent barriers to
new entrants, long-term markets may be presumed to be competitive.
Ultimately, I would like to see the Commission confirm that
hypothesis using the aforementioned test on a case-by-case basis.
    Until such time as we have developed such a test, however, we
have decided that the case-by-case approach described in this order
allows the Commission to examine these applications with the
appropriate rigor. The mitigated seller will have to show that a
buyer under a long-term contract has viable alternatives, including
the entry of third-party newly-constructed resources during the
relevant future period as an alternative to purchasing under the
contract at issue. I would prefer that mitigated sellers, in their
applications, include an identified buyer. I believe the presence of
an identified buyer will ensure that any assessment of the
application is confined to a set of circumstances specific to the
transaction, thereby avoiding the potential for granting a more
general market-based rate authority to a mitigated seller for a
particular area and period of time. I do not believe that such an
outcome would be helpful to or consistent with our goals of
promoting competition.
    As the Commission moves forward, I anticipate relying on the
views and expertise of interested parties in developing a specific
test to apply to each case.
    For these reasons, I respectfully concur with this order.

Suedeen G. Kelly.

 [FR Doc. E8-9073 Filed 5-6-08; 8:45 am]

BILLING CODE 6717-01-C