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

    \135\ Exelon Corp., 112 FERC ] 61,011, reh'g denied, 113 FERC ]
61,299 (2005), vacated, PPL Electric Utilities Corp. v. FERC, No.
06-1009 (D.C. Cir. Dec. 21, 2006).
---------------------------------------------------------------------------

    91. With regard to PJM East, however, we note that in proceedings
other than the Exelon/PSEG merger, the

Commission also treated PJM-East as a market within PJM.\136\
Accordingly, we reaffirm our finding in the Final Rule that because the
Commission already has found that PJM-East constitutes a separate
market in PJM, sellers located in PJM should use PJM-East as the
default geographic market.
---------------------------------------------------------------------------

    \136\ See, e.g., El Paso Energy Corporation, 92 FERC ] 61,076
(2000), Energy East Corporation, 96 FERC ] 61,322 (2001), Potomac
Electric Power Company, 96 FERC ] 61,323 (2001).
---------------------------------------------------------------------------

    92. We reject PSEG's argument that the Commission's policy
discriminates against some market participants. In particular, PSEG
contends that a market-based rate seller can be located in an RTO/ISO
sub-region that has greater instances of transmission constraints than
any of the submarkets specified in the Final Rule, but will be able to
proceed with a market-based rate application using the RTO/ISO as the
default relevant market. As the Commission has stated, default
geographic markets are adequate and sufficient for the typical
situation, and by defining default geographic markets, we provide the
industry as much certainty as possible while also providing affected
parties the right to challenge the default geographic market definition
and provide evidence in that regard.\137\ Thus, in the example posited
by PSEG, if there is evidence that indicates high instances of
transmission constraints within an RTO that has not been previously
found to constitute a submarket, intervenors have the opportunity to
present that evidence to the Commission. Accordingly, because all
market participants have the opportunity to challenge the default
geographic market definition, this policy does not discriminate against
some market participants. Rather, the Commission's policy in this
regard recognizes the findings the Commission has already made and
Order No. 697 provides guidance to parties that wish to challenge the
default geographic markets.
---------------------------------------------------------------------------

    \137\ Id. P 234.
---------------------------------------------------------------------------

    93. With regard to PSEG's claims that the Commission failed to
consider evidence submitted by CAISO, ISO-NE, and NYISO that there is
no technical and structural need for the examination of RTO/ISO
submarkets, we find that where the Commission has made a specific
finding that there is a submarket within an RTO/ISO, the market-based
rate analysis should reflect the facts and consider that submarket as
the default relevant geographic market. To do otherwise would be
inconsistent with our findings of a submarket in the first instance. In
particular, the Commission has consistently stated that the Commission-
approved market monitoring and mitigation provides added protection
against a seller's ability to exercise market power, but cannot replace
the generation market power analysis.\138\ While we consider carefully
comments by interveners, this Commission will also consider all the
facts before us before making a finding.
---------------------------------------------------------------------------

    \138\ See Order No. 697 at P 290.
---------------------------------------------------------------------------

    94. In addition, while PSEG is correct that transmission
constraints can be temporary, as noted above, all of the submarkets
that the Commission has identified result from frequently binding
transmission constraints during historical seasonal peaks examined;
these particular constraints have not tended to be temporary in nature.
Evidence with respect to whether a transmission constraint is temporary
or is frequently binding will be considered in determining whether a
submarket exists. To the extent that some existing constraints may be
alleviated by construction of new transmission facilities, parties may
bring these situations to our attention for further consideration.
    95. Without a correctly defined submarket, sellers with market
power in the RTO/ISO market may not be identified, and their market
power mitigated in both the real-time and day-ahead markets. While we
acknowledge PSEG's claim that the Commission's determination on RTO/ISO
submarkets departs from Commission policy utilizing the RTO/ISO as the
default relevant geographic market, we disagree with PSEG's claim that
this is inconsistent with Commission confidence in the impact of RTO/
ISO market monitoring and mitigation. The purpose of this rulemaking
proceeding has been to consider and evaluate the Commission's current
market-based rate policy and to make adjustments to this approach, as
warranted. Thus, we have carefully considered the facts before us,
including our historical approach, and found it reasonable that where
the Commission has made a specific finding that there is a submarket
within an RTO/ISO, the market-based rate analysis should reflect those
facts and consider that submarket as the default relevant geographic
market because to do otherwise would be inconsistent with our findings
of a submarket in the first instance. In addition, the Commission has
been in the process of developing and improving policies that best
protect customers and promote market competition in a manner that
accounts for the changing nature of developing electricity markets. We
will not depart from this basic approach.
    96. Moreover, PSEG overstates the difference between our prior
policy and the policy adopted in Order No. 697. Prior to Order No. 697,
the Commission did not identify submarkets within an RTO/ISO as default
geographic markets, but one of the principal reasons for this policy
was the ability to rely on Commission-approved mitigation in submarkets
within RTOs/ISOs to mitigate any localized market power. Although Order
No. 697 changed our approach to geographic market definition as it
relates to submarkets, applicants may propose to continue to rely on
Commission-approved mitigation in these submarkets as adequate to
address any market concerns.
RTO/ISO Exemption
Final Rule
    97. Prior to the April 14 Order, the Commission exempted sellers
located in markets with Commission-approved market monitoring and
mitigation from providing generation market power analyses stating that
such sellers will be governed by the specific thresholds and mitigation
provisions approved for the particular markets.\139\ In the April 14
Order, the Commission determined that it would no longer exempt these
sellers, on the basis that requiring sellers located in such markets to
submit screen analyses provided an additional check on the potential
for market power. In Order No. 697, the Commission declined the request
by commenters that it reinstate the pre-April 14 Order exemption for
sellers located in markets with Commission-approved market monitoring
and mitigation from providing generation market power analyses.
Instead, the Commission indicated that it would continue to require
generation market power analyses from all sellers, including those in
RTO/ISO markets. The Commission noted that while a single market with
Commission-approved market monitoring and mitigation and transparent
prices provides added protection against a seller's ability to exercise
market power, it cannot replace the generation market power
analysis.\140\
---------------------------------------------------------------------------

    \139\ See AEP Power Marketing, Inc., 97 FERC ] 61,219 (2001).
    \140\ Id. P 290.
---------------------------------------------------------------------------

Requests for Rehearing
    98. Reliant and PSEG argue that the Commission should reconsider
its decision not to exempt sellers located in markets with Commission-
approved

market monitoring and mitigation from submitting horizontal market
power analyses. Reliant contends that the Commission did not explain
what value a separate horizontal market power analysis would have,
given that market monitoring by an independent market monitor
consistent with Commission-approved rules and mitigation already
identifies and mitigates market power. According to Reliant, market
monitoring and mitigation provides a better picture of market power
issues in RTO/ISO markets as compared to an individual seller's
separate horizontal market power analysis which considers only market
power at a fixed moment in time and also provides relief from the costs
and burdens of producing a horizontal market power analysis.\141\ In
the alternative, if the Commission declines to reinstate the exemption,
Reliant asserts that the Commission should clarify that Commission-
approved mitigation rules presumptively mitigate a seller's market
power and, in addition, the Commission should reconsider its decision
to utilize previously identified RTO/ISO submarkets as the relevant
geographic market for the indicative screens.
---------------------------------------------------------------------------

    \141\ Reliant Rehearing Request at 2-3.
---------------------------------------------------------------------------

    99. Reliant opines that a fundamental purpose and objective of
market monitoring and mitigation is to detect actual, and the potential
for, market power and to safeguard against it so as to ensure that no
seller in the market can dominate the market, manipulate price, or
otherwise act to stifle competition.\142\ Accordingly, Reliant argues
that a presumption that a seller's market power is adequately mitigated
where Commission-approved market monitoring and mitigation rules are in
effect is entirely appropriate, unless an intervenor can demonstrate
why Commission-approved mitigation is insufficient in a particular
case. According to Reliant, it is not appropriate to add the
administrative burden of applying indicative screens if the Commission
believes that market monitoring and mitigation is generally
working.\143\
---------------------------------------------------------------------------

    \142\ Id. at 3 (citing Market Monitoring Units in Regional
Transmission Organizations and Independent System Operators, 111
FERC ] 61,267, at P 1 (2005) (market monitoring units perform an
important role in enhancing competitiveness of RTO/ISO markets by,
among other things, monitoring organized wholesale markets to
identify potential anticompetitive behavior by market participants
and providing comprehensive market analysis critical for informed
policy decision making); April 14 Order, 107 FERC ] 61,018 at P 186,
190 (recognizing the pro-competitive benefits of RTO/ISO markets
with market monitoring and mitigation)).
    \143\ Id. at 7.
---------------------------------------------------------------------------

    100. PSEG asserts that the Commission erred in failing to create a
presumption that, even when the Commission has found submarkets to
exist, no further analysis of the submarkets is required so long as a
robust RTO/ISO market monitoring and mitigation scheme is in place.
According to PSEG, a demonstration of a lack of market power in
submarkets should only be required if there is reason to question
whether such local market power is being addressed. RTO/ISO markets
with Commission-approved market monitoring and mitigation programs in
place should have a presumption that analysis of potential submarkets
is not required. PSEG states that, to the extent other market
participants believe otherwise, the burden should fall on them to show
that an analysis of these submarkets was in fact required.\144\
---------------------------------------------------------------------------

    \144\ PSEG Rehearing Request at 11-12.
---------------------------------------------------------------------------

    101. To further support its position, PSEG notes that none of the
three RTO/ISOs that filed comments on the NOPR saw any reason for
applying mitigation outside of their existing programs. PSEG states
that not accepting the efficacy of the RTO/ISO mitigation for purposes
of the market-based rate assessment potentially undermines the
authority and role of the RTO/ISOs.\145\ PSEG suggests that the
Advanced Notice of Proposed Rulemaking on organized markets would be a
preferable way for the Commission to fine-tune the market monitoring
and mitigation functions of such organizations on a prospective
basis.\146\
---------------------------------------------------------------------------

    \145\ Id.
    \146\ Id. at 12 (citing Wholesale Competition in Regions with
Organized Electric Markets, Advanced Notice of Proposed Rulemaking,
72 FR 36276 (July 2, 2007), FERC Stats. & Regs. ] 32,617 (2007)
(considering potential reforms to attributes of organized markets,
including market monitoring).
---------------------------------------------------------------------------

    102. Similarly, EEI requests that the Commission clarify that
``mitigated sellers in RTOs and ISOs may rely on Commission-approved
market monitoring and mitigation for sales within the RTOs and ISOs
without each seller having to demonstrate that such mitigation suffices
in place of the default mitigation, unless a complainant demonstrates
that the RTO and ISO monitoring and mitigation does not suffice as to a
particular seller.'' \147\ EEI is concerned that the Commission may
unnecessarily burden sellers in the organized markets with having to
demonstrate in each individual proceeding that the RTO/ISO mitigation
measures suffice as an alternative to Order No. 697's default
mitigation.
---------------------------------------------------------------------------

    \147\ EEI Rehearing Request at 4-5.
---------------------------------------------------------------------------

    103. NRG believes that Order No. 697 creates ambiguity regarding
how the Commission's default market power mitigation regime will
interact with existing mitigation regimes that have been approved in
organized RTO/ISO markets. NRG asserts that this ambiguity will
discourage suppliers from building new generation in constrained areas.
Thus, NRG seeks clarification, and, alternatively, rehearing, on two
points. First, NRG asks that the Commission clarify that it will
rebuttably presume that existing RTO/ISO regimes adequately mitigate
market power for any sellers located in an RTO/ISO market that fail to
pass indicative screens and a DPT analysis.\148\ Second, in the event
that a seller's market power is found not to be adequately mitigated,
the Commission should clarify that the seller is allowed to propose its
own tailored mitigation measures not necessarily based on embedded
costs.\149\
---------------------------------------------------------------------------

    \148\ NRG Rehearing Request at 2.
    \149\ Id. at 3.
---------------------------------------------------------------------------

    104. On the first point, NRG explains that the Final Rule does not
explicitly state that RTO/ISO monitoring and mitigation protocols will
provide sufficient mitigation for any market power presumed if a seller
fails the screens. NRG asserts that any generation market power a
seller might possess has already been mitigated by those protocols.
Thus, such sellers should not automatically be treated the same way as
other mitigated sellers and subjected to default mitigation. However,
NRG contends that the Final Rule leaves in question whether existing
RTO/ISO mitigation regimes or the conflicting mitigation regime adopted
in the Final Rule will govern in future seller-specific cases. NRG
warns that this regulatory uncertainty will put new investment at risk,
an outcome that should be avoided given the great efforts made to put
in place alternatives to RMR contracts.\150\ In addition, NRG claims
that the ambiguity threatens to harm state-sanctioned competitive
procurement programs, which typically require binding bids which cannot
be conditioned on obtaining subsequent Commission approval.\151\
---------------------------------------------------------------------------

    \150\ Id. at 7 (citing Devon Power LLC, 115 FERC ] 61,340 (2006)
(concerning the New England FCM settlement) and PJM Interconnection,
L.L.C., 117 FERC ] 61,331 (2006) (concerning the PJM RPM
settlement)).
    \151\ Id. at 10-12.
---------------------------------------------------------------------------

    105. Regarding the second requested clarification, NRG notes that
in several places in the Final Rule, the Commission states that it will
retain existing cost-based default mitigation rates, but is unclear
whether alternative, tailored mitigation rates must be cost-

based. NRG seeks clarification that the apparent limitation to cost-
based alternatives was inadvertent. In addition, NRG states that ``the
Commission should make clear that in reviewing alternative mitigation
measures proposed by merchant generators in RTOs, it will consider
whether the proposed measures will support and attract necessary
investment on reasonable terms, and recover the supplier's cost of
capital.'' \152\
---------------------------------------------------------------------------

    \152\  Id. at 16.
---------------------------------------------------------------------------

    106. NYISO states that it is unclear whether the Commission
intended to adopt a default mitigation measure that would be
inconsistent with its previously approved market design and mitigation
measures for the NYISO's bid-based, uniform clearing-price auction
markets.\153\ In particular, NYISO argues that there is no evidentiary
or policy basis that would justify the imposition of default mitigation
in the form of a revenue cap, rather than a bid cap, in Commission-
approved Locational Based Marginal Price markets like NYISO.\154\
---------------------------------------------------------------------------

    \153\ NYISO Rehearing Request at 4 (citing New York Independent
System Operator, Inc., 89 FERC ] 61,196 (1999), order on compliance
and reh'g, 90 FERC ] 61,317, clarified, 91 FERC ] 61,154 (2000)
(orders addressing the NYISO's proposed Market Mitigation Measures);
New York Independent System Operator, Inc., et al., 99 FERC ] 61,246
(2002) (order on the NYISO's comprehensive mitigation measures
filing); Midwest Independent Transmission System Operator, Inc., 108
FERC ] 61,163, at P 257, order on reh'g, 109 FERC ] 61,157 (2004)
(``We find that the conduct and impact approach with its associated
thresholds is an appropriate approach to mitigation in the Midwest
ISO's market. The conduct and impact approach allows for a lighter
handed approach to mitigation, in which the market is allowed to
function as is, except when problems are detected.'')).
    \154\ Id. at 7.
---------------------------------------------------------------------------

    107. NYISO argues that the imposition of default market power
mitigation in the form of revenue caps rather than bid caps would be
incompatible with the principles underlying uniform clearing price
auctions. NYISO ensures that the market clearing price will either be a
competitive price or it will be a mitigated price.\155\ Thus, NYISO
requests clarification that cost-based mitigation will limit a
mitigated entity's permissible maximum bid, but not constrain the
mitigated entity from receiving the market clearing price if it is not
the marginal seller. Additionally, NYISO argues that if the
Commission's default cost-based mitigation is interpreted to impose a
revenue cap as well as a bid cap, the NYISO states that it will face
significant administrative burdens if revenue caps are imposed rather
than bid caps.\156\
---------------------------------------------------------------------------

    \155\ Id. at 2, 3, 5.
    \156\ Id. at 7.
---------------------------------------------------------------------------

    108. APPA/TAPS, on the other hand, believe that the Commission
should clarify that a seller relying on RTO/ISO mitigation to remedy
its market power must demonstrate those measures' effectiveness. APPA/
TAPS note that the Final Rule indicates sellers can incorporate
existing RTO/ISO mitigation as part of their market power analyses, but
asks for clarification that an applicant must make a specific showing
that those mitigation measures in fact address the specific concerns in
the market-based rate analysis. APPA/TAPS assert that the scope of RTO/
ISO mitigation is much narrower than the default, cost-based mitigation
the Commission prescribes; it notes that the Commission has stated that
RTO/ISO mitigation and the market-based rate analysis are different and
that`` `pieces of one should not automatically be used as precedent for
the other.' '' \157\ APPA/TAPS state that RTO/ISO mitigation measures
apply only to spot markets and day-ahead and/or real time, but do not
apply to weekly, monthly or long-term transactions, including those
negotiated on a bilateral basis, and that RTO/ISO mitigation is often
far less protective than the Commission's cost-based default of
incremental cost plus 10 percent. APPA/TAPS explain that they are not
asking the Commission to make a generic finding that all RTO/ISO
mitigation is insufficient to mitigate sellers' generation market
power, but that they seek a ruling that the burden of proof that the
RTO/ISO mitigation adequately addresses the seller's market power falls
on the seller, rather than intervenors. If the Commission does not make
that clarification, APPA/TAPS state that it should clarify that it will
allow intervenors to challenge such claims and will give meaningful
consideration to those challenges.\158\
---------------------------------------------------------------------------

    \157\ APPA/TAPS Rehearing Request at 24 (citing Midwest
Independent Transmission System Operator, Inc., 109 FERC ] 61,157,
at P 242 (2004), order on reh'g, 111 FERC ] 61,043 (2005)).
    \158\ Id. at 26-27.
---------------------------------------------------------------------------

Commission Determination
    109. The Commission denies the requests of PSEG and Reliant to
reconsider its decision to require sellers located in markets with
Commission-approved market monitoring and mitigation to submit
horizontal market power analyses. As we explained in Order No. 697,
while the Commission-approved market monitoring and mitigation in RTO/
ISO markets provides protection against a seller's ability to exercise
market power, it cannot replace the horizontal market power analyses
which provide the Commission and the industry with critical information
regarding the potential market power of sellers in the market.
    110. We conclude that the dual protections of individual market
power analyses and mitigation rules of the RTO/ISOs provide the
Commission with better ability to discern and protect against potential
market power. While, as discussed below, mitigation rules for the
individual RTO/ISOs in most cases should be sufficient to guard against
the exercises of market power, we are not comfortable at this time with
dispensing of the requirement for sellers in RTO/ISOs to provide us
with horizontal market power analyses. Any administrative burden of
submitting such analyses is outweighed by the additional information
gleaned with respect to a specific seller's market power.
    111. APPA/TAPS request that the Commission clarify on rehearing
that a seller relying on RTO/ISO mitigation to mitigate its market
power must demonstrate the effectiveness of those measures. A number of
other petitioners, on the other hand, request that the Commission
clarify that it will rebuttably presume that existing RTO/ISO regimes
adequately mitigate market power for any sellers located in an RTO/ISO
market that fail the indicative screens and the DPT analysis. In
response to these requests, to the extent a seller seeking to obtain or
retain market-based rate authority is relying on existing Commission-
approved RTO/ISO market monitoring and mitigation, we adopt a
rebuttable presumption that the existing mitigation is sufficient to
address any market power concerns. However, intervenors may challenge
the effectiveness of that mitigation. We agree with PSEG that the
challenging party should have the burden of proof to demonstrate that
existing RTO/ISO mitigation is not sufficient. Thus, because existing
RTO/ISO mitigation has been found to be just and reasonable by the
Commission in the context of a proceeding specific to a particular RTO/
ISO and involving all of its stakeholders, we believe it appropriate
and clarify herein that there is a rebuttable presumption that such
RTO/ISO mitigation is adequate to mitigate market power in the RTO/ISO
market, including Commission-approved mitigation applicable to RTO/ISO
submarkets such as In-City New York. To the extent that a party wishes
to challenge that presumption, the challenging party will have the
burden of proof.

    112. In response to EEI, to the extent the Commission has
considered a challenge to existing mitigation and has found it to be
adequate, any additional challenges must demonstrate a change in
circumstances rather than just rearguing issues on which the Commission
has already ruled.
    113. A number of petitioners raise issues regarding the types of
mitigation that the Commission might impose on mitigated sellers in
RTOs/ISOs. NRG requests that, in the event a seller's market power is
found not to be adequately mitigated, the Commission should clarify
that the seller may propose tailored mitigation measures that are not
necessarily based on embedded costs. NYISO states that it is unclear
whether the Commission intended to adopt a default mitigation measure
for any sellers located in an RTO/ISO market that fail to pass the
indicative screens and the DPT analysis and seeks clarification that
cost-based mitigation will only limit a mitigated entity's permissible
maximum bid, but will not constrain the mitigated entity from receiving
the market clearing price if it is not the marginal seller.
    114. In response to these issues raised regarding the types of
mitigation that the Commission might impose on mitigated sellers in
RTO/ISO, the Commission will, depending on the nature of the evidence
submitted by an intervenor, consider whether to institute a separate
section 206 proceeding that would be open to all interested entities to
investigate whether the existing RTO/ISO mitigation continues to be
just and reasonable and, if not, how such mitigation should be revised.
Any intervenor in such a section 206 proceeding may present evidence on
the adequacy of the existing mitigation. If appropriate, the Commission
will consider modifying that mitigation on an RTO/ISO-wide basis,
rather than on a seller-specific basis, because RTO/ISO mitigation is
designed to mitigate market power generally. In other words, if
existing mitigation is found to be inadequate for a particular seller,
then it is likely to be insufficient for all similarly situated
sellers. We note that in reviewing alternative mitigation measures in
the context of RTOs, the Commission will consider whether the proposed
mitigation measures will adequately deter the exercise of market power,
are consistent with the RTO/ISO's market design and will support and
attract necessary investment on reasonable terms, and recover the
suppliers' cost of capital. With regard to NYISO's request, as
discussed above, with regard to sellers located in an RTO/ISO market
that fail to pass the indicative screens and the DPT analysis, we will
not impose default cost-based rate mitigation (which is used in non-
RTO/ISO markets) in addition to RTO/ISO mitigation. Rather, we adopt a
rebuttable presumption that the existing mitigation is sufficient to
address any market power concerns.
    115. With regard to APPA/TAPS' assertion that the scope of RTO/ISO
mitigation is much narrower than the default cost-based rate mitigation
and its argument that RTO/ISO mitigation provides less protection than
the Commission's default mitigation of incremental cost plus 10
percent, we understand that RTO/ISO mitigation measures apply to day-
ahead and/or real-time markets, and we reiterate that RTO/ISO
mitigation is determined to be just and reasonable when it is approved
by the Commission.\159\ We review and approve mitigation rules in RTO/
ISO markets on the basis of the specific facts and circumstances
prevailing in such markets. Thus, customers and other interested
parties are fully able, in the context of those proceedings, to comment
on whether the mitigation rules are sufficiently strong to deter the
exercise of market power. In addition, pursuant to the Final Rule,
customers or other affected parties may argue, in the context of a
specific market-based rate application or triennial review, that
changed circumstances have rendered such mitigation no longer just,
reasonable and not unduly discriminatory.
---------------------------------------------------------------------------

    \159\ APPA/TAPS rely on Midwest Independent Transmission System
Operator, Inc., 109 FERC ] 61,157, at P 242 (2004), order on reh'g,
111 FERC ] 61,043 (2005) (Midwest ISO) in arguing that RTO
mitigation and the market-based rate analysis are different. We
recognize that in Midwest ISO the Commission stated that its market-
based rate analysis and mitigation in the Midwest ISO differ, and,
as stated above, we reiterate that RTO mitigation is determined to
be just and reasonable when it is approved by the Commission.
---------------------------------------------------------------------------

7. Use of Historical Data
Final Rule
    116. The Commission held in the Final Rule that it would retain the
``snapshot in time'' approach for the indicative screens and the DPT,
so that sellers will be required to use actual historical data for the
previous calendar year in their market power analyses. After careful
consideration of the comments received, the Commission chose not to
adopt the NOPR proposal that the DPT analysis allow sellers and
intervenors to account for changes in the market that are known and
measurable at the time of filing. Instead, the Commission decided to
retain its existing practice that sellers are required to use
unadjusted historical data in the preparation of a DPT for a market-
based rate analysis and clarified that it would require the use of the
actual historical data for the previous calendar year.
    117. The Commission distinguished this treatment from the approach
in the Commission's merger analysis, which requires applicants and
intervenors to account for changes in the market that are known and
measurable at the time of filing. The Commission found that the purpose
of using the DPT in market-based rate proceedings is different from
that in a merger analysis. Whereas a merger analysis is forward-looking
and it is difficult and costly to undo a merger, the market-based rate
analysis is a ``snapshot in time'' approach where the Commission's
focus is on whether the seller passes the indicative screens and the
DPT based on unadjusted historical data. The Commission considered that
its grant of market-based rate authority is conditioned on, among other
things, the seller's obligation to inform the Commission of any change
in status from the circumstances the Commission relied on in granting
it market-based rate authority on an ongoing basis. Thus, the change in
status reporting requirement allows the Commission to evaluate changes
when they actually happen rather than relying on projections, making it
unnecessary and redundant for the Commission to allow sellers to
account for known and measurable changes in the DPT.
Requests for Rehearing
    118. Montana Counsel argues that the Commission erred in refusing
to allow adjustments to the DPT analysis to account for known and
measurable future changes, such as contracts for the sale of capacity
belonging to the seller that will expire during the term of its market-
based rate authority. Montana Counsel asserts that by refusing to
consider known and measurable changes, the Commission is intentionally
allowing the DPT analysis to be conducted based on data and assumptions
that are known not to be representative of reality.\160\ Montana
Counsel argues that it is inherently irrational, arbitrary, and
capricious to allow companies whose generation market power is being
analyzed to deduct the generation that is being tested from its supply
on grounds that the generation is committed, as the Commission does
when the contracts for power from that generation are expiring. Montana
Counsel states that such a market power test is inherently flawed, and
that this flawed test has concrete

results, with negative impacts for consumers. Montana Counsel cites the
Commission's May 2006 renewal of PPL Montana's market-based rate
authority, in spite of the fact that the main utility in Montana,
NorthWestern Energy, must buy from PPL Montana to serve its load, as an
example of the negative impact that the market power test can have on
consumers.\161\
---------------------------------------------------------------------------

    \160\ Montana Counsel Rehearing Request at 7.
    \161\ Id. at 7-8 (citing PPL Montana, LLC, 115 FERC ] 61,204
(2006) (PPL Montana)). Montana Counsel includes its request for
rehearing of PPL Montana, filed June 16, 2006 in Docket No. EL05-
124, et al., as Attachment A to its request for rehearing of Order
No. 697. Id. at 8. The Montana Counsel's rehearing request in the
PPL Montana proceeding asserts that the Commission's decision to
renew the market-based rate authority of the PPL Montana Companies
is error insofar as it is contrary to record evidence and the
requirements of the Federal Power Act. The Commission denied Montana
Counsel's request for rehearing in PLL Montana LLC, 120 FERC ]
61,096 (2007).
---------------------------------------------------------------------------

    119. Montana Counsel notes that the Final Rule distinguishes the
market-based rate process from the Commission's merger analysis by
saying that while mergers are difficult to undo, sellers with market-
based rate authority must file change in status reports, allowing the
Commission to evaluate changes when they happen. Montana Counsel argues
that the Commission misses the point that if the change in status is
caused by the expiration of a long-term contract for the sale of
capacity, then by the time the change in status report is submitted,
the seller may have already re-sold the capacity at a price reflecting
the seller's underlying market power.\162\
---------------------------------------------------------------------------

    \162\ Id. at 8-9.
---------------------------------------------------------------------------

    120. Montana Counsel contends that the refusal to consider known
and measurable changes is especially inappropriate in light of the fact
that the Commission considers mitigation proposed by the seller.\163\
Montana Counsel argues that, if the Commission will consider an
applicant's `` `propos[al] to transfer operational control of enough
generation to a third party such that the applicant would satisfy [the
Commission's] generation market power concerns' '' it should also
consider whether an applicant's available capacity will increase during
the market-based rate authorization period when contracts expire.\164\
---------------------------------------------------------------------------

    \163\ Id. at 9 (citing Order No. 697 at P 25, 63 n.46).
    \164\ Id.
---------------------------------------------------------------------------

    121. NRECA similarly asserts that the Final Rule's failure to
require applicants and allow intervenors to incorporate known and
measurable changes to historical data in the indicative screens and the
DPT in favor of a rigid ``snapshot'' analysis of historical data is
arbitrary, capricious, contrary to law, and in excess of statutory
authority.\165\ NRECA argues that, if the Commission knows a change
will take place, it would be arbitrary and capricious to grant market-
based rate authority based on an assumption that the change will not
take place.\166\ Long-term contracts will expire on a known schedule,
and the seller should not be allowed to assume that the capacity will
remain committed to the buyer. According to NRECA, the Commission
cannot, consistent with the FPA, ignore that pending change in
circumstances. At a minimum, intervenors should have the opportunity to
demonstrate the applicant's market power using data reflecting
conditions after the contracts expire.\167\
---------------------------------------------------------------------------

    \165\ NRECA Rehearing Request at 3, 21 (citing Cal. ex rel.
Lockyer v. FERC, 383 F.3d 1006 (9th Cir. 2004) (Lockyer); 5 U.S.C.
706(2)(A), (C)).
    \166\ Id. at 21 (citing Mo. Pub. Serv. Comm'n v. FERC, 337 F.3d
1066, 1075 (D.C. Cir. 2003) (``Reliance on facts that an agency
knows are false at the time it relies on them is the essence of
arbitrary and capricious decision making.'')).
    \167\ Id. at 22.
---------------------------------------------------------------------------

    122. NRECA states that the Commission's reliance on change in
status filings as the means to report the expiration of a long-term
contract is illogical and does not constitute reasoned decision
making.\168\ NRECA believes that absent a full market power analysis,
it is impossible to adequately determine the effect of the change.
NRECA submits that the triennial review will often come too late to
protect customers.\169\
---------------------------------------------------------------------------

    \168\ Id. (citing Motor Vehicle Mfrs. Ass'n, 463 U.S. at 43;
Pac. Gas & Elec. Co. v. FERC, 373 F.3d at 1319).
    \169\ Id. at 23 (citing Lockyer, 383 F.3d at 1014-15. See also
TDU Systems Rehearing Request at 17.
---------------------------------------------------------------------------

    123. TDU Systems also argue that the Commission should require
applicants' market-power analyses to reflect imminent changes which are
known and measurable. They agree that historical data are more
objective, but object that when they are not representative of market
conditions that will exist during the three-year period of market-based
rate authority, considering imminent changes is legally required.\170\
For soon-to-expire long-term contracts, TDU Systems assert that the
seller should not be permitted to assume that the capacity will remain
committed to the buyer. The burden should not be shifted to the
intervenors to propose the adjustment; rather, an applicant should be
required to include it as part of the analysis.\171\
---------------------------------------------------------------------------

    \170\ TDU Systems Rehearing Request at 7, 16 (citing Mo. Pub.
Serv. Comm'n v. FERC, 337 F.3d 1066, 1075 (D.C. Cir. 2003)).
    \171\ Id. at 17.
---------------------------------------------------------------------------

Commission Determination
    124. We will continue the use of historical data for both the
indicative screens and the DPT in market-based rate cases. We reject
several petitioners' requests that the Commission require sellers to
reflect imminent changes that are known and measurable, and therefore
we deny rehearing on this issue. Regarding the Commission's reliance
upon historical rather than projected data in analyzing market power
studies, and its determination not to require sellers to reflect
changes that are known and measurable, the Commission's practice for
many years has been to use a ``snapshot in time approach'' based on the
most recently available historical data at the time of filing, i.e., to
rely upon studies based on unadjusted historical data. We continue to
allow intervenors to submit sensitivity analyses including projected
data, but we reject the proposal that applicants include adjustments to
historical data as part of the required analyses.
    125. There are several reasons why this approach benefits customers
and is otherwise in the public interest. First, as we explained in the
Final Rule, historical data are more objective, readily available, and
less subject to manipulation by applicants than future
projections.\172\ If the Commission were to allow applicants to submit
studies based on their future projections or that reflect ``imminent
changes,'' then sellers would be able to selectively ``cherry pick''
those changes that benefited the seller in obtaining market-based rate
authorization while ignoring other equally likely future changes that
would undermine the seller's chances for obtaining such authorization.
Second, this approach benefits customers, state commissions and other
affected intervenors because it requires the use of a consistent
methodology that can be replicated by intervenors, rather than allowing
sellers to submit customized market power studies that, due to myriad
selective adjustments, are difficult to analyze and can hide the
presence of market power. Third, it is important to note that the
``snapshot in time'' approach does not preclude the Commission from
considering future changes in market conditions; rather, the
Commission's grant of market-based rate authority is conditioned, among
other things, on the seller's obligation to inform the Commission of
any change in status from the circumstances the Commission relied upon
in granting it market-based rate authority.

Accordingly, the market-based rate change in status reporting
requirement allows the Commission to evaluate changes when they
actually happen rather than relying on projections, making it
unnecessary and redundant for the Commission to allow sellers to
account for predicted changes in the DPT for market-based rate
purposes.
---------------------------------------------------------------------------

    \172\ Order No. 697 at P 299.
---------------------------------------------------------------------------

    126. Furthermore, accounting for ``imminent changes'' would be
excessively burdensome with regard to expiring contracts because, for
an accurate representation, a review of all expiring contracts and all
contracts being negotiated inside all balancing authority areas in the
relevant market and the seller's first-tier markets might be necessary.
In addition, because the definition of ``imminent'' is a matter of
interpretation and may change depending on the circumstances, it would
produce regulatory uncertainty. Furthermore, future changes are not
necessarily known and measurable. For example, a long-term contract may
be expiring in a year, but until it expires, it often can be renewed
for the same term(s). Therefore, an analysis that assumes that the
long-term capacity of that contract was uncommitted would not always be
correct, and therefore could overstate the seller's market power. When
a change does occur the Commission has a method to evaluate the new
situation through its requirement that sellers with market-based rate
authority report changes in status and what effect, if any, such a
change has on the grant of market-based rate authority. In any event,
the Commission may require a full market power analysis at any time
including as a result of a seller's change in status filing.
    127. With regard to Montana Counsel's argument that the Commission
should allow evidence of known and measurable changes rather than a
strict adherence to historical data because if a change in status is
caused by the expiration of a long-term contract for the sale of
capacity, then by the time a seller's change in status filing is
submitted, a seller may have already re-sold the capacity at a price
reflecting the seller's underlying market power, we recognize that a
seller's change in status filing would not be filed until after a long-
term contract expires. However, there are countervailing reasons why
the Commission believes that the use of historical data is appropriate
and reaffirms its practice of using a ``snapshot in time approach.''
\173\ As explained above, the Commission adopted this approach because
historical data are more objective, readily available, and less subject
to manipulation by sellers than future projections. We reiterate our
concern that if the Commission were to require sellers to submit
studies or change in status filings based on their future projections
such as ``imminent changes,'' then sellers would be able to selectively
``cherry pick'' those changes that benefited the seller in retaining
market-based rate authorization while ignoring other equally likely
future changes that would undermine the seller's chances for obtaining
or retaining market-based rate authorization. Similarly, intervenors
could introduce only those imminent changes that result in higher
market shares for a seller, thus artificially increasing the seller's
market shares. In addition, requiring a seller to submit market power
analyses that reflect future or ``imminent changes'' such as the future
expiration of a long-term contract would be excessively burdensome
because, for an accurate representation, review of all expiring
contracts, and all contracts being negotiated inside the relevant
market and the seller's home balancing authority area and its first-
tier markets may be necessary. Otherwise, the seller's analysis might
be incomplete and produce invalid results.
---------------------------------------------------------------------------

    \173\ For the reasons stated above, we also reject NRECA's
argument that the triennial review and the change in status filing
will come too late.
---------------------------------------------------------------------------

    128. In addition, as explained above, future changes are not
necessarily known and measurable since a long-term contract may be
expiring in a year, but until it expires, it often can be renewed for
the same term. Likewise, the Commission does not allow the seller to
deduct capacity that it is currently negotiating to sell to third
parties. To do so would allow the seller to argue that it has an
``imminent'' sale and the Commission should consider that capacity to
be committed, resulting in lowering the seller's market shares. The
danger in this circumstance is, like the expiring contract that could
be extended, the sale may not actually occur and the seller could
appear to have rebutted the presumption of market power when in fact,
based on actual data, it has market power. Therefore, an analysis that
assumes that the long-term capacity associated with an expiring
contract is uncommitted would not always be correct. In addition,
because the definition of ``imminent'' is a matter of interpretation
and may change depending on the circumstances, it would produce
regulatory uncertainty. For all of these reasons, our determination to
rely on unadjusted historical data in the indicative screens and the
DPT analysis is based on reasoned decision making.
    129. Notwithstanding our policy requiring the use of historical
data and a ``snapshot in time approach,'' in previous cases we
nevertheless have addressed evidence presented by intervenors who
sought to demonstrate that upon expiration of a long-term contract, a
seller would be able to exercise market power.\174\ Indeed, in cases
where this issue has arisen, the Commission considered the impact of
the expiring long-term contract on the seller's market power and
concluded that even when adjustments were made to the available
economic capacity measure to account for expiring contracts, the seller
did not fail the indicative screens.\175\
---------------------------------------------------------------------------

    \174\ PPL Montana, LLC, 115 FERC ] 61,204, at P 46 (2006), order
denying reh'g, 120 FERC ] 61,096, at P 52-54 (2007); Boralex
Livermore Falls LP, 122 FERC ] 61,033, at P 43 (2008).
    \175\ Id.
---------------------------------------------------------------------------

    130. While we continue to believe that the ``snapshot in time
approach'' is appropriate, and will continue to require the use of
historical data in the market power analysis, we nevertheless will
consider, on a case-by-case basis, clear and compelling evidence
presented by sellers and intervenors that seek to demonstrate that
certain changes in the market, such as the expiration of a long-term
contract, should be taken into account as part of the market power
analysis in a particular case. Entities who seek to make this
demonstration must present clear and compelling evidence in support of
their argument. The Commission will address any countervailing factors
that affect whether the seller will have the ability to exercise market
power. Such countervailing factors could include, but are not limited
to, any competitor that similarly has expiring long-term contracts and
any other factors that might impact the market power analysis such as
plant retirements, transmission access, and generation upgrades. In
this regard, we remind entities that they must perform the market power
screens as designed but may also provide a sensitivity analysis
consistent with the discussion above.
    131. We reject Montana Counsel's argument that, if the Commission
considers a seller's proposal to transfer operational control of enough
generation to a third party as part of its proposed mitigation so that
the seller would satisfy the Commission's horizontal market power
concerns, then the Commission should also consider imminent changes
that would increase a

seller's market shares. Consideration of a proposal to transfer
operational control of generation as part of a seller's proposed
mitigation, unlike consideration of imminent changes as part of a
seller's market power analysis, does not run the risk that a seller's
market power may be hidden. Moreover, the act of transferring control
may be enough to reduce the seller's market shares sufficiently to
address market power concerns.
8. Transmission Imports
Final Rule
    132. In Order No. 697, the Commission adopted the proposal to
continue to measure limits on the amount of capacity that can be
imported into a relevant market based on the results of a simultaneous
transmission import limit (SIL) study.\176\ Thus, a seller that owns
transmission will be required to conduct simultaneous transmission
import capability studies for its home balancing authority area and
each of its directly-interconnected first-tier balancing authority
areas consistent with the requirements set forth in the April 14 Order,
as clarified in Pinnacle West Capital Corp.\177\ The Commission
commented that ``the SIL study is `intended to provide a reasonable
simulation of historical conditions' and is not `a theoretical maximum
import capability or best import case scenario.' '' \178\ To determine
the amount of transfer capability under the SIL study, the Commission
stated that historical operating conditions and practices of the
applicable transmission provider should be used and the analysis should
reasonably reflect the transmission provider's OASIS operating
practices. The Commission will also continue to allow sensitivity
studies, but the sensitivity studies must be filed in addition to, not
in lieu of, an SIL study.\179\
---------------------------------------------------------------------------

    \176\ Order No. 697 at P 354.
    \177\ 110 FERC ] 61,127 (2005).
    \178\ Order No. 697 at P 354 (internal citations omitted).
    \179\ Id. P 355.
---------------------------------------------------------------------------

    133. In response to a commenter's suggestion, the Commission stated
it would allow the use of simultaneous total transfer capability (TTC)
values, provided that these TTCs are the values that are used in
operating the transmission system and posting availability on OASIS. In
addition, the Commission stated that ``[s]ellers submitting
simultaneous TTC values must provide evidence that these values account
for simultaneity, account for all internal transmission limitations,
account for all external transmission limitations existing in first-
tier areas, account for all transmission reliability margins, and are
used in operating the transmission system and posting availability on
OASIS.''\180\
---------------------------------------------------------------------------

    \180\ Id. P 364.
---------------------------------------------------------------------------

    134. The Commission also agreed with several commenters that short-
term firm reservations can be unpredictable, driven by real-time system
conditions, and do not necessarily indicate that the associated
transmission capacity is not available for competing supplies. Thus,
the Commission concluded that, in calculating simultaneous transmission
import limits, short-term reservations of 28 days or less in effect
during the study periods need not be accounted for.\181\
---------------------------------------------------------------------------

    \181\ Id. P 368.
---------------------------------------------------------------------------

    135. The Commission stated that when actual OASIS practices
conflict with the instructions in Appendix E of the April 14 Order,
sellers should follow OASIS practices and must provide documentation of
these practices.\182\ The Commission further stated that the SIL is a
benchmark of historical conditions, including peak load, and that if
additional supplies could be imported above a market's study year peak
load, the Commission will consider a sensitivity study that is
submitted in addition to the required SIL study and supported by record
evidence.\183\
---------------------------------------------------------------------------

    \182\ Id. P 356.
    \183\ Id. P 361.
---------------------------------------------------------------------------

    136. The Commission adopted the requirement for use of the SIL
study as a basis for transmission access for both the indicative
screens and the DPT analysis.\184\ The Commission stated that this
requirement assures that all factors important in determining
transmission access to the seller's market are taken into account.\185\
---------------------------------------------------------------------------

    \184\ Id. P 384.
    \185\ Id. P 386.
---------------------------------------------------------------------------

Requests for Rehearing
    137. APPA/TAPS request clarification that the use of simultaneous
TTC in the SIL study must properly account for all firm transmission
reservations, transmission reliability margin, and capacity benefit
margin.\186\ First, APPA/TAPS assert that the Commission should state
that clarifications provided in the Final Rule regarding firm
reservations apply to any use of simultaneous TTC.\187\ APPA/TAPS argue
that transmission reserved by a third party should not be double-
counted via pro-rata allocation of unused transmission capacity.\188\
Second, APPA/TAPS read the Final Rule's mention of the need for
simultaneous TTC to ``account for all transmission reliability
margins'' \189\ as affirming that TRM set-asides should not be included
in transmission capability, consistent with the July 8 Order.\190\
Third, APPA/TAPS ask the Commission to affirm that it will apply to
simultaneous TTC its prior findings in the July 8 Order that CBM set-
asides should be reflected in transmission capability as non-firm
capability unless they are used for reliability during seasonal peaks,
in which case they should not be treated as part of import
capability.\191\ APPA/TAPS point out that transmission providers do not
make CBM available on a firm basis, and when it is used for
reliability, it should not be deemed available at all to competing
suppliers.\192\
---------------------------------------------------------------------------

    \186\ APPA/TAPS Rehearing Request at 28-29 (citing Order No. 697
at P 364, 369; July 8 Order, 108 FERC ] 61,026).
    \187\ Id. at 28 (citing Order No. 697 at P 369).
    \188\ Id.
    \189\ Order No. 697 at P 364.
    \190\ APPA/TAPS Rehearing Request at 28-29.
    \191\ Id. at 29.
    \192\ Id.
---------------------------------------------------------------------------

    138. Southern states that the Final Rule concludes that short-term
reservations of more than 28 days are to be ``accounted for'' in the
simultaneous study, which suggests that they should be deducted from
the resulting import values. Southern submits that this treatment, if
intended by the Commission, is inappropriate and thus should be
reconsidered.\193\ Instead, Southern argues that such reservations
should be assigned to the entity ``that actually controls that
generation capacity on a long-term basis and who, by virtue of that
long-term control, might actually receive extra financial benefits if
the exercise of market power in wholesale electricity markets caused
wholesale prices to rise.'' \194\ Southern argues that there is a
conflict between the section on Control and Commitment, where the
Commission concludes ``that the determination of control is
appropriately based on a review of the totality of circumstances on a
fact-specific basis,'' \195\ and the SIL section that effectively
assigns to applicants any short-term purchases that they make between
one month and one year in duration so long as those purchases are
covered with firm transmission reservations. \196\
---------------------------------------------------------------------------

    \193\ Southern Rehearing Request at 32.
    \194\ Id. at 32-33 (quoting Frame Affidavit at ] 20).
    \195\ Order No. 697 at P 174.
    \196\ Southern Rehearing Request, Frame Affidavit at ] 19.
---------------------------------------------------------------------------

    139. Southern argues that the Commission's ``after-the-fact''
examination of short-term transmission reservations to see how many
were more

than 28 days in duration and who made those reservations is arbitrary
and capricious decision-making. Southern also contends that the Final
Rule is ambiguous and internally inconsistent when the Commission
states that short-term firm transmission reservations longer than 28
days must be accounted for in the simultaneous import capability
study.\197\ The Final Rule also provides that applicants do not need to
account for short-term reservations of one month or less. However,
according to Southern, the Commission then arbitrarily states that
since the shortest month of the year has only 28 days (in non-leap
years), reservations longer than 28 days must be accounted for in a
simultaneous import capability study. Thus, the Final Rule is
internally inconsistent with regard to what constitutes a month, and
the Commission selected the length of a month that is contrary to the
evidence and is thus arbitrary and capricious.\198\ According to
Southern, the Commission should grant rehearing and make clear that
applicants are not required to address short-term firm transmission
reservations in their simultaneous import capability studies.\199\
---------------------------------------------------------------------------

    \197\ Id. at 33.
    \198\ Id. at 34 (citing General Chemical Corp., 817 F.2d at 857
(reversing an order that was internally inconsistent); East Texas
Electric Co-op v. FERC, 218 F.3d 750, 754 (D.C. Cir. 2000); McElroy
Elecs. Corp. v. FCC, 990 F.2d 1351, 1358 (D.C. Cir. 1993); Motor
Vehicle Mfrs. Ass'n, 463 U.S. at 43 (finding that agency rule would
be arbitrary and capricious if the explanation runs counter to the
evidence before the agency); FPL v. Lorion, 470 U.S. 729, 744
(1985)).
    \199\ Id. at 34-35.
---------------------------------------------------------------------------

    140. Southern states that although Appendix E required the use of
generation scaling for calculating simultaneous import limit, the Final
Rule allowed sellers to use another methodology when their actual OASIS
practice conflicts with the instructions in Appendix E. Based on this
clarification, Southern states that Southern is to use the same load
shift methodology that it has historically used in calculating transfer
capability for OASIS posting instead of the Appendix E mandated
generation scaling. Southern states that in order to simulate a power
transfer under the load shift methodology to determine simultaneous
import capability into the Southern Companies' balancing authority area
for seasonal peak conditions, load in the power flow case is initially
set to the seasonal peak load level and served by a comparable amount
of generation in accordance with the engineering principle that for
each control area, generation must equal load plus losses plus
interchange. According to Southern, in order to perform transfer
analysis using the load shift methodology, load is uniformly increased
in the Southern Companies balancing authority area, while load is
simultaneously decreased in first-tier control areas to simulate the
appropriate transfer of power between the areas. Southern states that
this commonly used methodology has the effect of increasing loads
during the transfer to levels that, by definition, exceed the seasonal
peak load represented in the power flow case.\200\ Southern requests
clarification that, for purposes of performing transfer analysis under
the load shift methodology, transmission providers may allow the load
shift methodology to effect load levels that are higher than the
historical peak load levels as the means of simulating transfers.
Otherwise, Southern contends that the Final Rule will contain
inherently conflicting provisions that, on the one hand direct the use
of historical practices related to load shift transfer analyses, but at
the same time forbid the methodological process whereby the load shift
approach simulates the power flows under study.\201\
---------------------------------------------------------------------------

    \200\ Id. at 31.
    \201\ Id.
---------------------------------------------------------------------------

    141. Southern agrees that a simultaneous import capability study
conducted in accordance with Appendix E or historical practice for
seasonal peaks may be appropriate for the indicative screens. Further,
the same study approach used for the screens may be appropriate for use
in a DPT. However, Southern states that there is no legal or policy
justification for seeking a more complete analysis of competitive
conditions on the generation side, while not permitting a comparable
effort pertaining to transmission. Southern argues that to treat these
issues differently could potentially lead to serious distortions of the
competitive analysis. Therefore, Southern requests that the Commission
clarify that the Final Rule does not foreclose an applicant from
presenting a more thorough simultaneous import capability study based
upon historical conditions as part of a DPT study. Of course, any such
presentation would have to be considered on a case-specific basis and
it would have to be consistent with the fundamental determinations of
Appendix E related to simultaneous feasibility, historical practices
and the like.\202\
---------------------------------------------------------------------------

    \202\ Id. at 35.
---------------------------------------------------------------------------

Commission Determination
    142. In response to the comments from APPA/TAPS, we clarify that
the use of simultaneous TTC in the SIL study must properly account for
all firm transmission reservations, transmission reliability margin,
and capacity benefit margin. We agree that the clarifications provided
in the Final Rule regarding firm reservations apply to all simultaneous
transmission import limit studies, including those that use
simultaneous TTC.\203\ We agree that transmission reserved by a third
party should not be double-counted, such as by assuming it is available
a second time to other competitors via pro-rata allocation of unused
transmission capacity.\204\ We affirm that the Final Rule's mention of
the need for simultaneous TTC to ``account for all transmission
reliability margins'' \205\ means that TRM set-asides should not be
included in transmission capability, consistent with the July 8
Order.\206\ We also affirm that our prior findings in the July 8 Order
that capacity benefit margin set-asides should be reflected in
transmission capability as non-firm capability unless they are used for
reliability during seasonal peaks, in which case they should not be
treated as part of import capability, also apply to studies that use
simultaneous TTC.\207\ APPA/TAPS has correctly interpreted the Final
Rule in these respects.
---------------------------------------------------------------------------

    \203\ Order No. 697 at P 369.
    \204\ APPA/TAPS Rehearing Request at 28.
    \205\ Order No. 697 at P 364.
    \206\ APPA/TAPS Rehearing Request at 28-29.
    \207\ Id. at 29.
---------------------------------------------------------------------------

    143. Southern argues that there is inconsistency between the
proposed treatment of short-term transmission reservations and the
Control and Commitment section of Order No. 697. We disagree. In the
Control and Commitment section, we refer to the control of a generation
asset, including the ability to dispatch the generation asset. In the
SIL section, we refer to a firm transmission reservation. These are
different. The objective of the SIL calculation is to determine the
amount of transmission imports available to bring in supply from first-
tier areas.\208\

An applicant's firm transmission reservations represent transmission
that is not available to competing suppliers. Applicants who believe
that their firm transmission reservations should be treated as
available to import competing supply may present evidence that the
Commission will consider on a case-by-case basis.
---------------------------------------------------------------------------

    \208\ The Commission recognizes that there may be confusion
concerning the use of a pro-rata allocation of generation capacity
when performing a simultaneous transmission import limit (SIL) study
and the requirement that, when performing the indicative screens,
``[a]ny simultaneous transmission import capability should first be
allocated to the seller's uncommitted remote generation. Any
remaining simultaneous transmission import capability would then be
allocated to any uncommitted competing supplies.'' See Order No. 697
at P 38.
    With regard to performing a SIL study, pro-rata allocation is
used to assign shares to two ``groups'' of uncommitted generation
capacity in the aggregated first-tier market. The seller must first
calculate the sum of its owned and affiliated uncommitted generation
capacity, then it must sum all other sellers' uncommitted generation
capacity. The seller then divides these two numbers to compute a
ratio of the seller's (and affiliated) uncommitted generation
capacity to all other sellers' uncommitted generation which
determines the ``share'' that each seller is allocated to import
into the study area. In other words, when performing the SIL study,
any uncommitted generation capacity in the aggregate first-tier
market is allocated pro-rata for the purpose of determining the
value of the SIL.
    With regard to performing the indicative screen analyses, all of
the seller's and its affiliated uncommitted generation capacity in
first-tier markets (remote capacity) should be allocated to the
seller's total uncommitted capacity in the relevant market (study
area), up to the SIL limit. Any remaining simultaneous transmission
import capability is then allocated to any uncommitted competing
generation.
    For example, if the SIL limit is 200 MW, the seller and its
affiliates' uncommitted generation capacity in first-tier markets is
150 MW, and competing uncommitted generation capacity in first-tier
markets is 350 MW, then to properly perform the indicative screens
the seller's uncommitted generation capacity in the relevant market
is increased by 150 MW and competing supply in the relevant market
is increased by 50 MW.
---------------------------------------------------------------------------

    144. In response to Southern's comments regarding short-term
transmission reservations, we clarify that for the reasons described in
Order No. 697,\209\ applicants are not required to address short-term
firm reservations in the market power screens. Currently, the
Commission's EQR Data Dictionary defines monthly as more than 168
consecutive hours up to one month, and seasonal as greater than one
month and less than 365 consecutive days.\210\ Twenty-eight days fits
within the definition of a month, and is a reasonable limit to separate
short-term reservations from long-term reservations for purposes of the
generation market power screens. Since the market power screens are
conducted for four seasonal periods, and they are designed to model
historical conditions during the four seasonal peak periods, the
screens must account for transmission reservations typical for each
season. It is not practical to require applicants to provide data on
every transmission reservation, yet we cannot ignore the impact of
transmission reservations on the potential for market power. Requiring
applicants to account for reservations greater than one month in
duration strikes a balance between allowing the screens to reasonably
model historical conditions without requiring unreasonable amounts of
information from applicants. Therefore, we will require applicants to
allocate their seasonal and longer transmission reservations to
themselves from the calculated SIL, where seasonal reservations are
greater than one month and less than 365 consecutive days in duration,
as defined in the Commission's EQR Data Dictionary.
---------------------------------------------------------------------------

    \209\ Order No. 697 at P 368.
    \210\ Order Adopting Electric Quarterly Report Data Dictionary,
Order No. 2001-G, 72 FR 56735 (Oct. 4, 2007), 120 FERC ] 61,270, at
P 35 (2007).
---------------------------------------------------------------------------

    145. We grant the clarification Southern seeks in part. We would
allow sellers to use load shift methodology to calculate simultaneous
import limit while scaling their load beyond the historical peak load,
provided they submit adequate support and justification for the scaling
factor used in their load shift methodology and how the resulting SIL
number compares had the company used a generation shift methodology.
    146. In response to Southern's request for clarification regarding
whether applicants may present more thorough simultaneous import
capability studies based upon historical conditions as part of a DPT
study, we clarify that, as we stated in the Final Rule, applicants may
submit additional sensitivity studies, including a more thorough import
study as part of the DPT. We reaffirm, however, that any such
sensitivity studies must be filed in addition to, and not in lieu of,
an SIL study.\211\
---------------------------------------------------------------------------

    \211\ Id. P 355.
---------------------------------------------------------------------------

9. Further Guidance Regarding Control and Commitment of Capacity
    147. In Order No. 697, the Commission concluded that the
determination of control is appropriately based on a review of the
totality of circumstances on a fact-specific basis. We explained that
no single factor or factors necessarily results in control. We further
explained that the electric industry remains a dynamic, developing
industry, and no bright-line standard will encompass all relevant
factors and possibilities that may occur now or in the future. If a
seller has control over certain capacity such that the seller can
affect the ability of the capacity to reach the relevant market, then
that capacity should be attributed to the seller when performing the
generation market power screens.\212\
---------------------------------------------------------------------------

    \212\ Order No. 697 at P 174.
---------------------------------------------------------------------------

    148. We determined that the circumstances or combination of
circumstances that convey control vary depending on the attributes of
the contract, the market and the market participants. Therefore, we
concluded that it would be inappropriate to make a generic finding or
generic presumption of control, but rather that it is appropriate to
continue making our determinations of control on a fact-specific basis.
We explained, however, that we continue our historical approach of
relying on a set of principles or guidelines to determine what
constitutes control. Thus, we stated that we continue to consider the
totality of circumstances and attach the presumption of control when an
entity can affect the ability of capacity to reach the market. We
explained that our guiding principle is that an entity controls the
facilities when it controls the decision-making over sales of electric
energy, including discretion as to how and when power generated by
these facilities will be sold.\213\
---------------------------------------------------------------------------

    \213\ Id. P 175.
---------------------------------------------------------------------------

    149. We declined to adopt commenters' suggestions that we require
all relevant contracts to be filed for review and determination by the
Commission as to which entity controls a particular asset (e.g., with
an initial application, updated market power analysis, or change in
status filing). While we noted that under section 205 of the FPA, the
Commission may require any contracts that affect or relate to
jurisdictional rates or services to be filed, we explained that the
Commission uses a rule of reason with respect to the scope of contracts
that must be filed and does not require as a matter of routine that all
such contracts be submitted to the Commission for review. Our
historical practice has been to place on the filing party the burden of
determining which entity controls an asset. Therefore, we required a
seller to make an affirmative statement as to whether a contractual
arrangement transfers control and to identify the party or parties it
believes control the generation facility, but explained that the
Commission retains the right at the Commission's discretion to request
the seller to submit a copy of the underlying agreement(s) and any
relevant supporting documentation.
    150. Given the increased level of investment in the electric
utility industry as a result of the Energy Policy Act of 2005 (EPAct
2005) \214\ and our implementing rules and regulations, we find it
necessary to provide further guidance with respect to the
representations that a seller should make regarding which entity
controls a particular asset. An increasing number

of investors are acquiring interests in assets that may be relevant to
a seller's market-based rate authority. As we explained in Order No.
697, we will continue to place on the filing party the burden of
determining which entity controls an asset. We will rely on the
seller's representations regarding control, absent extenuating
circumstances. Therefore, to provide further guidance to the industry,
we reiterate that the seller, in advising the Commission of its
determinations of control, should specifically state whether a
contractual arrangement transfers control and should identify the party
or parties it believes control(s) the generation facility. In doing so,
the seller should make its representation in light of our discussion in
Order No. 697 and cite to that order as the basis for which it has made
its determination.
---------------------------------------------------------------------------

    \214\ Energy Policy Act of 2005, Pub. L. No. 109-58, 119 Stat.
594 (2005).
---------------------------------------------------------------------------

B. Vertical Market Power

1. OATT Violations and Market-Based Rate Revocation
Final Rule
    151. In the Final Rule, the Commission stated it will revoke an
entity's market-based rate authority in response to an OATT violation
upon a finding of a nexus between the specific facts relating to the
OATT violation and the entity's market-based rate authority, and
reiterated that an OATT violation may subject the seller to other
remedies the Commission may deem appropriate, such as disgorgement of
profits or civil penalties.\215\ The finding that an OATT adequately
mitigates transmission market power rests on the assumption that
individual entities comply with the OATT and that there may be OATT
violations in circumstances that, after applying the factors in the
Enforcement Policy Statement,\216\ merit revocation or limitation of
market-based rate authority. The Final Rule found, however, that it is
inappropriate to revoke a seller's market-based rate authority for an
OATT violation unless there is a nexus between the specific facts
relating to the OATT violation and the seller's market-based rate
authority. The Commission declined to adopt a rebuttable presumption
that any OATT violation has the requisite nexus to support revocation
of market-based rate authority, explaining that there is a wide range
of types of OATT violations, including ones that may be inadvertent and
others that are neither intended to affect, nor in fact affect, the
market-based rate sales of the transmission provider or its
affiliates.\217\
---------------------------------------------------------------------------

    \215\ Order No. 697 at P 417.
    \216\ Enforcement of Statutes, Orders, Rules and Regulations,
113 FERC ] 61,068 (2005) (Enforcement Policy Statement).
    \217\ Order No. 697 at P 417.
---------------------------------------------------------------------------

    152. The Commission stated that determining what constitutes a
sufficient factual nexus is best left to a case-by-case consideration,
explaining that the wide range of positions among commenters on how to
define a sufficient factual nexus itself suggested that this finding is
best made after review of a specific factual situation. Some commenters
had asserted that a finding of a ``material'' violation of the OATT
would be sufficient. The Commission disagreed. While a seller's
inconsequential OATT violation would not serve as a basis for revoking
that entity's market-based rate authority, the Commission stated that
revocation is warranted only when an OATT violation has occurred and
the violation had a nexus to the market-based rate authority of the
violator or its affiliates.\218\ The Commission also clarified that it
will allow intervenors on a case-by-case basis to file evidence if they
believe they have been denied transmission access in violation of the
OATT.\219\
---------------------------------------------------------------------------

    \218\ Id. P 418.
    \219\ Id. P 421.
---------------------------------------------------------------------------

    153. The Commission emphasized in the Final Rule that it has
discretion to fashion remedies for OATT violations that relate to the
violator's market-based rate authority in instances in which the
Commission does not find sufficient justification for revocation of
that authority. For example, in appropriate circumstances, the
Commission may modify or add additional conditions to the violator's
market-based rate authority or impose other requirements to help ensure
that the violator does not commit future, similar misconduct. The
Commission also explained that it will consider whether to impose
sanctions such as assessment of civil penalties for particularly
serious OATT violations in addition to revocation of the violator's
market-based rate authority.\220\
---------------------------------------------------------------------------

    \220\ Id. P 419.
---------------------------------------------------------------------------

Requests for Rehearing
    154. NRECA and TDU Systems argue that the Final Rule's
determination that the Commission will not revoke the market-based rate
authority of a public utility or its affiliates upon the utility's
violation of its OATT unless there is a ``nexus'' between the
``specific facts'' of the violation and the violator's market-based
rate authority is arbitrary, capricious, contrary to law, and in excess
of statutory authority. NRECA also argues that the Final Rule does not
provide clear guidance as to what would constitute a sufficient
nexus.\221\
---------------------------------------------------------------------------

    \221\ NRECA Rehearing Request at 28 (citing Order No. 697 at P
418).
---------------------------------------------------------------------------

    155. TDU Systems state that the Commission must clarify the
circumstances in which it will find that there is a sufficient nexus
between a transmission provider's OATT violations and the revocation of
market-based rate authorization of the provider or its affiliates, and
reconsider its decision to determine what constitutes a sufficient
factual nexus on a case-by-case basis.\222\ TDU Systems state that,
apart from trivial violations, which could be screened out by the kind
of materiality filter suggested by APPA/TAPS,\223\ the Commission has
not explained why material OATT violations should not create at least a
presumption that market-based rate authorization is inappropriate.\224\
TDU Systems state that, because having an OATT on file and being bound
by its terms are necessary to mitigating the public utility's vertical
market power, there is logical reason to be concerned that a violation
may have undermined a premise for the authorization. TDU Systems
therefore assert that an OATT violation should automatically trigger a
Commission proceeding in which the violator has the burden of
justifying its continued market-based rate authority.\225\ Furthermore,
TDU Systems state that shifting the burden to the transmission provider
could encourage transmission providers to be in full compliance with
coordinated and open regional planning.\226\
---------------------------------------------------------------------------

    \222\ TDU Systems Rehearing Request at 8, 20.
    \223\ Id. at 21 (citing APPA/TAPS Initial Comments at 81).
    \224\ Id. at 8, 21.
    \225\ Id. at 21.
    \226\ Id. at 8.
---------------------------------------------------------------------------

    156. TDU Systems also argue that the Commission needs to address
further the content of the ``nexus'' requirement. They contend that
transmission-owning public utilities might read Order No. 697 to allow
for revocation of their market-based rate authority only when it would
be arbitrary and capricious for the Commission not to do so.\227\ TDU
Systems contend that the Commission has offered no clue to
understanding why it may be relevant whether the alleged violator has
committed an OATT violation in order to further a specific sale under
its own market-based rate tariff or that of an affiliate. TDU Systems
conclude that if such a connection is indeed critical, there would
appear to be a substantial danger of deflecting attention from the
characteristics of a transmission

provider's conduct, i.e., whether it is anticompetitive or reflects the
exercise of market power.\228 \
---------------------------------------------------------------------------

    \227\ Id. at 22.
    \228\ Id.
---------------------------------------------------------------------------

    157. These petitioners claim that the Commission's position appears
to place the burden of proof on customers, competitors, or the
Commission to demonstrate the nexus, rather than requiring the violator
to demonstrate the lack of any such nexus.\229\
---------------------------------------------------------------------------

    \229\ NRECA Rehearing Request at 3, 27-29; TDU Systems Rehearing
Request at 3-4, 20.
---------------------------------------------------------------------------

    158. NRECA asserts that when a public utility violates its OATT,
one of the preconditions to the grant of market-based rate authority is
violated. It argues that, under the FPA, the seller, not customers,
must bear the burden of proof that its continuing sales under its
market-based rate tariff remain at just and reasonable levels.\230\
NRECA therefore contends that there should be a presumption that there
is a ``nexus'' between the OATT violation and the seller's market-based
rate authority.\231\ NRECA states that the burden, consistent with the
FPA, should be on the seller to rebut this presumption; however, it
suggests that the Commission could evaluate the seller's showing, and
if the issue is in doubt, set the matter for investigation or hearing
and order a temporary suspension of market-based rate authority until
the matter is resolved.\232\
---------------------------------------------------------------------------

    \230\ NRECA Rehearing Request at 28 (citing Lockyer, 383 F.3d at
1014-15; 16 U.S.C. 824d(e)).
    \231\ Id. at 29.
    \232\ Id.
---------------------------------------------------------------------------

Commission Determination
    159. The Commission denies rehearing of the decision to require a
factual nexus between a substantial OATT violation and the entity's
market-based rate authority to justify revocation of that authority. As
the Commission explained in Order No. 697, the ``nexus condition'' is
required in order to ensure that our actions are not arbitrary or
capricious or based on an inadequate factual record. We disagree with
NRECA and TDU Systems that any material OATT violation should
necessarily justify revocation of the entity's market-based rate
authority since the violation may have no relation to the market-based
rate authority. In such circumstances, the Commission will consider
such other remedies as may be appropriate. We also decline to provide
specific examples of what would constitute a sufficient nexus between
an entity's market-based rate authority and an OATT violation because
the factual circumstances involved in a claimed violation will be
unique to the company and, therefore, any list would be incomplete.
This is especially true in light of continually developing markets. We
continue to believe that the determination of what would be a
sufficient factual nexus between an OATT violation and revocation of
the violator's market-based rate authority is best left to case-by-case
consideration.
    160. With regard to the transmission provider's planning
obligations in particular, violations of the planning-related
requirements of the pro forma OATT may or may not have a sufficient
factual nexus with the transmission provider's market-based rate
authority. A case-by-case analysis will be necessary to determine if
the violation justifies revocation of the transmission provider's
market-based rate authority. We agree with TDU Systems that OATT
violations by a transmission provider that may not be explicitly
connected with its market-based rate authorization may nonetheless
promote conditions in which the violator could gain an advantage in
future transactions. However, we note that this is an example of why a
case-by-case determination is needed so that the Commission can
consider the violation, the seller's market-based rate authority, and
market conditions in determining what remedy, if any, best suits the
situation. Therefore, we will apply the mechanisms adopted in Order No.
890 to aid us in determining on a case-by-case basis if a particular
violation puts that company at an advantage vis-[aacute]-vis its
market-based rate authority.\233\
---------------------------------------------------------------------------

    \233\ See Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P
1037.
---------------------------------------------------------------------------

    161. We disagree with TDU Systems and NRECA that the Commission
inappropriately shifted the burden of proof regarding whether there is
a nexus. We anticipate that the Commission's consideration of a
seller's OATT violation and whether or not there is a nexus with its
market-based rate authority would normally arise as part of a
Commission-initiated enforcement proceeding. In enforcement
proceedings, the Commission has considerable discretion in how to
fashion an appropriate remedy and the burden of justifying any remedial
actions taken against a violator, including revocation of market-based
rate authority and determining what remedies are required to ensure
that any future sales, market-based rate or otherwise, are at just and
reasonable rates. Moreover, even if the issue arose in publicly noticed
proceedings (such as a section 206 or 306 complaint), the Commission
would exercise its remedial discretion based on the facts presented and
accordingly bear the burden of justifying any remedy imposed on the
transmission provider for a violation of its OATT. Whether or not a
violation justifies revocation of the seller's market-based rate
authority will depend on the facts and circumstances involved in each
case; therefore, it would not be appropriate to adopt a presumption of
that nexus, as requested by petitioners. The Commission will make a
determination based on the facts of each particular case as to whether
or not an OATT violation has a nexus to the seller's market-based rate
authority. In sum, the Commission's action in Order No. 697 does not
shift the burden of proving a nexus to customers and competitors.
    162. Contrary to TDU Systems' assertion, Order No. 697 does not
limit the Commission to revoking a seller's market-based rate authority
only in circumstances where it would be arbitrary and capricious not to
do so. If an OATT violation occurs, the Commission will investigate
whether or not the facts surrounding the violation have a nexus to the
seller's market-based rate authority. It would not be just and
reasonable for the Commission to revoke a seller's market-based rate
authority if in fact the violation had no bearing on the seller's
market-based rate position. The way to make such a determination is
based on an adequate factual record and that is what would be
established in such a proceeding before making any determinations.
2. Treatment of FTRs
Final Rule
    163. In the Final Rule, the Commission stated that provisions
concerning the reassignment or sale of transmission capacity or firm
transmission rights, congestion contracts, or fixed transmission rights
(as a group, FTRs) are not required to be included in a seller's
market-based rate tariff, nor is it appropriate to include
transmission-related services in a seller's market-based rate
tariff.\234\ The Commission explained that Commission-approved market
rules for RTO/ISOs address resales of FTRs and virtual trading to
ensure that no market power is exercised in such trades. In addition,
sellers engaging in these activities sign a participation agreement
with RTO/ISOs which require them to abide by those market rules. Hence,
the approval of the market rules in conjunction with approval of the
generic participation agreement by the Commission constitutes
authorization for public utilities to engage in the

resale of FTRs and virtual transactions, and no separate authorization
is required under the FPA.
---------------------------------------------------------------------------

    \234\ Order No. 697 at P 920.
---------------------------------------------------------------------------

Requests for Rehearing
    164. Morgan Stanley states that, when assessing whether a potential
market-based rate seller has market power, the Commission has focused
on ownership and control of physical transmission (except for that
which is necessary to interconnect generation to the transmission
grid).\235\ Morgan Stanley requests that the Commission clarify whether
a seller is required to include and report the acquisition of financial
transmission rights when assessing whether it has vertical market
power. Morgan Stanley states that the Commission declined to adopt such
a requirement as part of Order No. 652 governing changes in
status.\236\ However, Morgan Stanley asserts that ``Commission staff
and others have taken inconsistent positions on whether the failure to
disclose the acquisition of financial transmission rights constitutes a
violation of a seller's market-based rate tariff.''\237 \
---------------------------------------------------------------------------

    \235\ Morgan Stanley Rehearing Request at 1-2 (citing Iowa Power
Partners, 81 FERC ] 61,058, at 61,281 (1997)).
    \236\ Reporting Requirement for Changes in Status for Public
Utilities with Market-Based Rate Authority, Order No. 652, 70 FR
8253 (Feb. 18, 2005), FERC Stats. & Regs. ] 31,175, order on reh'g,
111 FERC ] 61,413 (2005).
    \237\ Morgan Stanley Rehearing Request at 2. (citing Enron Power
Marketing, 119 FERC ] 63,013 (2007) (discussing Enron's use of FTRs
to exercise market power and its failure to report its FTRs to the
Commission)).
---------------------------------------------------------------------------

Commission Determination
    165. The Commission clarifies herein that sellers are not required
to report on financial transmission rights as part of the vertical
market power assessment. Thus, failure to disclose the acquisition of
financial transmission rights in an application for market-based rate
authority, a three-year update or a change in status filing does not
constitute a violation of a seller's market-based rate tariff. While
ownership of financial transmission rights could affect a seller's
incentive to exercise market power, we find that there are adequate
mechanisms and protections in place to minimize a seller's ability to
do so (e.g., market monitoring and mitigation in RTO/ISOs; the
requirement that a seller must abide by its OATT and any violation
thereof could constitute a violation of a seller's market-based rate
tariff; the Commission's enforcement proceedings). Moreover, the
Commission does not analyze physical rights that a seller has to
transmission service when analyzing vertical market power, and the
Commission will treat financial rights in an equal manner. Physical and
financial rights to transmission service do not enable the customer to
control transmission capacity in a way that withholds the capacity from
the market. To the extent there is an issue with potential market
manipulation by a seller, the Commission would address this through an
Office of Enforcement proceeding.
 3. Other Barriers to Entry
Final Rule
    166. The Final Rule adopted the NOPR proposal to consider a
seller's ability to erect other barriers to entry as part of the
vertical market power analysis, but modified the requirements when
addressing other barriers to entry. It also provided clarification
regarding the information that a seller must provide with respect to
other barriers to entry (including which inputs to electric power
production the Commission will consider as other barriers to entry) and
modified the proposed regulatory text in that regard.\238 \
---------------------------------------------------------------------------

    \238\ Order No. 697 at P 440.
---------------------------------------------------------------------------

    167. In the Final Rule, the Commission drew a distinction between
two categories of inputs to electric power production: One consisting
of natural gas supply, interstate natural gas transportation (which
includes interstate natural gas storage), oil supply, and oil
transportation; and another consisting of intrastate natural gas
transportation, intrastate natural gas storage or distribution
facilities, sites for generation capacity development, and sources of
coal supplies and the transportation of coal supplies such as barges
and rail cars.\239\
---------------------------------------------------------------------------

    \239\ Id. P 441.
---------------------------------------------------------------------------

    168. With regard to the first category, the Commission removed the
inputs from the vertical market power analysis. Thus, the Final Rule
did not require a description of or affirmative statement with regard
to ownership or control of, or affiliation with an entity that owns or
controls, natural gas and oil supply, including interstate natural gas
transportation and oil transportation.\240\ The Commission explained
that prices for wellhead sales of natural gas were decontrolled by
Congress,\241\ and that the Commission has granted other sellers
blanket authority to make such sales at market rates. In the case of
transportation of natural gas, the Commission noted that pipelines
operate pursuant to the open and non-discriminatory requirements of
Part 284 of the Commission's regulations;\242\ these regulations
mandate that all available pipeline capacity be posted on the
pipelines' website, and that available capacity cannot be withheld from
a shipper willing to pay the maximum approved tariff rate. The
Commission noted that, to the extent intervenors are concerned about a
seller's market power from ownership or control of interstate natural
gas transportation, this would be actionable first in a complaint
proceeding under section 5 of the Natural Gas Act before turning to
market-based rate consequences, if any.\243\
---------------------------------------------------------------------------

    \240\ Id. P 442.
    \241\ INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002); Natural Gas
Decontrol Act of 1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess.,
at 6 (1989).
    \242\ Order No. 697 at P 443 (citing Pipeline Service
Obligations and Revisions to Regulations Governing Self-Implementing
Transportation; and Regulation of Natural Gas Pipelines After
Partial Wellhead Decontrol, Order No. 636, 57 FR 13267 (Apr. 16,
1992), FERC Stats. & Regs., Regulations Preambles January 1991-June
1996 ] 30,939 (Apr. 8, 1992); Regulation of Short-Term Natural Gas
Transportation Services and Regulation of Interstate Natural Gas
Transportation Services, Order No. 637, FERC Stats. & Regs.,
Regulations Preambles July 1996-December 2000 ] 31,091 (Feb. 9,
2000); clarified, Order No. 637-A, FERC Stats. & Regs., Regulations
Preambles July 1996-December 2000) ] 31,099 (May 19, 2000); reh'g
denied, Order No. 637-B, 92 FERC ] 61,062 (2000); aff'd in part and
remanded in part sub nom.).
    \243\ Order No. 697 at P 445.
---------------------------------------------------------------------------

    169. Similarly, the Commission noted that oil pipelines are common
carriers under the Interstate Commerce Act, specifically under section
1(4), that they are required to provide transportation service ``upon
reasonable request therefore,'' and that Congress has not chosen to
regulate sales of oil.\244\
---------------------------------------------------------------------------

    \244\ Id. P 444 (quoting 49 App. U.S.C. 1(4)).
---------------------------------------------------------------------------

    170. With regard to the second category of inputs to electric power
production, the Commission adopted a rebuttable presumption that
sellers cannot erect barriers to entry with regard to the ownership or
control of, or affiliation with any entity that owns or controls, those
inputs.\245\ The Commission noted that, to date, it has not found such
ownership, control or affiliation to be a potential barrier to entry
warranting further analysis in the context of market-based rate
proceedings. However, unlike the first category of inputs, the
Commission does not have sufficient evidence to remove these inputs
from the analysis entirely. Accordingly, the Commission stated that it
will rebuttably presume that ownership or control of, or affiliation
with an entity that owns or controls, any of the second category of
inputs does not allow a seller to raise entry barriers, but intervenors
will be allowed to

demonstrate otherwise. The Final Rule noted that this rebuttable
presumption only applies if the seller describes and attests to these
inputs to electric power production in its market power analysis, as
discussed below.\246\
---------------------------------------------------------------------------

    \245\ Id. P 446. The Commission modified the definition of
``inputs to electric power production'' in 18 CFR 35.36(a)(4) to
reflect this clarification.
    \246\ Id. P 446.
---------------------------------------------------------------------------

    171. The Commission required a seller to provide a description of
its ownership or control of, or affiliation with an entity that owns or
controls, any of the second category of inputs. The Final Rule required
sellers to provide this description and to make an affirmative
statement, with some modifications to the affirmative statement from
what was proposed in the NOPR. Instead of requiring sellers to make an
affirmative statement that they have not erected barriers to entry into
the relevant market, the Final Rule required sellers to make an
affirmative statement that they have not erected barriers to entry into
the relevant market and will not erect barriers to entry into the
relevant market. The Final Rule clarified that the obligation in this
regard applies both to the seller and its affiliates, but is limited to
the geographic market(s) in which the seller is located.\247\
---------------------------------------------------------------------------

    \247\ Id. P 447.
---------------------------------------------------------------------------

    172. Therefore, the Final Rule modified the proposed regulations to
require a seller to provide a description of its ownership or control
of, or affiliation with an entity that owns or controls these types of
assets, to ensure that this information is included in the record of
each market-based rate proceeding. In addition, the Commission required
sellers to make an affirmative statement that they have not erected
barriers to entry into the relevant market and will not erect barriers
to entry into the relevant market.\248\
---------------------------------------------------------------------------

    \248\ Id. P 448.
---------------------------------------------------------------------------

    173. The Commission also modified the change in status reporting
requirement in Sec.  35.42 of the Commission's regulations to be
consistent with the other barriers to entry part of the vertical market
power analysis as adopted in the Final Rule.
Requests for Rehearing
    174. Southern notes that the Final Rule modified the change in
status regulations adopted by the Commission in Order No. 652.
Specifically, Southern states that the Commission modified the
definition of inputs to electric power production to mean ``
`intrastate natural gas transportation, intrastate natural gas storage
or distribution facilities; sites for new generation capacity
development; sources of coal supplies and the transportation of coal
supplies such as barges and railcars,' '' \249\ and comments that under
the change in status reporting regulations, sellers would be required
to notify the Commission of any changes to such inputs. Southern
requests clarification of what is meant by the phrase ``sources of coal
supplies and the transportation of coal supplies such as barges and
railcars'' in the context of the definition of ``inputs to electric
power production.'' Because such inputs to electric power production
are considered in the Commission's vertical market power analysis,\250\
Southern believes that the Commission's intention is for this phrase to
mean physical coal sources (i.e., coal mines) and ownership or control
over who may access transportation of coal via barges and railcar
trains (e.g., control of a train system, a railcar manufacturing or
supply company, or a barge production or supply company), rather than
merely entering into a coal supply contract with a coal vendor.
Southern argues that if a change in status filing were required every
time a large utility entered into a coal purchase agreement, purchased
or leased a single railcar or barge, or engaged in other such routine
activities, which Southern asserts are a necessary and inherent part of
keeping power plants operating so that they can reliably serve a
utility's customers, the Commission could find itself inundated with
submissions. Accordingly, Southern requests that the Commission clarify
that the phrase ``inputs to electric power production'' is intended to
encompass physical coal sources and ownership of control over who may
access transportation of coal via barges and railcar trains.
---------------------------------------------------------------------------

    \249\ Southern Rehearing Request at 41 (citing Order No. 697 at
P 1016).
    \250\ Id. at 41 (citing Order No. 697 at P 446).
---------------------------------------------------------------------------

    175. APPA/TAPS request that the Commission clarify that intervenors
may introduce evidence that control and/or ownership of interstate
natural gas supply, transportation or storage, as well as oil supply
and transportation, creates entry barriers.\251\ APPA/TAPS request
clarification that the Final Rule's stated case-by-case consideration
of other entry barriers will include evidence that a seller's or its
affiliate's ownership or control of the first category of entry
barriers will be considered.\252\ According to APPA/TAPS, if, as the
Commission believes, markets in the first category are competitive,
intervenors will rarely raise concerns about them in specific cases,
which means there is no basis to reject this requested clarification on
grounds that allowing intervenors to raise entry concerns will be
unduly burdensome for applicants or the Commission. APPA/TAPS contend
that if there are concerns about these entry barriers, the Commission
provides no justification for requiring an intervenor to undertake the
time and expense of a `` `complaint proceeding under section 5 of the
Natural Gas Act before turning to market-based rate consequences.' ''
\253\ Further, APPA/TAPS state that by allowing intervenor evidence
regarding market issues surrounding the first category of inputs, the
market-based rate program `` `will allow unique or newly developed
barriers to entry to be brought before the Commission.' '' \254\
---------------------------------------------------------------------------

    \251\ APPA/TAPS Rehearing Request at 29-30 (citing Order No. 697
at P 441-49; United States v. Enova Corp., 107 F. Supp. 2d 10
(D.D.C. 2000)).
    \252\ Id. at 30.
    \253\ Id. (quoting Order No. 697 at P 445).
    \254\ Id. (quoting Order No. 697 at P 449).
---------------------------------------------------------------------------

Commission Determination
    176. We agree with Southern that it was not the Commission's intent
for the term ``inputs to electric power production'' to encompass every
instance of a seller entering into a coal supply contract with a coal
vendor in the ordinary course of business. The Commission clarifies
that Order No. 697 encompasses physical coal sources and ownership of
or control over who may access transportation of coal via barges and
railcar trains. Thus, the Commission will revise its definition of
``inputs to electric power production'' in Sec.  35.36(a)(4) as
follows: ``intrastate natural gas transportation, intrastate natural
gas storage or distribution facilities; sites for new generation
capacity development; physical coal supply sources and ownership of or
control over who may access transportation of coal supplies.''
    177. The Commission denies APPA/TAPS' request that the Commission
clarify that intervenors may introduce evidence that control and/or
ownership of interstate natural gas supply, transportation or storage,
as well as oil supply and transportation, create entry barriers. As
explained above and in Order No. 697, prices for wellhead sales were
decontrolled by Congress,\255\ and the Commission has granted other
sellers blanket authority to make such sales at market rates. In the
case of transportation of natural gas, pipelines operate pursuant to
the open and non-discriminatory requirements of Part 284 of the
Commission's regulations; \256\

these regulations require that all available pipeline capacity be
posted on the pipelines' Web site, and that available capacity cannot
be withheld from a shipper willing to pay the maximum approved tariff
rate. Similarly, the Final Rule noted that oil pipelines are common
carriers under the Interstate Commerce Act, specifically under section
1(4), that they are required to provide transportation service ``upon
reasonable request therefore,'' and that Congress has not chosen to
regulate sales of oil.\257\
---------------------------------------------------------------------------

    \255\ INGAA v. FERC, 285 F.3d 18 (D.C. Cir. 2002); Natural Gas
Decontrol Act of 1989, H.R. Rep. No. 101-29, 101st Cong., 1st Sess.,
at 6 (1989).
    \256\ Order No. 697 at P 443 (and cases cited therein).
    \257\ Id. P 444 (quoting 49 App. U.S.C. 1(4)).
---------------------------------------------------------------------------

    178. As stated in the Final Rule, to the extent intervenors are
concerned about a seller's market power from ownership or control of
interstate natural gas transportation, this would be actionable first
in a complaint proceeding under section 5 of the Natural Gas Act before
turning to any market-based rate consequences.
    179. The Commission found in Order No. 697 and we reiterate here
that there is no need to address these inputs to electric power
production as potential barriers to entry in the context of the market-
based rate program. In light of the precedent described above, we
conclude that sellers cannot erect barriers to entry with regard to
such inputs.
    180. Regarding APPA/TAPS' assertion that the Commission provides no
justification for requiring an intervenor to file a complaint
proceeding under section 5 of the Natural Gas Act when a concern arises
regarding interstate natural gas transportation, as explained in Order
No. 697, natural gas pipelines operate pursuant to the open and non-
discriminatory requirements of Part 284 of the Commission's
regulations. On this basis, the appropriate forum for addressing a
concern that may arise regarding interstate natural gas transportation
would initially be a proceeding under the Natural Gas Act, not the FPA.
Thus, a market-based rate proceeding would not be the proper forum for
such a complaint. The place to challenge a particular seller's
potential market power in interstate natural gas transportation markets
is in a complaint proceeding under section 5 of the Natural Gas Act.

C. Affiliate Abuse

    181. In Order No. 697, the Commission determined that affiliate
abuse should no longer be considered a separate ``prong'' of the
market-based rate analysis, and instead codified the affiliate
requirements and restrictions as an explicit requirement in section
35.39 of the Commission's regulations. The affiliate requirements and
restrictions must be satisfied on an ongoing basis as a condition of
obtaining and retaining market-based rate authority.\258\ The
regulations expressly prohibit power sales between a franchised public
utility with captive customers and any market-regulated power sales
affiliate, without first receiving Commission authorization for the
transaction under section 205 of the FPA. The regulations also include
the requirements formerly known as the market-based rate ``code of
conduct,'' as revised in Order No. 697.
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    \258\ A seller seeking market-based rate authority must provide
information regarding its affiliates and its corporate structure or
upstream ownership. To the extent that a seller's owners are
themselves owned by others, the seller seeking to obtain or retain
market-based rate authority must identify those upstream owners.
Sellers must trace upstream ownership until all upstream owners are
identified. Sellers must also identify all affiliates. Finally, an
entity seeking market-based rate authority must describe the
business activities of its owners, stating whether they are in any
way involved in the energy industry.
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1. General Affiliate Terms & Conditions
a. Affiliate Definition
    182. As an initial matter, we clarify that the term ``affiliate''
for purposes of Order No. 697 and the affiliate restrictions adopted in
Sec.  35.39 of our regulations is defined as that term is used in the
regulations adopted in the Affiliate Transactions Final Rule. In the
Affiliate Transactions Final Rule, the Commission considered the use of
the term affiliate in the context of the Affiliate Transactions NOPR,
the Commission's Standards of Conduct for Transmission Providers, and
other precedent.\259\ The Commission also reviewed the affiliate
definitions contained in both the Public Utility Holding Company Act of
1935 (PUHCA 1935) \260\ and the Public Utility Holding Company Act of
2005 (PUHCA 2005) \261\. After taking into account these differing
definitions of affiliate, and recognizing the need to provide greater
clarity and consistency in our rules, the Commission explained that it
believes it is important to try to adopt a more consistent definition
in its various rules and also one that is sufficiently broad to allow
us to adequately protect customers.\262\ On this basis, the definition
of affiliate as adopted in the Affiliate Transactions Final Rule
explicitly incorporates the PUHCA 1935 definition of affiliate for EWGs
(rather than incorporate it by reference as previously has been
done).\263\ The definition also adopts a parallel definition of
affiliate for non-EWGs, but with adjustments to reflect the previously-
used 10 percent voting interest threshold for non-EWGs and to eliminate
certain language not applicable or necessary in the context of the FPA.
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    \259\ See, e.g., Morgan Stanley Capital Group, Inc., 72 FERC ]
61,082, at 61,436-37 (1995) (Morgan Stanley).
    \260\ 15 U.S.C. 79a et seq.
    \261\ EPAct 2005 at 1261 et seq.
    \262\ For example, we adopt this definition of affiliate for
purposes of section 203 of the FPA in the Affiliate Transactions
Final Rule.
    \263\ We note that in EPAct 2005 section 1277(b)(2), Congress
enacted a conforming amendment which amended FPA section 214 to
refer to the section 2(a) PUHCA 2005 definition of ``affiliate''
rather than the section 2(a) PUHCA 1935 definition of ``affiliate.''
Our Affiliate Transactions Final Rule did not recognize this
conforming amendment. However, the conforming amendment is
ambiguous. There is no section 2(a) in PUHCA 2005 and, inexplicably,
the text of PUHCA 2005 retained only a portion of the full PUHCA
1935 definition of ``affiliate;'' although it retained the PUHCA
1935 threshold of five percent, it dropped much of the statutory
text, thus leaving a potential gap in the scope of entities that
could be considered affiliates. It is unclear whether this was a
drafting oversight, but we do not believe Congress intended to
preclude the Commission, in adopting regulations preventing cross-
subsidization, undue preferences or the exercise of market power
from using an ``affiliate'' definition that provides greater
customer protection with respect to EWG transactions. Our Affiliate
Transactions Final Rule and this rule thus use the 1935 statutory
text framework for EWGs. We adopt the definition of affiliate
promulgated in the Affiliate Transactions Final Rule with a
modification to reflect the approach discussed herein.
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    183. In light of the Commission's goal to have a more consistent
definition of affiliate for purposes of both EWGs and non-EWGs to the
extent possible, as well as to strengthen the Commission's ability to
ensure that customers are protected, we clarify that, for purposes of
Order No. 697, we will define ``affiliate'' as that term is used in the
Affiliate Transactions Final Rule, codified in Sec.  35.43(a)(1) of the
Commission's regulations. Accordingly, as discussed herein, we will
codify the definition of affiliate in our market-based rate regulations
at Sec.  35.36.
b. Definition of Market-Regulated Power Sales Affiliate
Final Rule
    184. The Commission explained in Order No. 697 that the market-
based rate affiliate restrictions codified in Sec.  35.39 govern the
relationship between a franchised public utility with captive customers
and its market-regulated power sales affiliates.\264\ The affiliate
restrictions codified in the regulations include a provision expressly
prohibiting power sales between a franchised public utility with
captive customers and a market-regulated power sales affiliate without
first receiving Commission authorization.\265\ The

Commission defined market-regulated power sales affiliate to mean ``any
power seller affiliate other than a franchised public utility,
including a power seller affiliate, whose power sales are regulated in
whole or in part at market-based rates.'' \266\
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    \264\ Id. at P 549.
    \265\ Id. at P 467.
    \266\ Id. at P 490.
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Requests for Rehearing
    185. Occidental states that, in its current form, Order No. 697
could be interpreted to permit franchised public utilities to require
their captive customers to subsidize their market-based rate
activities, so long as their regulated and market-based rate activities
were combined in a single entity.\267\ To prevent that result,
Occidental requests that the Commission explicitly require that the
functional attributes, rather than the arbitrary structure of a
utility, be considered in determining compliance with the rule's
affiliate abuse provisions.\268\ Occidental states that the Commission
should focus on potential market-based rate seller conduct rather than
on artificial structural distinctions selected by the seller.\269\
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    \267\ Occidental Rehearing Request at 2.
    \268\ Id.
    \269\ Id. at 5.
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    186. Specifically, Occidental argues that, because Order No. 697
focuses solely on conduct between a utility and a legally separate
affiliate, it would allow a utility to benefit its market-based rate
activities at the expense of its captive regulated customers simply by
collapsing its regulated and market-based rates sales activities into a
single entity that, while not technically an affiliate of the utility,
could attempt to engage in the abuses that Order No. 697 seeks to
prevent.\270\ Occidental asserts that the Commission can focus on
potential market-based rate seller conduct, rather than on artificial
structural distinctions selected by the seller, by clarifying that it
will not focus solely on the narrow definitions of franchised public
utility, captive customer, and market-regulated power sales affiliate,
but instead will use a functional test that broadly applies the concept
embodied in the rule to seller conduct.
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    \270\ Id. at 4.
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    187. Occidental states that the Commission should either clarify
that the affiliate abuse requirements of the rule apply equally to
market-regulated functions performed within a franchised public
utility, or revise the definition of market-regulated power sales
affiliate to achieve that same result.\271\ In the alternative,
Occidental states the Commission should grant rehearing and modify
``market-regulated power sales affiliate'' to ``market-regulated power
sales function'' which would necessitate removing the provision stating
that such an entity is not a franchised public utility.\272\
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    \271\ Id. at 8.
    \272\ Id.
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Commission Determination
    188. We deny Occidental's request for rehearing and clarification.
As we explained in Order No. 697, we ``are concerned that there exists
the potential for a franchised public utility with captive customers to
interact with a market-regulated power sales affiliate in ways that
transfer benefits to the affiliates and its stockholders to the
detriment of the captive customers.'' \273\ Accordingly, we have
adopted in our regulations affiliate restrictions intended to guard
against such behavior.
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    \273\ Order No. 697 at P 513.
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    189. If an entity decides to encompass its marketing function
within the franchised public utility's corporate structure, then there
is no longer any affiliate entity to trigger the concerns of affiliate
abuse that the market-based rate affiliate restrictions are designed to
address. For example, one of our primary concerns in adopting affiliate
restrictions is to prevent a franchised utility from making below-
market sales to its merchant affiliate and to prevent the merchant
affiliate from making above-market sales to its franchised utility
affiliate.
    In particular, Occidental's argument rests on the premise that the
franchised public utility that encompasses its marketing function
within the franchised public utility corporate structure could benefit
its market-based rate activities at the expense of its captive
customers. Occidental appears to be suggesting that revenues from the
franchised public utility's off-system sales at market-based rates
would be funneled to the utility's shareholders rather than credited to
the utility's customers. However, such a scenario is at odds with
Commission precedent requiring that off-system sales be reflected
through allocation or revenue credits in the rates of the utility's
customers.\274\
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    \274\ See, e.g., Public Service Co. of New Mexico, Opinion No.
146, 20 FERC ] 61,290 at 61,546-48 (crediting revenue from
intersystem opportunity sales to native load customers), reh'g
denied, 21 FERC ] 61,334 (1982); Golden Spread Electric Cooperative,
Inc., Opinion No. 501, 123 FERC ] 61,047 at P 94-98 (crediting
revenue from intersystem opportunity sales to native load customers)
(2008); Boston Edison Co., Opinion No. 53, 8 FERC ] 61,077 at 61,283
(allocating costs to firm services where the revenue crediting
methodology may result in over-allocation of costs to the customers
whose rates were at issue), reh'g denied, Opinion No. 53-A, 9 FERC ]
61,002 (1979).
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    190. Additionally, state commissions have oversight authority for
franchised public utilities with captive customers that make retail
sales. Therefore, the states should be able to ensure that a franchised
public utility with captive customers does not attempt any ``internal''
cross-subsidization to the detriment of captive customers. Generally,
states similarly require revenue crediting to the utility's retail
customers.
    191. Thus, we will deny Occidental's request for rehearing and
clarification and retain the current requirements for the affiliate
restrictions. We will also retain the current definition of market-
regulated power sales affiliate under Order No. 697.
c. Definition of Captive Customers
Final Rule
    192. As adopted in Order No. 697, 18 CFR 35.36(a)(6) defines
captive customer as ``any wholesale or retail electric energy customers
served under cost-based regulation.'' \275\ The Commission clarified
that the definition of captive customers did not include those
customers who have retail choice, i.e., the ability to select a retail
supplier based on the rates, terms, and conditions of service offered.
Rather, retail customers who have no ability to choose an electric
energy supplier are considered captive because they must purchase from
the local utility pursuant to cost-based rates set by a state or local
regulatory authority; that is, they are served under cost-based
regulation.
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    \275\ Order No. 697 at P 478 (to be codified at 18 CFR
35.36(a)(6)).
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    193. The Commission further explained in Order No. 697 that retail
customers who choose to be served under cost-based rates, even though
they have the ability to choose one retail supplier over another, are
not considered to be under ``cost-based regulation'' and therefore are
not captive under the definition.
    194. While much of the discussion in Order No. 697 focused on
retail customers, the Commission stated ``regarding wholesale
customers, sellers should continue to explain why, if they have
wholesale customers, those customers are not captive.'' \276\
    195. The Commission also declined to include transmission customers
in the definition of captive customers for purposes of market-based