discriminatory.\435\
---------------------------------------------------------------------------

    \435\ Order No. 697 at P 819.
---------------------------------------------------------------------------

Requests for Rehearing
    317. OG&E complains that the Commission erred by barring utilities
from selling power within a balancing authority area in which a seller
is found, or presumed, to have market power where the buyer's load
sinks in a non-mitigated balancing authority area.\436\ OG&E claims
that the Final Rule mistakenly assumes that the point of sale is
relevant to the market power analysis rather than the location of the
load.\437\ OG&E states that the Final Rule acknowledges that buyers
taking title to power ``at a metered boundary for delivery to serve
load in a balancing authority where the seller has market-based rate
authority have competitive choices and therefore are not required to
transact with the seller found to have market power within the
mitigated balancing authority area(s).'' \438\ OG&E suggests that this
reasoning applies with equal force to a transaction where the buyer
chooses to buy power at the seller's generator bus for load that is
located in a balancing authority area where the seller has market-based
rate authority because such a buyer also has competitive choices. OG&E
argues that these choices are not reduced by the location at which
title to the energy is transferred.\439\
---------------------------------------------------------------------------

    \436\ OG&E Rehearing Request at 3.
    \437\ Id. at 4-5.
    \438\ Order No. 697 at P 820.
    \439\ OG&E Rehearing Request at 5.
---------------------------------------------------------------------------

    318. OG&E also claims that the Commission's mitigation policy harms
competition and consumers by undermining the ability of a mitigated
company to compete in other markets within an RTO where that seller
does not have market power.\440\ OG&E asserts that if a power purchaser
located in a non-mitigated market within an RTO already takes network
transmission service under an OATT and that purchaser solicits power
supply bids based on the premise that the purchaser will arrange and
pay for any necessary transmission service, then potential suppliers
not subject to mitigation will bid on a ``power only'' basis. In
contrast, a mitigated supplier's bid would include the cost of
transmission service to take the power to the metered boundary of the
control area where the

seller is mitigated. OG&E complains that in such an instance, the
transmission service is not needed because the purchaser would prefer
to use its existing network service--priced on the basis of load--to
arrange for transmission. OG&E contends that the added transmission
costs imposed on a mitigated supplier in such a scenario would
undermine the competitiveness of a mitigated supplier's bid, thereby
reducing the competitive options available to the purchaser. OG&E
contends that the Commission's policy, because it can result in
additional transmission costs for a mitigated supplier as described
above, imposes a pancaked rate structure on mitigated suppliers, which
undermines an essential benefit associated with RTO participation.
This, OG&E complains, is inconsistent with the Commission's goal of
eliminating pancaked rates by establishing RTOs, and will interfere
with the development and efficiency of competitive wholesale
markets.\441\ OG&E adds that the Final Rule provides no justification
for a policy under which a mitigated supplier may incur the cost of
transmission service to take the power to the metered boundary of the
control area when it seeks to sell power to a potential customer
located in another non-mitigated balancing authority area within an
RTO. These effects are even greater, OG&E asserts, because the
Commission has approved other utilities' mitigation proposals that
allow them to sell power at their generator bus so long as that power
sinks in another balancing authority area. OG&E argues that those
tariffs remain in full force and effect after Order No. 697. Like these
sellers, OG&E should be permitted to compete on an equal basis to serve
customers whose loads sink outside OG&E's mitigated balancing authority
area.\442\
---------------------------------------------------------------------------

    \440\ Id.
    \441\ Id. at 6.
    \442\ Id. at 6-7.
---------------------------------------------------------------------------

    319. OG&E argues that the Final Rule fails to acknowledge that the
Commission's new mitigation policy departs from prior policy.\443\ OG&E
asserts that in several recent cases where sellers failed the market
share screens in their balancing authority area, the Commission imposed
mitigation prohibiting the seller from making sales to ``loads that
sink'' in that balancing authority area.\444\ While the Commission
later rejected this language, OG&E contends that it never has explained
this change in position.\445\ When the Commission departs from
established policy without explanation, as OG&E claims it did here, it
acts arbitrarily and fails to engage in the reasoned decision making
required by the law.\446\
---------------------------------------------------------------------------

    \443\ Id. at 7.
    \444\ Id. at 2 (citing Duke Power, 113 FERC ] 61,192 (2005); AEP
Power Marketing, Inc., 114 FERC ] 61,025 (2006); LG&E Energy
Marketing Inc., 113 FERC ] 61,229 (2005); South Carolina Electric
and Gas Co., 114 FERC ] 61,143 (2006); Florida Power Corp., 113 FERC
] 61,131 (2005)).
    \445\ Id. (citing Order No. 697 at P 794; MidAmerican Energy
Co., 114 FERC ] 61,280 (2006); Carolina Power & Light Co., 114 FERC
] 61,294 (2006); Aquila, Inc., 114 FERC ] 61,281 (2006)).
    \446\ Id. at 8.
---------------------------------------------------------------------------

Commission Determination
    320. OG&E complains that the Commission erred by barring utilities
from selling power within a balancing authority area in which a seller
is found, or presumed, to have market power when the buyer's load sinks
in a non-mitigated balancing authority area. As noted in the Final
Rule, another commenter similarly asserted that any buyer purchasing
power at a generator bus or elsewhere in a balancing authority area in
which a seller is found, or presumed, to have market power for purposes
of moving that power beyond that mitigated balancing authority area
should be treated no differently than a buyer who takes delivery of
purchased power outside of that balancing authority area. OG&E, like
earlier commenters advocating this approach, has failed to adequately
address how the Commission could effectively monitor such sales to
ensure that improper sales are not being made in the balancing
authority area in which a seller is found, or presumed, to have market
power. As the Commission stated in the Final Rule, several commenters
noted the complex administrative problems that would be associated with
trying to monitor compliance with such a policy.\447\
---------------------------------------------------------------------------

    \447\ Order No. 697 at P 818.
---------------------------------------------------------------------------

    321. Moreover, as the Commission explained in the Final Rule,
allowing market-based rate sales by a seller found to have market
power, or has so conceded, in the very balancing authority area in
which market power is a concern is inconsistent with the Commission's
responsibility under the FPA to ensure that rates are just and
reasonable and not unduly discriminatory. While we generally agree that
it is desirable to allow market-based rate sales into balancing
authority areas where the seller has not been found to have market
power, a mitigated seller cannot make market-based rate sales anywhere
within a balancing authority area in which a seller is found, or
presumed, to have market power. It is unrealistic to believe that sales
made anywhere in a balancing authority area can be traced to ensure
that no improper sales are taking place. In contrast, sales made at the
metered boundary for export do more readily lend themselves to being
monitored for compliance, and the nature of these types of sales do not
unduly disadvantage customers or competitors. Prohibiting market-based
rate sales at the metered boundaries of a balancing authority area in
which a seller is found, or presumed, to have market power could
prevent or adversely impact cross border sales at these unique
locations and reduce market liquidity unnecessarily in markets where
the seller does not possess market power.
    322. OG&E also claims that not allowing sales at the generator bus
undermines the ability of a mitigated company to compete in other
markets within an RTO where that seller does not have market power. For
example, if a mitigated seller attempts to transact with a purchaser
willing to use the purchaser's existing network transmission service,
OG&E asserts that a mitigated seller's ability to compete is
undermined. OG&E claims that because a mitigated seller must incur
transmission costs to deliver the power in the above scenario to the
metered boundary rather than simply to a generator bus in the balancing
authority area in which a seller is found, or presumed, to have market
power, the mitigated seller would be unable to bid on a ``power only''
basis and would be forced to pay an additional transmission cost that
is redundant due to the purchaser's ability to use its network service
if the mitigated seller could sell at the generator bus. This, OG&E
suggests, not only undermines that mitigated seller's ability to
compete beyond the mitigated balancing authority area, but also would
reduce the competitive options available to the buyer.
    323. OG&E's concern regarding mitigation undermining a seller's
ability to compete fails to appreciate that mitigated sellers are
prohibited from making sales at a generator bus in that particular
balancing authority area because they have been shown to have, or
conceded, market power in that market area. Mitigated sellers lose the
privilege of market-based rate sales at generator bus locations within
a balancing authority area in which a seller is found, or presumed, to
have market power. Unlike sales at the generator bus bar, sales made at
the metered boundary for export do lend themselves to being monitored
for compliance, and these sales do not

unduly disadvantage customers or competitors.
    324. OG&E also claims that its ability to compete is undermined
because the Commission approved several tariffs that permit a mitigated
entity to sell power at their generator bus so long as that power sinks
beyond the balancing authority area in which a seller is found, or
presumed, to have market power. However, a recent Commission order
explained that such tariffs are inconsistent with the Commission's
policy as set forth in Order No. 697, as of the effective date of Order
No. 697 (September 18, 2007).\448\ In that order, the Commission
explained that its acceptance of a mitigation proposal and tariff
provisions that focused on sales that did not sink within the balancing
authority area in which the seller was found, or presumed, to have
market power was inconsistent with the April 14 and July 8 Orders and,
therefore, in error.\449\ Moreover, the Commission's recent order
clarifying the Final Rule explained that sales made after September 18,
2007 must be in compliance with the requirements of Order No. 697.\450\
Because a mitigated entity is precluded from limiting its mitigation to
sales that sink in the balancing authority area in which it is found,
or presumed to have, market power, all mitigated sellers are now on the
same footing with regard to their ability to serve customers whose
loads sink outside mitigated balancing authority areas.
---------------------------------------------------------------------------

    \448\ See South Carolina Electric and Gas Company, 121 FERC ]
61,263 at P 12 (2007).
    \449\ Id.
    \450\ Clarification Order, 121 FERC ] 61,260 at P 4-8.
---------------------------------------------------------------------------

d. Tariff Language
Final Rule
    325. In the Final Rule, the Commission adopted a requirement that
mitigated sellers wishing to make market-based rate sales at the
metered boundary between a balancing authority area in which the seller
was found, or presumed, to have market power and a balancing authority
area in which the seller has market-based rate authority maintain
sufficient documentation and use a specific tariff provision for such
sales.\451\ In particular, the Final Rule requires that mitigated
sellers that want to make market-based rate sales at the metered
boundary adopt the following tariff provision:
---------------------------------------------------------------------------

    \451\ Order No. 697 at P 830.

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

Requests for Rehearing
    326. Pinnacle requests clarification of the provision's requirement
that ``any power sold is not intended to serve load in the seller's
mitigated market.'' As written, Pinnacle argues that this requirement
could limit liquidity, particularly for term sales transactions, in the
market trading hubs.\452\ For example, Pinnacle states that it
transacts at several liquid points in the Western markets such as Four
Corners, which is at the border of the APS balancing authority area.
Pinnacle explains that although it can assess its intent for the
destination of power purchased at the border point, it does not have
control over the intent of third parties purchasing the power. Further,
Pinnacle asserts that it is unlikely that counterparties at liquid
market hubs would agree to contractual limitations on where power can
sink for term transactions.\453\ Pinnacle adds that the Commission has
not placed any limits on the time at which intent is determined. For
example, if a buyer intends to sink the power outside of the market in
which the seller has or is presumed to have market power at the time of
purchase, but at the time of delivery determines that it must liquidate
its positions and sell power back into that market, the Final Rule is
unclear whether the mitigated seller may be liable for this sale into
the market in which it has market power. Pinnacle argues that without
the clarification on intent, mitigated sellers may be limited to cost-
based sales at the border. Pinnacle requests the Commission clarify
that intent is only directed at the determination of the mitigated
seller.
---------------------------------------------------------------------------

    \452\ Pinnacle Rehearing Request at 4. Although Pinnacle does
not provide a definition for ``term sale,'' we understand their use
of that phrase to refer to a sale that is neither executed nor
tagged immediately, and whose sink location is unknown at the time
of the sale.
    \453\ Id. at 5.
---------------------------------------------------------------------------

    327. If the Commission does not so clarify, Pinnacle requests on
rehearing that the Commission revise the second requirement in the
tariff provision to state: ``(ii) the seller does not intend for any
power sold to serve load in the seller's mitigated market.'' Pinnacle
claims that this revision will provide greater regulatory certainty.
    328. Morgan Stanley similarly is unclear on how the Commission will
ensure that a mitigated seller knows what an unaffiliated buyer intends
to do with power. It adds that a restriction forbidding unaffiliated
buyers from purchasing power at the metered boundary from a mitigated
seller and then selling the same power back into a balancing authority
area in which the seller was found, or presumed, to have market power
would be burdensome because every sale would have to be tracked.\454\
Morgan Stanley therefore requests the Commission to clarify that buyers
unaffiliated with a mitigated seller may purchase power at the metered
boundary to sell to customers that serve load in the mitigated seller's
balancing authority area. It argues that if restrictions are imposed on
unaffiliated buyers' purchases at the metered boundary, the Commission
should explain or, in the alternative, grant rehearing.\455\
---------------------------------------------------------------------------

    \454\ Morgan Stanley Rehearing Request at 3.
    \455\ Id. at 2-3.
---------------------------------------------------------------------------

    329. Pinnacle is further concerned about the metered boundary
tariff provision's requirement that mitigated sellers commit to and
demonstrate that ``no affiliate of the mitigated seller will sell the
same power back into the mitigated seller's mitigated market.''
Pinnacle submits that it might generally have immediate documentation
to meet the above requirement for real-time transactions because the
NERC tag (that notes the sink point for the power) will be made upon
the execution of a real-time transaction. However, in the context of a
term sale, Pinnacle explains that NERC tags are generally created not
at the time of the transaction, but rather the last scheduling day
prior to the start of the sale. The result, Pinnacle submits, is that
no immediate documentation is created to show that the mitigated seller
intended to sink the sale outside of the mitigated market where a term
sale followed by a ``coincidental sale'' \456\ that results in power
returning to the

balancing authority area in which the seller has been found, or
presumed, to have market power. Pinnacle therefore seeks clarification,
or in the alternative rehearing, on whether the requirement that a
mitigated seller commit to and demonstrate that ``no affiliate of the
mitigated seller will sell the same power back into the mitigated
seller's mitigated market'' applies in the following scenario: A
mitigated seller sells a term product to an unaffiliated counterparty
at the metered boundary for delivery sometime in the future.
Thereafter, an affiliated seller purchases the power in a coincidental
sale and, despite any lack of arrangement, the affiliate of the
mitigated seller then re-sells that power to the balancing authority
area in which the mitigated seller has been found, or presumed, to have
market power.\457\ If the unaffiliated counterparty does not advise the
affiliate of the mitigated seller that the unaffiliated counterparty is
selling to the affiliate of the mitigated seller the same power that
the unaffiliated counterparty originally purchased from the mitigated
seller, Pinnacle claims that it will only become apparent that the
mitigated seller is sourcing the transaction between the unaffiliated
counterparty and the affiliate of the mitigated seller when the NERC
tags are prepared.\458\
---------------------------------------------------------------------------

    \456\ Pinnacle describes a ``coincidental sale'' as the
situation where, after a mitigated seller makes a term sale to an
unaffiliated counter-party at the metered boundary, an affiliate of
the mitigated seller enters into an unrelated transaction to buy
that same power from the unaffiliated counterparty.
    \457\ Pinnacle Rehearing Request at 7-8.
    \458\ Id.
---------------------------------------------------------------------------

    330. Pinnacle also seeks clarification, or in the alternative
rehearing, as to the types of documentation that the Commission
requires to show the intent of the seller, and particularly whether the
Commission would consider audio tapes of transactions to be sufficient.
Pinnacle states that, generally, representative documentation for real-
time trading is created. For a term sale, however, a representative tag
is not created at the time of the transaction but rather around the
last scheduling prior to the start of the sale. Therefore, when a term
sale is involved, no immediate tag at the time of contracting is
created that can be evidenced as intent to sink the sale outside of the
market in which the seller has market power.
    331. Pinnacle also requests clarification that the physical point
of the metered boundary is the mitigated seller's side of the
electrical boundary, and does not include points at the border that are
in an adjacent balancing authority area.\459\ If the Commission does
not provide the requested clarification, Pinnacle requests rehearing of
this requirement. Pinnacle argues that, as currently written, the
tariff language on metered boundaries does not provide the regulatory
certainty necessary to accurately implement the requirements.\460\
---------------------------------------------------------------------------

    \459\ Pinnacle Rehearing Request at 8.
    \460\ Id. at 8-9.
---------------------------------------------------------------------------

    332. OG&E complains that the Final Rule's new mitigation policy is
improperly based on the assumption that utilities will violate their
tariffs despite the fact that such a purposeful circumvention of a
company's mitigation tariff would subject the violator to the risk of
substantial civil penalties. Moreover, OG&E adds that such conduct also
could violate the Commission's Market Manipulation Rule.\461\ OG&E
points out that, in the Final Rule, the Commission rejected fears of
gaming because such conduct would violate its existing rules.\462\ OG&E
asserts that the same logic applies to the Commission's concerns that a
seller might violate its market-based rate tariff to purposefully make
sales to a customer whose load sinks in the balancing authority area in
which that seller was found, or presumed, to have market power. OG&E
argues that, where a particular set of actions already are prohibited
by the Commission's rules, the Commission cannot impose new
requirements unless it first finds that the existing rules are
ineffective.\463\
---------------------------------------------------------------------------

    \461\ OG&E Rehearing Request at 9.
    \462\ Id. at 10.
    \463\ Id.
---------------------------------------------------------------------------

Commission Determination
    333. As an initial matter, we will revise the tariff language
governing market-based sales at the metered boundary to conform with
the discussion in the Clarification Order regarding use of the term
``mitigated market.'' As we explained in the Clarification Order, we
believe that ``balancing authority area in which a seller is found, or
presumed, to have market power'' is a more accurate way to describe the
area in which a seller is mitigated.
    334. After considering comments raised regarding the difficulty of
determining and documenting intent, we have decided to eliminate the
intent element of the tariff provision, which states that ``any power
sold hereunder is not intended to serve load in the seller's mitigated
market.'' As we are eliminating the seller's intent requirement, we
will modify the other tariff provision to require that ``the mitigated
seller and its affiliates do not sell the same power back into the
balancing authority area where the seller is mitigated.'' \464\ Because
we are eliminating the intent requirement, we need not address issues
raised regarding documentation necessary to demonstrate the mitigated
seller's intent.
---------------------------------------------------------------------------

    \464\ To provide additional regulatory certainty for mitigated
sellers, we clarify that once the power has been sold at the metered
boundary at market-based rates, the mitigated seller and its
affiliates may not sell that same power back into the mitigated
balancing authority area, whether at cost-based or market-based
rates.
---------------------------------------------------------------------------

    335. Pinnacle also asks whether a mitigated seller would be liable
if an affiliate purchases power from an unaffiliated intermediate
party, then arranges to re-sell that power back into the mitigated
seller's balancing authority area, and it is subsequently discovered,
when the NERC tags are prepared, that the mitigated seller was the
initial source of that power via a term sale with the unaffiliated
intermediate party. Under these circumstances, the mitigated seller
would have violated its market-based rate tariff. Whether or not
prearranged by affiliates, a series of transactions involving what
Pinnacle describes as a ``coincidental sale'' that may result in an
affiliate re-selling power back into the balancing authority area in
which the seller has been found, or presumed, to have market power are
prohibited by Order No. 697. This is because mitigated sellers and
their affiliates are prohibited from selling power at market-based
rates in the balancing authority area in which a seller is found, or
presumed, to have market power. Accordingly, an affiliate of a
mitigated seller is prohibited from selling power that was purchased at
a market-based rate at the metered boundary back into the balancing
authority area in which the seller has been found, or presumed, to have
market power.
    336. To the extent that the mitigated seller or its affiliates
believe that it is not practical to track such power, they can either
choose to make no market-based rate sales at the metered boundary or
limit such sales to sales to end users of the power, thereby
eliminating the danger that they will violate their tariff by re-
selling the power back into a balancing authority in which they are
mitigated.
    337. We also clarify that when using the term ``metered boundary,''
the Commission intends that applicable mitigation applies to sales made
at the metered boundary regardless of at which ``side'' of the border
the sale takes place. We adopt this approach as a concession to
mitigated sellers that wish to make sales that may technically take
place in a balancing authority area where they do not have market-based
rate authority. However, in adopting this approach we do not intend to
do so with such precision that we are drawn

into evidentiary hearings on this matter, which could result in long
drawn out contractual disputes to determine the precise spot at which
the sale took place. We further deny Pinnacle's request for rehearing
to seek a precise definition of ``metered boundary'' because we
believe, with the clarification provided herein, the existing tariff
language on metered boundaries does provide the regulatory certainty
necessary to accurately implement Order No. 697's requirements.
    338. We disagree with OG&E's contention that our policy is based on
the assumption that utilities will purposely violate their tariffs. We
make no such assumption; however, it would not be sensible for us to
establish conditions that we are unable to monitor for compliance.
Sales at the metered boundary are unique physical locations that lie on
the borders of balancing authority areas, and we believe that we can
monitor compliance for sales at the metered boundary more effectively
than sales made anywhere within the balancing authority area. As
explained above, such limitation is justified by the Commission's need
to monitor compliance with its conditions on sales within the balancing
authority area in which the seller is mitigated.
    339. Consistent with the preceding discussion, we will revise the
tariff provision for market-based rate sales at the metered boundary as
follows (bold font indicates new text):

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

    340. Any sellers that have already adopted the tariff language
prescribed in Order No. 697 are directed to revise the provision in
accordance with this discussion on the next occasion when they
otherwise would be required to file revised tariff sheets with the
Commission, a change in status filing, or triennial review.
E. Implementation Process
Final Rule
    341. In Order No. 697, the Commission created a category of market-
based rate sellers (Category 1 sellers) that are exempt from the
requirement to automatically submit updated market power analyses.
These Category 1 sellers include ``wholesale power marketers and
wholesale power producers that own or control 500 MW or less of
generation in aggregate per region; that do not own, operate or control
transmission facilities other than limited equipment necessary to
connect individual generating facilities to the transmission grid (or
have been granted waiver of the requirements of Order No. 888); that
are not affiliated with anyone that owns, operates or controls
transmission facilities in the same region as the seller's generation
assets; that are not affiliated with a franchised public utility in the
same region as the seller's generation assets; that are not affiliated
with a franchised public utility in the same region as the seller's
generation assets; and that do not raise other vertical market power
issues.'' \465\ Market power concerns for Category 1 sellers will be
monitored through the change in status reporting requirement \466\ and
through ongoing monitoring by the Commission's Office of Enforcement.
Category 2 sellers (all sellers that do not qualify for Category 1)
will be required to file regularly scheduled updated market power
analyses in addition to change in status reports.
---------------------------------------------------------------------------

    \465\ 18 CFR 35.36(a)(2) (citations omitted).
    \466\ See 18 CFR 35.42.
---------------------------------------------------------------------------

    342. In addition, to ensure greater consistency in the data used to
evaluate Category 2 sellers, the Commission modified the timing for the
submission of updated market power analyses.\467\ Order No. 697
requires analyses to be filed for each seller's region on a pre-
determined schedule, rotating by geographic region where two regions
are reviewed each year, with the cycle repeating every three
years.\468\ This process allows evaluation of each individual seller's
market power at the same time that other sellers in the same region are
examined. For corporate families that own or control generation in
multiple regions, the corporate family will be required to file an
update for each region in which members of the corporate family sell
power during the time period specified for that region.
---------------------------------------------------------------------------

    \467\ Previously, updated market power analyses were submitted
within three years of any order granting a seller market-based rate
authority, and every three years thereafter.
    \468\ See Order No. 697 at Appendix D. The regions include the
Northeast, Southeast, Central, Southwest Power Pool, Southwest, and
Northwest.
---------------------------------------------------------------------------

1. Category 1 and 2 Sellers
a. Establishment of Category 1 and 2 Sellers
Requests for Rehearing
    343. On rehearing, NASUCA argues that the exemption from market
power review for Category 1 sellers lacks factual and legal
justification. NASUCA contends that this exemption is inconsistent with
the justifications the Commission has previously given to the courts.
In particular, NASUCA argues that it is inconsistent with the
Commission's arguments before the court that it carefully assesses the
market power of any entity allowed to sell at market-based rates.\469\
---------------------------------------------------------------------------

    \469\ NASUCA Rehearing Request at 12-13.
---------------------------------------------------------------------------

    344. NASUCA contends that in Lockyer v. FERC, 383 F.3d 1006 (9th
Cir. 2004) (Lockyer), the Ninth Circuit mistakenly believed that the
market power assessment under current Commission orders is made
triannually (i.e., once every four months) when it is only required
triennially (once every three years).\470\ NASUCA believes that,
because the Final Rule would completely eliminate the triennial review
for many sellers in Category 1, the basis for the decision in Lockyer,
to the extent it is based on the Court's belief that the Commission
reviews the market power of all sellers four times a year, is
undermined. NASUCA concludes that the blanket exemption from market
power review of all sellers owning or controlling less than 500 MW
capacity is inconsistent with the Commission's stated rationale for
allowing a market-based rate system.
---------------------------------------------------------------------------

    \470\ Id. at 13.
---------------------------------------------------------------------------

    345. NASUCA also argues that the Commission has reversed the burden
previously placed on applicants for the ``privilege'' of having market-
based rates.\471\ NASUCA notes that the Final Rule states, `` `[w]hile
it is true that a portion of these sellers will continue to sell at
market-based rates for a time until their updated market power analyses
(in the case of Category 2 sellers) or their filings addressing
qualification as Category 1 sellers are due, no commenter has submitted
compelling evidence that Category 1 sellers have unmitigated market
power.' '' \472\ NASUCA contends that Order No. 697 essentially granted
all

Category 1 sellers market-based rates without their submitting an
application demonstrating a lack of market power, and required
objectors to submit ``compelling evidence'' in a non-evidentiary
proceeding.
---------------------------------------------------------------------------

    \471\ Id. at 13-14 (citing Schaffer v. Weast, 546 U.S. 49
(2005); Lavine v. Milne, 424 U.S. 577, 585 (1976)).
    \472\ Id. (quoting Order No. 697 at P 334) (emphasis added by
NASUCA).
---------------------------------------------------------------------------

    346. NASUCA argues that the Commission cannot presume that the
market price demanded by all Category 1 sellers will be a
``competitive'' price or a just and reasonable rate.\473\ NASUCA states
that the Supreme Court ``rejected any conflation of `competitive'
market price with the `just and reasonable' rate required by statute.''
\474\ NASUCA contends that for Category 1 sellers, which it asserts are
now exempt from any market power test, ``the `prevailing price in the
marketplace' is indeed the `final' measure of the rates being demanded,
changed and charged,'' a result contrary to the intent of
Congress.\475\
---------------------------------------------------------------------------

    \473\ Id. at 14.
    \474\ Id. (citing FPC v. Texaco, 417 U.S. at 397).
    \475\ Id. at 15 (quoting FPC v. Texaco, 417 U.S. at 397).
---------------------------------------------------------------------------

    347. NASUCA also argues that there is no basis in the record of
this proceeding to assume that power marketers or producers who own or
control less than 500 MW of generation lack market power at all
times.\476\ NASUCA notes that in load pockets or other transmission-
constrained areas, sellers with less than 500 MW of capacity could
exercise market power, either alone or acting strategically without
overt collusion to inflate rates when supply margins are tight. NASUCA
states that changing circumstances also may affect the opportunity of
seemingly small sellers to exercise market power.
---------------------------------------------------------------------------

    \476\ Id.
---------------------------------------------------------------------------

    348. Additionally, NASUCA argues that, because the definition of
seller includes not only owners of generating plants but also power
marketers, this loophole might encourage power marketers to control
segments of power plants up to 499.9 MW and through strategic bidding
and other methods exercise subtle market power in certain locations at
certain times.\477\ NASUCA states that, as a result of this exemption,
sales from these facilities will be at prices solely determined by
market forces, in contravention of FPC v. Texaco. NASUCA therefore
concludes that if the Commission desires to identify a threshold below
which a seller cannot exercise market power, it should commence a new
proceeding, conduct technical workshops, gather evidence from the
public and from RTO market monitors, and receive comments before
adopting an evidence-based standard.
---------------------------------------------------------------------------

    \477\ Id. at 16.
---------------------------------------------------------------------------

Commission Determination
    349. NASUCA's argument on rehearing that the Commission did not
adequately justify its decision to exempt Category 1 sellers from
filing regularly scheduled updated market power analyses is misplaced.
As we reiterate below, we thoroughly discussed the basis of our
decision in Order No. 697, including that exempting Category 1 sellers
is fully consistent with our statutory mandate to ensure just and
reasonable rates and with the court decisions that have construed that
obligation.\478\ Moreover, as discussed below, in a number of instances
NASUCA does not accurately describe the exemption or our justification
for it.
---------------------------------------------------------------------------

    \478\ Order No. 697 at P 848.
---------------------------------------------------------------------------

    350. With regard to NASUCA's argument that exempting sellers from
market power reviews undermines the court's decision in Lockyer, we
note that the Commission addressed this concern in Order No. 697.
Specifically, the Commission stated that ``the reporting requirement
relied upon by the court in Lockyer is the transaction-specific data
found in EQRs, which we continue to require of all sellers, and not the
updated market power analyses. Thus, exempting Category 1 sellers from
routinely filing updated market power analyses does not run counter to
Lockyer.'' \479\ The court in Lockyer emphasized that the Commission
``has broad discretion to establish effective reporting requirements''
for administering tariffs, and that the FPA ``explicitly leaves the
timing and form'' of rate filings to the Commission's discretion.\480\
---------------------------------------------------------------------------

    \479\ Id. P 854.
    \480\ Lockyer, 383 F.3d 1006, 1013.
---------------------------------------------------------------------------

    351. In any case, NASUCA fails to recognize that the Commission has
not exempted Category 1 sellers from initial market power reviews. In
addition, the Commission left in place the change in status reporting
requirements that allow the Commission to review market power of
sellers on an ongoing basis. Thus, we reject NASUCA's contention that
this exemption is inconsistent with the justifications the Commission
has previously given to the courts.
    352. We also reject NASUCA's contention that the Commission has
reversed the burden previously placed on applicants for the
``privilege'' of having market-based rates by not requiring Category 1
sellers to file regularly scheduled updated market power analyses. As
an initial matter, NASUCA argues incorrectly that Order No. 697
``essentially granted all Category 1 sellers market[-based] rates
without their applying and demonstrating a lack of market power, and
required objectors to submit `compelling evidence' in a non-evidentiary
proceeding.'' \481\ Order No. 697 did not grant Category 1 sellers
market-based rate authority without requiring the submission of an
application demonstrating a lack of market power. To the contrary, all
sellers seeking market-based rate authorization (including sellers that
qualify as Category 1 sellers) must initially demonstrate either a lack
of market power or that any market power is adequately mitigated in
order to obtain Commission market-based rate authorization.\482\ All
such proceedings are noticed and allow for public comment. Any party to
the proceeding has an opportunity during these proceedings to argue
that a seller has market power.\483\ Although Category 1 sellers are
not required to file regularly scheduled updated market power analyses,
they retain the initial burden of proof to demonstrate that they do not
have or have adequately mitigated market power in the first instance.
In addition, Category 1 sellers continue to have the burden of
informing the Commission of any change in the circumstances that the
Commission relied on in granting them market-based rate authority.
---------------------------------------------------------------------------

    \481\ NASUCA Rehearing Request at 14.
    \482\ A seller who previously was not required to demonstrate a
lack of horizontal market power based on the exemption contained in
18 CFR 35.27(a) and that believes it qualifies as a Category 1
seller, will be required to provide support for its claim to
Category 1 status. This filing will give the Commission and
interested parties an opportunity to review and, if appropriate,
challenge a seller's claim that it qualifies as a Category 1 seller.
To the extent that an intervenor has concerns about a seller's
potential to exercise market power, the Commission will entertain
them at that time. Order No. 697 at P 333.
    \483\ Additionally, if a seller's circumstances change from
those which the Commission reviewed and made a determination upon,
it is required to inform the Commission in a change in status
filing.
---------------------------------------------------------------------------

    353. Further, NASUCA takes the Commission's statement regarding the
submission of compelling evidence out of context. The passage that
NASUCA quotes from the Final Rule (Order No. 697 at P 334) discusses
the elimination of the exemption for new generation (formerly Sec.
35.27(a) of the Commission's regulations), and the lack of compelling
evidence that the Commission referenced there related to commenters'
unpersuasive reasons for retaining the Sec.  35.27(a) exemption.\484\
The

Commission discussed the establishment of Category 1 and 2 sellers in a
separate part of the Final Rule (Order No. 697 at P 848-62); the
Commission nowhere intimated that Category 1 sellers need not
demonstrate that they lack market power. Accordingly, NASUCA's
contention is rejected in this regard.
---------------------------------------------------------------------------

    \484\ The Commission was responding to NASUCA's concern that
sellers that initially received market-based rate authority without
any generation market power assessment pursuant to 18 CFR 35.27(a)
would, as Category 1 sellers, be exempted from filing update market
power analyses. The Commission explained that it would rely on
additional procedures, namely the change in status filing
requirements (triggered by the acquisition of additional
generation), EQR transaction filings, and the Commission's ability
to require an updated market power analysis from any seller at any
time, to address NASUCA's concern.
---------------------------------------------------------------------------

    354. With respect to NASUCA's assertion that there is no basis in
the record to assume that power marketers or producers who own or
control less than 500 MW of generation lack market power at all times,
in Order No. 697 the Commission fully explained the rationale
underlying the adoption of Category 1, as well as the rationale for
adopting 500 MW or less of generating capacity per region as the
cutoff. The Commission explained that Category 1 sellers have been
carefully defined to have attributes that are not likely to present
market power concerns: Ownership or control of relatively small amounts
of generation capacity; no affiliation with an entity with a franchised
service territory in the same region as the seller's generation
facility; little or no ownership or control of transmission facilities
and no affiliation with an entity that owns or controls transmission in
the same region as the seller's generation facility; and no indication
of an ability to exercise vertical market power. The Commission further
explained that, based on a review of past Commission orders, it is
aware of no entity that would have qualified as a Category 1 seller but
would nevertheless have failed the indicative screens, necessitating a
more thorough analysis.\485\ Furthermore, we believe that we have
maintained an ample degree of monitoring and oversight to detect
sellers that are not required to file regularly scheduled market power
updates but nevertheless obtain enough additional generation as to
raise market power concerns. This is so because we require all sellers
seeking market-based rate authority to conduct a market power analysis
and, once market-based rate authority is obtained, to submit change in
status filings when the circumstances on which the Commission has
granted market-based rate authority have changed. In these filings,
such sellers must report on what effect, if any, the additional
generation has on their market power. In addition, the Commission
reserves the right to require an updated market power analysis from any
market-based rate seller at any time.\486\ Finally, all sellers with
market-based rates, whether Category 1 or Category 2 sellers, must file
electronically with the Commission an EQR of transactions no later than
30 days after the end of each reporting quarter.
---------------------------------------------------------------------------

    \485\ See Order No. 697 at P 864.
    \486\ Id. P 853.
---------------------------------------------------------------------------

    355. Nevertheless, in light of concerns raised regarding the
potential for Category 1 sellers to exercise market power in load
pockets or other transmission-constrained areas, we will modify our
approach when analyzing the indicative screens (e.g., as a result of
regularly scheduled updated market power analyses). Specifically, to
the extent that a Commission-identified submarket is under analysis, we
will consider whether there is an indication that any sellers in that
submarket, including Category 1 sellers, have market power. While we
will not routinely require Category 1 sellers with generation assets in
a submarket to submit a regularly scheduled updated market power
analysis, when evaluating the market power analyses of Category 2
sellers, we will conduct our own analysis, based on publicly available
information, of whether there are any market power concerns related to
any Category 1 seller in a submarket. If, based on our analysis, we
determine that there may be potential market power concerns with
respect to any Category 1 sellers in a submarket, we will, if
appropriate, require an updated market power analysis to be filed by
such sellers. We will also notice such filings for public comment, thus
allowing parties to raise concerns regarding market power for
Commission consideration.
    356. Regarding concerns about the specific threshold chosen, when
the Commission proposed in the NOPR the establishment of Category 1 and
Category 2 sellers, the Commission proposed to define Category 1
sellers as power marketers and power producers that own or control 500
MW or less of generation capacity in aggregate, among other
requirements. The Commission received a variety of comments concerning
the proposed threshold. After careful review of these comments, the
Commission concluded that 500 MW or less of generation capacity per
region is an appropriate threshold. The Commission explained in Order
No. 697 that the 500 MW threshold would be used as a cutoff because,
during the Commission's 15 years of experience administering the
market-based rate program, there had only rarely been allegations that
sellers with capacity of 500 MW or less (in any geographic region) had
market power. The Commission noted that when those claims have been
raised, the Commission's review either found no evidence of market
power or found that the market power identified was adequately
mitigated by Commission-enforced market power mitigation. The
Commission explained that, while some commenters urged it to adopt
either a higher or lower threshold, the Commission believes that a 500
MW threshold is both a reasonable balance as well as conservative
enough to ensure that those unlikely to possess market power will be
granted market-based rate authority. Moreover, 500 MW is a clear,
bright line that will be easy to administer. On this basis, we reject
NASUCA's suggestion that the Commission should commence a new
proceeding, conduct technical workshops, gather evidence from the
public and from RTO market monitors, and receive comments to further
address the appropriate threshold.
b. Threshold for Category 1 Sellers
Requests for Rehearing
    357. On rehearing, PPM contends that Order No. 697 does not provide
any explanation as to why Category 1 membership is based on the
ownership or control of generation in a ``region,'' as opposed to in
the geographic area used to measure market power.\487\ PPM submits that
the appropriate geographic area for measuring ownership or control of
electric generation for purposes of identifying Category 1 sellers is
the same area used to assess market power: The balancing authority area
or, for RTOs and ISOs, the relevant RTO/ISO market or submarket. PPM
submits that the use of regions for determining Category 1 membership
would result in a seller owning or controlling 500 MW of generating
capacity located entirely in one balancing authority area being
considered to have less chance of possessing market power than a seller
owning or controlling 300 MW of generating capacity each in two
separate balancing authority areas separated by hundreds of miles but
located in the same region pursuant to the map provided in Appendix D
to the Final Rule. PPM contends that there is neither evidence nor a
rational basis for concluding that the seller in the second

example should be included in Category 2 and the seller in the first
example should be included in Category 1. Thus, PPM concludes that the
Commission's basis for distinguishing between Category 1 and Category 2
sellers is arbitrary and capricious.
---------------------------------------------------------------------------

    \487\ PPM Rehearing Request at 2-3.
---------------------------------------------------------------------------

    358. PPM also asserts that the Commission should treat ownership or
control of intermittent generating capacity differently from thermal
generating capacity for the purposes of establishing whether a seller
falls within Category 1 or Category 2. PPM claims that it is extremely
unlikely that any public utility will attain market power as a result
of its ownership or control of wind generation capacity due to the
intermittent nature of such capacity.\488\ Thus, it argues that the
Commission should adopt a less stringent limitation for purposes of
establishing Category 1 status for sellers of power from intermittent
generating capacity. PPM notes that the Commission rejected this
suggestion from commenters, stating ``[w]e believe that many sellers
with wind and other non-thermal capacity will fall below the 500 MW
threshold; those that do not may take advantage of simplifying
assumptions and other means to minimize the burden of filing an updated
market power analysis.'' \489\ However, PPM asserts that, other than
gas, wind power is the fastest growing source of electric generating
capacity.\490\ According to PPM, several wind power developers already
own or control more than 500 MW of intermittent generation capacity in
a region, as designated by Appendix D, and several more are likely to
attain this status before long. PPM contends that, as the United States
seeks to promote investment in electric generation technologies that
enhance national energy security and do not emit greenhouse gases, it
would be unwise to impose a burden on wind power generators that will
not enhance the competitiveness of wholesale electric markets.
---------------------------------------------------------------------------

    \488\ Id. at 4.
    \489\ Id. (citing Order No. 697 at P 867).
    \490\ Id. (citing Florence, Joseph, Global Wind Power Expands in
2006, ``Wind is the world's fastest-growing energy source with an
average annual growth rate of 29 percent over the last ten years. In
contrast, over the same time period, coal use has grown by 2.5
percent per year, nuclear power by 1.8 percent, natural gas by 2.5
percent, and oil by 1.7 percent.'' June 28, 2006 http://www.earth-
policy.org/Indicators/Wind/2006.htm).
---------------------------------------------------------------------------

Commission Determination
    359. With regard to PPM's argument that the use of regions for
determining Category 1 membership would result in a seller owning or
controlling 500 MW of generating capacity located entirely in one
balancing authority area being considered to have less chance of
possessing market power than a seller owning or controlling 300 MW of
generating capacity each in two separate balancing authority areas
separated by hundreds of miles but located in the same region pursuant
to the map provided in Appendix D to the Final Rule, we find that PPM
misses the point. The Commission's creation of a category of sellers
(Category 1 sellers) that are not required to submit regularly
scheduled updated market power analyses is based in part on recognizing
the administrative burden imposed on smaller sellers that are unlikely
to possess market power. In doing so, the Commission intends to remain
conservative in its approach to identifying such sellers. While PPM's
argument may make sense from a strictly analytical viewpoint, it also
greatly increases the universe of sellers that would not be required to
submit regularly scheduled updated market power analyses. We are not
willing to do so.
    360. The Commission explained in Order No. 697 that, ``[i]n keeping
with our conservative approach with regard to which entities qualify
for Category 1, we find that aggregate capacity in a given region best
meets our goal of ensuring that we do not create regulatory barriers to
small sellers seeking to compete in the market while maintaining an
ample degree of monitoring and oversight that such sellers do not
obtain market power.'' \491\ The Commission considered other
formulations for a threshold, but it concluded that the other
``methodologies are inconsistent with a straightforward, conservative
means of screening sellers * * *.'' \492\ Thus, we deny PPM's request
to define Category 1 sellers based on their ownership or control of
generation capacity located in a balancing authority area or an RTO/ISO
market rather than based on ownership in a region.
---------------------------------------------------------------------------

    \491\ Order No. 697 at P 865.
    \492\ Id. P 868.
---------------------------------------------------------------------------

    361. With regard to PPM's request that the Commission adopt a less
stringent limitation for purposes of establishing Category 1 status for
sellers of power from intermittent generating capacity, as PPM
acknowledges, the Commission considered and rejected this suggestion in
the Final Rule. The Commission stated that it believed ``that many
sellers with wind and other non-thermal capacity will fall below that
500 MW threshold'' \493\ and reiterated that those sellers that exceed
it may take advantage of simplifying assumptions to minimize the burden
of filing an updated market power analysis. While there may
theoretically be some merit to PPM's assertion that it is unlikely that
any public utility will attain market power as a result of its
ownership or control of wind generation capacity due to the
intermittent nature of such capacity, nevertheless, PPM's remark that
wind power is the fastest growing source of generating capacity (other
than gas) is further reason that intermittent capacity should not be
treated differently from thermal generating capacity for purposes of
establishing Category 1 status. There may be a time when a very large
wind power facility could possibly have market power and will warrant
Commission scrutiny. We note that PPM argues that the Commission should
adopt a less stringent limitation for purposes of establishing Category
1 status for sellers of power from intermittent generating capacity
because, in its view, it would be unwise to impose a burden on wind
power generators that will not enhance the competitiveness of wholesale
electric markets. However, PPM does not claim such a burden would be
unduly burdensome. Nor should it. Our approach is balanced, reasonable,
and consistent with our approach to examining market power of sellers
seeking to obtain or retain market-based rate authority. On this basis,
we believe it is appropriate that wind generators be subject to the
same 500 MW threshold for Category 1 status as other sellers. At the
same time, we note that we already afford intermittent generation more
flexibility in conducting market power analyses than, for example,
thermal generating capacity. In particular, we allow energy-limited
resources to provide a market power analysis based on historical
capacity factors to more accurately capture hydroelectric or wind
availability, in lieu of using nameplate or seasonal capacity.\494\
This is an option not available to thermal generating units. In
addition, as we stated in the Final Rule, such sellers can take
advantage of simplifying assumptions (such as performing the indicative
screens assuming no import capacity or treating the host balancing
authority area utility as the only other competitor). As a result, to
the extent that a wind power generator exceeds the 500 MW threshold and
therefore is considered a Category 2 seller, we believe that any burden
imposed on that

seller to file an updated market power analysis would be minimal.
---------------------------------------------------------------------------

    \493\ Id. P 867.
    \494\ Id. P 344. We also remind sellers that they may seek
exemption from Category 2 status on a case-by-case basis. See id. P
868.
---------------------------------------------------------------------------

2. Regional Review and Schedule
Requests for Rehearing
    362. On rehearing, FirstEnergy and MidAmerican object to the
regional filing approach adopted in the Final Rule.
    363. FirstEnergy argues that the Commission erroneously and
unreasonably ruled that for corporate families that own or control
generation in different regions, the corporate family would be required
to file an update for each region in which members of the corporate
family sell power during the time period specified for that
region.\495\ FirstEnergy contends that a corporate family with
generation assets in adjacent geographic markets finds it far more
efficient to prepare and submit a single, all-encompassing, updated
market power analysis every three years than to prepare separate
analyses for each region.\496\ It claims that adoption of a single
filing date for all entities within a corporate family that have
market-based rates will permit all necessary tariff revisions to be
filed at the same time, and will thereby reduce the possibility for
discrepancies among tariffs within the same corporate family.
---------------------------------------------------------------------------

    \495\ FirstEnergy Rehearing Request at 3.
    \496\ Id. at 5.
---------------------------------------------------------------------------

    364. FirstEnergy reasons that it is unlikely that there are a
significant number of corporate families that have affiliated
generation suppliers operating in adjacent geographic markets. For that
reason, FirstEnergy states that there is no reason to believe that
authorizing affected sellers to make a single, all-encompassing,
triennial market power update filing every three years will
significantly undermine the Commission's ability to obtain a complete
view of market forces in each region in order to ensure that seller's
rates remain just and reasonable.\497\ In the event that the Commission
permits all companies within a corporate family that operate in
adjacent geographic markets to file a single market power updated
analysis during a three-year filing cycle, FirstEnergy requests that
the filing companies be given the option of selecting the region with
which they will participate.\498\
---------------------------------------------------------------------------

    \497\ Id. at 6-7.
    \498\ Id. at 7. Alternatively, FirstEnergy suggests that the
Commission should establish a process by which it would determine
which cycle should be followed.
---------------------------------------------------------------------------

    365. MidAmerican seeks a filing schedule that permits it to submit
a single market power analysis reflecting the generating facilities
within its own balancing authority area (part of the Central region) as
well as its Quad Cities Station (QCS), which is located on the border
of that balancing authority area (part of the Northeast region).
MidAmerican seeks to align the filing schedules to lessen the burden on
the Commission in evaluating MidAmerican's market power, and the burden
on MidAmerican in preparing multiple filings.\499\ Its affiliate
Cordova operates a generating facility also electrically located within
the Northeast region, and MidAmerican states that Order No. 697 could
be construed to require Cordova to file with the Northeast region.
---------------------------------------------------------------------------

    \499\ MidAmerican Rehearing Request at 2.
---------------------------------------------------------------------------

    366. MidAmerican states that, as affiliates, it and Cordova
historically have prepared market power analyses that have evaluated
the competitive effects of the aggregate generation owned and
controlled by both. For that reason, Cordova is seeking to file on the
same schedule as MidAmerican. QCS and Cordova's facility electrically
are located immediately adjacent to MidAmerican's balancing authority
area, and the metering points within the respective substations form
part of the border between the Northeast and Central regions; each
facility is geographically within the MidAmerican service territory and
directly interconnected with the MidAmerican transmission system
through facilities owned by MidAmerican.\500\
---------------------------------------------------------------------------

    \500\ Id. at 4.
---------------------------------------------------------------------------

    367. MidAmerican seeks clarification that its undivided ownership
interest in QCS will not cause it to be deemed a seller that
``operates'' in the Northeast region subject to that region's filing
schedule.\501\ If the Commission is not willing to construe Order No.
697 in this manner, then, for the same reasons, MidAmerican seeks
waiver of the filing schedule to permit QCS to be treated as part of
MidAmerican's on-system generating resources; i.e., as if QCS were
within the Central region along with the other MidAmerican generating
resources.\502\ Cordova also seeks a similar clarification or waiver of
Order No. 697 to permit its updated market power analysis to be made
pursuant to the Central region schedule applicable to MidAmerican.
MidAmerican states that its request is narrowly tailored to the
circumstances applicable to itself and Cordova, whose relevant
generation is located electrically either within or at the border of
MidAmerican's balancing authority area in the Central region. By way of
distinction, MidAmerican is not requesting permission to make a single
filing for its entire corporate family.\503\
---------------------------------------------------------------------------

    \501\ Id. at 10.
    \502\ Id. at 10-11.
    \503\ Id. at 3-4.
---------------------------------------------------------------------------

Commission Determination
    368. The Commission specifically addressed FirstEnergy's argument
in Order No. 697. The Commission stated that its decision to adopt a
regional review properly and fairly balances the need to effectively
monitor and mitigate market power in the wholesale markets with the
desire to minimize any administrative burden associated with the
filings and review of updated market power analyses. The Commission
recognized that some sellers may have to file updated market power
analyses more frequently than they would have had to before Order No.
697, but the Final Rule carefully balanced the interests of all
involved. The Commission explained that the regional approach will
enhance the Commission's ability to continue to ensure that sellers
either lack market power or have adequately mitigated such market
power.\504\ We recognize FirstEnergy's contention that it is more
efficient to prepare and submit a single, all-encompassing, updated
market power analysis every three years than to prepare separate
analyses for each region. However, such an approach does not satisfy
our desire to ensure greater consistency in the data used to evaluate
sellers' market power. If corporate families are allowed to combine all
of their facilities nationwide into a single updated market power
analysis, the study year and associated data may not be consistent with
that required for the corresponding region, and thus the Commission's
ability to ensure greater consistency in the data used to evaluate
sellers' market power and to reconcile conflicting submissions would be
undermined. Thus, we deny FirstEnergy's request for rehearing in this
regard.
---------------------------------------------------------------------------

    \504\ Order No. 697 at P 883.
---------------------------------------------------------------------------

    369. With regard to FirstEnergy's claim that adoption of a single
filing date for all entities within a corporate family that have
market-based rates will permit all necessary tariff revisions to be
filed at the same time, and will thereby reduce the possibility for
discrepancies among tariffs within the same corporate family, from an
administrative perspective, we agree and note that nothing in Order No.
697 prohibits FirstEnergy or any other seller from making such a filing
revising all of its market-based rate tariffs at the same time. Our
concern addressed above pertaining to data consistency is not present
with regard to making a

corporation's market-based rate tariffs Order No. 697 compliant. Our
analysis of market-based rate tariffs' compliance with Order No. 697 is
not dependent on analyzing data but rather analyzing whether the
tariffs meet the standards set forth in Order No. 697. Unlike analysis
of data that can vary depending on the source of the data and the
underlying assumptions, Order No. 697 set forth the standard by which
the market-based rate tariff will be judged and those standards do not
vary nor are they subject to assumptions.
    370. We will deny MidAmerican's request for clarification. To the
extent that a seller's generation facilities are electrically located
in different regions, the intent of the regional review approach is for
those facilities to be studied with their separate regions. We note
that, prior to the adoption of the Final Rule, sellers were required to
prepare a market power analysis for all of their generation assets
nationwide. Some sellers with assets in multiple regions chose to
submit their individual updated market power analyses when each was due
rather than combining them into a single updated market power analysis.
Others filed one updated market power analysis for the entire corporate
family, with individual analyses of the different markets in which
their assets are located. Either way, the same analyses were required
to be filed before and after the Final Rule. Although the timing of the
filings may differ post-Final Rule, the increased burden, if any, of
filing pursuant to the regional approach is minimal.
    371. With respect to MidAmerican's company-specific request for
waiver from the requirements of Order No. 697, we will decline to act
in the context of this generic rulemaking proceeding. We do not believe
that this rehearing order is the proper vehicle to consider a waiver
request which, as MidAmerican describes it, is narrowly tailored to
itself and Cordova. MidAmerican's request for waiver may be submitted
in another individual proceeding, and the Commission will consider the
merits of its request at that time.
3. Clarifications on Implementation Process
    372. During the period since Order No. 697 became effective, a
number of implementation questions have come to the Commission's
attention, either as a result of questions received from sellers or as
raised in various filings. As we describe above, several of these
issues were addressed in the Clarification Order issued on December 14,
2007. We will use this opportunity to provide additional guidance.
    373. In the Clarification Order, among other things, the Commission
explained that there may have been confusion concerning which data and
market share calculations must be submitted as part of sellers' updated
horizontal market power analyses.\505\ The Commission clarified that
market shares calculated for the wholesale market share screen and the
DPT analysis should be based on the four seasons, as defined in the
April 14 Order,\506\ rather than the four quarters of the calendar
year. The Clarification Order revised Appendix D to Order No. 697 to
incorporate this clarification and explained that the study period runs
from December of one year through November of the following year.
---------------------------------------------------------------------------

    \505\ We note that, in an effort to continue to improve upon the
accuracy and consistency of data used within a region and to provide
the Commission and the public with a more complete picture of the
market, the Commission will allow RTO/ISOs to conduct market power
studies that the RTO/ISO members can rely on in their market power
filings.
    \506\ April 14 Order, 107 FERC ] 61,018 at n.85.
---------------------------------------------------------------------------

    374. In the Clarification Order, the Commission also clarified
which entities are required to file their updated market power analyses
first. In Order No. 697, the Commission discussed the need for entities
that have the information necessary to perform simultaneous
transmission import limit studies to file in advance of those who will
rely on that information.\507\ In Appendix D of Order No. 697, the
Commission identified those required to file first as ``Transmission
Operators.'' However, the Commission explained in the Clarification
Order, consistent with the discussion in paragraph 889 of Order No.
697, that transmission-owning utilities with market-based rate
authority and their affiliates with market-based rate authority are the
entities required to file their updated market power analyses first in
each region.\508\ Accordingly, revised Appendix D makes clear that
transmission owners and their affiliates have earlier filing periods
than other entities required to file in each region.
---------------------------------------------------------------------------

    \507\ Order No. 697 at P 889.
    \508\ Clarification Order, 121 FERC ] 61,260 at P 9.
---------------------------------------------------------------------------

    375. In the Final Rule, the Commission stated that it will
entertain individual requests for exemption from Category 2, and that
such requests must be filed no later than 120 days before a seller's
next updated market power analysis is due. However, the period for
filing updated market power analyses is not a specific date, but a
month-long period (either December or June of each year). In response
to questions regarding how to calculate 120 days prior to the filing
period, we clarify that a seller must make a filing requesting an
exemption from Category 2 no later than 120 days prior to the first day
of the month in which its next updated market power analysis is
due.\509\
---------------------------------------------------------------------------

    \509\ See id. P 868.
---------------------------------------------------------------------------

    376. In Order No. 697, the Commission explained that a power
marketer that does not own or control generation assets in any region
must submit a filing explaining why it meets the criteria for Category
1 and directed that such filings be submitted with the first scheduled
geographic region in which the power marketer makes any sales.\510\
Because the Commission has received several inquiries regarding this
directive, we will provide further clarification here. If an
unaffiliated power marketer has made no sales at any point in time
since it obtained its market-based rate authority, it should make this
submission during the next filing period, i.e., June 1-30, 2008. We
also clarify that, once a seller is determined to be in Category 1, it
is not required to file updated market power analyses, or evidence of
Category 1 status, for the other regions in which it makes sales so
long as it continues to meet the criteria for a Category 1 seller.\511\
---------------------------------------------------------------------------

    \510\ Id. at n.1027.
    \511\ See id. P 849 (stating that subsequent to being found to
be in Category 1, ``all Category 1 sellers will not be required to
file regularly scheduled updated market power analyses.'')
---------------------------------------------------------------------------

    377. Additionally, in response to inquiries from certain sellers in
the Central region, we will clarify the geographic area included in
that region. Specifically, the Central region will now be defined to
include portions of NERC Region RFC as follows: Central (Midwest ISO,
NERC Regions MRO and RFC (not including PJM)).\512\ Appendix D has been
revised to reflect this description of the Central region.
---------------------------------------------------------------------------

    \512\ Id. at Appendix D.
---------------------------------------------------------------------------

    378. Additionally, in Order No. 697 the Commission adopted a
requirement that all sellers include an appendix listing generation
assets as well as electric transmission and natural gas intrastate
pipelines and/or gas storage facilities with certain filings,
consistent with the example in Appendix B of Order No. 697.\513\ We
clarify that the transmission facilities that we require to be included
in that asset appendix are limited to those the ownership or control of
which would require an entity to have an OATT on file with the
Commission (even if the Commission has waived the OATT requirement for
a particular seller).
---------------------------------------------------------------------------

    \513\ Order No. 697 at P 895.

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

    379. Further, we clarify the manner in which transmission assets
should be identified and described in the asset appendix. In order to
lessen the reporting burden for sellers with large numbers of
transmission facilities, we will allow a company to combine lines of a
common size into one ``line item'' for purposes of the appendix; i.e.,
12 individual 500 kV lines could be identified as one line item in the
appendix. For companies using this approach, rather than listing each
line separately, the appendix must be filled out in a slightly
different manner. Specifically, under the Asset Name and Use section of
the appendix, rather than using the actual line name, a seller would
insert an appropriate asset identifier. For example, if combining all
500 kV lines together the asset identifier would be ``Combined 500kV
Lines.'' As a result, the Size section of the appendix would also
change. Rather than identifying the actual size of each line, the
seller would include the transmission asset size, described as the
total combined length of all the lines of that size. Because the
combined lines could run through several balancing authority areas and
regions, the seller should split up its combined assets into separate
balancing authority areas. Accordingly, the transmission asset aspect
of the appendix would be filled out similar to the following:

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                Location
                                                                                ----------------------------------
 Filing entity and its energy   Asset name and       Owned by        Controlled by     Date control                        Geographic          Size
          affiliates                  use                                               transferred       Balancing       region (per
                                                                                authority area    Appendix D)
--------------------------------------------------------------------------------------------------------------------------------------------------------
ABC Corp.....................  Combined 500kV    ABC Corp........  ABC Corp........  NA..............  New York ISO     Northeast and    Approx. 305
                                Lines.                                                                  and Tucson BA.   Southwest.       combined
                                                                                miles.
ABC Corp.....................  Combined 500kV    ABC Corp........  XYZ Inc.........  Jan. 1, 2000....  Tucson BA......  Southwest......  185 combined
                                Lines.                                                                                miles.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    380. However, we note that this combined approach can only be used
if lines of the same size are controlled by the same entity. If there
are lines of the same size controlled by different entities, they must
be identified in different line items; i.e., each combined set of lines
can only be identified as controlled by one entity. Thus, if the 500 kV
lines are owned or controlled by two different entities, there would
have to be two line items for 500 kV lines listed in the appendix. We
believe this approach will allow the Commission to continue to obtain
the information it seeks regarding a seller's affiliated transmission
assets while allowing those entities with a great number of assets to
simplify their appendices.
    381. Lastly, with regard to the asset appendix, we wish to make
clear that sellers must submit both tables in their entirety. Even if a
seller has no assets to list in a specific section, both the Market-
Based Rate Authority and Generation Assets table, as well as the
Electric Transmission Assets and/or Natural Gas Interstate Pipelines
and/or Gas Storage Facilities table must be submitted. As stated in
Appendix B to Order No. 697, a seller should indicate the fact that it
has no assets or that a field is not applicable by inputting N/A.
4. Market-Based Rate Tariff Clarifications
    382. In Order No. 697 the Commission adopted a requirement that all
sellers include a provision in their market-based rate tariffs
identifying all limitations on their market based rate authority
(including markets where the seller does not have market-based rate
authority) and any exemptions from, waivers of, or blanket
authorizations under the Commission's regulations that the seller has
been granted (such as exemption from the affiliate sales restrictions;
waiver of the accounting regulations; blanket authority under part 34
for the issuances of securities and assumptions of liabilities). The
Commission stated that this provision must include cites to the
Commission orders approving each limitation, exemption, waiver or
blanket authorization.\514\ On further review, the Commission will take
this opportunity to clarify several aspects of this requirement.
---------------------------------------------------------------------------

    \514\ Order No. 697 at P 916.
---------------------------------------------------------------------------

    383. First, we clarify that if a seller's market-based rate
authority is not subject to any limitations (for example, the seller's
market-based rate authority is not limited to certain markets) or if
the seller has not been granted any exemptions, waivers, or blanket
authorizations under the Commission's regulations, then the seller
should so state in the required ``Limitations and Exemptions''
provision in its market-based rate tariff, i.e., including ``not
applicable,'' or ``N/A.'' \515\
---------------------------------------------------------------------------

    \515\ See Niagara Mohawk Power Corp., 121 FERC ] 61,275 at P11
(2007) (Niagara Mohawk).
---------------------------------------------------------------------------

    384. Second, we provide additional guidance on the format for
citations to pertinent Commission orders or proceedings in which the
Commission imposed limitations on the seller's market-based rate
authority or granted the seller's requested exemptions, waivers, or
blanket authorizations. In particular, sellers which already have been
granted market-based rate authorization and which have previously been
placed under any limitation or granted any exemption, waiver or blanket
authorization should include the cite to the relevant orders in one of
the following two citation forms:
    Cal. Contract Power, 99 FERC ] 61,xxx, at P xx (2002).
    WWW Corp., Docket No. ER03-xxxx-000, at 2 (Apr. 12, 2003)
(unpublished letter order).
    385. When a seller files an application for market-based rate
authority seeking certain exemptions, waivers or blanket
authorizations, the seller should include in its proposed tariff sheets
the docket number associated with the filing. Under current Commission
procedure, a docket number is not assigned until after an application
has been filed. However, to enable an applicant to identify and include
the docket number of its filing in its proposed tariff sheets, the
Commission is establishing a new process for sellers to obtain a docket
number for their submission before filling. The Commission is creating
a location on its Web site where a new applicant for market-based rate
authorization will e-mail \516\ the Commission and retrieve a docket
number under which its filing can be made and which will be a
substitute for the required citation in the ``Limitations and
Exemptions'' provision of its tariff.\517\ The point of this process is
to

alleviate the need for compliance filings just to add a docket number
or citation once the Commission issues an order on the request. Any
modifications to the information submitted with the application would
be directed to be made in a compliance filing. Once the docket number
is obtained, the filing must be submitted to the Commission within 72
hours or the docket number will expire and the applicant must request a
new one. This reserved docket number should be included in the tariff
and the transmittal sheet, and a copy of the Commission's response
assigning this docket number should be attached as the first page of
the filing. Accordingly, the process for a seller newly filing for
market-based rate authorization will now require reserving a docket
number before submitting the filing.
---------------------------------------------------------------------------

    \516\ Any sellers unable to obtain this docket number via the
internet or e-mail will be directed to include the pertinent
information in their tariff sheets in a compliance filing.
    \517\ We note that while this approach will allow most new
applicants to comply with the Commission's citing requirement in the
``Limitations and Exemptions'' provision of the market-based rate
tariff, there may be some instances in which the Commission will
require a seller to make a subsequent filing to include a full
citation to the Commission order approving a limitation, exemption,
waiver or blanket authorization. An example of when the Commission
may require such a compliance filing is when the Commission exempts
a seller from affiliate restrictions which have been codified in 18
CFR 35.39 or when approving mitigation measures. However, unless an
applicant is informed by order to revise its tariff to include a
citation, the docket number used in the tariff in the initial
submission will suffice.
---------------------------------------------------------------------------

    386. In Appendix C of Order No. 697, the Commission provided
certain applicable tariff provisions that sellers must include in their
market-based rate tariffs to the extent they are applicable based on
the services provided by the seller. One of these is to be used if a
seller makes sales of ancillary services as a third-party
provider.\518\ We are revising this applicable provision so that it is
consistent with the other ancillary service provisions by inserting the
phrase ``Seller offers.'' Thus, the ``Third Party Provider'' provision
that should be included in all applicable market-based rate tariffs is
as follows:
---------------------------------------------------------------------------

    \518\ See Order No. 697 at P 917-18.

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

    387. Additionally, regarding other applicable tariff provisions,
which include those needed if a seller makes sales of ancillary
services in certain RTO/ISOs, the seller must include the standard
ancillary services provision(s) in its tariff, as applicable, without
variation.\519\ To the extent that a seller with market-based rate
authority does not already have authority to make sales of ancillary
services at market-based rates in one or more of the RTO/ISOs included
in Appendix C, but wishes to do so, it may file revised tariff sheets
including the standard applicable ancillary service tariff provision(s)
without seeking separate authorization from the Commission under FPA
section 205. Separate authorization for specific sellers is not needed
given that Order No. 697 implicitly granted authorization for ancillary
services sales by sellers with market-based rate authority by providing
standard tariff provisions for ancillary services sales.\520\
---------------------------------------------------------------------------

    \519\ Id. P 916-917; see Appendix C for a listing of the
standard ancillary services provisions. See also Niagara Mohawk
Power Corp., 121 FERC ] 61,275, at P 14 & n.22 (2007) (directing
seller to conform with Appendix C).
    \520\ See Niagara Mohawk Power Corp., 121 FERC ] 61,275, at P 18
(2007) (accepting tariff provisions that were new for National Grid
that comported with ancillary services previously approved by the
Commission for sale at market-based rates and were listed in
Appendix C of Order No. 697).
---------------------------------------------------------------------------

    388. The Commission also stated in Order No. 697 that it would
permit sellers to list in their market-based rate tariffs additional
seller-specific terms and conditions that go beyond the standard
provisions set forth in Appendix C.\521\ In the Clarification Order, we
clarified that these seller-specific terms and conditions do not
include those provisions that the Commission has codified in 18 CFR
Part 35, Subpart H. Specifically, we stated that `` `seller-specific
terms and conditions' are those provisions that are commonly found in
power sales agreements, such as creditworthiness, force majeure,
dispute resolution, billing, and payment provisions.'' \522\ In
addition, we clarify here that we expect that all provisions that were
contained in a seller's market-based rate tariff but that are now
codified in the Commission's regulations are to be removed from each
seller's market-based rate tariff at the time the seller modifies its
existing tariff to include the required provisions and any applicable
provisions set forth in Appendix C of Order No. 697. For example,
sellers should remove from their tariffs codes of conduct (which have
been replaced by the affiliate restrictions in Sec.  35.39), any
language prohibiting affiliate sales without first receiving Commission
authorization (which is codified in Sec.  35.39(b)), market behavior
rules (which are codified in Sec.  35.41), and the change in status
reporting requirement (which is codified in Sec.  35.42).
---------------------------------------------------------------------------

    \521\ Order No. 697 at P 919-22.
    \522\ Clarification Order, 121 FERC ] 61,260 at P15.
---------------------------------------------------------------------------

    389. We remind sellers that, consistent with Sec.  35.9(b)(4), all
tariff sheets must include a proposed effective date. The regulation
requires that the seller must place the specific effective date
proposed by the company on the tariff sheets. To alleviate any
confusion, we stated in the Clarification Order that, notwithstanding
the fact that Order No. 697 did not require market-based rate sellers
to make immediate compliance filings amending their market-based rate
tariffs, the Commission intended that all requirements and limitations
applicable to market-based rate sellers set forth in the Final Rule
should become effective on September 18, 2007. The Clarification Order
explained that, effective September 18, 2007, provisions in market-
based rate tariffs that are inconsistent with the requirements of Order
No. 697 are no longer in effect.\523\ Accordingly, sellers filing
revised tariff sheets solely to comply with Order No. 697 should use
September 18, 2007 as the effective date of the tariff sheets. However,
if there are any additional revisions other than those required by the
Final Rule, whether it be a name change or the addition or modification
of any provision for any other reason, sellers should propose the date
on which they wish the tariff sheets to become effective. We note that,
while the sheets will be made effective on the date that the seller
proposes, the provisions relating to and required by Order No. 697 are
still effective as of the effective date of Order No. 697.\524\
---------------------------------------------------------------------------

    \523\ Id. at P 5.
    \524\ See Clarification Order, 121 FERC ] 61,260 at P 5.
---------------------------------------------------------------------------

    390. Additionally, the Commission provides clarification regarding
requests for waiver of affiliate restrictions (including the affiliate
sales restriction and what was formerly the codes of conduct). If a
seller was granted waiver of a restriction by the Commission prior to
the effective date of Order No. 697, and the seller still qualifies for
that waiver, the waiver remains effective and no further action is
needed.\525\ However, if a seller has not previously been granted
waiver of the affiliate restrictions and seeks a finding that the
affiliate restrictions do not apply to it, a seller must file a request
with the

Commission pursuant to FPA section 205.
---------------------------------------------------------------------------

    \525\ Pursuant to Order No. 697, however, such a waiver must be
identified in a seller's tariff. See Order No. 697 at P 916 and
Appendix C.
---------------------------------------------------------------------------

    391. Lastly, in order to identify which sellers must file updated
market power analyses, we will now require each seller to specify in
its market-based rate tariff whether it is a Category 1 or Category 2
seller. In a separate provision of the market-based rate tariff
entitled Seller Category, each seller should state whether it believes
it is in Category 1 or Category 2.\526\ Specifically, the following
provision should be included in each market-based rate tariff:
---------------------------------------------------------------------------

    \526\ Sellers that have received an exemption from Category 2,
as described in Order No. 697 at P 868, should identify themselves
as Category 1 sellers.

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

    392. The Commission will make a finding on the category of each
seller. To the extent that the Commission finds that a seller is in the
other category, the Commission will order the appropriate tariff
revisions.
    393. Any seller whose category has been determined in a Commission
proceeding between the effective date of Order No. 697 and the issuance
of this order and which has not included a Seller Category provision in
its tariff should update its tariff with such a provision the next time
that it files revised tariff sheets, a triennial review, or a change in
status report.

F. Legal Authority

1. Whether Market-Based Rates Can Satisfy the Just and Reasonable
Standard Under the FPA
Final Rule
    394. In the Final Rule, the Commission rejected arguments that it
has no authority to adopt market-based rates or that the market-based
rate program adopted in the Final Rule does not comply with the FPA.
The Commission explained that it is settled law that market-based rates
can satisfy the just and reasonable standard of the FPA, as most
recently affirmed by the Ninth Circuit in Lockyer and Snohomish.\527\
The Commission explained that in Lockyer, the Ninth Circuit cited with
approval the Commission's dual requirement of an ex ante finding of the
absence of market power and sufficient post-approval reporting
requirements, finding that the Commission did not rely on market forces
alone in approving market-based rate tariffs.\528\ The Final Rule also
rejected arguments that the proposed rule impermissibly relied solely
on the market to determine just and reasonable rates, explaining that
in the market-based rate program adopted in the Final Rule and through
other Commission actions, the Commission is not relying solely on the
market, without adequate regulatory oversight, to set rates.\529\
Rather, it has adopted filing requirements, new market manipulation
rules, and a significantly enhanced market oversight and enforcement
division to help oversee potential increases in market power and
potential market manipulation.\530\
---------------------------------------------------------------------------

    \527\ Order No. 697 at P 943 (citing State of California, ex
rel. Bill Lockyer v. FERC), 383 F.3d 1006 (9th Cir. 2004), cert.
denied (S. Ct. Nos. 06-888 and 06-1100 (June 18, 2007) (Lockyer);
Public Utility District No. 1 of Snohomish County, Washington v.
FERC, 471 F.3d 1053 (9th Cir. 2006), cert. granted, 128 S. Ct. 31
(Sept. 25, 2007) (Nos. 06-1457, 06-1462) (Snohomish)).
    \528\ Id. P 953-954.
    \529\ Id. P 952.
    \530\ Id.
---------------------------------------------------------------------------

    395. The Commission retained its policy of granting market-based
rate authority to sellers without market power under the terms and
conditions set forth in the Final Rule.\531\ The Final Rule explained
that the Commission has a long-established approach when a seller
applies for market-based rate authority of focusing on whether the
seller lacks market power. The Commission explained that this approach,
combined with the Commission's filing requirements (EQRs, change in
status filings, and regularly scheduled updated market power analyses
for Category 2 sellers) and ongoing monitoring through the Commission's
Office of Enforcement and complaints filed pursuant to FPA section 206,
allows the Commission to ensure that market-based rates remain just and
reasonable. Moreover, for sellers in RTO/ISO organized markets, the
Commission has in place market rules to help mitigate the exercise of
market power, price caps where appropriate, and RTO/ISO market monitors
to help oversee market behavior and conditions.\532\
---------------------------------------------------------------------------

    \531\ Id. P 954-955.
    \532\ Id. P 955.
---------------------------------------------------------------------------

    396. The Final Rule rejected arguments that the market-based rate
program does not comply with the FPA, stating that ``[t]he Supreme
Court has held that `[f]ar from binding the Commission, the FPA's just
and reasonable requirement accords it broad ratemaking authority * * *.
The Court has repeatedly held that the just and reasonable standard
does not compel the Commission to use any single pricing formula in
general * * *.' '' \533\ The Commission also pointed out that in the
Lockyer court's analysis of the Commission's market-based rate
authority, the Ninth Circuit cited the Supreme Court's determination in
Mobil Oil Exploration and also noted that the use of market-based rate
tariffs was first approved by the courts as to sellers of natural gas
in Elizabethtown Gas, then as to wholesale sellers of electricity in
Louisiana Energy and Power Authority v. FERC.\534\
---------------------------------------------------------------------------

    \533\ Id. P 943 (quoting Mobil Oil Exploration v. United
Distribution Co., 498 U.S. 211, 224 (1991) (Mobil Oil Exploration),
citing FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944); FPC v.
Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian Basin
Area Rate Cases, 390 U.S. 747, 776-77 (1968) (Permian); FPC v.
Texaco, 417 U.S. 380 (1974) (Texaco)).
    \534\ Elizabethtown Gas Co. v. FERC, 10 F.3d 866 (D.C. Cir.
1993) (Elizabethtown Gas); Louisiana Energy and Power Authority v.
FERC, 141 F.3d 364 (D.C. Cir. 1998) (LEPA). See also Order No. 697
at P 944.
---------------------------------------------------------------------------

    397. The Commission rejected arguments that the Final Rule
impermissibly relies solely on the market to determine just and
reasonable rates.\535\ The Final Rule explained that in Texaco,\536\
the Supreme Court noted that it had sustained rate regulation based on
setting area rates that were based on composite cost considerations,
citing its decision in FPC v. Hope Natural Gas Co.,\537\ and added that
ratemaking agencies are not bound to the service of any single
regulatory formula.\538\ The Final Rule further explained that in
Texaco, the Supreme Court found that the NGA permits the indirect
regulation of small-producer rates, and noted that cases under the NGA
and the FPA are typically read in pari materia.\539\ The Commission
stated that in the market-based rate program adopted in the Final Rule
and through other Commission actions, unlike the situation in Texaco,
the Commission is not relying solely on the market without adequate
regulatory oversight to set rates.
---------------------------------------------------------------------------

    \535\ Order No. 697 at P 945-947.
    \536\ Id. P 946 (citing FPC v. Texaco, Inc., 417 U.S. 380 (1974)
(Texaco)).
    \537\ Id. (citing 320 U.S. 602).
    \538\ Id. (quoting Permian, 390 U.S. at 776-77).
    \539\ Id. P 946 n.1070 (citing FPC v. Sierra Pacific Power Co.,
350 U.S. 348, 353 (1956) (Sierra); Arkansas-Louisiana Gas Company v.
Hall, 453 U.S. 571 n.7 (1981)).
---------------------------------------------------------------------------

    398. The Final Rule also explained that in Elizabethtown Gas, a
decision relying on Texaco, the D.C. Circuit addressed a Commission
order approving a restructuring settlement under which Transcontinental
Gas Pipeline Corporation (Transco) would no longer sell gas bundled
with transportation, but would sell gas at the wellhead or pipeline
receipt point, to be transported as the buyer sees fit, and the sales
would be market-based while the rates for transportation on Transco's
system would be cost-of-service

based.\540\ In rejecting arguments that the proposed rule impermissibly
relied solely on the market to determine just and reasonable rates, the
Final Rule explained that in Elizabethtown Gas the D.C. Circuit upheld
the Commission's approval of market-based pricing.\541\ The Final Rule
explained that the D.C. Circuit had also affirmed the Commission's
approval of an application by Central Louisiana Electric Company
(CLECO) to sell electric energy at market-based rates.\542\
---------------------------------------------------------------------------

    \540\ Id. P 948.
    \541\ Id. P 949-950.
    \542\ Id. P 951 (citing LEPA, 141 F.3d at 365).
---------------------------------------------------------------------------

Requests for Rehearing
    399. Consumer Advocates argue that the Final Rule erred in claiming
that the Commission can legally rely on the market (viz. wholesale
buyers/re-sellers) to determine lawful rates. They contend that the
Final Rule errs in relying on wholesale buyers/re-sellers to determine
lawful rates by ``negotiation,'' particularly where the buyers
generally bear no risk of loss in passing along such prices.\543\ They
argue that such reliance constitutes an unlawful delegation of the
Commission's statutory obligations to wholesale buyers insofar as (1)
the Commission overlooked the economic fact that such wholesale buyers/
re-sellers generally bear no risk of loss because their negotiated
prices must be passed through to retail ratepayers; \544\ and (2) the
Final Rule may not rely on the markets to determine rates because the
Commission may not delegate to others its FPA responsibilities to
ensure that rates are lawful.\545\
---------------------------------------------------------------------------

    \543\ Consumer Advocates Rehearing Request at 10. Richard
Blumenthal, Attorney General for the State of Connecticut and the
People of the State of Illinois, by and through the Illinois
Attorney General, Lisa Madigan (Attorneys General of Connecticut and
Illinois) submitted a request for rehearing on July 19, 2007 that
adopts and incorporates by reference all of the arguments presented
by the Consumer Advocates in their request for rehearing filed in
this proceeding.
    \544\ Id. at 10 (citing Tejas Power Corp v. FERC, 908 F.2d 998
(D.C. Cir. 1990); Nantahala Power & Light Co. v. Thornburg, 476 U.S.
953, 970 (1986); Elizabethtown Gas).
    \545\ Id. at 10, 12. Consumer Advocates note that in a recent
order the Commission correctly held that it could not delegate to
state commissions its ``ratemaking obligations under the FPA.'' Id.
at 12 (citing Entergy Services, Inc., 120 FERC ] 61,020 (2007),
citing Louisiana, Inc. v. Louisiana Public Service Comm., 539 U.S.
39, 43 n.1; City of New Orleans v. Entergy Corp., 55 FERC ] 61,211,
at 61,729 (1991)).
---------------------------------------------------------------------------

    400. Consumer Advocates contend that the Final Rule failed to
provide a standard whereby the Commission can determine whether actual
market rate increases fall within a ``zone of reasonableness'' not just
in theory, but ``in fact.'' According to Consumer Advocates, the Final
Rule only addressed whether the ``market'' is competitive \546\ and
sellers are manipulative, not whether wholesale rates are not
excessive, as the FPA requires.\547\ Consumer Advocates argue that the
Final Rule attempted to distinguish Supreme Court and other judicial
precedent that requires the Commission to determine whether ``market''
rates in fact fall within a ``zone of reasonableness,'' but fails to do
so.\548\ They also contend that the Final Rule failed to explain how
the Commission, which is not an antitrust agency, acting under the FPA,
which is not an antitrust statute but a rate filing regulatory statute,
can rely entirely on its oft-changing antitrust analyses regarding
market power to determine whether market-based rates are within a zone
of reasonableness.\549\ NASUCA also asserts that the Final Rule failed
to identify an objective standard by which to ascertain, after rates
have been changed, charged and eventually reported, whether a market
rate is or is not in the zone of reasonableness.\550\
---------------------------------------------------------------------------

    \546\ As discussed at P 409 below, the Industrial Customers
argue that the Final Rule erred insofar as it failed to make the
finding that a competitive market exists. See Industrial Customers
Rehearing Request at 6-7.
    \547\ Consumer Advocates Rehearing Request at 12-13.
    \548\ Id. (citing Farmers Union Cent. Exch. v. FERC, 734 F.2d
1486 (D.C. Cir. 1984) (Farmers Union)).
    \549\ Id. at 13-14 (citing MCI Telecommunications Corp. v. AT&T
Co., 512 U.S. 218 (1994) (MCI); Southwestern Bell Corp. v. FCC, 43
F.3d 1515 (D.C. Cir. 1995) (Southwestern Bell)).
    \550\ NASUCA Rehearing Request at 18.
---------------------------------------------------------------------------

    401. Consumer Advocates contend that the Final Rule erred in
relying heavily on Natural Gas Act (NGA) cases and Interstate Commerce
Act oil pipeline cases as judicial support for the Commission's
authority to allow market-based rates.\551\ Consumer Advocates assert
that there are substantive differences among electricity and natural
gas statutes, the physical operations of the industries, and the costs
of providing service.\552\ They argue that in addition to the fact that
Congress has deregulated most natural gas wellhead sales, but has never
deregulated wholesale electric sales, the FPA and NGA have always
differed in certain respects, namely that NGA section 7 confers
authority on the Commission to certify and condition natural gas
service, whereas no such authority is given to the Commission under the
FPA.\553\ Consumer Advocates argue that the regulation of generation
and distribution was specifically reserved to the states \554\ and
contend that the costs of production of natural gas and electricity
differ markedly.\555\ They state that highly depreciated power plants
have very different costs from new ones, and they note that in the
Connecticut complaint against ISO New England, the complaint showed
that excessive rates of return were being made, but the Commission
found this `` `not relevant.' '' \556\
---------------------------------------------------------------------------

    \551\ Consumer Advocates Rehearing Request at 19 (citing Order
No. 697 at P 943, n. 1068 (citing Mobil Oil Exploration, 498 U.S. at
224, citing FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944);
FPC v. Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian,
390 U.S. at 776-77; Texaco, 417 U.S. at 308)).
    \552\ Id. at 17-18.
    \553\ Id. at 18.
    \554\ Id. (citing FPA section 201(e)).
    \555\ Id.
    \556\ Id. at 19 (citing Richard Blumenthal v. ISO New England,
Inc., 117 FERC ] 61,038 (2006), reh'g denied, 118 FERC ] 61,205
(2007) (Blumenthal)).
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    402. Consumer Advocates conclude that these differences result in
very different bidding strategies by market participants, yet the Final
Rule relied primarily on natural gas and oil cases in defense of the
Commission's market-based rate regime.\557\ In particular, they contend
that the claim in the Final Rule that ``costs of all natural gas
companies need not be ascertained separately,'' incorrectly cites to
the fact that the courts treat virtually identically parts of the
statute `` `in pari materia.' '' \558\ They argue that because this
language refers to the filing and rate review provisions of the two
statutes, it does not contend that the cost elements or physical
operations of these two distinct industries are the same.\559\
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    \557\ Id. (citing Order No. 697 at P 943, n. 1068).
    \558\ Id. (citing Order No. 697 at P 946, n. 1070).
    \559\ Id.
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    403. Consumer Advocates argue that the incentive provided by the
market-based rate regime is for plant owners to keep power supplies
tight, thus raising their profits from remaining power plants or
contracts.\560\ They state that because wholesale sellers have no
obligation to serve, the Commission's market-based rate regime requires
the Commission to give incentives, like locational pricing, to
essentially `` `bribe' '' suppliers to build power plants.\561\
Consumer Advocates contend that the Final Rule failed to explain why
this `` `perverse incentive' '' is in either the public or the national
interest. They also note that the court in Elizabethtown Gas did not
address these ``perverse economic incentives.'' \562\
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    \560\ Id. at 20.
    \561\ Id.
    \562\ Id. at 21.
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    404. Industrial Customers argue that a finding that competitive
markets exist is a prerequisite to relying upon market-

based rate authority to satisfy the mandates of the FPA. In particular,
Industrial Customers contend that the Final Rule does not reflect
reasoned decisionmaking because it fails to address their argument
stating that the Commission must find the existence of a competitive
market before it can rely on market-based rate authority.\563\
Additionally, Industrial Customers contend that the Final Rule is
arbitrary, capricious and insufficiently supported in presuming that
existing price setting mechanisms are competitive markets that will
enable the use of market-based rate authority to ensure just and
reasonable rates.\564\ Industrial Customers argue that their NOPR
comments relied on significant precedent for their argument that the
Commission must point to ``empirical proof'' that competitive markets
exist.\565\ Industrial Customers state that although the Commission
provides settled law supporting its conclusion that market-based rates
can satisfy the just and reasonable standard of the FPA,\566\ the issue
posed by Industrial Customers was whether the Commission has made the
necessary findings that a competitive market exists--and it has
not.\567\ Industrial Customers therefore assert that the Commission
failed its responsibility to respond to their arguments,\568\ and must
either (1) explain why the case law underlying market-based rate
authority no longer requires the prerequisite showing of competitive
markets based on empirical proof, or (2) undertake the task of
analyzing whether current wholesale electricity pricing mechanisms
amount to a competitive market.\569\ Industrial Customers argue that
the key question the Commission failed to answer in the Final Rule is
what constitutes a truly competitive market and whether there are any
in the country sufficient to enable use of market-based rate authority.
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    \563\ Industrial Customers Rehearing Request at 6 (citing
Electricity Consumers Res. Council v. FERC, 747 F.2d 1511, 1513;
Burlington Truck Lines v. United States, 371 U.S. 156, 168 (1962);
W. Mass Elec. Co. v. FERC, 165 F.3d 922, 927 (D.C. Cir. 1997);
Victor Broad, Inc. v. FCC, 722 F.2d 756, 760 (D.C. Cir. 1983);
Transcontinental Gas Pipe Line Corp. v. FERC, 922 F.2d 865, 869
(D.C. Cir. 1991); KN Energy, Inc. v. FERC, 968 F.2d 1295, 1303 (D.C.
Cir. 1992); PPL Wallingford, 419 F.3d at 1198; Canadian Petroleum
Producers, 254 F.3d at 299; Tesoro Alaska Petroleum Co. v. FERC, 234
F.3d 1286, 1294 (D.C. Cir. 2000)). Montana Counsel similarly argues
that the Commission erred in assuming that long-term markets are
inherently competitive. Montana Counsel Rehearing Request at 4-6.
    \564\ Id. at 8 (citing LEPA, 141 F.3d at 365; Elizabethtown Gas,
10 F.3d at 870).
    \565\ Id. at 7 (citing Industrial Customers' August 7 Comments
at 6-7; Farmers Union, 734 F.2d at 1510).
    \566\ Id. (citing Order No. 697 at P 943-955).
    \567\ Id.
    \568\ Id. (citing NorAm Gas, 148 F.3d at 1165; Brusco Tug &
Barge Co. v. NLRB, 247 F.3d 273, 278 (D.C. Cir. 2001); Missouri PSC
v. FERC, 234 F.3d 36, 41 (D.C. Cir. 2001)).
    \569\ Id. at 7-8 (citing Tripoli Rocketry v. Bureau of Alcohol,
Tobacco, 437 F.3d 75, 81 (D.C. Cir. 2006)).
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    405. Industrial Customers argue that as the Commission acknowledged
in its approval of the Southwest Power Pool's Energy Imbalance Service
Market, the process for assessing market-based rate authority is a two-
part analysis: (1) Determining whether a competitive market exists and
(2) ensuring that the seller-applicant cannot exercise market power,
based either on a finding that no market power exists or based on a
finding that mitigation is sufficient to protect against market
power.\570\ Industrial Customers contend that if this two-part analysis
is not undertaken, the Commission cannot demonstrate that reliance on
market-based rate authority is just and reasonable.\571\
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    \570\ Id. at 9 (citing Southwest Power Pool, Inc., 116 FERC ]
61,289, at P 30 (2006)).
    \571\ Id.
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    406. Industrial Customers state that there are definite criteria
such as barriers to entry or exit, demand elasticity, ease of product
deliverability, transparent market information, unconcentrated
generation asset ownership, correct market design, and absence of
market power that would help determine whether a competitive market
exists.\572\ They present information about existing markets that they
allege calls into question whether the Commission is capable of finding
the presence of dynamically competitive markets. Industrial Customers
argue that the widespread lack of demand elasticity and the equally
pervasive presence of generation ownership concentration and high
market shares within submarkets are the types of issues that the Final
Rule erroneously overlooked by presuming the existence of competitive
markets.\573\ Industrial Customers contend that market power issues are
prevalent in PJM,\574\ Midwest ISO,\575\ Southwest Power Pool,\576\ and
ISO New England.\577\
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    \572\ Id.
    \573\ Id. at 10.
    \574\ Id. at 10-13 (citing PJM 2006 State of the Market Report
at 89, 210 (Mar. 8, 2007), http://www.pjm.org; PJM Preliminary
Market Structure Screen for 2007-2008; PJM Preliminary Market
Structure Screen for 2008-2009; PJM Preliminary Market Structure
Screen for 2000-2010; Letter from PJM to Maryland Public Service
Commission, dated June 8, 2007 at 8, Maryland PSC Administrative
Docket No. PC 8; PJM 2008/2009 RPM Base Residual Auction Results at
1, (July 13, 2007); Statement of Joseph E. Bowring In Response to
the Federal Energy Regulatory Commission's Order of May 18, 2007 at
3, (filed June 12, 2007)).
    \575\ Id. at 14 (citing 2006 Midwest ISO State of Market
Report).
    \576\ Id. at 15 (citing Monthly Metrics Report for SPP Energy
Imbalance Services Market at 3, prepared by the SPP Market
Monitoring Unit (Apr. 2007)).
    \577\ Id. (citing ISO New England Report).
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Commission Determination
    407. In the Final Rule, the Commission fully addressed the
arguments raised by commenters challenging the Commission's market-
based rate program. Consumer Advocates and Industrial Customers repeat
on rehearing many of the arguments that they raised in their comments.
While these entities re-state their arguments in a variety of ways,
their arguments basically fall into two categories: (1) That the
Commission has no authority at all under the FPA to rely on the market
to ensure just and reasonable rates, in lieu of cost-based ratemaking;
and (2) that the standard adopted by the Commission in this rule for
allowing market-based rates--a demonstration by the individual seller
that it lacks or has mitigated both horizontal and vertical market
power--does not comply with the FPA requirement that rates be just,
reasonable, and not unduly discriminatory or preferential. As we set
forth below, we find all the iterations of these basic arguments to be
without merit because court precedent for the past 60 years validates
the Commission's discretion not to be bound to any particular
ratemaking method and indeed in more recent years has sanctioned
market-based rates under both the NGA and the FPA, and because the
market-based rate analysis in this rule will result in rates that fall
within a zone of reasonableness. Section 205 of the FPA requires that
``[a]ll rates and charges made * * * shall be just and reasonable.''
\578\ The FPA does not prescribe any particular ratemaking methodology
to be followed in setting rates so long as rates fall within a zone of
reasonableness,\579\ i.e., the rates are neither less than compensatory
to the seller nor excessive to the consumer.\580\

Further, the fixing of ``just and reasonable'' rates involves a
balancing of investor and consumer interests \581\ and the ``zone of
reasonableness'' may take into account all relevant public interests,
both existing and foreseeable.\582\ These public interests may
appropriately include non-cost factors, such as the need to stimulate
additional investment.\583\ As we explained in the Final Rule and
reiterate here, the Supreme Court has held that ``[f]ar from binding
the Commission, the `just and reasonable' requirement accords it broad
ratemaking authority * * *. The Court has repeatedly held that the just
and reasonable standard does not compel the Commission to use any
single pricing formula in general * * *.'' \584\ Accordingly, the FPA
grants the Commission broad discretion as to how the statute's
ratemaking mandate will be satisfied.\585\ The market-based rate
program represents a reasonable exercise of that discretion.\586\
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    \578\ 16 U.S.C. 824d(a).
    \579\ FPC v. Hope Natural Gas Co., 320 U.S. at 602 (``[u]nder
the statutory standard of `just and reasonable' it is the result
reached not the method employed which is controlling''); Permian,
390 U.S. at 776-77 (``rate-making agencies are not bound to the
service of any single regulatory formula; they are permitted, unless
their statutory authority otherwise plainly indicates, `to make the
pragmatic adjustments which may be called for by particular
circumstances,' '' citing FPC v. Natural Gas Pipeline Co., 315 U.S.
at 586).
    \580\ Bluefield Water Works and Improvement Co. v. Public
Service Commission, 262 U.S. 679, 692-93 (1923) (Bluefield) (``[a]
public utility is entitled to such rates as will permit it to earn a
return * * * equal to that generally being made at the same time and
in the same general part of the country on investments in other
business undertakings which are attended by corresponding risks and
uncertainties; but it has no constitutional right to profits such as
are realized or anticipated in highly profitable enterprises or
speculative ventures. The return should be reasonably sufficient to
assure confidence in the financial soundness of the utility and
should be adequate, under efficient and economical management, to
maintain and support its credit and enable it to raise the money
necessary for the proper discharge of its public duties'').
    \581\ FPC v. Hope Natural Gas Co., 320 U.S. at 603.
    \582\ See Farmers Union, 734 F.2d at 1501.
    \583\ See id. at 1502.
    \584\ Id. P 943 (quoting Mobil Oil Exploration v. United
Distribution Co., 498 U.S. 211, 224 (1991) (Mobil Oil Exploration),
citing FPC v. Hope Natural Gas Co., 320 U.S. 591, 602 (1944); FPC v.
Natural Gas Pipeline Co., 315 U.S. 575, 586 (1942); Permian Basin
Area Rate Cases, 390 U.S. 747, 776-77 (1968) (Permian); FPC v.
Texaco, 417 U.S. 380 (1974) (Texaco)).
    \585\ Mobil Oil Exploration, 498 U.S. at 224, citing FPC v. Hope
Natural Gas Co., 320 U.S. at 602; FPC v. Natural Gas Pipeline Co.,
315 U.S. at 586; Permian, 390 U.S. at 776-77; Texaco, 417 U.S. at
386-89; Mobil Oil Corp. v. FPC, 417 U.S. 283, 308 (1974).
    \586\ Lockyer, 383 F.3d at 1013; Snohomish, 471 F.3d at 1080.
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    408. It is settled law that market-based rates can satisfy the just
and reasonable standard of the FPA and cognate statutes. For example,
as the D.C. Circuit has held, ``when there is a competitive market the
FERC may rely upon market-based prices in lieu of cost-of-service
regulation to assure a `just and reasonable' result.'' \587\ Thus, the
Commission may rely on markets for a just and reasonable rate provided
that it has made the appropriate findings regarding whether sellers
lack market power.
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    \587\ Elizabethtown Gas, 10 F.3d at 870. See also Tejas Power,
908 F.2d at 1004; LEPA, 141 F.3d at 365.
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    409. The Commission exercises its statutory responsibility under
the FPA to ensure that market-based rates are just and reasonable
through the dual requirement of an ex ante finding that the seller
lacks or has mitigated both horizontal and vertical market power and
post-approval oversight through reporting requirements and ongoing
monitoring.\588\ In granting market-based rate authorization, the
Commission thoroughly examines an applicant's market power in the
relevant geographic markets. An examination of both horizontal
(generation market share) and vertical (transmission and other barriers
to entry) market power in the relevant markets gives the Commission
assurance that the seller cannot increase price by restricting supply
or denying customers access to alternative suppliers. When the
Commission determines that a seller lacks or has mitigated market
power, it is making a determination that the resulting rates will be
established through competitive forces, not the exercise of market
power, and thus will fall within a zone of reasonableness which
protects customers against excessive rates, on the one hand, but allows
the seller the opportunity to recover costs and earn a reasonable rate
of return, on the other hand. This is fully consistent with the
fundamental rate principles set forth in Hope and Bluefield, supra, and
their progeny. In addition, in developing its market-based rate regime,
the Commission has taken into account non-cost factors, recognized as
appropriate by the courts, associated with greater reliance on
competition; specifically, where sellers do not have market power, the
Commission believes it can encourage greater market entry, greater
efficiency and greater innovation in meeting the nation's power needs
through allowing such sellers a competitively set rate.
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