generating capacity, and Demand Side Management to maintain Contingency
Reserves in compliance with Reliability Standards; and (4) have
available sufficient generating capacity, Demand Side Management, and
frequency response to maintain Regulating Reserves and Operating
Reserves in compliance with Reliability Standards.\232\ It is the
interconnection and coordination between balancing authority areas that
provides a foundation for the Commission to analyze transmission
limitations and other transfers of energy and provides a reasonable
measure of the relevant geographic market under typical circumstances.
---------------------------------------------------------------------------

    \230\ See ``Glossary of Terms Used in Reliability Standards,''
at http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp
.

    \231\ See Basic Operating Functions and Responsibilities: A
White Paper by the Control Area Criteria Task Force.http://www.maac-rc.org/reports/documents/cactf_reliability_model_whitepaper_v2.pdf
.

    \232\ See Approved Reliability Standards. http://www.ferc.gov/industries/electric/indus-act/reliability/standards.asp
.

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

    252. The Commission adopts in this Final Rule ``balancing authority
area,'' instead of ``control area.'' We believe that such a change will
align the Commission's rules with NERC's Functional Model, thus helping
to avoid confusion.
c. Additional Guidelines for Alternative Geographic Market and
Flexibility
Commission Proposal
    253. In the NOPR, the Commission proposed to continue to provide
flexibility by allowing sellers and intervenors to present evidence
that the market is smaller or larger than the default market. The
Commission explained that when assessing an expanded geographic market
pursuant to the horizontal analysis, it looks for assurance that no
frequently recurring physical impediments to trade exist within the
expanded market that would prevent competing supply in the expanded
area from reaching wholesale customers. The Commission stated that any
proposal to use an expanded market should include a demonstration
regarding whether there are frequently binding transmission constraints
during historical seasonal peaks examined in the screens and at other
competitively significant times that prevent competing supply from
reaching the customers within the expanded market. The Commission
proposed to require that such a demonstration be made based on
historical data, and said it would require that a sensitivity analysis
be performed analyzing under what circumstances transmission
constraints would bind.
    254. The Commission explained that it also considers whether there
is other evidence that would support the existence of an expanded
market, such as evidence that customers can access the resources
outside of the default geographic market on similar terms and
conditions as those inside the default geographic market. It stated
that such evidence could be empirical or it could point to factors that
indicate a single market. It noted that the Commission has previously
stated that the operation of a single central unit commitment and
dispatch function for the proposed geographic market would be an
indicator of a single market, but that other evidence of a single
market could include a demonstration that: There is a single
transmission rate; there is a common OASIS platform for scheduling
transmission service across separate control areas; or there is a
correlation of price movements between the areas being considered as an
expanded geographic market or other information regarding wholesale
transactions in the proposed single market. The Commission stated that
evidence of active trading throughout the proposed geographic market
would also be considered. It stated that in determining whether two or
more control areas are a single market it would weigh, on a case-by-
case basis, all the factors presented. The Commission noted that once
it has been established that historically there were no physical
impediments to trade, there are several factors the Commission would
consider, and no one factor would be dispositive. The Commission sought
comment on this proposed guidance and, in particular, whether there are
other factors it should consider when assessing a proposed expanded
market and whether there are any factors that should be given more
weight or are essential in determining the scope of the market. The
Commission also asked whether it should apply the same criteria when
determining whether the geographic market is smaller than the default
geographic market.
Comments
    255. A number of commenters agree that it is appropriate to provide
sellers flexibility in presenting evidence that the appropriate
geographic market is broader than the default geographic market.\233\
Several state that greater Commission guidance is needed so that
sellers wishing to argue for a broader market definition have clear
objective criteria and can provide evidence that the Commission will
find probative.
---------------------------------------------------------------------------

    \233\ Indianapolis P&L at 5-6, Puget at 9-11, Ameren at 4-5,
Duke at 23-24, and Avista at 5-7.
---------------------------------------------------------------------------

    256. Puget submits that the examples listed in the NOPR provide
some guidance but are still too general to be of use to a seller
submitting a new market power study. It states that the Commission
should: (1) Provide additional guidance on the levels of price
convergence and trading activity across a proposed alternative market
that will support a seller's filing; (2) be more specific regarding the
level of transmission constraints that will preclude a finding of an
expanded

market; and (3) not rely heavily, if at all, on transmission operation
factors--such as common OASIS or common unit commitment and dispatch--
that are not necessarily indicative of a common market.\234 \
---------------------------------------------------------------------------

    \234\ Puget at 9-11.
---------------------------------------------------------------------------

    257. Southern states that the Commission's proposed focus on
evidence pertaining to frequently binding transmission constraints for
purposes of considering a larger geographic market seems appropriate.
However, Southern argues that the NOPR's apparent requirement of
additional evidence (beyond the absence of transmission constraints) to
support a larger geographic market is unnecessary. Moreover, Southern
submits that evidence of a single unit commitment and dispatch
function, a single transmission rate, and a common OASIS platform is
not likely to exist in the absence of an RTO or ISO. Accordingly,
making such evidence a requirement for a larger geographic market would
render illusory the opportunity for expansion for non-RTO/ISO
sellers.\235 \
---------------------------------------------------------------------------

    \235\ Southern at 24-25.
---------------------------------------------------------------------------

    258. Avista agrees that the absence of these factors does not
necessarily mean that a market contains impediments to trading or that
wholesale customers are unable to secure supply from alternative
sources. Avista supports the Commission's proposal to state what type
of evidence demonstrates active trading throughout the proposed
geographic market. Avista submits that a regional geographic market
could and should be established based upon: (1) The presence of an
actively traded liquid trading hub within the relevant defined market
area; (2) transparent pricing information from that hub being widely
available; and (3) the presence of extensive direct or single-wheel
transmission access, both for sellers into the competitive hub market
and for buyers' access to the hub market for purposes of serving
load.\236\
---------------------------------------------------------------------------

    \236\ Avista at 5-7.
---------------------------------------------------------------------------

    259. Powerex supports the Commission's initial specification of
evidence that may be used to support a demonstration of a broader or
smaller geographic market. However, Powerex is concerned that the
Commission's enumeration of relevant categories of evidence is at
present a partial list, and is not sufficiently comprehensive to
address the unique circumstances that are likely to be present in
various regions. Powerex states that the Commission should clarify that
additional types of evidence may also be used to support the propriety
of a broader or smaller market definition.
    260. One commenter states that the appropriate definition of the
relevant geographic market can be (and very often will be)
conditional--that is, when there are no binding transmission
constraints on imports into the relevant control area, the relevant
market appropriately encompasses a broader area than the default
geographic market; and when transmission constraints into the control
area are binding, the control area is the appropriate geographic
market. Accordingly, sellers should be allowed (or encouraged) to
present analytical results for several market definitions, dependent on
the existence or nonexistence of binding transmission constraints, to
sharpen the focus on when market power might be a real concern.\237\
---------------------------------------------------------------------------

    \237\ Dr. Pace at 15-16.
---------------------------------------------------------------------------

    261. APPA/TAPS generally agree that the factors set forth by the
Commission for assessing whether an alternative geographic market is
appropriate are reasonable, but urge that the factors be non-exclusive
and non-prescriptive. In addition to the factors the Commission
identified in the NOPR, APPA/TAPS suggest that a seller be allowed to
point to any joint transmission planning and coordinated construction
processes as evidence that the relevant market should be larger than
its own control area.\238\ APPA/TAPS state that a seller that is
correctly advancing efforts to expand markets deserves to have that
recognized and a seller that is not undertaking such efforts should
live with the consequences of the resulting smaller market.
---------------------------------------------------------------------------

    \238\ APPA/TAPS at 54.
---------------------------------------------------------------------------

    262. PPL states that if the Commission is to consider the potential
existence of geographic markets smaller or larger than a control area,
it should carefully consider the specific circumstances surrounding the
control area of concern, and use an objective review process. That is,
the Commission should consider these factors through the following
means: (1) Evaluation of the historical frequency of, and times when,
physical transmission constraints limit the ability to transmit power
within and between control areas, RTOs, and other defined regions
within which electricity system supply and demand are balanced in real-
time; (2) consideration of correlations of electricity prices, and
electricity price day-to-day changes, within and between control areas,
RTOs, and other defined regions within which electricity supply and
demand are balanced in real time; (3) reference to historical evidence
of actual transactions (including swaps/exchanges, etc.) wherein power
is delivered within, imported to, or exported from, control areas, RTOs
and sub-regions of RTOs; and (4) consideration of operational paradigms
for obtaining transmission services and the extent to which the system
allows for transparent access to transmission services.\239\
---------------------------------------------------------------------------

    \239\ PPL at 2-6.
---------------------------------------------------------------------------

    263. Several commenters urge the Commission to provide flexibility
by suggesting a trading hub for an alternative geographic market. E.ON
U.S. and PNM/Tucson state that the Commission should take regional
commercial patterns into account when evaluating proposals to use a
larger or smaller market, and they support allowing a seller to present
a market power analysis specific to a trading hub.\240\
---------------------------------------------------------------------------

    \240\ E.ON U.S. at 14-15, PNM/Tucson at 8-10.
---------------------------------------------------------------------------

    264. Indianapolis P&L asks that the Commission clarify that sellers
can propose different geographic definitions in their screen analyses.
Indianapolis P&L states that the NOPR is unclear as to whether
different geographic markets can be proposed for the indicative screen
analyses or only for additional, ``second stage'' analyses, such as the
DPT.\241\
---------------------------------------------------------------------------

    \241\ Indianapolis P&L at 5-6.
---------------------------------------------------------------------------

    265. Powerex seeks clarification on how the definition of ``home
control area'' (the control area where the seller is located) applies
to an entity that has small-volume contracts in multiple control areas
remote from its physical location. Powerex asks whether contracts with
third parties, to the extent they confer some level of ``control,''
create a multitude of home control areas. Powerex seeks additional
guidance, including whether the answer to the question depends on the
quantity of generation available under each contract, the level of
control, whether the seller is affiliated with the transmission
provider in that control area, or the remoteness of the contracted
generation from the sellers' physical location.\242 \
---------------------------------------------------------------------------

    \242\ Powerex at 13-17.
---------------------------------------------------------------------------

    266. Duke requests clarification of whether first-tier markets,
which are part of a larger RTO/ISO market (with an energy market that
has central commitment and dispatch and Commission-approved market
monitoring and mitigation) can be represented as the entire RTO/ISO
market. For example, in the case of the Duke Energy Carolinas' control
area, which is directly interconnected to the AEP transmission system,
Duke queries

whether all of PJM would be the relevant first-tier market for purposes
of determining the simultaneous import limitations into the Duke Energy
Carolinas control area.\243\
---------------------------------------------------------------------------

    \243\ Duke at 28.
---------------------------------------------------------------------------

Commission Determination
    267. As an initial matter, we acknowledge the desire for the
Commission to provide greater guidance to sellers wishing to argue for
a broader or smaller market definition. We continue to believe that
default geographic markets are adequate and sufficient for the typical
situation. However, defaults may not be appropriate in all
circumstances. Therefore, we will attempt to provide additional
guidance and clarification to help inform market participants regarding
the factors we believe are significant to consider when defining the
market.\244\
---------------------------------------------------------------------------

    \244\ Although the following discussion generally refers to an
expanded market (i.e., arguing that two or more default geographic
markets constitute a single market) the same guidance is applicable
for arguing that the market is smaller than the default geographic
market (e.g., a load pocket).
---------------------------------------------------------------------------

    268. First, we reiterate that reaching beyond the default
geographic market in which an entity is located can mean addressing
additional physical and other challenges than when trading within that
market. When assessing an alternative geographic market, the Commission
looks for assurance that no frequently recurring physical impediments
to trade exist within the alternative geographic market that would
prevent competing supply in the alternative geographic market from
reaching wholesale customers. Any proposal to use an alternative
geographic market (i.e., a market other than the default geographic
market) must include a demonstration regarding whether there are
frequently binding transmission constraints during historical seasonal
peaks examined in the screens and at other competitively significant
times that prevent competing supply from reaching customers within the
proposed alternative geographic market. We will require that a
demonstration be made based on historical data and that a sensitivity
analysis be performed analyzing under what circumstances transmission
constraints would bind. If the seller fails to show that there are no
frequently binding constraints at these critical times, then the
Commission may not consider other evidence of an expanded market since
we regard this as a necessary condition that must be satisfied to
justify an expanded market.
    269. The Commission also considers whether there is other evidence
that would support the existence of an alternative geographic market.
In deciding whether customers may be considered as part of an expanded
geographic market, the Commission will consider evidence that they can
access the resources outside of the default geographic market on
similar terms and conditions as those inside the default geographic
market.
    270. Any such evidence submitted to show that the seller's
customers have access to resources outside of their balancing authority
area at terms and conditions similar to those at which they can access
resources inside the balancing authority area could be empirical or it
could point to factors that indicate a single market. For example, the
Commission has previously stated that the operation of a single central
unit commitment and dispatch function for the proposed geographic
market would be an indicator of a single market. However, there are
other ways to demonstrate that two or more balancing authority areas
are indeed a single market. For example, other evidence of a single
market could include a demonstration that: there is a single
transmission rate; there is a common OASIS platform for scheduling
transmission service across separate balancing authority areas; or
there is a correlation of price movements between the areas being
considered as an expanded geographic market or other information
regarding wholesale transactions in the proposed single market.
Evidence of active trading throughout the proposed geographic market
would also be considered.
    271. In determining whether two or more balancing authority areas
are a single market, the Commission would weigh, on a case-by-case
basis, all relevant factors presented. As discussed above, there are
several factors the Commission would consider once it has been
established that historically there were no physical impediments to
trade, and no one factor or factors would be dispositive. Rather, all
factors will be considered and as a whole will indicate whether there
exists a single market.\245\
---------------------------------------------------------------------------

    \245\ We agree with Powerex that the Commission's enumeration of
relevant factors it would consider is not an exhaustive list. As
stated above, no comprehensive list of factors captures all factors
that could indicate a single market. Accordingly, the Commission
will consider additional types of evidence that may be presented on
a case-by-case basis.
---------------------------------------------------------------------------

    272. With regard to Puget's request that the Commission provide
additional guidance with regard to the levels of price convergence,
trading activity, and transmission constraints that define a market, no
such generic finding will encompass all possibilities and, therefore,
in all instances define the market. Accordingly, we will not attempt to
do so here.
    273. We also reject Southern's contention that the Commission has
somehow rendered ``illusory'' the opportunity for entities outside RTOs
and ISOs to demonstrate a larger geographic market.\246\ The examples
provided by the Commission of ways an entity could demonstrate a larger
geographic market were just that: examples.\247\ The Commission does
not require an entity proposing an alternative geographic market to
provide evidence other than historical transmission access. Sellers and
intervenors in both RTO/ISO and non-RTO/ISO markets may present any
probative evidence based on historical data of transmission
availability, wholesale sales, resource accessibility, and market
prices.
---------------------------------------------------------------------------

    \246\ Southern at 25.
    \247\ Thus, we agree with Avista that expansion of the
geographic market is not limited to only those instances where there
is either: a single transmission rate; a common OASIS; or operation
of a single central unit commitment and dispatch function.
---------------------------------------------------------------------------

    274. In response to Indianapolis Power & Light's comments, we
clarify that when a seller submits its screen analysis, it can also
propose an alternative analysis based on the use of a geographic market
larger than the default geographic market. However, such proposal
should be made in addition to, not in lieu of, the screen analysis
based on the default geographic market.
    275. With regard to using trading hubs as alternative market areas,
the Commission understands that numerous electricity trading hubs have
emerged over the past few years. A trading hub is a representative
location at which multiple sellers buy and sell power and ownership
changes hands, typically with trading of financial and physical
products. For physical trades, the hub may represent a specific
delivery point or set of points. Currently only select trading hubs
account for the majority of physical power trading although there
remains the possibility that market demand could initiate trading hubs
for each balancing authority area. In evaluating market power, however,
trading hub data alone does not provide a foundation for the Commission
to analyze transmission limitations and other transfers of energy.
Moreover, with regard to trading hubs, the combination of physical and
diverse financial products, the low barriers for

entry of new participants, and the unlimited potential for resale of
limited physical output may not provide a reasonable measure of the
relevant geographic market under typical situations, as a balancing
authority area does. Therefore, while trading data may be considered in
the illustration of relevant price correlation or of liquid trading
activity to demonstrate that two or more balancing authority areas are
indeed a single market, the Commission will not allow use of a trading
hub to define a relevant geographic market.
    276. With regard to one commenter's suggestion that the Commission
should allow (or encourage) sellers to present analytical results for
several market definitions because the appropriate definition of the
relevant geographic market can be conditioned on the existence or
nonexistence of binding transmission constraints, the Commission agrees
in principle. The Commission provides an opportunity for sellers who
fail one or more of the initial screens to present a more thorough
analysis using the DPT. As the April 14 Order states ``the [DPT]
defines the relevant market by identifying potential suppliers based on
market prices, input costs, and transmission availability, and
calculates each supplier's economic capacity and available economic
capacity for each season/load condition.'' \248\ In addition, in the
Merger Policy Statement the Commission stated that the flows on a
transmission system can be very different under different supply and
demand conditions (e.g. peak vs. off-peak). Consequently, the amount
and price of transmission available for suppliers to reach wholesale
buyers at different locations throughout the network can vary
substantially over time. If this is the case, the DPT analysis should
treat these narrower periods separately and separate geographic markets
should be defined for each period.\249\
---------------------------------------------------------------------------

    \248\ AEP Power Marketing, Inc., 107 FERC ] 61,018 at P 106.
    \249\ Merger Policy Statement, FERC Stats. & Regs. Regulations
Preambles July 1996-December 2000 ] 31,044 at 30,132.
---------------------------------------------------------------------------

    277. The Commission believes that the DPT can address the dynamic
nature of markets. Under the DPT, the amount and price of transmission
available for suppliers to reach wholesale buyers at different
locations throughout the network during different season/load
conditions (e.g., peak vs. off-peak) can be analyzed. For example, an
area may become constrained only during the highest load levels, in
which case the relevant geographic market could differ across seasons,
and separate geographic markets could be defined for each period.
However, as discussed earlier, in an effort to provide as much
regulatory certainty as possible, the Final Rule adopts as the default
geographic market the balancing authority area or the RTO footprint, as
applicable, but allows sellers or intervenors to propose alternative
markets based on historical transmission and sales data.
    278. We clarify in response to Powerex that sellers should do
market power studies for each balancing authority area where they own
or control assets (i.e., should study all balancing authority areas
where generation assets they own or control are located) regardless of
the quantity or location of generation they control (subject to the
terms adopted herein regarding Category 1 sellers). Also, to the extent
a market power study is required, sellers should study each balancing
authority area where they own or control assets regardless of whether
the seller is affiliated with the transmission provider in that
balancing authority area. The Commission also clarifies for Duke that
if the first-tier markets for a seller (whether or not the seller is a
member of the RTO) are part of a larger RTO/ISO market, all of the RTO/
ISO market would be a relevant first-tier market for purposes of
determining the simultaneous import limitations.
d. Specific Issues Related to Power Pools and SPP
Commission Proposal
    279. In the NOPR, the Commission proposed to continue its practice
of designating an RTO/ISO in which a seller is located as the default
relevant geographic market if the RTO/ISO has sufficient market
structure and a single energy market with Commission approved market
monitoring and mitigation.
Comments
    280. A number of commenters urge the Commission to consider power
pools as geographic market areas. Midwest Energy claims that, ``under
current Commission policy, sellers of power in RTOs/ISOs with a full-
fledged single central commitment and dispatch system are allowed to
treat the full RTO footprint as the relevant geographic market, thereby
facilitating qualification for market-based rates. Sellers in a
Commission-approved RTO without a single central commitment and
dispatch system are relegated to a relevant market defined by their own
control area.'' \250\ Midwest Energy urges the Commission to consider
changing its existing policy to create a presumption that the relevant
geographic market for a Commission-approved RTO is the region covered
by a single transmission tariff.\251\ Alternatively, Midwest Energy
states that the Commission could require, in addition to a regional
tariff, the implementation of a Commission-approved market monitor and
a centrally dispatched energy imbalance market. It states that these
changes would allow sellers to treat the Southwest Power Pool (SPP)
region as the relevant geographic market.
---------------------------------------------------------------------------

    \250\ Midwest at 1-3.
    \251\ Midwest at 1-3, 4-8.
---------------------------------------------------------------------------

    281. Westar states that the Commission should find that a
transmission region with a single OATT, non-pancaked transmission
rates, a common OASIS platform for scheduling transmission, and
approved market monitoring (e.g., SPP) presumptively qualifies as a
single region for purposes of the market power screens. Westar states
that although the NOPR identifies single unit commitment and/or
centralized dispatch of generation to be an important characteristic of
a regional market, the Commission has not always done so. For example,
the Commission did not identify this as a defining characteristic when
it accepted other RTOs/ISOs as a single region for market-based rate
purposes, such as New England. The Commission also did not rely upon
centralized dispatch in authorizing market-based power sales across the
California, New York or PJM markets. Westar states that the Commission
should find that SPP meets the criteria for a single market once its
energy imbalance market (EIM) becomes operational.\252\
---------------------------------------------------------------------------

    \252\ Westar at 3-6.
---------------------------------------------------------------------------

    282. In its reply comments, Southwest Coalition disagrees with
those commenters requesting that SPP qualify as a single geographic
region for sellers in its region once its EIM is operational. Southwest
Coalition states that Westar has not presented any evidence for the
Commission to change course with SPP in this rulemaking. It asserts
that SPP currently has underway a variety of market implementation
proceedings, of which Westar is a party, through which the Commission
can make a reasoned decision regarding SPP's status. As such, Southwest
Coalition states that this generic rulemaking proceeding is not the
appropriate vehicle for considering Westar's request. In addition,
Southwest Coalition states that Westar's request represents an improper
request for rehearing of the Commission's March 20, 2006 Order in

SPP's market implementation proceeding. Southwest Coalition requests
that, if the Commission were to consider Westar's request in this
proceeding, the Commission should reject Westar's request for a
Commission finding that SPP is a single geographic region for purposes
of the Commission's market power screens.\253\
---------------------------------------------------------------------------

    \253\ Southwest Industrial Customer Coalition reply comments at
2-9.
---------------------------------------------------------------------------

    283. Puget argues that applying the control area default to
utilities in the Pacific Northwest is arbitrary, and does not result in
an accurate measurement of a seller's potential market power in the
region's energy markets. According to Puget, the relevant geographic
market for the purpose of measuring horizontal market power in the
Pacific Northwest is the United States portion of the Northwest Power
Pool, which is dominated by a transmission system operated by
Bonneville Power Administration. Puget submits that many of the
criteria outlined in the NOPR--particularly those addressing parallel
price movements, single transmission rates, and active trading--are met
in this geographic region. Utilities in the Pacific Northwest would
like to have the opportunity to make a showing to the Commission that
the relevant geographic market for measuring market power in their
region is an area other than their home and first-tier control
areas.\254\
---------------------------------------------------------------------------

    \254\ Puget at 9-11.
---------------------------------------------------------------------------

Commission Determination
    284. We decline to address whether additional regions of the
country qualify as relevant geographic markets. Through this Final
Rule, we set forth several examples of criteria that sellers can use in
proposing an alternative geographic market. Individual sellers can
challenge our default geographic market and provide evidence to support
their proposal. Intervenors will have the opportunity to comment prior
to the Commission rendering a decision.
e. RTO/ISO Exemption
Commission Proposal
    285. In the April 14 Order, the Commission concluded that it would
no longer exempt sellers located in markets with Commission-approved
market monitoring and mitigation from providing generation market power
analyses, on the basis that requiring sellers located in such markets
to submit screen analyses provides an additional check on the potential
for market power.\255\ The Commission did not address this point in the
NOPR.
---------------------------------------------------------------------------

    \255\ 107 FERC ] 61,018 at P 186. The Commission had previously
stated that all sales, including bilateral sales, into an ISO or RTO
with Commission-approved market monitoring and mitigation would be
exempt from the Supply Margin Assessment test and, instead, would be
governed by the specific thresholds and mitigation provisions
approved for the particular market. AEP Power Marketing, Inc., 97
FERC ] 61,219 at P 176 (2001).
---------------------------------------------------------------------------

Comments
    286. In their comments in this proceeding, Reliant, NRG and
FirstEnergy urge the Commission to reinstate the exemption.\256\
Reliant states that reinstating the exemption would be appropriate
because real-time market monitoring by an independent market monitor
consistent with Commission-approved rules and Commission-approved
targeted mitigation address identification of market power concerns as
well as mitigation of market power in those markets and, therefore,
eliminate the value of any separate market power analysis submitted by
an individual seller. Reliant states that Commission-approved market
monitoring and mitigation provide the Commission with a better and more
sophisticated picture of market power issues in RTO/ISO markets as
compared to a seller's market power analysis, which looks only at
market power at a fixed moment in time.
---------------------------------------------------------------------------

    \256\ Reliant at 6-7; NRG at 7; and FirstEnergy at 33.
---------------------------------------------------------------------------

    287. Reliant states that if the Commission decides not to reinstate
the exemption, it is critical that the Commission continue to use RTO/
ISO markets as the default geographic market for sellers with
generation located in those markets. Reliant states that the key to the
determination of relevant geographic markets is the extent to which
sellers can compete in the defined market. RTO/ISO markets with
centralized markets provide a platform for all sellers located in the
pertinent RTO/ISO market to compete. Thus, Reliant states that it is
entirely appropriate to consider such markets as the default market
unless and until an intervenor can show that this is no longer
appropriate (e.g., due to transmission constraints).\257\
---------------------------------------------------------------------------

    \257\ Reliant at 6-7.
---------------------------------------------------------------------------

    288. In its reply comments, PSEG states that while it believes that
the RTO/ISO exemption would be warranted at least for regions with
pervasive market monitoring unit (MMU) oversight such as PJM, it
recognizes that some affected parties may not be comfortable with a
blanket exemption. It suggests that the Commission's regulations should
take account of the fact that the Commission has approved comprehensive
MMU oversight of markets and that MMUs take their duties seriously and
routinely exercise their authority. Accordingly, PSEG proposes that
evidence of active MMU oversight supply the basis for obviating the
need to conduct a market power study for a particular zone or sub-zone
of an RTO or ISO.\258\
---------------------------------------------------------------------------

    \258\ PSEG reply comments at 5-6.
---------------------------------------------------------------------------

    289. APPA/TAPS, in contrast, state that reinstating the RTO/ISO
exemption would represent an abdication of the Commission's
responsibilities.\259\
---------------------------------------------------------------------------

    \259\ APPA/TAPS reply comments at 2-3.
---------------------------------------------------------------------------

Commission Determination
    290. The Commission declines the request that it reinstate the pre-
April 14 Order exemption for sellers located in markets with
Commission-approved market monitoring and mitigation from providing
generation market power analyses. The Commission will continue to
require generation market power analyses from all sellers, including
those in RTO/ISO markets. All sellers are required to receive
authorization from the Commission prior to undertaking market-based
rate sales, and as discussed herein, all new applicants for market-
based rate authority are required to, among other things, provide a
horizontal market power analysis. The first step for a seller seeking
market-based rate authority is to file an application to show that it
and its affiliates do not have, or have adequately mitigated, market
power. Sellers can refer to RTO/ISO monitoring and mitigating as a
factor. We believe that a single market with Commission-approved market
monitoring and mitigation and transparent prices provides added
protection against a seller's ability to exercise market power but
cannot replace the generation market power analysis.
    291. To address Reliant's concern, we note that, as discussed
above, we will use RTO/ISO markets (including Commission findings with
regard to RTO/ISO submarkets) as the default geographic market for the
indicative screens for sellers with generation in those markets.
8. Use of Historical Data
Commission Proposal
    292. The Commission proposed in the NOPR to retain the ``snapshot
in time'' approach for the indicative screens, so that sellers are
required to use the most recently available unadjusted 12 months'
historical data. The

Commission stated that historical data are more objective, readily
available, and less subject to manipulation than future projections.
The Commission proposed to continue to permit sellers to make
adjustments to data that are essential to perform the indicative
screens provided that the seller fully justifies the need for the
adjustments, justifies the methodology used, provides all workpapers in
support, and documents the source data.
    293. However, the Commission proposed to allow, for the DPT
analysis, sellers and intervenors to account for changes in the market
that are known and measurable at the time of filing.\260\ The
Commission noted that this proposal mirrors the Commission's approach
in connection with its merger analysis. Sellers and intervenors
proposing known and measurable changes to be considered in the DPT
analysis would bear the burden of proof for their adjustments to
historical data. The Commission sought comment on whether the
Commission should provide a limitation on the time period past the
historical test period for which sellers can account for changes, what
that time period should be, and how flexible or inflexible that
limitation should be. In addition, the Commission sought comment on
exactly what types of changes should be allowed and under what
circumstances.
---------------------------------------------------------------------------

    \260\ See 18 CFR 35.13(a).
---------------------------------------------------------------------------

Comments
    294. Various commenters generally support the Commission's proposal
to use historical data for the indicative screens and allow known and
measurable changes for the DPT.\261\ Some suggestions made as to what
should be considered known and measurable changes include: Allowing
only changes that occur between updated market power analysis filings
\262\ and allowing only publicly available data or company
information.\263\ Powerex expresses concern that known and measurable
changes may not be publicly available.\264\ PG&E suggests that the
Commission evaluate on a case-by-case basis whether the seller or
intervenor can prove that the change is both foreseeable and
reasonable. It says that the Commission should not impose a time
restriction on such changes provided that the seller provides the
necessary support for changes that it claims are known and
measurable.\265\
---------------------------------------------------------------------------

    \261\ See, e.g., EEI at 23, PPL at 17-19; Powerex at 18-19.
    \262\ See, e.g., Ameren at 6. Ameren proposes that if a seller
chooses to rely on an historical period with no changes, the
Commission should honor that choice and not allow intervenors to
introduce suggested known and measurable changes. Conversely, if a
seller proposes to adjust the historical period for certain known
and measurable changes, Ameren states that the Commission should
permit intervenors to introduce competing known and measurable
changes. Id. at 6-7.
    \263\ Drs. Broehm and Fox-Penner at 12-13 (any adjustments to
historical base year must be known and measurable at the time of
filing; new capacity additions should only be accounted for if they
are on-line or under construction).
    \264\ Powerex at 18-19.
    \265\ PG&E at 9-10.
---------------------------------------------------------------------------

    295. A number of commenters suggest that sellers should be
permitted to account for known and measurable changes in both the
indicative screens and the DPT.\266\ Southern states that the
Commission ``should not * * * restrict the ability of parties to
provide the Commission with the best possible information and
analysis.'' \267\ Duke states that in all instances the objective
should be to obtain the most accurate and timely assessment of the
seller's ability to exercise market power under current market
conditions.\268\
---------------------------------------------------------------------------

    \266\ PG&E at 2; Southern at 25-26; Duke at 26; NRECA at 21-23.
    \267\ Southern at 26.
    \268\ Duke at 26.
---------------------------------------------------------------------------

    296. NRECA states that the screens should incorporate imminent
changes and that an example of known and measurable changes that should
be included in initial applications and triennial filings is the
capacity freed up by expiring long-term contracts. It submits that
these contracts will expire on a known schedule and, if the market is
competitive, the seller should not be allowed to assume that the
capacity will remain committed to the buyer.\269\
---------------------------------------------------------------------------

    \269\ NRECA at 21-23. See also APPA/TAPS at 13-15.
---------------------------------------------------------------------------

    297. PPL argues that long-term contracts should retain the current
definition as those expiring in one year or more, and recommends not
considering contracts that take effect after one year but before the
triennial update is due. It argues that buyers could withhold signing
contracts and force a market power finding. PPL also notes that a
notice of change in status must be filed at the expiration of contracts
that increase the seller's capacity by 100 MW or more and that the
Commission can initiate a section 206 investigation at that point if
need be.\270\
---------------------------------------------------------------------------

    \270\ PPL reply comments at 3-4.
---------------------------------------------------------------------------

Commission Determination
    298. We will continue to require the use of historical data for
both the indicative screens and the DPT in market-based rate cases. The
indicative screens are designed as a tool to identify those sellers
that raise no generation market power concerns and can otherwise be
considered for market-based rate authority. Accordingly, the indicative
screens are conservative in nature and not generally subject to debates
over projected data, which may unnecessarily prolong proceedings and
create regulatory uncertainty. However, in light of adopting a regional
approach with regard to regularly scheduled updated market power
analyses, we will require the use of the actual historical data for the
previous calendar year. Requiring all sellers in a region to provide
analyses using the same data set further enhances the Commission's
ability to evaluate market power and identify any discrepancies between
market studies.
    299. After careful consideration of the comments received, the
Commission will not adopt the NOPR proposal that the DPT analysis allow
sellers and intervenors to account for changes in the market that are
known and measurable at the time of filing. Instead, the Commission
will adopt its current practice that sellers are required to use, in
the preparation of a DPT for a market-based rate analysis, unadjusted
historical data and, consistent with the above discussion, the
Commission will require the use of the actual historical data for the
previous calendar year. The Commission has stated that historical data
are more objective, readily available, and less subject to manipulation
than future projections.
    300. We acknowledge that the Commission's approach in its merger
analysis requires applicants and intervenors to account for changes in
the market that are known and measurable at the time of filing.
However, we find that the purpose of using the DPT in market-based rate
proceedings is different from that in merger analysis. Intrinsically, a
merger analysis is forward-looking to identify what effect, if any,
there will be on competition if the proposed merger is consummated.
Even though the Commission has the ability to reopen a merger
proceeding under its section 203(b) authority, it is difficult and
costly to undo a merger, so the Commission is cognizant of the need to
analyze what might happen as a result of a proposed merger and put any
necessary mitigation in place prior to consummation of the merger.
    301. In contrast, the market-based rate analysis is a ``snapshot in
time'' approach. When the Commission evaluates an application for
market-based rate authority, the Commission's focus is on whether the
seller passes both of the indicative screens based on unadjusted
historical data. Likewise,

when a seller fails one of the screens and the Commission evaluates
whether that seller passes the DPT, the Commission's focus is on
whether the seller passes the DPT based on unadjusted historical data.
The Commission's grant of market-based rate authority is conditioned,
among other things, on the seller's obligation to inform the Commission
of any change in status from the circumstances the Commission relied
upon in granting it market-based rate authority. As such, the
Commission's market-based rate program is designed to require sellers
to report, and enable the Commission to examine, changes in facts and
circumstances on an ongoing basis. Such a reporting requirement
provides the Commission with ongoing monitoring in addition to its
right to require any market-based rate seller to provide an updated
market power analysis at any time. Accordingly, the market-based rate
change in status reporting requirement allows the Commission to
evaluate changes when they actually happen rather than relying on
projections, making it unnecessary and redundant for the Commission to
allow sellers to account for known and measurable changes in the DPT
for market-based rate purposes. For these reasons and the reasons
explained in the April 14 and July 8 Orders and existing Commission
precedent, the Commission reaffirms that the indicative screens and DPT
analyses should be based on unadjusted historical data.
9. Reporting Format
Commission Proposal
    302. In the NOPR, the Commission proposed to require all sellers to
submit the results of their indicative screen analysis in a uniform
format to the maximum extent practicable and appended a proposed
format. This format, provided in Appendix C of the NOPR, was intended
to promote consistency and aid the Commission in the decision-making
process. The Commission sought comment on this proposal.
Comments
    303. Although only a few comments were received on this topic,
those comments support the proposal to adopt a uniform reporting format
for the indicative screens. APPA/TAPS suggest that the proposed uniform
format should help all market participants, especially when assessing
the filings of a number of public utilities as part of the proposed
regional review process. APPA/TAPS state that the uniformity should
also help the Commission analyze market-based rate filings on a
consistent basis, thus increasing market participant confidence in
those assessments.\271\ Other commenters concur with the Commission's
proposal for a uniform reporting format. They state that a uniform
reporting format will increase consistency and thus aid the Commission
in its decision making process.\272\
---------------------------------------------------------------------------

    \271\ APPA/TAPS at 35.
    \272\ Drs. Broehm and Fox-Penner at 12.
---------------------------------------------------------------------------

    304. One commenter suggests formatting and presentation changes to
the NOPR's Appendix C reporting form. These changes include creating
sections for items such as the calculation of seller and market
uncommitted capacity and rearranging some in a more logical
fashion.\273\
---------------------------------------------------------------------------

    \273\ Dr. Pace at 8-9.
---------------------------------------------------------------------------

Commission Determination
    305. We will adopt the reporting format as proposed in the NOPR,
maintaining the same order of items as in the form provided in Appendix
C of the NOPR, but note that this form now appears as Appendix A of
this Final Rule. We believe standardizing the submission format has
benefits to all market participants. As noted, it appears that
commenters as well are generally supportive of this proposal to require
all sellers to submit the results of their indicative screen analyses
in a uniform format.
    306. Also, we will adopt many of the formatting changes suggested
in the comments. The row letter will be the first column and a better
delineation of sections will increase the comprehensibility of the
form. The revised form can be found in Appendix A.\274\
---------------------------------------------------------------------------

    \274\ The ``Workpapers'' column is meant to provide an easy way
to find sources and ensure that all submissions are properly
sourced. Hence, the items in that column (e.g., ``Workpaper 5'')
were merely meant to be illustrative and do not require that
information be submitted on specific workpapers or that workpapers
be submitted in a particular order.
---------------------------------------------------------------------------

10. Exemption for New Generation (Formerly Section 35.27(a) of the
Commission's Regulations)
a. Elimination of Exemption in Section 35.27(a)
Commission Proposal
    307. The Commission's regulations provide that any public utility
seeking authorization to engage in market-based rate sales is not
required to demonstrate a lack of market power in generation with
respect to sales from capacity for which construction commenced on or
after July 9, 1996.\275\ In the NOPR, the Commission noted that when it
established the exemption in Order No. 888 it indicated that it would
consider whether a seller citing Sec.  35.27(a) nevertheless possesses
horizontal market power if specific evidence is presented by an
intervenor.\276\
---------------------------------------------------------------------------

    \275\ 18 CFR 35.27(a). The regulation reads: ``Notwithstanding
any other requirements, any public utility seeking authorization to
engage in sales for resale of electric energy at market-based rates
shall not be required to demonstrate any lack of market power in
generation with respect to sales from capacity for which
construction has commenced on or after July 9, 1996.
    \276\ NOPR at P 67.
---------------------------------------------------------------------------

    308. The Commission stated in the NOPR that although it remains
committed to encouraging new entry of generation, it is concerned that
the continued use of the Sec.  35.27(a) exemption may become too broad
and, over time, would encompass all market participants as all pre-July
9, 1996 generation is retired. Accordingly, the Commission proposed in
the NOPR to eliminate the exemption in Sec.  35.27(a) and to require
that all new sellers seeking market-based rate authority on or after
the effective date of the Final Rule and all sellers filing updated
market power analyses on or after the effective date of the Final Rule
must provide a horizontal market power analysis of all of their
generation, whether or not it was built after July 9, 1996. Because the
Commission allows a seller to make simplifying assumptions where
appropriate and to submit a streamlined analysis, the Commission
explained that any additional burden imposed on sellers by this reform
would be minimal. In addition, the Commission anticipated that those
entities that otherwise would have relied on the exemption would, in
most cases, qualify as Category 1 sellers and therefore no longer be
required to file updated market power analyses as a routine matter. The
Commission sought comment on this proposal.
Comments
    309. Many commenters support the Commission's proposed elimination
of the Sec.  35.27(a) exemption, stating that there should be a level
playing field for market-based rate sellers so that all market
participants would be required to perform the generation market power
screens.\277\ A number of commenters support the Commission's position
that there is a valid concern that over time the exemption would
encompass all generation as older generating units are

retired and new generation is built.\278\ Several commenters state that
the Commission correctly observes that the indefinite continuation of
the exemption would ultimately result in the automatic grant of market-
based rate authority to all sellers as pre-1996 generation is
retired.\279\ They further state that eliminating the exemption will
not impose significant new burdens, deter new entry into a market, or
create any unreasonable disincentive or impediment for the construction
of future generating capacity.\280\ Contrary to the assertions of
several commenters, FirstEnergy states that the elimination would
encourage merchant power developers to expand generation in markets
where they do not already have a dominant position which, in turn,
would dilute market power concerns in these markets.
---------------------------------------------------------------------------

    \277\ Progress Energy at 2; PG&E at 10; FirstEnergy at 9; TDU
Systems at 2; New Jersey Board at 2; NASUCA at 7; Drs. Broehm/Fox-
Penner at 13.
    \278\ See PG&E at 10; APPA/TAPS at 27; NRECA at 11; Carolina
Agencies at 1.
    \279\ APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1.
    \280\ See FirstEnergy at 10; APPA/TAPS at 27; NRECA at 11;
Carolina Agencies at 1.
---------------------------------------------------------------------------

    310. NRECA and APPA/TAPS maintain that, despite EPSA's, Mirant's,
and PPL's assertions to the contrary,\281\ the Commission did not
create the exemption as an incentive to encourage new generation
investment.\282\ APPA/TAPS elaborates further, agreeing with the
Commission that many new entrants would qualify as Category 1 sellers
and, therefore, would not have to submit updated market power analyses
and that other entrants could make simplifying assumptions to
demonstrate that they qualify for market-based rate authority.\283\
These commenters contend that the benefits of eliminating the exemption
far outweigh any added burdens to ensure that all market participants
are treated equally and to ensure that rates for jurisdictional sellers
are just and reasonable.\284\
---------------------------------------------------------------------------

    \281\ EPSA at 12-13; Mirant at 11; PPL at 19-20.
    \282\ NRECA reply comments at 11; APPA/TAPS reply comments at
16-17.
    \283\ See APPA/TAPS at 27.
    \284\ APPA/TAPS at 27; NRECA at 11; Carolina Agencies at 1.
---------------------------------------------------------------------------

    311. In support of the elimination of the Sec.  35.27(a) exemption,
NASUCA acknowledges that under current procedures, if all the
generation owned or controlled by an applicant for market-based rate
authority and its affiliates in the relevant control area is new
generation, such seller is not required to provide a horizontal market
power analysis because of the exemption under Sec.  35.27(a).\285\
NASUCA asserts that under the current rule, there is no limit on the
amount of post-July 9, 1996 generation that could be exempt from the
Commission's analysis of market power. In addition, a commenter
explains that the potential to exercise market power has no relation to
whether generating plants were built before or after 1996.\286\ ELCON
suggests that generators that were built after July 9, 1996 are capable
of exercising market power.\287\ In addition, FirstEnergy points out
that merchant power plant developers have begun to aggregate fleets of
newer generating plants to which this exemption is applicable, and may
now be able to exercise generation market power.\288\ PG&E adds, ``in
situations where all generation owned or controlled by an applicant and
its affiliates in the relevant market is new generation, should they
control sufficient generation, the applicants and its affiliates may
freely exercise market power.'' \289\ In addition, Morgan Stanley
supports elimination of the exemption, stating that maintaining the
exemption would have unintended consequences going forward.\290\
---------------------------------------------------------------------------

    \285\ NASUCA at 7.
    \286\ Drs. Broehm/Fox-Penner at 13.
    \287\ ELCON at 6.
    \288\ See FirstEnergy at 9-10.
    \289\ PG&E at 10.
    \290\ Morgan Stanley at 13-14.
---------------------------------------------------------------------------

    312. Among those who oppose elimination of the exemption,
Constellation asserts that it would send an unfavorable signal to
market participants that the rules may be changed with a retroactive
effect, which in turn would deter investment.\291\ Constellation also
contends that the Commission offers no support and/or analysis to
demonstrate its inference that older generating units will be retired
in significant quantities to make a substantial difference to the
screening analysis of any seller. PPL submits, among other ill-effects,
that the elimination will deter investment in areas where there is a
limited supply and the new entrant may be deemed pivotal. In addition,
PPL contends that some sellers relied on the presumption that they
would not need to demonstrate a lack of market power in financing,
constructing, and operating their new power plants.\292\
---------------------------------------------------------------------------

    \291\ Constellation at 30.
    \292\ PPL at 19-20.
---------------------------------------------------------------------------

    313. EPSA opposes the elimination of the exemption under Sec.
35.27(a). EPSA states that the electric industry needs incentives for
new generation and does not need disincentives if capital is to be
invested on a timely basis to meet future demand and enhance
competition.\293\ EPSA asserts that the exemption encourages the
development of competitive supply outside of organized markets.\294\
Similarly, NRG contends that the elimination of the Sec.  35.27(a)
exemption will delay and deter investment in load pockets. NRG also
argues that eliminating the exemption runs counter to the Commission's
policy of encouraging investment in electric power infrastructure to
enhance reliability and market liquidity.\295\
---------------------------------------------------------------------------

    \293\ EPSA at 12.
    \294\ EPSA reply comments at 6.
    \295\ NRG at 2.
---------------------------------------------------------------------------

    314. In addition, EPSA argues that the purpose of the exemption was
to encourage new generation investment by competitive suppliers,
especially in areas of the country that are mostly dominated by
utility-owned generation.\296\ Specifically, EPSA explains that it is
in these regions of the country where affiliated generation is largely
treated as native load and, thus, is excluded from the market power
analysis even though it represents most of the capacity in the
region.\297\ EPSA explains that, even if a small increment of
competitive supply is introduced into the market, the analysis might
detect market power when measured against relatively small existing
generation. Therefore, without the exemption, a new competitive
supplier would fail the test and would have to utilize cost-based
rates.\298\
---------------------------------------------------------------------------

    \296\ EPSA at 13.
    \297\ In its reply comments NASUCA disagrees, submitting that
there are other regions where a seller with a fleet of newer
exempted generating plants could exercise market power or bid the
output strategically to drive prices up. NASUCA reply comments at 4-
5.
    \298\ EPSA at 13.
---------------------------------------------------------------------------

    315. Allegheny argues that the Commission overlooks the reason why
it initially adopted the exemption. Allegheny states that, in Order No.
888, the Commission determined that long-term generation markets are
competitive.\299\ Allegheny further argues that ``the Commission cannot
`gloss over' its prior reasoning without discussion, and without
showing that there has been a fundamental change in facts and
circumstances that have [sic] caused long-term markets to be no

longer competitive.'' \300\ PPL asserts that the Commission in Order
No. 888 recognized the power that the opportunity of free entry has to
eliminate market power concerns and stated that open access
advancements removed structural impediments for new entrants competing
with existing market participants.\301\
---------------------------------------------------------------------------

    \299\ Allegheny at 8-9 (citing Promoting Wholesale Competition
Through Open Access Non-discriminatory Transmission Services by
Public Utilities and Recovery of Stranded Costs by Public Utilities
and Transmitting Utilities, Order No. 888, FERC Stats. & Regs.,
Regulations Preambles, January 1991-June 1996 ] 31,036 at 31,657
(1996), order on reh'g, Order No. 888-A, FERC Stats. & Regs.
Regulations Preambles July 1996-December 2000 ] 31,048 (1997), order
on reh'g, Order No. 888-B, 81 FERC ] 61,248 (1997), order on reh'g,
Order No. 888-C, 82 FERC ] 61,046 (1998), aff'd in part and rev'd in
part sub nom. Transmission Access Policy Study Group v. FERC, 225
F.3d 667 (D.C. Cir. 2000), aff'd sub nom. New York v. FERC, 535 U.S.
1 (2002)).
    \300\ Allegheny at 9 (citation omitted).
    \301\ PPL at 20.
---------------------------------------------------------------------------

    316. Mirant and EPSA expand on arguments that eliminating the
exemption will deter investment. They argue that, when reserve levels
are tight in a control area where the host utility has lost or forgone
its market-based rate authority, a competitive supplier would have to
weigh the risks as to whether the Commission would authorize it to make
market-based rate sales if it were to build a new asset in that control
area.\302\ They contend that there is no incentive for a competitive
supplier to build new generation if its sales will be mitigated at some
level of cost-based rates.\303\ In particular, Mirant explains that if
a municipal utility issued a request for proposals (RFP) for 600 MW of
power commencing in 2010 and terminating in 2020, with the current
exemption competitive suppliers could bid on the RFP knowing that the
supplier would be authorized to sell the output of its new generating
station at market-based rates. However, Mirant asserts that if the
exemption were eliminated, a supplier would have to get Commission
approval for market-based rate sales prior to bidding on the RFP. \304\
---------------------------------------------------------------------------

    \302\ Mirant at 11-12; EPSA at 13-14.
    \303\ EPSA at 13; Mirant at 12.
    \304\ Mirant at 11-12. Mirant elaborates: ``In calculating the
pivotal supplier and market share screens, an applicant is allowed
to deduct from its installed capacity the amount of capacity that is
committed under a long-term sale, but the seller is presented with a
Catch-22. The seller cannot enter into a long-term sales contract at
market-based rates without prior Commission authorization, but the
seller cannot pass the applicable indicative screens without
deducting the amount of the capacity sold under long-term contract.
Retaining the exemption eliminates this problem and is consistent
with Commission precedent regarding competitive forward markets.''
Id. at 12.
---------------------------------------------------------------------------

    317. Mirant disagrees with the Commission's contention that
eliminating the exemption would not affect many sellers and that the
cost of compliance would be minimal. Mirant states that five of its
subsidiaries would have to file updated market power analyses if the
exemption were eliminated because they own more than 500 MW in the
relevant market or control area and would not qualify as Category 1
sellers. Mirant argues that its cost of compliance would increase
because it would have to prepare four updated market power analyses,
each costing $20,000 to prepare and file.\305\ In its reply comments,
APPA/TAPS state that Mirant's increased cost is paltry compared to the
over $3.4 billion in generation revenues reported by Mirant in 2005,
which APPA/TAPS suggest is in no small part due to Mirant's market-
based rate sales.\306\
---------------------------------------------------------------------------

    \305\ Mirant at 11.
    \306\ APPA/TAPS reply comments at 17.
---------------------------------------------------------------------------

    318. Some commenters contend that the Commission's concern that
over time all older generation will be retired and the Commission will
be unable to analyze sellers for market power is not a valid concern in
the immediate or mid-term; they state that the most recent retirement
announcements concern generation assets that were built in the 1940s
and 1950s.\307\ PPM and Allegheny argue that the Commission offers no
evidence or observations to quantify the magnitude of future
retirements.\308\ Some commenters assert that, in order for this
speculative concern to become realistic, the retirement of generating
units that were constructed in the 1980s would have to become
commonplace, and it will take decades for this situation to
materialize. As such, they suggest that the Commission revisit this
issue in 5 to 10 years rather than act prematurely.\309\
---------------------------------------------------------------------------

    \307\ Mirant at 10; EPSA at n.2, citing for example: http://pjm.com/planning/project-queues/gen-retirements/20060601-pjm-gen-retir-list-public-future.pdf
.

    \308\ PPM at 6; Allegheny at 8.
    \309\ EPSA at 15; Mirant at 10.
---------------------------------------------------------------------------

    319. PPM suggests that, if the Commission wishes to limit the
overall amount of generation that is exempt for purposes of conducting
a horizontal market power analysis, an alternative approach would be to
keep the exemption and phase in exempted units over time. Thus, units
that were built after 1996 but before 1999 would lose the exemption in
2010, while facilities built in 2001 would lose it in 2015, and so
on.\310\
---------------------------------------------------------------------------

    \310\ PPM at 6.
---------------------------------------------------------------------------

Commission Determination
    320. The Commission adopts the proposal set forth in the NOPR and
eliminates the exemption provided in Sec.  35.27(a). All sellers
seeking market-based rate authority, or filing updated market power
analyses, on or after the effective date of this Final Rule must
provide a horizontal market power analysis for all of the generation
they own or control. As a number of commenters recognize, over time the
exemption would become too broad and would encompass all market
participants as pre-July 9, 1996 generation is retired. In addition, we
note that even assuming for the sake of argument that there are not a
large number of retirements, the current exemption would allow sellers
to grow unabated as load increases and could result in such sellers
gaining a dominant position in the market without being subject to any
horizontal market power analysis. Thus, continuing the exemption would
result in unintended consequences where all sellers would be given an
automatic presumption that they lack market power in generation.
Accordingly, the Commission finds that eliminating the exemption in
Sec.  35.27(a) and requiring every new seller to submit a generation
market power analysis will allow the Commission to ensure that the
seller does not have market power in generation.\311\
---------------------------------------------------------------------------

    \311\ We note that the Commission may change its policy if it
provides, as it does here, a reasoned analysis indicating that prior
policies are being deliberately changed and the basis for that
change. E.g., B&J Oil and Gas v. FERC, 353 F.3d 71 (D.C. Cir. 2004).
---------------------------------------------------------------------------

    321. We do not believe that this change will have an adverse effect
on the majority of sellers that have previously relied on the Sec.
35.27(a) exemption. The sellers that have taken advantage of the
exemption will largely qualify as Category 1 sellers, and thus will be
unaffected to the extent that they will not be required to file a
regularly scheduled updated market power analysis. For those sellers
seeking market-based rate authority for the first time (e.g., building
new generation facilities), and those that do not qualify as Category 1
sellers, there are several mechanisms or alternatives that can help to
minimize the burden of submitting a horizontal market power analysis.
For example, a seller, where appropriate, can make 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.\312\ We expect that, for most sellers,
the cost of compliance and document preparation occasioned by the
elimination of Sec.  35.27(a) will not be burdensome. To the extent
that there are greater costs for some sellers, we find that the benefit
of ensuring that markets do not become less competitive over time
outweighs any additional costs. Equally important, the elimination of
Sec.  35.27(a) will place all sellers on the same footing. On this
basis, we disagree with commenters that eliminating the exemption would
send an unfavorable

signal to market participants and deter investment.
---------------------------------------------------------------------------

    \312\ See April 14 Order, 107 FERC ] 61,018 at P 69, 117.
---------------------------------------------------------------------------

    322. We also disagree with commenters that find our rationale for
adopting the exemption in 1996 necessarily constrains our decision
making at this time. In light of our experience over the past decade
and our desire to have a more rigorous market-based rate program,
combined with the concern that over time generation will be retired, we
believe a more conservative approach for granting market-based rate
authority is appropriate and will provide us a better means to ensure
that customers are protected.
    323. We find unpersuasive Mirant's concern that, if the Sec.  35.27
exemption were eliminated, a seller would have to get Commission
approval for market-based rate sales prior to bidding on an RFP. If
Mirant is concerned that certain RFPs require, among other things, that
all bidders have in place all regulatory requirements including any
applicable market-based rate authority, we find that RFPs typically
afford bidders ample opportunity to put together their bids and put in
place any necessary regulatory approvals. In this regard, we note that
if a potential seller wishes to participate in an RFP but does not have
market-based rate authority, the seller can file for such authorization
and request expedited treatment and the Commission will use its best
efforts to process the request as quickly as possible.
    324. With regard to the specific argument raised by Mirant, if a
prospective seller wins an RFP, then the capacity would be counted as
committed capacity, and therefore would not adversely affect the
results of the seller's generation market power screen (which analyzes
uncommitted capacity). If the entity loses the RFP, then it would not
build the plant. In either case, the need for market-based rate
authorization does not appear to discourage new investment by
competitive suppliers as Mirant suggests.
    325. Some commenters assert that the retirement of generating units
that were constructed in the 1980s would have to become commonplace
before the Commission's concern is realized that over time all older
generation will be retired. Others contend that it will take decades
for this situation to materialize. However, commenters have provided no
evidence that the elimination of Sec.  35.27(a) will create a
regulatory barrier to new construction or otherwise depress the
building of new generation facilities, and we need not wait for an
inevitable adverse circumstance to materialize.
    326. Finally, we will not implement PPM's suggestion that we retain
the exemption and apply a phasing in approach whereby generating units
would lose the exemption over time based on the date on which the units
were built. Such an approach would create several ``classes'' of
generation facilities which would result in confusion for both the
Commission and market participants. This confusion would become more
acute in situations where market participants may own a number of
generating facilities located in the same balancing authority area or
relevant geographic market, each of which may be considered a different
``class'' of generator in terms of filing horizontal market power
analyses. Moreover, given the regional review and schedule for updated
market power analyses discussed below in this rule, we believe that a
phased-in approach would become overly problematic and unmanageable for
market participants as a whole. Therefore, we will not accept PPM's
suggestion.
b. Grandfathering
Comments
    327. EPSA and Mirant suggest grandfathering units for which
construction commenced between July 9, 1996 and May 19, 2006, the date
of issuance of the NOPR, when generation owners were put on notice that
the Commission was considering eliminating the exemption in Sec.
35.27(a).\313\ Constellation proposes that the exemption not be
eliminated entirely but be limited to generation with construction that
commenced on or after July 9, 1996, but before the effective date of
the Final Rule in this proceeding.\314\ Constellation and EPSA also
contend that this would be consistent with the Commission's prior
decision to grandfather from PJM's mitigation any generating units that
were built in reliance on the post-1996 exemption.\315\
---------------------------------------------------------------------------

    \313\ EPSA at 15; Mirant at 13.
    \314\ See Constellation at 31; PPL reply comments at 20.
    \315\ Constellation at 31, citing PJM Interconnection, LLC, 110
FERC ] 61,053 at P 60-62 (grandfathering the exemption from
mitigation for generating units for which construction commenced on
or after the date the exemption became effective and before the date
when PJM filed its proposal to eliminate the exemption for all
generation units) (PJM), order on reh'g, 112 FERC ] 61,031 at P 38
(2005) (PJM II), order on reh'g, 114 FERC ] 61,302 (2006); EPSA at
16-17.
---------------------------------------------------------------------------

    328. Although NASUCA agrees with the Commission's proposal to
eliminate the new generator exemption, NASUCA raises a concern about
the prospective treatment of sellers with generating plants built after
July 9, 1996 that initially received market-based rate authority
without any generation market power assessment. NASUCA notes that its
understanding is that, ``the Commission would effectively
``grandfather'' the market-based rate status for owners of these newer
power plants,\316\ at least until the time of the next applicable
triennial review, when a market power analysis would be required for
continuation of market-based rate authority.'' \317\ Specifically,
NASUCA explains that a Category 2 seller who recently obtained market-
based rate authority, could have up to three years of future market-
based rate sales with no review of its horizontal market power, while
any that fall into Category 1 would be exempted entirely from the
triennial review process and thus ``grandfathered'' indefinitely and
able to sell at market-based rates without passing any market power
test. If this ``grandfathering'' is not intended, then, according to
NASUCA, the Commission should clarify that new market power assessments
must be made now for those sellers whose market power has never been
reviewed.\318\ Otherwise, NASUCA contends that their rates could be
vulnerable to challenge because they are established solely on the
basis of market price.\319\
---------------------------------------------------------------------------

    \316\ NASUCA at 10 n.12, ``[T]he Commission would require that
all new applicants seeking market-based rate authority on or after
the effective date of the final rule issued in this proceeding,
whether or not all of their or their affiliates' generation was
built after July 9, 1996, must provide a horizontal market power
analysis of their generation.'' Citing NOPR at P 71 (emphasis
added).
    \317\ Id. at n.13, ``[W]ith regard to triennial reviews, the
Commission's proposal to eliminate the section 35.27(a) exemption
would require that, in its triennial review, a seller must perform a
horizontal market power analysis of all of its generation regardless
of when it was built, thus eliminating any special treatment of
generation built after July 9, 1996.'' Citing NOPR at P 72.
    \318\ NASUCA at 10-11.
    \319\ Id. at 11, citing FPC v. Texaco, Inc., 417 U.S. 380 (1974)
(stating that the prevailing price in the marketplace cannot be the
final measure of just and reasonable rates) (Texaco). See also
NASUCA reply comments at 7-8 (asserting that for any grandfathered
sellers the market is the final determinant of price, an
impermissible result under Texaco.)
---------------------------------------------------------------------------

Commission Determination
    329. We will not adopt commenters' proposals with regard to the
grandfathering of any generating units that were built relying on the
exemption in Sec.  35.27(a). As discussed above, we find establishing
``classes'' of generation facilities would result in confusion for both
the Commission and market participants. In this regard, no

commenter has demonstrated that harm would result from having to submit
a horizontal market power analysis, and no commenter has claimed that
it would lose its financing or that its financing would be adversely
affected as a result of the elimination of the exemption in Sec.
35.27(a). Moreover, as the Commission stated in Order No. 888,
intervenors could present evidence that a seller seeking market-based
rates for sales from new generation possesses market power, and sellers
were aware that they may have to submit a horizontal market power
analysis even if their generation fell within the exemption.\320\
Therefore, we will require that all sellers seeking market-based rate
authority for the first time on or after the effective date of the
Final Rule in this proceeding must provide a horizontal market power
analysis that includes all generation that the seller owns or controls.
---------------------------------------------------------------------------

    \320\ See Order No. 888-A, FERC Stats.& Regs. Regulations
Preambles July 1996-December 2000 ] 31,048 at 30,188 (``[T]he policy
eliminates the [generation dominance] showing only as a matter of
routine in each filing.'')
---------------------------------------------------------------------------

    330. All existing sellers that fall in Category 2 must provide a
horizontal market power analysis that includes all generation that each
seller owns or controls when it files its regularly scheduled updated
market power analysis. To the extent a Category 1 seller acquires
enough generation to be reclassified as a Category 2 seller, that
seller will be required to submit a change in status report and provide
a horizontal market power analysis.
    331. Further, with regard to PJM, in establishing whether units
constructed after July 9, 1996 should be exempt from PJM's existing
market power mitigation rules, we initially approved the post-1996
exemption based on the concern that the price cap regulation or the
mitigation rules in PJM might deter market entry and would create
certain equity issues. However, we reconsidered our position and found
that the exemption was unduly discriminatory by creating two classes of
reliability must run generators: one that is price or offer capped and
another that is not. Equally important, other RTOs/ISOs applied local
market mitigation rules to all generation within their respective areas
regardless of when the generator was built, and we determined that
comparable authority for PJM would allow it to address local market
power issues.\321\ We concluded that units built on or after July 9,
1996 had the same ability to exercise market power as counterparts that
were built prior to July 9, 1996. Accordingly, the Commission
terminated the blanket exemption, but in the case of units that were
built with the expectation that they would not be subject to
mitigation, the Commission allowed the exemption to be
grandfathered.\322\
---------------------------------------------------------------------------

    \321\ PJM, 110 FERC  61,053 at P 59.
    \322\ PJM II, 112 FERC  61,031 at P 38.
---------------------------------------------------------------------------

    332. Our reasons for grandfathering units in PJM are dissimilar
enough that our holding in the PJM orders should not affect our
decision here. The factors that led to the establishment and later the
termination of the exemption from mitigation in PJM are unrelated to
the reasons for instituting and, now, eliminating the express exemption
in Sec.  35.27(a). In PJM and PJM II, the Commission considered whether
local market power mitigation might deter new entry and whether new
units were built with the expectation that they would not be subject to
mitigation. The Commission grandfathered units that could reasonably
have relied on the exemption after it went into effect in their
zone.\323\ In contrast, in this proceeding the Commission desires a
more rigorous market-based rate program and is concerned that over time
generation will be retired leaving less and less generation subject to
our horizontal analysis or sellers relying on the Sec.  35.27 exemption
will otherwise grow to a degree that they have market power in the
relevant market in which they are located. The Commission's primary
statutory obligation under FPA sections 205 and 206 is to ensure that
rates are just and reasonable, and we believe the elimination of the
exemption will better provide us with the ability to screen all market
participants' ability to exercise horizontal market power regardless of
whether their generation units were constructed before or after July 9,
1996. Therefore, we will not allow any grandfathering as part of this
proceeding.
---------------------------------------------------------------------------

    \323\ Nevertheless, the Commission stated that the units would
still be subject to mitigation if PJM or its market monitor
concluded that they exercised significant market power. Id. at P 60.
---------------------------------------------------------------------------

    333. NASUCA's concerns regarding entities that originally enjoyed
the Sec.  35.27 exemption are addressed by our decision, discussed
below in the Implementation Process section of this Final Rule, to
require a seller that believes it qualifies as Category 1 to make a
filing with the Commission at the time that its updated market power
analysis for the seller's region would otherwise be due (based on the
regional schedule set forth in Appendix D). That filing should explain
why the seller meets the Category 1 criteria and should include a list
of all generation assets (including nameplate or seasonal capacity
amounts) owned or controlled by the seller and its affiliates grouped
by balancing authority area. Thus, a seller that previously qualified
for the Sec.  35.27 exemption and that believes it qualifies as a
Category 1 seller would 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.\324\ In
addition, a seller that previously qualified for the Sec.  35.27
exemption and that believes it qualifies as a Category 2 seller will be
required to file an updated market power analysis based on the regional
schedule set forth in Appendix D.
---------------------------------------------------------------------------

    \324\ Moreover, if specific concerns regarding market power
exist, interested persons may file a complaint pursuant to FPA
section 206.
---------------------------------------------------------------------------

    334. While 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. We will rely on our change in status
requirements that require, among other things, all sellers that obtain
or acquire a net increase of 100 MW in owned or controlled generation
to make a filing with the Commission and to provide the effect, if any,
such an increase in generation has on the indicative screens.
Additionally, all sellers must file EQRs of transactions no later than
30 days after the end of each reporting quarter. Furthermore, the
Commission retains the ability to require an updated market power
analysis from any seller at any time. With these procedures in place,
we believe NASUCA's concerns are addressed.
c. Creation of a Safe Harbor
Comments
    335. NRG urges the Commission to create a ``safe harbor'' such that
``if the generation owner controls less than 20 percent of the capacity
in an organized market, the Commission should irrebuttably presume that
the new entry will not contribute to market power and thus no
demonstration is required to obtain market-based rate authority for the
new capacity.'' \325\ NRG states that

only where an owner controls more than 20 percent of capacity in a
relevant market should the presumption be rebuttable and subject to
challenge by intervening parties. It is NRG's contention that the
creation of such a ``safe harbor'' retains most of the benefits of the
Commission's current policy under Sec.  35.27(a), while preserving its
flexibility to investigate where a seller adding generating capacity
already has a large market share. NRG believes that this codifies the
general approach the Commission took in Order No. 888 \326\ and
responds to the Commission's evolving concerns in this area, while at
the same time facilitating new entry in the organized markets where
sufficient safeguards exist.\327\ NRG contends that new generation,
timely developed and brought online, is imperative; thus, a ``safe
harbor'' for new generation is necessary.
---------------------------------------------------------------------------

    \325\ NRG at 5 & n.8, suggesting that the use of a 20 percent
market share in the safe harbor proposal replicates one of the two
screens that the Commission proposes in the NOPR to use as a general
screen for market power in all markets reviewed for market-based
rate authority. NRG argues that a 20 percent market share screen is
well-established and appropriate for use in reviewing the market
power implications associated with the addition of new generation.
The use of a lightened, single screen approach to review the market
power implications of new generation is appropriate, argues NRG, in
that new generation expands the supply available in a market.
According to NRG, for organized markets administered by RTOs that
have in place Commission-approved market monitoring and mitigation
authority, subjecting new generation only to a 20 percent market
share screen is appropriate in light of the existing controls over
the exercise of market power.
    \326\ Id. at n.9, citing Order No. 888, FERC Stats. & Regs.,
Regulations Preambles, January 1991--June 1996 ] 31,036 at 31,657.
    \327\ Id. at n.10. Under NRG's proposal, the Commission would
also need to apply the safe harbor analysis to the notice of change
of status for the suppliers' existing generation, when the notice of
change is triggered by the addition of new generation capacity.
Failure to do so would mean the lightened review appropriate for new
generation would not, in effect, produce the intended lessening of
regulatory burden.
---------------------------------------------------------------------------

    336. Ameren agrees that there is a need for the Commission to
address the Sec.  35.27 exemption before it encompasses all generating
capacity; however, Ameren submits that the Commission should allow an
exemption for new generation under certain circumstances. Ameren argues
that ``the Commission should amend its regulations to provide that new
generation that represents less than 20 percent of the uncommitted
capacity at peak in the relevant geographic market be exempt from the
requirement of a horizontal market power analysis, so long as the owner
of, or entity that controls, such capacity and its affiliates own no
other generation or transmission facilities (other than interconnection
facilities) in the relevant market.'' \328\ Ameren submits that the
Commission should allow the seller to file a letter which identifies:
(1) The transmission system it is interconnected to; (2) the amount of
uncommitted capacity it controls; and (3) the Commission-approved
market power study that it relied on to determine that its uncommitted
capacity is less than twenty percent of the net uncommitted capacity in
the relevant geographic market. Ameren contends that this abbreviated
process would reduce a seller's cost of compliance and administrative
burdens.\329\
---------------------------------------------------------------------------

    \328\ Ameren at 7-8.
    \329\ Id.
---------------------------------------------------------------------------

Commission Determination
    337. The Commission will not create a safe harbor.\330\ For the
reasons set forth in the April 14 Order and reiterated in the July 8
Order, there will be no safe harbor exemption from the generation
market power screen based upon a seller's size.\331\ While there is no
safe harbor exemption from the screens based on the seller's size, any
seller, regardless of size, has the option of making simplifying
assumptions in its analysis where appropriate that do not affect the
underlying methodology utilized by these screens.
---------------------------------------------------------------------------

    \330\ We note that although Category 1 sellers are not required
to provide a regularly scheduled updated market analysis, such an
approach does not establish a safe harbor because all sellers will
be required to perform the indicative screens as part of their
initial applications, make change in status filings and file EQRs.
    \331\ See April 14 Order, 107 FERC ] 61,018 at P 69, 117; July 8
Order, 108 FERC 61,026 at P 107 (the Commission explained that small
sellers are able to use simplifying assumptions).
---------------------------------------------------------------------------

    338. Further, while we eliminate the Sec.  35.27 exemption in this
Final Rule, we note that sellers that have enjoyed that exemption
historically have been required to address the other parts of the
market-based rate analysis, vertical market power, affiliate abuse, and
other barriers to entry.\332\ Therefore, the Commission believes that,
on balance, any additional cost of compliance or administrative burden
due to this change will not be substantial compared to a seller's
investment and revenues.\333\
---------------------------------------------------------------------------

    \332\ As described in this Final Rule, we consolidate the
transmission market power and other barriers to entry analyses into
one vertical market power analysis. In addition, we discontinue
considering affiliate abuse as a separate part of the analysis and
instead codify affiliate restrictions in our regulations.
    \333\ NOPR at P 71.
---------------------------------------------------------------------------

11. Nameplate Capacity
Commission Proposal
    339. In the NOPR, the Commission proposed to allow sellers the
option of using seasonal capacity instead of nameplate capacity, as is
currently required. The Commission indicated that the seller must be
consistent in its choice and thus must choose either seasonal or
nameplate capacity and use it consistently throughout the analysis. The
Commission stated that it believed the use of seasonal capacity ratings
more accurately reflects the seasonal real power capability and is not
inconsistent with industry standards and, therefore, it may be more
convenient for sellers to acquire and compile the associated data. The
Commission added that it did not think the use of such ratings will
materially impact results. The Commission sought comment on this
proposal, including comment as to whether this information is publicly
available to all market participants.
Comments
    340. Many commenters on this topic express strong support for the
proposal to substitute seasonal capacity for nameplate capacity.\334\
The reason most commonly cited is that seasonal capacity is a more
accurate representation of actual output. Several commenters state that
firms should be allowed to use net seasonal capacity,\335\ which allows
for station service requirements and energy consumed by environmental
equipment. MidAmerican points out that station usage, including
environmental equipment, can approach 10 percent of overall output in
steam plants.\336\ EEI states that coal plants, which make up 51
percent of generation in the United States, are required to comply with
both Federal and State regulations that mandate emission reductions.
The plants are equipped with scrubbers and other emissions reduction
technology that require a portion of the power produced by the plant in
order to operate, thereby reducing the output available to serve
customers. For companies with a large percentage of their generation
coming from coal, the reduced output from such equipment could be
significant.\337\ PG&E favors using seasonal capacity if it could be
filed confidentially, because it maintains that it is commercially
sensitive information.\338\
---------------------------------------------------------------------------

    \334\ Duke at 22; First Energy at 10; Southern at 26; SoCal
Edison at 8.
    \335\ EEI at 18; PNM/Tucson at 10; Allegheny at 7-8; Pinnacle
West at 5-6; PPL at 17.
    \336\ MidAmerican at 8.
    \337\ EEI at 18.
    \338\ PG&E at 10-11.
---------------------------------------------------------------------------

    341. PG&E requests clarification that if sellers are allowed to
submit seasonal capacity, they are allowed to de-rate

hydroelectric capacity resources based on historical output for the
past five years, as specified in the April 14 Order.\339\ Powerex
supports seasonal ratings as more accurate, because hydroelectric
systems are often able to generate in excess of nameplate ratings and
these ``peak capability'' ratings are typically reflected in seasonal
determinations, and seasonal ratings better reflect operating
conditions that can impact the capacity ratings of renewable
resources.\340\
---------------------------------------------------------------------------

    \339\ April 14 Order, 108 FERC ] 61,018 at P 126. The July 8
Order allowed this method to be used for wind resources as well.
July 8 Order, 108 FERC ] 61,026 at P 129.
    \340\ Powerex at 20.
---------------------------------------------------------------------------

    342. APPA/TAPS support the adoption of seasonal capacity ratings if
they are consistently used, and request that the Commission clarify
that the seasonal capacity ratings be used for all plants in a
geographic region ``so that the consistency benefits of the regional
reviews are not diminished.'' \341\
---------------------------------------------------------------------------

    \341\ APPA/TAPS at 35.
---------------------------------------------------------------------------

Commission Determination
    343. We will adopt the NOPR proposal that allows sellers to use
seasonal capacity. We clarify that each seller must be consistent in
its choice and thus must choose either seasonal or nameplate capacity
and use it consistently throughout the analysis. In addition, a seller
using seasonal capacity must identify in its submittal from what source
the data was obtained.\342\ We also note and adopt the Energy
Information Administration (EIA) definition of seasonal capacity as it
is reported on Form EIA-860, Schedule 3, Part B, Line 2, which provides
that seasonal capacity is the ``net summer or winter capacity.'' \343\
EIA instructions elaborate that ``net capacity should reflect a
reduction in capacity due to electricity use for station service or
auxiliaries,'' \344\ which includes scrubbers and other environmental
devices.
---------------------------------------------------------------------------

    \342\ In the July 8 Order, the Commission stated that ``[w]ith
respect to data that is only available from commercial sources, we
clarify that commercial sources may be used to the extent the data
is made available to intervenors and other interested parties.
Applicants utilizing commercial information to perform the screens
should include it in their filing.'' July 8 Order, 108 FERC ] 61,026
at P 121.
    \343\ EIA-860 Instructions are available at http://www.eia.doe.gov/cneaf/electricity/forms/eia860/eia860.pdf
.

    \344\ Tip Sheet for Reporting on Form EIA-860, ``Annual Electric
Generator Report'' at item ``III. Schedule 3B, Line 2 and Schedule
3D, Line 2: Net Capacity'' available at http://www.eia.doe.gov/cneaf/electricity/forms/eia860/tipsheet.doc
.

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

    344. With regard to energy-limited resources, such as hydroelectric
and wind capacity, in lieu of using nameplate or seasonal capacity in
their submissions, we will allow such resources to provide an analysis
based on historical capacity factors reflecting the use of a five-year
average capacity factor including a sensitivity test using the lowest
capacity factor in the previous five years, and in recognition of
Powerex's concern that hydroelectric systems can generate in excess of
nameplate ratings and these ``peak capability'' ratings, the highest
capacity factor in the previous five years. Our approach in this regard
will more accurately capture hydroelectric or wind availability.\345\
---------------------------------------------------------------------------

    \345\ In the April 14 Order, we explained that commenters
expressed concerns regarding the appropriate measure of the capacity
of hydroelectric units given that hydroelectric facilities are
energy-limited units. Our experience with Western markets shows that
market outcomes can be significantly different during low water
years. We agree with the comments raised by Western market
participants and conclude that properly accounting for water
availability will provide a better picture of competitive conditions
in the West. Moreover, while not as critical in other parts of the
country as in the West, the same principle regarding water
availability applies to all electricity markets, and we will permit
all sellers to de-rate hydroelectric capacity in the analysis.
---------------------------------------------------------------------------

    345. We will not adopt APPA/TAPS' suggestion that we require use of
either nameplate capacity or seasonal capacity throughout a region.
While we appreciate APPA/TAPS' concern for data consistency for
analysis purposes, we note that although we adopt a regional approach
for the filing of updated market power analyses, the horizontal market
power analysis itself continues to focus on the seller seeking to
obtain or retain market-based rate authority. We find that consistency
of data is critical within each individual analysis as results could
vary depending on the assumptions taken. However, because we are not
necessarily analyzing the entire region within a single study, we will
not mandate the use of either nameplate capacity or seasonal capacity
on a regional basis, but instead will allow sellers to choose either
nameplate or seasonal capacity, and require them to identify the choice
and use it consistently throughout the analysis.\346\
---------------------------------------------------------------------------

    \346 \ When submitting a change in status filing regarding
horizontal market power, sellers should use the same assumptions
they used (e.g., use of nameplate or seasonal ratings) in their most
recent market power analysis.
---------------------------------------------------------------------------

12. Transmission Imports
    346. In the NOPR, the Commission proposed to continue to measure
limits on the amount of capacity that can be imported into a relevant
market based on the results of a simultaneous transmission import
capability study. A seller that owns, operates or controls transmission
is required to conduct simultaneous transmission import capability
studies for its home control area and each of its directly-
interconnected first-tier control areas consistent with the
requirements set forth in the April 14 Order, as clarified in Pinnacle
West Capital Corp.\347\ These studies are used in the pivotal supplier
screen, market share screen, and DPT to approximate the transmission
import capability. When centering the generation market power analysis
on the transmission providing utility's first-tier control area (i.e.,
markets), the transmission-providing seller should use the
methodologies consistent with its implementation of its Commission-
approved OATT, thereby making a reasonable approximation of
simultaneous import capability that would have been available to
suppliers in surrounding first-tier markets during each seasonal peak.
The transfer capability should also include any other limits (such as
stability, voltage, Capacity Benefit Margin, or Transmission
Reliability Margin) as defined in the tariff and that existed during
each seasonal peak. The ``contingency'' model should use the same
assumptions used historically by the transmission provider in
approximating its control area import capability.
---------------------------------------------------------------------------

    \347\ 110 FERC ] 61,127 (2005).
---------------------------------------------------------------------------

    347. The Commission also proposed to reaffirm the exclusion of
control areas that are second-tier to the control area being studied.
In addition, it proposed that a seller's pro rata share of simultaneous
transmission import capability should be allocated between the seller
and its competitors based on uncommitted capacity. The Commission
sought comment on this proposal.
a. Use of Historical Conditions and OASIS Practices
Comments
    348. Montana Counsel states that transmission capability used in
the tests should not be greater than the capability measures that are
shown on the OASIS or that are used to measure ATC into markets unless
there is a demonstrated change in available transmission
capability.\348\ In particular, Montana Counsel states that the
Commission's requirement that sellers follow historical OASIS practice
during each historical seasonal peak is essential; otherwise, companies
could submit screens using transmission availability numbers that
differ substantially from those which sellers and transmission

providers use in day-to-day activities in providing transmission market
access.\349\ In Montana Counsel's view, one cannot rely on capacity
being able to reach a market based upon hypothetical transmission
availability, as the Commission appropriately recognizes.
---------------------------------------------------------------------------

    \348\ Montana Counsel at 4.
    \349 \ Id. at 14.
---------------------------------------------------------------------------

    349. In response to Montana Counsel's assertion to use OASIS
postings, PPL Companies maintain that the Commission should continue to
use simultaneous import limit studies. OASIS postings do not adjust for
transmission rights controlled by unaffiliated resources that may be
used to compete against the seller in wholesale markets. PPL Companies
state: ``The Commission should reject this proposal and continue to
rely on [SILs]. The Commission properly has found that using actual
OASIS postings understates import capability because OASIS postings do
not take into account the capacity that may be imported as a result of
existing reservations.''\350\
---------------------------------------------------------------------------

    \350\ PPL Companies reply comments at 9-11.
---------------------------------------------------------------------------

    350. EEI and Southern request clarification of a perceived conflict
in Appendix E, which instructs sellers to use Commission criteria for
calculating simultaneous import capability and also to strictly follow
their OASIS practices.\351\ They recommend that the Commission clarify
that if historical practices are different from Appendix E, historical
practices should be used to calculate simultaneous transmission import
capability and to allocate this transmission capability.
---------------------------------------------------------------------------

    \351\ EEI at 27-29; Southern at 32.
---------------------------------------------------------------------------

    351. Duke asserts that scaling methods for calculating simultaneous
transmission import capability should not be solely limited to
historical practices used by the seller to post ATC on OASIS. Duke
proposes a collaborative method involving the seller and transmission
customers. Duke states: ``the Commission should allow applicants
flexibility to use the appropriate methodology for SIL determinations
including collaborative, regional efforts--so that screen results for
control area markets can be accurate. For example, the Commission
should not be overly prescriptive as to the scaling methodology to be
used in such a collaborative effort, as long as the methodology is
clearly defined and supported by the applicants.''\352\ PPL Companies
support the collaborative effort proposed by Duke, stating that sellers
should have ``the option of proposing alternative [SILs] for first-tier
markets, but would have to justify and document the proposed
deviations.''\353\
---------------------------------------------------------------------------

    \352\ Duke at 27-28.
    \353\ PPL Companies reply comments at 9-11
---------------------------------------------------------------------------

    352. Southern states that the SIL study requires ``blind'' scaling
(scaling that does not consider economic dispatch) because only
generation that is ``on-line'' is used. Southern states that to the
extent a transmission provider does not customarily employ blind
scaling, its use would not be consistent with historical practice. It
asserts that a problem with blind scaling is that it does not
necessarily reflect reality and therefore has the potential to
understate, perhaps significantly, the simultaneous import limit.\354\
EEI seeks clarification that the Commission is not requiring blind
scaling in a manner that requires proportionate increases and decreases
to generation resources. EEI requests clarification that scaling is
allowed to include expert judgment reflecting how generation resources
would likely be scaled up or down in a real-time operating environment.
EEI contends that expert judgment in some cases may determine
simultaneous import capability by scaling load rather than generation
resources. EEI requests that the Commission defer to expert judgment in
scaling and not be overly prescriptive as to whether generation or load
is scaled to determine simultaneous import capability.\355\
---------------------------------------------------------------------------

    \354\ Southern at 35 and 36.
    \355\ EEI at 24.
---------------------------------------------------------------------------

    353. PPL Companies contend the simultaneous import capability
should not be limited by load in a control area. Since generators
within the control area may sell power within or outside the control
area, the Commission should consider the market prices of surrounding
regions. If the prices are 105 percent or less, compared to control
area prices, then the Commission should assume the resident control
area resources will remain within the control area and not result in
economic withholding within the seller's area.\356\
---------------------------------------------------------------------------

    \356\ PPL Companies at 8.
---------------------------------------------------------------------------

Commission Determination
    354. The Commission will continue to require sellers to submit the
Appendix E analysis, i.e., the SIL study, to calculate aggregated
simultaneous transfer capability into the balancing authority area
being studied.\357\ The Commission reaffirms that the SIL study is
``intended to provide a reasonable simulation of historical
conditions'' \358\ and is not ``a theoretical maximum import capability
or best import case scenario.'' \359\ To determine the amount of
transfer capability under the SIL study, ``historical operating
conditions and practices of the applicable transmission provider (e.g.,
modeling the system in a reliable and economic fashion as it would have
been operated in real time) are reflected.'' \360\ In addition, the
``analysis should not deviate from'' and ``must reasonably reflect''
its OASIS operating practices\361\ and ``the techniques used must have
been historically available to customers.'' \362\ We also reaffirm that
the power flow cases (which are used as inputs to the SIL study) should
represent the transmission provider's tariff provisions and firm/
network reservations held by seller/affiliate resources during the most
recent seasonal peaks.\363\
---------------------------------------------------------------------------

    \357\ Benefits of using a uniform transmission import model
include: Transparency, consistency, clarity, and reasonable
assurance that system conditions have been adequately captured.
    \358\ In this regard, actual flows during the study periods may
be used as a proxy for the simultaneous transmission import limit.
    \359\ NOPR at P 77.
    \360\ Id.
    \361\ By OASIS practices, we mean sellers shall use the same
OASIS methods and studies used historically by sellers (in
determining simultaneous operational limits on all transmission
lines and monitored facilities) to estimate import limits from
aggregated first-tier control areas into the study area. In this
sense, sellers are modeling first-tier balancing authority areas as
if they are the transmission operator/security coordinator
(monitoring reliability) operating an OASIS for the aggregated
first-tier footprint. We recognize that sellers are not the
balancing authority area operators of first-tier balancing authority
areas and in some instances, sellers may not be familiar with all
aspects of their first-tier balancing authority areas' transmission
system limits. However, sellers should be familiar with major
constraints, path limits, and delivery problems in these neighboring
transmission systems. If a seller participates in regional planning
studies and day-to-day coordination with neighboring first-tier
balancing authority areas then this will provide a reasonable basis
for including transmission system constraints of first-tier
balancing authority areas in SIL study calculations. In using OASIS
practices the SIL study shall capture real-life physical limitations
of first-tier balancing authority areas that impede power flowing
from remote first-tier resources into the seller's study.
    \362\ Id. at P 77, 78.
    \363\ Network reservations include any grandfathered
transmission rights applicable to the seller or its affiliated
companies.
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    355. The Commission will also continue to allow sensitivity
studies, but the sensitivity studies must be filed in addition to, and
not in lieu of, an SIL study. We clarify that sensitivity studies are
intended to provide the seller with the ability to modify inputs to the
SIL study such as generation dispatch, demand scaling, the addition of
new transmission and generation facilities

(and the retirement of facilities), major outages, and demand
response.\364\
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    \364\ We note that several sellers from the Western
Interconnection have relied on Western Electricity Coordinating
Council (WECC) path ratings for their SIL studies. The Commission
has accepted these ratings when sellers have demonstrated that they
are simultaneously feasible and take into account any
interdependencies between paths.
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    356. The Commission agrees with Montana Counsel and clarifies for
PPL Companies that a SIL study must reflect transmission capability no
greater than the capability measures that were historically shown on
the OASIS or that were historically used to measure transmission
capability into markets unless there is a demonstrated change in
transmission capability, and account for the actual practice of posting
ATC to OASIS in order to capture a realistic approximation of first-
tier generation access to the seller's market. Further, and in response
to EEI and Southern's comments, the Commission clarifies that when
actual OASIS practices conflict with the instructions of Appendix E,
sellers should follow OASIS practices and must provide adequate support
in the form of documentation of these processes.
    357. We disagree with Duke's argument that a seller's (generation
or load) scaling methods should not be limited to historical OASIS
practices when conducting an SIL. Using historical practices provides
an appropriate method to obtain a transparent and measurable analysis
of a seller's actual balancing authority area transmission conditions
and practices. Improper or theoretical scaling methods which do not
represent a seller's actual transmission practices may have the effect
of allowing more competing generation into the balancing authority area
than could actually be accommodated. This in turn has the effect of
reducing a seller's generation market share and perhaps causing the
seller to inappropriately pass the market share screen (a false
negative).\365\ In addition, relying on historical OASIS practices
gives a seller the data needed to support its conclusions.
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    \365 \ See, e.g., Pinnacle West Capital Corp., 117 FERC ] 61,316
(2006).
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    358. With regard to Duke and PPL's request that the Commission
allow sellers to submit a flexible SIL study based on regional
collaboration, the Commission finds that such an approach does not
satisfy our concerns and may result in an unrealistic representation of
the market.
    359. Southern states that to the extent a transmission provider
does not customarily employ blind scaling, its use would not be
consistent with historical practice.
    We agree and, as noted herein, the horizontal analysis and the SIL
study are designed to study historical and realistic conditions during
peak seasons. Accordingly, in this circumstance, sellers should follow
their OASIS practices and must provide adequate support in the form of
documentation of these processes.
    360. With regard to EEI's argument that the Commission should
consider allowing expert judgment in predicting real-time scaling
techniques that will likely be used in real-time market environments,
the Commission requires the use of a study that captures historical
transmission operating practices. The SIL study is not a prediction of
import possibilities; rather, it is a simulation of historical
conditions. We assume that such historical conditions are the result of
``expert judgment'' used when determining generation dispatch and/or
scaling techniques to make transmission capacity available during
actual system conditions. Accordingly, this expert judgment is captured
when conducting an SIL study that is based on historical operating
practices.
    361. In response to PPL's comments that the SIL should not be
limited by load in a balancing authority area, the Commission
reiterates that the SIL study is a benchmark of historical conditions,
including peak load. It is a study to determine how much competitive
supply from remote resources can serve load in the study area.
Increasing the load in the study area beyond historical peak levels
makes the study less realistic and can bias the study.\366\ The
Commission does, however, consider sensitivity studies on a case-by-
case basis, when submitted in addition to the SIL study and supported
by record evidence. For example, in Puget Sound Energy, Inc.'s (Puget)
updated market power analysis filing, Puget demonstrated that the
simultaneous transmission import limit was greater than the peak load
in its balancing authority area, and the Commission allowed Puget to
use a simultaneous transmission import limit based on its peak
load.\367\
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    \366\ We note that there may be a circumstance where additional
supplies could be imported above the market's study year peak load.
If such a circumstance occurs, we will allow the seller to submit a
sensitivity analysis in this regard and we will consider such an
analysis on a case-by-case basis.
    \367\ Puget Sound Energy, Inc., 111 FERC ] 61,020 at P 13
(2005).
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    362. PPL also contends the simultaneous import capability should
not be limited by load in a balancing authority area since generators
within the balancing authority area may sell power within or outside
the balancing authority area. Accordingly, PPL believes that the
Commission should consider the market prices of surrounding regions.
The Commission disagrees. We base the SIL on historical conditions that
actually existed during the study periods. In this regard, PPL has
provided no compelling reason for the Commission to abandon historical
evidence in favor of a theoretical estimation of what could have
occurred. We find that PPL's approach would make the studies more
subjective and thus less accurate and more prone to dispute and
controversy.
b. Use of Total Transfer Capability (TTC)
Comments
    363. Southern asserts that the Commission's assumption that all TTC
values posted on OASIS platforms are non-simultaneous is not correct.
Southern states that although many TTC values may be calculated on a
point-to-point non-simultaneous basis, some TTC values are
simultaneous, thus accounting for ``loop flow'' created by other paths.
Southern contends that those transmission providers that post
simultaneous TTC values on OASIS should have the flexibility to add
these TTC values to calculate simultaneous transmission import
capability for the control area. Southern believes that conflicts can
occur between the generic methods presented in the Appendix E interim
market screen order and actual OASIS practices used by transmission
providers to post TTC.
Commission Determination
    364. Southern's suggestion that the Commission allow the use of
simultaneous TTC values is consistent with the SIL study provided that
these TTCs are the values that are used in operating the transmission
system and posting availability on OASIS. The simultaneous TTCs \368\
must represent more than interface constraints at the balancing
authority area border and must reflect all transmission limitations
within the study area and limitations within first-tier areas. The
source (first-tier remote resources) can only deliver power to load in
the seller's balancing authority area if adequate transmission is
available out of its first-tier area, adequate transmission is
available at the seller's balancing authority area

interface, and transmission is internally available. Thus, the TTC must
be appropriately adjusted for all applicable (as discussed below) firm
transmission commitments held by affiliated companies that represent
transfer capability not available to first-tier supply. Sellers
submitting simultaneous TTC values must provide evidence that these
values account for simultaneity, account for all internal transmission
limitations, account for all external transmission limitations existing
in first-tier areas, account for all transmission reliability margins,
and are used in operating the transmission system and posting
availability on OASIS.
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    \368\ The simultaneous TTCs include seller's balancing authority
area and aggregated first-tier areas.
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c. Accounting for Transmission Reservations
Comments
    365. Duke and EEI propose that short-term firm reservations should
not be subtracted from simultaneous import limits because longer firm
reservation requests can displace control of these transmission
holdings.\369\ EEI explains, ``it is inappropriate to net out
transmission capacity that is not reserved to commit long-term
generation resources to load. Short-term firm transmission
reservations, some as short as one week in duration, provide
flexibility to the market and will not necessarily persist for the
duration, or even large portions, of the MBR authorization period.
Therefore, they should not be used to reduce the estimate of
simultaneous import capability.''\370\
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    \369\ Duke at 26-29.
    \370\ EEI at 25-26.
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    366. Southern agrees, referring to the nature of short-term
reservations as ``transient and unpredictable.'' \371\ Southern states:
``In most cases, short-term purchases by the applicant essentially
allow the market to provide generation within the applicant's control
area instead of the applicant utilizing its `owned' generation
capacity. Alternatively, the associated import capability is released
to the market. In either case, these short-term reservations should not
be used to inflate artificially the applicant's market share in
conjunction with a screen or DPT evaluation.'' \372\
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    \371\ Southern at 36-37.
    \372\ Id. at 37.
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    367. APPA/TAPS state that the Commission should revisit the
treatment of firm transmission reservations held by third parties. In
the July 8 Rehearing Order (at P 49), the Commission stated that the