\199\ See, e.g., CECA Report at 10-11.
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    208. Transmission providers have a disincentive to remedy
transmission congestion when doing so reduces the value of their
generation or otherwise stimulates new entry or greater competition in
their area. As the Commission noted in Order No. 888, ``[i]t is in the
economic self-interest of transmission monopolists, particularly those
with high-cost generation assets, to deny transmission or to offer
transmission on a basis that is inferior to that which they provide
themselves.'' \200\ This statement continues to be true today. In
upholding the Commission's authority to require open access in Order
No. 888, the court in TAPS v. FERC noted that ``[u]tilities that own or
control transmission facilities naturally wish to maximize profit. The
transmission-owning utilities thus can be expected to act in their own
interest to maintain their monopoly and to use that position to retain
or expand the market share for their own generated electricity, even if
they do so at the expense of lower-cost generation companies and
consumers.'' \201\ Thus, even when transmission providers do address
congestion, they have an incentive to do so in a manner that benefits
their own generation or loads rather than the generation or loads of
their competitors. These disincentives frustrate new investment that
could remedy both ``local'' congestion (i.e., within the transmission
provider's control area) and congestion between control areas, as well
as remedy undue discrimination and increase bulk power trade. For
example, a transmission provider does not have an incentive to relieve
local congestion that restricts the output of a competing merchant
generator if doing so will make the transmission provider's own
generation less competitive. A transmission provider also does not have
an incentive to increase the import or export capacity of its
transmission system if doing so would allow cheaper power to displace
its higher cost generation or otherwise make new entry more profitable
by facilitating exports.
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    \200\ Order No. 888 at 31,682.
    \201\ 225 F.3d at 684; see also New York v. FERC, 535 U.S. at 8-
9 (addressing Order No. 888's open access requirements, the Court
noted that ``public utilities retain ownership of the transmission
lines that must be used by their competitors to deliver electric
energy to wholesale and retail customers. The utilities' control of
transmission facilities gives them the power either to refuse to
deliver energy produced by competitors or to deliver competitors'
power on terms and conditions less favorable than those they apply
to their own transmissions.'') (citation and footnote omitted).
---------------------------------------------------------------------------

    209. The existing pro forma OATT does not adequately address the
above-referenced problems. As noted, there is no general requirement
that a transmission provider coordinate its transmission planning with
customers, market participants, or its interconnected neighbors.\202\
Additionally, though the pro forma OATT does require transmission
providers to plan for the needs of their network customers and to
expand their systems to provide service to point-to-point customers,
there is no requirement that the overall transmission planning process
be open to customers, competitors, and state commissions. Rather, the
transmission provider currently is allowed to create its own
transmission plan with limited or no input from affected market
participants or other affected entities, such as state commissions.
There is also no requirement that the planning process be transparent.
While we recognize that certain planning information is required to be
filed annually in FERC Form No. 714--Annual Electric Control and
Planning Area Report and FERC Form 715--Annual Transmission Planning
and Evaluation Report, this does not appear to provide sufficient
transparency to remedy the remaining concerns expressed in this
proceeding about the potential for undue discrimination in planning.
---------------------------------------------------------------------------

    \202\ As discussed more fully in Part V.C.2, section 30.9 of the
current pro forma OATT may inhibit coordinated planning by making
transmission providers reluctant to engage in coordinated planning,
because of the requirement to give customers credits for jointly
planned facilities. We are proposing to sever the link between
credits and planning, and treat the two issues separately within the
pro forma OATT.
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    210. Taken together, this lack of coordination, openness, and
transparency results in opportunities for undue discrimination in
transmission planning. Without adequate coordination and open
participation, market participants have no input into whether a
particular plan treats all loads and generators comparably. Without
sufficient transparency, market participants have no means to determine
whether the plan developed by the transmission provider in isolation is
discriminatory. Moreover, the process is inefficient. Disputes over
discrimination occur primarily after-the-fact because there is
insufficient coordination and transparency between transmission
providers and their customers for purposes of planning. The Commission
has a duty to prevent undue discrimination in the rates, terms, and
conditions of public utility transmission service, and therefore, an
obligation to remedy these transmission planning deficiencies. The
Commission's authority to remedy undue discrimination is broad.\203\ In
addition, new section 217 of the FPA requires the Commission to use its
FPA authorities in a manner that facilitates the planning and expansion
of transmission facilities to meet the reasonable needs of load-serving
entities. Finally, we note that a more transparent and coordinated
regional planning process can support the DOE's responsibilities under
EPAct 2005 section 1221 to study transmission congestion and issue
reports designating National Interest Transmission Corridors.
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    \203\ See Order No. 888 at 31,669 (noting that the FPA ``fairly
bristles'' with concern for undue discrimination (citing Associated
Gas Distributors v. FERC, 824 F.2d 981, 998 (D.C. Cir. 1987)).
---------------------------------------------------------------------------

    211. We are encouraged that since the adoption of open access in
Order No. 888, a number of voluntary coordinated and regional planning
efforts have been developed throughout the country, including those
administered by RTOs and ISOs. For example, each of the Commission-
approved RTOs in the Northeast, Midwest and Southwest, as well as
CAISO, provide for a coordinated and regional planning process with
stakeholder input from each industry segment. The Commission also notes
that there are several other promising efforts to establish voluntary
coordinated and regional planning efforts around the country. For
example, WECC is in the process of expanding its reliability
responsibilities to include comprehensive transmission planning to
address the regional economic transmission needs of its members and
other stakeholders in its regional footprint. In addition, each of the
subregions in WECC has a coordinated transmission planning process
that, in varying degrees, is open to market participants and, in some
instances, has resulted in significant new transmission being built on
a joint ownership basis. In North Carolina, Duke, Progress Energy, and
two other organizations--North Carolina Electric Membership Corporation
and ElectriCities of North Carolina, Inc.--have endeavored to create
and implement a collaborative electric transmission planning process in
that state. This process provides for broad stakeholder input as well
an independent facilitator. Other models

for coordinated planning include the Georgia ITS and joint ownership
arrangements like it around the country.
    212. We fully support these voluntary efforts and believe they are
consistent in significant respects with the nature of the reforms we
are proposing for transmission planning under the pro forma OATT. In
those regions and subregions that already have adopted significant
reforms, our proposal may require only modest changes, while other
regions and subregions may need to undertake more significant changes
to the way in which the transmission system is planned today.
    213. Today, numerous competing interests have a need to utilize the
transmission grid, and yet in many areas of the country that grid is
planned much the same way as it was before the electric industry
matured into a regional business and Order No. 888 was implemented.
That is, the same public utilities that own and control the grid also
control the planning process that governs when and how the grid is
expanded and upgraded. In short, the transmission grid is being
utilized in a fundamentally different way, consistent with the intent
of open access, and a decade of experience has shown us that in order
to remedy undue discrimination, the existing provisions of the pro
forma OATT respecting transmission system planning must be reformed.
Accordingly, in order to provide for more comparable open access
transmission service, eliminate the potential for undue discrimination
and anticompetitive conduct, and satisfy our statutory responsibilities
under section 217 of the FPA, we propose that each public utility
transmission provider participate in an open and transparent local and
regional planning process that addresses certain fundamental principles
of transmission planning. As we indicated above, existing regional
planning processes will be expected to meet or exceed the transmission
planning principles we outline in this proposed rule.
Coordinated, Open, and Transparent Transmission Planning
    214. In order to eliminate the potential for undue discrimination
as described above, and to ensure that comparable transmission service
is provided by all public utility transmission providers, including
RTOs and ISOs, we propose to amend the pro forma OATT to require
coordinated, open, and transparent transmission planning on both a
local and regional level. We propose to require each public utility
transmission provider to submit, as part of its compliance filing in
this proceeding, a proposal for a coordinated and regional planning
process that complies with the following coordinated and regional
planning principles.\204\ In the alternative, transmission providers
may make a compliance filing in this proceeding describing their
existing coordinated and regional planning process and showing that it
is consistent with or superior to the requirements set forth below.
Moreover, we expect municipal, cooperative, and other public power
entities to participate in these processes as well, consistent with
their obligation to provide reciprocal transmission service as detailed
in Order No. 888. An open and transparent regional planning process
cannot succeed unless all transmission owners participate.
---------------------------------------------------------------------------

    \204\ The revised pro forma OATT reflects the proposed planning
requirement in sections 15.4, 16.1, 17.2(x), 28.2, 29.2, 31.6, and
Attachment K.
---------------------------------------------------------------------------

    Under our proposal in this NOPR, a coordinated, open and
transparent process must satisfy the following eight principles:
    1. Coordination--The transmission provider must meet with all its
transmission customers and interconnected neighbors to develop a
transmission plan on a nondiscriminatory basis. The Commission seeks
comment on specific requirements for this coordination, such as the
minimum number of meetings to be required each year, the scope of the
meetings, the notice requirements, the format, and any other features
deemed important by commenters.
    2. Openness--Transmission planning meetings must be open to all
affected parties (including all transmission and interconnection
customers, and state commissions). The Commission seeks comment on
whether there are any circumstances under which participation should be
limited, e.g., to address confidentiality concerns.
    3. Transparency--The transmission provider is required to disclose
to all customers and other stakeholders the basic criteria,
assumptions, and data that underlie its transmission system plans. The
Commission seeks comment on whether the information provided in FERC
Form 715 is adequate and, if not, what additional detail should be
provided. The Commission also seeks comment on the format for
disclosure, including protections to address confidentiality concerns.
    4. Information Exchange--Network transmission customers are
required to submit information on their projected loads and resources
on a comparable basis (e.g., planning horizon and format) as used by
transmission providers in planning for their native load; and point-to-
point customers are required to submit any projections they have of a
need for service over the planning horizon and at what receipt and
delivery points. The Commission seeks comment on whether specific
requirements should be adopted for this information exchange.\205\ The
transmission provider must allow market participants the opportunity to
review and comment on draft transmission plans.
---------------------------------------------------------------------------

    \205\ For network service, some of this information already is
required by sections 29, 30 and 31 of the pro forma OATT, but to the
extent it is not, we propose to require customers to provide
additional information as necessary for the transmission provider to
develop a system plan.
---------------------------------------------------------------------------

    5. Comparability--After considering the data and comments supplied
by market participants, the transmission provider is to develop a
transmission system plan that: (1) Meets the specific service requests
of its transmission customers; and (2) otherwise treats similarly
situated customers (e.g., network and retail native load) comparably in
transmission system planning.
    6. Dispute Resolution--The transmission provider must propose a
dispute resolution process, such as requiring senior executives to meet
prior to the filing of any complaint and using a third-party neutral.
The Commission's Dispute Resolution Service is available to assist
transmission providers in developing a dispute resolution process. In
addition to informal dispute resolution, affected parties would have
the right to file complaints with the Commission under FPA section 206.
The Commission seeks comment on whether any specific dispute resolution
processes should be required.
    7. Regional Participation--In addition to preparing a system plan
for its own control area on an open and nondiscriminatory basis, the
transmission provider is required to coordinate with interconnected
systems to: (1) Share system plans to ensure that they are
simultaneously feasible and otherwise use consistent assumptions and
data, and (2) identify system enhancements that could relieve
``significant and recurring'' transmission congestion (defined below).
The Commission strongly encourages that such coordination encompass as
broad a region as possible, given the interconnected nature of the
transmission grid and the efficiency of addressing these issues in a
single forum. The Commission also recognizes that, as in the West, it
may be appropriate to organize regional planning efforts on both a
subregional

and regional level. The Commission seeks comment on whether there are
existing institutions (such as the NERC regional councils or
subregional planning groups) that are well situated to perform or
coordinate this function.
    8. Congestion Studies--The transmission provider is required
annually to prepare studies identifying ``significant and recurring''
congestion and post such studies on its OASIS. The studies should
analyze and report on the location and magnitude of the congestion;
possible remedies for the elimination of the congestion, in whole or in
part; the associated costs of congestion; and the cost associated with
relieving congestion through system enhancements (or other means). The
Commission seeks comment on how to define ``significant and recurring''
congestion, such as by reference to generation redispatch, repeated
denials of service requests, zero ATC, frequent curtailments or a
combination of these factors. The required congestion studies would
address both ``local'' congestion (i.e., within the transmission
provider's system) and congestion between control areas and subregions.
The purpose of this requirement is to ensure that affected market
participants, state commissions, and this Commission understand both
the costs of recurring transmission congestion and the remedies. The
Commission seeks comment on how this information should be used by the
transmission provider and market participants to address significant
and recurring congestion.
    215. The Commission encourages the use of an independent third
party to oversee or coordinate the planning process. The Commission is
not proposing to require an independent third party to control the
process, but does believe that independence can provide greater
confidence in the planning process and resulting studies. Independence
can take many forms, from having an independent entity resolve disputes
over planning assumptions and decisions (as in an RTO) to having an
independent consultant coordinate and otherwise perform the annual
congestion studies referred to above. The Commission seeks comment on
the levels of independence that can provide benefits and the
institutions that could offer such independence, such as whether
Regional Entities under the ERO could provide such independence.
    216. Additionally, the Commission strongly encourages the
participation of state commissions and other state agencies,
particularly with regard to regional planning, in the coordinated
transmission planning processes being proposed in this NOPR. The
participation and support of state commissions and other state agencies
is important because state commissions regulate the cost of
transmission that is included in bundled retail rates and states also
perform transmission siting. Many states also have traditionally been
involved in utility planning in some way for their state or region. The
Commission seeks comment on how best to accommodate effective state
participation.
    217. The Commission seeks comment on several aspects of this
proposal. First, the Commission seeks comment on how much flexibility
each transmission provider in a region should be given in implementing
any principles adopted. Second, the Commission seeks comment, by way of
examples, on transmission planning processes that comply with the
proposed transmission planning reforms in principle.
    218. Third, we seek comment on whether there are other principles
or requirements that should be adopted to support the construction of
needed new infrastructure and otherwise ensure that all market
participants are treated on a comparable basis. For example:
    a. We seek comment on whether there should be a principle or
guideline to govern the recovery and allocation of costs associated
with funding the regional planning requirement. To devote the resources
necessary to support an open and transparent regional planning process,
we recognize that the participating entities must be assured of
recovery of their costs, as well as assured that the costs will be
borne equitably by all parties benefiting from the process.
    b. We seek comment on whether there should be a requirement that,
at least for large new transmission projects (such as new regional
backbone facilities), there be an open season to allow market
participants to participate in joint ownership of these projects. We
believe that such a requirement could stimulate more investment in the
grid and ensure that all customers have the ability to participate in
new projects on a nondiscriminatory basis, including smaller market
participants that cannot support the construction of large new
facilities on their own.\206\ We seek comment on whether to include
such a requirement and, if so, what conditions or limitations should be
associated with it.
---------------------------------------------------------------------------

    \206\ We note that transmission providers in the Western
Interconnection already participate in regional and sub-regional
transmission planning processes that include the opportunity for
joint financing and ownership of transmission facilities. Such
facilities are typically owned by the participants as ``tenants in
common'' with each participant owning a pro rata share of the land
and common facilities and sharing the costs and expenses in
proportion to their ownership percentage in each project.
Additionally, all owners participate in the oversight and
administration of jointly-owned projects through representation on
various administration committees. Among other benefits, this has
allowed all participating utilities, large and small, to take
advantage of the economies of scale associated with larger
transmission projects.
---------------------------------------------------------------------------

    c. We further seek comment on whether there should be a specific
study process to identify opportunities to enhance the grid for
purposes beyond maintaining reliability or reducing current congestion.
Such a process would allow interested entities, including state
resource agencies, siting bodies and commissions, load-serving
entities, or other market participants to request that the transmission
provider model grid upgrades needed to accommodate the construction of
new resources, e.g., remote coal, nuclear or wind on a local and
regional basis and prior to the existence of an actual proposal for
such resources. Such a process could provide the information necessary
to allow interested entities to proactively evaluate, on a
nondiscriminatory basis, different resource options in light of the
differing transmission infrastructure needs associated with them. We
recognize that resource planning is traditionally performed at the
state level and do not believe that any such study process would
conflict with these state prerogatives. To the contrary, we believe
such a study process could provide states better information to
evaluate all relevant resource options in exercising their resource
adequacy authority.
    d. We also seek comment on whether we should require public
utilities to develop cost allocation principles to address the sharing
of the costs of new transmission projects. Would the development of
specific cost allocation principles provide greater certainty and hence
support the construction of new infrastructure? Or is cost allocation
better handled on a case-by-case basis? We also seek comment on how, as
part of any cost allocation process, to address the fact that upgrades
that may not be needed for reliability in the near term (e.g., 3-5
years) may be necessary to support reliability in the longer term
(e.g., 10-15 years). Furthermore, because transmission upgrades,
particularly multi-state regional backbone facilities, often can
require 10 to 15 years to construct, we seek comment on whether the
planning process proposed here should be

required to look out at least as far as the longest time it would take
to build such an upgrade in the region in question.
    219. Finally, the Commission seeks comment on the level of detail
to be required in transmission providers' OATTs.

C. Transmission Pricing

    220. Order No. 888 and the pro forma OATT included primarily non-
rate terms and conditions of open access non-discriminatory
transmission service. The Commission required transmission providers to
propose corresponding rates in a subsequent filing under FPA section
205. Similarly, here we do not propose to undertake a comprehensive
overhaul of our transmission pricing policies. We do, however, propose
a number of reforms to several discrete provisions in the pro forma
OATT, as further described below. We also provide a clarification of
our policy for pricing of system expansions.
1. Imbalances
Energy Imbalances
    221. In Order No. 888, the Commission concluded that six ancillary
services must be included in an OATT.\207\ One of those ancillary
services is energy imbalance service under Schedule 4 of the pro forma
OATT.\208\ Energy imbalance service is provided when the transmission
provider makes up for any difference that occurs over a single hour
between the scheduled and the actual delivery of energy to a load
located within its control area.\209\ The Commission recognized that
the amount of energy taken by load in an hour is variable and not
subject to the control of either a wholesale seller or a wholesale
requirements buyer.\210\
---------------------------------------------------------------------------

    \207\ Order No. 888 at 31,703.
    \208\ Id.
    \209\ See id. at 31,960.
    \210\ Order No. 888-A at 30,230.
---------------------------------------------------------------------------

    222. The Commission found that the energy imbalance service should
have an energy deviation band appropriate for load variations and a
price for exceeding the deviation band that is appropriate for
excessive load variations.\211\ The deviation band established by the
Commission is an hourly deviation band of 1.5 percent (with
a minimum of 2 MW) for energy imbalance. The Commission explained that
this deviation band promotes good scheduling practices by transmission
customers, which ensures that the implementation of one scheduled
transaction does not overly burden another.\212\
---------------------------------------------------------------------------

    \211\ Id.
    \212\ Id. at 30,232.
---------------------------------------------------------------------------

    223. With respect to compensation associated with the hourly energy
deviation band, the Commission explained that for energy imbalances
within the deviation band, the transmission customer may make up the
difference within 30 days (or other reasonable period generally
accepted in the region) by adjusting its energy deliveries to eliminate
the imbalance (i.e., return energy in kind within 30 days).\213\ In
addition, the Commission explained that the transmission customer must
compensate the transmission provider for each imbalance that exceeds
the hourly deviation band and for accumulated minor imbalances that are
not made-up within 30 days.\214\ With respect to the price of energy
imbalance service, the Commission explained that it intentionally did
not provide detailed pricing requirements.\215\ Instead, the Commission
required transmission providers to propose rates for energy imbalance
service.\216\
---------------------------------------------------------------------------

    \213\ Id. at 30,229.
    \214\ Id. The Commission further stated that the pro forma OATT
permits schedule changes up to twenty minutes before the hour at no
charge, and that it would allow the transmission provider and the
customer to negotiate and file another deviation band more flexible
to the customer, if the same deviation band is made available on a
not unduly discriminatory basis. Id. at 30,232-33.
    \215\ Id. at 30,234.
    \216\ Id.
---------------------------------------------------------------------------

    224. Although transmission providers have different energy
imbalance charges, they typically require customers to correct energy
imbalances within the deviation band through return in kind or a
financial settlement that requires payment for underdeliveries of
energy equal to 100 percent of the transmission provider's system
incremental cost for the hour the deviation occurred. For energy
overdeliveries, the transmission customer would receive a payment equal
to 100 percent of the transmission provider's decremental cost for the
hour the deviation occurred.\217\ Outside the deviation band,
transmission providers either charge the transmission customer: (1) A
percentage of the utility's system cost, such as 110 percent of
incremental costs for underscheduling or 90 percent of decremental
costs for overscheduling, or (2) the greater of a percentage of system
costs or a fixed charge, such as $100 per MWh.\218\
---------------------------------------------------------------------------

    \217\ See, e.g., Arizona Public Service Co., FERC Electric
Tariff, Twelfth Revised Volume No. 2, Schedule 4 (Energy Imbalance
Charge), accepted in Arizona Public Service Co., Docket No. ER04-
442-003 (Sep. 30, 2004) (unpublished letter order); Public Service
Company of New Mexico, FERC Electric Tariff, Second Revised Volume
No. 4., Schedule 4 (Energy Imbalance Charge), accepted in Public
Service Co. of New Mexico, Docket No. ER04-416-002 (Sep. 30, 2004)
(unpublished letter order).
    \218\ See Arizona Electric.; see also Idaho Power Co., 102 FERC
] 61,351 (2003); see also Duke Electric Transmission FERC Electric
Tariff, Third Revised Volume 4, Original Sheet No. 120 accepted in
Duke Energy Corp., Docket No. ER04-812-001 (Jul. 2, 2004)
(unpublished letter order).
---------------------------------------------------------------------------

Generator Imbalances
    225. While the Commission found in Order No. 888 that energy
imbalance was an ancillary service, it also recognized that differences
arise between energy scheduled for delivery from a generator and the
amount of energy actually generated in an hour,\219\ commonly called
generator imbalance. It concluded, however, that a generator should be
able to deliver its scheduled hourly energy with precision and
expressed concern that if it were to allow the generator to deviate
from its schedule by 1.5 percent without penalty, so long as it
returned the energy in kind at another time, it would discourage good
generator operating practices.\220\ The Commission stated that a
generator's interconnection agreement with its transmission provider or
control area operator should specify the requirements for the generator
to meet its schedule and any consequence for persistent failure to meet
its schedule.\221\
---------------------------------------------------------------------------

    \219\ Order No. 888-A at 30,230.
    \220\ Id.
    \221\ Id.
---------------------------------------------------------------------------

    226. Subsequently, however, the Commission, in a number of cases,
accepted modifications to a transmission provider's OATT to include
generator imbalance provisions.\222\ Moreover, in Order No. 2003-B, the
Commission permitted the transmission provider to include a provision
for generator balancing service arrangements in individual
interconnection agreements.\223\ Further, in a NOPR concerning
generator imbalance provisions for intermittent resources, the
Commission proposed to establish a standardized schedule under the pro
forma OATT to address generator imbalances created by

intermittent resources and to clarify the application of the current
energy imbalance provision of the pro forma OATT.\224\ In particular,
the Commission proposed that generator imbalance provisions for
intermittent resources would reflect a deviation band of 10
percent (with a minimum of 2 MW) and allow net hourly intermittent
generator imbalances within the deviation band to be settled at the
system incremental cost at the time of the imbalance.\225\ The
Commission also reiterated its policy that a transmission provider may
only charge the transmission customer for either hourly generator
imbalances or hourly energy imbalances for the same imbalance, but not
both.
---------------------------------------------------------------------------

    \222\ See, e.g., Niagara Mohawk Power Corp., 86 FERC ] 61,009
(1999) (Niagara Mohawk); PacifiCorp, 95 FERC ] 61,145, order on
reh'g and clarification, 95 FERC ] 61,467 (2001); Alliant Energy
Corporate Services, Inc., 93 FERC ] 61,340 (2000); Wolverine Power
Supply Coop., 93 FERC ] 61,330 (2000); Commonwealth Edison Co., 93
FERC ] 61,021 (2000); FirstEnergy Operating Cos., 93 FERC ] 1,200
(2000), order denying reh'g & granting clarification, 94 FERC ]
61,184 (2001); Tampa Electric Co., 90 FERC ] 61,330 (2000), reh'g
denied, 95 FERC ] 61,101 (2001); Florida Power Corp., 89 FERC ]
61,263 (1999); Consumers Energy Co., 87 FERC ] 61,170 (1999).
    \223\ Order No. 2003-B at P 74-75.
    \224\ Imbalance Provisions for Intermittent Resources; Assessing
the State of Wind Energy in Wholesale Electricity Markets, Notice of
Proposed Rulemaking, 70 FR 21349 (Apr. 26, 2005), FERC Stats. &
Regs. ] 32,581 at P 9 (2005) (Imbalance Provisions Proceeding).
    \225\ The Commission defined incremental cost as ``the
transmission provider's actual average hourly cost of the last 10 MW
dispatched to supply the transmission provider's native load, based
on the replacement cost of fuel, unit heat rates, start-up costs,
incremental operation and maintenance costs, and purchased and
interchange power costs and taxes.'' Id. at P 9 n.17 (citing
Consumers Energy Co., 87 FERC ] 61,170 at 61,179 (1999).
---------------------------------------------------------------------------

    227. A variety of different deviation bands and pricing methods are
on file for generator imbalances. Rates for generator imbalance
underdeliveries range from the greater of $100/MWh or 110 percent of
system incremental cost to the greater of $150/MWh or 200 percent of
the incremental cost.\226\ Generator imbalance rates for overdeliveries
range from 90 percent \227\ of system decremental cost to 50 percent
\228\ of the decremental cost.
---------------------------------------------------------------------------

    \226\ See Duke Energy Corp., Docket No. ER05-855-000 (Dec. 20,
2005) (unpublished letter order) (accepting Duke Electric
Transmission's Large Generator Interconnection Agreement with Power
Ventures Group, LLC (Duke Delegated Letter Order)).
    \227\ See Entergy Services, Inc., 90 FERC ] 61,272 (2000)
(concerning various generator imbalance agreements).
    \228\ See Duke Delegated Letter Order.
---------------------------------------------------------------------------

    228. In the NOI, we asked several questions about the need to
modify the treatment of energy and generator imbalances. For example,
with respect to energy imbalances, the Commission asked whether the
deviation band of 1.5 percent continues to be appropriate
and whether penalty charges should be eliminated entirely for
transmission customers, or whether transmission customers should be
charged no more than the control area's cost of supplying energy to
correct the imbalance. With respect to generator imbalances, the
Commission asked if comparability in the treatment of generator
imbalances is needed, how generator imbalances should be priced, and
whether a generator imbalance provision should be included as a
schedule in the pro forma OATT rather than in generator interconnection
agreements.\229\
---------------------------------------------------------------------------

    \229\ NOI at P 31.
---------------------------------------------------------------------------

Comments
    229. Many commenters assert that the deviation band of 1.5 percent
for energy imbalances continues to be appropriate. EEI argues that the
deviation band for energy imbalance service is reasonable because it
appropriately balances the need to protect transmission system
reliability and the need for operational flexibility. LG&E argues that
the deviation band of 1.5 percent and associated penalties
for transactions that fall outside this band are an appropriate means
of disciplining market participants. Southern argues that allowing a
larger deviation band could encourage gaming and leaning on the system,
which ultimately would jeopardize reliability. Southern adds that
allowing deviations of more than 1.5 percent without penalty could
cause, among other things, inefficient use of generation resources and
inappropriate cost shifting from those most able to control imbalances
to those lacking such control.
    230. Several commenters assert that the deviation band for energy
imbalances should be modified. APPA argues that imbalances outside the
deviation band currently must be paid off at rates that often bear no
resemblance to the actual cost that the transmission provider likely
incurs to deal with the imbalance. APPA recommends revising Schedule 4
to increase the deviation band and to institute a graduated series of
increasing penalties outside of the expanded deadband. Public Power
Council states that there is no forecast model that accurately predicts
actual fluctuations in loads within the deviation band and therefore
penalties will not induce parties to schedule more accurately. Public
Power Council states that the 1.5 percent deviation band encourages
loads to over-schedule and encourages the Commission to either expand
the deviation band or adopt a multi-band system similar to the one
Bonneville has in place. Snohomish notes that Bonneville has two
deviation bands beyond the 1.5 percent that have greater penalties when
customers cannot manage their energy imbalances within the first
deviation band and states that this approach seems equitable because it
gives customers the proper incentives to keep their schedules accurate.
    231. Constellation argues that the Commission should eliminate
energy imbalance penalties and require that imbalances be netted across
all suppliers and with respect to each customer. EPSA contends that
imbalances outside the deviation band should be netted on a system-wide
basis and settled at incremental costs. Snohomish states that it
prefers an approach that provides for netting and penalizes intentional
deviation. Nevada Companies explains that its energy imbalance tariff
nets all negative and positive imbalances such that penalties are only
invoked if there is a net positive or a net negative imbalance outside
of the deviation band. PPL also advocates that the Commission should
allow suppliers the flexibility to net and trade imbalances in areas
where no imbalance market exists.
    232. Duke contends that requiring transmission providers to supply
imbalance service at a system incremental cost may eliminate the
erroneous perception that the existing charges are discriminatory, but
such an approach does nothing to solve the problems that imbalances
cause, nor does such an approach reflect the actual costs of leaning on
and dumping on the system. A number of commenters argue that penalties
should be imposed because without penalties there is insufficient
economic incentive for transmission customers to properly schedule and,
as such, reliability could be harmed.\230\ WAPA states that if a
balancing authority has very limited generation capacity (either
physical or market) available for the provision of energy imbalance
service, the assessment of penalties is warranted in order to establish
a disincentive to improper behavior that potentially may affect
reliability.
---------------------------------------------------------------------------

    \230\ E.g., MidAmerican, NorthWestern, PacifiCorp, PNM-TNMP,
Powerex, Progress Energy, Salt River, and Southern.
---------------------------------------------------------------------------

    233. Powerex notes that some mechanism should be in place that
distinguishes between intentional or repeated deviations and unit
outages or force majeure events and argues that penalties should be
tiered so that they increase exponentially as a generator's imbalances
increase.
    234. With regard to generator imbalances, EEI, Entergy,
MidAmerican, and Southern contend that the Commission should continue
its current policy, as established in Order No. 2003, of requiring that
generator imbalances be addressed either in the OATT or in the
generator interconnection agreement. EEI, MidAmerican and Entergy
contend that the Commission

should retain the flexibility of transmission providers to deal with
the issue of generator imbalances on a case-by-case basis, subject to
the requirement that they do not engage in unduly discriminatory or
preferential treatment with respect to other generators on the system.
Calpine contends that requiring transmission providers to treat
generator imbalances in the pro forma OATT in the same way regardless
of the generator, and in all control areas, would provide greater
certainty and consistency for generators and help to eliminate the
opportunity for transmission providers to engage in discriminatory
behavior. Bonneville argues that its three-tiered pricing and penalty
approach for energy imbalances also is appropriate for generator
imbalances.
    235. PNM-TNMP states that the 1.5 percent deviation band for
imbalance service continues to be appropriate except for intermittent
resources. For those resources, it maintains, imbalance energy costs
should not be punitive, but rather should be designed to allow the
transmission provider to recover its full costs of providing the
generator imbalance service. NRECA urges the Commission not to revise
imbalance provisions in a manner that singles out wind generators for
preferential treatment. Northwestern, on the other hand, argues that a
generator imbalance service schedule should be included in the pro
forma OATT for intermittent resources and the service should not apply
to traditional generators.
    236. Commenters argue that the treatment of imbalances should be
made comparable with the treatment of inadvertent energy for
transmission providers. APPA argues that Schedule 4 raises concerns
about discriminatory treatment because Schedule 4 is not applicable to
OATT transmission providers, who clear their imbalances through the use
of inadvertent interchange, if they operate their own control areas.
TDU Systems contend that transmission providers that operate control
areas hold a competitive advantage over non-control area operators
solely by virtue of the fact that they have access to balancing
options, such as inadvertent interchange, that are not available to all
market participants, including customers of the transmission providers.
TDU Systems argue that this advantage can be decisive when sellers that
do not operate control areas try to compete with control area operators
for sales to entities concerned about exposure to the penalties imposed
under existing imbalance tariff provisions.\231\ East Texas
Cooperatives argue that control area utilities, moreover, enjoy a
double benefit because: (1) They are not subject to penalties
themselves, and (2) the control area operator's own generation is used
to provide imbalance service to the other transmission customers in the
control area. TAPS asserts that comparability requires affording
transmission dependent utilities the same return-in-kind treatment
control areas use for inadvertent energy. It maintains that, at a
minimum, the Commission should eliminate the $100/MWh penalty, except
in egregious circumstances and/or the Commission should expand the
return-in-kind deviation band substantially.
---------------------------------------------------------------------------

    \231\ Accord APPA, Constellation, EPSA, Steel Manufacturers
Association, and TAPS.
---------------------------------------------------------------------------

    237. EEI and Entergy, on the other hand, argue that inadvertent
energy and energy imbalances are not comparable and should thus be
treated differently. EEI states that a NERC-certified control area is
responsible for supporting the reliability of its own area as well as
supporting the reliability of the interconnected power system grid. EEI
explains that the inadvertent energy that a control area experiences
reflects the moment-by-moment netting of load, generation and schedules
into or out of the control area, and that inadvertent energy reflects
the loads, generator output and schedules of all entities within the
control area, and not simply the loads and generation of the
transmission provider. Entergy explains that control area interchange
imbalances may involve the failure of control areas to match their
scheduled inflows and outflows due to contingencies occurring even in
another control area.\232\
---------------------------------------------------------------------------

    \232\ Accord Progress Energy, Salt River, and Southern.
---------------------------------------------------------------------------

Discussion
    238. The existing energy imbalance charges under Schedule 4 of the
pro forma OATT and the generator imbalance charges described in Order
No. 2003 are the subject of significant concern and confusion in the
industry. The Commission is concerned about the variety of different
methodologies used for determining imbalance charges and whether the
level of the charges provides the proper incentive to keep schedules
accurate without being excessive. The Commission proposes to modify the
current pro forma OATT Schedule 4 treatment of energy imbalances and to
adopt a separate pro forma OATT schedule for the treatment of generator
imbalances. More specifically, the Commission seeks to balance the
needs of transmission providers to operate their transmission systems
in a reliable manner with the needs of transmission customers to have
reasonable access to those systems at just and reasonable rates, as
well as the needs of a variety of transmission customers with different
generator sources.
    239. To achieve this, the Commission proposes to create new energy
and generator imbalance schedules based on the following three
principles: (1) The charges must be based on incremental cost or some
multiple thereof; (2) the charges must provide an incentive for
accurate scheduling, such as by increasing the percentage of the adder
above (and below) incremental cost as the deviations become larger; and
(3) the provisions must account for the special circumstances presented
by intermittent generators and their limited ability to precisely
forecast or control generation levels, such as waiving the more
punitive adders associated with higher deviations.
    240. Bonneville has taken an energy imbalance pricing approach that
appears consistent with the three principles outlined above and seems
to be working well. Bonneville's imbalance pricing approach is based on
a three-tiered deviation band that would appear workable for both
energy imbalance service and generator imbalance service. Under this
proposal, imbalances of less than or equal to 1.5 percent of the
scheduled energy (or two megawatts, whichever is larger) would be
netted on a monthly basis and settled financially at 100 percent of
incremental or decremental cost at the end of each month. Imbalances
between 1.5 and 7.5 percent of the scheduled amounts (or two to ten
megawatts, whichever is larger) would be settled financially at 90
percent of the transmission provider's system decremental cost for
overscheduling imbalances that require the transmission provider to
decrease generation or 110 percent of the incremental cost for
underscheduling imbalances that require increased generation in the
control area. Imbalances greater than 7.5 percent of the scheduled
amounts (or 10 megawatts, whichever is larger) would be settled at 75
percent of the system decremental cost for overscheduling imbalances or
125 percent of the incremental cost for underscheduling imbalances.
Intermittent resources are exempt from the third-tier deviation band
and would pay the second-tier deviation band charges for all deviations
greater than the larger of 1.5 percent or two megawatts.

    241. The Commission seeks comment on whether this approach should
be adopted for inclusion in the pro forma OATT for energy and generator
imbalances. Does this approach provide sufficient incentives to ensure
that transmission systems can be operated in a reliable manner and
ensure that customers are treated in a just and reasonable manner?
    242. We note that the Bonneville provision allows for greater
charges when a customer has an ``intentional deviation.'' \233\ We seek
comment on whether the pro forma OATT imbalance provision should
provide for penalties for behavior that represents deliberate reliance
on the transmission provider's generation resources, as opposed to
scheduling errors, with such penalties being subject to prior notice
and approval by the Commission and based on the facts and circumstances
of the individual transmission provider.
---------------------------------------------------------------------------

    \233\ See 2006 Transmission and Ancillary Service Rate
Schedules, approved in United States Dep't of Energy--Bonneville
Power Administration, 112 FERC ] 62,258 (2005). The Bonneville
tariff provides that ``For any hour(s) that an imbalance is
determined by [Bonneville] to be an Intentional Deviation: (1) No
credit is given when energy taken is less than the scheduled energy,
(2) When energy taken exceeds the scheduled energy, the charge is
the greater of: (i) 125% of [Bonneville's] highest incremental cost
that occurs during that day, or (ii) 100 mills per kilowatthour.''
An ``Intentional Deviation'' is defined as ``a deviation that is
persistent during multiple consecutive hours or at specific times of
the day,'' a ``pattern of under-delivery or over-use of energy,'' or
``persistent over-generation or under-use during Light Load Hours,
particularly when the customer does not respond by adjusting
schedules for future days to correct these patterns.'' Id. at 46.
---------------------------------------------------------------------------

    243. If the Commission adopts revised energy and generator
imbalance schedules consistent with the principles proposed in this
NOPR, that would eliminate the need for a final rule in the Imbalance
Provisions Proceeding in Docket No. RM05-10-000 concerning generator
imbalance provisions for intermittent resources. As such, the
Commission would expect to terminate that docket concurrent with the
adoption of revised energy and generator imbalance schedules in this
proceeding.
    244. With respect to the pricing of energy and generator
imbalances, the Commission believes that charges based on incremental
costs or multiples of incremental costs will provide the proper
incentive to keep schedules accurate without being excessive. In
deriving such charges, the Commission proposes that incremental cost be
defined to include both energy and commitment \234\ costs (to the
extent additional commitments are needed). The Commission seeks comment
on how such charges should be calculated, as well as how they would be
applied to transmission customers. How should additional demand and
energy costs, if incurred in responding to imbalances, such as
redispatch, commitment, or additional regulation reserves be
appropriately reflected in the calculation of imbalance charges and
which customers should be charged for such costs? Who should receive
any additional revenue from the charges above incremental costs?
---------------------------------------------------------------------------

    \234\ ``Capacity commitment'' generally is defined as the
generating capacity committed by a utility to provide capability for
another utility to attain its reserve level. See, e.g., Central &
South West Services, Inc., 48 FERC ] 61,197 at 61,731 n.9 (1989).
---------------------------------------------------------------------------

    245. The Commission proposes to continue to allow inadvertent
energy to be treated differently than energy and generator
imbalances.\235\ The Commission believes that these two types of
service are not comparable. Inadvertent energy represents the
difference between a control area's net actual interchange and the net
scheduled interchange. It is caused by the combined effects of all the
generation and loads in the control area and not simply the loads and
generation of the transmission provider. Further, management of
inadvertent energy is needed to adhere to NERC standards and to ensure
reliability. Many of the variables of inadvertent interchange are
beyond the control of individual transmission providers. Because of the
nature of inadvertent energy and historical practices, transmission
providers pay back imbalances in kind, and the Commission has accepted
this treatment as just and reasonable. In contrast, allowing customers
to pay back all energy and generator imbalances in kind would not
provide sufficient incentives for them to minimize imbalances. Some
commenters have argued that the return-in-kind approach to inadvertent
energy between control areas is discriminatory because OATT customers
are required to bear actual charges for their imbalances. As we have
described, we believe the two services are different and hence do not
believe that the two should have precisely the same treatment. However,
we seek comment on whether the current return-in-kind approach to
inadvertent energy encourages leaning on the grid in times of shortage,
and therefore whether any reforms in this area are appropriate. Would
pricing inadvertent energy at incremental cost (or some variant
thereof) be an appropriate disincentive? If any reforms in this area
are appropriate, should they be pursued under FPA section 215 as part
of the review of reliability standards?
---------------------------------------------------------------------------

    \235\ See Order No. 888-A at 30,233.
---------------------------------------------------------------------------

    246. Furthermore, we propose to add provisions to schedule 4--
Energy Imbalance Service and schedule 9--Generator Imbalance Service of
the pro forma OATT to reflect the Commission's policy that a
transmission provider may only charge a transmission customer for
either hourly generator imbalances or hourly energy imbalances for the
same imbalance, but not both.\236\ We also clarify that this policy
only applies to a transmission customer that otherwise would be charged
for both generator imbalances and energy imbalances for the same
imbalance occurring within the same control area.
---------------------------------------------------------------------------

    \236\ Imbalance Provisions Proceeding at 32,123 (citing Niagara
Mohawk, 86 FERC at 61,028).
---------------------------------------------------------------------------

    247. Finally, the Commission seeks comment on whether or not it is
appropriate to allow a transmission customer to net energy and
generator imbalances for a particular transaction within a single
control area to the extent they offset. For example, if a transmission
customer schedules 100 MWh over an hour but has a load of 120 MWh, it
would face an imbalance of 20 MW. However, if it also dispatches its
generation to the same 120 MWh, should there be no net charge?
Similarly, what if a transmission customer schedules 100 MWh but has a
load of 80 MWh and dispatches its generation to 80 MWh? Does the
potential to allow netting for offsetting imbalances contradict the
principle of encouraging good scheduling practices? We also seek
comment on what would be a reasonable percentage to net without
concerns that allowing such netting would lead to reliability concerns
from using unscheduled transmission or would cause redispatch costs by
the transmission provider.
2. Credits for Network Customers
    248. Section 30.9 of the pro forma OATT states that a network
customer owning existing transmission facilities that are integrated
with the transmission provider's transmission system may be eligible to
receive cost credits against its transmission service charges if the
network customer can demonstrate that its transmission facilities are
integrated into the plans or operations of the transmission provider to
serve its power and transmission customers. The section also states
that new facilities are eligible for credits when the facilities are
jointly planned and installed in coordination with the transmission
provider. In the NOI, we asked several questions regarding the
Commission's

policy on credits for new facilities, including whether the Commission
should reconsider its policy of denying credits for transmission
facilities owned by point-to-point customers.
Comments
    249. Many commenters argue that the existing credit requirement has
the effect of discouraging joint transmission planning.\237\ NRECA
asserts that making the existence of joint planning a condition of a
customer's eligibility for credits or revenue requirement recovery
simply provides another excuse for public utility transmission
providers to refuse to engage in joint planning.
---------------------------------------------------------------------------

    \237\ E.g., Arkansas Cities, East Texas Cooperatives, Nevada
Companies, NRECA, PNM-TNMP, Suez Energy NA, TAPS, TransAlta, TDU
Systems, and Xcel.
---------------------------------------------------------------------------

    250. EEI contends that if the transmission provider is required to
provide credit against the customer's cost of transmission service, the
cost of the customer's jointly planned and integrated transmission
facilities should be automatically added to the transmission provider's
cost of service. EEI states that the Commission has adopted a similar
approach with respect to third party supply of reactive capability. EEI
also argues that automatic credit for customer facilities is
inappropriate because in instituting open access and requiring
transmission providers to offer network service, the Commission made it
clear that it did not direct a merging of the parties' transmission
systems or the operation of a joint transmission network.\238\ EEI
argues that the Commission should retain the requirement that customer
transmission facilities are eligible for credits from transmission
providers other than RTOs and ISOs only if they meet the integration
standard.
---------------------------------------------------------------------------

    \238\ For support, EEI cites Florida Municipal Power Agency v.
Florida Power & Light Co., 74 FERC ] 61,006 at 61,009-10 (1996),
order on reh'g, 96 FERC ] 61,130 (2001), aff'd sub nom. Florida
Municipal Power Agency v. FERC, 315 F.3d. 362 (D.C. Cir. 2003).
---------------------------------------------------------------------------

    251. Some commenters argue that the OATT should not be reformed to
include credits for transmission facilities built by point-to-point
customers.\239\ EEI states that the question posed in the NOI appears
to contemplate providing credits to a point-to-point customer who
constructs new facilities that are jointly planned with the
transmission provider regardless of whether those facilities meet the
Commission's standards for integration of customer-owned transmission
facilities. Instead, EEI argues, the Commission should apply the test
from Consumers Energy Co., which provides that a transmission customer
should receive credits against its transmission bill when the
transmission provider uses facilities owned by that customer to provide
service to other transmission customers.\240\ Bonneville and PNM-TNMP
state that if applied to existing facilities, credits for point-to-
point customers could cause major cost shifts. Bonneville argues that
these problems would be especially severe in the Northwest, where there
are numerous areas of multiple transmission ownership, both in series
and in parallel, and where transmission owners purchase large amounts
of transmission from each other. Southern states that to effectuate
this proposal, the Commission would need to revise its ``higher of''
pricing requirements, otherwise no point-to-point customer would build
transmission facilities when it can require the transmission provider
to do so and costs are rolled into rate base. Entergy opposes providing
credits for transmission facilities owned by point-to-point service
customers because those facilities are not used to integrate resources
and loads in the same way that facilities owned by network customers
are.
---------------------------------------------------------------------------

    \239\ E.g., Bonneville, EEI, and PNM-TNMP.
    \240\ EEI cites Consumers Energy Co., 86 FERC ] 63,004 at 65,016
(1999), order on initial decision, 98 FERC ] 61,333 (2002) and
Northeast Texas Electric Cooperative, Inc., 111 FERC ] 61,189 at P 6
(2005).
---------------------------------------------------------------------------

    252. Other commenters argue that the Commission should modify the
pro forma OATT to include a provision allowing credits for transmission
facilities built by a point-to-point customer.\241\ TAPS states the
Commission should re-evaluate its bright line denial of credits for
transmission facilities owned by point-to-point customers. TAPS
contends that the current section 30.9 integration test may be
appropriate for long-term (e.g., at least 5 years) point-to-point
customers. South Carolina E&G supports modifying the pro forma OATT to
provide credits for facilities built by point-to-point customers, but
asserts that credits should apply only when the customer's facilities
are in service. South Carolina E&G states that after the passage of a
defined period of inactivity, such as when a customer takes a facility
out of service, the credits should be suspended, to reduce the burden
on other customers.
---------------------------------------------------------------------------

    \241\ E.g., MidAmerican, South Carolina E&G, TAPS, and Williams.
---------------------------------------------------------------------------

Discussion
    253. Section 30.9 of the pro forma OATT establishes two categories
of facilities owned by network customers that are eligible for credits.
First, existing transmission facilities ``integrated with the
Transmission Provider's Transmission Systems,'' are eligible for
credits if the network customer can ``demonstrate that its transmission
facilities are integrated into the plans or operations of the
Transmission Provider to serve its power and transmission customers.''
The second category comprises new facilities (i.e., facilities
constructed by the network customer after the service commencement date
in the OATT), if the facilities ``are jointly planned and installed in
coordination with the Transmission Provider.''
    254. We agree with the commenters who argue that section 30.9
should be reformed. We agree that the link between credits for new
facilities and the requirement for joint planning can act as a
disincentive to coordinated planning, which is contrary to the
Commission's original objective in adopting the provision. A
transmission provider has an incentive to deny coordinated planning if
it believes that the cost of any facilities constructed as a result of
that process will have to be borne in significant part by its bundled
retail customer.
    255. Therefore, we propose to sever the link between credits and
planning, and treat the two issues separately within the pro forma
OATT.\242\ Eliminating the link is appropriate because the crediting of
integrated facilities serves a purpose independent of the planning
obligation. Traditionally, the Commission has allowed a transmission
provider to allocate the costs of integrated facilities to all users of
the integrated system or grid consistent with the view that the entire
grid is interconnected and provides generalized benefits to all
users.\243\ But because integration is a fact-specific matter, the
Commission in Order No. 888 decided that credits were appropriately
addressed on a case-by-case basis. \244\
---------------------------------------------------------------------------

    \242\ See Part V.B for a discussion of our proposed planning
obligations.
    \243\ See, e.g., Pacific Gas and Electric Co., 106 FERC ] 61,144
at P 12, reh'g denied, 108 FERC ] 61,297 (2004); Niagara Mohawk
Power Corp., 42 FERC ] 61,143 at 61,531 (1988); Otter Tail Power
Co., 12 FERC ] 61,169 at 61,420 (1980).
    \244\ Order No. 888 at 31,742.
---------------------------------------------------------------------------

    256. Regarding the eligibility for credits, as the Commission
stressed in Order No. 888, while certain facilities may warrant some
form of cost credit, the mere fact that transmission customers may own
transmission facilities is not a guaranteed entitlement

to such credit.\245\ Rather, a network customer's transmission
facilities must provide additional benefits to the transmission grid in
terms of capability, delivery options, and reliability, and be relied
upon for the coordinated operation of the grid. The integration
standard, in brief, requires that to be eligible for credits under pro
forma OATT section 30.9, the customer ``must demonstrate that its
facilities not only are integrated with the transmission provider's
system, but also provide additional benefits to the transmission grid
in terms of capability and reliability and can be relied on by the
transmission provider for the coordinated operation of the grid.''
\246\ This policy is premised on the principle that ``just as the
transmission provider cannot charge the customer for facilities not
used to provide transmission service, the customer cannot get credits
for facilities not used by the transmission provider to provide
service.'' \247\ The Commission continues to believe that, for existing
facilities, the integration standard is the appropriate standard for
determining whether a network customer's facilities should be eligible
for credits. We clarify, however, that for new facilities, the
integration standard must be applied comparably,\248\ because
application of the integration test in a manner that exclusively
benefits the transmission provider is unduly discriminatory, and a
violation of the FPA.\249\ Specifically, we propose that the network
customer shall receive credit for transmission facilities added
subsequent to the effective date of the Final Rule in this proceeding
provided that: (1) Such facilities are integrated into the operations
of the transmission provider's facilities, and (2) if the transmission
facilities were owned by the transmission provider, would be eligible
for inclusion in the transmission provider's annual transmission
revenue requirement as specified in Attachment H of the pro forma OATT.
---------------------------------------------------------------------------

    \245\ Order No. 888 at 31,742-43.
    \246\ Southwest Power Pool, Inc., 108 FERC ] 61,078 at P 17
(2004) (citing Order No. 888-A at 30,271), reh'g denied, 114 FERC ]
61,028 (2006).
    \247\ Id. at P 20 (citing Order No. 888-A at 30,271 & n.277);
accord East Texas Coop., Inc. v. Central & South West Services,
Inc., 108 FERC ] 61,079 at P 28 (2004), reh'g denied, 114 FERC ]
61,027 (2006); Southern California Edison Co., 108 FERC ] 61,085 at
P 10 (2004); Northern States Power Co., 87 FERC ] 61,121 at 61,488
(1999); Florida Municipal Power Agency v. Florida Power & Light Co.,
74 FERC ] 61,006 at 61,010 (1996), reh'g denied, 96 FERC ] 61,130 at
61,544-45 (2001), aff'd sub nom. Florida Municipal Power Agency v.
FERC, 315 F.3d 362 (D.C. Cir. 2003).
    \248\ In Order No. 888, the Commission addressed the
comparability requirement:
    We caution all transmission providers that while our discussion
here addresses the requirements necessary for a customer's
transmission facilities to become eligible for a credit, the
principles of comparability compel us to apply the same standard to
the transmission provider's facilities for rate determination
purposes.
    Order No. 888 at 31,743 n.452.
    \249\ Credits may not be necessary if the transmission provider
and a transmission customer jointly own the transmission facilities
and operate those facilities under the terms of a joint ownership
agreement. See Northern States Power Co., 83 FERC ] 61,098 at 61,472
(explaining that the crediting provision in pro forma OATT section
30.9 was not intended to apply to jointly owned transmission
facilities), order on clarification, 83 FERC ] 61,338, order denying
reh'g and clarification, 84 FERC ] 61,122 (1998), remanded on other
grounds sub nom. Northern States Power Co. v. FERC, 176 F.3d 1090
(8th Cir. 1999).
---------------------------------------------------------------------------

    257. Thus, the Commission proposes revising section 30.9 to
eliminate the disincentive to coordinated planning and investment in
the transmission grid (i.e., by deleting language that permits
transmission providers to refuse crediting for network-customer-owned
facilities that are not part of its planning process) and provide for
non-discriminatory crediting for integrated facilities comparable to
those transmission provider facilities that are included in rates. We
are proposing this change to ensure that section 30.9 does not impede
coordinated planning and to otherwise ensure that our crediting policy
is just, reasonable and not unduly discriminatory. Our action is not in
any way intended to lessen our commitment to coordinated planning
between a transmission provider and its customers. To the contrary, we
propose elsewhere in the NOPR to require coordinated planning by all
transmission providers. This requirement is not linked to the issue of
crediting for customer-owned facilities, but rather is a general
requirement intended to avoid opportunities for undue discrimination in
transmission planning.
    258. We decline to allow transmission providers as part of this
proceeding to automatically add costs of credits associated with
integrated transmission facilities to the transmission provider's cost
of service. These costs typically are considered and evaluated as part
of a regular cost of service review process. Nevertheless, a
transmission provider that wishes to add an automatic adjustment clause
to its rates may seek Commission approval for its methodology in a
filing submitted under section 205 of the FPA.\250\
---------------------------------------------------------------------------

    \250\ See, e.g., id. at 61,467.
---------------------------------------------------------------------------

    259. Finally, the Commission does not propose revising the pro
forma OATT to expressly allow transmission credits for facilities owned
by point-to-point customers. Unlike a network customer, a point-to-
point customer only pays for a discrete transmission service over the
contract term. The network customer takes a usage-based service which
integrates its resources and loads and pays on the basis of its total
load on an ongoing basis. The transmission provider includes the
network customer's resources and loads in its long-term planning
horizon and the two parties coordinate operations of their facilities
through a network operating agreement. In this way, network service is
comparable to the service that the transmission provider uses to serve
its own retail native load, and credits for certain integrated network
facilities are appropriate. The point-to-point customer, however, does
not purchase integration service, nor does it sign a network operating
agreement with the transmission provider. Thus, because of the inherent
differences between point-to-point and network service, we do not
propose adding a new OATT requirement that the transmission provider
make credits generically available to point-to-point customers that own
transmission facilities. Nevertheless, there may be some facilities
owned by a point-to-point customer that meet all the criteria for
credits. Although the Commission is not including a specific provision
in the OATT that provides credits for these facilities, consistent with
the Commission's statement in Order No. 888, the Commission will
address such situations on a fact-specific, case-by-case basis.\251\
---------------------------------------------------------------------------

    \251\ Order No. 888 at 31,742; Order No. 888-A at 30,271.
---------------------------------------------------------------------------

3. Capacity Reassignment
    260. In Order No. 888, the Commission concluded that a public
utility's tariff must explicitly permit the voluntary reassignment of
all or part of a holder's firm point-to-point capacity rights to any
eligible customer.\252\ As for the rate for capacity reassignment, the
Commission concluded that it could not permit reassignments at market-
based rates because it was unable to determine that the market for
reassigned capacity was sufficiently competitive so that assignors
would not be able to exert market power. Instead, the Commission capped
the rate at the highest of: (1) The original transmission rate charged
to the purchaser (assignor), (2) the transmission provider's maximum
stated firm transmission rate in effect at the time of the reassignment
or (3) the assignor's own opportunity costs

capped at the cost of expansion (price cap).\253\
---------------------------------------------------------------------------

    \252\ Order No. 888 at 31,696; pro forma OATT section 23.1.
    \253\ Order No. 888 at 31,697.
---------------------------------------------------------------------------

    261. The Commission explained in Order No. 888 that opportunity
cost pricing had been permitted at ``the higher of embedded costs or
legitimate and verifiable opportunity costs, but not the sum of the two
(i.e., `or' pricing is permitted; `and' pricing is not).'' \254\ In
Order No. 888-A, the Commission explained that opportunity costs for
capacity reassigned by a customer should be measured in a manner
analogous to that used to measure the transmission provider's
opportunity cost.\255\ As a result, the Commission required that
assignors proposing to recover opportunity costs file with the
Commission a fully developed formula describing the derivation of
opportunity costs. The Commission further required that all information
necessary to calculate and verify opportunity costs must be made
available to the eligible customer.\256\
---------------------------------------------------------------------------

    \254\ Id. at 31,740.
    \255\ Order No. 888-A at 30,224.
    \256\ See id.; Order No. 888 at 31,740.
---------------------------------------------------------------------------

    262. In the NOI, the Commission asked whether the price cap
remained reasonable, or whether it should be modified or eliminated to
further encourage capacity reassignment.
Comments
    263. Some commenters argue that the price cap should not be
eliminated.\257\ According to EEI, transmission pricing policies do not
have much impact on reassignment of capacity rights, so changes to the
approach would be largely irrelevant.
---------------------------------------------------------------------------

    \257\ E.g., Ameren, EEI, Southern, and Tacoma Power.
---------------------------------------------------------------------------

    264. Southern contends that elimination of the price cap might
result in inefficiencies by providing an incentive for entities to
hoard transmission capacity. Moreover, Tacoma and Public Power Council
reason that because transmission remains a monopoly business, cost-
based rates remain appropriate.
    265. Snohomish expresses concern that eliminating the price cap may
encourage speculation in the purchase of transmission capacity, greatly
driving up costs for transmission customers. Snohomish, nonetheless,
states that auctions of secondary capacity may be appropriate, provided
the capacity is purchased under a long-term contract for the purpose of
serving load and the sale does not reduce transmission capacity for
existing customers that have contracted for the capacity.
    266. Other commenters argue that the price cap should be
revised.\258\ Exelon supports the maximum flexibility possible in use
of the transmission system, including allowing transmission rights to
be assigned and redirected--so long as the transfer capability is
available and existing service will not be curtailed. Exelon recommends
that the Commission modify the OATT to permit transmission customers to
charge market-based rates for transmission capacity in the secondary
market. This change, Exelon argues, would provide greater incentive for
the owner of the transmission right to actively pursue reassigning the
transmission service, thereby using the transfer capability more
efficiently. Alcoa states that economic incentives are needed to enable
a secondary transmission capacity market to develop and thrive.
---------------------------------------------------------------------------

    \258\ E.g., Alcoa, Constellation, EPSA, Exelon, and MidAmerican.
---------------------------------------------------------------------------

    267. EPSA and Constellation argue that the only desirable
modification to this pricing policy would be to eliminate the
requirement that transmission customers file with the Commission a
method to impose opportunity cost pricing. EPSA states that to its
knowledge, no transmission customer has yet been able to develop and
file a predefined formula mechanism that would serve as an opportunity
cost rate, probably because opportunity cost pricing reflects dynamic
market conditions. MidAmerican claims that even when there is no
disagreement over the assignor's determination of opportunity costs,
considerable time may be required to prepare and obtain approval from
the Commission of the resulting FPA section 205 filing. EPSA asserts
that the market itself will cap the value of reassignment at the price
the transmission provider would charge, i.e., its expansion cost.
Constellation states that prices of reassigned capacity will be
disciplined by the opportunity costs of releasing the capacity. Both
Constellation and EPSA state that the Commission should recognize that
opportunity costs for released transmission capacity are dynamic and
provide a market discipline on the price that any seller will charge
and any purchaser will pay for reassigned capacity. In response to
EPSA's proposal to eliminate the requirement that transmission
customers file with the Commission a method to impose opportunity cost
pricing, APPA argues that to ensure that the price a seller would
charge for firm transmission capacity is just and reasonable, as the
FPA requires, the Commission should require such a filing.
    268. While Cinergy maintains that the current pricing approach for
capacity assignments is appropriate, it supports consideration of new
alternatives that would allow more effective capacity reassignment by
the transmission customer. Cinergy asserts that one area that could be
considered is to require the transmission provider to provide more
clarity on how reassignment requests are analyzed for approval and the
options available to the transmission customer to post existing service
for reassignment.
    269. Williams and Powerex argue that revising the price cap will
not encourage greater capacity reassignment. Williams submits that
other non-price limitations on capacity reassignment--such as the
requirement that the assignee utilize the same source and sink as the
original customer--are the real reasons there has not been more
capacity reassignment. Stated differently, Williams contends that the
price cap does not restrict capacity reassignment--source and sink
requirements do.
Discussion
    270. In Order No. 888, the Commission explained that it expected
capacity reassignment to achieve three goals: ``(1) help [customers]
manage the financial risks associated with their long-term transmission
commitments, (2) reduce the market power of transmission providers by
enabling customers to compete, and (3) foster efficient capacity
allocation.'' \259\ Because capacity reassignment does not appear to
have developed into a competitive alternative to primary capacity, the
Commission is proposing modifications to its existing pricing policy.
We propose removing the price cap on capacity reassignment and allowing
negotiated rates for transmission capacity reassigned by transmission
customers. We do not propose to lift the price cap for capacity resold
by transmission providers or their affiliates due to market power
concerns.
---------------------------------------------------------------------------

    \259\ Order No. 888 at 31,696.
---------------------------------------------------------------------------

    271. The Commission notes that transmission customers have not used
the opportunity cost pricing option for capacity reassignment. Comments
suggest that this may be due in part to the complexity of establishing
an opportunity cost formula, or the administrative hurdle of filing and
supporting a proposal. Simply put, the goals of the capacity assignment
program remain important to the

Commission, but the price cap has not served as a useful means of
achieving them. While we recognize that other factors may inhibit
capacity reassignment, eliminating the price cap should provide more
flexibility to market participants and encourage customers to sell
their capacity to another customer who values the capacity more highly.
It also will facilitate the release of capacity and encourage the
maximum number of voluntary transactions to occur in a secondary
market, which will benefit all market participants consistent with the
Commission's goals for capacity reassignment.
    272. Although in Order No. 888 the Commission decided not to allow
reassignment at market-based rates because of concerns that capacity
assignors might exert market power, due to several factors, we now
believe that market forces will limit the ability of most assignors to
exert market power. First, we expect that competition among releasing
customers will restrict the potential exercise of market power. Second,
the Commission will monitor the market by requiring quarterly reports
and regular OASIS postings from transmission providers based on
information submitted to them from reassigning customers regarding
their reassignment activity (including the negotiated rate). The
Commission's complaint procedures and the Enforcement Hotline also are
available for participants raising market power concerns, which should
supplement the Commission's existing market oversight efforts. Third,
the continued regulation of rates for primary capacity will act as a
check to ensure just and reasonable reassignment rates. For example,
without congestion on the transmission system, the transmission
provider's rate on file serves as the de facto price cap and, if
congestion exists, the ``incremental rate,'' which reflects the
transmission provider's cost of expansion, should act as a price
ceiling for long-term transactions.
    273. The Commission concludes that because the price cap appears to
have reduced customers' transmission options, removal of the price cap
is warranted without a market-by-market analysis. Our reform is
intended to provide alternatives for customers that value the capacity
more highly. The Commission finds that lifting the price cap strikes a
reasonable balance between promoting more efficiency through trading
and relying upon competition and price disclosure to prevent
anticompetitive behavior. Though we recognize that the price of
reassigned capacity may temporarily exceed the cost of expansion, that
price signal is an important economic incentive to induce greater
transmission investment.
    274. Concerns have been raised that allowing negotiated rates may
provide an incentive to ``hoard'' capacity, or to reserve transfer
capability for no legitimate use other than to speculate on the price
of the reassigned capacity. The ability of a transmission customer to
hoard capacity is not without limits in that the transmission provider
has the obligation to resell as non-firm point-to-point service any
firm point-to-point transfer capability reserved by a customer but not
scheduled within the time-frames established in pro forma OATT section
13.8. As discussed above, we believe that the incentive for the
transmission customer to hoard would be limited by the transmission
provider's cost of expansion for long-term transactions. Thus, we
believe that the greater efficiency created by a more effective
capacity trading market for customers who need capacity during peak
periods outweighs such concerns and that hoarding concerns are
overstated. However, we seek comment on whether circumstances exist
where unaffiliated transmission customers could amass market power
similar to that of the transmission provider.
    275. We do not propose lifting the price cap for all assignors. A
stated goal of capacity reassignment is to ``reduce the market power of
transmission providers by enabling customers to compete.'' \260\
Commission precedent has allowed transmission provider affiliates to
reassign capacity under the price cap,\261\ and we propose to continue
this policy. To allow transmission providers and their affiliates to
use negotiated rates allows the transmission provider to use its
primary market power in the secondary market. A transmission provider
not subject to a price cap would have the ability and incentive to
exercise market power to favor its own generation sales when it
operates and administers the reassignment process. Furthermore, lifting
the cap for the transmission provider may eliminate the incentive to
build or expand, as it may allow the transmission provider to take
advantage of congested pathways to charge rates above the cost of
expansion. Because these expected outcomes would reduce the ability of
other customers to compete, and undermine the development of a viable
secondary market, we conclude that it remains appropriate to require
transmission providers and their affiliates to conform to the price cap
for capacity reassignment.
---------------------------------------------------------------------------

    \260\ Id.
    \261\ Commonwealth Edison Co., 78 FERC ] 61,312 at 62,336
(1997).
---------------------------------------------------------------------------

    276. The Commission seeks comment on the quarterly reports and
OASIS postings we propose to require from transmission providers under
this proposal. They will be based on information that we will require
assignors to give to transmission providers. What information should we
require in the quarterly reports and OASIS postings, i.e., information
about the capacity released, the original rate paid for that capacity,
the price charged to the assignee for the capacity, and the term of the
assignment? Is other information necessary for operational and
reliability purposes? Are additional reports by assignors to the
transmission provider necessary, and if so, what information should be
reported by assignors? Should the Commission establish a new quarterly
reporting process, e.g., a new form, or utilize the existing electronic
electric quarterly report procedures? How frequently should the OASIS
postings be made?
4. ``Operational'' Penalties
 a. Unauthorized Use Penalties
    277. Section 13.7 of the pro forma OATT stipulates that a point-to-
point service customer's use of the transmission system may not exceed
the firm capacity it has reserved at each point of receipt and each
point of delivery except as specified in section 22 of the pro forma
OATT.\262\ Section 13.7 of the pro forma OATT also directs the
transmission provider to specify the rate treatment and all related
terms and conditions for an unauthorized use operational penalty in the
event that a point-to-point customer exceeds its firm reserved capacity
at any point of receipt or point of delivery. Section 14.5 of the pro
forma OATT contains similar provisions for an unauthorized use penalty
in the event that a transmission customer exceeds its non-firm point-
to-point service capacity reservation. The pro forma OATT does not
otherwise address unauthorized use penalties.
---------------------------------------------------------------------------

    \262\ Section 22 (Changes in Service Specifications) of the pro
forma OATT prescribes the circumstances under which the transmission
customer may modify the point of delivery and the point of receipt
for an existing firm point-to-point service reservation.
---------------------------------------------------------------------------

    278. In Allegheny Power, the Commission capped unauthorized use
penalties at a level equal to twice the standard rate for the service
at issue.\263\ In addition, the Commission clarified that the standard
rate to be used as the

basis of the unauthorized use penalty charge must be that of the
service at issue, without regard to the duration of the violation;
i.e., if overuse occurs for one hour, but the service overused is
weekly service, the penalty charge is to be capped at twice the
standard weekly rate.\264\ In APS, the Commission issued an audit
report to Arizona Public Service Company (APS) that contains two
findings that Commission audit staff characterized as unauthorized use
of transmission service.\265\ In the first finding, APS's wholesale
merchant function did not request and pay for point-to-point service to
support some of the off-system power sales it made at trading hubs
where APS system resources were directly connected. In the second
finding, APS incorrectly treated the Phoenix Valley 230kV system as a
single node on its transmission system. As a result, off-system sales
made by generators connected to the Phoenix Valley system should have
been, but were not, supported by point-to-point service. Other than
these cases, the Commission has not addressed the appropriate method of
applying unauthorized use penalties pursuant to the provisions of
sections 13.7 and 14.5 of the pro forma OATT.
---------------------------------------------------------------------------

    \263\ Allegheny Power System, Inc., 80 FERC ] 61,143 at 61,545-
46 (1997) (Allegheny Power).
    \264\ Id. at 61,546 n.131.
    \265\ Arizona Public Service Co., 109 FERC ] 61,271 at P 6
(2004) (APS).
---------------------------------------------------------------------------

Comments
    279. MidAmerican states that unauthorized use penalties should only
be imposed if the pro forma OATT clearly specifies that they are
applicable to a proscribed conduct.
Discussion
    280. We propose to clarify the circumstances under which we would
expect transmission providers to assess unauthorized use penalties.
This clarification will eliminate a potential source of discretion in
the implementation of the pro forma OATT and will assist the Commission
in its enforcement of the obligations imposed by it. Specifically, we
propose to clarify that unauthorized use penalties apply to any
circumstance when a transmission customer uses transmission service
that it has not reserved.\266\ An unauthorized use penalty would be
assessed in circumstances when a transmission customer has a
transmission service reservation, but uses transmission service in
excess of its reserved capacity. An unauthorized use penalty also would
be assessed if a transmission customer uses transmission service when
it does not have a transmission service reservation, including the
situations described in APS. We further clarify that an unauthorized
use penalty would not be assessed in circumstances when a transmission
customer inappropriately uses a network service reservation to support
an off-system sale, as discussed in Part V.D.7. However, a transmission
customer that inappropriately uses network service would be required to
pay for the point-to-point service it should have reserved and could be
subject to a civil penalty depending on the circumstances. We seek
comment on whether the current policy that limits unauthorized use
penalties to twice the standard rate for the service at issue has
resulted in penalties that are not just and reasonable; and, if so, we
seek comment regarding provisions that would yield unauthorized use
penalties that are just and reasonable.
---------------------------------------------------------------------------

    \266\ The revised pro forma OATT reflects this proposed reform
in sections 13.7 and 30.4.
---------------------------------------------------------------------------

b. How Transmission Providers Should Pay Operational Penalties
Comments
    281. In the NOI, the Commission observed that the existing pro
forma OATT allows transmission providers to impose certain operational
penalties against transmission customers for violations of the pro
forma OATT, but does not address the adverse consequences to a
transmission provider who violates its OATT.
    282. Several commenters indicate that a transmission provider would
not face the same financial consequence as other transmission customers
when the transmission provider or an affiliated transmission customer
pays an operational penalty. TAPS notes that applying customer-focused
penalties to the transmission provider is meaningless if a transmission
provider merely pays itself. EPSA suggests that the Commission include
provisions in the new pro forma OATT to ensure that the penalty imposes
a true financial consequence, e.g., penalties imposed on a transmission
provider should be distributed to those OATT customers that were taking
service during the period in which the violation occurred. ELCON
suggests that the pro forma OATT be revised to provide for tariff-based
sanctions against a transmission provider that fails to comply with its
OATT. Occidental argues that one of the fundamental problems with the
current OATT is the lack of tariff-based penalties for violations.
Occidental states that tariff-based penalties are needed to focus
transmission providers on compliance and to permit customers and the
Commission's enforcement staff to bring both specific tariff violations
and general issues of non-compliance before the Commission.
Discussion
    283. We propose to have transmission providers pay non-offending,
unaffiliated transmission customers when the transmission provider or
its affiliate incurs operational penalties. This proposal is consistent
with our prior findings that operational penalties collected by the
transmission provider should be credited back to non-offending
transmission customers in order to provide an incentive to the
transmission provider to develop non-penalty remedies that will elicit
appropriate behavior by transmission customers.\267\ For those
transmission providers subject to operational penalties, we propose to
require the transmission provider to make an annual compliance filing
to notify the Commission of the amounts of all such operational
penalties incurred during the year and to propose a method to identify
non-offending, unaffiliated transmission customers to which the
transmission provider would distribute penalty amounts. In addition, we
propose to allow a transmission provider to avoid an annual compliance
filing by making a one-time filing to propose a mechanism through which
it would identify non-offending, unaffiliated transmission customers
and a method by which it would distribute the operational penalties it
or its affiliates have incurred to the identified transmission
customers. We also propose to prohibit transmission providers from
recovering for ratemaking purposes or through any service or facility
under the Commi-sion's jurisdiction any cost it incurs when it or an
affiliate pays an operational penalty.
---------------------------------------------------------------------------

    \267\ See, e.g., Carolina Power & Light Co., 103 FERC ] 61,209
(2003); Regulation of Short-Term Natural Gas Transportation Services
and Regulation of Interstate Natural Gas Transportation Services,
Order No. 637, 65 FR 10156 (Feb. 25, 2000), FERC Stats. & Regs. ]
31,091 at 31,315 (2000) (noting that ``to the extent that penalty
revenues are generated, the required crediting of penalty revenues
will eliminate any economic incentive for pipelines to rely on
penalties rather than inducements''); order on reh'g, Order No. 637-
A, 65 FR 35705 (Jun. 5, 2000), FERC Stats. & Regs. ] 31,099 (2000).
---------------------------------------------------------------------------

5. ``Higher of'' Pricing Policy
    284. In Order No. 888, the Commission stated that system expansions
should be priced at the higher of the embedded cost rate (including the
expansion costs) or the incremental cost rate, consistent with the
Transmission Pricing Policy

Statement.\268\ The Commission has explained that when rolling in the
costs of network upgrades incurred to meet a transmission service
request would have the effect of raising the average embedded cost rate
paid by existing customers, the transmission provider may elect to
charge an incremental cost rate for the new service and thereby
insulate existing customers from the costs of any necessary system
upgrades. However, the transmission provider may not charge both an
incremental cost rate and an embedded cost rate associated with
existing network transmission facilities.\269\
---------------------------------------------------------------------------

    \268\ Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities Under the Federal
Power Act, Policy Statement, 59 FR 55031 at 55037 (Nov. 3, 1994),
FERC Statutes and Regulations ] 31,005 at 31,146 (1994), order on
reconsideration, 71 FERC ] 61,195 (1995) (Transmission Pricing
Policy Statement).
    \269\ See Northeast Utilities Service Company (Re: Public
Service Company of New Hampshire), Opinion No. 364-A, 58 FERC ]
61,070 (1992), reh'g denied, Opinion No. 364-B, 59 FERC ] 61,042,
order granting motion to vacate and dismissing request for
rehearing, 59 FERC ] 61,089, aff'd in part and remanded in part sub
nom. Northeast Utilities Service Company v. FERC, 993 F.2d 937 (1st
Cir. 1993), order on remand, 66 FERC ] 61,332, reh'g denied, 68 FERC
] 61,041 (1994) pet. denied; Pennsylvania Electric Co., 58 FERC ]
61,278, reh'g denied, 60 FERC ] 61,034 (clarifying pricing policy),
reh'g denied, 60 FERC ] 61,244 (1992), aff'd sub nom. Pennsylvania
Electric Co. v. FERC, 11 F.3d 207 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    285. Although we are not undertaking generic transmission pricing
reform in this proceeding, we are concerned that our existing policies
may not be being applied consistently and, as a result, customers may
be quoted prices that are not consistent with the ``higher of'' policy.
We understand that customers typically are quoted an incremental rate
in the form of a total dollar amount of needed facility upgrades (e.g.,
$5,000,000) rather than in the form of a monthly transmission rate that
can be compared, on an ``apples-to-apples'' basis, to the embedded cost
rate. Presenting an incremental rate as a lump sum payment request is
inconsistent with our ratemaking policy and has the potential to
discourage customers from proceeding with service requests.\270\ As we
have noted, under our ``higher of'' pricing policy for network
upgrades, the transmission provider should compare the monthly revenue
requirement from the upgrade to the monthly revenue requirement from
the embedded transmission rate.\271\ We also have said that the
incremental rate should be established by amortizing the cost of the
upgrades over the life of the contract.\272\ Presenting the incremental
charge in the form of a monthly rate allows a customer seeking a lower
rate to choose to request a longer transaction term.
---------------------------------------------------------------------------

    \270\ Southwest Power Pool, Inc., 100 FERC ] 61,096 (2002)
(designing a rate to include a balloon payment is not a substitute
for a properly designed rate).
    \271\ Southwest Power Pool, Inc., 112 FERC ] 61,319 at P 33
(2005).
    \272\ Southwest Power Pool, Inc., 98 FERC ] 61,256 (``We agree
with SPP that the amortization period for upgrade costs should match
the contract period. * * * As the customer is only obligated to take
service for the term of the contract, it is reasonable that the
costs only be amortized over the term of the contract.''); reh'g
denied in pertinent part, 100 FERC ] 61,096 (2002).
---------------------------------------------------------------------------

    286. We encourage comments on whether changes to the pro forma OATT
are necessary to ensure that incremental costs are presented as monthly
rates for service.

D. Non-Rate Terms and Conditions

    287. In this section, we propose a number of reforms to non-rate
terms and conditions of service under the pro forma OATT. We propose
these reforms to eliminate opportunities for undue discrimination, to
ensure that the services offered under the pro forma OATT are just and
reasonable, to increase the transparency of service being provided, and
to provide clarity with respect to terms and conditions that have
caused confusion in the industry.
1. Potential Modifications to Long-Term Firm Point-to-Point Service
    288. In Order No. 888, the Commission required all public utilities
to offer both firm and non-firm point-to-point service and firm network
service on a non-discriminatory open access basis.\273\ In the NOI, the
Commission asked for comments on pricing policies that can create an
incentive to maximize the use of the transmission system.\274\ Also,
the Commission asked whether the OATT should require transmission
providers to offer new transmission services, such as conditional firm,
partial firm, and seasonal firm service.\275\ Further, the Commission
asked in the NOI whether deviations from the ``higher of'' pricing
policy would encourage greater incremental pricing of redispatch
service.\276\
---------------------------------------------------------------------------

    \273\ Order No. 888 at 31,690.
    \274\ NOI at P 13.
    \275\ Id. at P 13.
    \276\ Id. at P 12.
---------------------------------------------------------------------------

Comments
    289. Some commenters support the inclusion of a required new
service and contend that the existing rules for long-term firm point-
to-point service pose barriers to new entry. Constellation states that
new products are needed that facilitate the efficient use of the
transmission system in a competitive market. AWEA and EPSA argue that a
long-term request for service from a new generator can be denied
because there are reliability violations in only a few hours of a year,
even though firm service is nonetheless available for the large
majority of hours of the year. They also argue the existing grid is
underutilized and that these practices only exacerbate this problem.
EPSA further states that some transmission provider base case models
show that the transmission provider is operating its system to serve
its bundled retail native load under contingencies that the
transmission provider would not accommodate for an OATT customer.
    290. PPL argues that the Commission should enforce the requirement
in section 13.5 of the pro forma OATT that transmission providers must
redispatch to relieve congestion that may only occur during a few hours
a year. PPL further contends that transmission providers have the
incentive to simply deny requests for transmission over a path that
experiences occasional congestion, rather than properly undertake
redispatch actions to minimize this congestion. Others state that they
have not received an offer by a transmission provider to redispatch to
accommodate a request for transmission service, but instead are given
no choice but to pay for facilities studies that are costly and time
consuming.\277\ Entergy states in its reply comments that it only
evaluates redispatch as part of a system impact study if requested by
the transmission customer.
---------------------------------------------------------------------------

    \277\ E.g., AWEA, Arkansas Cities, EPSA, and Renewable Energy.
---------------------------------------------------------------------------

    291. Several commenters suggest that pricing complexities and
certainty of recovery must be resolved before requiring mandatory
redispatch. These commenters state that the cost of redispatch is more
than the fuel cost differential and includes hard to quantify costs
such as start-up costs, higher capital costs due to shorter life and
accelerated replacement, higher maintenance costs, and potential
emergency power purchases to serve load in constrained areas.\278\
---------------------------------------------------------------------------

    \278\ E.g., Ameren, EEI, Progress Energy, and Southern.
---------------------------------------------------------------------------

    292. PacifiCorp suggests that the higher charge, whether embedded
costs or redispatch costs, be determined on a monthly basis rather than
making a one-time determination prior to commencement of service.
PacifiCorp argues that the typical cost analysis fails to consider the
complexity of determining redispatch. PacifiCorp contends that cost
estimates become increasingly unreliable as the analysis

extends over time, and the complications of one-year transmission
service agreements with rollover options make an accurate calculation
nearly impossible.
    293. AWEA provides a detailed proposal for conditional firm
service, in which the transmission provider would identify certain
months, weeks, or days when firm transmission service may be limited or
unavailable and identify the number of potential hours during those
conditional times, when the customer could have its reservations cut or
reduced prior to any firm customer reductions. Under specified
conditions, for a limited number of hours over a set number of
``conditional'' months, weeks, days or hours, the firm service may be
reduced day-ahead by the transmission provider, with conditional firm
service provided instead in those hours firm service is unavailable.
The ``conditional'' periods would be established when the service is
offered. Also, capacity commitments for conditional firm service would
be accounted for in ATC calculations prior to new sales of short-term
firm transmission service. Commenters support a requirement that
transmission providers post on OASIS the paths for which conditional
firm service is available, clearly listing the available capacity for
each period, and hours during which firm service is available or
curtailment is possible as a result of congestion.\279\
---------------------------------------------------------------------------

    \279\ E.g., EPSA and PPL.
---------------------------------------------------------------------------

    294. Those supporting conditional firm service argue that it should
be offered to customers requesting long-term firm service when firm ATC
is not available during all hours of the request, and allow the
transmission customer to obtain service when it would otherwise be
denied.\280\ As for the rate design of the service, EPSA and PPL
recommend that it include either a discount from the firm rate to
reflect the reduction in use at the system peak or no discount from the
firm rate, but customers taking conditional firm service would have a
right of first refusal when firm service becomes available for the
hours in which they have agreed to be curtailed.
---------------------------------------------------------------------------

    \280\ E.g., AWEA, Constellation, EPSA, MidAmerican, PPL, and
Renewable Energy.
---------------------------------------------------------------------------

    295. Commenters arguing against a requirement to provide
conditional firm service argue that it would degrade the quality of
service received by existing long-term firm point-to-point and network
customers.\281\ Also, Bonneville argues that providing conditional firm
service would require modification to the current curtailment
priorities in the OATT and the design and purchase of systems to track
the purchases and implement the more complex curtailment schemes. TAPS
notes that PacifiCorp amended its OATT to make more explicit the
potential for granting part of a request for firm service in terms of
both the amounts of service and/or the periods of time for which there
is sufficient ATC.\282\ If the Commission develops new services, TAPS
contends that the Commission should build on PacifiCorp's OATT
amendments. Many commenters that object to requiring new transmission
services recommend that the Commission encourage transmission providers
to develop and adopt new services in response to customer needs.\283\
Ameren explains that this process should result in additional services
being provided that meet the needs of the customers, that are
physically feasible considering the existing uses of the system, and
that do not adversely affect the service provided to other users of the
system and are not unduly discriminatory. Finally, several commenters
express a general sentiment against requiring a service that may not be
suited to all regions or systems.\284\
---------------------------------------------------------------------------

    \281\ E.g., APPA Reply Comments, Powerex, and Salt River.
    \282\ See PacifiCorp Open Access Transmission Tariff, section
19.7, FERC Electric Tariff, Fifth Revised Volume No. 11, Substitute
Original Sheet No. 100 (effective April 26, 2004); see also
PacifiCorp Open Access Transmission Tariff, Schedule 7, Long-Term
Firm Point-To-Point Transmission Service, section 2, FERC Electric
Tariff, Fifth Revised Volume No. 11, First Revised Sheet No. 252
(effective April 1, 2006) (rates for partial delivery of long-term
firm point-to-point transmission service).
    \283\ E.g., Ameren, Bonneville, Cinergy, EEI, KCP&L, Nevada
Companies, NRECA, Salt River, Sempra Global, Southern, TVA, and
WAPA.
    \284\ E.g., Ameren, Cinergy, Salt River, and Southern.
---------------------------------------------------------------------------

    296. Commenters also expressed support for services aside from, or
in addition to, conditional firm service. Exelon proposes that the
Commission should require ``seasonal firm'' service, though other
commenters ask if seasonal firm service would invite hoarding or
``cream skimming.'' MidAmerican contends that in most cases, the need
for seasonal service can be accommodated by multiple consecutive
purchases of monthly service. PPL supports a required ``partial firm''
service that is confirmed and available on a firm basis but provided in
various amounts over an annual period. PPL states that the amount of
partial firm service offered would be shaped to match the available
capacity within each interval or the year. Powerex and WAPA argue long-
term priority non-firm point-to-point service is the most workable new
service.
    297. MidAmerican states that various transmission providers
interpret and apply the provisions of section 19.7 (Partial Interim
Service) of the pro forma OATT in different ways. MidAmerican states
that the Commission should clarify whether section 19.7 refers to a
partial period of service (i.e., granting firm service for the full MW
amount of the initial request, but for only a portion of the requested
time period), or a partial quantity of service (i.e., granting firm
service for the time period of the initial request, but for only a
portion of the requested full MW amount). MidAmerican suggests that the
revised OATT should provide that partial interim service be offered
both for partial periods and for partial quantities.
    298. Bonneville states that, currently, when a customer accepts an
offer of partial service, Bonneville keeps the remaining portion of the
customer's request in the queue if the customer executes a system
impact study agreement. Bonneville contends that the Commission's OASIS
Standards and Communication Protocols, however, appear to disallow this
result, as does standard OASIS functionality. Bonneville asks that the
Commission clarify whether the Commission intends that a customer
accepting an offer of partial service should lose its position in the
queue.
    299. EPSA further argues that transmission providers should be
required to accommodate a request for any service, whether or not
articulated in the new OATT, to the extent they can do so, on a
nondiscriminatory basis and without unreasonably affecting reliability.
EPSA also states that the burden should be on the transmission provider
to state in writing why it cannot accommodate any given request.
Discussion
Proposed Findings
    300. The Commission preliminarily finds that the existing methods
for evaluating requests for long-term firm point-to-point service may
no longer be just, reasonable and not unduly discriminatory. We believe
that transmission providers may evaluate transmission availability to
serve long-term transmission service requests in a manner that is not
comparable with the method they use to evaluate transmission needs for
bundled retail native load and, therefore, that certain reforms are
necessary to ensure comparability.
    301. When a transmission provider considers new resources to serve
its bundled retail native load, the

transmission provider will not eliminate an otherwise economic option
because the resource may not be deliverable in a few hours of the year.
Rather, the transmission provider will evaluate whether it can
redispatch its resources as necessary to ensure that load is served on
a reliable and economic basis. If redispatch is needed in only a few
hours of the year, the transmission provider typically will not
construct new facilities to accommodate new resources. Rather, the
transmission provider will look for a resource at a different location
to fulfill its needs on a least cost basis taking into account
transmission and energy costs. This use of redispatch to accommodate a
new resource means that the resulting service is provided even though
the transmission provider's power flow studies show that ATC is not
available in all hours of the year. In this situation, the new resource
receives a firm service that is not currently available on many systems
to OATT customers because the transmission provider uses redispatch on
a long-term basis to accommodate a new resource for which ATC is not
available in every hour; in some respects, this firm service is similar
to conditional firm service because it uses firm transmission capacity
to serve bundled retail native load even though the resource is not
deliverable in every hour of the year.
    302. The Commission believes that the current practices for
evaluating long-term transmission service requests generally may not
reflect the same practices used to evaluate transmission needs to serve
bundled retail native load. Under current practices, the transmission
provider evaluates whether service can be granted in every hour of the
year that is modeled and, if not, it informs the customer that long-
term firm transmission service cannot be provided out of existing
transmission capacity. Section 19.3 of the pro forma OATT provides that
a system impact study is required before the transmission provider must
identify available redispatch options. Before redispatch options are
offered, however, the customer must also agree to fund a facilities
study to determine whether redispatch is less expensive than the
transmission facilities upgrades.\285\ Thus, it is only if the customer
requests a system impact study and facilities study, and agrees to pay
for the studies, that the request will be evaluated further and the
option of redispatch will be offered to the customer. This study
process is both time consuming and expensive. More importantly, it
differs from the evaluation typically undertaken by the transmission
provider in deciding whether transmission is available to serve bundled
retail native load with a new resource.
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    \285\ See pro forma OATT section 27.
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    303. In Order No. 888, the Commission's goal was to ``facilitate
the development of competitively priced generation supply options, and
to ensure that wholesale purchasers of electric energy can reach
alternative power suppliers and vice versa.'' \286\ The first part of
this goal, development of competitive supplies, has been realized to
some degree.\287\ However, the lack of transmission access threatens
the viability of customer alternatives to their traditional suppliers.
Without long-term firm service, it is difficult for alternative
suppliers to procure the financing they need for project development.
Customers taking non-firm point-to-point service have a lower
reservation priority and are subject to curtailment and interruption
more frequently than network customers taking transmission service from
resources other than designated network resources. Thus, the lack of
long-term firm transmission access being provided on a
nondiscriminatory basis is a significant problem in realizing the goals
of Order No. 888.
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    \286\ Order No. 888 at 31,646.
    \287\ In 2004, electric generation from IPPs represented an
increasing share of the wholesale markets with nearly 36 percent of
total sales, a significant increase from 1996 when they accounted
for only 12 percent of total sales. In 2004, IPPs accounted for 36
percent of generator nameplate capacity compared to 56.5 percent for
utilities and 7.5 percent for combined heat and power. Office of
Coal Nuclear Electric and Alternative Fuels, Energy Information
Administration, Electric Power Annual 2004 at 9 (2005).
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    304. The Commission's preliminary view is that current practices do
not adequately reflect the manner in which transmission service is
planned for bundled retail native load and may no longer be just,
reasonable and not unduly discriminatory. Transmission customers,
especially those customers seeking service to or from new generation
resources, must be given greater flexibility of service to meet their
needs comparable with the flexibility provided on behalf of bundled
retail native load. New generation resources often face a grid that
cannot accommodate requests for long-term firm transmission, at least
not without the significant delay required by transmission
construction, despite the fact that redispatch options may exist that
would allow that resource to be accommodated. In sum, maintaining the
status quo, as advocated by several commenters, may be insufficient to
ensure comparable treatment of new generation resources for all
transmission customers, eliminate barriers to entry for new generation
sources seeking long-term transmission arrangements, and encourage the
efficient and flexible use of the transmission system in a competitive
market.
Proposed Solutions
    305. The Commission believes there are two basic options for
addressing this problem.\288\ The first option focuses on generation
redispatch to accommodate long-term firm point-to-point service, while
the second option creates a modified form of firm point-to-point
service that includes non-firm service in a defined number of hours of
the year when firm point-to-point service is not available. The
Commission's preliminary view is that the redispatch option is superior
because it: (1) Mirrors the way that transmission providers plan for
bundled retail native load, (2) would provide firm service to new
entrants, rather than service that is subject to more frequent
curtailment in certain hours of the year, and (3) may avoid certain
implementation issues associated with designing a modified long-term
point-to-point service. However, we seek comment on this preliminary
view and on both of the options outlined below.\289\
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    \288\ We will continue to encourage transmission providers to
propose other services requested by customers or such services that
may meet their customers' and systems' needs as energy markets
evolve. However, the Commission does not propose to require
transmission providers to provide any service other than the
services expressly set forth in the pro forma OATT. In response to
EPSA, the decision to provide a new OATT service in the first
instance remains with the transmission provider. Moreover, several
of the proposals included in this NOPR such as lifting the price cap
associated with capacity reassignment for firm point-to-point
service and hourly firm point-to-point service should provide
transmission customers with greater service flexibility.
    \289\ We also request comment on the applicability of these two
options for transmission providers who operate RTOs or ISOs. Because
RTOs provide redispatch service and the ability to access
transmission with no prior reservation by paying congestion charges,
they may not need to reform their existing procedures to satisfy our
proposal with respect to redispatch. We also note that conditional
firm service has the potential to disturb the link between long-term
service and the allocation of Financial Transmission Rights (FTRs)
or auctions of FTR rights.
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Redispatch Service
    306. The Commission believes that full utilization of generation
redispatch is the preferred method of ensuring that long-term point-to-
point service is not unduly discriminatory and does not serve as a
deterrent to new entry. The preferred approach is described below.
    307. Section 13.5 of the pro forma OATT requires the transmission

provider to expand or upgrade its transmission system or, if it is more
economical, to redispatch its resources to provide requested firm
point-to-point service without: (1) Degrading or impairing the
reliability of service to native load customers, network customers and
other transmission customers taking firm point-to-point service; or (2)
interfering with the transmission provider's ability to meet prior firm
contractual commitments to others. The cost of any redispatch performed
pursuant to section 13.5 is to be specified in the service agreement
prior to initiating service and charged to the transmission customer
consistent with Commission policy. For network service, section 33.2 of
the pro forma OATT also requires all network customers to agree to
redispatch their network resources, along with transmission provider's
own resources, to relieve a constraint that may impair reliability.
Section 33.3 of the pro forma OATT provides that the costs of
reliability redispatch performed pursuant to section 33.2 are to be
shared between network customers and the transmission provider on a
load-ratio share basis.\290\
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    \290\ Order No. 888-A at 30,267.
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    308. To encourage the provision of redispatch as an option to
facilitate use of the existing transmission grid, we propose to revise
the pro forma OATT to require the offer of redispatch prior to the
performance of a facilities study. We note that the system impact
study, as defined by the pro forma OATT, is the transmission provider's
assessment of the adequacy of its grid to accommodate a request for
firm point-to-point or network service and whether any additional costs
may be incurred to provide the requested service. It is followed by a
facilities study, which is defined as an engineering study to determine
the transmission system modifications necessary to provide the
requested service, including cost and scheduled completion date.
Neither study references the steps necessary to evaluate the cost of
redispatch that could be performed in lieu of expanding the grid.
Therefore, we propose that the transmission provider must, as part of
the system impact study process, include an estimate of the number of
hours of redispatch that may be required to accommodate the request for
transmission service, and a preliminary estimate of the cost of that
redispatch. The customer would then be given the option of having the
transmission provider perform the necessary studies to determine the
projected redispatch costs or perform the facilities study, or both.
    309. Consistent with the existing requirements of the OATT, the
redispatch requirement would apply to the redispatch of the
transmission provider's own generation resources and would not require
the transmission provider to purchase new resources to provide this
service.\291\ However, we propose to require the transmission provider,
when it cannot accommodate a long-term firm point-to-point transmission
request through redispatch of its own resources, to identify the
generators in other control areas that could relieve the constraint on
the affected flowgates to allow the transmission customer to seek
redispatch with transmission providers in adjacent control areas to
remove such constraints. We also seek comment on whether to expand the
existing OATT obligation to require the transmission provider to
redispatch not just its own resources, but those of its network
customers also, subject to the network customers receiving appropriate
compensation when their resources are redispatched.
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    \291\ However, we also request comment on whether it would be
appropriate to require the transmission provider to contract to