to meet its schedule and any consequence for persistent failure to meet
its schedule.\382 \
---------------------------------------------------------------------------

    \380\ Order No. 888-A at 30,230.
    \381\ Id.
    \382\ Id.
---------------------------------------------------------------------------

    632. The Commission subsequently accepted in a number of cases
modifications to a transmission provider's OATT to include generator
imbalance provisions.\383\ 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.\384\ 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.\385\ 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.\386 \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.\387\
---------------------------------------------------------------------------

    \383\ See, e.g., Niagara Mohawk Power Corp., 86 FERC ] 61,009,
order on reh'g, 87 FERC ] 61,148 (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 ] 61,200 (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) (Consumers).
    \384\ Order No. 2003-B at P 74-75.
    \385\ 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).
    \386\ 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, 87 FERC ] 61,170 at 61,179 (1999)).
    \387\ Under existing Commission policy, a transmission provider
may only charge a transmission customer for the penalty percent
adder to the incremental cost for either hourly generator imbalances
or hourly energy imbalances for the same imbalance. For example, if
a transmission customer has a 100 MWh point-to-point schedule in a
control area, but produces 105 MWh and consumes 105 MWh, the
transmission provider may charge the transmission customer 110% of
its incremental cost for the 5 MWh of energy imbalance, but then
must pay the transmission customer its incremental cost for the 5
MWh generator imbalance.
---------------------------------------------------------------------------

    633. 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.\388\ Generator imbalance rates for overdeliveries
range from 90 percent \389\ of system decremental cost to 50 percent
\390\ of the decremental cost.
---------------------------------------------------------------------------

    \388\ 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)).
    \389\ See Entergy Services, Inc., 90 FERC ] 61,272 (2000)
(concerning various generator imbalance agreements).
    \390\  See Duke Delegated Letter Order.
---------------------------------------------------------------------------

a. Tiered Approach to Imbalance Penalties in the OATT
NOPR Proposal
    634. In the NOPR, the Commission noted that the existing energy
imbalance charges described in Order No. 2003 are the subject of
significant concern and confusion in the industry. The Commission
expressed concern 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 therefore proposed 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.
    635. The Commission proposed 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.
    636. The Commission noted that Bonneville has adopted an energy
imbalance pricing approach based on a three-tiered deviation band that
appears workable for both energy imbalance service and generation
imbalance service. Under this approach, 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 pay the second-tier deviation band charges for all
deviations greater than the larger of 1.5 percent or two megawatts.
    637. The Commission sought comment regarding whether this tiered
approach should be adopted for inclusion in the pro forma OATT for
energy and generator imbalances. The Commission specifically asked
whether this approach provides 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.
Comments
    638. A number of entities generally support a tiered approach to
imbalance penalties that progressively increases the penalties for
imbalances, as implemented by Bonneville.\391\ These

commenters generally state that a graduated bandwidth approach
recognizes the link between escalating deviations and potential
reliability impacts on the system. Other entities, however, take issue
with aspects of the Commission's proposal or propose a different
approach to resolving imbalances. For example, Entegra submits that the
Commission should require transmission providers to establish, or
permit market participants to establish, markets or pools for the
netting and settlement of imbalances. Steel Manufacturers Association
argues for the Commission to require real-time balancing markets.
---------------------------------------------------------------------------

    \391\ E.g., Ameren, Northwest IOUs, Progress Energy, Suez Energy
NA, Public Power Council, Sacramento, South Carolina E&G, Pinnacle,
Allegheny, TDU Systems, Constellation, Imperial, and Morgan Stanley.
---------------------------------------------------------------------------

    639. Among those supporting the Commission's proposal, Ameren
asserts that the tiered approach properly allows for higher penalties
for imbalances that have a greater impact on the system and thus have a
greater potential to affect reliability. NorthWestern is not opposed to
the generation imbalance provisions applying to all generators, arguing
that imbalance charges must be based upon incremental cost and must
provide an incentive for accurate scheduling. Morgan Stanley contends
that basing the imbalance charge on incremental cost should be a
bedrock principle for developing methods to financially settle
imbalances.
    640. Progress Energy, Sacramento, and Entergy encourage the
Commission to allow each transmission provider to have the flexibility
to craft penalty provisions that provide the right incentives to
encourage their transmission customers to act responsibly. Grant
similarly contends that the transmission provider must be able to
decide what to charge for imbalance services and must consider the
incentives for resource development and the potential for cross-
subsidies paid by other customers associated with such pricing. Grant
argues that transmission providers should have an ability to ``opt
out'' if they can demonstrate an inability to provide the service
without creating an undue burden on other ratepayers.
    641. Constellation, while supporting the Commission's proposal,
asks that transmission providers be required to utilize a security-
constrained economic dispatch to procure and settle imbalances at least
cost, which would ensure that least cost is determined on the most
efficient basis. Constellation contends that imbalance charges should
be based on the transmission provider's actual cost of meeting a
positive imbalance or liquidating a negative imbalance, which costs can
include required ancillary services and redispatch costs. Morgan
Stanley states that facing an imbalance cost measured by full
replacement value of redispatch measured under LMP would be an
appropriate incentive. Morgan Stanley contends that the pro forma OATT
should specify using opportunity cost principles to charge for
imbalance solutions in those areas without LMP and come as close to
mimicking the result under LMP as possible. In reply comments, Mark
Lively suggests the Commission make the price for imbalances a function
of the size of Area Control Error. Public Power Council recommends that
transmission providers not assess penalties against loads or resources
when their deviations from the schedule help the system in a given
delivery hour. TDU Systems argue that inadvertent scheduling errors
that do not threaten system integrity or reliability should not be
penalized through charges for imbalances that exceed incremental cost
in the upper tiers of imbalance bandwidths.
    642. Although FirstEnergy states that the Bonneville approach for
generator imbalances is appropriate, it argues that the current pro
forma OATT methodology for calculating and assessing energy imbalances
should be retained. FirstEnergy argues that it is more appropriate and
fair to apply a graduated penalty structure to generation imbalances
since greater deviations usually occur from generation. Ameren,
however, believes that generators are generally better able to control
their imbalances than transmission customers who take energy off of the
system and that the use of a narrower deviation band may be appropriate
for generator imbalances. Nonetheless, Ameren states that it does not
oppose the Commission's proposal to use the same deviation bandwidths
for both energy imbalances and generator imbalances.
    643. Ameren contends that developing standardized provisions for
generator imbalances in the OATT would eliminate the plethora of
penalties that now exist. Ameren asserts that moving to a tariff
approach would increase transparency and would help address the
situation where such provisions may appear either in the relevant OATT
or in specific interconnection agreements (at least for interconnection
agreements entered into as of the date of the revised tariff
provisions). Progress Energy and South Carolina E&G support separate
tariff (or Generator Interconnection Agreement) provisions for these
services, suggesting that generator and energy imbalance provisions
could be tailored for generators and LSEs. NorthWestern states that it
has long been an advocate of the inclusion of a generation imbalance
OATT mechanism. TDU Systems contend that the Commission should require
that the specific bandwidths and the basis for the charges be spelled
out in detail in the revisions to the pro forma OATT and in each
transmission provider's tariff. Allegheny argues that changing Energy
Imbalance Service from Schedule 4 to Schedule 4a, adding a new Schedule
4b for Generator Imbalance Service, and eliminating proposed Schedule 9
would call attention to the fact that a transmission provider may only
charge a transmission customer either an hourly generator imbalance
charge or an hourly energy imbalance charge, but not both for the same
imbalance.
    644. Other entities contend that the Commission's imbalance
proposal will not do enough to protect reliability and prevent entities
from deviating from their schedules. Entergy states that the Commission
should recognize that a system with significant hydro resources, such
as the Bonneville system, faces different challenges in matching
generation and load than a system with predominantly thermal
generation. Unlike the fast ramping capability of hydro units, Entergy
asserts that thermal units have a more limited ability to adjust and
compensate for imbalances. Entergy adds that the Bonneville model may
not provide sufficient incentives in those areas with large amounts of
independent generation. In reply comments, some APPA members noted that
wind variability may pose significant operational concerns that could
increase regulating reserve requirements, particularly on smaller
transmission systems.
    645. Steel Manufacturers Association asks the Commission to delete
any further reference to charges based on some multiple of incremental
costs, which applies to scheduling incentives, not cost recovery. It
believes that charges based on multiples of incremental costs are not
necessary and do not produce rates that are just and reasonable. Steel
Manufacturers Association asserts that balancing mechanisms based on
real time market-clearing prices provide full compensation and adequate
scheduling incentives in the organized markets and there is no reason
to apply a deadband/penalty mechanism for individual OATT providers
unless there is a demonstrated need, i.e., a showing that excessive
gaming by LSEs or generators has been a problem.
    646. Steel Manufacturers Association also contends that the current
imbalance mechanism is a losing proposition for loads that cannot
control energy

consumption to match an hourly schedule of energy deliveries, with
transmission providers receiving windfall revenues. It argues that the
mechanism is unfair to smaller transmission systems that are not
control areas (and therefore may not settle all of their imbalances
through return-in-kind energy) and certain retail customers that take
unbundled retail transmission service. Steel Manufacturers Association
asks the Commission to institute a larger bandwidth of, at minimum, 10
percent for small wholesale customers and discrete retail loads. It
contends that large utilities and wholesale transmission customers that
acquire power for many discretely operated loads with varying load
stages and load factors and averaging those loads creates an overall
predictability to load curves that permits the practical use of a 1.5
percent bandwidth for large utilities and wholesale customers.
    647. Utah Municipals assert that the Commission is wrong to believe
that imbalances tend to result from carelessness or intentional conduct
rather than unavoidable uncertainties and error. Utah Municipals
contend that, while technology that permits perfectly accurate
scheduling (i.e., namely the AGC equipment used by control area
operators) is theoretically available, it is prohibitively expensive
for many transmission customers and unavailable to those who do not own
generation. Utah Municipals argue that financial incentives for
accurate scheduling do not alter scheduling behavior or actual
imbalances, but only result in a potential windfall for the
transmission provider and a potentially significant competitive
advantage for the transmission provider's market function, which
(because of the AGC equipment that all transmission customers pay for
through rates) will not be subject to the charges. Utah Municipals
suggest that the Commission limit the imbalance charges for
unintentional deviations by applying the third deviation band only to
intentional imbalances.
    648. Imperial argues that the Bonneville approach would not provide
appropriate incentives for small geothermal generating units on its
system to control their scheduled output, especially if imbalances are
recorded on an hourly basis rather than on a cumulative basis over the
course of a month. Under the Bonneville approach, Imperial asserts that
it would have to pay its generators 100 percent of its incremental cost
for overgeneration because such imbalances are usually less than 2 MW
in any given hour. It states that using a 100 percent credit for net
overgeneration would result in crediting the generator more than
$28,500.
    649. WECC states that it is very important to differentiate between
the kind of behavior that the Commission is worried about and
appropriate practices that support system reliability. WECC is
concerned that inflexible generator imbalance provisions in the pro
forma OATT may create incentives for generators in the West to restrict
governor action on their generators in ways that degrade system
reliability. WECC notes that the number of rotating machines connected
to the grid in the Eastern Interconnection is much greater than in the
Western Interconnection, which impacts the ability of generators to
respond to maintain frequency when a system's load-resource balance
changes. WECC explains that a sudden change in load-resource balance of
a particular magnitude (for example, the loss of a 1,000 MW generating
plant) will require a proportionately greater response from each
generating unit in the West as compared to the Eastern Interconnection.
WECC contends that in the West a significant frequency decline could
cause responding generators to exceed a 1.5 percent deviation threshold
applied under current pro forma Tariff imbalance schedules.
    650. If the manner of implementing generator imbalance charges in
the West does not consider the need for generators to respond to
frequency deviations, WECC worries that these charges could produce
perverse incentives that will undermine reliability. WECC argues that
generators that use set-point controllers to override governor action
will be less likely to incur imbalance charges and penalties, while
those with properly operating governors may be punished for deviating
from scheduled output to respond to system reliability needs. WECC
believes that this has in fact been happening in the West and is one of
the reasons that frequency response in the Western Interconnection has
deteriorated in recent years. WECC urges the Commission to consider how
generators can be given appropriate incentives to meet their
obligations to supply energy to load but also to support system
reliability by effectively responding to frequency deviations. WECC
explains that the Commission could adopt a policy that set-point
controllers should not be allowed to override governor response. WECC
suggests that deviations from scheduled generator output needed to
correct frequency decay could be excused from imbalance penalties under
the pro forma OATT.
    651. Indianapolis Power contends on reply that variation should be
allowed to account for the individual facts and circumstances
associated with a specific region as well as specific types of
intermittent resources. A number of entities agree with providing
flexibility to intermittent generators, but suggest different ways of
doing so.\392\ Fertilizer Institute agrees that intermittent resources
should be exempt from any penalties beyond the 90 percent/110 percent
``second tier.'' However, Fertilizer Institute also believes that
intermittent resources should receive greater tolerance before they run
into the 90 percent/110 percent penalty level in the first place.
Fertilizer Institute urges the Commission to relax the first-tier
tolerance band from 2MW to 20MW (or 40 percent of nameplate capacity,
whichever is greater) for intermittent generators only. It asserts that
this action is consistent with the Commission's recognition that
intermittent generators can undergo sudden changes of conditions for
which they cannot fairly be held responsible. Fertilizer Institute
argues that a broader first-tier tolerance band for these generators
will present no threat to the transmission grid, because intermittent
generation facilities are limited both in size and in number.
    652. Geothermal Producers supports a first-tier deviation band of
+/-5 percent for intermittent resources, rather than the 1.5 percent
threshold proposed by Bonneville. Geothermal Producers believes a 5
percent band is appropriate for intermittent resources, since a five
percent band more accurately recognizes that intermittent resources are
less capable of controlling deviations from schedules than are
conventional resources. For over- or under-deliveries in excess of five
percent, Geothermal Producers contends that intermittent resources
should be charged no more than the control area's cost of supplying
energy to correct the imbalance. Geothermal Producers also supports
Bonneville's position that intermittent resources should be exempt from
the third-tier deviation band and instead should pay the second-tier
deviation band charges for all deviations greater than the second-tier
deviation band.
---------------------------------------------------------------------------

    \392\ E.g., NorthWestern, Fertilizer Institute, and Geothermal
Producers.
---------------------------------------------------------------------------

    653. Other commenters, however, do not support providing exceptions
for

intermittent resources.\393\ If society decides to provide incentives
for intermittent resources, Morgan Stanley states that this is better
done in a direct fashion, such as a certification program akin to
resource adequacy rules that require LSEs to source a proportion of
supply from such resources. Morgan Stanley asserts that this would
motivate developers to mitigate imbalance costs through other market or
technical means to the full extent of the economic signal imbedded in
the imbalance price and thereby optimize the design and operation of
such resources. MidAmerican argues on reply that special treatment of
intermittent resources and loads has the effect of penalizing those
resources and loads that have made investments to manage scheduling and
enhance reliability. TDU Systems believe that the NOPR's third
principle, which requires transmission providers to accord special
treatment to intermittent generators, is contrary to the principle of
comparability.
---------------------------------------------------------------------------

    \393\ E.g., Morgan Stanley, Northwest IOUs, Steel Manufacturers
Association, and TDU Systems.
---------------------------------------------------------------------------

    654. Northwest IOUs argue that the transmission provider should
have the option to elect whether to exempt intermittent resources from
the third-tier deviation band and instead charge, in a not unduly
discriminatory or preferential manner, the second-tier deviation band
charge for all deviations greater than the larger of 1.5 percent or 2
megawatts.
    655. Several commenters suggested that the Commission include a
definition of intermittent resource in the final rule. Fertilizer
Institute and South Carolina E&G contend that it is essential for the
Commission to provide a clear definition of ``intermittent generation''
or ``intermittent resource'' to avoid disputes. Fertilizer Institute
argues that the question of whether a given generator is
``intermittent''--and thereby entitled to the special provisions--is
likely to become a source of contention. Fertilizer Institute suggests
that an intermittent resource be defined as ``an electric generator
that (1) Cannot store its fuel sources and (2) has limited capability
to be dispatched and to respond to changes in system demand and
transmission security constraints.'' EEI, however, suggests that the
definition apply only to weather-driven units. Fertilizer Institute
argues on reply that restricting the definition in this way would be
unduly discriminatory. Fertilizer Institute argues that the definition
should include the most common forms of intermittent generation--wind
and solar power--as well as the less common but equally valuable forms,
such as generation with ocean energy or ``waste heat'' from an
industrial process. Fertilizer Institute asserts that the Commission
should not broaden the definition of intermittent resource to encompass
generators who are not truly ``intermittent'' and should not narrow the
definition to exclude some intermittent generators in favor of others.
Fertilizer Institute contends on reply that a generator should not have
to be ``weather-driven'' to qualify as ``intermittent.'' Geothermal
Producers supports the inclusion of geothermal energy as an
intermittent resource. Geothermal Resources contends that geothermal
resources satisfy both the Commission's proposed definition and the EEI
proposal.
    656. Ameren and Entergy ask the Commission to clarify that it does
not intend to amend any existing interconnection agreements to require
the use of any pro forma imbalance penalties. Entergy believes that the
present form of its Generation Interconnection Agreement is absolutely
critical to managing imbalances on its system and maintaining
reliability. Entergy states that it has developed specialized software
to monitor and manage generator imbalances and employs six system
operators (one per shift) to monitor and manage generator imbalances.
    657. Although Entergy supports the ``grandfathering'' of existing
generator imbalance arrangements, it does not believe that it would be
appropriate to require the prospective use of a different methodology
while simultaneously maintaining the grandfathered arrangements.
Entergy contends that administering two different generator imbalance
arrangements would not be consistent with the comparability principles
of Order No. 888 and would be difficult and costly from an operational
perspective.
    658. Several commenters \394\ argue on reply that it would be
inappropriate for the Commission to grandfather existing imbalance
provisions. In its reply comments, Entegra argues that prior
arrangements should remain in place only if a transmission provider can
demonstrate that its existing imbalance arrangements are consistent
with or superior to the provisions of the pro forma OATT as modified by
the Final Rule in this proceeding.
---------------------------------------------------------------------------

    \394\ E.g., Fertilizer Institute, Entegra, and TAPS.
---------------------------------------------------------------------------

    659. EEI and Exelon contend that the transmission provider may not
be able to charge a generator under its OATT if the generator is not
the transmission customer and, therefore, generators should be able to
include standardized imbalance terms in agreements with eligible
customers prior to providing service. Exelon suggests that the
Commission both adopt in the pro forma OATT a standard imbalance
penalty structure and direct transmission providers to include the same
terms and conditions in their interconnection agreements with
generators. TAPS suggests on reply that each generator could simply be
required to sign a service agreement that requires it to comply with
the generator imbalance provisions of the transmission provider's OATT.
Unless the pro forma OATT governs both generator and load imbalances,
TAPS argues that it would be impossible to implement and enforce the
Commission's prohibition against charging both energy and generator
imbalances for a single transaction.
    660. ICNU argues on reply that the Commission should adopt less
restrictive imbalance charges for retail access customers or, at a
minimum, continue to recognize that the standard energy imbalance
charge needs to be modified to accommodate direct access customers.
ICNU asks the Commission to modify its proposed imbalance provision to
reflect the unique characteristics of direct access customers by
adopting wider imbalance bandwidths and/or waiving the more punitive
adders associated with higher deviations.
    661. Several entities assert that the proposed imbalance reform
should not apply to RTOs. Exelon requests that the Commission
explicitly state that these rules do not apply in regions that have
organized markets, such as PJM, that obviate the need for imbalance
penalties. They contend that within organized markets, an imbalance
penalty rule is not necessary, as the independent transmission
operators have effectively addressed the concerns that the proposed
imbalance schedules are intended to address. Indicated New York
Transmission Owners contend that the Commission should grant the NYISO
a regional variation from the revised pro forma OATT with respect to
imbalance charges. It contends that the existing mechanisms in ISO/RTO
markets with LMP are consistent with the Commission's objectives in its
NOPR and that the Commission should permit a regional variation to the
NYISO. SPP states that the Commission should state that it does not
intend to affect its effort to implement a real-time energy imbalance
market by any final rule. SPP further contends that the Commission
should clarify that its energy imbalance changes do not apply to ISOs
and RTOs with organized

markets providing for real-time energy imbalance markets. SPP believes
that the Commission should view the existence of a spot energy price in
organized markets as superior to penalties based on incremental costs
or some multiple thereof.
    662. Entegra suggests that, since many RTOs have (or are
developing) separate markets for commitment costs, it may not be
necessary to incorporate such costs into imbalance prices in certain
RTO markets. Organizations of MISO and PJM States contend that this
proposed change to Schedule 4 is not applicable in the RTO context and
argue that, to the extent that the Commission's suggestions regarding
the special circumstances presented by intermittent generators are
applicable to RTOs, those issues are best addressed in a context other
than the instant rulemaking proceeding.
Commission Determination
    663. In order to increase consistency among transmission providers
in the application of imbalance charges, and to ensure that the level
of the charges provides appropriate incentives to keep schedules
accurate without being excessive, the Commission adopts in the pro
forma OATT imbalance provisions similar to those implemented by
Bonneville. We agree with commenters that a graduated bandwidth
approach recognizes the link between escalating deviations and
potential reliability impacts on the system. Furthermore, we conclude
that these provisions adhere to the three principles discussed in the
NOPR, which we also adopt here: (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.
    664. Specifically, imbalances of less than or equal to 1.5 percent
of the scheduled energy (or two megawatts, whichever is larger) will 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) will 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) will be settled at 75
percent of the system decremental cost for overscheduling imbalances or
125 percent of the incremental cost for underscheduling imbalances.
    665. The Commission adopts Bonneville's tariff provisions that
provide that 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.
We believe this is consistent with the fact that intermittent
generators cannot always accurately follow their schedules and that
high penalties will not lessen the incentive to deviate from their
schedules.
    666. Several commenters argue that the Commission should adopt a
standard definition of intermittent resource. In order to clarify
application of imbalance charges, we define an intermittent resource
for this limited purpose as ``an electric generator that is not
dispatchable and cannot store its fuel source and therefore cannot
respond to changes in system demand or respond to transmission security
constraints.'' \395\ We conclude that this definition of intermittent
resource properly limits the exemption from imbalance charges, without
excluding certain classes of intermittent generators for which the
exemption is appropriate (e.g., non-weather driven intermittent
resources).
---------------------------------------------------------------------------

    \395\ See Docket No. RM05-10-000. We note that this definition
was proposed by the Commission in the NOPR on Imbalance Provisions
for Intermittent Resources. See 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 (2005).
---------------------------------------------------------------------------

    667. The Commission believes that adopting a tiered approach for
both energy and generation imbalances will best 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.
Furthermore, we conclude that the partial exemption from imbalance
charges for intermittent resources appropriately reflects the special
circumstances faced by such resources and, consequently, is not unduly
discriminatory. Moreover, formalizing generator imbalance provisions in
the pro forma OATT will standardize the future treatment of such
imbalances from the wide variety of generator imbalance provisions that
exist today in various generator interconnection agreements.
Standardizing generator imbalances should lessen the potential for
undue discrimination, increase transparency and reduce confusion in the
industry that results from the current plethora of different
approaches.
    668. Several commenters debate whether the imbalance provisions
adopted here should be applied to energy imbalances, generation
imbalances, or both. The Commission concludes that subjecting both
energy and generation imbalances to the same charges is appropriate.
Energy and generation imbalances have the same net effects on the
transmission system in requiring other generation to be ramped up or
down to make up for the imbalance. As such, the Commission will modify
the current pro forma OATT Schedule 4 treatment of energy imbalances
and adopt a new separate pro forma OATT Schedule 9 for the treatment of
generator imbalances, each based on the tiered structure described
above. To the extent a transmission provider wishes to deviate from
these revised pro forma provisions, it may demonstrate in an FPA
section 205 proceeding that the proposed changes are consistent with or
superior to the pro forma OATT as modified by this Final Rule. However,
we note that proposed alternative provisions must comply with the three
imbalance charge principles addressed in the NOPR and adopted in this
Final Rule and be consistent with or superior to the specific imbalance
charges set forth in the pro forma OATT (and discussed above).
    669. Some commenters stated that the Commission should require
transmission providers to establish, or permit market participants to
establish, markets or pools for the netting and settlement of
imbalances. As explained previously, the purpose of this rule is to
strengthen the pro forma OATT to remedy undue discrimination and not to
impose any particular market structure. If transmission providers offer
to modify their OATTs to allow such pools, we will consider such
proposals. But, imposing such requirements goes beyond the scope of
this proceeding. The Commission therefore declines, for all these
reasons, to impose the structural reforms requested by some commenters.
    670. The Commission instead adopts the three-tiered approach in the
pro

forma OATT. As with other reforms adopted in this Final Rule, all
transmission providers must submit compliance filings containing these
pro forma tariff provisions. Transmission providers with previously-
approved tariff provisions governing imbalances that no longer conform
to the pro forma OATT, as revised in this Final Rule, may seek renewed
approval of those tariff deviations in accordance with the procedures
described in section IV.C above, demonstrating that the alternative
imbalance charge structures are consistent with or superior to the
reformed pro forma OATT. With respect to the concerns raised by ISOs
and RTOs, we agree that LMP-based markets can provide an efficient and
nondiscriminatory means of settling imbalances and, as indicated in the
NOPR, we are not proposing to redesign ISO/RTO markets in this
rulemaking. Nevertheless, ISOs and RTOs must follow the procedures
described in the Applicability section for seeking approval of
deviations that are consistent with or superior to the pro forma OATT.
    671. We do not, however, abrogate existing generator imbalance
agreements between transmission providers and their customers. These
agreements have been negotiated between willing parties, and the
Commission will not re-open them generically in this proceeding. To the
extent a particular party desires to amend an existing generator
imbalance agreement in light of the reforms we adopt in this Final
Rule, that party may exercise whatever rights it may have under the
agreement or FPA section 206.
    672. With regard to WECC's frequency-response concerns, we agree
that a generator should be excused from imbalance penalties that occur
due to directed reliability actions by generators to correct frequency.
It would not be appropriate to assess imbalance charges on generator
deviations that are associated with supporting system reliability by
responding to frequency deviations as directed by the transmission
provider or general reliability requirements. As such, if a response
from a generator (particularly in the West) is required to prevent
frequency decay and the corresponding deviations from the generator's
schedule would cause additional imbalance penalties, the transmission
provider should exempt the generator from those penalty charges.
b. Intentional Deviations
NOPR Proposal
    673. In the NOPR, the Commission noted that the Bonneville
imbalance provision allows for greater charges when a customer has an
``intentional deviation.'' \396\ The Commission sought comment on
whether the pro forma OATT imbalance provision should provide for
similar 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.
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    \396\ 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.
---------------------------------------------------------------------------

Comments
    674. Several entities contend that higher imbalance charges and
penalties for deliberately leaning on the grid can be appropriate.\397\
Imperial supports an imbalance provision that allows for greater
charges for persistent or patterned deviations. Pinnacle agrees that
deliberate reliance on the transmission provider's generation resources
is inappropriate and could adversely affect the reliability of the
transmission system, but they are unsure if such an intentional
deviation could be proven. Imperial also expresses concern that the
burden to prove the intent of the generator will fall on transmission
providers and that, in reality, transmission providers may face an
uphill battle to prove a generator's deviation was intended. South
Carolina E&G and Imperial request that the Commission provide a
specific process for imposing such penalties, including what procedures
should be followed if a transmission provider seeks to have the
Commission impose such penalties.
---------------------------------------------------------------------------

    \397\ E.g., Imperial District Irrigation, Progress Energy and
Ameren.
---------------------------------------------------------------------------

    675. Several entities oppose penalties for intentional deviations
or suggest modifications. Constellation supports an elimination of the
separate penalty structure for customers deliberately leaning on the
system. Constellation and Grant believe that a graduated percentage
adder/discount will provide the right incentives and disincentives
without the need for an intentional deviation provision. If deviation
costs are properly calculated, Morgan Stanley contends that requiring
those who deviate to pay the full marginal cost of that deviation would
result in fair allocation of cost responsibility and sufficient
stability of system operations as a result of both cost and risk
avoidance by participants. TDU Systems argue that the Commission should
eliminate the 100 mill per kWh floor for penalties for intentional
deviations.
Commission Determination
    676. The Commission recognizes the need to provide transmission
customers with the appropriate incentives not to intentionally dump
power on the system or lean on other generation. We do not believe,
however, that separate penalties for intentional deviations need to be
generically imposed in the pro forma OATT. The tiered imbalance
penalties adopted in this Final Rule generally provide a sufficient
incentive not to engage in such behavior. Proposals to assess
additional penalties for intentional deviations will continue to be
considered on a case-by-case basis, subject to a showing that they are
necessary under the circumstances. We note that any such tariff
provisions must include clearly defined processes for identifying
intentional deviations and the associated penalties.
c. Calculation of Incremental Cost
NOPR Proposal
    677. With respect to the pricing of energy and generation
imbalances, the Commission stated in the NOPR its belief that charges
based on incremental costs or multiples of incremental costs would
provide the proper incentive to keep schedules accurate without being
excessive. The Commission proposed that incremental cost be defined to
include both energy and commitment \398\ costs, to the extent
additional commitments are needed.\399\

The Commission sought comment on how such charges should be calculated,
as well as how they would be applied to transmission customers. The
Commission sought further comment as to how additional demand and
energy costs, if incurred in responding to imbalances, such as
redispatch, commitment, or additional regulation reserves, should be
appropriately reflected in the calculation of imbalance charges and
which customers should be charged for such costs.
---------------------------------------------------------------------------

    \398\ The Commission noted that ``capacity commitment'' is
generally 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).
    \399\ The Commission proposed defining incremental cost, based
on its decision in Consumers, 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.
---------------------------------------------------------------------------

Comments
    678. Several entities argue that incremental pricing for both
energy imbalances and generator imbalances should reflect the full
incremental costs incurred by the transmission provider (e.g., such as
redispatch costs, capacity commitment costs or additional regulation
reserve costs) resulting from the imbalance.\400\ Allegheny questions
whether the Consumer's definition is appropriate because ``the last 10
MW'' requirement is independent of the time of the scheduling
deviation. Allegheny contends that the definition should be modified
such that it specifically addresses the incremental dispatch to supply
the transmission provider's load ``in the hour in which the imbalance
occurs.''
---------------------------------------------------------------------------

    \400\ E.g., Allegheny, Ameren, Indicated New York Transmission
Owners, and FirstEnergy.
---------------------------------------------------------------------------

    679. Entergy argues that imbalance pricing on an hourly basis does
not capture all of the costs and reliability risk to the transmission
provider of over- and under-deliveries. Entergy states that the real-
time regulation burden imposed by IPPs is similar to the real-time
regulation burden imposed by loads, and loads are charged for this cost
through a transmission provider's Schedule 3 Regulation and Frequency
Response Service. Entergy asserts that the NOPR does not propose any
recovery mechanism for the regulation burden imposed by IPPs,
recognizing that Bonneville may not face significant generator
regulation costs due to the rapid ramping rate and relatively low cost
of hydroelectric resources. Entergy submits that its regional
experience has demonstrated that generator regulation service is a
necessity. Entergy states that its generator regulation service
recovers charges for the generating capacity that Entergy must maintain
on-line in order to respond to the moment-to-moment deviations between
scheduled output and actual generation. Entergy explains that the
charge compensates Entergy on a cost-basis for the generation capacity
used by IPPs, while at the same time sending the appropriate economic
signal that encourages generators to match their generation with their
schedules.
    680. In its reply comments, EEI argues that a transmission provider
should be entitled to recover the cost of additional reserves needed to
meet the increased reliability requirements resulting from the
provision of the imbalance energy if the transmission provider
generates additional energy to compensate for a load that schedules
less energy than it takes or a generator that produces less energy than
it schedules. EEI further contends that transmission providers should
be permitted to include in their calculation of imbalance charges any
other costs associated with committing a unit that is not on-line such
as minimum run times, losses, etc.
    681. Entergy opposes a single price for settling over-deliveries
and under-deliveries. For transmission providers who choose to base
energy and generator imbalance charges on incremental and decremental
costs, Entergy requests that the Commission not adopt standardized
definitions of incremental cost and decremental cost in the pro forma
OATT. In its reply comments, Entergy further argues that a requirement
that the transmission provider post incremental and decremental cost
information is unfair and harmful to the market, placing the
transmission provider at an unfair competitive disadvantage in the
market. Duke on reply proposes that System Incremental Cost (SIC) be
used to price both over-deliveries and under-deliveries. Duke defines
SIC to mean the incremental expense, measured in dollars per megawatt
hour, incurred by the utility to produce or procure the next megawatt
hour (MWh) of energy, after serving all of the utility's electric
energy and/or capacity sales. Duke proposes that SIC shall include but
not be limited to: The replacement cost of fuel; incremental operating
and maintenance costs; emissions allowance replacement costs and other
environmental compliance costs; the cost of starting and operating any
generating units, (including costs incurred due to minimum runtimes or
loading levels); purchase and interchange power costs; and all
applicable taxes or assessments based on the revenues received or
quantities sold.
    682. Allegheny states that the Commission should clarify that the
definition of incremental cost is equally applicable to intermittent
generator imbalance service as well as non-intermittent generator
imbalance service.
    683. Pinnacle and Utah Municipals request that the Commission allow
the use of alternative pricing methodologies, such as market proxy
pricing methodology based on trading hubs in or adjacent to their
respective control areas, where appropriate. Utah Municipals urge the
Commission to make clear in the final rule that market-based pricing
may be acceptable in some circumstances and to amend Schedule 4 of the
pro forma OATT to ensure that imbalance charges are designed not only
to provide legitimate incentives for accurate scheduling, but also to
avoid unjustified penalties (masquerading as ``incentives''), to
minimize the discriminatory impact of such charges, and to avoid
penalizing behavior or results that in fact help to keep the system as
a whole in balance.
    684. TDU Systems believe the Commission should disallow recovery of
demand charges or capacity commitment costs in any charges approved for
imbalances. TAPS and TDU Systems argue that capacity required to follow
load is already paid for by charges for regulation and reserves under
Schedules 3, 5 and 6. TDU Systems also support that the Commission
continue to apply its existing policy of imposing a heavy burden on
transmission providers to justify such demand or capacity commitment
charges in the context of a full base rate case, and of requiring
transmission providers to develop alternative solutions for balancing
schedules and loads.
    685. To the extent transmission providers are permitted to include
commitment costs in negative imbalance charges, Entegra believes that
additional monitoring would be needed, to include posting of hourly
imbalance charges, even if with a lag of a day or so. Suez Energy NA
contends that the Commission should require a transmission owner to
support its incremental cost filing on the basis of Form No. 423 data
and actual operations of the selected units, based on operational data
as reported in utilities Continuous Emission Monitoring reports.
    686. EEI argues that since Schedule 3, 5 and 6 charges recover the
costs of capacity based on test year data, they would not recover the
additional costs of reserves that transmission providers incur to
compensate for their customers' failures to match their schedules and
their loads or generator output, and they also do not recover other
commitment costs such as start-up costs or minimum run times. EEI
argues that if transmission providers could not recover such costs
through imbalance

charges, they would not be able to recover them at all.
Commission Determination
    687. The Commission concludes that it is appropriate to define
incremental cost, for purposes of the tiered imbalance provisions
adopted above, 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, as applicable.
    688. In deriving such charges, we note that the Commission proposed
in paragraph 244 of the NOPR that incremental cost be defined to
include both additional energy and commitment costs. The Commission
also sought comment on how additional demand and energy costs, such as
redispatch, commitment, or additional regulation reserves, would be
appropriately recovered if incurred in responding to imbalances.
    689. The Commission finds that it is appropriate, through the
definition of incremental cost, to allow for recovery of both
commitment and redispatch costs while excluding the cost recovery of
additional regulation reserve costs. Commitment and redispatch costs
shall be accommodated as a part of the hourly cost of the last 10 MW
dispatch and in the start up cost portion of the definition. The
Commission concludes that excluding additional regulation costs as a
general matter is appropriate since much of those costs would be demand
costs.\401\ We believe including charges for unit commitment costs
(e.g., start-up and minimum load costs) and O&M costs is necessary to
ensure that both energy and generation imbalance charges reflect the
full incremental costs incurred by the transmission provider. We
emphasize, however, that such costs should only be the additional costs
incurred by the transmission provider due to the imbalance. If
applicable, start-up costs should be allocated pro rata to the
offending transmission customers based on cost causation principles.
---------------------------------------------------------------------------

    \401\ To the extent a transmission provider wishes to recover
costs of additional regulation reserves associated with providing
imbalance service, it must do so via a separate FPA section 205
filing demonstrating that these costs were incurred correcting or
accommodating a particular entity's imbalances.
---------------------------------------------------------------------------

    690. If the transmission provider elects to have separate demand
charges assigned to customers for the purpose of recovering the cost of
holding additional reserves for meeting imbalances, the transmission
provider should file a rate schedule and demonstrate that these charges
do not allow for double recovery of such costs. To address Entergy's
concern that the real-time regulation burden imposed by IPPs is similar
to the real-time regulation burden imposed by loads, we will allow
transmission providers to propose separate regulation charges for
generation resources selling out of the control area and consider such
proposals on a case-by-case basis. We believe that the other demand
costs of providing imbalance service are already being provided under
Schedule 3, 5, and 6 charges.
    691. In responding to Allegheny's comments, we clarify that the
definition of incremental cost is equally applicable to intermittent
generator imbalance service as well as non-intermittent generator
imbalance service.
    692. We do not believe it appropriate to require transmission
providers to use market proxy pricing to calculate incremental costs in
the pro forma OATT. The feasibility of using market proxies must be
considered on a case-by-case basis, given the characteristics of each
market. If proposed, the proxy price must represent a valid alternative
to the incremental cost calculation, reflecting competitive,
transparent and liquid conditions similar to those that would exist in
the seller's market.\402\
---------------------------------------------------------------------------

    \402\ See RockGen Energy, LLC, 100 FERC ] 61,261 (2002) (setting
for hearing, inter alia, whether proposed market proxy price is
reliable, verifiable, and also indicative of the prevailing price in
liquid non-redispatch markets in the region).
---------------------------------------------------------------------------

d. Inadvertent Energy Treatment
NOPR Proposal
    693. The Commission proposed in the NOPR to continue to allow
inadvertent energy to be treated differently from energy and generator
imbalances, explaining that these two types of service are not
comparable. The Commission noted that, given the nature of inadvertent
energy and historical practices, transmission providers pay back
inadvertent energy imbalances and that the Commission has accepted this
practice as just and reasonable. The Commission sought 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. The Commission asked
whether pricing inadvertent energy at incremental cost (or some variant
thereof) would be an appropriate disincentive and, if any reforms in
this area are appropriate, whether they should be pursued under FPA
section 215 as part of the review of reliability standards.
Comments
    694. A number of commenters support continuing to allow inadvertent
energy to be treated differently from energy and generator imbalances,
agreeing that these two types of services are not comparable.\403\
Allegheny argues that this historical practice makes sense because the
variables germane to inadvertent interchange are beyond the control of
individual transmission providers and, therefore, are best addressed in
the context of reliability. Entergy notes that transmission customers
have some flexibility to mitigate the deviations between their
schedules and the operation of their load in real-time, while control
area interchange imbalances may involve the failure of control areas to
match their scheduled inflows and outflows due to contingencies
occurring even in a third control area.
---------------------------------------------------------------------------

    \403\ E.g., Entergy, Allegheny, Progress Energy, Public Power
Council, South Carolina E&G, PGP, and Ameren.
---------------------------------------------------------------------------

    695. Northwest IOUs argue that there is no reason to think that
there is abuse of one system leaning on another in regards to
inadvertent energy, particularly in light of Control Performance
Standards 1 and 2 and other protocols for balancing flows across
interconnections. Public Power Council states that in-kind return of
inadvertent energy between Balancing Authorities is governed by
numerous agreements and tariffs that are designed to limit the ability
of one system to lean on another.
    696. Sacramento states that the Commission expressed concern in
other settings that generators may intentionally undergenerate during
high-cost hours and make it up by overgenerating during low-cost hours
under a return-in-kind approach. Sacramento contends that in kind means
not only a return of energy, but a return of energy at like times and
conditions and does not believe that this results in leaning. In its
reply comments, Exelon requests that the Commission's imbalance penalty
rules explicitly prohibit the local utility Balancing Authority
operator from relying on inadvertent energy to balance its affiliated
generators' schedules and thus obtaining a competitive advantage.
    697. Other commenters disagree that inadvertent energy should
continue to be treated differently. Exelon expresses concern that in
regions without organized markets there is the potential

for local utility balancing authority operators to seek to avoid paying
deviation charges by favoring their own generators over merchant
generators or by using inadvertent energy to balance their schedule.
Exelon argues that a balancing authority operator could maintain system
balance by choosing to order its affiliated generators to deviate from
the schedule and thereby allow its affiliated generator to avoid
deviation charges that the merchant generator could not avoid. If the
local utility balancing authority operator relies on inadvertent energy
to balance its affiliated generators' schedules, Exelon contends it is
using an option that is unavailable to other generation resources and
obtains a competitive advantage.
    698. TDU Systems argue that energy imbalances and inadvertent
interchange may occur for many of the same reasons, e.g., telemetry
failure, meter error, generator governor response to system problems,
human error, and under- or over-supply of generation. TDU Systems state
that deviations between load and supply, whether in the form of energy
imbalances or inadvertent interchange, require adjustment or
compensation, but there is no reason why the form of that adjustment or
compensation should be different among transmission users. TDU systems
explain that NERC's Final Report of the Control Area Criteria Task
Force describes inadvertent interchange as one of the ``strong
incentives'' driving the newer market participants, such as independent
generators, to become control areas, and driving existing control area
operators to retain their functions.
    699. TDU Systems explain that as the Commission acknowledged in
Order No. 2000, for transmission providers in RTO regions, unequal
access to balancing options can lead to unequal access in the quality
of transmission service. TDU Systems oppose deferring consideration of
inadvertent interchange issues until the Commission's order in the
Mandatory Reliability Standards rulemaking proceeding in Docket No.
RM06-16-000. TDU Systems argue that the Commission should place energy
imbalance service on a footing as nearly comparable to inadvertent
interchange as feasible by allowing like-kind exchanges of energy, at
the incremental cost of their own supply portfolio, to remedy
imbalances in lieu of the present paradigm of punitive charges.
    700. TDU Systems also argue that the Commission should require
comparability between transmission providers and transmission customers
by imposing charges for inadvertent interchange at the suppliers'
incremental cost. FirstEnergy believes that the Commission should
establish a tiered penalty structure that, similar to the Bonneville
method discussed by the Commission, levies penalties based on the
severity of the inadvertent energy violation. TDU Systems state that
currently there are no penalties for under-supply even when one control
area could be deemed to be intentionally ``leaning'' on the grid to
arbitrage energy market prices; but there should be.
    701. FirstEnergy argues that a nationwide process should be
established by the Commission to eliminate regional differences in the
treatment of inadvertent energy. Constellation asks the Commission to
require that transmission providers specifically separate imbalances
from inadvertent energy and closely track and report the two.
Commission Determination
    702. As stated in the NOPR, the Commission finds that inadvertent
energy is not comparable to energy and generation imbalances and,
therefore, we will continue to allow inadvertent energy to be treated
differently from energy and generation imbalances. 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 generation and loads outside of the control area. Variables
affecting inadvertent interchange often depend on the actions or the
omissions of utilities other than the individual transmission providers
and are distinct from those resulting in energy and generation
imbalances.
    703. We also note that management of inadvertent energy is needed
to adhere to NAESB standards. Historically, transmission providers have
paid back inadvertent interchange imbalances in kind, which has not, as
a general matter, proven to be problematic. Our primary concern with
respect to inadvertent energy is to avoid incentives that could degrade
reliability. To date, the return-in-kind approach has proven to be
adequate as a general matter. However, if there is evidence that it is
no longer sufficient to maintain reliability, or is allowing certain
entities to lean on the grid to the detriment of other entities, the
Commission has authority under FPA section 215 to direct the ERO to
develop a new or modified standard to address the matter.
e. Netting/Crediting of Energy and Generator Imbalances
NOPR Proposal
    704. In the NOPR, the Commission sought 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.\404\ The Commission asked
whether the potential to allow netting for offsetting imbalances
contradicts the principle of encouraging good scheduling practices. The
Commission sought further 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.
---------------------------------------------------------------------------

    \404\ For example, the Commission noted that a transmission
customer scheduling 100 MWh over an hour, but with a load of 120
MWh, would face an imbalance of 20 MW. The Commission questioned
whether there should be a net charge if the customer also dispatched
its generation to the same 120 MWh. Similarly, what if a
transmission customer schedules 100 MWh, but has a load of 80 MWh
and dispatches its generation to 80 MWh?
---------------------------------------------------------------------------

    705. The Commission also proposed 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.\405\ The Commission explained 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.
---------------------------------------------------------------------------

    \405\ Imbalance Provisions Proceeding at 32,123 note 19 (citing
Niagara Mohawk, 86 FERC ] 61,009 at 61,028).
---------------------------------------------------------------------------

Comments
    706. A number of entities believe that transmission customers
should be permitted to net energy and generator imbalances to the
extent that such imbalances offset.\406\ Ameren and FirstEnergy assert
that netting better reflects the impact of imbalances. Morgan Stanley
argues that allowing such netting provides a clear competitive benefit
because it would allow competitive suppliers to offer a load following
service in competition with the transmission provider. Sacramento
agrees that netting of offsetting imbalances should be allowed

provided the transmission customer relies on reasonable load forecasts.
---------------------------------------------------------------------------

    \406\ E.g., Ameren, FirstEnergy, Xcel, Suez Energy NA, Morgan
Stanley, Sacramento, TDU Systems, and Utah Municipals.
---------------------------------------------------------------------------

    707. Utah Municipals and Steel Manufacturers Association argue that
the Commission should impose charges based on netted imbalances, both
for each customer and across the system as a whole. PGP contends that
there is no reason to charge for both imbalances if a generator
overruns during the same hour when a load overruns, so long as the
overruns cancel out within a given control area. Steel Manufacturers
Association contends that the Commission should incorporate control
area-wide netting of imbalances to ensure that penalties are only
assessed on significant imbalances and energy imbalance charges do not
become a windfall profit center for utilities. Utah Municipals suggest
that the Commission provide that all imbalances be netted for each hour
and that penalties (charges above or credits below actual costs) be
imposed only when the system as a whole is out of balance by more than
a de minimis amount and, even then, only on those customers whose
imbalances fall in the same direction as the system imbalance. Utah
Municipals note that Sierra Pacific has established a similar imbalance
mechanism, which appears to be working well in its control area.
    708. TDU Systems argue that the netting rules should be
sufficiently flexible to allow individual customers to net their
transactions within an hour, a day, a week or a month, so long as the
results keep the transmission provider economically whole. TDU Systems
state that the Commission should not impose a cap on the quantity of
netting allowed unless the transmission provider is able to demonstrate
that good system performance requires such a cap. Ameren suggests that
the Commission use a tiered system for determining when imbalances can
be netted, but argues that a transmission customer should not be
allowed to net offsetting imbalances elsewhere on the system if the
imbalance has the potential to have a significant reliability impact.
    709. FirstEnergy and Utah Municipals contend that both point-to-
point and network transactions should be eligible for netting. Utah
Municipals and NRECA in their reply comments note that the Commission's
reference to ``a particular transaction'' does not mesh with the needs
and practices of network customers, who do not attempt to match
portions of their total hourly loads with particular resources or
``transactions.'' Utah Municipals argue that the Commission's proposal
should be modified to make clear that such customers should be
permitted to net energy and generator imbalances within a single
control area to the extent they offset, with no requirement that the
imbalances be part of a single ``transaction.''
    710. Other commenters, however, contend that transmission customers
should not be permitted to net energy and generator imbalances.\407\
For example, Entergy and Pinnacle believe that to permit netting of
energy and generator imbalances is to undercut the very purpose of the
imbalance provisions, which is to provide adequate incentives to
schedule correctly and in accordance with good utility practice.
Pinnacle asserts that, depending upon the location, energy or generator
imbalances could create reliability or economic problems for specific
areas of the system and it is important that the transmission operator
know what is happening on its system and for the customer to adhere to
accurate scheduling. SPP argues that allowing netting of imbalance
energy between generation and load would allow price arbitrage that
would be unjust and unreasonable. Indicated New York Transmission
Owners assert that positive and negative imbalances do not actually
offset, as the NOPR would suggest, but rather each imbalance
independently places stress on the transmission system. Duke states on
reply that, although several commenters support netting imbalances, not
one entity supporting such netting has put forth a workable proposal
for how to implement such netting where multiple generators are serving
multiple loads.
---------------------------------------------------------------------------

    \407\ E.g., Entergy, Pinnacle, Indianapolis Power, and Indicated
New York Transmission Owners.
---------------------------------------------------------------------------

    711. Entergy believes that independent generators must take full
responsibility for meeting their own schedules, including making
adjustments to their schedules to conform them to their operation in
real-time. Entergy argues that a netting approach, however, would
provide an incentive for a generator to over-generate above its
schedule if its load proves to be greater than expected in real-time.
Entergy argues that allowing the netting of these imbalances will
result in the virtual elimination of transmission schedules.
    712. In instances in which transmission customers intentionally
game the transmission system through netting, FirstEnergy contends that
the transmission provider should have the ability to apply punitive
measures through a Commission-mandated penalty process. FirstEnergy
states that there appears to be no clear cut number which defines the
boundary between ``good'' netting and ``bad'' netting associated with
reliability issues and additional redispatch cost. During periods when
transmission constraints exist, Entergy contends that it may in fact be
ramping up some generators to respond to imbalances while ramping down
other generation to respond to other imbalances at exactly the same
time and, therefore, it is incorrect to assume that over-generation
supplied by one IPP accompanied by under-generation from another IPP,
even simultaneously, will have no operational effect or impose no costs
on a transmission provider.
    713. Allegheny believes that allowing netting of hourly deviations
inside the first deviation band on a monthly basis would not allow for
full recovery of imbalance costs because balances that occur in on-peak
periods cost more than imbalances that occur during off-peak periods.
Allegheny contends that deviations within the first band should be
measured and settled financially on an hourly or, at least, an on-peak/
off-peak basis, rather than allowing deviations during one part of the
month to be offset by deviations in another part of the month.
Indianapolis Power & Light Company argues that the imbalance volume
could be within the allowed bandwidth tolerance, but still be
significant enough to allow for the energy market participant to make
money off of the price difference.
    714. Entergy also contends that a crediting mechanism for generator
imbalances would be not appropriate. Entergy asserts that such a credit
would result in indifference by generators by largely immunizing them
from the costs resulting from their imbalances and, as a consequence,
produce economic inefficiencies and a potential threat to system
reliability. Entergy argues that the current method, which provides an
incentive to generators to control their own imbalances, is appropriate
because generators have a desire to accurately schedule to avoid
imbalances. Entergy argues that a non-offending generator in one hour
can be an offending generator in the next hour and that the credit will
bankroll generators so that penalty payments in one hour will be offset
and paid for by penalty receipts in another hour.
Commission Determination
    715. The Commission recognizes that there is a trade off between
the competitive benefits of reducing imbalance charges, including
allowing transmission customers to net energy and generation
imbalances, and the reliability implications of the transmission
provider needing to plan to accommodate such imbalances.

Allowing transmission customers to net imbalances would further
comparability between the transmission provider's dispatch and the
transmission customers serving load. However, netting and crediting
could lessen the incentive for accurate scheduling and resulting energy
or generator imbalances could create reliability or economic issues for
specific areas of the system if the transmission provider cannot
adequately plan for such imbalances.
    716. In weighing these tradeoffs, the Commission concludes that for
both energy and generator imbalance services it is not appropriate to
require transmission providers to allow netting of imbalances outside
of the tier one band. We agree that netting can cause problems because
netting would lessen the incentive for transmission customers to
schedule accurately, and inaccurate schedules, in turn, could require
actions by the transmission provider even when the imbalances offset.
Where transmission constraints exist, a transmission customer whose
load and generation was on net equal could still have an effect on the
transmission system if, as Entergy contends, some generation is ramping
up to respond to some imbalances while other generation is ramping down
at exactly the same time. Similarly, where transmission constraints
exist, if one IPP has a positive deviation from its schedule while
another IPP has a corresponding negative deviation from its schedule,
the transmission provider could need to ramp up generation in one area
while simultaneously ramping down generation in another area. Further,
we believe that flexible scheduling deadlines should allow transmission
customers to change their schedules such that their loads can be
accurately met and implementation of the tiered imbalance bands will
ensure that charges corresponding to imbalances are just and
reasonable.
f. Intra Hour Netting
NOPR Proposal
    717. Under the current pro forma OATT, energy imbalances occur when
there is a difference between the scheduled and the actual delivery of
energy to a load located within a control area aggregated over a single
hour. As a result, if a transmission customer is under its scheduled
level for the first half of a given hour, but over its schedule the
second half of the hour, there would be no imbalance charge. The
Commission did not address intra hour netting in the NOPR.
Comments
    718. Several commenters argue that the Final Rule should address
within-hour deviations that occur when generator imbalances are
calculated on an integrated hour basis.\408\ If the generator imbalance
is measured over an integrated hour, as is typical of the current
practice, TVA asserts that significant intra-hour swings may be masked.
---------------------------------------------------------------------------

    \408\ E.g., TVA, South Carolina E&G, and International
Transmission.
---------------------------------------------------------------------------

    719. South Carolina E&G states that generators, unable to ramp
precisely to the 15-minute schedules, often undergenerate in the
initial part of the hour, then overgenerate in later parts of the hour,
in order to integrate closer to the schedule when settled over the
entire hour. South Carolina E&G contends these intentional swings
burden the balancing authorities who are charged with continuously
keeping Area Control Error within predefined limits. International
Transmission argues that intentional swings in output can be quite
severe, imposing operational strains on the system, negatively
impacting the control area's ability to meet NERC Control Performance
Standards, and potentially jeopardizing reliability.\409\ Entergy
agrees that settling hourly energy imbalances with generators does not
provide adequate incentives for generators to schedule and dispatch
accurately within the hour. Entergy asserts that generators have
imposed significant moment to moment swings within the hour requiring
it to deploy its regulating reserves in response. Entergy states that
it has been increasingly difficult to meet NERC's operating criteria
for control area performance without committing, and incurring the
costs for, additional regulating reserves. TVA contends that all
generators should be required to ensure that the instantaneous
generation level equals the scheduled output. International
Transmission asks that the imbalance provisions in the Final Rule
address this situation by either specifying penalties that may be
assessed for within-hour variations or advising that transmission
providers may implement their own penalties to the extent that within-
hour variations cause operational difficulties.
---------------------------------------------------------------------------

    \409\ International Transmission provides the example that a
large generator with scheduled output of 100 MW for an hour might
stay at zero for the first 50 minutes of the hour and then generate
600 MW during the last ten minutes.
---------------------------------------------------------------------------

    720. South Carolina E&G contends that allowing generator imbalance
settlements over a shorter period, such as at 15-minute intervals,
together with the proposed tiered charges for imbalances, would provide
better, more refined incentives for generators to more closely match
their scheduled deliveries and would help balancing authorities reduce
Area Control Error excursions. TVA suggests generator imbalances be
measured on ten-minute intervals rather than integrated over an hour.
These ten-minute imbalances would not be netted against other imbalance
intervals, so as to avoid the problem of encouraging undergeneration
followed by overgeneration and vice versa. In addition to having
generator imbalance charges for generation outside the operating bands,
TVA argues that there should be a separate charge assessed based on the
peak generator imbalance between the scheduled and actual generation
recorded instantaneously during the clock hour to provide a further
incentive for proper generator scheduling.
    721. Pinnacle and Utah Municipals assert that a transmission
provider should only charge hourly generator imbalances or hourly
energy imbalances for the same imbalance. PGP argues that customers
should pay only one charge for the net imbalance that occurs within a
single control area, either energy or generation, unless congestion
occurs inside a control area that requires redispatch.
Commission Determination
    722. The Commission concludes that it is appropriate to maintain
the status quo of aggregating net generation over the hour in the pro
forma OATT. Requests by transmission providers to adopt a shorter
interval will continue to be considered on a case-by-case basis.\410\
The Commission acknowledges that shorter intervals may be appropriate
in particular circumstances and, for this reason, declined to use a
clock-hour interval in the Large Generator Interconnection Final
Rule.\411\ There, the Commission permitted use of an interval
``consistent with the scheduling requirements of the Transmission
Provider's Commission-approved Tariff and any applicable Commission-
approved market structure.'' \412\ Allowing transmission providers to
continue to propose alternative intervals for purposes of the pro forma
OATT imbalance provisions is therefore appropriate provided that such
proposals are consistent with relevant market structures.
---------------------------------------------------------------------------

    \410\ See Entergy Services, Inc., 102 FERC ] 61,014 (2003) and
Entergy Services, Inc., 111 FERC ] 61,314 (2005).
    \411\ See Order No. 2003 at P 335.
    \412\ See pro forma LGIA Article 4.3.1

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

g. Distribution of Penalty Revenues Above Incremental Cost
NOPR Proposal
    723. The Commission also sought comment in the NOPR regarding the
treatment of revenues the transmission provider receives above the cost
of providing the imbalance service.
Comments
    724. Various commenters state that the transmission provider should
retain any amounts above the incremental cost of providing imbalance
service. Ameren and Constellation argue such revenues should serve as a
contribution towards the fixed costs of providing this service. Entergy
argues that premium charges would compensate it for the administrative
costs of maintaining an organization capable of providing this purchase
and sales function and provide generators with an incentive to avoid
mismatches between scheduled quantities and actual deliveries to
Entergy. Entergy states that the Commission has previously recognized
that these generator imbalance charges are analogous to the economy
power rates that have historically included a percentage adder for out-
of-pocket costs to recover difficult-to-quantify costs.
    725. On the other hand, FirstEnergy states that the additional
revenue derived from charges above incremental costs should be provided
to generators and/or customers able to regulate load that provided the
redispatch, commitment, or additional regulation reserves. Utah
Municipals contend that the Commission should credit revenues from
charges above incremental costs to accurately-scheduling customers,
rather than to the transmission provider. Utah Municipals argue that
the penalty portion of incremental and decremental charges and rates
could be credited back to all transmission customers who incur
imbalance charges and whose schedules fell within the first deviation
band for that hour. Progress Energy suggests that all imbalance
revenues above the cost of providing the imbalance should be
distributed to all non-offending transmission customers, based on the
weighted amount of each non-offending transmission customer's usage of
the transmission provider's transmission system. TAPS and TDU Systems
ask on reply that penalty revenues not be earmarked for retail
customers.
    726. Morgan Stanley believes that imbalance charges should be
``keep whole'' charges calculated and designed to reimburse whoever
remedied whatever problem the imbalance caused while leaving the
transmission provider financially indifferent.
Commission Determination
    727. In this Final Rule, the Commission has reformed existing
imbalance provisions to reduce the variety of different methodologies
used for determining imbalance charges and ensure that the level of the
charges provide appropriate incentives to keep schedules accurate
without being excessive. We also believe that transmission providers
should have a consistent method of treating revenues received through
imbalance penalties or charges that are in excess of incremental cost.
The Commission has previously required transmission providers with
significant imbalance penalties to develop a mechanism to credit
penalty revenues to non-offending transmission customers.\413\ This was
intended to remove the incentive of the transmission provider to hinder
the development of other imbalance services that do not rely on
penalties.\414\ We believe it is appropriate to maintain the
requirement that transmission providers credit revenues in excess of
incremental costs. Therefore, as part of their compliance filings in
this proceeding, transmission providers are required to develop a
mechanism for crediting such revenues to all non-offending transmission
customers (including affiliated transmission customers) and the
transmission provider on behalf of its own customers. Such a
distribution of penalty revenues recognizes that transmission providers
bear the responsibility to correct imbalances and often use their own
facilities to do so.
---------------------------------------------------------------------------

    \413\ See Carolina Power & Light Co., 103 FERC ] 61,209 at P 25
(2003) (CP&L); Entergy Svcs., 105 FERC ] 61,319, reh'g denied, 109
FERC ] 61,095 at P 65-66 (2004).
    \414\ See Carolina Power & Light Co., 97 FERC ] 61,048 at 61,279
(2001).
---------------------------------------------------------------------------

    728. We acknowledge that in the CP&L decision, the Commission
declined to allow the transmission provider to allocate a share of
imbalance penalty revenues to itself as a user of the transmission
system on behalf retail customers. Given the reforms to the pro forma
OATT imbalance provisions adopted in this Final Rule, we believe the
circumstances presented in that case are no longer applicable. There,
the Commission based its holding on its understanding that the high
imbalance penalties imposed by the transmission provider were an
interim measure that were intended to be in place only until an
imbalance market was developed.\415\ In this Final Rule, we are
adopting imbalance charges that are closely related to incremental cost
and therefore minimize any incentive on the part of the transmission
provider to rely on penalty revenues rather than seeking other methods
of encouraging accurate scheduling. Under these circumstances, there
remains no reason to exclude the transmission provider from receiving
an appropriate share of penalty revenues.
---------------------------------------------------------------------------

    \415\ Id.
---------------------------------------------------------------------------

3. Credits for Network Customers
    729. In Order No. 888, the Commission established that network
customers should be eligible for credits for customer-owned
transmission facilities under certain circumstances. Specifically,
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. Section 30.9 also states
that new facilities are eligible for credits when the facilities are
jointly planned and installed in coordination with the transmission
provider.
NOPR Proposal
    730. In the NOPR, the Commission proposed severing the link in the
pro forma OATT between joint planning and credits for new facilities
owned by network customers because such linkage can act as a
disincentive to coordinated planning. The Commission proposed deleting
from section 30.9 the language that permits transmission providers to
refuse crediting for new network customer-owned facilities that are not
part of its planning process, and adding language that puts a greater
emphasis on comparability. Specifically, the Commission proposed 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 such facilities are integrated into the
operations of the transmission provider's facilities and if the
transmission facilities were owned by the transmission provider, they
would be eligible for inclusion in the transmission provider's annual
transmission revenue requirement as specified in Attachment H of the
pro forma OATT.
    731. In the NOPR, the Commission also declined to allow
transmission providers as part of this proceeding to automatically add
costs of credits to the transmission provider's cost of service.
However, the Commission stated that a

transmission provider may propose to add an automatic adjustment clause
to its rates in a filing submitted under section 205 of the FPA. The
Commission also explained that it would not propose to make credits
generically available to point-to-point customers that own transmission
facilities, but clarified that if some facilities owned by a point-to-
point customer meet all the criteria for credits, consistent with the
Commission's statement in Order No. 888, the Commission would address
such situations on a fact-specific, case-by-case basis.\416\
---------------------------------------------------------------------------

    \416\ Order No. 888 at 31,742; Order No. 888-A at 30,271.
---------------------------------------------------------------------------

a. Severance of Credits and Planning
Comments
    732. The NOPR proposal to sever the link between transmission
credits and joint planning by eliminating the joint-planning
requirement for credits for new facilities constructed by network
customers is supported by a cross-section of the industry.\417\ Exelon
asserts that linking credits to network customers with coordinated
planning simply creates an incentive for the transmission provider to
avoid coordinated planning with the network customers so that the
provider can avoid providing credits. In addition, the criterion of
``jointly planned'' with the transmission provider provides little or
no value for discerning what facilities should qualify for crediting
treatment. Further, Exelon argues, tying credits to joint planning is
no longer necessary because the Commission's regional planning
initiatives will insure that most, if not all, newly constructed
facilities will be jointly planned. While EEI disagrees that the joint
planning provision has acted as a disincentive to joint planning, it
agrees that the coordinated planning initiatives in the NOPR has made
the link unnecessary.
---------------------------------------------------------------------------

    \417\ E.g., Allegheny, East Texas Cooperatives, ELCON, Exelon,
FMPA, MDEA, MidAmerican, MISO, Suez Energy NA, Tacoma, TAPS, and
Utah Municipals.
---------------------------------------------------------------------------

    733. FMPA also argues that the link between credits and planning
discourages joint planning because companies can avoid transmission
rate credits, often for competitors, by simply refusing to jointly
plan. FMPA asserts that it makes no sense to create economic
disincentives to joint planning. According to these commenters,
transmission lines cannot be built without some exchange of
information; the joint planning link may discourage the most productive
exchange and can create needless and non-productive disputation over
whether joint planning did or should have taken place.
    734. PGP points out, however, that credits for new facilities can
only result from joint planning, because new facilities must be
interconnected with the existing grid, and planning studies are
necessary for that to happen. NorthWestern requests that the Commission
reconsider its proposal to allow crediting of customer-owned facilities
that have not been jointly planned with the transmission provider.
NorthWestern contends that allowing the construction of network
facilities and making a judgment after the fact is inefficient and will
result in protracted litigation and facilities that do not serve the
overall grid as efficiently as planned facilities. PNM-TNMP contends
that the Commission's proposed action to ``sever the link'' will excuse
the network customer from the coordinated planning process and can only
operate at cross-purposes with the coordinated transmission planning
goal that is addressed in the planning sections of the NOPR.
Commission Determination
    735. The Commission adopts the NOPR proposal to sever the link in
the pro forma OATT between joint planning and credits for new
facilities owned by network customers. The proposal received broad
industry support, and we agree with these commenters 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 in order to avoid granting credits for customer-owned
transmission facilities.
    736. We find that arguments against the proposal are largely
theoretical and do not adequately take into account the coordinated
planning provisions proposed in the NOPR. The coordinated planning
initiatives that the Commission is adopting in the Final Rule will
ensure that most, if not all, transmission facilities are planned on a
coordinated basis, making it unnecessary to retain this provision of
section 30.9.
b. The New Test to Determine Eligibility for Credits
    737. Comments support the test for new facilities proposed in the
NOPR.\418\ Some argue that the test for network customer credits should
continue to be whether the network customer's facilities provide
capability and reliability benefits to the grid--the same standard that
would apply to inclusion of the facilities in the transmission
provider's cost of service if the transmission provider constructed the
facilities.\419\ MidAmerican states that further clarification of this
point in the Final Rule would be beneficial in minimizing disputes over
this issue. Likewise, MidAmerican asks the Commission to clarify in the
Final Rule that such credit can be applied only to network customers
taking OATT service and not to transmission customers that are under
non-OATT (i.e., grandfathered bundled agreements) contracts. PGP
supports the new rules for granting credits to network customers, but
argues implementation details should be left up to individual
transmission providers.
---------------------------------------------------------------------------

    \418\ E.g., Allegheny, EEI, Exelon, MISO, Nevada Companies,
South Carolina E&G, Suez Energy NA, and Tacoma.
    \419\ E.g., Allegheny, Ameren, and MidAmerican.
---------------------------------------------------------------------------

    738. Although several transmission providers support the continued
use of the integration test,\420\ other commenters representing
municipal and public power interests ask that the Commission reconsider
or clarify its application.\421\ Some commenters argue that given the
Commission's current interpretation of ``integration'' for transmission
credit purposes and the historical application of the test, retaining
any integration requirement for existing or new facilities conflicts
with comparability or constitutes undue discrimination.\422\ TDU
Systems argue that the integration standard has encouraged
discriminatory behavior by allowing transmission providers to charge
network customers for transmission provider facilities constructed to
serve the transmission provider's native load, while refusing to pay
the network customer for comparable customer-owned transmission
facilities. TDU Systems further argue that the integration test has
resulted in a form of ``and'' pricing since the TDU Systems, as network
transmission service customers, remain obligated to pay their load
ratio share of the full transmission revenue requirement of the
transmission provider's system, including the cost of transmission
facilities built to serve the transmission provider's own loads.
---------------------------------------------------------------------------

    \420\ E.g., EEI, MidAmerican, and Nevada Companies.
    \421\ E.g., FMPA, NRECA, and TAPS.
    \422\ E.g., East Texas Cooperatives, NRECA, TAPS, and TDU
Systems.
---------------------------------------------------------------------------

    739. NRECA questions the Commission's statement in the NOPR that,
in order to satisfy the integration

standard, a 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.'' \423\ According
to NRECA, that statement identifies three nominal requirements for
customer facilities--integration, benefits and ``relied upon''--as
compared to the one nominal requirement for transmission provider
facilities--integration. This is fundamentally inconsistent with
comparability, NRECA continues, as the Commission seems to recognize in
its rationale for adding the comparability requirement to new
facilities.
---------------------------------------------------------------------------

    \423\ NRECA further notes that proposed OATT section 30.9 does
not include these additional ``benefits'' and ``relied upon''
requirements. NRECA argues that these requirements cannot be part of
the section 30.9, since regulatory preambles cannot vary the words
of the rule, citing Wyoming Outdoor Council v. U.S. Forest Service,
165 F.3d 43, 53 (D.C. Cir. 1999) (``[L]anguage in the preamble of a
regulation is not controlling over the language of the regulation
itself'').
---------------------------------------------------------------------------

    740. NRECA further argues that the NOPR failed to distinguish the
proposed new standard in revised section 30.9 from the Commission's
recent decision in North East Texas Electric Cooperative, Inc.,\424\
which found transmission provider facilities integrated on the grounds
that a showing of any degree of integration is sufficient, rejected a
``benefits'' requirement, and did not consider a ``relied upon''
requirement. East Texas Cooperatives argues that the Commission's
decision in East Texas Electric Cooperative, Inc. v. Central and South
West Services, Inc.,\425\ applied an integration requirement for
customer facility credits that was different and stricter than the
standard applied to a transmission provider's facilities.
---------------------------------------------------------------------------

    \424\ 108 FERC ] 61,084 (2004), reh'g denied, 111 FERC ] 61,189
(2005).
    \425\ 114 FERC ] 61,027 at P 42 (2006), appeal docketed, No. 06-
1090 (D.C. Cir. Mar. 10, 2006).
---------------------------------------------------------------------------

    741. Regarding the application of the integration component, FMPA
argues that, in order to avoid continued discrimination, it is
important that the Commission reaffirm that ``additional benefits to
the transmission grid in terms of capability, delivery options, and
reliability'' \426\ are benefits, regardless whether the transmission
customers or the transmission provider (or others) benefit. Similarly,
FMPA continues, the requirement that facilities must ``be relied upon
for the coordinated operation of the grid'' \427\ must equally include
operations that serve transmission providers, customers or others.
---------------------------------------------------------------------------

    \426\ NOPR at P 256.
    \427\ Id.
---------------------------------------------------------------------------

    742. Comments on the comparability component of the proposed
credits test for new facilities range from several requesting that the
Commission adopt a comparability-driven analysis \428\ to one asking
the Commission to eliminate the comparability component in favor of an
integration-only analysis.\429\
---------------------------------------------------------------------------

    \428\ E.g., APPA, FMPA, and NRECA.
    \429\ Entergy.
---------------------------------------------------------------------------

    743. Some commenters argue that eligibility for credits should turn
in the first instance on the comparability standard set forth in the
NOPR, otherwise the proposal does not eliminate undue
discrimination.\430\ NRECA argues that this requirement does not
abandon integration because current Commission policy requires a
Transmission Provider's facilities to be integrated for their cost to
be rolled in to the transmission provider's annual transmission revenue
requirement.\431\ APPA would apply an integration test only if the
transmission facilities for which the customer seeks credits are found
not to be eligible under this comparability standard.
---------------------------------------------------------------------------

    \430\ E.g., APPA, East Texas Cooperatives, FMPA, and NRECA.
    \431\ NRECA compares North East Texas Electric Cooperative,
Inc., 108 FERC ] 61,084 (2004), reh'g denied, 111 FERC ] 61,189
(2005) (finding transmission provider facilities integrated and
rolling in their cost over transmission provider objection) with
Mansfield Municipal Electric Department v. New England Power Co., 97
FERC ] 61,134 (2001), reh'g denied, 98 FERC ] 61,115 (2002) (finding
transmission provider facilities not integrated and rolling out
their cost over transmission provider objection).
---------------------------------------------------------------------------

    744. TAPS states that, by eliminating the integration test and
simply providing that customer-owned facilities would be eligible for
credits to the extent they would be included in the transmission
provider's rate base if they were owned by the transmission provider
(i.e.comparability test), the Commission would avoid litigation over
what (if anything) the separate ``integration'' requirement adds in the
proposed formulation. If the integration terminology is retained in
section 30.9, TAPS argues that the Commission at least should clarify
that the new integration test is truly different from the old
integration test and cannot properly be read as limiting the
comparability requirement and that the Commission will not follow
precedents developed in credits cases decided under the original
section 30.9.
    745. To provide a comparability baseline and eliminate the need for
an integration test, APPA recommends that transmission providers
provide a detailed inventory of the existing facilities owned by
transmission provider and network transmission customers that are
included in their annual transmission revenue requirement. Network
transmission customers could use the inventory, which would be updated
annually, to assess whether they currently own transmission facilities
comparable to those included in the transmission provider's
transmission rate base, or to third-party transmission facilities for
which credits are being provided.
    746. MDEA argues that proposed section 30.9 appears contrary to
comparability principles by imposing a standard for transmission
facilities owned by customers that is more stringent than the one
applied to the transmission provider's own facilities. In MDEA's view,
the NOPR proposal is inconsistent with prior Commission precedent to
the extent comparability is not required in evaluating eligibility of
existing facilities owned by transmission providers for cost
recovery.\432\
---------------------------------------------------------------------------

    \432\ MDEA cites Florida Power and Light Co., 116 FERC ] 61,013
(2006), and notes that the Commission applied principles of
comparability to a transmission provider's existing facilities.
---------------------------------------------------------------------------

    747. TDU Systems ask that the Commission clarify that the
comparability prong will be aggressively enforced. For example, TDU
Systems request that the Commission consider a bright-line voltage
criterion to address comparability, rather than leaving it to the
transmission provider's discretion as to whether the facilities would
be eligible for inclusion in the transmission provider's annual
transmission revenue requirement.
    748. Arguing against the use of the comparability component,
Entergy contends that it could cause significant confusion, and should
in no way change the basic requirements needed to show integration of
network customer facilities. According to Entergy, a network customer
should be entitled to credits only when the transmission provider
cannot meet the transmission provider's firm obligations without the
customer's transmission facilities.
    749. On reply, MDEA states that the principle of comparability
requires that there be no distinction based on ownership or between
existing and new facilities. It further asserts that Entergy attempts
to draw a distinction between customer-owned transmission facilities
needed by the transmission provider to meet the transmission provider's
obligations to native load and firm transmission customers (for which
credits should be available) and

facilities that a network customer decides that it needs to meet its
obligations. Entergy argues that credits should be available only for
the former type of facility. According to MDEA, there is no
justification for the distinction Entergy seeks to draw or the standard
it proposes to apply. Network customers pay a full load ratio share of
the embedded costs of the transmission grid, based on the premise that
the entire grid is available and required to support network loads. In
this regard, there is no difference between Entergy's native load and
network customer loads. Transmission facilities required to meet
network customer needs by definition are required to meet grid needs,
provided that such facilities are integrated with the transmission
network.
    750. Several commenters ask the Commission to consider crediting
mechanisms other than the NOPR proposal.\433\ For example, Entergy and
Exelon contend that new facilities should be eligible for credit only
if determined through the regional planning process that such new
facilities are needed, i.e., that a measurable system capability or
reliability benefit is provided. In their view, this will avoid
litigation of cases addressing questions of integration. Utah
Municipals argue that the Commission should not discount the potential
evidentiary value of joint planning in assessing eligibility for
customer credits. Taking a more expansive view, APPA argues that
network transmission customers also should be able to obtain credits
for transmission facilities they build pursuant to an open and
collaborative transmission planning process in their region or sub-
region. This additional opportunity for credits, according to APPA,
would spur participation in the transmission planning process and would
be superior to litigating the proper application of the integration
standard.
---------------------------------------------------------------------------

    \433\ E.g., Entergy, Exelon, and Utah Municipals.
---------------------------------------------------------------------------

    751. Entegra argues that the Commission should make the crediting
policy for network customers consistent with the Commission's policies
for generator interconnection facilities, and require credits to be
available for facilities that are integrated with the transmission
grid, without any showing of additional benefits and irrespective of
whether the service in question is interconnection service, network
service, or point-to-point service. Entegra further argues that the
Commission should allow customers to sell transmission credits to
obtain transmission service elsewhere on the transmission provider's
system. By allowing the development of a more liquid market for such
credits, Entegra reasons, the Commission could increase the willingness
of market participants to fund upgrades to the transmission system.
    752. TDU Systems request that the Commission recognize that
inequities have occurred and, if any upgrades are required to make
network customers' facilities comparable (or comparably integrated),
the costs of such network upgrades should be rolled into the
transmission providers' rates.
Commission Determination
    753. The Commission declines to adopt the credits test for new
facilities proposed in the NOPR. The intent underlying that proposal
was to prevent application of the integration test in a manner that
exclusively benefits the transmission provider.\434\ After reviewing
the comments, we conclude that the proposed test may not in fact
accomplish this objective. The test proposed in the NOPR may not
effectively set forth the relationship of the integration standard to
the comparability requirement. We therefore revise the test as follows,
to more accurately reflect the Commission's intent as expressed in the
NOPR: A network customer shall receive credit for transmission
facilities added subsequent to the effective date of the Final Rule if
such facilities are integrated into the operations of the transmission
provider's facilities; provided however, the customer's transmission
facilities shall be presumed to be integrated if the transmission
facilities, if 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.
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    \434\ See NOPR at P 256.
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    754. Under our precedent, a transmission provider's facilities are
presumed to provide benefits to the transmission grid, whereas a
transmission customer must make an affirmative showing that its
facilities provide benefits in order to qualify for credits.\435\ Under
the test we adopt in this Final Rule, a transmission customer will be
required to meet the integration standard under pro forma OATT section
30.9 in order to receive a credit for its facilities.\436\ Because
joint planning will no longer be required in order to obtain credits,
we find that it is particularly important in this context to require a
showing that a network customer's facilities provide benefits to the
transmission provider's grid, i.e., a transmission customer should not
be eligible for credits for facilities that the network customer may
use to provide service for itself but that the transmission provider
does not need to use to provide transmission service to any other
customer. However, to ensure comparability, a presumption of
integration will be afforded to transmission customer facilities if it
is shown that, if owned by the transmission provider, such facilities
would be eligible for inclusion in the transmission provider's rate
base.
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    \435\ See e.g., North East Texas Electric Cooperative, Inc., 108
FERC ] 61,084; East Texas Electric Cooperative, Inc. v. Central and
South West Services, Inc., 114 FERC ] 61,027.
    \436\ 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. 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). 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.'' 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).
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c. Application of the New Test to Existing Facilities
Comments
    755. Several commenters object to the Commission's proposal to
apply the new comparability test in section 30.9 to new facilities, and
not to existing facilities.\437\ If the Commission requires the same
integration standard for both existing and new facilities, East Texas
Cooperatives ask us to specify which integration standard--the pre-
existing integration standard, or the new standard that applies the
integration standard comparably--applies and explain the difference and
the basis for that choice. MDEA, FMPA and TAPS argue that no
distinction is warranted between the treatment of new and

existing facilities and that the same standard should apply.
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    \437\ E.g., APPA, FMPA, MDEA, NRECA, and TAPS.
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    756. TAPS clarifies that it is not suggesting that the standard be
applied retroactively to past uses, but rather prospectively to
existing facilities, with the key consideration being when the claim
for credits is brought and not when the facilities are constructed.
TAPS argues that it cannot be claimed that the revised standard should
apply only to new facilities because the comparability requirement is
new. To the contrary, TAPS contends that comparability has been the
theme and bedrock foundation of the Commission's transmission open-
access requirement since its inception.
    757. APPA argues that the Commission effectively acknowledges in
the NOPR that transmission providers have failed to plan new facilities
jointly with their transmission customers for the last ten years under
the current section 30.9, but offers no redress for this past
discrimination.
Commission Determination
    758. We conclude that the new test for determining credits will
apply only to transmission facilities added subsequent to the effective
date of this Final Rule. A number of customer-owned transmission
facilities have been developed, and resulting credits negotiated and
litigated, under the prior test which the Commission determined to be
just and reasonable at the time.\438\ We find no basis for revisiting
the Commission's determinations in those cases in this Final Rule. On a
prospective basis, however, given the increased planning and
coordination we require in the Final Rule, we believe it appropriate to
apply the new test for determining credits.
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    \438\ See East Texas Electric Cooperative v. Central and South
West Services, Inc., 114 FERC ] 61,027 (2006).
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d. Cost of Customer Facilities Automatically Included in Transmission
Provider Cost of Service Without a Rate Filing
Comments
    759. Several transmission providers argue that, contrary to the
Commission's proposal, credits should be added automatically to the
transmission provider's cost of service.\439\
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    \439\ E.g., Allegheny, EEI, MidAmerican, and Nevada Companies.
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    760. MidAmerican argues that requiring the transmission provider to
defer including the cost of the transmission credit until its next
filed transmission rate case penalizes the transmission provider's
shareholders who must unfairly bear the cost of providing the credit
until the next rate case. If the Commission does not allow automatic
rate recovery of the incremental cost of credits, MidAmerican
continues, the Commission should clarify that the customer will not be
allowed transmission facility credits until the rate adjustments are
filed and accepted by the Commission. MidAmerican explains that such
filings would examine only the new revenue requirements to be added and
should not require a general rate case for the transmission provider's
entire revenue requirement. Nevada Companies likewise argues that
credits should not be granted to network customers if the recovery of
those credits is not provided for in the revenue requirement.
    761. TAPS agrees with the Commission's conclusion that it would not
be appropriate in this rulemaking to allow transmission providers to
automatically add costs of credits to their cost of service, and that
such costs should continue to be evaluated as part of a regular
transmission rate case (or recovered through an approved formula rate).
APPA expresses concern that transmission providers may attempt to use
the Commission's decision not to allow them to add the costs of credits
associated with customer-owned transmission facilities automatically to
their costs of service as a pretext for not granting such credits in
the first instance (at least until they decide to file a new rate
case). APPA continues that a transmission provider's decision not to
exercise the option to file under FPA section 205 a new rate case or an
automatic adjustment clause should not serve as a reason to allow it to
decline to provide credits.
    762. EEI explains that the customary basis for not allowing single-
issue rate adjustments for new transmission facilities is that while
one aspect of the transmission provider's costs may have increased,
others may have decreased or load may have increased. This is not the
case with respect to the inclusion of the transmission costs related to
customer-owned facilities, EEI continues, since the existence of
customer-owned facilities does not have any impact on the transmission
provider's own cost of service. EEI concludes that a transmission
provider should not be forced into what is essentially re-justifying
its transmission cost of service simply because a customer receives a
credit for the integration of its own facilities.
    763. Some commenters also address the option currently open to
transmission providers to add an automatic adjustment clause to their
rates through a rate filing with the Commission.\440\ EEI argues that
if the concept of an automatic adjustment clause is just and reasonable
for one transmission provider, it is equally just and reasonable for
all transmission providers, and there is no need to adopt a case-by-
case approach. EEI further requests that the Commission clarify that
its policy is to accept rate adjustments that incorporate the costs
that transmission providers incur to provide credits related to
customer-owned facilities, provided that the rate adjustment
methodology is just and reasonable. MidAmerican contends that the
revenue requirement of the transmission provider and those of
transmission customers should not be co-mingled, rather, consistent
with Commission precedent, the burden is on the transmission-owning
customer to demonstrate to the Commission that its cost of service and
revenue requirement used to establish the amount of the credit are just
and reasonable before it can receive credits. As for nonjurisdictional
entities, MidAmerican explains that they may file for a declaratory
ruling from the Commission regarding their revenue requirement.
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    \440\ E.g., Allegheny, EEI, Exelon, and MidAmerican.
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    764. Allegheny argues that if the Commission continues to deny
transmission providers an automatic adjustment clause for these
credits, it should, at a minimum, assure transmission providers that
transmission credits will be recognized as a cost of service in FPA
section 205 rate proceedings.
    765. Entergy argues that the Commission should recognize that any
filed agreement providing for payments of credits would be subject to
the filed-rate doctrine.
Commission Determination
    766. We are not persuaded to generically allow automatic recovery
of the 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. Automatic recovery of the costs of credits
would be contrary to our long-standing policy concerning single-issue