revise Schedule 9 to allow a transmission provider to identify the
total amount of generator imbalance service it will offer.
    282. Other petitioners request clarification or rehearing regarding
the Commission's decision to exempt deviations associated with
correcting system frequency from associated imbalance penalties. Xcel
agrees with the Commission that generators should not be subject to
imbalance penalties that occur when the generator is responding to
reliability directives to correct frequency deviations and requests
that this exception be expressly incorporated into the pro forma OATT.
Xcel requests that the Commission either amend the Order No. 890 pro
forma OATT on rehearing or clarify that a transmission provider can
implement this practice by including such language in its compliance
filing. Xcel suggests that the Commission also could, in the
alternative, clarify that a transmission provider may implement this
practice by posting a business practice indicating the transmission
provider will waive such imbalance charges for generators correcting
frequency deviations on a non-discriminatory basis.
    283. EPSA and TAPS request that the Commission expand the exemption
to include other situations in which a generator is directed to be off-
schedule by transmission operators, balancing authorities, or
reliability coordinators. EPSA states, for example, that generators are
often given directives by balancing authorities in order to reduce
unscheduled flows on other systems and/or change line flows or voltage
levels. TAPS argues that there should be an exception for generator
imbalances resulting from transmission loading relief procedures (TLRs)
or other transmission provider instructions, and for both the
unexpected loss of a generating unit and the response of other
generators to replace that unit under the reserve sharing arrangements,
with resulting imbalances treated as being within the first deadband.
TAPS argues that penalizing imbalances in the case of forced generation
outages is particularly inappropriate since such charges do not give
plant operators any better incentive to schedule accurately because
unplanned unit outages by their very nature cannot be predicted and
scheduled.
    284. Several petitioners request that the Commission clarify its
definition of intermittent resources for purposes of applying imbalance
charges. TAPS argues that intermittent generation should include test
energy produced by newly completed units, so that generators are not
unduly penalized (i.e., at third-tier penalty levels) for output
variations that are inherently unpredictable. EEI and AMP-Ohio argue
that run-of-river hydroelectric generating facilities should be deemed
to be intermittent resources because their inability to store water to
produce energy on demand satisfies the intention of the Order No. 890
definition, notwithstanding the fact that strictly speaking they do not
have fuel sources. Northwestern, however, argues that run-of-river
hydroelectric projects should not qualify as an intermittent resource
because they generally do have the ability to predict flows and
schedule accurately. NorthWestern also requests that the Commission
specifically require utilities to update their tariffs to reflect this
new definition.
    285. AMP-Ohio also argues that intermittent resources should be
entirely exempt from imbalance penalties, arguing that it is unfair to
impose any level of penalties on resources that are not dispatchable.
In AMP-Ohio's view, wind generators and run-of-river hydroelectric
facilities alike depend on uncontrollable forces that

affect their actual levels of generation. AMP-Ohio argues that fully
exempting intermittent resources from imbalance penalties would not be
unduly discriminatory vis-[agrave]-vis generators that are dispatchable
since the different treatment would merely recognize their different
circumstances.
    286. Finally, Entergy asks that the Commission confirm that
transmission providers do not need to seek renewal of existing
generator imbalance agreements. Entergy contends that it is unclear
whether the procedures described in section IV.C of Order No. 890,
regarding Commission consideration of previously-approved variations
from the pro forma OATT, are intended to apply to generator imbalance
agreements that have been previously negotiated between willing
parties.
Commission Determination
    287. The Commission affirms the decision in Order No. 890 to adopt
standardized generator imbalance provisions in Schedule 9 of the pro
forma OATT. We agree with Sempra Global that section 3 of the pro forma
OATT, as revised in Order No. 890, does not properly reflect that
generator imbalance service must be offered for any transmission
service used to deliver energy from a generator located within the
transmission provider's control area, as required in Schedule 9. We
revise section 3 to make this clear.
    288. We also agree with EEI and Southern that, in certain
circumstances, it may be appropriate for the transmission provider to
allow a generator located within its control area to execute a service
agreement for generator imbalance service, even if the generator is not
otherwise a transmission customer. Without settling with the individual
generator, it could be impossible for the transmission provider to
determine which transmission customer should be assessed a charge and
how the billing would be determined if a single generator was selling
to multiple customers. We have revised Schedule 9 of the pro forma OATT
to require the transmission provider to offer generator imbalance
service to any generator in its control area (subject to the
limitations discussed below). We clarify that, if a generator has
executed a service agreement for generator imbalance service, any
transmission customer scheduling from the generator will be deemed to
have satisfied its obligation to purchase generator imbalance service
under section 3 and Schedule 9.
    289. We further clarify that a transmission provider only has to
provide generator imbalance service from its own resources to the
extent that it is physically feasible to do so (i.e., the transmission
provider is able to manage the additional potential imbalances without
compromising reliability). It is not the Commission's intent to require
transmission providers to provide generator imbalance service from its
resources when it would unreasonably impair reliability. Each
transmission provider therefore may state on its OASIS the maximum
amount of generator imbalance service it is able to offer from its
resources, based on an analysis of the physical characteristics of its
system. Alternatively, a transmission provider may consider requests
for generator imbalance service on a case-by-case basis, performing as
necessary a system impact study to determine the precise amount of
additional generation it can accommodate and still reliably respond to
the imbalances that could occur.
    290. This does not relieve the transmission provider of its
obligation to provide generator imbalance service if it is able to
acquire additional resources in order to do so. We acknowledge PNM's
concerns that some control area operators may only be able to provide
generator imbalance service by procuring balancing energy and
associated capacity from another entity. If it is not physically
feasible for the transmission provider to offer generator imbalance
service using its own resources, either because they do not exist or
they are fully subscribed, the transmission provider must attempt to
procure alternatives to provide the service, taking appropriate steps
to offer an option that customers can use to satisfy their obligation
to acquire generator imbalance service as a condition of taking
transmission service. In the unlikely circumstance that there are no
additional resources available to enable the transmission provider to
meet its obligation for generator imbalance service, the transmission
provider must accept the use of dynamic scheduling to the extent a
transmission customer has negotiated appropriate arrangements with a
neighboring control area.\103\
---------------------------------------------------------------------------

    \103\ The Commission addresses request to require transmission
providers to offer dynamic scheduling as a new service under the pro
forma OATT in section III.D.1.d.
---------------------------------------------------------------------------

    291. We also reject requests to further exempt intermittent
resources by eliminating imbalance penalties altogether for such
resources. Generator imbalance charges are based on the incremental
costs incurred by the transmission provider to respond to the
generator's imbalance. In the second tier, charges escalate somewhat to
provide an incentive for generators not to deviate outside of the first
tier. Without this penalty component, intermittent resources would not
have any additional incentive to accurately schedule. At the same time,
the Commission recognized that intermittent generators cannot always
accurately follow their schedules and therefore exempted those
resources from third-tier penalties. If given proper incentives,
intermittent generators can improve their forecasting methods in order
to submit more accurate schedules. Thus, we continue to believe this
relaxed penalty structure strikes the right balance between the need to
encourage accurate scheduling and the operating limitations of
intermittent resources.
    292. We agree with EEI and AMP-Ohio that the definition of
intermittent resources includes run-of-river hydroelectric units that
do not store water used to generate electricity, i.e., for which
instantaneous inflow equals instantaneous outflow. Hydroelectric units
using storage, however, are not intermittent resources within the
meaning of Schedule 9 of the pro forma OATT. The ability of those units
to schedule their output is not as limited as intermittent resources.
The same is true of newly completed generating units producing test
energy. Under the pro forma OATT, generators do not have to submit
final schedules until the morning of the prior operating day and may
revise those schedules up until 20 minutes prior to the operating hour.
We conclude that this provides sufficient flexibility for hydroelectric
units using storage and newly completed units producing test energy to
change their schedules to reflect forecasted output and that any
charges resulting from remaining imbalances are just and reasonable
under the reformed generator imbalance provisions of the pro forma
OATT.
    293. We agree with Xcel that the exemption from generation
imbalance penalties for generators responding to correct frequency
decay should be expressly stated in the pro forma OATT. We also agree
with EPSA and TAPS that a generator that deviates from its schedule due
to directives by balancing authorities, transmission operators, and
reliability coordinators should not be subject to the penalty component
of imbalance charges and that this exemption should be expressly stated
in Schedule 9. It would be inappropriate to assess imbalance penalties
on generators following instructions to, for example, reduce
unscheduled flows on other

systems (such as a TLR) or change line flows or voltage levels, because
such charges could create incentives not to respond and in turn
compromise reliability. Similarly, generators responding to a reserve
sharing event, with properly structured arrangements with transmission
providers, should not be subject to penalties. We revise Schedule 9
accordingly.
    294. We decline, however, to carve out an exception for imbalances
associated with the loss of a generating unit itself. We disagree with
TAPS that penalizing imbalances in the case of forced generation
outages does not give plant operators any better incentive to schedule
accurately. Appropriately designed penalties provide a proper incentive
for generators to reduce instances of forced outage by, for example,
properly maintaining their facilities, and therefore adhere to their
schedules.
    295. Finally, we reiterate in response to Entergy that the
Commission did not intend to abrogate existing generator imbalance
agreements as a part of this rulemaking proceeding.\104\ The imbalance-
related reforms do, however, apply to provisions contained in a
transmission provider's OATT, including previously-approved variations
from the pro forma OATT. Transmission providers were given an
opportunity to seek continued approval of such previously-approved
variations, provided the variations continued to be consistent with or
superior to the revised pro forma OATT. We note that Entergy made such
a showing with respect to the generator imbalance provisions of its
OATT.\105\
---------------------------------------------------------------------------

    \104\ See Order No. 890 at P 671.
    \105\ See Entergy Services, Inc., 120 FERC ] 61,042 (2007).
---------------------------------------------------------------------------

c. Intentional Deviations and Intra-hour Netting
    296. The Commission declined in Order No. 890 to impose generic
penalties in the pro forma OATT for intentional deviations, concluding
that the tiered imbalance penalties generally provide a sufficient
incentive not to engage in such behavior. The Commission explained that
proposals to assess additional penalties for intentional deviations
would continue to be considered on a case-by-case basis, subject to a
showing that they are necessary under the circumstances. Any such
tariff provisions must include clearly defined processes for
identifying intentional deviations and the associated penalties.
Requests for Rehearing and Clarification
    297. South Carolina E&G argues that the Commission should grant
rehearing to assess additional penalties for entities that deliberately
lean on the system or, in the alternative, provide for generator
imbalance settlements over a shorter period than one hour. In its view,
generators unable to ramp up precisely to meet their schedules can
under-generate in the initial part of the hour and then over-generate
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 that
this practice imposes costs on balancing authorities and affects system
reliability, yet does not necessarily trigger the higher-tiered
imbalance charges. South Carolina E&G argues that adopting higher
penalties for substantial hourly imbalances does not address the issue
of intra-hour swings, which instead could be resolved by adopting 10-
minute imbalance charges.
Commission Determination
    298. The Commission denies rehearing of the decision in Order No.
890 not to impose generic penalties for intentional deviations. We
continue to believe that it is appropriate to maintain the status quo
of aggregating net generation over the hour in the pro forma OATT. To
the extent a transmission provider wishes to adopt additional penalties
for intentional deviations, it may do so provided it can show they are
necessary under the circumstances. As the Commission explained in Order
No. 890, requests to adopt a shorter interval over which to calculate
imbalances also will be considered on a case-by-case basis, provided
that such proposals are consistent with relevant market
structures.\106\
---------------------------------------------------------------------------

    \106\ See Order No. 890 at P 722.
---------------------------------------------------------------------------

d. Definition of Incremental Cost
    299. In Order No. 890, the Commission defined incremental cost, for
purposes of the tiered imbalance provisions, 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, purchased and interchange power costs
and taxes, as applicable. The Commission also concluded that it was
appropriate, through the definition of incremental cost, to allow for
recovery of both commitment and redispatch costs, but excluded on a
generic basis the cost of additional regulation reserves. The
Commission emphasized that allowable costs should only be those
additional costs incurred by the transmission provider due to the
imbalance and, if applicable, start-up costs should be allocated pro
rata to the offending transmission customers based on cost causation
principles.
    300. If the transmission provider elects to have separate demand
charges to recover the cost of holding additional regulation reserves
for meeting imbalances, the Commission stated that the transmission
provider should file a rate schedule and demonstrate that these charges
do not allow for double recovery of such costs. With regard to the
real-time regulation burden imposed by merchant generation, the
Commission stated that transmission providers could propose, on a case-
by-case basis, separate regulation charges for generation resources
selling out of the control area. The Commission concluded that the
other demand costs of providing imbalance service are already provided
under Schedule 3, 5, and 6 charges.
Requests for Rehearing and Clarification
    301. While generally supporting the Commission's definition of
incremental costs, Williams requests that the Commission further
identify how each component of the transmission provider's incremental
cost is to be determined. In Williams's view, a specific calculation
methodology should be imposed, otherwise the definition of the
incremental cost will afford transmission providers undue discretion in
the calculation of imbalance charges. To remove this discretion,
Williams suggests that the Commission require transmission providers to
use the same components and the same methodology for the calculation of
incremental costs for imbalance charges as the transmission provider
(or its affiliate) uses to calculate the incremental cost of each
resource for dispatching generation resources. At a minimum, Williams
asks that the Commission require transmission providers to post on
their OASIS the method used to calculate incremental costs for purposes
of imbalance charges, along with the method to obtain each component or
variable in the calculation.
    302. Several petitioners argue that the Commission's definition of
incremental cost for purposes of calculating imbalance charges does not
properly account for the costs actually incurred to provide imbalance
energy.\107\ Ameren and Southern assert that failure to provide for
recovery of opportunity

costs will prevent utilities required to serve an imbalance from being
made whole for forgone opportunities to sell excess energy to third
parties. Ameren contends that the Commission has determined that not
allowing the recovery of opportunity costs is inappropriate when the
applicable rate is lower than the market clearing price.\108\ Ameren
argues that excluding opportunity costs unnecessarily harms the
transmission provider's native load customers since the revenues that
the utilities would have realized from selling their excess energy
would have been credited back to those customers. Southern and E.ON
U.S. ask that the Commission expressly provide that incremental costs
include opportunity costs, as well as environmental costs, capacity
charges, dispatch losses and other costs that the transmission provider
must bear to provide the transmission customer with imbalance service.
---------------------------------------------------------------------------

    \107\ E.g., Ameren, EEI, E.ON U.S., and Southern.
    \108\ Citing Xcel Energy Services, Inc., 117 FERC ] 61,127
(2006).
---------------------------------------------------------------------------

    303. Some petitioners argue that it is inappropriate to base the
calculation of incremental cost on the last 10 MW dispatched to supply
the transmission provider's native load.\109\ EEI argues that the
definition of incremental and decremental cost should be determined
based on the cost to provide the last 10 MW of energy to serve the
transmission provider's native load and all other contractual or
franchise obligations, including the imbalance service itself. Progress
Energy and EEI contend that the transmission provider almost always
incurs incremental costs per kWh that are higher than the incremental
costs of serving its native load because native load typically has
first call on least-cost resources. As a result, EEI argues that the
Commission's definition of incremental cost transfers to imbalance
customers the value of the difference between the incremental cost per
kWh to serve native load and the incremental cost per kWh to serve
other contractual commitments, to the detriment of either the
transmission provider or its native load customers.
---------------------------------------------------------------------------

    \109\ See, e.g., Ameren, EEI, MidAmerican, Progress Energy, and
Southern.
---------------------------------------------------------------------------

    304. MidAmerican argues that the Commission's definition of
incremental cost could create an incentive to deliberately under-
generate in order to receive the benefit of the transmission provider's
least-cost dispatching. To provide appropriate incentives, Progress
Energy asks that the Commission revise the definition to include the
cost of providing the last 10 MW of energy to serve the transmission
provider's native load plus third party sales, while MidAmerican argues
that imbalance charges should be based on the incremental cost of the
most expensive 10 MW of generation resources in service at the time the
imbalance occurs. Southern contends that incremental cost should be
defined based on the next (not the last) 10 MW dispatched. Southern
asserts that this distinction is especially important in those
instances where the cost of the next 10 MW will be significantly
different than the last 10 MW, such as at the break point requiring
deployment of a combustion turbine generator. Southern therefore asks
that the Commission grant rehearing to establish separate definitions
for incremental and decremental cost and revise the definition of
incremental cost so that it is based on the next 10 MW dispatched.
    305. EEI and Progress Energy also seek clarification of the
definition of, and cost recovery for, decremental costs in particular.
EEI contends that the definition adopted in Order No. 890 could result
in the transmission provider crediting the customer an amount that
exceeds the costs that the transmission provider actually avoided by
accepting excess energy. EEI states, for example, that a transmission
provider might decrease the output of a dispatchable unit in response
to an imbalance even though it might also have a higher-cost power
purchase contract with a fixed amount of energy to be delivered in that
hour. EEI argues that the Commission's definition of decremental cost
would require the transmission provider to pay the imbalance customer
based on the higher-cost purchased power resource even though it has
not avoided those costs as a result of accepting the customer's excess
energy. In EEI's view, decremental cost should be defined to include
costs that are avoided as a result of receiving imbalance energy.
    306. Progress Energy asks that the definition of decremental cost
be clarified to allow the recovery of start-up costs that are incurred
in an hour different from the hour of excess imbalance. Progress Energy
contends that requiring a transmission provider to accept excessive
imbalance energy could force it to cycle a unit off-line in order to
accommodate the energy. Progress Energy argues that the later start-up
cost for the shut-down unit should be passed along to the imbalance
customer, rather than shifted to the native load.
    307. Other entities assert the Commission's definition of
incremental cost is inappropriate in light of their particular market
structure. When a joint dispatch agreement exists between the
transmission provider and other balancing authorities, MidAmerican
argues that the joint dispatch incremental or decremental cost should
be used in place of native load since there is no identification of the
transmission provider's native load other than as part of an
aggregated, jointly dispatched load. MidAmerican also argues that
transmission providers may have little or no native load from which to
price imbalance costs in retail choice states. NorthWestern agrees that
the definition of incremental cost fails to consider the circumstances
of transmission providers that have little or no generation on their
system. NorthWestern argues that the Commission should have expressly
provided additional flexibility for such transmission providers through
the definition of incremental cost instead of requiring them to file
under FPA section 205 for acceptance of previously-approved imbalance
pricing based on purchased power costs.
    308. Entergy challenges as too narrow the Commission's decision to
consider on a case-by-case basis proposals to charge separate
regulation charges for generation resources selling out of the control
area. Entergy states that the generator imbalance provisions of its
OATT contain both a generator imbalance charge and a generator
regulation charge, each of which are calculated based on the internal
and external schedules submitted by independent generators. Entergy
argues that this is appropriate because, regardless of whether the load
is within the control area or outside the control area, the generator
has a schedule with the control area that is met by control area
resources. Entergy contends that applying a generation regulation
charge only to external transactions would be arbitrary. Entergy
requests clarification that the generator regulation service charges
contained in its pro forma Generator Imbalance Agreement, which Entergy
states was negotiated with generators on its system, continues to be
acceptable.
Commission Determination
    309. The Commission grants rehearing of the decision to calculate
incremental costs for purposes of assessing imbalance charges based on
the last 10 MW dispatched to supply the transmission provider's native
load. Upon consideration of petitioners' arguments, we agree that it is
more reasonable to base imbalance charges on the actual cost to correct
the imbalance, which may be different than the cost of serving native
load. As such, we will

modify the definition to require transmission providers to use the cost
of the last 10 MWs dispatched for any purpose, i.e., to serve native
load, correct imbalances, or to make off-system sales. We believe this
satisfies Southern's concerns and therefore decline to adopt its
suggestion to separately define incremental and decremental cost for
purposes of calculating imbalance charges by using the ``next 10 MW of
generation dispatched'' in the incremental cost definition.
    310. We also agree with Williams that, in order to provide
transparency and minimize opportunities for undue discrimination, each
transmission provider must provide language in its OATT clearly
specifying the method by which it calculates incremental costs for
purposes of imbalance charges, as well as the method it will use to
obtain each component of the calculation. We direct transmission
providers to include this proposed tariff language as part of the
compliance filing ordered in section II.C.
    311. Several entities complain that the Commission's definition of
incremental cost does not properly allow for recovery of opportunity
costs. The determination and calculation of opportunity costs
associated with providing imbalance service will vary based on the
circumstances of the transmission provider and, as such, we do not
believe that it is appropriate to amend the definition of incremental
cost in the pro forma OATT to address opportunity costs. We will
therefore continue to consider proposals to include recovery of
legitimate and verifiable opportunity costs on a case-by-case basis
consistent with Commission precedent.\110\ Such proposals must clearly
explain how opportunity costs would be determined and demonstrate that
the recovery of opportunity costs would not lead to over-recovery of
costs. Similarly, transmission providers participating in joint
dispatch agreements or otherwise procuring imbalance energy from other
generators may need to have alternative definitions of incremental
cost. Proposals to adopt a modified definition of incremental cost to
reflect the transmission provider's particular circumstances also will
be considered on a case-by-case basis.
---------------------------------------------------------------------------

    \110\ See Order No. 888 at 31,740.
---------------------------------------------------------------------------

    312. With regard to the definition of incremental cost in
particular, we clarify that transmission providers can include in the
calculation of incremental cost start-up costs that are incurred in an
hour different from the hour of excess imbalance, provided that the
costs are in fact associated with providing imbalance service. We
disagree with EEI with respect to its description of incremental costs.
The fixed amount power purchase contract in EEI's example should not be
used in calculating incremental costs because it would not be included
in the last 10 MW of generation dispatched by the transmission
provider. In the case that a transmission provider is ramping down
generation in an hour, the additional costs of the last 10 MW
dispatched by the transmission provider should be used in calculating
incremental costs for the purpose of financially settling imbalances.
    313. In response to Entergy, we clarify that transmission providers
may propose to assess regulation charges to generators selling in the
control area, as well as generators selling outside the control area,
and that the Commission will consider such proposals on a case-by-case
basis, as we have in the case of Entergy's pro forma Generator
Imbalance Agreement. In accordance with the procedures established in
Order No. 890, Entergy sought continued approval of its generator
imbalance provisions, including the assessment of generator regulation
charges. The Commission accepted this variation as consistent with or
superior to the pro forma OATT, based on the particular circumstances
presented by Entergy.\111\ We will continue to consider requests to
assess regulation charges on generators on a case-by-case basis upon
consideration of the facts and circumstances presented.
---------------------------------------------------------------------------

    \111\ See Entergy Services, Inc., 120 FERC ] 61,042 at P 66
(2007).
---------------------------------------------------------------------------

e. Inadvertent Energy Treatment
    314. The Commission found in Order No. 890 that inadvertent energy
is not comparable to energy and generator imbalances and, therefore,
allowed inadvertent energy to be treated differently from imbalances.
The Commission explained that 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 generator imbalances. The Commission
concluded that the historic practice of paying back inadvertent
interchange in kind has not proven to have adverse effects on
reliability.
Requests for Rehearing and Clarification
    315. TDU Systems contend that the Commission's acceptance of in-
kind compensation for interchange energy undermines its rejection of
requests to allow transmission customers to address monthly imbalances
with in-kind transfers. TDU Systems argue that there is no evidentiary
basis for the Commission to conclude that transmission providers have
little control over the causes of system imbalances. TDU Systems state
that transmission providers typically control 80-90 percent of the load
on their systems and the dispatch of resources to serve that load. In
TDU Systems' view, both transmission provider and transmission customer
imbalances result from circumstances beyond their control, namely:
telemetry failure, meter error, generator governor response to system
problems, human error, uncontrollable load forecast errors due to
rapidly changing weather, and under-or over-supply of generation.
    316. TDU Systems state that deviations between load and supply,
whether in the form of energy imbalances or inadvertent energy, each
require adjustment or compensation and that there is no reason why that
adjustment or compensation should be different among transmission
users. TDU Systems argue that failure to allow for in-kind payment for
imbalances within the month provides a competitive advantage to
transmission providers and constitutes undue discrimination in
violation of the FPA. In their view, the Commission remedied this
discrimination within RTOs by requiring in Order No. 2000 that the same
imbalance rules apply to transmission users and control area
operators.\112\ TDU Systems argues that the Commission fails to explain
its departure from its resolution of this issue in the RTO context and
that it is irrelevant that transmission providers may have historically
paid back inadvertent interchanges with in-kind transfers without
problem.
---------------------------------------------------------------------------

    \112\ Citing Regional Transmission Organizations, Order No.
2000, 65 FR 809 (Jan. 6, 2000), FERC Stats. & Regs. ] 31,089 at
31,142 (1999), order on reh'g, Order No. 2000-A, 65 FR 12088 (Mar.
8, 2000), FERC Stats. & Regs. ] 31,092 (2000), aff'd sub nom. Public
Utility District No. 1 of Snohomish County, Washington v. FERC, 272
F.3d 607 (D.C. Cir. 2001).
---------------------------------------------------------------------------

Commission Determination
    317. The Commission denies rehearing of the decision in Order No.
890 to allow inadvertent energy to be treated differently from energy
and generator imbalances. As the Commission explained in Order No. 890,
inadvertent energy is not comparable to energy and generation
imbalances and the variables affecting each are distinct. It is
therefore

appropriate to treat inadvertent energy and imbalances differently
notwithstanding the fact that both inadvertent exchanges and imbalances
may be beyond the control of the transmission provider or customer,
respectively.
    318. Our primary concern with respect to inadvertent energy
continues to be avoidance of incentives that could degrade reliability.
To date, the return-in-kind approach to inadvertent energy has proven
adequate as a general matter. Petitioners do not present any evidence
that in-kind payment of inadvertent energy is no longer sufficient to
maintain reliability or allows certain entities to lean on the grid to
the detriment of other entities. We disagree that this treatment of
inadvertent energy is inconsistent with Order No. 2000. There the
Commission required both control area operators and transmission
customers within an RTO to clear imbalances through a real-time
balancing market.\113\ In the absence of a real-time balancing market,
we continue to believe it is appropriate for transmission providers
operating under the pro forma OATT to treat inadvertent interchange
differently than customer imbalances.
---------------------------------------------------------------------------

    \113\ See Order No. 2000 at 31,142.
---------------------------------------------------------------------------

f. Netting of Energy and Generator Imbalances
    319. In Order No. 890, the Commission concluded that it is not
appropriate to require transmission providers to allow netting of
generator and energy imbalances outside of the tier one band. While the
Commission recognized that allowing transmission customers to net
energy and generator imbalances would have competitive benefits and
enhance comparability, the Commission determined that it could lessen
the incentive for accurate scheduling and, in turn, increase imbalances
that create reliability or economic issues for specific areas of the
system.
Requests for Rehearing and Clarification
    320. Several petitioners ask that the Commission clarify that
netting and settling within the first deviation band should be done on
a financial basis, based on hourly incremental and decremental costs,
rather than netting imbalances on the basis of megawatt-hours of
imbalance and settling the net imbalance on a financial basis.\114\
EEI, MidAmerican and Progress Energy assert that otherwise customers
would be able to offset energy shortfalls in on-peak, high-cost periods
against excess energy in off-peak, lower-cost hours, which would
inappropriately shift costs to native load customers. If imbalances are
netted based on megawatt-hours prior to financial settlement, EEI and
Progress Energy argue that it would be impossible to calculate charges
for net imbalances at the end of the month because the transmission
provider would not be able to correlate monthly net imbalances with
hourly incremental and decremental costs without exercising subjective
judgment. Southern and EEI contend that the Commission, at a minimum,
should require the imbalances to be netted separately for on-peak
periods and off-peak periods if it determines that imbalances should be
netted on a megawatt-hour basis. EEI suggests that the price for net
first tier imbalances then be based on each month's average incremental
and decremental costs, calculated separately for on-peak periods and
off-peak periods.
---------------------------------------------------------------------------

    \114\ E.g., EEI, MidAmerican, Southern, Progress Energy, and
Entergy.
---------------------------------------------------------------------------

    321. Other petitioners assert that the Commission should allow
netting outside of the first tier band.\115\ Ameren argues that the
threshold of the first tier band is unnecessarily low, suggesting it
would be more appropriate to allow imbalances of less than 10 MW to be
netted. For imbalances from 10 MW up to as much as 50 MW, Ameren
suggests that the Commission allow netting of imbalances equal to the
greater of 10 MW or 50 percent of its scheduled amount. TDU Systems
argue that transmission customers should be allowed to net all
imbalances across the transmission system within a month, reflecting
appropriate differences for imbalances incurred during peak and off-
peak hours. TDU Systems contend that netting should be unrestricted
within the month so long as the results keep the transmission provider
economically whole. TDU Systems argue that there is no evidence that
netting creates reliability problems and that limiting netting is not
comparable to the transmission provider's treatment of imbalances of
its retail native load, generation affiliates, and marketing
affiliates. TDU Systems also argue that restricting netting within the
month is an unexplained departure from the Commission's treatment of
natural gas pipeline imbalances.
---------------------------------------------------------------------------

    \115\ E.g., TAPS, Ameren, and TDU Systems.
---------------------------------------------------------------------------

    322. NRECA asks the Commission to confirm, either on clarification
or rehearing, that separate imbalance charges may not be assessed on
each of a customer's separate transactions on an interface or within a
control area in a single hour. NRECA contends that a customer's
contribution to area control error (ACE) on a given interface is no
more than the aggregate difference between schedules and deliveries
and, therefore, its impact on the balance of resources and loads within
a control area is no more than the aggregate difference between its
resources' output and its load. If a transmission provider's system is
so underdeveloped that constraints prevent transactions sourcing at
different locations within the control area from being treated
comparably, the Commission should require the transmission provider to
upgrade its system rather than penalize the customer with multiple sets
of imbalance charges on separate transactions.
Commission Determination
    323. The Commission affirms the decision in Order No. 890 to allow
netting of imbalances within the first tier deviation band. As the
Commission explained in Order No. 890, there is a tradeoff between
allowing customers to net imbalances, which would enhance comparability
between the transmission provider's dispatch and the customers serving
load, and the need to create incentives to limit customer imbalances
due to the reliability or economic issues they can cause for specific
areas of the system.\116\ Netting can cause problems because it lessens
the incentive for transmission customers to schedule accurately and
inaccurate schedules, in turn, can require actions by the transmission
provider even when imbalances offset. We believe the Commission struck
the appropriate balance in Order No. 890 between the customer's need
for flexibility and the transmission provider's need for accuracy and,
therefore, deny TDU Systems' request to require netting of imbalances
outside the tier one band and Ameren's related request to expand the
tier one band for purposes of netting.
---------------------------------------------------------------------------

    \116\ See Order No. 890 at P 715.
---------------------------------------------------------------------------

    324. We also deny NRECA's request that separate imbalance charges
not be assessed on each of a customer's separate transactions on an
interface or within a control area in a single hour. Where transmission
constraints exist, a customer whose load and generation was on net
equal could still have an effect on the transmission system if some
generation is ramping up to respond to some imbalances while other
generation is ramping down exactly at the same time. We disagree with
TDU Systems that our decision is an unexplained departure from the
Commission's treatment of natural gas

pipeline imbalances. Natural gas pipelines frequently have
opportunities to use storage and line pack to absorb day-to-day
imbalances. Individual pipelines have tailored their imbalance
requirements, including penalty provisions as needed, to meet their
specific circumstances. The transmission of electricity, in contrast to
the transportation of natural gas, requires instantaneous balancing
which makes the need for imbalance provisions on a shorter-term basis
important for the protection of reliability. NERC has created standards
such that each control area is responsible for managing its Area
Control Error and operating within line limits in order to protect
reliability. Imbalances created by transmission customers impose an
additional burden on the transmission provider to manage imbalances
within the hour (as well as shorter time periods) justifying a
different tariff approach under the pro forma OATT. As such, the
imbalances provisions adopted in the pro forma OATT are used to protect
reliability during the applicable time period.
    325. With regard to netting within the tier one band, we clarify
that netting should be done on a megawatt-hour basis, rolling over the
month. Imbalances remaining at the end of the month should be settled
at the load weighted average of the hourly incremental costs during
that month.\117\ We decline to require that imbalances be netted
separately for on-peak and off-peak periods. Netting only applies to
imbalances within the tier one band, which are relatively minor and
largely within the normal range of uncertainty that cannot be avoided
even under optimal operating conditions. We therefore disagree that it
is necessary to adopt a more granular imbalance pricing mechanism when
netting imbalances within the first tier. However, if a transmission
provider finds that its customers are arbitraging on-peak and off-peak
prices within the first tier, it may propose a more granular approach
to netting subject to a showing that it is necessary under the
circumstances.
---------------------------------------------------------------------------

    \117\ For example, if a generator had 5 imbalances within the
first deviation band in a month of +2 MWh, -6 MWh, +4 MWh, -2 MWh, -
1 MWh, the net MWh imbalance for the generator at the end of the
month would be -3 MWh. The generator would pay the transmission
provider for 3 MWh at the load weighted average of the hourly
incremental costs during that month.
---------------------------------------------------------------------------

g. Distribution of Penalty Revenues Above Incremental Cost
    326. With regard to revenues received through imbalance charges,
the Commission required transmission providers 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. The Commission
concluded that such distribution of revenues recognizes that
transmission providers bear the responsibility to correct imbalances
and often use their own facilities to do so.
Requests for Rehearing and Clarification
    327. Ameren contends that the transmission provider should be
allowed to keep all the penalty revenues associated with correcting
imbalances and that development of a credit mechanism imposes an
unnecessary and unwarranted administrative burden on transmission
providers. Ameren argues that the transmission provider should receive
any amounts above its incremental costs of providing imbalance service
as a contribution towards the fixed costs of providing this service and
that any revenues from penalties assessed on customers for leaning on
the system should be credited to long-term firm transmission customers.
    328. TDU Systems, however, object to the Commission's decision to
allow transmission providers to retain a portion of the imbalance
penalty revenues for their own retail customers. TDU Systems contend
that transmission providers do not pay imbalance penalties when they
over- or under-schedule their loads and, thus, receipt of related
penalty revenues by transmission providers would constitute a windfall.
TDU Systems argue that the Commission failed to explain its departure
from Carolina Power & Light \118\ because the Commission's decision in
that case to deny credits to CP&L on behalf of its retail customers was
based on those customers not being subject to energy imbalance
penalties in the first place. TDU Systems contend that this fundamental
paradigm has not changed with reform of the OATT.
---------------------------------------------------------------------------

    \118\ 103 FERC ] 61,209 (2003) (CP&L).
---------------------------------------------------------------------------

    329. MidAmerican requests clarification that it is appropriate to
propose its imbalance penalty distribution mechanism in the compliance
filing containing the non-rate terms and conditions of the pro forma
OATT. Joined by NorthWestern and Mark Lively, MidAmerican also requests
guidance as to the particular information the Commission would require
in those filings with regard to the penalty distribution mechanism.
NorthWestern asks the Commission to specify how the transmission
provider should determine what customers are non-offending and over
what period of time. Mark Lively seeks clarification of the time frame
during which there is to be a matching of penalty revenue and credits
to non-offending customers. If the matching is done on a monthly basis,
Mark Lively contends that most if not all transmission customers will
be found to be offending at some time during the month and thus not be
eligible to be in the class of customers to receive a credit for part
of the penalty revenue collected by the transmission provider. Mark
Lively suggests an alternative crediting mechanism to synchronize
penalties and credits by having the variance from full incremental cost
be uniform for any hour or any intra-hour period, with revenues from
over-deliveries shared with non-offending load and revenues from under-
deliveries shared with non-offending supply.
    330. NorthWestern also asks the Commission to expressly confirm
that the transmission provider is not required to distribute penalty
revenues until after it recovers all costs (including any associated
transmission costs) incurred in providing imbalance service.
NorthWestern contends that the market for such services is limited and,
as a result, it has had to contract with entities located outside its
control area for system balancing and load following services in order
to provide imbalance service.
Commission Determination
    331. The Commission affirms the decision in Order No. 890 to
require transmission providers to credit revenues from imbalance
charges in excess of incremental costs to all non-offending customers,
including affiliates, and the transmission provider on behalf of its
retail customers. As the Commission explained in Order No. 890,
transmission providers with significant imbalance penalties have been
required in the past to develop a mechanism to credit penalty revenues
to non-offending transmission customers.\119\ We disagree with Ameren
that this imposes an unreasonable administrative burden on transmission
providers. We note that Ameren did not seek rehearing of the decision
to require transmission providers to develop a similar mechanism to
distribute unreserved use penalties to non-offending customers,
discussed in section III.C.4.b.\120\ We would not

expect development of that distribution mechanism to be any more
burdensome than distributions of imbalance penalty revenues.
---------------------------------------------------------------------------

    \119\ See Order No. 890 at P 727 (citing CP&L, 103 FERC ] 61,209
at P 25; Entergy Services, Inc., 105 FERC ] 61,319 (2003), reh'g
denied, 109 FERC ] 61,095 (2004)).
    \120\ See id. at P 860-61.
---------------------------------------------------------------------------

    332. We also disagree with TDU Systems that the transmission
provider on behalf of its native load customers should be excluded from
the distribution of imbalance revenues. Transmission providers bear the
responsibility to correct imbalances, often using their own facilities
to do so, and thus their receipt of imbalance revenues does not
constitute a windfall. While it is true that the Commission in CP&L
considered relevant the fact that CP&L's customers were not subject to
imbalance charges, the Commission expressly rejected CP&L's proposal to
retain revenues because it would have been ``contrary to the
Commission's objective to eliminate incentives for transmission
providers to use penalties as a profit center.'' \121\ The imbalance
charges adopted in Order No. 890 more closely relate 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.
---------------------------------------------------------------------------

    \121\ CP&L, 103 FERC ] 61,209 at P 26.
---------------------------------------------------------------------------

    333. Regarding the time frame during which there is to be a
matching of penalty revenue and credits to non-offending customers, we
clarify that the transmission provider should distribute the penalty
revenue received in a given hour to those non-offending customers in
that hour, i.e., those customers to whom the penalty component did not
apply in the hour. Customers that were out of balance, but within the
first tier, should therefore be included in the distribution. Since
most transmission customers will be out of the first deviation band at
some hour during the month, we agree that it would not be appropriate
to exclude these customers from receiving a pro rata portion of penalty
revenues in the other hours. In response to NorthWestern, we clarify
that the transmission provider, as part of its distribution
methodology, may address how distributions may be affected by the
transmission provider's inability to recover the costs incurred to
provide imbalance service.
2. Credits for Network Customers
a. Severance of Credits and Planning
    334. In Order No. 890, the Commission adopted 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 Commission concluded
that linking credits for new facilities to a joint planning requirement
can act as a disincentive to coordinated planning, which is contrary to
the Commission's original objective in adopting the provision. The
Commission also concluded that the coordinated planning initiatives
adopted in Order No. 890 will ensure that most, if not all,
transmission facilities are planned on a coordinated basis,
notwithstanding the severance of the link between credits for new
facilities and joint planning.
Requests for Rehearing and Clarification
    335. E.ON U.S. argues on rehearing that the Commission failed to
adequately address comments suggesting that severing the link will
excuse network customers from participating in the joint planning
process and permit a network customer to build facilities without
oversight or input from a transmission provider. While Order No. 890
places an affirmative burden on the transmission provider to coordinate
long-term transmission planning, E.ON U.S. states that no corresponding
obligation is placed on the transmission customer. E.ON U.S. argues
that transmission service credits for facilities constructed by network
customers should be available only when the facility is jointly planned
with the transmission provider.
    336. NorthWestern agrees, arguing that if a network customer is
permitted to construct facilities and later declare them to be worthy
of a credit, such facilities will not serve the overall grid as
efficiently as jointly planned facilities. NorthWestern also argues
that severing the link will lead to protracted litigation regarding
what facilities qualify for credits. To ensure efficient coordination
of facility planning, NorthWestern requests that the Commission
reconsider its decision to sever joint planning and transmission
service credits.
Commission Determination
    337. E.ON U.S. and NorthWestern both argue that, by severing the
link between joint planning and credits for network customers, the
Commission is sacrificing the benefits that resulted when a
transmission provider made credits available as part of its centralized
planning process. We disagree. As the Commission explained in Order No.
890, the linkage between credits and joint planning gave the
transmission provider an incentive to deny coordinated planning to
avoid granting credits for customer-owned facilities.\122\ Therefore,
it was necessary to sever the link between credits and joint planning.
Any efficiencies that may be lost by severing that link should be
offset by the increased efficiencies resulting from the coordinated
planning initiative required in Order No. 890, which the Commission
noted will ensure that most, if not all, transmission facilities are
planned on a coordinated basis.\123\ With the clarifications provided
below, we do not expect that severing the link between joint planning
and credits will lead to unnecessary litigation.
---------------------------------------------------------------------------

    \122\ See Order No. 890 at P 735.
    \123\ See id. at P 736.
---------------------------------------------------------------------------

b. The New Test To Determine Eligibility for Credits
    338. In Order No. 890, the Commission declined to adopt the credits
test for new facilities proposed in the NOPR and, instead, revised the
test to more accurately reflect the Commission's intent as expressed in
the NOPR. A transmission customer is required to meet the integration
standard under pro forma OATT section 30.9 to receive a credit for its
facilities. Under the integration standard, 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.\124\ Because joint planning will no longer be required to
obtain credits, the Commission noted 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. To
ensure comparability, the Commission adopted the presumption of
integration for transmission customer facilities that, 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.
---------------------------------------------------------------------------

    \124\ See id. at P 754, n.436 (citing Southwest Power Pool,
Inc., 108 FERC ] 61,078 (2004), reh'g denied, 114 FERC ] 61,028
(2006)).
---------------------------------------------------------------------------

Requests for Rehearing and Clarification
    339. NRECA, TAPS and the TDU Systems request that the Commission
confirm that the integration requirement under Order No. 890 does not
require a more stringent standard for network customer facilities than
for transmission provider facilities or in any way

compromise the language in section 30.9 of the pro forma OATT. NRECA
argues that the language in Paragraph 754 of Order No. 890 and, in
particular the affirmation of the ``benefits to the grid'' test in
footnote 436, contradict section 30.9 by establishing an explicitly
different and harder test for transmission customer facilities than for
transmission provider facilities. Other petitioners agree,\125\
requesting that the Commission explain that it did not intend to impose
the ``additional benefits to the grid'' and ``relied on by the
transmission provider'' criteria (which they state are not required for
a transmission provider's facilities) on a network customer's
facilities.
---------------------------------------------------------------------------

    \125\ E.g., TAPS and TDU Systems.
---------------------------------------------------------------------------

    340. Several petitioners argue that an integration standard
requiring the showing of benefits to the grid is unduly discriminatory
because it maintains the presumption that a transmission provider's
transmission facilities provide benefits while requiring a network
customer to make an affirmative showing that its facilities provide
benefits to qualify for credits.\126\ FMPA and TDU Systems argue that
comparability requires the same presumption of integration to be
applied to all transmission facilities. To provide certainty for those
building new infrastructure, TDU Systems contend that the Commission
should require transmission providers to credit third parties for the
costs of new facilities in a manner comparable to the compensation
provided for a transmission provider's comparable facilities.
---------------------------------------------------------------------------

    \126\ E.g., APPA, FMPA, NRECA and TAPS.
---------------------------------------------------------------------------

    341. APPA contends that the presumption of integration is confusing
because it is unclear how a network customer would make a showing that
facilities would be eligible for inclusion in a transmission provider's
revenue requirement if owned by the transmission provider or what the
specific legal effect would be if the network customer succeeded in
making such showing. APPA suggests that the Commission require credits
if the customer can show that the transmission provider includes in its
own revenue requirement or gives credits to other customers for
facilities similar to those for which the networks customer seeks
credits.
    342. In implementing the presumption of integration to obtain
credits, TAPS and APPA maintain that the Commission cannot require a
network customer to show more than that its facilities are comparable
to similar facilities the transmission provider actually includes in
its rate base. TAPS argues that the Commission should clarify that the
presumption cannot be overcome by evidence that the transmission
provider and the transmission provider's other customers do not use or
directly benefit from the customer-owned facilities. TAPS therefore
requests that the Commission make clear that it will not follow
precedents developed in credit cases decided under the original OATT
section 30.9 regarding the types of ``benefits'' provided by a
customer's facilities. Specifically, TAPS argues that a network
customer of a transmission provider that includes the cost of
facilities (including radials) that are used solely to serve the
transmission provider's retail customers must be able to use the Order
No. 890's presumption to obtain credits for similar facilities that
serve only that transmission customer's retail customers.
    343. FMPA also oppose any implementation of the Commission's
integration test that treats customers and transmission providers
differently. FMPA argue that, if a customer's facilities are necessary
to serve the customer's load, the customer should be provided a credit
since the transmission provider includes in rate base the cost of its
facilities used to serve load. In their view, the same presumption of
integration applies to all transmission facilities, i.e., that
transmission is integrated when, if owned by the transmission provider,
it would be includable in rate base. FMPA cite legislative history and
the court's decision in TAPS v. FERC \127\ in support of their argument
that the comparability principle is central to the issue of cost
recognition for customer facilities. FMPA contend that recognizing
their members' transmission through credits is beneficial because it
involves all owners in joint planning and the exchange of information
that results in grid construction and operation that will better serve
the needs of all consumers. Without this role in joint planning, less
reliable transmission and fewer generation and power supply options for
systems will result. In addition, if credits are denied, FMPA will be
inhibited from contributing necessary capital to the grid and likely
result in reduced public support for transmission construction.
---------------------------------------------------------------------------

    \127\ 225 F.3d 667, 681 (D.C. Cir. 2000), aff'd sub nom., New
York v. FERC, 535 U.S. 1 (2002).
---------------------------------------------------------------------------

    344. Other petitioners contend that the Commission should eliminate
any presumption that a network customer is entitled to credits, arguing
that the presumption violates the cost-causation principle by shifting
costs to customers for whom the facilities were not planned and who are
not benefited by their use.\128\ These petitioners contend that a
network customer's facilities are not planned around the needs of the
transmission provider to meet its obligations and many customer
facilities are designed only to pick up power from the transmission
provider's grid and deliver it to that network customer's distribution
network.\129\ These petitioners request that the Commission allow for
credits only when the customer's facilities provide a benefit to the
transmission provider's grid, i.e., when the transmission provider
relies on a network customer's facility to serve the transmission
provider's transmission customers (including the network customer
seeking credits) or the transmission provider's retail customers. They
argue that there is no basis to presume integration simply because the
transmission provider would include the cost of such facilities were it
the owner.
---------------------------------------------------------------------------

    \128\ E.g., Entergy and Florida Power.
    \129\ E.g., Entergy, Florida Power and South Carolina E&G.
---------------------------------------------------------------------------

    345. South Carolina E&G argues a presumption of integration will
encourage customer overbuilding paid for by a transmission provider's
native load customers. South Carolina E&G asks that the Commission
confirm that it is not departing from the decade-old two-part test for
credits for customer-owned facilities that requires that the facilities
are both integrated into the network grid and provide benefits to the
grid. South Carolina E&G disagrees that any revision to that test is
required by comparability. In its view, customer-owned facilities are
not comparable to transmission provider-owned facilities for purposes
of credit eligibility, since each are built for different purposes and
are subject to different regulatory oversight.
    346. Florida Power argues that the application of the rebuttable
presumption may impact reliability. Florida Power contends that, under
the new test for credits, a transmission provider must show that it
does not need the network customer's facilities to provide transmission
service to any other customer in order to deny credits. Florida Power
states that this could result in a network customer being denied
credits for a facility even if the transmission provider needs the
facility to reliably serve the network customer.
    347. Entergy and Florida Power also request that the Commission
change its policy of applying a stricter standard to a transmission
provider's own facilities

when a network customer has been denied credits. These petitioners
state that, when the Commission denies credits for customer-owned
facilities, it applies the same integration test to the transmission
provider's facilities as that applied to the network customer's
facilities. The petitioners argue that application of the integration
test to the transmission provider's facilities in that instance is
unreasonable since the nature of those facilities does not change. They
argue that different tests for transmission providers and network
customer systems are appropriate since each are planned for and used
differently. In their view, concerns about comparability can be
addressed by allowing a transmission provider's looped facility to be
rolled into rate base only if the transmission provider uses the
facility to serve a transmission customer or the transmission
customer's retail customers.
    348. Entergy and Florida Power further claim that the Commission's
approach is inconsistent with the treatment of generator
interconnections because the Commission's policy entitling an
interconnecting generator to credits against transmission charges does
not change simply because the Commission has denied a network customer
credits. These petitioners contend that an interconnecting generator
could be entitled to credits when at the same time the transmission
provider could be prohibited from rolling the costs of those credits
into its rates.
Commission Determination
    349. The Commission denies rehearing of the decision in Order No.
890 to modify the credits test for new customer-owned facilities. In
Order No. 890, the Commission explained that it was retaining the
existing integration standard, but adopting a new presumption of
integration for customer-owned facilities that would be included in
rate base if owned by the transmission provider.\130\ The integration
standard to be applied to new facilities under section 30.9 therefore
remains unchanged, so Commission precedent regarding application of the
standard will continue to apply. Specifically, to satisfy the
integration standard set forth in section 30.9 of the pro forma OATT,
it must be shown that a new facility is integrated with a transmission
provider's system, provides 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.\131\ However, in recognition of the new requirement for
transmission providers to plan their system on an open and coordinated
basis, a customer's transmission facilities will be presumed to be
integrated if the 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.
---------------------------------------------------------------------------

    \130\ Order No. 890 at P 753-754.
    \131\ 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).
---------------------------------------------------------------------------

    350. The adoption of this presumption is necessary to ensure
comparability between network customers and transmission providers
serving native load. It is reasonable to presume, without application
of any particular standard or test, that the transmission provider's
facilities benefit the network because they are planned, constructed
and owned, from the beginning, by the transmission provider to meet its
obligations to its customers. In comparison, because customer-owned
facilities are generally constructed to serve that individual
customer's needs, the Commission requires the customer to satisfy the
integration standard in order to qualify for credits. The Commission
concluded in Order No. 890 that it is now reasonable to presume that
any new customer-owned facilities satisfy the integration standard, to
the extent they would be included in the transmission provider's
revenue requirement if they were owned by the transmission provider, in
light of the requirement imposed on transmission providers to implement
an open and coordinated transmission planning process that applies to
all transmission facilities.
    351. To the extent necessary, we clarify that these presumptions of
integration are rebuttable both as applied to the transmission provider
and the network customer. For the network customers' facilities,
transmission providers may challenge the presumption that the
customer's facilities are integrated by showing they do not actually
meet the integration standard, notwithstanding the fact that they are
similar to facilities in the transmission provider's rate base.
Similarly, the presumption that a transmission provider's facilities
benefit the network could be overcome by a showing that the facilities,
in fact, do not provide such benefit. By allowing the presumptions of
integration to be rebutted, the Commission will ensure that only the
costs of facilities that are actually part of the integrated network
that serves all customers will receive credits. It also serves as an
incentive for the transmission provider to give credits to network
customers that own integrated facilities and remove from its rate base
its own non-integrated facilities.
    352. In light of the modifications to the credits test adopted in
Order No. 890, we further clarify that denial of credits for a network
customer no longer triggers a need for the transmission provider to
demonstrate that its own facilities satisfy the integration standard,
because credits for network customer facilities can now be denied only
after an affirmative showing by the transmission provider that its
facilities are not similar under the integration test to those of the
network customer (i.e., by overcoming the presumption of integration).
This approach departs from the approach adopted in FP&L,\132\ but
reflects the fact that the new rebuttable presumption in favor of the
transmission customer has shifted the burden to the transmission
provider to provide evidence that credits for the customer are not
warranted.
---------------------------------------------------------------------------

    \132\ Florida Mun. Power Agency v. Florida Power and Light Co.,
74 FERC ] 61,006 at 61,010 (1996) (finding that the integration of
facilities into the plans or operations of a transmitting utility is
the proper test for cost recognition), reh'g denied, 96 FERC ]
61,130 at 61,544-45 (2001), aff'd sub nom. Florida Mun. Power Agency
v. FERC, 315 F.3d 362 (D.C. Cir. 2003).
---------------------------------------------------------------------------

    353. To provide clarity regarding how to implement the presumption
that a network customer's facilities are integrated, we make clear that
a network customer may justify application of the presumption by
reference to the existing facilities in the transmission provider's
rates. A customer need only show that its new facilities are similar in
design and purpose to facilities owned by the transmission provider
that are included in rates. A transmission provider may overcome the
network customer's presumed integration by demonstrating, with
reference to its own facilities that meet the integration standard,
that the network customer's new facilities do not meet the standard. To
the extent there are disputes regarding whether a customer's new
facilities are sufficiently similar to those in the transmission
provider's rate base, we encourage transmission providers and customers
to resolve those disputes informally or with the assistance of the
Commission's Dispute Resolution Service.
    354. We reject requests to eliminate the presumption of integration
for new customer-owned facilities, as advocated by certain transmission
providers. The planning-related reforms adopted in

Order No. 890 will ensure that a process exists to jointly plan all
transmission facilities, including new facilities developed by
customers. Comparability requires that transmission providers and
customers alike benefit from a presumption of integration. It is also
appropriate for both the transmission provider and its customers to be
subject to the integration standard to the extent the presumption of
integration is overcome, notwithstanding any coordinated planning of
those facilities. Under Order No. 890, the Commission therefore will
not apply, as some petitioners imply, a different or stricter standard
to a transmission provider's own facilities when a network customer has
been denied credits.
    355. We disagree with claims that a presumption of credits for
certain customer-owned facilities will encourage over-building or harm
reliability. Facilities owned by transmission providers have long
enjoyed a presumption of integration, yet petitioners do not object to
the presumption as applied to those facilities. Petitioners offer no
reason to believe that application of a comparable presumption for new
customer-owner facilities would lead to reliability or operational
difficulties, particularly in light of the obligation for transmission
providers under Order No. 890 to plan their transmission systems on an
open and coordinated basis.\133\ We also believe that it is unlikely
that a transmission provider would be required to provide credits to an
interconnecting generator, but be prohibited from rolling the same
credits into its rates. Nevertheless, should any such circumstance
arise, the transmission provider should bring the issue to the
Commission's attention for resolution.
---------------------------------------------------------------------------

    \133\ As we discuss in section III.B, planning activities must
be open to all customers, who must provide information regarding
expected uses of the system so that the transmission provider can
plan for their needs.
---------------------------------------------------------------------------

c. Application of the New Test to Existing Facilities
    356. In Order No. 890, the Commission concluded that the new test
for determining credits will apply only to transmission facilities
added subsequent to the effective date of Order No. 890. The Commission
found that there is no reason to revisit the determinations with
respect to the number of customer-owned transmission facilities that
have been developed, and resulted in credits negotiated and litigated,
under the prior test that the Commission determined to be just and
reasonable at the time.\134\ On a prospective basis, however, given the
increased planning and coordination required in Order No. 890, the
Commission stated that it is appropriate to apply the new test for
determining credits.
---------------------------------------------------------------------------

    \134\ See East Texas Electric Coop., Inc. v. Central and South
West Services, Inc., 114 FERC ] 61,027 (2006).
---------------------------------------------------------------------------

Requests for Rehearing and Clarification
    357. Several petitioners contend that it is inappropriate for the
Commission to conclude that the newly announced test for determining
credits under OATT section 30.9 will apply only to transmission
facilities added subsequent to the effective date of Order No. 890,
arguing that the Commission should remedy past undue discrimination
against network service customers such as the failure of transmission
providers to jointly plan facilities with transmission customers.\135\
APPA also asks that the Commission explain why this result is legally
appropriate.
---------------------------------------------------------------------------

    \135\ E.g., APPA, East Texas Cooperatives, FMPA, NRECA, TAPS and
TDU Systems.
---------------------------------------------------------------------------

    358. NRECA contends that the Commission should apply the new test
for transmission credits to both existing and new facilities, but
clarify that existing credit agreements or determinations will not be
impacted. NRECA argues that Mobile-Sierra concerns can be avoided by
applying the new test to facilities that are built but not yet the
subject of a credits agreement or determination. APPA suggests that
allowing network customers to obtain credits going forward for existing
facilities that are comparable to those the transmission provider
includes in its revenue requirement would be a reasonable remedy for
past discrimination. Noting the Commission's requirement for
transmission providers to remove all generator step-up facility costs
from their transmission rates (not only those costs incurred after the
Commission changed its policy in Order No. 888), TAPS maintains that
the ``correct and fair approach'' is to prospectively remedy such
discrimination by applying the new standard to both existing and new
facilities.\136\ To do otherwise would, in TAPS' view, undermine
comparability.
---------------------------------------------------------------------------

    \136\ TAPS also cites Tennessee Gas Pipeline Co., 104 FERC ]
61,063 (2003), order on reh'g, 108 FERC ] 61,177 (2004), order on
reh'g, 110 FERC ] 61,385 (2005) for the proposition that new
policies can be implemented for existing contracts.
---------------------------------------------------------------------------

    359. TDU Systems argue that the Commission cannot endorse rates
that it knows are unjust and unreasonable and, therefore, agree that
transmission customers should be credited for transmission facilities
regardless of their vintage to the extent the facilities have not been
subject to a prior determination. TDU Systems contend that Order No.
890 failed to adequately justify allowing rates to remain in place that
reflect undue discrimination. FMPA argue that comparability similarly
requires that the Commission apply the presumption of integration to
existing as well as new customer-owned facilities, since both existing
and new transmission provider-owned facilities are presumed to provide
benefits to the grid.
    360. Entergy and Florida Power ask that, to the extent the
Commission applies the new test to transmission provider facilities,
the rule apply only to new facilities constructed by the transmission
provider, not to existing facilities.
Commission Determination
    361. The Commission denies rehearing of the decision to apply the
modified test for credits only to transmission facilities added
subsequent to the effective date of Order No. 890. In light of the new
planning and coordination required in Order No. 890, it is appropriate
to apply the new test on a prospective basis.\137\ Existing facilities,
by definition, have been developed without the benefit of the planning-
related reforms adopted in Order No. 890 and, therefore, are not
similarly situated to new facilities developed after the effectiveness
of Order No. 890. As a result, only a network customer's new facilities
will be subject to the presumption of integration standard. Similarly,
the existing presumption applied to the transmission provider's
facilities will continue to allow it to include in its rate base from
the outset all network facilities constructed to meet its obligations
to its customers, provided the presumption is not rebutted.
---------------------------------------------------------------------------

    \137\ Order No. 890 at P 758.
---------------------------------------------------------------------------

d. Cost of Customer Facilities Automatically Included in Transmission
Provider Cost of Service Without a Rate Filing
    362. Noting that automatic recovery of the costs of credits would
be contrary to the Commission's long-standing policy concerning single-
issue rate adjustments, the Commission declined to generically allow
automatic recovery of the costs of credits associated with integrated
transmission facilities to the transmission provider's cost of service.
The Commission explained that transmission providers continue to have

the option to propose an automatic adjustment clause in their rates
under FPA section 205 to address the time lag between incurring costs
associated with credits and the transmission provider's next rate case.
Requests for Rehearing and Clarification
    363. Florida Power requests that the Commission grant rehearing of
the decision that customer credits do not warrant an exception to the
Commission's general policy regarding single-issue rate adjustments.
Florida Power argues that a transmission provider should not be
required to dedicate the extensive resources required by a full-blown
rate case to recover costs that, in its view, it has been forced to
incur by the Commission's policy and over which it has no control.
    364. E.ON U.S. requests that the Commission clarify that payment of
credits is dependent on the transmission provider's ability to recover
the costs of the credits. E.ON U.S. asks that the Commission adopt one
of the following requirements: if the network customer's facilities are
to be eligible for credits, the network customer must petition the
Commission for a declaratory order stating that the transmission
provider will be able to recover costs for the credits in the
transmission provider's next rate case; the transmission provider need
not provide the network customer with credits for its facilities until
the costs of the credits are approved in the transmission provider's
next rate case; or if the cost of the credits are rejected in the
transmission provider's next rate case, the network customer is
required to refund any amounts collected through the transmission
credits, plus interest.
    365. APPA asks that the Commission clarify that, if a transmission
provider denies credits for network customer owned facilities, the
transmission provider has a corresponding obligation to take steps to
strip the costs of similar transmission facilities out of its own
transmission revenue requirement where comparability requires such a
result. TAPS argues that nothing in Order No. 890 altered the
transmission provider's existing obligation to remove from its rate
base transmission provider facilities comparable to those for which it
denies credits to network customers.
Commission Determination
    366. The Commission affirms its decision in Order No. 890 not to
generically allow automatic rate recovery of the costs of credits
associated with integrated transmission facilities to the transmission
provider's cost of service. As explained in Order No. 890, automatic
recovery would be contrary to our long-standing policy concerning
single-issue rate adjustments, and transmission providers continue to
have the option to propose an automatic adjustment clause in their
rates under FPA section 205 to address the time lag between incurring
costs associated with credits and the transmission provider's next rate
case.\138\ Since transmission providers may choose to add an automatic
adjustment clause to their rates to address any lag in cost recovery,
we reject as unnecessary the alternative proposals offered by E.ON U.S.
---------------------------------------------------------------------------

    \138\ See id. at P 766.
---------------------------------------------------------------------------

    367. As for APPA's argument regarding the transmission provider's
obligation to remove nonintegrated facilities from its revenue
requirement, as explained above, the denial of credits for a network
customer will no longer trigger an examination of the transmission
provider's own facilities. Rather, the presumption of integration shall
be rebuttable for transmission providers and customers alike. If it
becomes apparent that the transmission provider has included facilities
in its revenue requirement that are ineligible, such as when the
transmission provider relies on its own facilities to demonstrate the
lack of integration for customer-owned facilities, the network customer
or the Commission, as appropriate, may initiate a complaint proceeding
to have such facilities removed from rates.
e. RTO and ISO Issues
    368. The Commission concluded in Order No. 890 that it would not be
appropriate to generically exempt all RTOs and ISOs from the revised
requirements regarding credits for network transmission customers. The
Commission stated that it would address issues relating to network
transmission customer credits in the RTO and ISO context in orders
addressing OATT reform compliance filings submitted by each RTO and
ISO. The Commission noted its prior determination that the existing
tariffs of certain RTOs and ISOs provide opportunities for transmission
customers to receive credit or the equivalent (e.g., Transmission
Congestion Contracts, Firm Transmission Rights or Auction Revenue
Rights) for building facilities or upgrades that are consistent with or
superior to Order No. 888 requirements.\139\ The Commission explained
that each RTO and ISO would have the opportunity to show on compliance
that this continues to be the case given the reforms adopted in Order
No. 890.
---------------------------------------------------------------------------

    \139\ See id. at P 773, n.447.
---------------------------------------------------------------------------

    369. The Commission also addressed a request by NRECA to prohibit
RTOs and ISOs from using a non-public utility's transmission facilities
without compensating the entity because it is not a member of the RTO/
ISO. The Commission found that there is not enough evidence on the
record to make a generic determination on that issue. The Commission
instead concluded it would be appropriate to address such issues on a
case-by-case basis in response to appropriate filings under FPA
sections 205 and 206.
Requests for Rehearing and/or Clarification
    370. TAPS is concerned that Order No. 890 suggests that RTOs/ISOs
can justify an exemption from OATT section 30.9 by claiming that firm
transmission rights or similar mechanisms are the ``equivalent'' of
credits under section 30.9. TAPS states that the RTO/ISO tariff
provisions referred to by the Commission relate only to upgrades, which
are funded by a customer but owned by a transmission owner, for a new
service request or generator interconnection. TAPS therefore requests
clarification that the rules with respect to whether a network customer
funding facilities owned by a transmission owner should receive firm
transmission rights in lieu of credits are unrelated to, and should not
be confused with, the requirement in OATT section 30.9 that a network
customer must be compensated for customer-owned facilities in a manner
comparable to transmission owners.
    371. NRECA reiterates its argument that the Commission should
require RTOs/ISOs to compensate non-jurisdictional entities for use of
the non-jurisdictional entities' transmission facilities as required by
the principle of comparability. NRECA argues that the issue is purely
legal and that no additional evidence is necessary, since NRECA is not
seeking a ruling that a particular entity is entitled to compensation.
NRECA states that the Commission's reliance on a ``case-by-case''
approach will be illusory if the Commission dismisses a complaint by a
non-jurisdictional utility on the ground that the Commission has no
jurisdiction over the non-jurisdictional entity's rates

under sections 205 and 206 of the FPA, as it did in Central Iowa Power
Coop.\140\
Commission Determination
---------------------------------------------------------------------------

    \140\ Central Iowa Power Coop. v. Midwest ISO, 110 FERC ]
61,093, order on reh'g, 113 FERC ] 61,116 (2005).
---------------------------------------------------------------------------

    372. It was not the Commission's intention in Order No. 890 to
prejudge whether Transmission Congestion Contracts, Firm Transmission
Rights or Auction Revenue Rights should be treated as equivalents to
the credits available under section 30.9 of the pro forma OATT. The
Commission simply noted that those mechanisms exist and that the
Commission would determine, as it evaluated compliance filings from
individual ISOs and RTOs, whether such mechanisms served the same
purpose and goal of section 30.9 and, in turn, should be considered
proper substitutes for network customer credits. To the extent TAPS or
others object to proposals made by a particular RTO or ISO, the
appropriate forum to address those concerns is in the relevant
compliance docket.
    373. In response to NRECA, we continue to believe that it is
appropriate to consider on a case-by-case basis customer claims that
RTOs or ISOs are using the transmission facilities of a non-public
utility without compensation. It would not be appropriate to address
this issue in a vacuum, without a complete discussion by interested
parties of the legal and policy merits of both sides of this issue.
3. Capacity Reassignment
a. Removal of the Price Cap
    374. The Commission concluded in Order No. 890 that it is
appropriate to lift the price cap for all transmission customers
reassigning point-to-point transmission capacity, i.e., resellers. The
Commission found that the price cap had served to reduce transmission
options for customers and impair the development of a secondary market
for transmission capacity. The Commission concluded that removing the
price cap will allow capacity to be allocated to those entities that
value it the most, thereby sending more accurate price signals for
identification of the appropriate location for construction of new
transmission facilities to reduce congestion.
    375. To enhance oversight and monitoring by the Commission of the
secondary market for transmission capacity, certain reforms were
adopted to the underlying rules governing capacity reassignments.
First, the Commission required that all sales or assignments of
capacity be conducted through, or otherwise posted on, the transmission
provider's OASIS on or before the date the reassigned service
commences. Second, the Commission required that assignees of
transmission capacity execute a service agreement with the transmission
provider prior to the date on which the reassigned service commences.
Third, in addition to existing OASIS posting requirements, the
Commission required transmission providers to aggregate and summarize
in an electric quarterly report (EQR) the data contained in the service
agreements for reassigned capacity. The Commission explained that,
taken together, these reforms will increase the transparency of
capacity reassignments and facilitate our monitoring of the secondary
market for transmission capacity.
Requests for Rehearing and Clarification
    376. Several petitioners request rehearing of the decision to lift
the price cap on reassigned capacity.\141\ Some petitioners question
the Commission's stated justifications for the removal of the price
cap. TDU Systems contend that the non-cost factors cited by the
Commission, including promotion of the secondary market, enabling
customers to better manage the risk of their long term commitments
required by the reform of rollover rights, and sending more accurate
price signals for capacity, do not justify lifting the price cap or
substitute for analyzing the potential for the exercise of market power
before lifting it. TDU Systems, APPA, and NRECA challenge the
Commission's conclusion that removing the price cap for capacity
reassignments will stimulate greater infrastructure investment by
sending more accurate price signals as to the incremental cost of
transmission capacity. They argue that explicit congestion price
signals in RTO markets have failed to stimulate investment and, in any
event, are useless for transmission customers that lack the regulatory
certainty required to facilitate third-party construction of new
facilities. APPA argues that entrenched economic interests often find
it more profitable to pocket the remaining dollars than to invest in
new facilities.
---------------------------------------------------------------------------

    \141\ See, e.g., APPA, NRECA, and TDU Systems.
---------------------------------------------------------------------------

    377. These petitioners all disagree with the Commission's finding
that the price cap has impaired the development of a secondary market
for transmission. They argue that the Commission cites no support for
this finding and that it failed to address comments in response to the
NOPR stating that non-price limitations on capacity reassignment, such
as the requirement that the assignee use the same source and sink as
original customers, are the real reason that reassignments of capacity
do not occur. APPA also contends that the Commission failed to explain
why the lifting of the price cap is necessary to spur investment in
light of other reforms adopted in Order No. 890, such as a more robust
transmission planning process and the provision of planning redispatch
and conditional firm point-to-point service.
    378. TAPS argues that the precedent relied upon by the Commission
in Order No. 890 does not support the decision to lift the price cap
for reassigned capacity. TAPS states that, in Alternatives to
Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines and
Regulation of Negotiated Transportation Services of Natural Gas
Pipelines,\142\ the Commission actually required a market power
analysis to justify market-based rates. TAPS argues that in Interstate
Nat'l Gas Ass'n of America v. FERC,\143\ the D.C. Circuit relied on
empirical evidence to affirm the Commission's decision to lift the cap
on gas pipeline capacity releases. In that case, TAPS argues that:
there was a significant amount of firm capacity going unused,
suggesting that excess capacity could constrain prices and with
evidence that it did in fact put a downward pressure on prices;
evidence existed that new entry could restrain prices; and, the price
cap at issue was lifted only for two years during an experiment. TAPS
argues that similar empirical evidence is required, showing that prices
for secondary transmission capacity above the cap would be competitive
and that new entry could constrain prices.
---------------------------------------------------------------------------

    \142\ 74 FERC ] 61,076, reh'g denied, 75 FERC ] 61,024 (1996),
petitions for review denied sub. nom. Burlington Resources Oil & Gas
Co. v. FERC, 172 F.3d 918 (D.C. Cir. 1998).
    \143\ 285 F.3d 18 (D.C. Cir. 2002) (INGAA).
---------------------------------------------------------------------------

    379. Petitioners generally argue that removal of the price cap may
expose transmission customers to market power and is therefore contrary
to Commission and judicial precedent. APPA and TAPS argue that the
Supreme Court has rejected seller claims justifying higher prices for
electricity based upon the value ascribed to the product by the buyer,
stating that a ``focus on the willingness to pay or ability of the
purchaser to pay for a service is the concern of a monopolist, not a
government agency charged both with assuring the industry a fair return
and with assuring the public reliable and efficient service, at a
reasonable

price.'' \144\ In their view, this precedent requires the Commission to
maintain the price cap in the absence of hard evidence of a competitive
market for reassigned capacity.
---------------------------------------------------------------------------

    \144\ Quoting Gainesville Utilities Department, et al. v.
Florida Power Corp., 402 U.S. 515, 528 (1971).
---------------------------------------------------------------------------

    380. Joined by NRECA and TDU Systems, APPA and TAPS argue that the
Commission is allowed to authorize market-based rates only with
empirical proof that existing competition would ensure that the actual
price is just and reasonable and that undocumented reliance on market
forces will not suffice.\145\ In their view, the Commission must engage
in an ex ante competitive analysis to find that the seller lacks market
power, or take sufficient steps to mitigate market power, as well as
adopt sufficient post-approval reporting requirements.\146\ These
petitioners argue that the Commission's reliance on competition among
resellers, continued rate regulation of primary capacity, and the
reassignment-related reforms adopted in Order No. 890 is insufficient
to justify lifting the cap.
---------------------------------------------------------------------------

    \145\ Citing Farmers Union Cent. Exch., Inc. v. FERC, 734 F.2d
1486 (D.C. Cir. 1984) (Farmers Union) (finding that the Commission
failed to justify relaxation of cost-based regulation of oil
pipeline companies because it did not ensure rates would remain
within the zone of reasonableness).
    \146\ Citing California ex. rel. Lockyer, 383 F.3d 1006 (9th
Cir. 2004) (Lockyer).
---------------------------------------------------------------------------

    381. With regard to competition among resellers, APPA contends that
transmission capacity is a scarce commodity and demand is currently
inelastic, due in part to substantial load growth. APPA argues that
allowing point-to-point customers to make virtually unlimited profits
from reassignments of their firm service will not further competition
among resellers and, instead, may discourage participation in joint
planning to support expansion or acceptance of increased rates to
support new facilities. APPA acknowledges that firm transmission not
scheduled will be released on a non-firm basis, but argues that is of
little use to LSEs in need of firm transmission to deliver their firm
power supplies.
    382. NRECA and TDU Systems argue that it is contradictory for the
Commission to conclude that competition among resellers will assure
just and reasonable prices when, elsewhere in Order No. 890, the
Commission acknowledges congestion and the number of curtailments has
dramatically increased in recent years. These petitioners question what
market forces would constrain prices for secondary capacity at or below
the price of primary capacity if primary capacity is so scarce. They
question how it can be just and reasonable to price secondary rights at
a level higher than the just and reasonable price of primary capacity.
TAPS argues that a market power study of particular transmission paths
is necessary to support a finding that competition among resellers will
restrict market power.
    383. With regard to the availability of primary capacity at cost-
based rates, TAPS argues that the Commission has presented no factual
basis to conclude that entry will be timely, likely or sufficient to
defeat price increases due to transmission market power. TAPS contends
that, where capacity is fully subscribed, non-existent capacity cannot
act as a price restraint. APPA argues that any requirement for the
transmission provider to build new facilities in future years has
little if any bearing on the price an LSE is willing to pay for the
next day, week or month to ensure it meets its service obligation.
NRECA and TDU Systems contend that, notwithstanding the planning-
related reforms of Order No. 890, transmission providers can continue
to exert market power by refusing to expand the system to meet
competitors' needs. TDU Systems contends that failure to mandate
expansion of the grid or to encourage third party construction of
needed upgrades will ensure a lack of expansion, allowing the holder of
rights to transmission capacity to exert monopoly power in a secondary
market unprotected by price caps.
    384. Petitioners maintain that the revised oversight and reporting
requirements adopted in Order No. 890 are insufficient to protect
transmission customers from the exercise of market power. APPA and
NRECA argue that post hoc reporting cannot prevent real-time harm to
transmission customers and the end-users they serve or relieve the
Commission of the obligation to ensure, at the outset, that the
secondary market for capacity is competitive. TDU Systems similarly
contend that the new posting and reporting requirements are unlikely to
restrain the exercise of market power, since monthly reports will lag
significantly behind the daily and hourly market transactions, even
though greater price transparency may make market power easier to
detect after the fact.
    385. MISO argues that, instead of relying on continued regulation
in the primary market and competition in the secondary market to limit
the exercise of market power in the secondary market, the Commission
should provide for a sharing mechanism between the reseller and the
owner of the transmission asset to allocate any market premium obtained
from the resale. MISO contends that revenue sharing would reduce
incentives to engage in hoarding on the part of the reseller and
encourage efficient use of the grid. In its view, sharing market
premiums would have a solid ground in equity, ensuring that the owners
of transmission, constrained by cost-based rates, are not unduly
discriminated against in favor of the reseller.
    386. APPA also contends that the use of value-of-service pricing
for firm transmission service that LSEs require to meet their loads'
needs violates FPA section 217(b)(4) because it does not enable the
LSEs to secure the firm transmission rights they need to serve their
loads as Congress intended. While not specifically opposing the
Commission's decision to lift the price cap on reassignments of
transmission capacity, South Carolina E&G makes a similar request that
removal of the price cap be subject to the Commission's assurances that
the resulting increased use of the grid will not compromise service to
native load customers. In its view, an active secondary market could
crowd the limits of the grid and increase the likelihood of
curtailments. Southern Carolina E&G argues that FPA section 217
requires that native load service not be marginalized a result of any
increased use of the grid.
    387. If the Commission declines to reinstate the price cap on
assignments of transmission capacity, TAPS asks that the Commission
take two steps to offer consumer protection. First, TAPS asks the
Commission to require utilities seeking to reassign transmission
capacity to demonstrate a lack of transmission market power. TAPS
argues that this demonstration should examine each point of receipt/
point of delivery pair as a distinct market, unless the public utility
can show that alternative paths provide meaningful substitutes. Second,
TAPS asks the Commission to lift the price cap only for short-term
services and only for a period of two years. TAPS suggests that, at the
end of this period, the Commission should assess whether prices for
reassigned capacity are competitive and whether the experiment produced
the desired increase in reassigned capacity.
Commission Determination
    388. The Commission affirms the decision in Order No. 890 to remove
the price cap on reassignments of transmission capacity. We continue to
believe that removal of the price cap will give market participants
additional options for acquiring transmission. Point-to-point
transmission service

customers will have increased incentives to resell their service
whenever others place a higher value on it. Existing transmission
therefore will be put to better, more efficient use. Point-to-point
customers also may be willing to commit to buy additional transmission
service (such as for periods long enough to get rollover rights) since
they are able to resell above the price cap during periods in which
they do not need the capacity. On this basis alone, we find that
establishing a competitive market for secondary transmission capacity
will send more accurate signals that promote efficient use of the
transmission system by fostering the reassignment of unused capacity.
    389. We agree with petitioners that restricting reassignment to the
same point of receipt and point of delivery has limited, and may
continue to limit, the number of reassignments that take place. It does
not follow, however, that the price cap is irrelevant or that lifting
the cap will not encourage additional reassignments of transmission
capacity. Petitioners acknowledge that the secondary market for
transmission capacity is underdeveloped. Even if the price cap is not
the sole cause for this lack of development, it is at least a
contributing factor. While other reforms adopted in Order No. 890 also
will facilitate use of and investment in the transmission system, this
does not mean that lifting the price cap on capacity reassignments is
unnecessary or unimportant. The reforms adopted in Order No. 890,
including the decision to lift the price cap, work together to enhance
customer options and the transmission provider's operation of the grid.
    390. We are sensitive, however, to the concerns expressed by
petitioners and grant rehearing to limit the period during which
reassignments may occur above the cap. In Order No. 890, the Commission
directed staff to closely monitor the quarterly reassignment-related
data submitted by transmission providers to identify any problems in
the development of the secondary market and to prepare a report on
staff's findings for the Commission within 6 months of the receipt of
two years worth of data, i.e., by May 1, 2010. Upon further
consideration, we conclude that it is most appropriate to lift the
price cap on reassignments of capacity only to accommodate this study
period and amend section 23.1 of the pro forma OATT to reinstate the
price cap as of October 1, 2010. Upon review of the staff report and
any feedback from the industry, the Commission can determine whether it
is appropriate to continue to allow reassignments of capacity above the
price cap beyond that date.
    391. We disagree that a market power study or other empirical
competition analyses are required to lift the price cap on capacity
reassignments during this study period. Contrary to petitioners'
assertions, market power analyses are not the only method to ensure
that market-based rates remain just and reasonable.\147\ In INGAA,\148\
the court affirmed the Commission's removal of price ceilings for
short-term capacity releasing shippers in the natural gas market
without requiring sellers to submit market power analyses, recognizing
non-cost factors such as the need to lift price ceilings to facilitate
movement of capacity into the hands of those who value it most. The
court concluded that these non-cost factors, combined with the
limitation of negotiated rates to the secondary market, distinguished
the case from Farmers Union.\149\ Similarly, continuing rate regulation
of the transmission provider's primary capacity, competition among
resellers, and reforms to the secondary market for transmission
capacity, combined with enforcement proceedings, audits, and other
regulatory controls, will assure that prices in the secondary market
for transmission capacity remain within a zone of reasonableness.\150\
---------------------------------------------------------------------------

    \147\ See Alternatives to Traditional Cost-of-Service Ratemaking
for Natural Gas Pipelines and Regulation of Negotiated
Transportation Services of Natural Gas Pipelines, 74 FERC ] 61,076
at 61,227-36 (1996). The Commission ultimately determined in that
case that a market power analysis was required in order to allow a
pipeline to use market-based pricing instead of cost-of-service
rates. The Commission has not proposed to allow transmission
providers to engage in sales of primary capacity at market based
rates and, as explained below, sufficient protections exist to
ensure the secondary market for transmission capacity remains
sufficiently competitive without requiring market power analyses
from each reseller.
    \148\ 285 F.3d at 33.
    \149\ INGAA, 285 F.3d at 31-34.
    \150\ See Order No. 890 at P 811.
---------------------------------------------------------------------------

    392. Petitioners inappropriately discount the importance of these
regulatory protections, particularly the continued rate regulation of
primary transmission capacity. Unlike gas pipelines, transmission
providers are obligated to construct new facilities to satisfy a
request for service if that request cannot be satisfied using existing
capacity. The pro forma OATT does not, and will not, permit the
withholding of transmission capacity by the transmission provider and
effectively establishes a price ceiling for long-term reassignments at
the transmission provider's cost of expanding its system. Petitioner
arguments to the contrary assume non-compliance with the transmission
provider's obligations under the pro forma OATT. If a customer has
evidence of such non-compliance, it should bring the matter to the
Commission's attention through a complaint or other appropriate
procedural mechanism. Absent such evidence, the Commission concludes
that the continued rate regulation of the primary market, and the
transmission provider's obligation to expand its system to accommodate
service requests, adequately mitigates any market power that resellers
may have in the long-term secondary market.
    393. Pending the completion of upgrades, we acknowledge that delays
associated with constructing new facilities could limit the downward
effect that the transmission provider's cost of expansion has on
prices. Resellers could attempt to gain market power through economic
or physical withholding of their primary capacity when congestion
arises. As the Commission found in Order No. 890, however, competition
among resellers, as well as the ability of customers desiring
additional capacity to access primary capacity using conditional firm
point-to-point service or the modified planning redispatch implemented
in Order No. 890, will mitigate the exercise of market power in the
interim.\151\ Moreover, any primary capacity that is not scheduled is
made available to other customers on a non-firm basis, frustrating any
attempts to withhold capacity.\152\
---------------------------------------------------------------------------

    \151\ See Order No. 890 at P 809, 812.
    \152\ See id. at P 811.
---------------------------------------------------------------------------

    394. Reforms to the rules governing reassignments and associated
reporting obligations also increase our regulatory oversight of the
secondary market, allowing the Commission to effectively monitor that
market for any attempts to exercise market power. All reassignments
must now be conducted through or otherwise posted on OASIS and
assignees must execute service agreements prior to the date on which
service commences. Transmission providers must provide information
regarding reassignments in their EQRs.\153\ As noted above, Commission
staff will also closely monitor the

quarterly reassignment-related data submitted by transmission providers
and prepare a report on staff's findings for the Commission's
consideration. The Commission takes seriously the possibility that
resellers may attempt to exercise market power in the secondary market
for transmission capacity. We continue to believe, however, that the
regulatory protections in place and our increased oversight of this
market will limit the potential for market power abuse during the
period in which the price cap is lifted. There is no need for
particularized market power studies regarding secondary transmission
capacity, as suggested by TAPS.
---------------------------------------------------------------------------

    \153\ As TDU Systems point out, the reports will lag behind the
daily and hourly transactions in the market. As explained above,
competition among resellers and regulatory protections embedded in
the pro forma OATT will ensure that prices remain within the zone of
reasonableness in the immediate near-term. The reports will enable
the Commission to identify trends in the market and inefficiencies
that may occur. Furthermore, if parties see that particular holders
of transmission capacity are attempting to exercise market power
through hoarding or other tactics, they can report such instances to
the Office of Enforcement for investigation without delay.
---------------------------------------------------------------------------

    395. We disagree with NRECA and TDU Systems that the potential for
secondary prices to rise above primary capacity prices indicates that
rates may not be just and reasonable. As the courts have recognized,
prices in a competitive market should rise during periods when capacity
is truly scarce in order to ensure that capacity is being allocated
appropriately.\154\ The precedent cited by petitioners clearly permits
the Commission to implement alternative pricing structures provided
that safeguards are in place to ensure that rates remain within a zone
of reasonableness.\155\ We continue to believe that the regulatory
framework governing the reassignment of transmission capacity, combined
with our increased oversight and enforcement authority, will ensure
that the rates for secondary transmission capacity remain within the
zone of reasonableness. At the same time, lifting the price cap will
give primary transmission customers greater incentives to commit to
long-term service because they will be able to resell above the cap
during periods when they do not need the capacity.
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    \154\ See INGAA, 285 F.3d at 18, 32 (``[B]rief spikes in moments
of extreme exigency are completely consistent with competition,
reflecting scarcity rather than monopoly * * * A surge in the price
of candles during a power outage is no evidence of monopoly in the
candle market.'').
    \155\ See Farmers Union, 734 F.2d at 1509-10; INGAA, 285 F.3d at
32-34; Lockyer, 383 F.3d at 10-13; see also Environmental Action v.
FERC, 996 F.2d 401, 410 (D.C. Cir. 1993).
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    396. We decline to adopt a mechanism to share revenues from
capacity reassignments with the transmission provider. Allocation of
the entire reassignment premium to the reseller is appropriate because
it promotes an efficient allocation of transmission capacity, while
sharing of the premium could make a potential seller less likely to
resell even though another customer places a higher value on the
transmission service. The Commission addressed a similar request in
Order No. 636-A and concluded that releasing shippers in the gas market
should be entitled to receive the proceeds from reselling their
capacity.\156\ Notwithstanding differences in the secondary market for
transmission capacity, we believe that a similar approach should be
followed for transmission providers, particularly since they already
receive their full cost-of-service through payments for the underlying
primary capacity. In any event, it would only be fair to share premiums
with the transmission provider if losses were also shared when capacity
was resold for less than the cost to the reseller of the capacity. Such
sharing could lead to under-recovery of costs contrary to the premise
of cost-of-service rates.
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    \156\ See Pipeline Service Obligations and Revisions to
Regulations Governing Self-Implementing Transportation; and
Regulation of Natural gas Pipelines After Partial Wellhead
Decontrol, Order No. 636-A, 57 FR 36128 (August 12, 1992) FERC
Stats. & Regs., Regulations Preambles January 1991-June 1996 ]
30,950 at 30,562 (1992) (``Since the pipeline is not releasing the
capacity, no efficiency or other pro-competitive goal would be
furthered by allowing it to retain incremental proceeds.'').
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    397. Finally, we do not believe that assignments will impose risks
upon native load customers in contravention of FPA section 217 by
increasing the likelihood of curtailments. Transmission providers
should be planning the operation of their system to accommodate all
reserved uses. Simply reassigning primary capacity from one customer to
another should not alter the transmission provider's ability to satisfy
its service commitments. We also disagree that lifting the price cap on
reassignments of capacity will make it more difficult for LSEs to
obtain firm capacity to serve their load or otherwise marginalize
native load service, as APPA suggests. Lifting the price cap should
encourage primary capacity holders to make more, not less, transmission
available to other customers, including LSEs. While it is true that
secondary capacity may at times be more expensive than primary
capacity, establishing a competitive market for secondary transmission
capacity will benefit all customers, including LSEs, by sending more
accurate signals that promote efficient allocation of transmission
capacity.
b. Lifting the Price Cap for Merchant Function and Affiliates
    398. The Commission declined in Order No. 890 to adopt the NOPR
proposal to retain price caps for capacity resold by a transmission
provider's merchant function or its affiliates. After reviewing the
comments submitted in response to the NOPR, and further considering its
experience regulating capacity reassignments, the Commission concluded
that retaining price caps for this portion of the market would continue
to impair development of the secondary market and that price caps for
such capacity are not otherwise necessary to ensure just and reasonable
rates. The Commission found that there are no significant market power
concerns to justify retaining the price caps for any transmission
customer, noting that the Commission did not distinguish between
affiliated and non-affiliated transmission customers when the
Commission initially found in Order Nos. 888 and 888-A that excess
capacity reserved could be reassigned.
Requests for Rehearing and Clarification
    399. The same petitioners challenging the Commission's decision to
lift the price cap for reassignments of capacity object specifically to
lifting the price cap for reassignments by the transmission provider
and its affiliates. APPA argues that this decision will result in more
limited primary capacity, since it will be in the economic interest of
the transmission provider's corporate family for the merchant function
and/or affiliates of the transmission provider to buy any primary
capacity that is available. APPA contends that such transactions would
technically satisfy the transmission provider's obligation to make
primary capacity available to customers, but effectively convert
primary capacity into secondary capacity not subject to a price cap.
APPA acknowledges that the Commission found in Order No. 890 that the
Standards of Conduct will mitigate the ability of an affiliate to hoard
capacity, but argues that the Commission failed to explain how such
mitigation would occur.
    400. TAPS expresses similar concern that the transmission provider
will have an incentive to sell primary capacity to its merchant
function or affiliates to get around the rate ceiling on primary
capacity. If the secondary market is clearing at rates above the
transmission provider's rate ceiling, TAPS argues that the parent
corporation will have the incentive to put as much capacity in the
hands of its merchant function or affiliates as possible, reducing the
amount of price-restraining primary capacity and producing higher
revenues for the parent corporation for sales of monopoly transmission
service. In TAPS' view, costs associated with hoarding will not
encourage resale if withholding profitably raises prices in the
secondary market. TAPS also argues that the Commission's decision is

inconsistent with its conclusion elsewhere in Order No. 890 that
transmission providers have an incentive to over-designate CBM, which
TAPS states is a form of hoarding. TAPS complains that, although the
Commission stated in Order No. 890 that it will monitor for hoarding
behavior by transmission providers and their affiliates, it proposed no
remedy in the event they engage in this behavior.
    401. APPA, TAPS and TDU Systems argue that lifting the price cap
for the transmission provider's merchant function and affiliate sales
also will discourage transmission providers from constructing
transmission capacity in an attempt to raise prices in the secondary
market. They contend that corporate families profiting more from
transmission capacity resold by its merchant function or unregulated
affiliates will have a disincentive to build new transmission that
would lower those resale prices. APPA argues that much of Order No. 890
is devoted to attempting to ensure that transmission providers do not
discriminate in order to favor their own generation, yet lifting the
resale cap for the transmission provider's merchant function and
affiliates gives transmission providers incentives to favor their own
and their affiliates' sale of reassigned capacity at unregulated rates
and to limit construction of new transmission facilities and upgrades
to keep the rates for such reassignments high. NRECA and TDU Systems
agree, arguing that shareholders and senior management will be
indifferent as to whether the profits are from primary or secondary
markets, or from transmission or generation, and will seek to drive
profits to monopoly levels if possible. TDU Systems argue that the fact
that both affiliated and non-affiliated transmission customers were
permitted in Order No. 888 to engage in reassignments of capacity is
irrelevant because the ability to reassign capacity invoked few market
power concerns so long as the price cap remained.
    402. APPA also requests clarification as to whether the
transmission capacity that a transmission provider's merchant function
uses to serve the transmission provider's own retail loads is eligible
for reassignment. If so, APPA argues that it is unduly discriminatory
to deny network customers the ability to reassign their capacity. APPA
contends that network service was developed specifically to provide to
other LSEs a transmission service comparable to the transmission
service that public utilities provide themselves.
Commission Determination
    403. The Commission affirms the decision in Order No. 890 to lift
the price cap for capacity resold by any point-to-point transmission
customer, including the transmission provider's merchant function and
its affiliates. We continue to believe that retaining the price cap for
this portion of the market would impair development of the secondary
market and is not otherwise necessary to ensure just and reasonable
rates. In light of the protections discussed above, we find there are
not significant market power concerns that would justify retaining
resale price caps for any transmission customer.
    404. While it is true that lifting the price cap for reassignments
of capacity could provide an economic incentive for the transmission
provider's merchant function or its affiliates to acquire transmission
capacity in an attempt to exercise market power, the same is true for
any customer. Under the Standards of Conduct, affiliated and
unaffiliated customers have equal access to transmission-related
information and, through the OASIS, equal opportunity to acquire
primary transmission capacity. Thus, any customer could engage in
speculative purchasing in an attempt to gain market power. The
Commission found in Order No. 890 that the entire secondary market is
now sufficiently competitive, in light of the reforms adopted, market
forces, and other considerations, to justify lifting the price cap for
all transmission customers reselling capacity.\157\ As we explain
above, there are sufficient structural and regulatory protections to
ensure that no holder of capacity is able to exercise market power,