assertion that where no cost allocation method or methods exist, the
Commission cannot use section 206 as a basis for requiring them. The
basis for the Commission's reforms in Order No. 1000 is that
transmission planning for transmission service and the associated
allocation of costs for new transmission facilities are practices that
affect rates for purposes of section 206.\696\ The Commission also
explained that the allocation of transmission costs is often
contentious and prone to litigation,\697\ and that the lack of ex ante
cost allocation methods that identify the beneficiaries of proposed
regional and interregional transmission facilities may be impairing the
ability of public utility transmission providers to implement more
efficient or cost-effective transmission solutions identified in the
transmission planning process.\698\ The absence of a cost allocation
method or methods also has an adverse effect on rates by making it
difficult to deal with free rider problems related to new facilities.
The Commission's authority to require the adoption of a cost allocation
method or methods arises directly from its authority under section 206
to ensure that practices that affect transmission rates, such as
transmission planning, are just and reasonable and not unduly
discriminatory or preferential.
---------------------------------------------------------------------------

    \696\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 58.
    \697\ Id. P 498.
    \698\ Id. P 499.
---------------------------------------------------------------------------

    589. FirstEnergy Service Company's argument that section 205 does
not permit the Commission to require the filing of rates or contracts
is equally flawed. Here, FirstEnergy Service Company is simply arguing
that all rates are initially to be proposed by public utility
transmission providers. However, the Commission is not requiring the
proposal of a particular rate. It is requiring that public utility
transmission providers have a cost allocation method or methods in
their OATTs to ensure that the costs of new transmission facilities
selected in a regional transmission plan for purposes of cost
allocation are properly allocated to beneficiaries. It is for public
utility transmission providers to propose an actual method or methods.
The Commission is simply requiring that any cost allocation method or
methods that are proposed meet certain general

principles established in Order No. 1000.
    590. The case law cited by FirstEnergy Service Company to support
the proposition that the Commission cannot impose a new rate without
first determining that an existing rate is unjust, unreasonable, or
unduly discriminatory or preferential reinforces our above points. All
the cases that FirstEnergy Service Company cites in this connection
involve situations in which the court found that the Commission had
moved beyond rejecting a proposed rate to the task of redesigning
it.\699\ The Commission is not here ``imposing'' any rates, as it is
not specifying, designing, or redesigning any rates. Instead it is
requiring that all public utility transmission providers have a cost
allocation method or methods for certain new transmission facilities
that comply with a broad set of general principles.
---------------------------------------------------------------------------

    \699\ See, e.g., Western Resources, Inc. v. FERC, 9 F.3d 1568,
1578-79 (D.C. Cir. 1993).
---------------------------------------------------------------------------

    591. We agree with California ISO that rates are not unjust and
unreasonable simply because another rate might be more just and
reasonable. However, this point applies in a situation where the status
quo has been found to be just and reasonable and not unduly
discriminatory or preferential, which is not the case here. California
ISO argues that in its case such a finding is necessary because it has
voluntarily included in its tariff provisions that ensure the
construction of needed transmission projects, and it takes into account
cost-effectiveness in choosing these transmission projects. This
argument misconstrues the Commission's actions here, which are to
ensure that certain minimum requirements pertaining to transmission
planning and cost allocation are in place. California ISO's practices
may already satisfy some of these requirements, in which case it need
only explain how it satisfies them in its compliance filing.\700\ This,
however, does not show that there is no need for such requirements.
---------------------------------------------------------------------------

    \700\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 565,
583.
---------------------------------------------------------------------------

    592. Ad Hoc Coalition of Southeastern Utilities questions the
Commission's ability to require a cost allocation method or methods on
the grounds that section 206 limits the Commission's authority over
practices affecting rates to those that directly affect rates. Cost
allocation is a practice that affects rates because the effect of a
cost allocation method or methods is quite direct, as it determines who
is responsible for specific costs. As explained above, Order No. 1000
found that the lack of a regional cost allocation method known in
advance to transmission planners and the existence of free riders,
result in inefficient transmission planning that impedes the
development of more efficient and cost effective new transmission
facilities, with the result that jurisdictional rates are higher than
they would otherwise be. As we have noted previously, we disagree with
Ad Hoc Coalition of Southeastern Utilities' contention that requiring
utilities to pay for facilities that they do not use does not directly
affect rates for jurisdictional transmission service and is therefore
beyond the Commission's authority. This argument ignores the reality
that any entity connected to the transmission grid may benefit from a
transmission facility whether or not it is connected to, or
specifically requests service from, a particular transmission facility
for which costs have been allocated.\701\ Order No. 1000's cost
allocation reforms are therefore intended to ensure that all of these
beneficiaries are allocated costs roughly commensurate with the
benefits they receive in their use of the transmission grid, and we
believe that such a requirement can be seen as directly affecting the
rates for jurisdictional transmission service.
---------------------------------------------------------------------------

    \701\ Id. P 625.
---------------------------------------------------------------------------

B. Cost Allocation Method for Regional Transmission Facilities

1. Final Rule
    593. In Order No. 1000, the Commission required that each public
utility transmission provider have in place a method, or set of
methods, for allocating the costs of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation.\702\ The Commission stated that if the public utility
transmission provider is an RTO or ISO, then the cost allocation method
or methods must be set forth in the RTO or ISO OATT.\703\ In a non-RTO/
ISO transmission planning region, the Commission required each public
utility transmission provider located within the region to set forth in
its OATT the same language regarding the cost allocation method or
methods used in its transmission planning region.\704\ In either
instance, the Commission required that such cost allocation method or
methods be consistent with the regional cost allocation principles
adopted in Order No. 1000.\705\
---------------------------------------------------------------------------

    \702\ Id. P 558.
    \703\ Id.
    \704\ Id.
    \705\ Id.
---------------------------------------------------------------------------

    594. The Commission did not specify how the costs of an individual
regional transmission facility should be allocated.\706\ It noted,
however, that while each transmission planning region may develop a
method or methods for different types of transmission projects, each
such method or methods should apply to all transmission facilities of
the type in question and would have to be determined in advance for
each type of facility.\707\ Additionally, the Commission acknowledged
that cost containment is important, but declined to establish a
corresponding cost allocation principle, primarily because cost
containment concerns the level of costs, not how costs should be
allocated among beneficiaries.\708\
---------------------------------------------------------------------------

    \706\ Id. P 560.
    \707\ Id.
    \708\ Id. P 704.
---------------------------------------------------------------------------

    595. With respect to cost allocation for a proposed transmission
facility located entirely within one public utility transmission
owner's service territory, the Commission found that a public utility
transmission owner may not unilaterally apply the regional cost
allocation method or methods developed pursuant to Order No. 1000.\709\
However, the Commission also found that a proposed transmission
facility located entirely within a public utility transmission owner's
service territory could be determined by the public utility
transmission providers in the region to provide benefits to others in
the region and thus be selected in the regional transmission plan for
purposes of cost allocation; then the cost of that transmission
facility would be allocated according to that region's regional cost
allocation method or methods.\710\
---------------------------------------------------------------------------

    \709\ Id. P 564.
    \710\ Id.
---------------------------------------------------------------------------

    596. In Order No. 1000, the Commission also declined to make new
findings with respect to pancaked rates, stating that it was beyond the
scope of the proceeding.\711\ The Commission further stated that it was
not making any modifications to the Commission's pancaked rate
provisions for an RTO under Order No. 2000.\712\ However, the
Commission noted that if rate pancaking was an issue in a particular
transmission planning region, stakeholders could raise their concerns
in the consultations leading to the compliance proceedings for Order
No. 1000 or make a separate filing with the Commission under section
205 or 206 of the FPA, as appropriate.\713\
---------------------------------------------------------------------------

    \711\ Id. P 764.
    \712\ Id.
    \713\ Id.

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

2. Requests for Rehearing and Clarification
    597. North Carolina Agencies argue that the Commission's planning
and cost allocation reforms represent major changes that have the
potential to preempt state authority over bundled retail rates. They
state that to date, the Commission has declined to exercise its
authority over the transmission component of bundled retail rates and
service despite pressure to do so and the U.S. Supreme Court's decision
in New York v. FERC.\714\ North Carolina Agencies assert that the
Commission must recognize that the applicability of any cost allocation
methods that result from Order No. 1000 is limited to unbundled
transmission and cannot impinge on state jurisdiction with respect to
bundled retail rates. Ad Hoc Coalition of Southeastern Utilities
likewise contends that the allocation of the cost of regional
transmission facilities to entities performing a retail sales function
would preempt state commissions in setting bundled retail rates because
under the Supremacy Clause, utilities will be entitled to recover their
costs in retail rates.
---------------------------------------------------------------------------

    \714\ North Carolina Agencies at 4 (citing 535 U.S. 1 (2002)).
North Carolina Agencies state that while New York v. FERC includes
dicta suggesting that the Commission's authority is an open issue,
the Court found that the jurisdictional issue is a difficult one.
North Carolina Agencies at 5.
---------------------------------------------------------------------------

    598. Northern Tier Transmission Group also states that the
Commission should clarify that it does not intend to set retail rates.
It states that the Commission has not explained the relationship
between the mandatory cost allocation process and the ability of a
project proponent to recover the costs of a selected transmission
facility.
    599. In a related argument, Alabama PSC argues that Order No. 1000
fails to satisfy the requirements of the Administrative Procedure Act
(APA) \715\ because it lacks definiteness on how cost allocation will
translate into recovery. It is concerned that the rule will result in
stranded costs if a transmission provider cannot recover allocated
costs because of the absence of an appropriate contractual vehicle and
lead to cost shifting to others within the region. Alabama PSC also
asserts that Commission is being inconsistent when it does not address
cost recovery but then does not accept participant funding, which
Alabama PSC describes as a form of cost recovery, as a regional cost
allocation method. Southern Companies argue that if there is no payment
obligation coinciding with a cost assignment, industry cannot presume
that Order No. 1000's objective is to create a rate structure to induce
transmission developers to participate more fully in regional
transmission planning processes. They state that the Commission should
address this issue in order to prevent parties from engaging in a
futile exercise over the next eighteen months.
---------------------------------------------------------------------------

    \715\ Administrative Procedure Act, 5 U.S.C. 706(2)(A).
---------------------------------------------------------------------------

    600. Several other petitioners also take issue with the
Commission's determination to not address cost recovery issues in Order
No. 1000. Sacramento Municipal Utility District argues that the issue
with respect to cost recovery mechanisms is not the identity of the
transmission provider, but whether the party being assessed charges is
one of the provider's customers. It maintains that ``it is not a mere
concern over form'' to expect an explanation of the mechanism for
recovering a rate when the party being charged is not a customer.
    601. Edison Electric Institute, NV Energy and Southern Companies
argue that the Commission does not explain how costs can be allocated
under a regional transmission plan in a non-RTO/ISO region without a
contractual mechanism permitting the charging and collection of such
costs. Edison Electric Institute acknowledges that a tariff could
provide a contractual mechanism for the collection of allocated costs,
but states that Order No. 1000 does not identify any mechanism for
requiring the payment of costs in the absence of such an applicable
tariff or agreement. Edison Electric Institute thus asserts that the
Commission is not engaging in reasoned decision making when it
concludes that it ``would permit recovery of costs from a beneficiary
in the absence of a voluntary arrangement.'' \716\
---------------------------------------------------------------------------

    \716\ Edison Electric Institute at 7-8.
---------------------------------------------------------------------------

    602. In the alternative, Edison Electric Institute argues that the
Commission should clarify: (1) Whether allocation in a regional plan of
costs to a beneficiary in a non-RTO/ISO region without a voluntary
arrangement to pay creates an obligation of the beneficiary to pay
those costs; and (2) if so, the mechanism for collecting such costs,
including the source of the obligation of the beneficiary to pay.
Southern Companies make a similar argument.
    603. National Rural Electric Coops argue that the distinction
between cost allocation and cost recovery in Order No. 1000 has no
practical significance. NARUC argues that if cost allocation is
distinct from cost recovery, it is not clear that the Commission's
authority to set rates for transmission under the FPA provides the
Commission with jurisdiction over cost allocation.
    604. Northern Tier Transmission Group requests that the Commission
clarify the relationship between cost allocation and cost recovery. It
states that the ability to recover costs appears to be merely a factor
that can be considered and acknowledged in the cost allocation process.
Northern Tier Transmission Group asserts that this issue is material to
the decision to participate in the construction of a project. Therefore
a clarification of the intended relationship between cost allocation
and cost recovery will better inform the methods developed for and the
analysis performed by the regional and interregional transmission
planning processes.
    605. Northern Tier Transmission Group also asserts that the
Commission has no authority under the FPA to require the imposition of
transmission construction costs on non-jurisdictional beneficiaries or
to impose cost recovery on the United States or any state including any
political subdivision.\717\ Edison Electric Institute states that
paragraph 629 of Order No. 1000 states that non-jurisdictional
transmission providers that do not participate in the regional planning
process are not responsible for costs allocated in that process. It
states that it is arbitrary and capricious to treat jurisdictional
transmission providers and non-public utility transmission providers
differently with respect to any obligation they may have, in the
absence of a voluntary agreement, to pay costs allocated to them in a
regional planning process.
---------------------------------------------------------------------------

    \717\ Northern Tier Transmission Group at 6 (citing 16 U.S.C.
824(e) and (f); Bonneville Power Admin. v. FERC, 422 F.3d 908 (9th
Cir. 2005)).
---------------------------------------------------------------------------

    606. Arizona Cooperative and Southwest Transmission argue that
paragraph 629 in Order No. 1000 suggests that a non-public utility will
be forced to accept the regional cost allocation, and may effectively
forfeit its right to avoid an unduly discriminatory cost assignment if
participating in the process means that it loses the ability to
exercise its right to seek relief from the Commission. Arizona
Cooperative and Southwest Transmission argue that non-participation is
not a desirable answer to this problem, especially as an entity that
does not participate could still get saddled with costs and would also
forego the opportunity to have its own contributions to a more robust
grid included in the regional plan.
    607. Alabama PSC argues that if the regional planning process
supersedes or replaces the output of a state integrated

resource plan that relies on participant funding, it will infringe on a
state's prerogative to manage the costs borne by its consumers. Alabama
PSC also states that Order No. 1000 incorrectly asserts that the cost
allocation requirements conform fully with the position taken by the
Alabama PSC. Instead, it states that its concern is that a regional
process may identify electricity consumers in Alabama as receiving
benefits from a new transmission project selected in a regional
transmission plan for purposes of cost allocation, even if the supposed
benefits are completely at odds with Alabama PSC's conclusions. Thus,
even though Order No. 1000 states that consumers will not be assigned
costs from which they derive no benefit, Alabama PSC remains concerned
about this and maintains that states should have the option of vetoing
such a course or opting out of any cost allocation.
    608. Florida PSC argues that the cost allocation provisions of
Order No. 1000 infringe on its jurisdiction. Florida PSC states that
Florida utilities are vertically-integrated, and no part of the state
is a member of an RTO or ISO. It thus retains authority over cost
allocation. Florida PSC asserts that planning decisions under the new
processes will affect wholesale rates that will flow to retail
customers. Florida PSC thus argues that regions may find themselves
paying higher retail rates for benefits realized only in a neighboring
region. Florida PSC argues that the Commission does not have authority
to assign cost recovery to retail rates for benefits not defined as
such in the retail customers' region.
    609. Transmission Access Policy Study Group argues that Order No.
1000 erred in finding that comments on access to regionally cost
allocated facilities through regional tariffs at non-pancaked rates
were beyond the scope of the proceeding.\718\ It asserts that failing
to address these issues leaves a void that must be filled before
regional cost allocations can be implemented in non-RTO regions.\719\
It believes that a regional tariff, with non-pancaked rates covering
both existing and new facilities, is the best way to address these
issues because such tariffs can solve cost allocation implementation
issues and avoid the creation of new rate pancakes. Transmission Access
Policy Study Group suggests that if the Commission does not grant
rehearing, it should use its authority to induce transmission providers
to adopt regional rates that eliminate pancaking and foster
transmission investment.
---------------------------------------------------------------------------

    \718\ Transmission Access Policy Study Group at 40 (citing Order
No. 1000, FERC Stats. & Regs. ] 31,323 at PP 549, 764).
    \719\ Transmission Access Policy Study Group asserts that Order
No. 1000's focus on cost allocation as disassociated from service
relationships heighten these concerns.
---------------------------------------------------------------------------

    610. Alternatively, Transmission Access Policy Study Group states
that the Commission should require a process to address access issues
at the compliance stage. It also argues that access should be addressed
when a specific cost allocation is applied to a project. Transmission
Access Policy Study Group states that in non-RTO regions, the
Commission should require that access issues be addressed in the
regional process for selection of an upgrade and the application of the
regional cost allocation to a facility, as well as require filing of
the specific cost allocation as applied to the particular project
selected for regional cost allocation, with a description of how access
will be provided and on what rates, terms, and conditions. Transmission
Access Policy Study Group believes that specific applications of the
regional cost allocation should be filed as soon as the constructor of
the facility is identified, with access issues addressed at that time
rather than when the facility is completed.\720\ According to
Transmission Access Policy Study Group, this will help address
uncertainty caused by the absence of regional tariffs and Order No.
1000's preference for flexibility. Finally, Transmission Access Policy
Study Group urges prompt public disclosure of the mechanism to provide
access to regionally cost-allocated facilities, and it states that it
is essential to address access issues before a proposed facility
proceeds through the permitting and siting process.
---------------------------------------------------------------------------

    \720\ Transmission Access Policy Study Group notes that Order
No. 1000 does not address timing of the filing of specific
applications of the regional cost allocation.
---------------------------------------------------------------------------

    611. Several petitioners question the Commission's decision not to
address cost containment issues in Order No. 1000. For example,
Illinois Commerce Commission argues that the Commission does not
provide a good reason for not addressing cost containment, and that it
must be addressed to prevent excessive costs, which is a fundamental
part of any appropriate cost allocation method. Illinois Commerce
Commission asserts that even if Order No. 1000 is not the appropriate
forum, the Commission erred in failing to identify an alternative
forum.
    612. Wisconsin PSC requests that there be a mandate to consider
cost overrun containment mechanisms. It argues that uncontained costs
are as likely to undermine needed transmission development as a flawed
cost allocation method or no method at all would. Wisconsin PSC states
that Order No. 1000's distinction between the allocation of costs and
the amount of costs is a hollow one because the key question for states
and the customers who pay for the lines is the cost/benefit of the
buildout.\721\ It also argues that since the Commission saw fit to
develop a fallback mechanism for situations where a project developer
abandons a line that a transmission provider had depended upon for
reliability and supply purposes; it should also have a fallback
mechanism for cost overruns, which pose a much greater prospect of harm
to the consuming public.
---------------------------------------------------------------------------

    \721\ Wisconsin PSC at 10-11 (citing Order No. 1000, FERC Stats.
& Regs. ] 31,323 at PP 704-05 (2007)).
---------------------------------------------------------------------------

3. Commission Determination
    613. We affirm Order No. 1000's requirement that each public
utility transmission provider have in place a method, or set of
methods, for allocating the costs of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation.\722\ In Order No. 1000, the Commission did not specify how
the costs of an individual regional transmission facility should be
allocated.\723\ It noted, however, that while each transmission
planning region may develop a method or methods for different types of
transmission projects, each such method or methods should apply to all
transmission facilities of the type in question and would have to be
determined in advance for each type of facility.\724\ We continue to
believe that such an approach is necessary to ensure that the rates,
terms, and conditions of jurisdictional service are just and reasonable
and not unduly discriminatory or preferential. This is because in the
absence of clear cost allocation rules, there is a greater potential
that pubic utility transmission providers and nonincumbent transmission
developers may be unable to develop transmission facilities that are
determined by the region to meet their needs.\725\
---------------------------------------------------------------------------

    \722\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 558.
    \723\ Id. P 560.
    \724\ Id.
    \725\ Id. P 559.
---------------------------------------------------------------------------

    614. In response to Alabama PSC's argument that a state should be
permitted to veto any particular cost allocation if it disagrees with
the outcome, we reiterate Order No. 1000's finding declining to mandate
veto rights

for state committees. However, as stated in Order No. 1000, the
Commission does not preclude public utility transmission providers from
proposing such mechanisms on compliance if they choose to do so.\726\
We emphasize that any such mechanisms must be consistent with the goals
of Order No. 1000's transmission planning and cost allocation reforms,
an important part of which are to provide that costs are allocated to
beneficiaries roughly commensurate with the benefits that they receive.
---------------------------------------------------------------------------

    \726\ Id. P 502.
---------------------------------------------------------------------------

    615. In response to Alabama PSC's concern that the Commission's
cost allocation reforms could lead to stranded transmission costs due
to the absence of a necessary contractual vehicle, we note that
entities that receive benefits are subject to a Commission-approved
transmission tariff. The existence of obligation arising under such a
tariff is sufficient to ensure that there will be no stranded costs,
and the question of specific recovery mechanisms is beyond the scope of
this proceeding. This point applies equally to Southern Companies'
concern about payment obligations that correspond to cost assignments.
    616. Additionally, we find no merit in the arguments advanced to
challenge our position in Order No. 1000 that cost allocation and cost
recovery are distinct issues and our determination not to address
matters of cost recovery there.\727\ We therefore affirm the
Commission's decision in Order No. 1000 that cost recovery is a
separate issue, and we will not specify how costs can be recovered for
transmission projects that are selected in the regional transmission
plan for purposes of cost allocation. The U.S. Supreme Court has found
that the Commission has broad discretion in determining which issues to
address in a particular proceeding.\728\ While we will not address cost
recovery in this proceeding, we note that cost recovery may be
considered as part of a region's stakeholder process in developing a
cost allocation method or methods to comply with Order No. 1000.
Therefore, to the extent that cost recovery provisions are considered
in connection with a cost allocation method or methods for a regional
or interregional transmission facility, public utility transmission
providers may include cost recovery provisions in their compliance
filings.
---------------------------------------------------------------------------

    \727\ Id. P 563.
    \728\ Mobil Oil Exploration & Producing Southeast, Inc. v.
United Distribution Companies, 498 U.S. 211, 230 (1991). See also
Tennessee Valley Municipal Gas Association v. FERC, 140 F.3d. 1085,
1088 (D.C. Cir. 1998).
---------------------------------------------------------------------------

    617. We thus reject Sacramento Municipal Utility District's
contention that Order No. 1000 is deficient because it does not explain
the mechanism for recovering a cost ``when the party being charged is
not a customer.'' \729\ Sacramento Municipal Utility District's claim
of deficiency is premised on the proposition that costs cannot be
allocated in a situation where an entity does not have a preexisting
contractual relationship with the entity that will recover the costs.
It considers a cost allocation in this situation to be a cost
allocation to a non-customer. We have addressed this issue at length
above. Because we disagree with Sacramento Municipal Utility District's
premise, we disagree that our decision not to address cost recovery in
Order No. 1000 makes the order deficient. This conclusion applies
equally to Sacramento Municipal Utility District's assertion that it is
not a mere concern over form to expect an explanation of the mechanism
for recovering a charge when the party being charged is not a customer.
---------------------------------------------------------------------------

    \729\ Sacramento Municipal Utility District at 11.
---------------------------------------------------------------------------

    618. Edison Electric Institute seeks clarification on how costs can
be recovered from a beneficiary in the absence of an applicable tariff
or agreement. Edison Electric Institute's request is based on its
reading of paragraph 506 of Order No. 1000, which it notes states that
the Commission ``would permit recovery of costs from a beneficiary in
the absence of a voluntary arrangement.'' However, this statement is
simply part of a summary of the Commission's ruling in AEP. This
summary does not imply that Order No. 1000 contemplates the recovery of
costs from a beneficiary in the absence of an applicable tariff or
agreement. All tariffs will be required to contain an appropriate cost
allocation method or methods.
    619. In response to Alabama PSC, the Commission was not being
inconsistent on the issue of cost recovery when it found that
participant funding, which it describes as a form of cost recovery,
cannot be a regional cost allocation method. This argument assumes that
cost allocation and cost recovery are not distinct issues. The
Commission's position is that they are distinct--a point that Alabama
PSC does not challenge--and thus when it concluded that participant
funding cannot serve as a regional cost allocation method, the
Commission was not making a conclusion regarding cost recovery
mechanisms. As a result, the Commission was not taking an action that
was inconsistent with its position that it would not address cost
recovery in Order No. 1000. We address the prohibition against
participant funding as a regional cost allocation method elsewhere in
this order. Similarly, we disagree with Northern Tier Transmission
Group that the Commission is impermissibly imposing recovery of
transmission construction costs on non-jurisdictional entities, as
Order No. 1000 did not address matters of cost recovery.
    620. Moreover, we disagree with petitioners' arguments that Order
No. 1000's cost allocation provisions infringe on state authority over
the siting and permitting of transmission facilities, or that they
infringe on integrated resource planning. Petitioners have not
demonstrated anything persuasive to support their comments. More
generally, as we discuss in the cost allocation legal authority section
above, we have ample authority under the FPA to require public utility
transmission providers to file regional and interregional cost
allocation methods, and we direct petitioners to that section for a
fuller discussion of the Commission's legal authority.
    621. We disagree with those petitioners who claim the Commission is
seeking to regulate bundled retail rates. North Carolina Agencies
provide no clear explanation for their position. Indeed, they state
only that there is a potential for the Commission to regulate bundled
retail rates. As for Ad Hoc Coalition of Southeastern Utilities'
arguments, we disagree that requiring the implementation of a method to
allocate the costs of new transmission facilities selected in a
regional transmission plan for purposes of cost allocation amounts to
regulation of bundled retail rates.\730\ As discussed in Order No. 1000
and in this order, we have ample legal authority to adopt the Order No.
1000 cost allocation reforms.\731\ We also affirm Order No. 1000's
discussion of this issue, namely, that:
---------------------------------------------------------------------------

    \730\ Ad Hoc Coalition of Southeastern Utilities at 74.
    \731\ See, e.g., Order No. 1000, FERC Stats. & Regs. ] 31,323 at
P 530-49; see also discussion supra at section 0 and discussion
supra at section IV.A.3.

    [I]t is not clear why cost allocations consistent with this
Final Rule would affect state jurisdiction differently from existing
cost allocations. In any event, we find that such arguments are
premature. It is inappropriate for the Commission to decide such
issues generically in a rulemaking, as such issues should be decided
based on

specific facts and circumstances, none of which are presented
here.\732\
---------------------------------------------------------------------------

    \732\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 548.

    Accordingly, we reiterate here that in this generic rulemaking
proceeding, these issues are not presented for Commission
determination.
    622. To the extent a non-public utility transmission provider
exercises its discretion to enroll as a transmission provider in a
regional transmission planning process, it may be allocated costs
roughly commensurate with the benefits that it is determined to receive
from new transmission facilities selected in the regional transmission
plan for purposes of cost allocation.\733\ We disagree with Arizona
Cooperative and Southwest Transmission that a non-public utility
transmission provider will effectively forfeit its rights to avoid
undue discrimination by participating in the regional transmission
planning process for several reasons. First, the choice of whether to
enroll in the regional transmission planning process, and thus be
subject to being determined to be a beneficiary for which cost
allocation is appropriate, remains with each non-public utility
transmission provider. Second, it will have a voice in the process of
determining the cost allocation method, and if it believes that the
result is unduly discriminatory, it maintains the right to intervene in
the compliance proceeding when that method is filed at the Commission.
Third, for future applications of the method to actual new facilities,
a non-public utility transmission provider could exercise any right it
has in the regional transmission planning process to withdraw rather
than accept the allocation of costs.\734\ And finally, non-public
utility transmission providers choosing to remain in the transmission
planning region notwithstanding dissatisfaction with a particular
application of the cost allocation method may file with the Commission
for a FPA 206 determination that the approved method is no longer just
and reasonable or is unduly discriminatory or preferential in practice.
---------------------------------------------------------------------------

    \733\ See discussion supra at PP 0-0.
    \734\ To accommodate the participation of non-public utility
transmission providers, the relevant tariffs or agreements governing
the regional transmission planning process could establish the terms
and conditions of orderly withdrawal for non-public utility
transmission providers that are unable to accept the allocation of
costs pursuant to a regional or interregional cost allocation
method. See Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 820.
---------------------------------------------------------------------------

    623. We affirm the Commission's finding in Order No. 1000 that this
is not the proper proceeding to address rate pancaking issues. If rate
pancaking is an issue in a particular transmission planning region,
stakeholders may raise their concerns in the consultations leading to
the compliance proceedings for Order No. 1000 or make a separate filing
with the Commission under section 205 or 206 of the FPA, as
appropriate.\735\ The Commission has the discretion to determine which
issues to address in a particular proceeding.\736\
---------------------------------------------------------------------------

    \735\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 764.
    \736\ Mobil Oil Exploration & Producing Southeast, Inc. v.
United Distribution Companies, 498 U.S. 211, 230 (1991). See also
Tennessee Valley Municipal Gas Association v. FERC, 140 F.3d. 1085,
1088 (D.C. Cir. 1998).
---------------------------------------------------------------------------

    624. With regard to concerns related to access to new transmission
facilities for which an entity has been allocated costs pursuant to a
regional or interregional cost allocation method, the Commission
believes that the appropriate forum to consider such issues in the
first instance is in the regional transmission planning process for
each transmission planning region. Each regional transmission planning
process must provide entities who will receive regional or
interregional cost allocation an understanding of the identified
benefits on which the cost allocation is based. The Commission
anticipates that regions may approach these issues in different ways
and thus will allow public utility transmission providers, in
consultation with stakeholders, to address these issues as they develop
the regional and interregional cost allocation methods for their
transmission planning region. We note that entities may utilize the
existing OATT provisions regarding Order No. 890 dispute resolution,
which will also apply to the new transmission planning and cost
allocation processes adopted under Order No. 1000, if they disagree
with the public utility transmission provider's identification of
benefits and beneficiaries for a regional or interregional transmission
facility selected in the regional transmission plan for purposes of
cost allocation.
    625. We affirm the Commission's decision in Order No. 1000 that
cost containment issues relate to the level of costs and not how costs
should be allocated among beneficiaries.\737\ As the Commission
emphasized in Order No. 1000, this proceeding relates to transmission
planning reforms, including the role of cost allocation in transmission
planning, not the level of transmission costs,\738\ and therefore this
proceeding is not the appropriate forum for addressing the transmission
cost containment issues raised by petitioners. However, as with cost
recovery, we note that cost containment may be considered as part of a
region's stakeholder process in developing a cost allocation method or
methods to comply with Order No. 1000. Therefore, to the extent that
cost containment provisions are considered in connection with a cost
allocation method or methods for a regional or interregional
transmission facility, public utility transmission providers may
include transmission cost containment provisions in their compliance
filings.
---------------------------------------------------------------------------

    \737\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 704.
    \738\ Id.
---------------------------------------------------------------------------

C. Cost Allocation Method for Interregional Transmission Facilities

1. Final Rule
    626. In Order No. 1000, the Commission required each public utility
transmission provider in a transmission planning region to have,
together with the public utility transmission providers in its own
transmission planning region and a neighboring transmission planning
region, a common method or methods for allocating the costs of a new
interregional transmission facility among the beneficiaries of that
transmission facility in the two neighboring transmission planning
regions in which the transmission facility is located. The Commission
explained that the cost allocation method or methods used by the pair
of neighboring transmission regions can differ from the cost allocation
method or methods used by each region to allocate the cost of a new
interregional transmission facility within that region.\739\ The
Commission stated that in an RTO or ISO region, the method must be
filed in the OATT.\740\ Additionally, the Commission stated that in a
non-RTO/ISO transmission planning region, the same common cost
allocation method or methods must be filed in the OATT of each public
utility transmission provider in the transmission planning region.\741\
In either instance, the Commission stated that such cost allocation
method or methods must be consistent with the interregional cost
allocation principles adopted in Order No. 1000.\742\
---------------------------------------------------------------------------

    \739\ Id. P 578.
    \740\ Id.
    \741\ Id.
    \742\ Id.
---------------------------------------------------------------------------

    627. The Commission also clarified that it would not require each
transmission planning region to have the same interregional cost
allocation method or methods with each of its neighbors.\743\ Order No.
1000 provided that each pair of transmission planning

regions may develop its own approach to interregional cost allocation
that satisfies both transmission planning regions' needs and concerns,
as long as that approach satisfies the interregional cost allocation
principles.\744\
---------------------------------------------------------------------------

    \743\ Id. P 580.
    \744\ Id.
---------------------------------------------------------------------------

    628. The Commission did not specify how the costs for an individual
interregional transmission facility should be allocated.\745\ However,
the Commission stated that while transmission planning regions can
develop a different cost allocation method or methods for different
types of transmission projects, such a cost allocation method or
methods should apply to all transmission facilities of the type in
question and each cost allocation method would have to be determined in
advance for each type of transmission facility.\746\ Also, the
Commission adopted the requirement that an interregional transmission
facility must be selected in a relevant regional transmission plan for
purposes of cost allocation to be eligible for interregional cost
allocation pursuant to the interregional cost allocation method or
methods.\747\
---------------------------------------------------------------------------

    \745\ Id. P 581.
    \746\ Id.
    \747\ Id.
---------------------------------------------------------------------------

    629. The Commission also noted that as it made clear in its
discussion of Cost Allocation Principle 4,\748\ costs may be assigned
only on a voluntary basis to a transmission planning region in which an
interregional transmission facility is not located.\749\ The Commission
noted that, given this option, regions are free to negotiate
interregional transmission arrangements that allow for the allocation
of costs to beneficiaries that are not located in the same transmission
planning region as any given interregional transmission facility.\750\
---------------------------------------------------------------------------

    \748\ See Order No. 1000, FERC Stats. & Regs. ] 31,323 at
section IV.E.5.
    \749\ Id. P 582.
    \750\ Id.
---------------------------------------------------------------------------

    630. In addition, the Commission clarified that the requirement to
coordinate with neighboring regions applies to public utility
transmission providers within a region as a group, not to each
individual public utility transmission provider acting on its own. For
example, within an RTO or ISO, the RTO or ISO would develop an
interregional cost allocation method or methods with its neighboring
regions on behalf of its public utility transmission owning
members.\751\
---------------------------------------------------------------------------

    \751\ Id. P 584.
---------------------------------------------------------------------------

2. Requests for Rehearing or Clarification
    631. Several petitioners seek clarification of the Commission's
interregional cost allocation requirements. California ISO seeks
clarification that one planning region cannot allocate costs to a
neighboring transmission planning region for a transmission line that
interconnects to the system of the neighboring region but that the
neighboring region has not determined is needed and has not included in
its transmission plan.
    632. MISO Transmission Owners Group 1 requests clarification that
Order No. 1000's statement that a transmission owner in an RTO or ISO
can comply with the proposed interregional cost allocation mandates
through participation in the RTO and ISO is not intended to alter a
transmission owner's section 205 rights or the division of section 205
filing rights between an RTO and its transmission owners. It states
that if the Commission does not provide this clarification, the
Commission must grant rehearing because limiting the section 205 filing
rights of transmission owners would be contrary to judicial
precedent.\752\
---------------------------------------------------------------------------

    \752\ MISO Transmission Owners Group 1 at 13-14 (citing Atlantic
City Electric Co. v. FERC, 295 F.3d 1 (D.C. Cir. 2002)).
---------------------------------------------------------------------------

    633. Transmission Dependent Utility Systems request clarification
that transmission customer load-serving entities should be able to
review and comment on the development of interregional cost allocation
methods and have their input considered and addressed before public
utility transmission providers make their compliance filings.
Transmission Dependent Utility Systems assert this is necessary to
ensure consistency with the non-discrimination requirements of FPA
section 205.
3. Commission Determination
    634. As stated in Order No. 1000, the Commission requires that each
public utility transmission provider in a transmission planning region
must have, together with the public utility transmission providers in
its own transmission planning region and a neighboring transmission
planning region, a common method or methods for allocating the costs of
a new interregional transmission facility among the beneficiaries of
that transmission facility in the two neighboring transmission planning
regions in which the transmission facility is located.\753\ We continue
to believe that the absence of clear cost allocation rules for
interregional transmission facilities can impede the development of
such transmission facilities due to the uncertainty regarding the
allocation of responsibility for associated costs, potentially
adversely affecting rates for jurisdictional services causing them to
become unjust and unreasonable or unduly discriminatory or
preferential.\754\
---------------------------------------------------------------------------

    \753\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 579.
    \754\ Id.
---------------------------------------------------------------------------

    635. In response to California ISO's request that we clarify that
another region could not impose costs on it for an interregional
transmission facility without approval, Order No. 1000 states that, for
an interregional transmission facility to receive interregional cost
allocation, each of the neighboring transmission planning regions in
which the interregional transmission facility is proposed to be located
must select the facility in its regional transmission plan for purposes
of cost allocation.\755\ As such, we believe that it is clear that, if
one of the regional transmission planning processes does not select the
interregional transmission facility to receive interregional cost
allocation, neither the transmission developer nor the other
transmission planning region may allocate the costs of that
interregional transmission facility under the provisions of Order No.
1000 to the region that did not select the interregional transmission
facility.
---------------------------------------------------------------------------

    \755\ Id. P 436.
---------------------------------------------------------------------------

    636. In response to MISO Transmission Owners Group 1, we clarify
that the Order No. 1000 interregional cost allocation requirements are
not intended to alter the section 205 rights of transmission owners and
RTOs.
    637. In response to Transmission Dependent Utility Systems, we
clarify that all interested parties, including transmission customer
load-serving entities, must have the opportunity to participate in the
process of developing the interregional cost allocation method or
methods. As the Commission stated in Order No. 1000, in developing
appropriate cost allocation methods for their regional and
interregional transmission facilities, public utility transmission
providers must consult with stakeholders.\756\ The Commission also
stated that stakeholder input in the development of a cost allocation
method or methods should ensure that the method or methods ultimately
agreed upon is balanced and does not favor any

particular entity.\757\ Consistent with Order No. 890, the Commission
defined ``stakeholder'' in Order No. 1000 as including any party
interested in the regional transmission planning process.\758\ As such,
we view stakeholder participation, including that by load-serving
entities, as an important aspect of the development of compliance
filings to meet the requirements of Order No. 1000.
---------------------------------------------------------------------------

    \756\ Id. P 482.
    \757\ Id. P 671.
    \758\ Id. P 143.
---------------------------------------------------------------------------

D. Principles for Regional and Interregional Cost Allocation

1. Use of a Principles-Based Approach
    638. In Order No. 1000, the Commission required each public utility
transmission provider to show on compliance that its cost allocation
method or methods for regional cost allocation and its method or
methods for interregional cost allocation are just and reasonable and
not unduly discriminatory or preferential by demonstrating that each
method satisfies the six cost allocation principles.\759\ The
Commission took a principles-based approach because it recognized that
regional differences may warrant distinctions in cost allocation
methods among transmission planning regions. The Commission explained
that the six regional cost allocation principles apply to, and only to,
a cost allocation method or methods for new regional transmission
facilities selected in a regional transmission plan for purposes of
cost allocation.\760\ Likewise, the Commission stated that the six
analogous interregional cost allocation principles apply to, and only
to, a cost allocation method or methods for a new transmission facility
that is located in two neighboring transmission planning regions and
accounted for in the interregional transmission coordination procedure
in an OATT.\761\ Additionally, the Commission stated that the cost
allocation principles do not apply to other new transmission facilities
and therefore did not foreclose the opportunity for a developer or
individual customer to voluntarily assume the costs of a new
transmission facility.\762\
---------------------------------------------------------------------------

    \759\ Id. P 603.
    \760\ Id.
    \761\ Id.
    \762\ Id.
---------------------------------------------------------------------------

    639. The Commission declined to adopt a default regional or
interregional cost allocation method, but stated that in the event of a
failure to reach an agreement on a cost allocation method or methods,
it would use the record in the relevant compliance filing proceeding as
a basis to develop a cost allocation method or methods that meets its
proposed requirements.\763\
---------------------------------------------------------------------------

    \763\ Id. PP 607, 610.
---------------------------------------------------------------------------

a. Arguments That Principles-Based Cost Allocation Methods Are Unfair
and Arguments Related to Commission Determination of Cost Allocation
Method Pursuant to the Compliance Process
    640. Illinois Commerce Commission argues that Order No. 1000
appears to require transmission providers to be responsible for
estimating project benefits, which effectively delegates the
Commission's authority over rates and to define what constitutes
benefits. It maintains that delegating this authority to the
transmission provider and the stakeholder process does not ensure that
planning criteria and cost allocation methods based on benefits will be
just and reasonable.
    641. Illinois Commerce Commission asserts that the stakeholder
process may neglect the interests of some load-serving entities that
will bear the costs of transmission investment when the interests of
those load-serving entities are not aligned or directly conflicts with
the majority of load-serving entities and other stakeholders within the
region. It cites Illinois Commerce Commission as an example of an
outcome where the majority of stakeholders agreed to spread costs in
eastern PJM to utilities in western PJM, and the Commission deferred to
this ``regional consensus'' while acknowledging there was none.
Illinois Commerce Commission states that the Seventh Circuit disagreed
and found that one group of utilities' desire to be subsidized by
another is no reason in itself for giving them their way.
    642. Illinois Commerce Commission further argues that delegating
the Commission's obligation to ensure just and reasonable rates to a
stakeholder process violates section 205 due process rights of
interested parties because it imposes an undue burden on parties to
participate in a new and costly process without providing the funding
to participate. It contends that the process will lack a public
administrative record, making it difficult for interested parties who
would have otherwise intervened in a normal administrative process to
follow the proceeding. Illinois Commerce Commission states that the
right of parties to bring a section 206 complaint is an inadequate
remedy in light of these issues.
    643. Several petitioners seek rehearing of the Commission's
statement that if an agreement on a cost allocation method is not
reached, it will use the record to develop a method or methods for the
region, arguing that the Commission does not have the authority to do
so.\764\ Florida PSC argues that this provision encroaches on Florida's
jurisdiction because the Commission does not have authority to assign
cost recovery to retail customers.\765\ Kentucky PSC also argues that
the due process requirements of the state integrated resource planning
and certificate of public convenience and necessity processes is being
replaced by majoritarian processes backed by the threat that the
Commission will determine cost allocation processes if the regional
group cannot.
---------------------------------------------------------------------------

    \764\ See, e.g., Georgia PSC; Illinois Commerce Commission; and
Florida PSC.
    \765\ Florida PSC at 7 (citing Order No. 1000, FERC Stats. &
Regs. ] 31,323 at P 607).
---------------------------------------------------------------------------

    644. Illinois Commerce Commission argues that Order No. 1000
implies that if there is consensus, the Commission will accept that
compliance filing. Illinois Commerce Commission seeks rehearing of the
meaning of ``consensus'' if it means here something different from
``agreement.'' \766\ It argues that the term is insufficient to protect
those who may be harmed by a majority. Additionally, Illinois Commerce
Commission argues that requiring a consensus means that minority
interests will always lose, which is unduly discriminatory on its face,
and forcing minority interests to bring a section 206 complaint is
insufficient to protect their interests and overly burdensome.
---------------------------------------------------------------------------

    \766\ Illinois Commerce Commission at 35.
---------------------------------------------------------------------------

    645. New York Transmission Owners seek clarification that the
Commission will impose a cost allocation method on transmission
planning regions only as a last resort after consensus has been
encouraged through mediation and other alternative dispute resolution
procedures.
    646. Transmission Dependent Utility Systems seek clarification, or
in the alternative rehearing, that compliance filings must document the
opportunities for customer input in the development of regional and
interregional cost allocation methods as well as the basis relied upon
for disregarding any such input. They argue that this information is
necessary to gauge the inclusiveness and transparency of the processes
for developing cost allocation methods.
i. Commission Determination
    647. We affirm the Commission's decision that the appropriate
approach is for public utility transmission providers to develop
regional and interregional cost allocation methods based on the six
cost allocation

principles described in Order No. 1000, thereby allowing public utility
transmission providers the flexibility to develop cost allocation
methods that best suit regional needs. The Commission disagrees that
Order No. 1000 is delegating the Commission's authority over rates to
define what constitutes benefits. The proper context for further
consideration of ``benefits'' and ``beneficiaries'' is in the
Commission's review of compliance proposals and a record before the
Commission.\767\ As the Commission explained in Order No. 1000, the
cost allocation principles do not prescribe a uniform approach, but
provide the public utility transmission providers in consultation with
the stakeholders in each region the opportunity to first develop their
own method or methods, and recognized that regional differences may
warrant distinctions in cost allocation methods.\768\ It would be
inconsistent with the regional flexibility provided in Order No. 1000
for the Commission to prescribe a uniform approach to determining
benefits or beneficiaries when a multitude of factors vary across
transmission planning regions and the entire country.
---------------------------------------------------------------------------

    \767\ Id. P 624.
    \768\ Id.
---------------------------------------------------------------------------

    648. In response to concerns that a stakeholder process is an
inappropriate way to allocate costs, we note that the Commission has
previously found, and the D.C. Circuit has affirmed, that a stakeholder
process is appropriate when unresolved issues may be better addressed
in a forum featuring broad stakeholder input, and where a transmission
solution can be better tailored to meet regional transmission needs
through broad input from interested participants that may not otherwise
participate in a Commission proceeding.\769\ The public utility
transmission providers and stakeholders that make up the region are
intimately familiar with the transmission needs of their region.
Therefore, they are in the best position to develop, and submit to the
Commission for review, a cost allocation method or methods that
complies with the six cost allocation principles and best meets the
transmission planning region's needs. This does not amount to a
delegation of Commission authority because the Commission ultimately
will determine whether the method or methods are just and reasonable
and interested parties will continue to have an opportunity to support
or oppose the cost allocation methods proposed in the compliance
filings at the Commission.\770\
---------------------------------------------------------------------------

    \769\ Braintree Elec. Light Dept. v. ISO New England, Inc., 128
FERC ] 61,008 (2009) (citing MISO, 125 FERC ] 61,038, at P 19
(2008); Pepco Energy Servs. v. PJM Interconnection, L.L.C., 124 FERC
] 61,008, at P 24 (2008); PSC of Wis. v. FERC, 545 F.3d 1058, 1063
(D.C. Cir. 2008)).
    \770\ PSC of Wis. v. FERC, 545 F.3d at 1064.
---------------------------------------------------------------------------

    649. It also does not interfere with section 205 rights or
otherwise impose an undue burden on parties to participate in new and
costly processes. The transmission planning and cost allocation
processes in Order No. 1000 are not entirely new, but rather build on
the reforms to the processes already required by Order No. 890, in
which all interested parties should already be participating. In any
event, with regard to state regulators, such as Illinois Commerce
Commission, we have already explained above that, consistent with Order
Nos. 1000 and 890, they may request that the public utility
transmission providers in their region propose a mechanism in their
compliance filings providing for state regulators to recoup the costs
of their participation in the regional transmission planning
process.\771\ In addition, interested parties retained their section
206 rights to file a complaint if they have concerns about the process
or the method or methods proposed. Illinois Commerce Commission has not
provided a reason that section 206 would not be an appropriate remedy
and not identified specific facts to illustrate a scenario where it
would not be able to obtain an adequate remedy under section 206.
---------------------------------------------------------------------------

    \771\ See discussion supra at section 0. (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 162 and quoting Order No. 890,
FERC Stats. & Regs. ] 31,241 at P 574 n.339 and P 586)).
---------------------------------------------------------------------------

    650. We also affirm the Commission's decision in Order No. 1000
that, in the event of a failure to reach an agreement on a cost
allocation method or methods, the Commission will use the record in the
relevant compliance filing proceeding as a basis to develop a cost
allocation method or methods that meets Order No. 1000's cost
allocation principles.\772\ This provision does not infringe upon state
jurisdiction, as suggested by the Florida and Kentucky PSCs, because,
as discussed above, states retain whatever jurisdiction they have over
retail rates.
---------------------------------------------------------------------------

    \772\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 607.
---------------------------------------------------------------------------

    651. In response to Illinois Commerce Commission's argument
regarding whether a ``consensus'' of stakeholders is synonymous with
``agreement,'' and if so, that such an approach would allow the
majority to override minority interests when making compliance filings,
we reiterate our finding in Order No. 1000 that ``the Commission will
consider in response to compliance filings all issues raised by
commenters, such as what constitutes an impasse, [and] whether there
should be deference to the majority * * *.'' \773\ Accordingly, we
decline to speculate in advance of these compliance filings the extent
to which the Commission would give weight to the majority of public
utility transmission providers and stakeholders in a region.
---------------------------------------------------------------------------

    \773\ Id. P 609.
---------------------------------------------------------------------------

    652. In response to New York Transmission Owners, we reiterate that
the Commission will use the record in the relevant compliance filings
as a basis to develop a cost allocation method or methods for a
transmission planning region when the transmission planning region
fails to reach an agreement. To this end, we note that in response to a
directive to do so in Order No. 1000,\774\ the Commission's staff has
been made available to assist public utility transmission providers and
stakeholders in the various regions around the country in reaching an
agreement on a compliance filing. The Commission also noted in Order
No. 1000 that the procedural mechanisms used by it in response to
compliance filings will depend on the nature of remaining disputes and
what issues are still at stake that are preventing the public utility
transmission providers in each transmission planning region or pair of
transmission planning regions from reaching a consensus.\775\
Accordingly, in advance of such compliance filings, we decline to
specifically endorse any particular procedural method for resolving
cost allocation disputes brought forward in compliance filings;
mediation or other alternative dispute resolution procedures, as
suggested by New York Transmission Owners are certainly viable methods
to encourage consensus and will be considered if necessary at the
appropriate time.
---------------------------------------------------------------------------

    \774\ Id. P 14.
    \775\ Id. P 609.
---------------------------------------------------------------------------

    653. In response to Transmission Dependent Utility Systems' request
that compliance filings must document the opportunities for customer
input provided, as well as the basis relied upon for disregarding any
such customer input, we do not believe any clarification of Order No.
1000 is necessary. Order No. 1000 already provides that ``[p]ublic
utility transmission providers must document in their compliance
filings the steps they have taken to reach consensus on a cost
allocation method or set of methods to comply with this Final Rule, as
thoroughly as practicable, and provide whatever information they view

as necessary for the Commission to make a determination of the
appropriate cost allocation method or methods.'' \776\
---------------------------------------------------------------------------

    \776\ Id. P 607.
---------------------------------------------------------------------------

2. Cost Allocation Principle 1--Costs Allocated in a Way That Is
Roughly Commensurate With Benefits
    654. In Order No. 1000, the Commission adopted the following Cost
Allocation Principle 1 for both regional and interregional cost
allocation:

Regional Cost Allocation Principle 1: The cost of transmission
facilities must be allocated to those within the transmission
planning region that benefit from those facilities in a manner that
is at least roughly commensurate with estimated benefits. In
determining the beneficiaries of transmission facilities, a regional
transmission planning process may consider benefits including, but
not limited to, the extent to which transmission facilities,
individually or in the aggregate, provide for maintaining
reliability and sharing reserves, production cost savings and
congestion relief, and/or meeting Public Policy Requirements.

and

Interregional Cost Allocation Principle 1: The costs of a new
interregional transmission facility must be allocated to each
transmission planning region in which that transmission facility is
located in a manner that is at least roughly commensurate with the
estimated benefits of that transmission facility in each of the
transmission planning regions. In determining the beneficiaries of
interregional transmission facilities, transmission planning regions
may consider benefits including, but not limited to, those
associated with maintaining reliability and sharing reserves,
production cost savings and congestion relief, and meeting Public
Policy Requirements.\777\
---------------------------------------------------------------------------

    \777\ Id. P 622.

    655. However, the Commission stated that it was not prescribing a
particular definition of ``benefits'' or ``beneficiaries'' in Order No.
1000.\778\ In the Commission's view, the proper context for
consideration of these matters is in the regional stakeholder meetings
in the first instance, followed by Commission consideration of these
matters on review of compliance proposals and the record before the
Commission.\779\
---------------------------------------------------------------------------

    \778\ Id. P 624.
    \779\ Id.
---------------------------------------------------------------------------

    656. The Commission also stated that if a non-public utility
transmission provider makes the choice to become part of the
transmission planning region and it is determined by the transmission
planning process to be a beneficiary of certain transmission facilities
selected in the regional transmission plan for purposes of cost
allocation, that non-public utility transmission provider is
responsible for the costs associated with such benefits.\780\
---------------------------------------------------------------------------

    \780\ Id. P 629.
---------------------------------------------------------------------------

    657. Additionally, in Order No. 1000, the Commission found that
issues related to the generator interconnection process and to
interconnection cost recovery were outside the scope of the rulemaking
proceeding.\781\ The Commission stated that Order No. 2003 \782\ sets
forth the procedures for the interconnection of a large generating
transmission facility to the bulk power system.\783\ Additionally, the
Commission emphasized that Order No. 1000 did not set forth any new
requirements with respect to such procedures for interconnecting large,
small, or wind or other generation facilities.\784\ Therefore, the
Commission determined that Order No. 1000 was not the proper proceeding
for commenters to raise issues about the interconnection agreements and
procedures under Order Nos. 2003, 2006 \785\ or 661.\786\
---------------------------------------------------------------------------

    \781\ Id. P 760.
    \782\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146,
order on reh'g, Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, 70 FR 265, FERC Stats. &
Regs. ] 31,171, order on reh'g, Order No. 2003-C, 70 FR 37661, FERC
Stats. & Regs. ] 31,190, aff'd sub nom. Nat'l Ass'n of Regulatory
Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied,
552 U.S. 1230 (2008).
    \783\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 760.
    \784\ Id.
    \785\ Order No. 2006, 70 FR 34189, FERC Stats. & Regs. ] 31,180,
order on reh'g, Order No. 2006-A, 70 FR 71760, FERC Stats. & Regs. ]
31,196, order granting clarification, Order No. 2006-B, 71 FR 42587,
FERC Stats. & Regs. ] 31,221.
    \786\ Order No. 661, 70 FR 34993 (Jun. 16, 2005), FERC Stats. &
Regs. ] 31,186, order on reh'g, Order No. 661-A, FERC Stats. & Regs.
] 31,198.
---------------------------------------------------------------------------

a. Requests for Rehearing or Clarification
    658. Several petitioners seek rehearing or clarification regarding
the lack of a definition of ``benefits'' in Order No. 1000. Illinois
Commerce Commission argues that by failing to establish definitions and
standards for transmission providers to implement in identifying
project benefits, the Commission has placed transmission providers in
conflict with majority desires in the stakeholder process because an
RTO is obligated to act in the interests of its transmission owning
members. It argues that RTO behavior has been more accommodating to
transmission owning utilities than captive ratepayers, and this issue
will be exacerbated with less Commission oversight.
    659. Arizona Cooperative and Southwest Transmission also argue that
there is insufficient Commission oversight of the definition and
measurement of benefits. It argues that ``benefits'' can, within the
context of a network, become so pliable as to become meaningless,
especially as applied to individual situations. Arizona Cooperative and
Southwest Transmission add that different outcomes are apt to flow from
how benefits are defined. Public utilities may value needs and
interests differently from other stakeholders, and customers and
entities will not all have the same needs and interests. Arizona
Cooperative and Southwest Transmission are concerned that it may be
deemed to receive benefits that have little or nothing to do with its
needs.
    660. Georgia PSC and Florida PSC seek clarification of the
definition of benefits and what constitutes too narrow or too broad a
definition. Florida PSC asserts that leaving this question to the
stakeholder and subsequent compliance process creates the possibility
that regions will adopt a definition of benefits that does not meet
whatever undefined standard the Commission may have in mind. It argues
that this approach limits regional autonomy in an undefined way, even
though the Commission states that regions are free to determine their
own definitions of benefits.
    661. Georgia PSC and Florida PSC also seek clarification of what
benefits must be quantifiable and based on existing policies in state
and federal law. Florida PSC argues that ambiguities on this issue and
what constitutes too broad or narrow a definition of benefits violate
the Due Process Clause ``fair notice'' requirement.\787\
---------------------------------------------------------------------------

    \787\ Florida PSC at 8 (citing Trinity Broadcasting of Fla.,
Inc. v. FCC, 211 F.3d 618, 628 (D.C. Cir. 2000)).
---------------------------------------------------------------------------

    662. Other petitioners argue that the definitions of ``benefits''
and ``beneficiary'' were left too broad.\788\ Kentucky PSC argues that
the Commission erred in failing to define ``cost causer'' and
``beneficiary.'' \789\ It asserts that recently there has been
considerable dispute over the meaning of cost causer and when an entity
becomes a beneficiary of a new or expanded facility developed by
others. Kentucky PSC is concerned that there is no requirement that
cost allocation processes account for proximity to a project, which it
asserts is directly related a project's actual benefits in terms of
improving reliability, reducing congestion, and opening markets. It
contends that it appears that a project may be eligible for cost
allocation solely

due to its ability to meet the public policy requirements of state or
federal governments.\790\ Kentucky PSC explains that there is no
requirement that a state have a need for a project, which will result
in ratepayers paying for projects that may not be located within their
state and that are designed to meet other states' public policy
requirements. It maintains that to exempt a state's ratepayers from
cost allocation only if they will not benefit at present or in a
``future scenario'' appears to enable the majority in a regional
planning entity to decide that a particular state's legislature will,
or should, ultimately enact certain public policies or that the federal
government will do so.
---------------------------------------------------------------------------

    \788\ See, e.g., Coalition for Fair Transmission Policy; and
PSEG Companies.
    \789\ Kentucky PSC at 5.
    \790\ Kentucky PSC at 6 (quoting Order No. 1000, FERC Stats. &
Regs. ] 31,323 at P 585).
---------------------------------------------------------------------------

    663. Likewise, Coalition for Fair Transmission Policy argues that
not limiting the definition of ``benefits'' and ``beneficiary'' will
lead to uncertainty and dispute.\791\ It states that a beneficiary-pays
approach is appropriate for certain types of projects, such as projects
driven by reliability compliance obligations, because the relationship
between specific transmission projects, reliability impacts, and the
benefits of reliability are well established and capable of examination
within a framework of existing transmission planning horizons and study
methodologies. However, Coalition for Fair Transmission Policy asserts
that it is difficult to define benefits and beneficiaries in a way that
is just and reasonable and objectively verifiable for projects such as
upgrades driven by economics and/or public policy requirements.
---------------------------------------------------------------------------

    \791\ Coalition for Fair Transmission Policy at 8.
---------------------------------------------------------------------------

    664. According to Coalition for Fair Transmission Policy, failure
to define potential benefits correctly on compliance will have adverse
economic and policy impacts. For instance, it maintains that if
benefits are defined to include broad societal benefits of building
renewables in a certain area, and that definition is used to justify
cost socialization of transmission projects to that area, the generator
or customer will not face the true costs of their resource decisions.
Buyers may decide to buy from remote renewable resources that require
long-distance transmission, rather than potentially lower cost local
renewable resources, because they do not have to pay the full
transmission costs. According to Coalition for Fair Transmission
Policy, competitive wholesale markets using locational-marginal pricing
would at that point begin to see price signals break down and become
inefficient. It also argues that siting may become more difficult
because those required to pay for lines they do not see benefit from
will litigate both the cost and siting-approval processes.
    665. Coalition for Fair Transmission Policy urges the Commission to
limit regions to considering only benefits that: (1) Occur within the
typical transmission planning horizon of the public utilities within
the region that can be measured or projected through the kinds of
transmission planning studies that are normally conducted; (2) are not
speculative; and (3) are not based on ``societal'' benefits that are
not embodied in existing federal and state public policy
requirements.\792\ It also argues that the Commission should clarify
that regional transmission planning may not adopt presumptions that
broad categorizations of types or classes of transmission lines driven
by economic or public policy requirements have broad benefits and
should be allocated widely. Also, Coalition for Fair Transmission
Policy and North Carolina Agencies argue that the Commission should
require that those seeking cost allocations for individual transmission
projects be able to demonstrate quantifiable, observable and tangible
reliability and economic benefits with reasonable particularity that is
tied directly to those who will be required to pay under a cost
allocation methodology. North Carolina Agencies argue that both the FPA
and Commission precedent require the allocation of costs in proportion
to the real reliability and economic benefits resulting from a
transmission investment that can be measured or projected within the
planning horizon.
---------------------------------------------------------------------------

    \792\ Coalition for Fair Transmission Policy at 13.
---------------------------------------------------------------------------

    666. In addition, Coalition for Fair Transmission Policy argues
that the Commission should revise its cost allocation principles to
assure that benefits are defined in way that conforms with what it
asserts are established cost-causation standards, which include, among
other things, tying cost allocation to the taking of transmission
service.\793\
---------------------------------------------------------------------------

    \793\ Coalition for Fair Transmission Policy at 15-16 (citing
Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361, 1369 (D.C.
Cir. 2004); citing Illinois Commerce Commission v. FERC, 576 F.3d at
474-77; citing Pacific Gas & Electric Co. v. FERC, 373 F.3d 1315,
1321 (D.C. Cir. 2004); quoting Algonquin Gas Transmission Co. v.
FERC, 948 F.2d 1305, 1312-14 (D.C. Cir. 1991)).
---------------------------------------------------------------------------

    667. Coalition for Fair Transmission Policy maintains that while
Order No. 1000 states that the Commission will fill in the gaps that it
left in Order No. 1000 through the process of accepting or rejecting or
requiring modification of proposed definitions, the courts have
rejected this approach as contrary to law, arbitrary and
capricious.\794\ Coalition for Fair Transmission Policy asserts that
the Commission must supply sufficient explanation to provide a
reasonable benchmark and guidance in the development of compliance
filings. Coalition for Fair Transmission Policy asserts that the lack
of additional guidance creates a risk of stalemate at the regional
level and a likelihood that the Commission ultimately would have to
define the terms for a region. It argues that this would essentially
penalize public utility transmission providers because the process is
designed to fail and then be saved by the Commission.
---------------------------------------------------------------------------

    \794\ Coalition for Fair Transmission Policy at 14 (citing
Appalachian Power Co. v. EPA, 208 F.3d 1015, 1020 (D.C. Cir. 2000)).
---------------------------------------------------------------------------

    668. Illinois Commerce Commission argues that there is no way to
identify ``more efficient or cost effective'' transmission projects in
the planning process without a meaningful estimation of benefits, and
there is no way to assess whether a transmission provider has complied
with the Commission's directive that costs be allocated at least
roughly commensurate with benefits unless the level of benefits
expected to be provided by a project to each load-serving entity have
been determined.\795\ It adds that if the Commission's requirements are
not clear, there will be no basis to make compliance findings or to
detect planning and cost allocation abuses.
---------------------------------------------------------------------------

    \795\ Illinois Commerce Commission at 10.
---------------------------------------------------------------------------

    669. Illinois Commerce Commission and MISO Northeast seek
clarification that generators are subject to regional cost allocation.
Illinois Commerce Commission requests clarification that costs can be
recovered when the planning itself is undertaken to accommodate the
interconnection of particular generators. It notes that Order No. 1000
ruled out participant funding as an acceptable regional or
interregional cost allocation method, but Illinois Commerce Commission
states that participant funding has applied to generation developers
that agree to fund transmission network upgrades to enable their
generator to be interconnected to the network. Illinois Commerce
Commission requests clarification that Order No. 1000 does not prohibit
transmission providers from finding generators to be cost causers or
beneficiaries of new transmission facilities developed pursuant to the
regional or interregional planning process and allocating costs to
those generators accordingly. MISO Northeast likewise requests that the

Commission clarify that any regionwide cost allocation method adopted
pursuant to Order No. 1000 must allocate costs to generators and end-
users commensurate with the share of public policy benefits that they
receive.
    670. In contrast, NextEra argues that generators should not be
responsible for costs not specified in interconnection agreements. It
explains that Order No. 2003 recognized that generators must be able to
identify all risks prior to entering into an interconnection agreement
and commencing construction when it concluded that interconnection
customers should only be responsible for costs specifically identified
in their interconnection agreements.\796\ It argues that it follows
that generators should not be responsible for costs not identified in
their interconnection agreements, and asserts that if costs could be so
allocated, it would make the cost of project financing prohibitive
because lenders would likely seek protection for such contingencies.
NextEra thus urges the Commission to clarify that generators and other
tie line owners will not be responsible for costs not specified in
their interconnection agreements, which it argues is consistent with
Order No. 1000's conclusion that costs cannot be involuntarily
allocated to non-beneficiaries. Otherwise, NextEra argues, such
unknowable and unworkable cost allocation creates unjust and
unreasonable risks and would be inconsistent with Order No. 2003.
---------------------------------------------------------------------------

    \796\ NextEra at 18 (citing Order No. 2003, FERC Stats. & Regs.
] 31,146 at P 421).
---------------------------------------------------------------------------

    671. Illinois Commerce Commission also takes issue with the
requirement in Order No. 1000 that cost allocation methods consider the
benefits and costs of groups of new transmission facilities rather than
requiring that each project satisfy the Commission's principles and
requirements on its own merits. It argues that a portfolio approach to
transmission planning allows the approval of projects that, when
considered individually, are not cost beneficial.
    672. Illinois Commerce Commission states that if individual
projects are cost beneficial, and in the aggregate their estimated
benefits are roughly commensurate with a postage stamp allocation, then
an allocation according to the benefits of each project individually
would result in an allocation roughly equivalent with a postage stamp
allocation. It argues that this scenario would render the postage stamp
allocation unnecessary. Therefore, Illinois Commerce Commission argues
that the Commission erred by including the word ``aggregate'' in
Principle 1 because it allows transmission providers to avoid
demonstrating that each individual project is cost beneficial. It also
argues that the Commission violated the FPA and case precedent in
failing to remove postage stamp rates as a possible cost allocation
method. Specifically, it maintains that it is incorrect to conclude
that even when ``all customers within a transmission planning region
are found to benefit from the use or availability of a transmission
facility or class or group of transmission facilities,'' they all
benefit roughly equally.\797\ Illinois Commerce Commission also points
to the Seventh Circuit's statement that an assertion of generalized
system benefits is not sufficient to justify a cost allocation and that
alleged benefits, without specific evidentiary support, are too
speculative to be considered.
---------------------------------------------------------------------------

    \797\ Illinois Commerce Commission at 16.
---------------------------------------------------------------------------

    673. Finally, ELCON, AF&PA, and the Associated Industrial Groups
argue that use of a postage stamp rate for cost allocation at the
regional or interregional level is a form of cost socialization, and it
is therefore inconsistent with the cost causation principle. They also
maintain that the statement by the court in Illinois Commerce
Commission that benefits be at least roughly commensurate with costs
requires one to conclude that a postage stamp rate is an impermissible
form of cost causation.
i. Commission Determination
    674. We affirm Order No. 1000 and therefore deny those arguments
requesting us to prescribe a particular definition of ``benefits'' or
``beneficiaries.'' As the Commission found in Order No. 1000, the
proper context for further consideration of these matters is on review
of compliance proposals and a record before us. Many of the petitioners
here essentially expound on concerns they raised in the rulemaking
proceeding that more specificity in Order No. 1000 itself is required
because an overly broad or overly narrow definition of beneficiary or
beneficiaries could lead to cost allocations that do not correspond to
cost causation. However, as stated in Order No. 1000, we believe that
concerns regarding overly narrow or broad interpretations of benefits
will be addressed in the first instance during the process of public
utility transmission providers consulting with their stakeholders as
part of the development of a compliance filing. If such interpretations
should emerge, we can more effectively ensure that the term is not
given too narrow or broad a meaning by considering a specific proposal
and a record than by attempting to anticipate and rule on all
possibilities before the fact. This point applies equally to those
petitioners that note the potential difficulties in quantifying
benefits.\798\ For this reason, we decline to adopt any of the many
suggestions offered by petitioners in their requests for rehearing and
clarification, including those who argue that only certain benefits,
such as reliability benefits, should be considered, because determining
other types of benefits is difficult or speculative.
---------------------------------------------------------------------------

    \798\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 624-25.
---------------------------------------------------------------------------

    675. In response to Illinois Commerce Commission's concern that by
not providing a definition of ``benefits'' in Order No. 1000 the
Commission would exacerbate an RTO's ability to favor its transmission
owning members to the detriment of other stakeholders, we first note
that we do not accept the premise that RTOs as a rule engage in such
behavior. In any event, when each public utility transmission provider,
including an RTO, proposes its cost allocation method or methods, the
Commission will review the method or methods, including how benefits
and beneficiaries are defined, to determine whether it complies with
the requirements of Order No. 1000. This review will include an
analysis of whether the cost allocation method or methods comply with
Principle 1, which requires that the cost allocation method or method
result in an allocation of costs roughly commensurate with benefits. If
the compliance filing is unclear on these matters or if parties take
issue with aspects of the compliance filing, such as the definition of
benefits, the Commission will address those issues at that time.
    676. We also disagree with petitioners, such as Georgia PSC and
Florida PSC, who assert that by not defining benefits the Commission is
limiting regional autonomy. By permitting public utility transmission
providers in a region to define benefits collectively together with
regional stakeholders, the Commission is enabling them to account for
regional differences rather than prescribing a one-size-fits-all method
that might not do so as effectively. We also decline to grant the
requests of Georgia PSC and Florida PSC for clarification of what
benefits must be quantifiable based on

existing policies in state and federal law. Consistent with the
discussion above, we believe that this is a matter that is best
addressed in the first instance by the public utility transmission
providers and their stakeholders in the development of the cost
allocation methods for their regions. Furthermore, Florida PSC's
argument that the fair notice requirement of the Due Process Clause
requires a definition of benefits is without merit, as Florida PSC and
all other stakeholders will have ample opportunity to participate in
both in the development of the cost allocation methods for their
regions, as well as in the Commission proceeding to review the
compliance filings that incorporate those cost allocation methods.
    677. Moreover, we note that, as applied by the courts, the Due
Process standard has been held to allow for flexibility in the wording
of an agency's rules and for a reasonable breadth in their
construction.\799\ In fact, the courts have recognized that ``by
requiring regulations to be too specific, [courts] would be opening up
large loopholes allowing conduct which should be regulated to escape
regulation.'' \800\ As the Supreme Court has noted, the degree of
vagueness tolerated by the Constitution depends in part on the nature
of the rules at issue.\801\ In the case of economic regulation, the
Supreme Court has found that the vagueness test must be applied in a
less strict manner because, among other things, ``the regulated
enterprise may have the ability to clarify the meaning of the
regulation by its own inquiry, or by resort to an administrative
process.'' \802\
---------------------------------------------------------------------------

    \799\ See Grayned v. City of Rockford, 408 U.S. 110 (1971)
(holding that an anti-noise ordinance was not vague where the words
of the ordinance ``are marked by flexibility and reasonable breadth,
rather than meticulous specificity.'').
    \800\ See Ray Evers Welding Co. v. OSHRC, 625 F.2d 726, 730 (6th
Cir. 1980).
    \801\ See Village of Hoffman Estates v. The Flipside, Hoffman
Estates, Inc., 455 U.S. 489 (1981).
    \802\ See id. at 498.
---------------------------------------------------------------------------

    678. We also note several petitioners' concerns that the
definitions of ``benefits,'' ``beneficiary,'' and ``cost causer,'' are
too broad, which they argue will lead to further disputes. As the
Commission stated in Order No. 1000, the Commission is allowing
flexibility to accommodate a variety of approaches which can better
advance the goals of Order No. 1000, recognizing that regional
differences may warrant distinctions in cost allocation method or
methods.\803\ This flexibility is provided so that public utility
transmission providers and their stakeholders can develop cost
allocation methods that best meet their region's needs. The Commission
established the Cost Allocation Principles to provide general guidance
to public utility transmission providers to limit uncertainty as they
develop their compliance filings. However, for those cost allocation
methods to be accepted by the Commission as Order No. 1000-compliant,
they will have to clearly and definitively specify the benefits and the
class of beneficiaries. Accordingly, we disagree with the premise of
some petitioners' arguments that there will be uncertainty once the
Commission accepts the cost allocation method or methods in exactly who
is a beneficiary and how such determinations are made. That is the very
purpose of requiring an ex ante cost allocation method: To be clear
upfront about who is benefitting so that disputes are minimized and so
that the transmission facilities selected in the regional transmission
plan for purposes of cost allocation are more likely to be constructed.
---------------------------------------------------------------------------

    \803\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 624.
---------------------------------------------------------------------------

    679. Additionally, we agree with Illinois Commerce Commission's
argument that there is no way to identify ``more efficient or cost
effective'' transmission solutions, or to assess whether costs are
being allocated at least roughly commensurate with benefits, without a
meaningful estimation of benefits. However, we do not believe that this
requires any change or clarification to Order No. 1000. As we explain
above, while Order No. 1000 does not define benefits and beneficiaries,
it does require the public utility transmission providers in each
region to be definite about benefits and beneficiaries for purposes of
their cost allocation methods. Once beneficiaries are identified,
public utility transmission providers would then be able to identify
what is the more efficient or cost effective transmission solution or
assess whether costs are being allocated at least roughly commensurate
with benefits.
    680. With respect to generators being identified as beneficiaries
and ultimately responsible for costs, we find that just as each
transmission planning region retains the flexibility to define benefit
and beneficiary, the public utility transmission providers in each
transmission planning region, in consultation with their stakeholders,
may consider proposals to allocate costs directly to generators as
beneficiaries that could be subject to regional or interregional cost
allocation. However, we emphasize that any effort to do so must not be
inconsistent with the generator interconnection process under Order No.
2003 \804\ because, as we stated in Order No. 1000, the generator
interconnection process and interconnection cost recovery are outside
the scope of this rulemaking. With this said, however, we are not
minimizing the importance of evaluating the impact of generation
interconnection requests during transmission planning, nor limiting the
ability of public utility transmission providers to take requests for
generator interconnections into account in developing assumptions to be
used in the transmission planning process.\805\ While we agree with
NextEra that interconnection costs would be specified in
interconnection agreements, we deny NextEra's request that the
Commission clarify those are the only transmission costs for which
generators could be responsible. The Commission determined in Order No.
2003 that interconnection service does not convey the right to flow
output of the interconnection customer's generating facility onto the
transmission provider's transmission system and does not constitute a
reservation of transmission capacity.\806\ Order No. 2003 states that
the interconnection customer, load or other market participant would
have to request either point-to-point or Network Integration
Transmission Service under the Transmission Provider's OATT in order to
receive the delivery service that is a prerequisite to flowing power
onto the system.\807\ As such, the interconnection customer could be
subject to charges associated with transmission service that are not
addressed in its interconnection agreement.
---------------------------------------------------------------------------

    \804\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146,
order on reh'g, Order No. 2003-A, 69 FR 15932, FERC Stats. & Regs. ]
31,160, order on reh'g, Order No. 2003-B, 70 FR 265, FERC Stats. &
Regs. ] 31,171, order on reh'g, Order No. 2003-C, 70 FR 37661, FERC
Stats. & Regs. ] 31,190, aff'd sub nom. Nat'l Ass'n of Regulatory
Util. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied,
552 U.S. 1230 (2008).
    \805\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 760.
    \806\ Order No. 2003, 68 FR 49846, FERC Stats. & Regs. ] 31,146
at P 767.
    \807\ Id.
---------------------------------------------------------------------------

    681. We affirm the Commission's finding in Order No. 1000 that in
determining the beneficiaries of transmission facilities, Regional Cost
Allocation Principle 1 should permit a regional transmission planning
process to ``consider benefits including, but not limited to, the
extent to which transmission facilities, individually or in the
aggregate, provide for maintaining reliability and sharing reserves,
production cost savings and congestion relief, and/or meeting Public
Policy

Requirements.'' \808\ Order No. 1000 was not intended to restrict
regional choice in the transmission planning and cost allocation
process as petitioners request.
---------------------------------------------------------------------------

    \808\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 622.
---------------------------------------------------------------------------

    682. Accordingly, we continue to believe that it is appropriate to
allow public utility transmission providers in a transmission planning
region to propose a cost allocation method that considers the benefits
and costs of a group of new transmission facilities, although they are
not required to do so.\809\ As such, we deny Illinois Commerce
Commission's arguments that ask us to decide in advance that such an
approach is inappropriate and at odds with cost causation. We reiterate
that if public utility transmission providers in a region in
consultation with their regional stakeholders choose to propose and
adequately support a cost allocation method or methods that considers
the benefits and costs of a group of new transmission facilities, Order
No. 1000 would not require a facility-by-facility showing, so long as
the aggregate cost of the transmission facilities in the group is
allocated roughly commensurate with aggregate benefits.\810\ Such an
approach could be reasonable if it, for instance, enables a
transmission planning region to prioritize its new transmission
facilities in such a way as to ensure benefits from the facilities and
maximize the number of system users who will share in those benefits.
---------------------------------------------------------------------------

    \809\ Id. P 627.
    \810\ Id. P 641.
---------------------------------------------------------------------------

    683. We also decline to forbid in advance the potential use of a
postage stamp cost allocation method. We continue to believe that a
postage stamp cost allocation method may be appropriate where all
customers within a specified transmission planning region are found to
benefit from the use or availability of a transmission facility or
class or group of transmission facilities, especially if the
distribution of benefits associated with a class or group of
transmission facilities is likely to vary considerably over the long
depreciation life of the transmission facilities amid changing power
flows, fuel prices, population patterns, and local economic
considerations.\811\ As such, we believe that public utility
transmission providers, if they choose to do so in consultation with
stakeholders, should be permitted to make the case in their compliance
filings that a postage stamp cost allocation is consistent with
Principle 1's requirement that all costs be allocated roughly
commensurate with benefits. To this end, we agree with Illinois
Commerce Commission that any such case would have to do more than make
a mere assertion of generalized system benefits. Last, we decline to
address Illinois Commerce Commission's arguments related to the MISO
MVP proceeding in Docket No. ER10-1791-000 as outside the scope of this
proceeding.
---------------------------------------------------------------------------

    \811\ Id. P 605.
---------------------------------------------------------------------------

3. Cost Allocation Principle 2--No Involuntary Allocation of Costs to
Non-Beneficiaries
a. Final Rule
    684. The Commission adopted the following Cost Allocation Principle
2 for both regional and interregional cost allocation:

    Regional Cost Allocation Principle 2: Those that receive no
benefit from transmission facilities, either at present or in a
likely future scenario, must not be involuntarily allocated any of
the costs of those transmission facilities.

and

    Interregional Cost Allocation Principle 2: A transmission
planning region that receives no benefit from an interregional
transmission facility that is located in that region, either at
present or in a likely future scenario, must not be involuntarily
allocated any of the costs of that transmission facility.\812\
---------------------------------------------------------------------------

    \812\ Id. P 637.

    685. The Commission also required that every cost allocation method
or methods provide for allocation of the entire prudently incurred cost
of a transmission project to prevent stranded costs.\813\
---------------------------------------------------------------------------

    \813\ Id. P 640.
---------------------------------------------------------------------------

b. Requests for Rehearing or Clarification
    686. PSEG Companies argue that Principle 2's ``likely future
scenarios'' language is problematic because it could easily result in
the expansion of the class of customers that are labeled beneficiaries
as more scenarios are introduced, thus making cost allocation
determinations more likely to be inexact and speculative.\814\ They
further state that Order No. 1000's statement that benefits must be
``identifiable'' does not cure the defect, particularly because Order
No. 1000 allows not only transmission providers to identify the
beneficiaries of proposed projects based on ``likely future
scenarios,'' but also allows them to develop such scenarios based on
potential public policy requirements.\815\ PSEG Companies argue that
allowing transmission providers to exercise unfettered discretion in
identifying beneficiaries under future scenarios will allow them to act
arbitrarily and capriciously, and that the expansive interpretations of
``benefits'' and ``beneficiaries'' would permit the allocation of costs
based on tenuous associations with benefits, contrary to Illinois
Commerce Commission.\816\
---------------------------------------------------------------------------

    \814\ PSEG Companies at 41-42.
    \815\ PSEG Companies at 42-43.
    \816\ PSEG Companies at 43-44. PSEG Companies also cite to
Transcontinental Gas Pipe Line Corp., 112 FERC ] 61,170 (2005),
where the Commission rejected reliance on a claim of generalized
system benefits as a basis for allocating gas pipeline upgrade costs
to existing shippers.
---------------------------------------------------------------------------

    687. ITC Companies seek clarification that a ``likely future
scenario'' that would justify an allocation of costs for new
transmission facilities includes the transmission planning scenarios
being used by a transmission provider to prepare a regional
transmission plan.\817\ ITC Companies state that one helpful
clarification would be to confirm that, if a project is shown to have
benefits for a zone or customer in one or more of the planning
scenarios generally used by the transmission provider to prepare a
regional transmission plan, those benefits satisfy Principle 2 and
support the allocation of costs to the beneficiaries.
---------------------------------------------------------------------------

    \817\ ITC Companies at 14.
---------------------------------------------------------------------------

    688. Long Island Power Authority seeks clarification that entities
not subject to a Public Policy Requirement will have an opportunity to
demonstrate this fact for purposes of cost allocation. Long Island
Power Authority acknowledges, however, that where an approved project
provides multiple benefits, it could be appropriate for an entity to be
allocated that portion of a project's costs that are unrelated to
fulfilling certain public policy goals, provided that the economic and
reliability related costs were allocated according to the economic and
reliability procedures of the region, or as agreed upon by neighboring
regions.
c. Commission Determination
    689. We affirm Order No. 1000's adoption of Regional and
Interregional Cost Allocation Principle 2. Accordingly, we deny PSEG
Companies' request for rehearing, which largely repeats arguments it
made in the rulemaking proceeding. The Commission disagreed with PSEG
Companies in Order No. 1000 that basing a determination of who
constitutes a ``beneficiary'' on ``likely future scenarios''
necessarily would result in inexact and speculative proposed
transmission plans and cost allocation methods.\818\ The Commission
explained that scenario analysis is a common feature of electric power

system planning, and that it believed that public utility transmission
providers are in the best position to apply it in a way that achieves
appropriate results in their respective transmission planning
regions.\819\ We disagree that the use of ``likely future scenarios''
and Public Policy Requirements will expand the class of customers who
will be identified as beneficiaries. The Commission stated in the
discussion on Cost Allocation Principle 1 above that the identification
of beneficiaries is based on the principle of cost causation.
Accordingly, the scenario analysis is not unfettered. It is limited to
scenarios in which a beneficiary is identified as such on the basis of
the cost causation principle.
---------------------------------------------------------------------------

    \818\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 626.
    \819\ Id.
---------------------------------------------------------------------------

    690. In response to ITC Companies, we therefore clarify that public
utility transmission providers may rely on scenario analyses in the
preparation of a regional transmission plan and the selection of new
transmission facilities for cost allocation. If a project or group of
projects is shown to have benefits in one or more of the transmission
planning scenarios identified by public utility transmission providers
in their Commission-approved Order No. 1000-compliant cost allocation
methods, Principle 2 would be satisfied.
    691. In response to Long Island Power Authority's request that the
Commission clarify that entities have the opportunity to demonstrate
that a transmission project proposed to meet a given Public Policy
Requirement is not applicable to them and provides no benefit to them,
we affirm the Commission's statement in Order No. 1000 that
consideration of regional transmission needs driven by Public Policy
Requirements must follow the cost allocation principles. For instance,
Cost Allocation Principle 1 makes clear that Long Island Power
Authority will be allocated only costs that are roughly commensurate
with the benefits it receives from a transmission facility or
facilities. Additionally, Cost Allocation Principle 2 states that those
that receive no benefit from new transmission facilities, either at
present or in a likely future scenario, must not be involuntarily
allocated any of the costs of those transmission facilities.\820\ Given
this, if it is true that Long Island Power Authority would not benefit
from a transmission project or group of projects designed to meet a
regional transmission need driven by a Public Policy Requirement, the
transmission planning region's cost allocation method or methods would
not be permitted to allocate any costs to it. As Long Island Power
Authority acknowledges, even if it does not need the transmission
facility to meet a Public Policy Requirement of its own, it
nevertheless may receive other economic or reliability benefits from a
proposed transmission facility and then the cost allocation method may
allocate the costs for the economic or reliability benefits received.
---------------------------------------------------------------------------

    \820\ Id. P 219.
---------------------------------------------------------------------------

4. Cost Allocation Principle 3--Benefit to Cost Threshold Ratio
a. Final Rule
    692. The Commission adopted the following Cost Allocation Principle
3 for both regional and interregional cost allocation:

    Regional Cost Allocation Principle 3: If a benefit to cost
threshold is used to determine which transmission facilities have
sufficient net benefits to be selected in a regional transmission
plan for the purpose of cost allocation, it must not be so high that
transmission facilities with significant positive net benefits are
excluded from cost allocation. A public utility transmission
provider in a transmission planning region may choose to use such a
threshold to account for uncertainty in the calculation of benefits
and costs. If adopted, such a threshold may not include a ratio of
benefits to costs that exceeds 1.25 unless the transmission planning
region or public utility transmission provider justifies and the
Commission approves a higher ratio.

and

    Interregional Cost Allocation Principle 3: If a benefit-cost
threshold ratio is used to determine whether an interregional
transmission facility has sufficient net benefits to qualify for
interregional cost allocation, this ratio must not be so large as to
exclude a transmission facility with significant positive net
benefits from cost allocation. The public utility transmission
providers located in the neighboring transmission planning regions
may choose to use such a threshold to account for uncertainty in the
calculation of benefits and costs. If adopted, such a threshold may
not include a ratio of benefits to costs that exceeds 1.25 unless
the pair of regions justifies and the Commission approves a higher
ratio.\821\
---------------------------------------------------------------------------

    \821\ Id. P 646.

    693. The Commission stated that Cost Allocation Principle 3 did not
require the use of a benefit to cost ratio threshold.\822\ However, if
a transmission planning region chooses to have such a threshold, the
principle limited the threshold to one that is not so high as to block
inclusion of many worthwhile transmission projects in the regional
transmission plan.\823\ Further, it allowed public utility providers in
a transmission planning region to use a lower ratio without a separate
showing and to use a higher threshold if they justify it and the
Commission approves a greater ratio.\824\
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    \822\ Id. P 647.
    \823\ Id.
    \824\ Id.
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b. Request for Rehearing or Clarification
    694. Transmission Dependent Utility Systems seek clarification, or
in the alternative rehearing, that stakeholders will have access to the
data necessary to replicate any benefit-to-cost analysis that public
utility transmission providers conduct pursuant to Cost Allocation
Principle 3. They state that the Commission did not respond in Order
No. 1000 to their argument that Cost Allocation Principle 3 be modified
to ensure that implementation of any cost benefit analysis is
transparent to load serving entity transmission customers.
c. Commission Determination
    695. We find that it is not necessary to modify Cost Allocation
Principle 3 to require transparency in the implementation of the
benefit to cost analysis because this requirement already exists in
Cost Allocation Principle 5. The language in Regional Cost Allocation
Principle 5 and Interregional Cost Allocation Principle 5 states that
``[t]he cost allocation method and data requirements for determining
benefits and identifying beneficiaries * * * must be transparent with
adequate documentation to allow a stakeholder to determine how they
were applied.'' \825\ Accordingly, we believe that it is clear that the
transparency requirement in Cost Allocation Principle 5 applies to any
benefit to cost analysis subject to Cost Allocation Principle 3, such
that all data relating to the benefit to cost ratio must be
transparent. Additionally, the Order No. 890 transparency principle
requires ``transmission providers to disclose to all customers and
other stakeholders the basic criteria, assumptions, and data that
underlie their transmission system plans.'' \826\
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    \825\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 668.
    \826\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 471.
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5. Cost Allocation Principle 4--Allocation To Be Solely Within
Transmission Planning Region(s) Unless Those Outside Voluntarily Assume
Costs
a. Final Rule
    696. The Commission adopted the following Cost Allocation Principle
4 for both regional and interregional cost allocation:

    Regional Cost Allocation Principle 4: The allocation method for
the cost of a transmission facility selected in a regional
transmission plan must allocate costs solely within that
transmission planning region unless another entity outside the
region or another transmission planning region voluntarily agrees to
assume a portion of those costs. However, the transmission planning
process in the original region must identify consequences for other
transmission planning regions, such as upgrades that may be required
in another region and, if the original region agrees to bear costs
associated with such upgrades, then the original region's cost
allocation method or methods must include provisions for allocating
the costs of the upgrades among the beneficiaries in the original
region.

and

    Interregional Cost Allocation Principle 4: Costs allocated for
an interregional transmission facility must be assigned only to
transmission planning regions in which the transmission facility is
located. Costs cannot be assigned involuntarily under this rule to a
transmission planning region in which that transmission facility is
not located. However, interregional coordination must identify
consequences for other transmission planning regions, such as
upgrades that may be required in a third transmission planning
region and, if the transmission providers in the regions in which
the transmission facility is located agree to bear costs associated
with such upgrades, then the interregional cost allocation method
must include provisions for allocating the costs of such upgrades
among the beneficiaries in the transmission planning regions in
which the transmission facility is located.\827\
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    \827\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 657.

b. Requests for Rehearing or Clarification
    697. Several petitioners argue that Principle 4 is inconsistent
with cost causation.\828\ Energy Future Coalition Group and AEP assert
that the Commission should require beneficiaries in adjoining regions
to contribute to the costs of new transmission facilities. They assert
that otherwise it is likely that intraregional transmission projects
that are in the public interest, and would benefit customers in
multiple regions, will fail.
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    \828\ See, e.g., Joint Petitioners; Energy Future Coalition
Group; and AEP.
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    698. Energy Future Coalition Group argues that the Commission
disregarded the beneficiary pays principle by providing that costs for
a transmission facility located in one region may be allocated to
beneficiaries in another region only if those beneficiaries volunteer
to pay those costs.\829\ Energy Future Coalition Group, Joint
Petitioners, and AEP add that the Commission's decision fails to
address the concern about free-riders. AEP argues that the Commission's
decision is contrary to its findings that the FPA and court precedent
\830\ require all rates to ``reflect to some degree the costs actually
caused by the customer who must pay them,'' and ``[t]o the extent that
a utility benefits from the costs of new facilities, it may be said to
have `caused' a part of those costs to be incurred.'' \831\ AEP argues
that this cost causation principle applies to all identifiable
beneficiaries, not only those who voluntarily agree to pay the costs
associated with the facilities. AEP further argues that the
Commission's policy results in unjust and unreasonable rates that
discriminate against a set of customers.
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    \829\ Energy Future Coalition Group at 9 (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 582).
    \830\ AEP at 7 (citing Illinois Commerce Commission v. FERC, 576
F.3d 470 (7th Cir. 2009); K N Energy, Inc. v. FERC, 968 F.2d 1295,
1300 (D.C. Cir. 1992); Midwest ISO Transmission Owners v. FERC, 373
F.3d 1361, 1369 (D.C. Cir. 2004); Sithe/Independent Power Partners,
L.P. v. FERC, 285 F.3d 1, 5 (D.C. Cir. 2002)).
    \831\ AEP at 8 (quoting Illinois Commerce Commission v. FERC,
576 F.3d at 476).
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    699. Joint Petitioners further argue that it is arbitrary to follow
the beneficiary pays principle within a region, but not across regions,
when the Commission has declined to define what these regions should be
and when they may have little or no electrical significance. AEP makes
a similar argument. Energy Future Coalition Group and AEP also argue
that there will be a perverse incentive to create regional boundaries
for the purpose of evading cost responsibility for nearby transmission
facilities. AEP adds that the choice between a regional and an
interregional project configuration would make an enormous difference
with respect to cost allocation, but that there may be very little
difference in the distribution of benefits or the physical design of
the project.
    700. Energy Future Coalition Group notes that the Commission held
that within a given region, costs of a new project built wholly within
the service territory of one transmission provider can be allocated to
beneficiaries throughout the region if there is a clear regional
benefit. It argues that this is directly analogous to the potential for
extraregional benefits from a regional transmission project and asserts
that the Commission unaccountably reaches the opposite conclusion as to
the possibility of broader interregional cost allocation for a regional
project with broader benefits.
    701. Energy Future Coalition Group argues that the Commission can
ensure that the attenuated assessments of benefits are avoided by
providing that interregional planning and cost allocation are required
for a project located wholly within one region only when: (1) The
extraregional benefits are directly related to the proposed
transmission project, not to assumed electricity market reactions or
influences; (2) the identified extraregional benefits are enjoyed in an
adjacent planning region; and (3) the extraregional benefits are
similar in nature to the benefits for which costs are proposed to be
allocated within the region where the facility is proposed.\832\
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    \832\ Energy Future Coalition Group at 11.
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    702. Joint Petitioners suggest that to limit the stakeholder burden
of monitoring transmission planning in other regions, and in keeping
with the evidence of the broad benefits of extra high voltage
transmission, Regional Cost Allocation Principle 4 and Interregional
Cost Allocation Principle 4 should be limited to transmission projects
less than 345 kV. Joint Petitioners recommend that for projects at 345
kV and above, the Commission should expand its interregional
coordination requirements to require that a regional planning entity
notify its neighbors when it is considering such an extra high voltage
project. Joint Petitioners state that the neighboring transmission
planning region then could have an opportunity to participate in the
planning process through which the project's beneficiaries will be
determined or may conduct its own planning process to consider the
project. They suggest similar opportunities should be provided in the
regional planning process.
    703. Similarly, AEP proposes that the Commission expand the scope
of ``interregional transmission facilities'' to include new facilities
located solely within a single region in certain circumstances, such as
where the facilities are extra high voltage facilities that provide
demonstrable benefits to the neighboring region.\833\ AEP adds that
identification of potential beneficiaries will be strictly limited to a
region that adjoins the region in which the facility will be located,
and would specifically exclude any region that does not have a direct