the key incentives to complete a project once begun. Similarly,
Southern Companies argue that Order No. 1000 will discriminate in favor
of third party developers at the expense of an incumbent's native load
and OATT customers unless the Commission ensures that developers of
regional projects are held responsible and accountable for any and all
adverse effects of their construction delays or abandonments upon
incumbents, including any increased costs caused thereby.\560\
---------------------------------------------------------------------------

    \560\ Southern Companies at 83-84 (citing Chicago v. FPC, 385
F.2d 629, 637 (D.C. Cir. 1967)).
---------------------------------------------------------------------------

iii. Commission Determination
    489. In response to Transmission Access Policy Study Group and
APPA, we clarify that we will, consistent with Order No. 679,\561\
grant abandoned plant recovery on a case-by-case basis. Order No. 1000
did not provide a blanket grant of abandoned plant recovery, but merely
stated that where an incumbent transmission provider is called upon to
complete a transmission project that another entity has abandoned, this
would be a basis for the incumbent transmission provider to be granted
abandoned plant recovery for that transmission facility, upon the
filing of a petition for declaratory order requesting such rate
treatment or a request under section 205 of the FPA.\562\
---------------------------------------------------------------------------

    \561\ Order No. 679, FERC Stats. & Regs. ] 31,222.
    \562\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 267.
---------------------------------------------------------------------------

    490. In response to Southern California Edison, nothing in Order
No. 1000 requires an incumbent transmission provider to construct a
nonincumbent transmission developer's transmission project selected in
the regional transmission plan for purposes of cost allocation if it
abandons a transmission facility.\563\ We note, however, that some RTOs
and ISOs may have the authority under their tariff or membership
agreements to direct a member to build a transmission facility under
certain circumstances.\564\ Further, Order No. 1000 did not address the
issue of backstop construction authority or responsibility for any
transmission project, whether undertaken initially by an incumbent or a
nonincumbent transmission developer. Accordingly,

this issue is beyond the scope of this proceeding, and we will not
address it on rehearing.
---------------------------------------------------------------------------

    \563\ Id. P 344.
    \564\ See, e.g., PJM Consolidated Transmission Owners Agreement
at section 4.2.1.We note that a nonincumbent transmission developer
that becomes a member of an RTO or ISO may be subject to an
obligation to build that applies to transmission-owning members.
---------------------------------------------------------------------------

    491. In response to Southern California Edison's request that
incumbent transmission providers be compensated for the cost of
developing implementing a mitigation plan through ``grid-wide'' rates,
we did not provide a generic answer in Order No. 1000 and do not do so
here. That is, we are not deciding here whether a transmission provider
may recover, or how it may recover, the costs that result from
complying with the Reliability Standards if a nonincumbent transmission
developer delays or abandons a needed transmission project.
    492. In response to Edison Electric Institute, the Commission does
not require under Order No. 1000 that an incumbent transmission
developer purchase the facilities, materials, or any other assets
related to an abandoned project that the incumbent transmission
provider determines it must complete. However, Order No. 1000 also does
not preclude an incumbent transmission developer from purchasing such
facilities, materials or other assets if it believes it is prudent to
do so.

C. Interregional Transmission Coordination

1. Interregional Transmission Coordination Requirements
a. Interregional Transmission Coordination Procedures and Geographical
Scope
i. Final Rule
    493. In Order No. 1000, the Commission required each public utility
transmission provider, through its regional transmission planning
process, to establish further procedures with each of its neighboring
transmission planning regions for the purpose of (1) coordinating and
sharing the results of respective regional transmission plans to
identify possible interregional transmission facilities that could
address transmission needs more efficiently or cost-effectively than
separate regional transmission facilities; and (2) jointly evaluating
such facilities, as well as jointly evaluating those transmission
facilities that are proposed to be located in more than one
transmission planning region.\565\ Furthermore, the Commission required
each public utility transmission provider, through its regional
transmission planning process, to describe the methods by which it will
identify and evaluate interregional transmission facilities and to
include a description of the type of transmission studies that will be
conducted to evaluate conditions on neighboring systems for the purpose
of determining whether interregional transmission facilities are more
efficient or cost-effective than regional facilities.\566\
---------------------------------------------------------------------------

    \565\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 396.
    \566\ Id. P 398.
---------------------------------------------------------------------------

    494. In Order No. 1000, the Commission also required each public
utility transmission provider through its regional transmission
planning process to coordinate with the public utility transmission
providers in each of its neighboring transmission planning regions
within its interconnection to implement the interregional transmission
coordination requirements.\567\ The Commission defined an interregional
transmission facility as one that is located in two or more
transmission planning regions.\568\ The Commission declined to require,
but did not prohibit, joint evaluation of other facilities or study of
the effects in a second region of a new transmission facility proposed
to be located in a single transmission planning region.\569\ The
Commission explained that to do otherwise could have the effect of
mandating interconnectionwide transmission planning, because a
transmission facility located within one transmission planning region
can have effects on many systems in the interconnection, which could
trigger a chain of multiregional evaluation processes. Furthermore, the
Commission observed that its interregional transmission coordination
requirements will assist transmission planners in understanding and
managing the effects of a transmission facility located in one region
on a neighboring region.\570\
---------------------------------------------------------------------------

    \567\ Id. P 415.
    \568\ Id. P 482 n.374.
    \569\ Nevertheless, consistent with Cost Allocation Principle 4,
each regional transmission planning process must identify the
consequences of a proposed new transmission facility for other
transmission planning regions. The Commission also stated that Order
No. 1000 did not affect any obligations that public utility
transmission providers may otherwise have to assess the effects of
new transmission facilities on other systems, including, but not
limited to, any other requirement of the OATT for interconnection
studies, any requirement under the NERC reliability standards, and
the requirements of Good Utility Practice. Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 416 n.351.
    \570\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 416.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    495. AEP asks the Commission to ensure that the interregional
coordination requirements apply to transmission needs driven by public
policy requirements. Otherwise, AEP states, planners will settle on
less efficient and less cost-effective solutions, which increase costs.
AEP argues that it is arbitrary and capricious for the Commission not
to require consideration of needs driven by public policy requirements
as part of interregional coordination, in light of its findings on the
importance of public policy considerations in the Final Rule. AEP also
argues that requiring consideration of transmission needs driven by
public policy requirements within a region but not between regions
places too much emphasis and importance on the decisions about
configuration of the planning regions given that the Commission has
declined to prescribe the geographic scope of any transmission planning
region.
    496. Bonneville Power states that certain aspects of Order No. 1000
indicate that formal procedures need to cover only identification and
joint evaluation rather than planning and developing interregional
transmission facilities. If this is what the Commission meant, then
Bonneville Power requests that the Commission so clarify.
    497. On rehearing, MISO Transmission Owners Group 1 and Wisconsin
PSC request that the Commission expand the definition of an
interregional transmission facility. Specifically, MISO Transmission
Owners Group 1 requests that the Commission find that transmission
facilities physically located within one region can be considered
interregional transmission facilities when they provide sufficient
benefits as determined in accordance with the applicable interregional
agreement or OATTs, and can be eligible for interregional cost
allocation pursuant to criteria set forth in that agreement or those
OATTs. Wisconsin PSC makes a similar argument. Wisconsin PSC also
requests that the Commission remove the single-region limitation, and
instead limit evaluation of a single-region project to interregional
transmission planning processes that involve no more than two
transmission planning regions. Wisconsin PSC adds that the Commission
could further limit consideration by requiring the project sponsor to
publicly identify a single-region transmission facility as benefiting
the other affected region to ensure that a project does not ``fly under
the radar.'' \571\ Both Wisconsin PSC and MISO Transmission Owners
Group 1 argue that their respective definitions eliminate the
Commission's concern

that expanding the scope of interregional transmission coordination
would lead to interconnectionwide transmission planning.
---------------------------------------------------------------------------

    \571\ Wisconsin PSC at 6-7.
---------------------------------------------------------------------------

    498. Furthermore, MISO Transmission Owners Group 1 argues that the
Commission should expand the definition because the expanded definition
would help ensure that the costs of such facilities are allocated in a
manner that is at least roughly commensurate with the benefits
received. Wisconsin PSC asserts that requiring regions to jointly
consider single-region projects in the interregional planning process
would diminish the risk of inadvertent free ridership, ensure that
intended beneficiaries of a project are allocated a share of the
project costs, and expand the set of potential cost-effective
transmission solutions to regional transmission needs. Wisconsin PSC
adds that not eliminating this exclusion may create a specific
violation of the application of the cost causation/beneficiaries pay
principles articulated in Illinois Commerce Comm'n v. FERC, which
require beneficiaries of a transmission project to pay a roughly
commensurate share of project costs.\572\
---------------------------------------------------------------------------

    \572\ Wisconsin PSC at 5 (citing 576 F.3d 470 (7th Cir. 2009)).
---------------------------------------------------------------------------

    499. Wisconsin PSC and MISO Transmission Owners Group 1 also argue
that it is especially important to expand the definition because MISO
has extensive seams with neighboring RTOs and other regions. Wisconsin
PSC adds that it is virtually impossible for MISO to plan a
transmission line in those areas without providing potential benefits
to PJM load. Thus, it argues that the single-region limitation would
increase the free ridership that the Commission seeks to deter.
iii. Commission Determination
    500. We deny AEP's arguments that Order No. 1000's interregional
transmission coordination requirements do not adequately provide for
consideration of transmission needs driven by Public Policy
Requirements. In Order No. 1000, the Commission determined that
interregional transmission coordination neither requires nor precludes
longer-term interregional transmission planning, including the
consideration of transmission needs driven by Public Policy
Requirements.\573\ Order No. 1000 stated that whether and how to
address this issue with regard to interregional transmission facilities
is a matter for public utility transmission providers, through their
regional transmission planning processes, to resolve in the development
of compliance proposals.\574\ We clarify that Order No. 1000 does not
require or prohibit consideration of transmission needs driven by
Public Policy Requirements as part of interregional transmission
coordination. However, such considerations are required through the
regional transmission planning process, which is an integral part of
interregional transmission coordination because all interregional
transmission projects must be selected in both of the relevant regional
transmission planning processes in order to receive interregional cost
allocation. Therefore, consideration of transmission needs driven by
Public Policy Requirements is an essential part of the evaluation of an
interregional transmission project, not as part of interregional
transmission coordination, but rather as part of the relevant regional
transmission planning processes. As such, we continue to believe that
the decision of whether and how to address these issues with regard to
interregional transmission facilities in the regional transmission
planning processes is a matter for public utility transmission
providers to work out with their stakeholders in the development of
compliance proposals.\575\
---------------------------------------------------------------------------

    \573\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 401.
    \574\ Id. P 401.
    \575\ Id.
---------------------------------------------------------------------------

    501. We clarify for Bonneville Power that Order No. 1000 only
requires the development of a formal procedure to identify and jointly
evaluate interregional transmission facilities that are proposed to be
located in neighboring transmission planning regions.\576\ We
emphasize, however, that while the Commission does not require any
particular type of studies to be conducted, the purpose of identifying
and jointly evaluating interregional transmission facilities is to
determine whether they may more efficiently or cost-effectively meet
transmission needs than regional transmission facilities.\577\
---------------------------------------------------------------------------

    \576\ Id. P 435.
    \577\ Id. P 398.
---------------------------------------------------------------------------

    502. We decline to expand the definition of an interregional
transmission facility adopted in Order No. 1000, as requested by MISO
Transmission Owners Group 1 and Wisconsin PSC. As the Commission
explained in Order No. 1000, requiring joint evaluation of the effects
of a new transmission facility proposed to be located solely in a
single transmission planning region could, in effect, mandate
interconnectionwide transmission planning. This is because transmission
facilities located in one transmission planning region often have
effects on multiple neighboring systems, which could trigger a chain of
multilateral evaluation processes.\578\ While the definitions of an
interregional transmission facility proposed by MISO Transmission
Owners Group 1 and Wisconsin PSC could help to restrict the range of
proposed new transmission facilities subject to joint evaluation, we
disagree that they are sufficient to address the Commission's concern
that expanding the definition of an interregional transmission facility
adopted in Order No. 1000 could mandate interconnectionwide
transmission planning. Adopting MISO Transmission Owners Group 1 and
Wisconsin PSC's expanded definitions of an interregional transmission
facility could still, in effect, mandate that certain transmission
projects located solely in a single transmission planning region be
planned on a multilateral, if not interconnectionwide, basis, and we
are not persuaded that such a requirement is necessary at this time.
The Commission exercised its discretion in this rulemaking to improve
regional transmission planning and bilateral interregional transmission
coordination in a manner that does not have the effect of requiring
interconnectionwide planning. Moreover, we reiterate here the
Commission's conclusion in Order No. 1000 that imposing multilateral or
interconnectionwide transmission coordination requirements at this time
could frustrate the progress being made in the ARRA-funded transmission
planning initiatives.\579\
---------------------------------------------------------------------------

    \578\ Id. P 416.
    \579\ Id. P 417.
---------------------------------------------------------------------------

    503. We also do not believe it is necessary to expand the
definition of an interregional transmission facility, as argued by
Midwest ISO Transmission Owners Group 1 and Wisconsin PSC, in order to
ensure that the costs of a transmission facility located in a single
transmission planning region that benefits a neighboring transmission
planning region are allocated commensurately with the benefits it
provides. As we explain more fully below,\580\ these arguments fail to
take into account the relationship between the Commission's cost
allocation reforms and the other reforms contained in Order No. 1000
and the need to balance a number of factors to ensure that the reforms
achieve the goal of improved transmission planning. In particular, as
we stated in Order No. 1000, these reforms establish a closer link
between regional transmission planning and cost allocation, both of

which involve the identification of beneficiaries. In light of that
closer link, we continue to find that allowing one region to allocate
costs unilaterally to entities in another region would effectively
impose an affirmative burden on stakeholders to actively monitor
transmission planning processes in numerous other regions in which they
could be identified as beneficiaries and thus be subject to cost
allocation. This would essentially result in interconnectionwide
transmission planning with corresponding cost allocation, albeit
conducted in a highly inefficient manner.\581\
---------------------------------------------------------------------------

    \580\ See discussion infra at section 0.
    \581\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 660.
---------------------------------------------------------------------------

    504. We note, however, that the public utility transmission
providers in neighboring transmission planning regions may negotiate an
agreement to share the costs of a particular transmission facility with
the beneficiaries in another transmission planning region, as they
always have been free to do.\582\ Further, nothing in Order No. 1000
precludes public utility transmission providers in consultation with
stakeholders from voluntarily developing and proposing interregional
transmission coordination procedures providing for the joint evaluation
by more than one transmission planning region of a transmission
facility located solely in one transmission planning region should the
public utility transmission providers in neighboring transmission
planning regions agree to do so.\583\ Also, we reiterate that Order No.
1000's limited requirements for bilateral interregional transmission
coordination do not prohibit either voluntary multilateral
interregional transmission coordination or planning, or the development
of stronger bilateral coordination agreements than the rule requires.
---------------------------------------------------------------------------

    \582\ Id. P 658.
    \583\ Id. P 416.
---------------------------------------------------------------------------

    505. Finally, Wisconsin PSC specifically mentions that transmission
lines in MISO often provide potential benefits to PJM load. As the
Commission recognized in Order No. 1000, MISO and PJM developed a
cross-border cost allocation method in response to Commission
directives related to their intertwined configuration that permits
them, in certain cases, to allocate to one RTO or ISO the cost of a
transmission facility that is located entirely within the other RTO or
ISO. We reiterate here that Order No. 1000 does not require MISO and
PJM to revise their existing cross-border cost allocation method in
response to Cost Allocation Principle 4.\584\
---------------------------------------------------------------------------

    \584\ Id. P 662.
---------------------------------------------------------------------------

2. Implementation of the Interregional Transmission Coordination
Requirements
a. Procedure for Joint Evaluation
i. Final Rule
    506. The Commission required the developer of an interregional
transmission project to first propose its transmission project in the
regional transmission planning processes of each of the neighboring
regions in which the transmission facility is proposed to be located.
The submission of an interregional transmission project in each
regional transmission planning process will trigger the procedure under
which the public utility transmission providers, acting through their
regional transmission planning processes, will jointly evaluate the
proposed transmission project.\585\ The Commission required that joint
evaluation be conducted in the same general timeframe as, rather than
subsequent to, each transmission planning region's individual
consideration of the proposed transmission project.\586\ For an
interregional transmission facility to receive cost allocation under
the interregional cost allocation method or methods developed pursuant
to Order No. 1000, the Commission required that the transmission
facility be selected in both of the relevant regional transmission
plans for purposes of cost allocation.\587\ Finally, the Commission
directed each public utility transmission provider, through its
transmission planning region, to develop procedures by which
differences in planning criteria can be identified and resolved for
purposes of jointly evaluating a proposed interregional transmission
facility.\588\
---------------------------------------------------------------------------

    \585\ Id. P 436.
    \586\ Id. P 439.
    \587\ Id. P 436.
    \588\ Id. P 437.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    507. Joint Petitioners and ITC Companies seek rehearing of the
Commission's requirement that both neighboring transmission planning
regions must agree to include a proposed interregional transmission
facility in their respective regional transmission plans for it to be
eligible for interregional cost allocation. Instead, Joint Petitioners
argue that the Commission should require the preparation and approval
of an interregional plan, or at the very least, provide a mechanism by
which a sponsor of an interregional transmission project can obtain
Commission review of a disagreement or failure to act by and among
affected planning regions. They assert that requiring each region to
include an interregional facility in its respective plan is
counterproductive because the Commission did not require the consistent
use of specific planning horizons or the performance of particular
scenario analyses for purposes of regional planning. Additionally,
Joint Petitioners contend that even if a project is determined to be
the most efficient, cost-effective project for the broader region
composed of both planning regions, either region may veto the project
because those broader benefits are not considered in the individual
regional plans.
    508. WIRES states that the planning experiences of RTOs and ISOs
and the record in this proceeding contain many examples of planning
procedures and criteria that are suitable for two regions to coordinate
their planning efforts. WIRES adds that adopting these procedures,
which establish fixed timelines for decision, data exchange
requirements, planning assumptions, and standard modeling techniques,
along with clear opportunities for exceptions where necessary, would
shorten and rationalize planning processes without dictating outcomes.
WIRES asserts that technical conferences could be useful for developing
a consensus on these matters.
iii. Commission Determination
    509. We deny Joint Petitioners' and ITC Companies' request for
rehearing of Order No. 1000's requirement that an interregional
transmission facility must be selected in each relevant regional
transmission plan for purposes of cost allocation to be eligible for
cost allocation under the interregional cost allocation method or
methods.\589\ Rather, we reaffirm this requirement. As stated above,
Order No. 1000 establishes a closer link between transmission planning
and cost allocation. As discussed more fully below in the section on
stakeholder participation,\590\ Order No. 1000 provides for stakeholder
involvement in the consideration of an interregional transmission
facility primarily through the regional transmission planning
processes.\591\ We

therefore conclude that this requirement is necessary to ensure that
stakeholders have an opportunity to provide meaningful input with
respect to proposed interregional transmission facilities before such
facilities are selected in each relevant regional transmission plan for
purposes of cost allocation.
---------------------------------------------------------------------------

    \589\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 436.
    \590\ See discussion infra at section 0.
    \591\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 465; see
also id. P 443.
---------------------------------------------------------------------------

    510. We disagree with Joint Petitioners' contention that Order No.
1000 did not require consistency in planning horizons or scenario
analyses. In Order No. 1000, the Commission directed each public
utility transmission provider, through its transmission planning
region, to develop procedures by which differences in the data, models,
assumptions, planning horizons, and criteria used to study a proposed
interregional transmission project can be identified and resolved for
purposes of jointly evaluating an interregional transmission
project.\592\ This approach allows regions the flexibility to develop
procedures that work for them, while still addressing the concern that
joint evaluation of a proposed interregional transmission facility
cannot be effective without some effort by neighboring transmission
planning regions to harmonize differences in the data, models,
assumptions, planning horizons, and criteria used to study a proposed
transmission project.\593\ We therefore decline to adopt WIRES'
suggestion that we require that public utility transmission providers
implement certain specific planning procedures or criteria, or that we
hold a technical conference to consider such matters.
---------------------------------------------------------------------------

    \592\ Id. P 437.
    \593\ Id.
---------------------------------------------------------------------------

    511. Moreover, we decline to require the preparation and approval
of an interregional transmission plan or to adopt a mechanism for the
Commission to review neighboring transmission planning regions'
disagreements about or failure to act on a proposed interregional
transmission facility as requested by Joint Petitioners. Joint
Petitioners have not convinced us that such measures are necessary in
this generic rulemaking. As the Commission found in Order No. 1000, the
interregional transmission coordination reforms do not require the
creation of a distinct interregional transmission planning process to
produce an interregional transmission plan or the formation of
interregional transmission planning entities. Rather, the requirement
is for public utility transmission providers to consider whether the
local and regional transmission planning processes result in
transmission plans that meet local and regional transmission needs more
efficiently and cost-effectively, after considering opportunities for
collaborating with public utility transmission providers in neighboring
transmission planning regions.\594\ However, as the Commission stated
in Order No. 1000, public utility transmission providers may
voluntarily engage in interregional transmission planning and, as
relevant, rely on such a planning process to comply with the
interregional transmission coordination requirements of Order No.
1000.\595\
---------------------------------------------------------------------------

    \594\ Id. P 399.
    \595\ Id.
---------------------------------------------------------------------------

    512. Finally, we understand Joint Petitioners' concern that a
transmission planning region may decline to select an interregional
transmission project in its regional transmission plan for purposes of
cost allocation if the project does not sufficiently benefit that
region, even if it is the more efficient or cost-effective project for
the broader multiregional area. This is another version of the argument
made by petitioners that prefer interconnectionwide transmission
planning to regional transmission planning. However, we decline to
require interconnectionwide planning in this rulemaking for the reasons
set out in Order No. 1000 and summarized above. We understand that,
under the interregional transmission coordination procedures of Order
No. 1000, an interregional transmission facility is unlikely to be
selected for interregional cost allocation unless each transmission
planning region benefits or the transmission planning region that
benefits compensates the region that does not through a separate
agreement--and that this feature would not necessarily apply for
interconnectionwide planning. We continue to believe however that,
under the regional transmission planning approach adopted in Order No.
1000, it is appropriate for each transmission planning region to
determine for itself whether to select in its regional transmission
plan for purposes of cost allocation an interregional transmission
facility that extends partly within its regional footprint based on the
information gained during the joint evaluation of an interregional
transmission project.
b. Stakeholder Participation
i. Final Rule
    513. In Order No. 1000, the Commission did not require the
interregional transmission coordination procedures to meet the
requirements of the transmission planning principles required for local
planning (under Order No. 890) and regional planning (under Order No.
1000).\596\ The Commission explained that stakeholders will have the
opportunity to participate fully in the consideration of interregional
transmission facilities during the regional transmission planning
process, because each region must select such a facility in its
regional transmission plan for purposes of cost allocation in order for
it to be eligible for interregional cost allocation.\597\ The
Commission also required public utility transmission providers to make
transparent the analyses undertaken and determinations reached by
neighboring transmission planning regions in the identification and
evaluation of interregional transmission facilities.\598\ Last, the
Commission required that each public utility transmission provider give
stakeholders the opportunity to provide input into the development of
its interregional transmission coordination procedures and the commonly
agreed-to language to be included in its OATT.\599\
---------------------------------------------------------------------------

    \596\ Id. P 465.
    \597\ Id.
    \598\ Id.
    \599\ Id. P 466.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    514. Transmission Dependent Utility Systems and PSEG Companies
argue that the Commission should have required public utility
transmission providers to provide for more stakeholder participation in
the interregional coordination process and procedures. Transmission
Dependent Utility Systems also seek clarification or, in the
alternative, argue that the Commission should require on rehearing,
that stakeholders have a meaningful opportunity to participate in the
development of the interregional coordination process before it is
submitted to the Commission in a compliance filing, whether the process
is reflected in the OATT or in a bilateral agreement.
    515. In addition, Transmission Dependent Utility Systems argue that
stakeholders must be allowed to participate throughout the process to
ensure that load-serving transmission customers receive treatment
comparable to the treatment transmission providers accord their retail
and wholesale merchant functions, as required by sections 205 and
217(b)(4), Order No. 890, and the judicial requirement for reasoned
decision-making.\600\ PSEG

Companies argue that Order No. 1000's assumption that this issue will
be addressed under the regional processes is unsupported. They also
argue that the lack of a specific requirement for stakeholder
participation is inconsistent with some of the other interregional
coordination requirements in Order No. 1000, including requirements
related to joint evaluation of interregional projects and the
determination of beneficiaries of such projects.
---------------------------------------------------------------------------

    \600\ Transmission Dependent Utility Systems at 18 (citing Motor
Vehicle Mfrs. Ass'n v. State Farm Mut. Auto Ins. Co., 463 U.S. 29,
43 (1983)).
---------------------------------------------------------------------------

    516. Moreover, Transmission Dependent Utility Systems argue that
stakeholders must have a meaningful opportunity to participate in the
early stages of the process for identifying and evaluating possible
interregional solutions to transmission customer concerns. Similarly,
PSEG Companies recommend that the Commission require that interregional
coordination procedures include information on: (1) How transmission
providers will facilitate stakeholder participation; (2) how market
participants can propose ideas for cross-border projects and identify
and submit concerns about problems in one region caused by activity in
another (and how to address those concerns); and (3) how transmission
providers will accommodate and track in a transparent manner all
questions, comments, and other input from stakeholders regarding data
posted on coordination activities, as well as transmission providers'
responses.
    517. Transmission Dependent Utility Systems also assert that Order
No. 1000 fails to address their larger concern, which is that the
interregional coordination processes fail to obligate public utility
transmission providers to share with stakeholders the data exchanged
among themselves, including study results, models, input data, and
assumptions used in running those studies. Transmission Dependent
Utility Systems are concerned that public utility transmission
providers may contend that the obligation to share does not include
load-serving customers. Further, Transmission Dependent Utility Systems
state the Commission should clarify that the interregional planning
data that is shared with load-serving entities must be sufficient to
allow them to replicate the interregional planning study results,
including models, base cases, data inputs, and assumptions.
Transmission Dependent Utility Systems also believe it is important
that benefit-to-cost analyses of interregional projects be transparent
and verifiable to protect customers, ensure accuracy, and minimize ex
post facto disputes regarding regional and interregional cost
allocation.
iii. Commission Determination
    518. First, we clarify for Transmission Dependent Utility Systems
that each public utility transmission provider must provide
stakeholders with a meaningful opportunity to provide input into the
development of its interregional transmission coordination procedures
before those procedures are submitted to the Commission in its
compliance filing, whether those procedures are included in its OATT or
reflected in an interregional transmission coordination agreement.\601\
Accordingly, stakeholders must be afforded sufficient time to
meaningfully comment on a public utility transmission provider's
proposed interregional transmission coordination procedures as they are
being developed.
---------------------------------------------------------------------------

    \601\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 466.
---------------------------------------------------------------------------

    519. In response to those petitioners that raise concerns regarding
stakeholder participation in the interregional transmission
coordination process, we reiterate the Commission's statement in Order
No. 1000 that stakeholder participation in the consideration of
interregional transmission facilities is an important component of
interregional transmission coordination. Moreover, we also reiterate
that stakeholders will have the opportunity to provide input with
respect to the consideration of interregional transmission facilities
when these facilities are being considered in the regional transmission
planning process. As stated above, Order No. 1000 provides that only if
an interregional transmission facility is selected in each region's
transmission plan for purposes of cost allocation will that facility's
cost be allocated to either region.\602\ It is therefore through
participation in the regional transmission planning process that
stakeholders will have the primary opportunity to participate fully in
the consideration of interregional transmission facilities. While
nothing in Order No. 1000 prohibits an interregional transmission
coordination process from providing for more direct stakeholder
involvement in interregional transmission coordination, it may be the
case that much of the interregional transmission coordination would
occur through sharing computer modeling results regarding the effects
and benefits of a proposed interregional transmission facility, which
may be harder for a broad community of stakeholders to participate in
than would face to face meetings be. If we are being asked to require
there be in-person meetings for interregional transmission coordination
with all stakeholders attending, we would be concerned about requiring
a cumbersome process that could necessitate significant expense and
travel time to multiple neighboring regions by the large number of
stakeholders in each region. We continue to believe it is sufficient
and appropriate to allow for consideration of stakeholder interests by
requiring that any decision on interregional cost allocation be
affirmed by each of the transmission planning regions involved.
---------------------------------------------------------------------------

    \602\ Id. P 465.
---------------------------------------------------------------------------

    520. For similar reasons, we decline to expand the requirements of
Order No. 1000 regarding the types and sufficiency of interregional
transmission coordination information to be exchanged between regions
and provided to stakeholders. We therefore affirm Order No. 1000's
requirement that, in order to facilitate stakeholder involvement,
public utility transmission providers must, subject to appropriate
confidentiality protections and CEII requirements, make transparent the
analyses undertaken and determinations reached by neighboring
transmission planning regions in the identification and evaluation of
interregional transmission facilities.\603\
---------------------------------------------------------------------------

    \603\ Id.
---------------------------------------------------------------------------

    521. Further, we decline to adopt PSEG Companies' recommendation
that the Commission require the interregional transmission coordination
procedures to include information on how stakeholders in one
transmission planning region can raise issues and solutions regarding
activity in another transmission planning region. The regional
transmission planning process already provides stakeholders with the
opportunity to present such concerns, and we continue to believe that
these concerns are best addressed in the first instance through the
regional transmission planning process, particularly as the solution
may not involve an interregional transmission facility.
    522. In light of this, however, we clarify that each public utility
transmission provider must describe in its OATT how its regional
transmission planning process will enable stakeholders to provide
meaningful and timely input with respect to the consideration of
interregional transmission facilities. Moreover, as requested by PSEG
Companies, we require that each public utility transmission provider
must explain in its OATT how stakeholders and transmission developers
can propose interregional transmission facilities for

the public utility transmission providers in neighboring transmission
planning regions to evaluate jointly. This is consistent with Order No.
1000's requirement that on compliance, public utility transmission
providers must describe the methods by which they will identify and
evaluate interregional transmission facilities.\604\
---------------------------------------------------------------------------

    \604\ Id. P 398.
---------------------------------------------------------------------------

IV. Cost Allocation

    523. In Order No. 1000, the Commission required that each public
utility transmission provider have in its OATT a method, or set of
methods, for allocating the costs of new regional transmission
facilities selected in the regional transmission plan for purposes of
cost allocation (``regional cost allocation''); and that each public
utility transmission provider within two (or more) neighboring
transmission planning regions develop a method or set of methods for
allocating the costs of new interregional transmission facilities that
each of the two (or more) neighboring transmission planning regions
selected for purposes of cost allocation because such facilities would
resolve the individual needs of each region more efficiently or cost-
effectively (``interregional cost allocation'').\605\ The OATTs of all
public utility transmission providers in a region must include the same
cost allocation method or methods adopted by the region.
---------------------------------------------------------------------------

    \605\ Id. P 482. For purposes of Order No. 1000, a regional
transmission facility is a transmission facility located entirely in
one region. An interregional transmission facility is one that is
located in two or more transmission planning regions. A transmission
facility that is located solely in one transmission planning region
is not an interregional transmission facility. Id. P 482 n.374.
---------------------------------------------------------------------------

    524. The regional and interregional cost allocation methods each
must adhere to six regional and interregional cost allocation
principles: (1) Costs must be allocated in a way that is roughly
commensurate with benefits; (2) there must be no involuntary allocation
of costs to non-beneficiaries; (3) a benefit to cost threshold ratio
cannot exceed 1.25; (4) costs must be allocated solely within the
transmission planning region or pair of regions unless those outside
the region or pair of regions voluntarily assume costs; (5) there must
be a transparent method for determining benefits and identifying
beneficiaries; and (6) there may be different methods for different
types of transmission facilities.\606\ The Commission directed that,
subject to these general cost allocation principles, public utility
transmission providers in consultation with stakeholders would have the
opportunity to agree on the appropriate cost allocation methods for
their new regional and interregional transmission facilities, subject
to Commission approval.\607\ The Commission also found that if public
utility transmission providers in a region or pair of regions could not
agree, the Commission would use the record in the relevant compliance
filing proceeding(s) as a basis to develop a cost allocation method or
methods that meets the Commission's requirements.\608\ Finally, the
Commission emphasized that its cost allocation requirements are
designed to work in tandem with its transmission planning requirements
to identify more appropriately the benefits and the beneficiaries of
new transmission facilities so that transmission developers, planners
and stakeholders can take into account in the transmission planning
process who would bear the costs of transmission facilities, if
constructed.\609\
---------------------------------------------------------------------------

    \606\ Id. PP 622-93.
    \607\ Id. P 588.
    \608\ Id. P 482.
    \609\ Id. P 483.
---------------------------------------------------------------------------

A. Legal Authority for Cost Allocation Reforms

1. Final Rule
    525. In Order No. 1000, the Commission determined that its
jurisdiction is broad enough to allow it to ensure that all
beneficiaries of services provided by specific transmission facilities
bear the costs of those benefits regardless of their contractual
relationship with the owner of those transmission facilities.\610\ The
Commission stated that this comports fully with the specific
characteristics of transmission facilities and transmission services,
and that the provisions of Order No. 1000 are necessary to fulfill the
Commission's statutory duty of ensuring rates, terms and conditions of
jurisdictional service are just and reasonable and not unduly
discriminatory or preferential.\611\
---------------------------------------------------------------------------

    \610\ Id. P 531.
    \611\ Id.
---------------------------------------------------------------------------

    526. The Commission based its finding on the language of section
201(b)(1) of the FPA, which gives the Commission jurisdiction over
``the transmission of electric energy in interstate commerce.'' \612\
The Commission concluded that its jurisdiction therefore extends to the
rates, terms and conditions of transmission service, rather than merely
transactions for such transmission service specified in individual
agreements.\613\ Moreover, the Commission found that section 201(b)(1)
gives the Commission jurisdiction over ``all facilities'' for the
transmission of electric energy, and this jurisdiction is not limited
to the use of those transmission facilities within a certain class of
transactions.\614\ As a result, the Commission stated that it has
jurisdiction over the use of these transmission facilities in the
provision of transmission service, which includes consideration of the
benefits that any beneficiaries derive from those transmission
facilities in electric service regardless of the specific contractual
relationship that the beneficiaries may have with the owner or operator
of these transmission facilities.\615\
---------------------------------------------------------------------------

    \612\ Id. P 532.
    \613\ Id.
    \614\ Id.
    \615\ Id.
---------------------------------------------------------------------------

    527. The Commission also explained that neither section 205 nor
section 206 of the FPA state or imply that an agreement is a
precondition for any transmission charges.\616\ The Commission also
concluded that cost allocation cannot be limited to voluntary
arrangements because if it were the Commission could not address free
rider problems associated with new transmission investment, and it
could not ensure that rates, terms and conditions of jurisdictional
service are just and reasonable and not unduly discriminatory.\617\
---------------------------------------------------------------------------

    \616\ Id. P 533.
    \617\ Id. P 535.
---------------------------------------------------------------------------

    528. In addition, the Commission explained that its approach is
consistent with the concept of cost causation, because a full cost
causation analysis may involve ``an extension of the chain of
causation'' \618\ beyond those causes captured in voluntary
arrangements. The Commission explained that in order to identify all
causes, it is necessary to some degree to begin with their effects,
i.e., the benefits that they engender and then work back to their
sources.\619\ The Commission noted that this point was acknowledged in
the Seventh Circuit's characterization of cost causation in Illinois
Commerce Commission.\620\ The Seventh Circuit stated that:
---------------------------------------------------------------------------

    \618\ Id. P 536 (quoting KN Energy, 968 F.2d 1295 at 1302).
    \619\ Id.
    \620\ Id. P 537.

    To 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, as without the expectation of its contributions the
facilities might not have been built, or might have been
delayed.\621\
---------------------------------------------------------------------------

    \621\ Id. (quoting Illinois Commerce Commission, 576 F.3d at 476
(emphasis supplied)).

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

    The court fully recognized that, to identify causes of costs, one
must to some degree begin with benefits.\622\
---------------------------------------------------------------------------

    \622\ Id.
---------------------------------------------------------------------------

    529. Last, the Commission emphasized that its cost allocation
reforms are a component of its transmission planning reforms, which
require that, to be eligible for regional or interregional cost
allocation, a proposed new transmission facility first must be selected
in a regional transmission plan for purposes of cost allocation, which
depends on a full assessment by a broad range of regional stakeholders
of the benefits accruing from transmission facilities planned according
to the reformed transmission planning processes.
2. Requests for Rehearing or Clarification
a. Petitioners' Arguments That the FPA Requires a Contract Before Costs
Are Allocated
    530. Several petitioners argue that the Commission does not have
the jurisdiction to require that beneficiaries of service provided by
specific transmission facilities bear the costs of those benefits
regardless of their contractual relationship with the owner of those
facilities.\623\ They contend that the Commission's requirement to
allocate costs without regard to whether there is a contract or service
provided is inconsistent with the FPA.\624\ For example, Ad Hoc
Coalition of Southeastern Utilities and Large Public Power Council
assert that the Commission has confused the FPA's expression of
jurisdiction in section 201 with the grant of substantive authority,
and that the Commission's interpretation of what section 201 allows
would make sections 205 and 206 superfluous. They also assert that the
Commission's view of section 201 would also render section 203
superfluous and allow the Commission to compel sales or purchases of
jurisdictional facilities when the public interest required it.
---------------------------------------------------------------------------

    \623\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Coalition for Fair Transmission Policy; Large Public Power Council;
National Rural Electric Coops; New York ISO at 4 (citing Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 539); New York PSC; New York
Transmission Owners; Northern Tier Transmission Group at 5 (citing
Atlantic City Elec. Co. v. FERC, 295 F.3d 1, 8 (D.C. Cir. 2002)
(stating that in the absence of statutory authority authorization
for its act, an agency's action is plainly contrary to law and
cannot stand)); Sacramento Municipal Utility District; Southern
Companies at 96-97 (citing Illinois Commerce Comm'n, 576 F.3d 470
(2009); Morgan Stanley Capital Group, Inc. v. Pub. Util. Dist. No. 1
of Snohomish County, Washington et al., 554 U.S. 527, 533 (2008);
Ottertail Power Co. v. United States, 410 U.S. 366, 374 (1973); In
re Permian Basin Area Rate Cases, 390 U.S. 747, 822 (1968); United
Gas Pipeline Co. v. Mobile Gas Service Corp., 350 U.S. 332, 343
(1956)); and Vermont Agencies at 6, 10 (citing Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 532).
    \624\ See, e.g., Coalition for Fair Transmission Policy;
Southern Companies; National Rural Electric Coops; and Ad Hoc
Coalition of Southeastern Utilities.
---------------------------------------------------------------------------

    531. National Rural Electric Coops state that a contractual
relationship is required as a basis for a jurisdictional rate or
charge. They maintain that in providing for Commission regulation of
rates ``for or in connection with the transmission or sale of electric
energy,'' the FPA ties the Commission's rate authority directly to the
jurisdictional service provided by those public utilities.\625\ They
argue that where an entity takes no jurisdictional service from a
public utility, the Commission cannot permit the public utility to
collect charges from that entity. Several other petitioners make
similar arguments.\626\ Large Public Power Council argues that the
natural implication of terms in section 205 and 206 such as ``made,''
``demanded,'' ``received,'' ``observed,'' ``charged,'' or ``collected''
is that they pertain to rates assessed to utility customers in
connection with an agreement to take service.\627\
---------------------------------------------------------------------------

    \625\ National Rural Electric Coops at 14 (quoting 16 U.S.C.
824d(a)).
    \626\ See, e.g., National Rural Electric Coops; New York ISO;
Northern Tier Transmission Group; Sacramento Municipal Utility
District; Southern Companies; and Vermont Agencies.
    \627\ Large Public Power Council at 35.
---------------------------------------------------------------------------

    532. Large Public Power Council argues that the approach taken in
Order No. 1000 to cost allocation for new transmission development is
at odds with the Commission's requirement that interstate gas pipeline
projects be self-sustaining and not be subsidized by existing services.
Large Public Power Council states that courts have held that the
Natural Gas Act and the FPA should be interpreted similarly, and the
Commission must explain substantial discrepancies.
    533. Sacramento Municipal Utility District argues that if the rates
that the Commission regulates are for transmission service, it
logically follows that only customers who receive the transmission
service can be charged for it. Vermont Agencies contend that even if
the statute were ambiguous, it would still be unreasonable to allocate
costs on the beneficiary theory because it would not follow logically
from the Commission's acknowledgement that it only regulates the
provision of transmission service.
    534. Sacramento Municipal Utility District argues that the
Commission never disputed its arguments that: (1) In theory, a utility
could build a facility and then claim that because it provided a
benefit to someone remote from the facility, that entity--customer or
not--should bear some of the costs; and (2) it cannot force unwilling
customers to pay for additional service.\628\ Sacramento Municipal
Utility District argues that Order No. 1000 allows ``beneficiaries'' of
new transmission facilities to be charged even if they are not getting
a new service.\629\
---------------------------------------------------------------------------

    \628\ Sacramento Municipal Utility District at 9 (citing Exxon
Mobil Corp. v. FERC, 430 F.3d 1166, 1176-77 (D.C. Cir. 2005)).
    \629\ Sacramento Municipal Utility District at 9 & n.4.
---------------------------------------------------------------------------

    535. National Rural Electric Coops also argue that FPA sections 205
and 206 require that costs and benefits be fairly allocated between the
two parties providing and receiving jurisdictional service. They
contend that the fact that there may be third-party beneficiaries to an
agreement does not change the analysis. They state that, even though
other utilities may look more like transmission customers than entities
that benefit indirectly from increased transmission capacity and are
not subject to jurisdictional rates, this does not mean that those
utilities have greater legal or contractual obligations.
    536. Coalition for Fair Transmission Policy argues that the
Commission is incorrect in finding that it has the legal authority to
authorize public utilities to charge third party beneficiaries for
transmission facilities because the issue has not been squarely
addressed by the courts.\630\ It asserts that the matter has not
merited analysis or discussion because it is an undisputed maxim that
lawful rates are founded on privity of contracts.
---------------------------------------------------------------------------

    \630\ Coalition for Fair Transmission Policy at 20 (citing Order
No. 1000, FERC Stats. & Regs. ] 31,323 at P 540).
---------------------------------------------------------------------------

    537. Several petitioners disagree that free rider problems are a
basis for the cost allocation requirements established in Order No.
1000.\631\ Southern Companies argue that under Order No. 1000, the mere
potential of free riders is absolute poison to the justness and
reasonableness of a cost allocation methodology. They contend that
Order No. 1000 does not explain who these free riders may be, what
benefits might be taken without compensation, or whether in the absence
of the new transmission, they would require and financially support
their own new transmission. Southern Companies add that Order No. 1000
does not explain why complaints under section 206 are

insufficient for resolving free rider problems.
---------------------------------------------------------------------------

    \631\ See, e.g., Ad Hoc Coalition of Southeastern Utilities;
Large Public Power Council; and National Rural Electric Coops.
---------------------------------------------------------------------------

    538. Southern Companies also assert that the FPA does not allow the
allocation of costs to third-party non-customers because it does not
allow the Commission to regulate cost allocations or rate structures
that apply to the conveyance of abstract nonjurisdictional ``benefits''
other than electricity. Southern Companies assert that the FPA requires
that cost allocations and rate structures must apply to the conveyance
of benefits that are the actual use of transmission facilities or
services (or support services required to provide the same). They argue
that Mobil Oil Corp. v. FPC supports this conclusion.\632\ In that
case, the court found that the Commission exceeded its authority when
it required cost allocation and rate structures for certain
nonjurisdictional liquids as part of the transportation of natural
gas.\633\
---------------------------------------------------------------------------

    \632\ 483 F.2d 1238 (D.C. Cir. 1973).
    \633\ Southern Companies at 100-101 (citing Mobil Oil, 483 F.2d
1238, 1248; also Office of Consumers' Counsel v. FERC, 655 F.2d
1132, 1148 (D.C. Cir. 1980)).
---------------------------------------------------------------------------

    539. Sacramento Municipal Utility District argues that the
Commission is incorrect in determining that it can require non-public
utilities participating in a regional planning organization to accept
an allocation of costs for new transmission facilities approved by the
regional entity as a condition of reciprocity, even if they have no
customer relationship with the transmission provider. It also states
that the Commission's longstanding position is that without evidence
that two systems are in fact acting as one, the Commission cannot
mandate the use of a single joint rate.\634\ Sacramento Municipal
Utility District argues that if the Commission cannot mandate the use
of joint rates, it cannot mandate that an entity pay the rates charged
by a utility with which it has no contractual or tariff-based customer/
provider relationship at all.
---------------------------------------------------------------------------

    \634\ Sacramento Municipal Utility District at 15 (citing Ft.
Pierce Utils. Comm'n v. FERC, 730 F.2d 778 (D.C. Cir. 1984);
Richmond Power & Light v. FERC, 574 F.2d 610 (D.C. Cir. 1978);
Alabama Power Co. v. FERC, 993 F.2d 1557 (D.C. Cir. 1993); Illinois
Power Co., 95 FERC ] 61,183, at 61,144 (2002)).
---------------------------------------------------------------------------

    540. Several petitioners argue that the courts have rejected
attempts to impose cost liability without a contract for Commission-
jurisdictional service.\635\ For example, Southern Companies and
Coalition for Fair Transmission Policy argue that the entire design of
the FPA is based on the premise that those who impose charges have a
service relationship with those on whom charges are levied.\636\ They
assert that this is supported by the Supreme Court's finding in Morgan
Stanley, where it stated that ``the regulatory system created by the
FPA is premised on contractual agreements voluntarily devised by the
regulated companies.'' \637\ Coalition for Fair Transmission Policy
states that in Otter Tail Power Co. v. United States, the Supreme Court
wrote that Congress had rejected a pervasive regulatory scheme for
transmission planning and cost allocation ``in favor of voluntarily
contractual relationships.'' \638\
---------------------------------------------------------------------------

    \635\ See, e.g., Coalition for Fair Transmission Policy at 19-20
(citing Morgan Stanley Capital Group, Inc. v. Public Utility
District No. 1 of Snohomish County, Washington, 554 U.S. 527, 533
(2008)); Illinois Commerce Commission; National Rural Electric
Coops; New York PSC; Ad Hoc Coalition of Southeastern Utilities; and
Large Public Power Council.
    \636\ Southern Companies at 97 (citing Morgan Stanley Capital
Group Inc. v. Pub. Util. Dist. No. 1 of Snohomish County,
Washington, 554 U.S. 527, 533 (2008); Otter Tail Power Co. v. United
States, 410 U.S. 366, 374 (1973); In re Permian Basin Area Rate
Cases, 390 U.S. 747, 822 (1968); United Gas Pipeline Co. v. Mobile
Gas Service Corp., 350 U.S. 332, 343 (1956)). See also Coalition for
Fair Transmission Policy at 20-21.
    \637\ Southern Companies at 97-98 (quoting Morgan Stanley, 554
U.S. at 533 (2008) (citing and quoting with approval Permian Basin
Rate Cases, 390 U.S. at 822); also citing KN Energy, Inc. v. FERC,
968 F.2d 1295, 1300 (D.C. Cir. 1992) (``[I]t has been traditionally
required that all approved rates reflect to some degree the costs
actually caused by the customer who must pay them.'') (emphasis
added); Alabama Electric Cooperative, Inc. v. FERC, 684 F.2d 20, 27
(D.C. Cir. 1982) (``Properly designed rates should produce revenue
from each class of customers which match, as closely as practicable,
the costs to serve each class or individual customer.'') (emphasis
added)). See also Coalition for Fair Transmission Policy at 20-21;
New York PSC at 6.
    \638\ Coalition for Fair Transmission Policy at 20-21 (quoting
Otter Tail Power Co. v. United States, 410 U.S. 366, 374 (1973)).
---------------------------------------------------------------------------

    541. Ad Hoc Coalition of Southeastern Utilities also asserts that a
utility's ability to collect rates is a matter of its contractual
relationship with its customers, and the Commission's authority is
limited to reviewing rates and, if unlawful, to remedying them. It
asserts that this is apparent on the face of the FPA, and it has been a
fundamental building block of energy law since the Supreme Court
articulated the Mobile-Sierra doctrine.\639\ Ad Hoc Coalition of
Southeastern Utilities argues that the Mobile-Sierra doctrine makes it
clear that the Commission's oversight of utility rates is subordinate
to parties' contractual rights. It argues that the Commission errs in
its attempt to distinguish Mobile-Sierra on the ground that ``we are
dealing here with conditions under which costs can be recovered in
rates, not conditions under which contracts can be altered.'' \640\
Large Public Power Council makes similar arguments and also asserts
that while the Commission has the authority to alter the terms of a
contract for service under FPA section 206, subject to the ``public
interest'' standard, it cannot establish a right to recover costs where
no contractual authority exists.
---------------------------------------------------------------------------

    \639\ Ad Hoc Coalition of Southeastern Utilities at 68 (citing
United Gas Pipe Line Co. v. Mobile Corp., 350 U.S. 332 (1955
(Mobile); FPC v. Sierra Pacific Co., 350 U.S. 348 (1956) (Sierra));
see also Northern Tier Transmission Group at 6.
    \640\ Ad Hoc Coalition of Southeastern Utilities at 70 (quoting
Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 540).
---------------------------------------------------------------------------

    542. National Rural Electric Coops state that a central holding of
the Mobile-Sierra cases was that the Commission's authority to review
and modify jurisdictional rates does not confer new rights on the
public utilities subject to the Commission's jurisdiction. They argue
that Order No. 1000 is inconsistent with Mobile-Sierra in concluding
that costs may be allocated to entities in the absence of contractual
privity because neither section 205 nor section 206 of the FPA state or
imply that an agreement is a precondition for any transmission charges.
National Rural Electric Coops maintain that it is impermissible for the
Commission to infer authority to act based on the lack of an express
Congressional denial of such authority.\641\
---------------------------------------------------------------------------

    \641\ National Rural Electric Coops at 16 (citing American
Petroleum Institute v. EPA, 52 F.3d 1113 (D.C. Cir. 1995); Mobil Oil
Corp. v. FPC, 483 F.2d 1238 (DC Cir. 1973)).
---------------------------------------------------------------------------

    543. Several petitioners maintain that both court and Commission
precedent show that a section 205 filing requires a customer or other
contractual relationship between the filing utility and the
ratepayer.\642\ New York Transmission Owners assert that FPA section
205 does not authorize a utility to submit (and does not authorize the
Commission to accept) a rate filing where the utility lacks a
contractual or customer relationship with the entities to which the
rate will be charged. They state that an administrative agency cannot
exceed the authority granted to it by Congress and that the agency's
role is not to preempt Congressional action or to fill gaps where it
believes federal action is needed.\643\
---------------------------------------------------------------------------

    \642\ New York ISO at 4 (citing In re Permian Basin Area Rate
Cases, 390 U.S. 747, 822 (1968)). See also New York ISO at 5-9
(citing Midwest Indep. Transmission Sys. Operator, Inc., 131 FERC ]
61,173 (2010) and Commonwealth Edison Co., 129 FERC ] 61,298 (2009),
order on reh'g, 132 FERC ] 61,268 (2010)); Ad Hoc Coalition of
Southeastern Utilities at 68-69 (citing 16 U.S.C. Sec.  824d(a));
and New York Transmission Owners at 4.
    \643\ New York Transmission Owners at 5-6 (citing California
Indep. Sys. Operator Corp. v. FERC, 372 F.2d 395, 398 (D.C. Cir.
2004) and Office of Consumers' Counsel v. FERC, 655 F.2d 1132, 1152
(DC Cir. 1980)).

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

    544. Ad Hoc Coalition of Southeastern Utilities asserts that there
is no Commission or court case approving an allocation of costs outside
a contractual relationship. National Rural Electric Coops state that
the Commission cited Illinois Commerce Commission for the proposition
that to identify causes of costs, one must begin with benefits, but
this statement does not address cost allocation in the absence of
contractual privity when a non-customer is shown to benefit from a
particular transmission project. They maintain that the court in
Illinois Commerce Commission strongly suggested that costs must be
recovered from customers when it noted that rates must ``reflect to
some degree the costs actually caused by the customer who must pay
them.'' \644\ Southern Companies makes similar arguments. National
Rural Electric Coops argue that Commission forbid cost allocations to
non-customers when it refused to allow MISO to charge Green Mountain
Energy Company (Green Mountain) for Seams Elimination Charge/Cost
Adjustments/Assignment (SECA) costs under MISO's tariff because Green
Mountain did not directly contract with MISO for transmission service,
even though Green Mountain purportedly benefited from the transmission
service.\645\
---------------------------------------------------------------------------

    \644\ National Rural Electric Coops at 20-21 (quoting Illinois
Commerce Commission, 576 F.3d 470, 476 (7th Cir. 2009) (emphasis
added by National Rural Electric Coops)).
    \645\ National Rural Electric Coops at 18 (citing MISO, 131 FERC
] 61,173 (2010) (SECA Order)).
---------------------------------------------------------------------------

    545. Vermont Agencies similarly argue that if the Commission is now
asserting authority to allocate costs to non-customers, it failed to
provide a reasonable basis for its change in course.\646\ They state
that AEP recognizes that utilities, in limited circumstances, can seek
protection when they are forced to transmit for others, but an entity
cannot build a transmission facility and then seek compensation for the
benefit it provides to an entity that did not ask for it. Sacramento
Municipal Utility District states that AEP provides no basis for
charging an entity that simply benefits in some way from the new line's
existence but has not caused loop flow through unscheduled deliveries.
---------------------------------------------------------------------------

    \646\ Vermont Agencies at 14-15 (citing American Elec. Power
Co., 49 FERC ] 61,377, at 62,381 (1986) (AEP); Southern Cal. Edison
Co., 70 FERC ] 61,087 (1995); Midwest Indep. Transmission Sys.
Operator, Inc., 131 FERC ] 61,173, at P 421 (2010)).
---------------------------------------------------------------------------

    546. Sacramento Municipal Utility District also reiterates its
argument that the Commission relied upon cases for authority to
allocate costs to non-customers that are inapt because they all
involved situations where a customer/provider relationship
existed.\647\ It states that the Commission dismissed this argument in
Order No. 1000 by stating that the issue was not before the court in
any of those cases. It argues that the Commission did not defend its
interpretation of these cases.\648\ Moreover, Sacramento Municipal
Utility District and Vermont Agencies assert that if the rationale for
charging non-customers rests on cases the Commission now concedes are
inapplicable, saying that those cases do not preclude it from
allocating costs to non-customers does not answer just what does
authorize the Commission to do so.
---------------------------------------------------------------------------

    \647\ Sacramento Municipal Utility District at 10-11 (citing
Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC ] 61,168,
P 60 (2004); see also Midwest Indep. Transmission Sys. Operator,
Inc., 113 FERC ] 61,194, P 1-4, 10 (2005); Midwest Indep.
Transmission Sys. Operator, Inc., 122 FERC ] 61,084, P22 (2008);
Midwest ISO Transmission Owners v. FERC, 373 F.3d 1361 (D.C. Cir.
2004)).
    \648\ Sacramento Municipal Utility District at 11 (citing
Tennessee Gas Transmission Co. v. FERC, 789 F.2d 61, 62-63 (D.C.
Cir. 1986)).
---------------------------------------------------------------------------

    547. Sacramento Municipal Utility District also argues that the
Commission's policy on cost allocation in Order No. 1000 would do more
harm than good. For example, it contends that the risk of facing
charges as an incidental beneficiary of a facility that a party did not
want and will not use may discourage, rather than promote, regional
cooperation.
b. Arguments That Order No. 1000's Cost Allocation Reforms Are
Inconsistent With the Cost Causation Principle
    548. Illinois Commerce Commission contends that the Commission
misinterpreted the cost causation principle and failed to recognize the
important distinction between cost causers and beneficiaries. It
maintains that the applicable court decisions do not support equating
cost causers and beneficiaries for purposes of cost allocation. It
argues that the cost causation principle associates beneficiaries with
cost causers only to the extent that the facilities might be delayed or
not built without the revenues expected from them. Illinois Commerce
Commission asserts that costs must be allocated primarily to such cost
causers. Allocations to any other beneficiaries must be substantiated
through an appropriate process.
    549. Illinois Commerce Commission asserts that Illinois Commerce
Commission makes it clear that when a line is planned to address the
reliability concerns of one subregion of an RTO, there should be no
cost allocations to others when the benefits to them are trivial or
nonexistent.\649\
---------------------------------------------------------------------------

    \649\ Illinois Commerce Commission contends that this is the
case with respect to the projects at issue on remand in the PJM
Interconnection, LLC matter in Docket No. EL06-121-006.
---------------------------------------------------------------------------

    550. New York ISO states that transmission facilities may provide
some greater or lesser degree of ``benefit'' to a broad range of system
users, but showing that an entity receives some incidental benefit
(based on a standard that has not yet been articulated) does not prove
that the entity is receiving transmission service over that facility
and should be assessed costs.
c. Arguments That the Commission Did Not Show That Existing Rates Are
Unjust and Unreasonable
    551. FirstEnergy Service Company and California ISO argue that the
FPA does not authorize the Commission to require the filing of new
rates without first finding that the existing rate is unjust,
unreasonable, or unduly discriminatory or preferential. FirstEnergy
Service Company maintains that the Commission concludes that the
absence of clear cost allocation rules can impede the development of
transmission facilities, which may adversely affect jurisdictional
rates.\650\ FirstEnergy Service Company argues that where no
methodologies exist, the Commission cannot fulfill the basic
requirement of section 206 that it find existing contracts or rates
unjust, unreasonable, or unduly discriminatory or preferential. It
maintains that section 206 applies to rates ``demanded, observed,
charged or collected,'' not to rates that might apply to a future
jurisdictional service.\651\ FirstEnergy Service Company asserts that,
if, on the other hand, there is an existing rate that applies to cost
allocation for regional and interregional transmission facilities, then
the Commission's conclusion that the absence of a rate is inapplicable,
and the Commission does not find any such existing rates unjust or
unreasonable. California ISO makes a similar argument. It also argues
that the Commission cannot use section 206 to promote goals such as
cost-effectiveness and transmission expansion, and rates are not unjust
and unreasonable simply because another rate might be more just and
reasonable.\652\ California ISO states that its tariff already includes
provisions that ensure the construction of needed

projects, and it takes cost-effectiveness into consideration when
choosing projects.
---------------------------------------------------------------------------

    \650\ FirstEnergy Service Company at 14 (quoting Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 579).
    \651\ FirstEnergy Service Company at 18.
    \652\ California ISO at 18 (citing Duke Energy Trading and
Marketing, LLC, 315 F.3d 377, 382 (D.C. Cir. 2003)).
---------------------------------------------------------------------------

    552. FirstEnergy Service Company also asserts that the courts have
admonished the Commission for seeking to impose new rates without first
determining that the existing rate is unjust, unreasonable, or unduly
discriminatory or preferential.\653\ It cites Public Service Commission
of New York v. FERC in which the court disagreed with the Commission
that it could act under section 4 of the NGA rather than section 5 in
finding that an existing zone allocation in the utility's rates was
unlawful and prescribing a new allocation because the utility had
proposed a rate increase under section 4 of the NGA.\654\ FirstEnergy
Service Company states that the court reversed the Commission's
decision because the Commission did not make a finding under section 5
of the NGA. FirstEnergy Service Company also cites other cases in which
it states that the court rejected Commission filing requirements as an
impermissible attempt to avoid the strictures of sections 4 and 5 of
the NGA.\655\
---------------------------------------------------------------------------

    \653\ FirstEnergy Service Company at 16 (citing Western
Resources, Inc. v. FERC, 9 F.3d 1568, 1578 (D.C. Cir. 1993); Tenn.
Gas Pipeline Co. v. FERC, 860 F.2d 446 (D.C. Cir. 1988); Northern
Natural Gas Co. v. FERC, 827 F.2d 779 (D.C. Cir. 1987); Sea Robin
Pipeline Co. v. FERC, 795 F.2d 182 (D.C. Cir. 1986); ANR Pipeline
Co. v. FERC, 771 F.2d 507 (D.C. Cir. 1985); Panhandle E. Pipe Line
Co. v. FERC, 613 F.2d 1120 (D.C. Cir. 1980)).
    \654\ FirstEnergy Service Company at 16-17 (citing Public
Service Commission of New York v. FERC, 642 F.2d 487 at 1344-45).
FirstEnergy Service Company states that although the Court was
describing the NGA, the FPA and NGA are interpreted in parallel. FPC
v. Sierra Pacific Power Co., 350 U.S. 348, at 353 (1956).
    \655\ FirstEnergy Service Company at 17 (citing Public Service
Commission of New York v. FERC, 866 F.2d 487 (D.C. Cir. 1989) and
Consumers Energy Co. v. FERC, 226 F.3d 777 (6th Cir. 2000)).
---------------------------------------------------------------------------

    553. FirstEnergy Service Company argues that the Supreme Court has
found that the right to file new rates and contracts belongs solely to
public utilities under the FPA.\656\ It disagrees with the Commission's
assertion that it is setting standards for filings under section 205
rather than interfering with public utilities' rights to file new
rates,\657\ it argues that Order No. 1000 directs transmission
providers to amend their tariffs to include cost allocation provisions
for regional and interregional facilities. FirstEnergy Service Company
contends that the Commission may issue guidelines that will be used to
determine whether future rates for regional and interregional
facilities will be just and reasonable, but section 205 does not permit
it to compel filings of rates or contracts.
---------------------------------------------------------------------------

    \656\ FirstEnergy Service Company at 13 (quoting United Gas
Pipeline Co. v. Mobile Gas Ser. Co., 350 U.S. 332 at 341).
    \657\ FirstEnergy Service Company at 18 (quoting Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 547).
---------------------------------------------------------------------------

    554. Ad Hoc Coalition of Southeastern Utilities argues that the
Commission cannot support its determination by simply finding that
rates will be unjust and unreasonable without a cost allocation
mechanism. As support for this position, Ad Hoc Coalition of
Southeastern Utilities argues that the Commission's authority over
practices affecting rates under section 206 is limited to practices
that directly affect rates,\658\ and effectively requires utilities to
pay transmission developers for investments that the utilities do not
use indirectly affects rates for jurisdictional service. Large Public
Power Council makes similar arguments.
---------------------------------------------------------------------------

    \658\ Ad Hoc Coalition of Southeastern Utilities at 73 (citing
California Independent System Operator v. FERC, 372 F.3d at 403).
---------------------------------------------------------------------------

3. Commission Determination
    555. Many petitioners object to the Commission's cost allocation
reforms in Order No. 1000 based on what they consider to be fundamental
principles concerning both the Commission's jurisdiction as well as the
nature of transmission operations and the benefits they provide. Many
of the arguments raised by petitioners share common themes, and we thus
will address them collectively as far as possible. In order to do this
comprehensively, we think it is important first to state briefly what
the Commission did, and did not, require in Order No. 1000 with respect
to cost allocation and to address some of the basic principles that
inform those decisions.
    556. The cost allocation reforms in Order No. 1000 are grounded in
our determination that it is necessary to establish a closer link
between regional transmission planning and cost allocation, both of
which involve the identification of beneficiaries of new transmission
facilities. Planning of new transmission facilities in a regional
transmission planning process involves assessing how such facilities
will affect the existing transmission grid and how they will benefit
users of the grid within the relevant region.\659\ Cost allocation for
new transmission facilities that are selected in a regional
transmission plan for purposes of cost allocation similarly involves
assigning the costs of those facilities in a manner that accounts for
the identified benefits. Recognizing this relationship, the Commission
found that the lack of clear ex ante cost allocation methods that
identify 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 during the transmission planning
process. The Commission also found that linking transmission planning
and cost allocation through the regional transmission planning process
would increase the likelihood that transmission facilities in regional
transmission plans are constructed.
---------------------------------------------------------------------------

    \659\ Users of the regional transmission grid could be, for
example, public utility transmission providers that may effectively
rely on transmission facilities of another transmission provider in
order to provide transmission service, whether or not there is a
service agreement between those public utility transmission
providers.
---------------------------------------------------------------------------

    557. This emphasis on a closer link between regional transmission
planning and cost allocation also informs the cost allocation
principles that the Commission adopted in Order No. 1000. The
Commission found that in light of the need for a closer link between
regional transmission planning and cost allocation, allowing one region
to allocate costs unilaterally to entities in another region would
impose too heavy a burden on stakeholders to actively monitor
transmission planning processes in numerous other regions, from which
they could be identified as beneficiaries and be subject to cost
allocation. The Commission also stated that if it expected such
participation, the resulting regional transmission planning processes
could amount to interconnectionwide transmission planning with
corresponding cost allocation. The Commission stated clearly that Order
No. 1000 does not require either interconnectionwide transmission
planning or interconnectionwide cost allocation. We reaffirm these
findings here, as discussed further below with respect to Cost
Allocation Principle 4.\660\
---------------------------------------------------------------------------

    \660\ See discussion infra at section 0.
---------------------------------------------------------------------------

    558. Against this backdrop, we note the actions that the Commission
took in Order No. 1000 with respect to cost allocation are based on its
jurisdiction under section 201(b)(1) of the FPA over the transmission
of electric energy in interstate commerce and the facilities for such
transmission and its duty to exercise it authority under sections 205
and 206 of the FPA to ensure that Commission-jurisdictional rates are
just and reasonable and not unduly discriminatory or preferential.\661\
The nature and scope of this authority must be viewed in the context of
the specific characteristics of transmission facilities

and their operation, among other considerations.\662\
---------------------------------------------------------------------------

    \661\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 532,
535.
    \662\ As discussed further below, the Commission finds that
there is a need to balance a number of factors to ensure that the
reforms adopted in Order No. 1000 achieve the goal of improved
planning and cost allocation for transmission in interstate
commerce. See discussion infra at section 0.
---------------------------------------------------------------------------

    559. Transmission operations are characterized by a number of
unique features that are essential for understanding the Commission's
position, and therefore they merit summarizing here. Electric energy
does not travel on a preset path but rather along all available
pathways in accordance with the laws of physics.\663\ Continuous
fluctuations in the demand for power and in generation operations
affect power flows throughout the transmission grid. This means that
electric energy received by an individual customer at any one time
could be delivered over any number of transmission facilities that
constitute the transmission grid. Changes in demand for or supply of
electricity at any point in the system will change flows on all the
transmission lines to varying degrees, often in ways that are not
easily controlled.\664\
---------------------------------------------------------------------------

    \663\ An interconnected AC transmission grid essentially
functions as a single piece of equipment. See, e.g., Tampa Electric
Co., 99 FERC ] 61,192, at 61,796 (2002).
    \664\ See, e.g., Jack A. Casazza, Transmission Access and Retail
Wheeling: The Key Questions, in Electricity Transmission Pricing and
Technology 81 (Michael Einhorn and Riaz Siddiqi eds., 1996); Narain
G. Hingorani, Flexible AC Transmission System (Facts), in id. 242;
Karl Stahlkopf, The Second Silicon Revolution, in id. 263.
---------------------------------------------------------------------------

    560. The courts have recognized this fundamental fact and have
acknowledged that it has important implications for the Commission's
regulation of transmission service. The DC Circuit has stated:

    * * * In order to determine a utility's cost of providing a
transmission service, the Commission typically treats a transmission
network * * * as an integrated system. In other words, all of the
individual facilities used to transmit electricity are treated as if
they were part of a single machine. The Commission takes this
approach on the ground that a transmission system performs as a
whole; the availability of multiple paths for electricity to flow
from one point to another contributes to the reliability of the
system as a whole. This principle has a strong basis in the physics
of electrical transmission for there is no way to determine what
path electricity actually takes between two points or indeed whether
the electricity at the point of delivery was ever at the point of
origin.
    As a corollary, in determining permissible prices for
transmission services, the Commission treats each transmission
customer not as using a single transmission path but rather as using
the entire transmission system.\665\
---------------------------------------------------------------------------

    \665\ Northern States Power Co. v. FERC, 30 F.3d 177, 179 (DC
Cir. 1994) (emphasis supplied) (Northern States); see also Western
Massachusetts Electric Company v. FERC, 165 F.3d 922, 927 (DC Cir.
1999) (stating that ``[w]hen a system is integrated, any system
enhancements are presumed to benefit the entire system'').

In other words, in the case of transmission, there is only one
service--service over the entire grid.\666\
---------------------------------------------------------------------------

    \666\ We note that this principle is not, in itself,
determinative of what would constitute a just and reasonable cost
allocation method. For example, a regional cost allocation method
must satisfy the principles set forth in Order No. 1000 and affirmed
here, including that the costs of transmission facilities must be
allocated to those within the transmission planning region that
benefit from those facilities in a manner that is roughly
commensurate with estimated benefits. See, e.g., Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 622.
---------------------------------------------------------------------------

    561. The Commission appreciates that these prior decisions related
to transmission rates for a single public utility transmission
provider's facilities. However, the principle underlying those
decisions is equally applicable across larger regions of the
transmission system. Given the physics of power flows, and the
ownership of transmission facilities in the United States, the actual
transmission facilities that are affected by a particular transaction
are owned by multiple, interconnected transmission providers
irrespective of whether the transaction involves a single contract for
transmission service with one of the owners of the transmission
facilities or multiple contracts with all of the owners of the
transmission facilities along a contract path. That is, the
transmission grid constitutes a common infrastructure, ``a cohesive
network moving energy in bulk.'' \667\ Entities that contract for
service on the transmission grid cannot ``choose'' to affect only the
transmission facilities for which they have entered into a contract, as
some petitioners contend. Similarly, those entities cannot claim that
they are not using or benefiting from such transmission facilities
simply because they did not enter a contract to use them.
---------------------------------------------------------------------------

    \667\ Public Serv. Co. of Colo., 62 FERC ] 61,013, at 61,061
(1993).
---------------------------------------------------------------------------

    562. We also note that in an interconnected electric transmission
system, the enlargement of one path between two points can provide
greater system stability, lower line losses, reduce reactive power
needs, and improve the throughput capacity on other facilities. Given
the nature of transmission operations, it is possible that an entity
that uses part of the transmission grid will obtain benefits from
transmission facility enlargements and improvements in another part of
that grid regardless of whether they have a contract for service on
that part of the grid and regardless of whether they pay for those
benefits. This is the essence of the ``free rider'' problem the
Commission is seeking to address through its cost allocation
reforms.\668\ Any individual beneficiary of a new transmission facility
has an incentive to defer investment in the anticipation that other
beneficiaries in the region will value the project enough to fund its
development. This can lead to situations in which no developer moves
forward, adversely affecting development of transmission facilities
and, as a result, rates for jurisdictional services.
---------------------------------------------------------------------------

    \668\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP 534-35.
---------------------------------------------------------------------------

    563. The Supreme Court has stated that the Commission's
jurisdiction is ``to follow the flow of electric energy, an engineering
and scientific, rather than a legalistic or governmental, test.'' \669\
Indeed, the Supreme Court described the entire FPA as ``couched largely
in the technical language of the electric art.'' \670\
---------------------------------------------------------------------------

    \669\ Connecticut Light & Power Co. v. F.P.C., 324 U.S. 515, 529
(1945) (Connecticut Light & Power Co.).
    \670\ Id.
---------------------------------------------------------------------------

    564. Despite these considerations, many petitioners argue that the
costs of new transmission facilities can only be allocated within a
preexisting contractual relationship. These arguments are based on the
assumption that only preexisting contracts define jurisdictional
transmission service. In relying exclusively on contracts to perform
this role, petitioners are advocating a legalistic test for assessing
the scope of the Commission's jurisdiction that is inconsistent with
the Supreme Court's interpretation of the FPA in Connecticut Light &
Power Co. Contracts do not reflect the actual flow of electric energy
on the transmission grid. Nor do contracts define or limit the benefits
that an entity receives from its use of the transmission grid. To argue
that costs for new transmission facilities can be allocated only
through preexisting contractual relations means that some entities that
will benefit from those transmission facilities simply cannot be
allocated costs roughly commensurate with the benefits that they
receive. This is inconsistent with the well-established Commission and
judicial interpretation of the FPA and contrary to the requirement that
transmission rates be just and

reasonable and not unduly discriminatory or preferential.\671\
---------------------------------------------------------------------------

    \671\ We also note that Order No. 1000 states: ``Neither section
205 nor section 206 of the FPA state or imply that an agreement is a
precondition for any transmission charges. These statutory
provisions speak of rates and charges that are `made,' `demanded,'
`received,' `observed,' `charged,' or `collected' by a public
utility.'' Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 533.
---------------------------------------------------------------------------

    565. This explains why the cost allocation provisions of Order No.
1000, which seek to allocate costs to beneficiaries in a region roughly
commensurate with benefits they receive, are consistent with the
statement in Illinois Commerce Commission that ``[a]ll approved rates
[must] reflect to some degree the costs actually caused by the customer
who must pay them.'' \672\ Petitioners argue that because the court in
Illinois Commerce Commission used the word ``customer'' in the quote
above, it suggests that costs must be recovered from entities that have
a preexisting contractual relationship with the entity seeking the cost
allocation. However, given the nature of cost causation itself, some
entities that actually cause costs would not be required to pay them if
they could utilize the absence of a contractual relationship to shield
themselves from an allocation of costs. Rather than contractual
relationships, the benefits received by users of the regional
transmission grid provide a basis for how costs should be allocated.
Petitioners' argument would inappropriately revise the Illinois
Commerce Commission court's explanation that the cost causation
principle requires that ``all approved rates [must] reflect to some
degree the costs actually caused by the customer who must pay them'' by
adding a further requirement that the customer also agree to be
responsible for such costs. The court did not, however, reach such a
conclusion. We thus reject the claim by Ad Hoc Coalition of
Southeastern Utilities that the Commission's adherence to the cost
causation principle is subordinate to parties' contractual rights.
---------------------------------------------------------------------------

    \672\ Illinois Commerce Commission, 576 F.3d 470 at 476
(internal citations omitted).
---------------------------------------------------------------------------

    566. Moreover, our interpretation of the court's use of
``customer'' in Illinois Commerce Commission is consistent with the
statements that the court makes immediately thereafter. The court first
notes that compliance with the principle involved is evaluated `` `by
comparing the costs assessed against a party to the burdens imposed or
benefits drawn by that party.'' ' \673\ The court did not condition its
statement on a need for a preexisting contractual relationship. Rather,
the court allowed for a full comparison of costs for any party that
imposed burdens on, and benefited from enhancement of, the network
transmission grid. Furthermore, the court follows this by stating that
``[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, as without the expectation of its contributions the
facilities might not have been built, or might have been delayed.''
\674\ That is precisely the role that the Commission's cost allocation
reforms play within the context of its planning reforms. 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.\675\
---------------------------------------------------------------------------

    \673\ Id. (internal citations omitted).
    \674\ Id.
    \675\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 499.
---------------------------------------------------------------------------

    567. Some petitioners also argue that the Supreme Court's statement
in Morgan Stanley that ``the regulatory system created by the [FPA] is
premised on contractual agreements voluntarily devised by the regulated
companies'' \676\ means that a preexisting contractual relationship is
an essential precondition of cost allocation. Given the nature of
transmission grid operations, we disagree that this statement by the
Supreme Court means that contracts, which will not fully reflect how
transmission facilities are impacted by power flows, are the only
device that defines what rates are just and reasonable and not unduly
discriminatory or preferential. We do not read the importance that the
Supreme Court ascribes to voluntary contracts in Morgan Stanley to
imply that entities that use the transmission grid are entitled to
structure their contractual arrangements so that they are shielded from
paying costs that are roughly commensurate with the benefits that they
receive. In any event, Morgan Stanley never stated that, by refusing to
sign a contract, an entity benefiting from another's improvement of the
regional transmission grid can limit its obligation to something less
than an obligation to pay for all benefits that it receives.
---------------------------------------------------------------------------

    \676\ Morgan Stanley, 554 U.S. at 533.
---------------------------------------------------------------------------

    568. The obligation under the FPA to pay costs allocated under a
regional or interregional cost allocation method is imposed by a
Commission-approved tariff concerning the charges made by a public
utility transmission provider for the use of the public utility
transmission provider's facility. Such use is voluntary, and it does
not become less so because it is determined in part by immutable laws
of physics. Voluntary use therefore also entails voluntary acceptance
of the terms and conditions of use set forth in the tariff, including
an applicable cost allocation.
    569. We disagree with National Rural Electric Coops' argument that
Order No. 1000 is conferring new rights on public utility transmission
providers. We are not conferring new rights on public utility
transmission providers when we seek to ensure that they can allocate
the costs of their new transmission facilities to the beneficiaries of
those facilities. Nor are we claiming a power based solely on the fact
that there is not an express withholding of such power, as National
Rule Electric Coops claim. We are acting under the provisions of
section 206 of the FPA applied in accordance with the reasoning that we
have set forth both here and in Order No. 1000.
    570. In response to Large Public Power Council's argument that the
references in sections 205 and 206 to rates ``made,'' ``demanded,''
``received,'' ``observed,'' ``charged,'' or ``collected'' pertain to
rates assessed to utility customers in connection with an agreement to
take transmission service, we reiterate the Commission's finding in
Order No. 1000 that ``nothing in these sections precludes flows of
funds to public utility transmission providers through mechanisms other
than agreements between the service provider and the beneficiaries of
those transmission facilities.'' \677\ As explained in further detail
above, an entity that uses the transmission grid will necessarily use
transmission facilities owned by multiple owners, and the FPA permits a
public utility transmission provider to charge for the costs of using
its transmission facilities.
---------------------------------------------------------------------------

    \677\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 533.
---------------------------------------------------------------------------

    571. Contrary to the claim of National Rural Electric Coops, all
cost allocation contemplated by Order No. 1000 pertains to rates ``for
or in connection with the transmission * * * of electric energy.''
Order No. 1000 does not permit a public utility transmission provider
to collect charges other than in connection with the use of the
transmission grid. In suggesting that it does, National Rural Electric
Coops misconstrues the criteria for identifying the scope of
transmission usage. That scope is defined by the transmission grid
operations, not simply the terms of individual contracts, which can
diverge

from the underlying transmission grid operations. It is the purpose of
the cost allocation method or methods required by Order No. 1000 to
align cost responsibility with the reality of transmission grid
operations in the case of new transmission facilities selected in the
regional transmission plan for purposes of cost allocation.\678\
---------------------------------------------------------------------------

    \678\ As explained above, providing for such cost allocation
will help to ensure that rates are just and reasonable and not
unduly discriminatory or preferential as required by section 205 of
the FPA. 16 U.S.C. 824d.
---------------------------------------------------------------------------

    572. Moreover, contrary to Large Public Power Council's argument,
the cost allocation provisions of Order No. 1000 do not alter any
existing contract provisions governing the use of existing transmission
facilities and, therefore, are not inconsistent with Mobile-Sierra
doctrine regarding revision of contracts. Order No. 1000 requires each
public utility transmission provider to revise its OATT to include a
method, or set of methods, for allocating the costs of new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation--not transmission facilities already in service.
    573. We reject the characterization of the cost allocation
requirements of Order No. 1000 as authorizing allocation of costs to
third-party beneficiaries. Order No. 1000 authorizes allocation of
costs to entities that benefit in their own right from new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. To the extent that an entity is not required to pay
for a benefit that it receives, it is a free rider not a third party
beneficiary. The fact that a free rider benefits from a transaction
between two other entities does not make it a third party beneficiary,
which is a legal concept that refers to parties that have a right to a
benefit under a contract between two other entities. Such rights are
not at issue here.
    574. We thus also disagree with National Rural Electric Coops that
Order No. 1000 suggests that charges could be imposed on ``third party
beneficiaries'' such as ``[s]teel producers, crane operators, and wind
turbine manufacturers who may find more customers for their products
and services as a result of increased transmission capacity * * *.''
\679\ We note that Regional Cost Allocation Principle 1 provides that:
---------------------------------------------------------------------------

    \679\ National Rural Electric Coops at 21.

    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.\680\
---------------------------------------------------------------------------

    \680\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 622.

    While this statement explicitly is not intended to be an exhaustive
recitation of possible benefits, our expectation is that additional
types of benefits would be ``in connection with'' transmission of
electric energy. We do not intend that these benefits should include
such things as increased sales of goods and services used in the
construction of new transmission facilities.
    575. Likewise, in response to Southern Companies, Order No. 1000
does not authorize cost allocations or rate structures that apply to
conveyance of ``benefits [that] are not the actual use of transmission
facilities or services (or support services required to provide
same).'' \681\ We see no inconsistency between the cost allocation
provisions of Order No. 1000 and Mobil Oil Corp. v. FPC, as Southern
Companies claim. In that case, the court held that the Commission had
jurisdiction over rates for the transportation of natural gas on an
interstate pipeline but not over rates for the transportation of
certain non-jurisdictional liquid hydrocarbons that were also
transported on the pipeline. The court held that the Natural Gas Act
restricted the Commission's jurisdiction to rates for natural gas
transportation.\682\ Southern Companies maintains that Order No. 1000
authorizes rates for non-jurisdictional benefits that are analogous to
the non-jurisdictional liquid hydrocarbons in Mobil Oil Corp. v. FPC.
However, Order No. 1000 does not do this. It authorizes cost allocation
for benefits consistent with Regional Cost Allocation Principle 1,
which explicitly refers to matters that are subject to Commission
jurisdiction. For the same reasons, we disagree with the claim of
Vermont Agencies that Order No. 1000 authorizes allocation of costs to
persons that benefit in some way from the existence of a transmission
facility even if they use no transmission service at all.
---------------------------------------------------------------------------

    \681\ Southern Companies at 99.
    \682\ Mobil Oil Corp. v. FPC, 483 F.2d 1238, 1246-47 (D.C Cir.
1973).
---------------------------------------------------------------------------

    576. In response to Southern Companies regarding free riders, we
note that free riders for purposes of Order No. 1000 are entities who
do not bear cost responsibility for benefits that they receive in their
use of the transmission grid, specifically benefits they receive from
new transmission facilities selected in a regional transmission plan
for purposes of cost allocation. Such benefits include the traditional
benefits that transmission facilities can provide, such as lowered
congestion, increased reliability, and access to generation resources.
Southern Companies state that the Commission does not address whether
such entities would pursue or support new transmission facilities in
the absence of a transmission project that is entitled to cost
allocation, but this overlooks the purpose of the cost allocation
requirements of Order No. 1000. They are intended to promote regional
and interregional transmission planning that facilitates more efficient
or cost-effective transmission infrastructure development. 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. For this reason,
individual complaints under section 206 of the FPA would not suffice to
overcome the free rider problem because litigating complaints burdens
and unduly delays the transmission planning process. Individual
complaint procedures thus do not permit effective transmission
planning.
    577. The Commission has not confused the FPA's expression of
jurisdiction in section 201 with a grant of substantive authority. Ad
Hoc Coalition of Southeastern Utilities and Large Public Power Council
argue that according to the Commission's rationale, its jurisdiction
under section 201 over transmission service and transmission facilities
would also cover the matters for which specific authority is granted in
sections 205 and 206, as well as section 203, thereby rendering those
sections superfluous. As the Commission found in Order No. 1000,
section 201 simply sets forth the facilities and transactions in
interstate commerce that are subject to the Commission's jurisdiction
under Part II of the FPA. Our authority to act in Order No. 1000 on
matters subject to our jurisdiction arises under section 206 of the
FPA, specifically our authority to establish requirements regarding
transmission planning and cost allocation which are practices affecting
rates. The Commission's jurisdiction permits that authority to be
applied in a way that follows ``the flow of electric energy, an
engineering and scientific, rather than a legalistic or governmental,
test,'' \683\ and Order No. 1000's

application of the principle of cost causation is a reasonable exercise
of that authority. However, such action is not based directly on
section 201. It is based on section 206, which we apply to matters that
are within the scope of our jurisdiction set forth in section 201.
Moreover, we disagree with those petitioners that argue that our
interpretation of section 201 in Order No. 1000 could render either
section 203, section 205, or section 206 of the FPA superfluous,
because as we explain above, section 201 sets forth the subject matter
over which the Commission exercises its jurisdiction pursuant to those
other sections.
---------------------------------------------------------------------------

    \683\ Connecticut Light & Power Co., 324 U.S. at 529.
---------------------------------------------------------------------------

    578. Contrary to Large Public Power Council's contention, the cost
allocation requirements of Order No. 1000 are not at odds with the
Commission's policy on interstate gas pipeline development regarding
subsidization of development by existing shippers. The requirements of
Order No. 1000 are based on the principle of cost causation, which
requires that costs be allocated in a way that is roughly commensurate
with benefits. The principle of cost causation is intended to prevent
subsidization by ensuring that costs and benefits correspond to each
other. Indeed, in seeking to eliminate free riders on the transmission
grid, Order No. 1000 seeks to eliminate a form of subsidization, as
free riders by definition are entities who are being subsidized by
those who pay the costs of the benefits that free riders receive for
nothing.
    579. We disagree with Sacramento Municipal Utility District's
assertion that Order No. 1000 fails to prevent a utility from building
a transmission facility and then simply claiming that a remote entity
receives benefits from it and thus must bear some of the costs. Under
Order No. 1000, for a regional cost allocation method to apply to a new
regional or interregional transmission facility, the transmission
facility must first be selected in a regional transmission plan or
plans for purposes of cost allocation. This means that the public
utility transmission providers in a region, in consultation with
stakeholders, have evaluated a given facility and determined that it
provides benefits that merit cost allocation under a regional method.
As such, a developer of a transmission facility will not be entitled to
recover costs from other entities without its facility being subject to
the requirements of the regional transmission planning process,
including the selection of its facility in the regional transmission
plan for purposes of cost allocation.
    580. We also disagree with Sacramento Municipal Utility District
that Order No. 1000 forces unwilling customers to pay for additional
transmission service or to be charged even if they are not getting a
new transmission service. Order No. 1000 requires that new costs be
allocated in a way that is roughly commensurate with the benefits
derived from the new transmission facilities that are eligible for cost
allocation in accordance with Order No. 1000. As discussed above,
entities that receive benefits from these facilities in the course of
their use of the transmission grid cannot be characterized as
``unwilling customers.'' New York ISO notes that benefits come in
various degrees, and it maintains that entities should not be charged
for an ``incidental benefit.'' But again, Order No. 1000 requires that
costs be allocated in a way that is roughly commensurate with benefits,
and the court stated in Illinois Commerce Commission that entities
cannot be allocated costs for benefits that are trivial in relation to
those costs.\684\ All cost allocation methods will be subject to
Commission review and approval, and issues related to the
appropriateness of a particular method or methods can be raised at that
time.
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    \684\ Illinois Commerce Commission, 576 F.3d at 476.
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    581. Sacramento Municipal Utility District's argument that joint
rates are necessary for cost recovery in the case of a regional cost
allocation under Order No. 1000, describes a false dilemma. It argues
that without evidence that two systems are in fact acting as one, the
Commission cannot mandate the use of a single joint rate, and if it
cannot mandate the use of joint rates, it cannot mandate that an entity
pay the rates charged by a utility with which it has no contractual or
tariff-based customer/provider relationship. However, our position
regarding the role of preexisting contractual relationships goes to the
problem of cost allocation, not cost recovery, which Sacramento
Municipal Utility District focuses on when it speaks of the payment of
charges and which Order No. 1000 does not address.\685\ Moreover, Order
No. 1000 requires that the tariffs of transmission providers in a
region contain the regional cost allocation method or methods, which
means that in any event, there will be a tariff basis for implementing
a cost allocation. We thus reject the claim that a regional cost
allocation could be implemented only through a joint rate.
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    \685\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 563.
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    582. Turning to arguments that Order No. 1000 represents a change
in policy expressed in prior cases, we disagree with National Rural
Electric Coops' contention that the cost allocation provisions of Order
No. 1000 are contradicted by the Commission's refusal to allow MISO to
charge Green Mountain for SECA costs under MISO's tariff because Green
Mountain did not directly contract with MISO for transmission service.
In the SECA Order, the Commission found merely that Green Mountain's
affiliate BP Energy, not Green Mountain, was responsible for paying the
SECA charges because the contract between the affiliate and Green
Mountain stipulated that BP Energy was responsible for paying MISO for
network transmission service.\686\ The Commission found that since SECA
charges were intended to be surcharges assessed to the transmission
customer taking transmission service, and BP Energy, not Green
Mountain, was taking transmission service from MISO, BP Energy was
responsible for paying the SECA charges.\687\ The Commission emphasized
on rehearing of the SECA Order that MISO's tariff specifically provided
for its transmission customers to pay SECA charges, and therefore the
fact that BP Energy was the transmission customer, not Green Mountain,
was pivotal to the Commission's conclusion that BP Energy was
responsible for the SECA charges.\688\ This conclusion was based on a
reading of the requirements of the MISO tariff, and as such, it cannot
be read as establishing general principles regarding the authority of a
public utility transmission provider to collect charges for the
transmission of electric energy, as National Rural Electric Coops
argue.
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    \686\ SECA Order, 131 FERC ] 61,173 at P 422.
    \687\ Id. P 423.
    \688\ 136 FERC ] 61,244 at P 205.
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    583. Vermont Agencies and Sacramento Municipal Utility District
argue that the cost allocation reforms of Order No. 1000 represent a
change in policy from the position that the Commission took in AEP, and
they maintain that the Commission has failed to explain this change in
policy. AEP dealt with unintended loop flows on existing facilities,
which the Commission viewed as an operational issue that ``in the first
instance'' was to be dealt with by ``the interconnected parties''
establishing ``mutually acceptable operating practices.'' \689\ The
Commission also stated that if the party complaining of unintended loop
flows on its facilities could show that they created ``a burden on its
system, [it] can file a transmission service rate for

Commission consideration which would account for any unauthorized loop
flows.'' \690\ Vermont Agencies and Sacramento Municipal Utility
District describe Order No. 1000 as containing a policy change on this
point because in their view, the Commission maintains in Order No. 1000
that ``it could allocate the costs of new transmission facilities to
entities that somehow benefit from their existence--whether or not they
take service from the utility,'' whereas AEP ``addresses the issue of
compensation where the utility is involuntarily forced to provide
service.'' \691\ However, we see no fundamental difference between AEP
and Order No. 1000 precisely because individual owners of facilities on
an interconnected grid ``can file a transmission service rate for
Commission consideration'' under AEP. Additionally, it is because such
owners will often forgo grid enlargements that benefit many owners of
other facilities who will not pay for these enlargements that Order No.
1000 seeks to ensure that the former may be compensated through a cost
allocation to the latter.
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    \689\ AEP, 49 FERC ] 61,377, at 62,381.
    \690\ Id.
    \691\ Vermont Agencies at 16; Sacramento Municipal Utility
District at 14.
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    584. We also disagree with Vermont Agencies and Sacramento
Municipal Utility District that Order No. 1000 represents a change in
policy because the Commission has ``rejected assessment of charges'' in
situations such as that presented in AEP.\692\ The Commission did not
reject an assessment of charges in AEP. It stated that the operational
issue in question was in the first instance to be dealt with through
mutually acceptable operating practices, but a rate filing would be
appropriate if the loop flows created a burden on the system. Moreover,
Order No. 1000 does not deal with operating problems on existing
transmission facilities but rather solely with benefits to be derived
from new transmission facilities that regional participants themselves
select as having broad regional benefits, and it deals with cost
allocation for such new facilities as integral to transmission
planning. In this respect, Order No. 1000 does not express a change a
policy position taken in AEP because AEP does not deal with planning
and cost allocation for new transmission facilities and expresses no
policy with regard to these matters.
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    \692\ Vermont Agencies at 16-17; Sacramento Municipal Utility
District at 14.
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    585. In response to Illinois Commerce Commission's argument that
beneficiaries are to be associated with cost causers only to the extent
that transmission facilities might be delayed or not built without the
revenues expected from them, we note that it is for this reason that
the cost allocation requirements of Order No. 1000 are necessary. By
allocating costs in a way that is roughly commensurate with benefits,
the requirements help to ensure that more efficient and cost-effective
transmission solutions are implemented and that this occurs without
undue delay. In addition, one of the purposes of the regional
transmission planning process is to identify the beneficiaries of a
proposed transmission facility. This addresses Illinois Commerce
Commission's concern about the substantiation of benefits through an
appropriate process.
    586. We also disagree with Sacramento Municipal Utility District
that the Commission's position on cost allocation is likely to do more
harm than good by discouraging regional cooperation. On the contrary,
Order No. 1000 is intended to encourage the development of more
efficient and cost-effective transmission solutions to regional
transmission needs, which will promote considerable economic benefits
in the form of lower congestion, greater reliability, and greater
access to generation resources. Therefore, we do not believe that the
Commission's reforms will discourage cooperation when the potential
gains from cooperation are so great.
    587. Finally, several petitioners also argue that the Commission
must first find an existing rate to be unjust, unreasonable or unduly
discriminatory or preferential before it can take the actions regarding
cost allocation that it took in Order No. 1000. We disagree that such a
finding must be made case-by-case rather than generically. As explained
above,\693\ the Commission is not required to make individual findings
concerning the rates of individual public utility transmission
providers when proceeding under FPA section 206 by means of a generic
rule.\694\ Nor do we agree with FirstEnergy Service Company that
Commission actions taken in a rulemaking cannot apply to future
jurisdictional transmission service. Commission rulemakings are
prospective in their effect, and when the Commission proceeds by rule
it can conclude that ``any tariff violating the rule would have such
adverse effects * * * as to render it `unjust and unreasonable' ''
within the meaning of section 206 of the FPA.\695\ The effects that a
tariff would have include effects on future jurisdictional transmission
service.
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    \693\ See discussion supra at section 0.
    \694\ Associated Gas Distributors v. FERC, 824 F.2d at 1008.
    \695\ Id. (emphasis in original).
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    588. We further disagree with FirstEnergy Service Company's