interconnection with the region in which the new facility is located.
AEP asserts that this approach addresses several of the Commission's
concerns and does not place any undue burden on stakeholders.\834\
---------------------------------------------------------------------------

    \833\ AEP at 14.
    \834\ AEP adds that the Commission should find that the
transmission planning provisions of the joint operating agreement
between PJM and MISO meet the requirements of the Final Rule for
interregional transmission coordination without the need to justify
the process in a compliance filing.

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

    704. MISO argues that Cost Allocation Principle 4 should not
preclude an RTO from allocating to a withdrawing RTO member the cost of
eligible transmission upgrades located solely in the RTO and approved
before the withdrawal. It states that in recently accepting MISO's
tariff provisions regarding multi-value projects, the Commission
specifically found just and reasonable tariff provisions that authorize
allocating to a withdrawing transmission owner the cost of a multi-
value project approved before the withdrawal, although the associated
facility will be located only in a MISO state.
    705. Vermont Agencies note that while Order No. 1000 states that it
will not authorize the allocation of costs of facilities located in one
region to entities located in another region, because Order No. 1000
does not define ``region'' it could be read to claim authority to force
market participants into a region where they will be subject to cost
allocation plans agreed upon by the participants in that region.\835\
---------------------------------------------------------------------------

    \835\ Vermont Agencies at 9.
---------------------------------------------------------------------------

    706. Finally, North Carolina Agencies state that while the
Commission approves Principle 4, the Commission also states that if
there are benefits of a new transmission project to a public or non-
public utility within a region that has no transmission arrangement
with the entity building the project, costs can still be allocated to
that utility if it is found to benefit from the project. According to
North Carolina Agencies, the Commission has committed error by not
recognizing this apparent contradiction in the foregoing statements, as
well as by stating that the costs of new transmission projects may be
allocated involuntarily to those that lack any sort of connection to
the transmission project in question.
c. Commission Determination
    707. We affirm Regional and Interregional Cost Allocation Principle
4. Accordingly, we deny the arguments of those petitioners that ask us
to expand the scope of Cost Allocation Principle 4 to permit a
transmission planning region where a new transmission facility is
located to allocate costs of the facility unilaterally to a neighboring
region that benefits from it. Such 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 planning and cost allocation for transmission in interstate
commerce.
    708. In Order No. 1000, the Commission acknowledged that its
approach may lead to some beneficiaries of transmission facilities
escaping cost responsibility because they are not located in the same
transmission planning region as the transmission facility. Nonetheless,
the Commission found this approach to be appropriate since Order No.
1000 establishes a closer link between regional transmission planning
and regional cost allocation, both of which involve the identification
of beneficiaries. In light of that closer link, the Commission found
that 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 noted that if it expected
such participation, the resulting regional transmission planning
processes could amount to interconnectionwide transmission planning
with corresponding cost allocation, albeit conducted in a highly
inefficient manner. The Commission further explained that it is not
requiring either interconnectionwide transmission planning or
interconnectionwide cost allocation.\836\
---------------------------------------------------------------------------

    \836\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 660.
---------------------------------------------------------------------------

    709. Moreover, the discussion above highlights the importance that
the ability to participate in the transmission planning and cost
allocation process has for the Commission's transmission planning
reforms. While the Commission concluded in Order No. 1000 that cost
allocation is not dependent on a preexisting contractual relationship,
we also think it is important that any entities that will be
responsible for costs have an opportunity to participate in the process
through which they will be allocated costs. This follows directly from
the requirement of Order No. 890 that transmission planning be open and
transparent. It also promotes a close link between transmission
planning and cost allocation and helps to ensure fairness, which
ultimately promotes successful transmission planning. Entities outside
of a region may not be capable of being full participants in each and
every region's transmission planning process in which they could
potentially be allocated transmission costs. Unilateral allocation of
costs to them thus could undermine rather than promote the linking of
cost allocation and transmission planning.
    710. Energy Future Coalition Group, Joint Petitioners, and AEP
state that failing to revisit Cost Allocation Principle 4 does not
address the Commission's concerns about free riders. North Carolina
Agencies argue that the Commission's adoption of Cost Allocation
Principle 4 contradicts the Commission's finding that costs can still
be allocated to any entity that benefits from a new transmission
facility without a transmission arrangement. As noted above, the
Commission acknowledged in Order No. 1000 that its decision ``may lead
to some beneficiaries of transmission facilities escaping cost
responsibility because they are not located in the same transmission
planning region as the transmission facility.'' \837\ However, the
Commission's cost allocation reforms represent a significant advance
over current practices, and it is important to balance the possibility
that some beneficiaries could escape cost responsibility against the
larger goal of linking cost allocation with the transmission planning
process for the purpose of improving that process. Additionally, as
noted in our discussion of the need for the Commission's reforms,
transmission planning is more likely to succeed if it is understood in
advance how the costs of planned facilities will be allocated. While a
preexisting contract is not necessary to establish a cost allocation,
we believe that an ability to participate in the process in which costs
are allocated is important as it promotes the improved transmission
planning that Order No. 1000 seeks to achieve. The Commission
acknowledged in Order No. 1000 that some beneficiaries could escape
cost responsibility as a result of the decision not to allow costs to
be allocated outside the region in which a transmission facility is
located, but the implementation of any policy often requires one to
balance a number of considerations, which we believe Cost Allocation
Principle 4 does appropriately.
---------------------------------------------------------------------------

    \837\ Id.
---------------------------------------------------------------------------

    711. For these same reasons, we decline to adopt the suggestions
made by those petitioners that attempt to address the burden on
stakeholders to participate in several transmission planning regions,
by for example, limiting extraregional cost allocation to higher
voltage facilities or by requiring that costs be allocated only to
regions adjacent to the one in which a transmission facility is
located. While

we agree that these suggestions might mitigate the burden on some
stakeholders, we nevertheless are not convinced that they are
sufficient to ensure that the Commission is not through this rulemaking
proceeding effectively requiring interconnectionwide transmission
planning. In any event, nothing in Order No. 1000 would prohibit
regions from voluntarily agreeing to bear the costs for transmission
facilities located in neighboring regions and from which they receive a
benefit. Doing so is not inconsistent with Cost Allocation Principle
4.\838\
---------------------------------------------------------------------------

    \838\ Id. PP 658-59.
---------------------------------------------------------------------------

    712. We further disagree with petitioners that this determination
will result in arbitrary drawing of regional boundaries to avoid cost
allocation. In Order No. 890, the Commission determined that ``the
scope of a transmission planning region should be governed by the
integrated nature of the regional power grid and the particular
reliability and resource issues affecting individual regions.'' \839\
Consistent with that guidance, regions already have defined themselves
for purposes of transmission planning. The Commission appreciates that
these regional boundaries may change in response to Order No. 1000, but
any such changes will be subject to Commission review on compliance to
ensure that they continue to be appropriate. In response to Vermont
Agencies' concerns about entities being forced into regions against
their will, we note that in Order No. 1000, the Commission found that a
transmission planning region ``is one in which public utility
transmission providers, in consultation with stakeholders and affected
states, have agreed to participate in for purposes of regional
transmission planning and development of a single regional transmission
plan.'' \840\
---------------------------------------------------------------------------

    \839\ Id. P 160 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 527).
    \840\ Id. P 160 (emphasis added).
---------------------------------------------------------------------------

    713. We agree with AEP that there can be cases where a project can
have similar transmission flow impacts whether it is configured
regionally or interregionally. However, we conclude that the regional
and interregional transmission planning and coordination requirements
of Order No. 1000 provide sufficient opportunities for analyzing the
potential benefits of new transmission facilities, whether regional or
interregional in configuration.
    714. In response to MISO, we clarify that Cost Allocation Principle
4 does not preclude an RTO from allocating to a withdrawing RTO member
the cost of eligible transmission upgrades located solely in the RTO
and approved before the withdrawal pursuant to a Commission-approved
RTO agreement.
6. Whether To Establish Other Cost Allocation Principles
a. Final Rule
    715. In Order No. 1000, the Commission stated that it did not
believe that any additional cost allocation principles were necessary
at that time.\841\
---------------------------------------------------------------------------

    \841\ Id. P 705.
---------------------------------------------------------------------------

b. Requests for Rehearing
    716. ELCON, AF&PA, and the Associated Industrial Groups argue that
Order No. 1000 should address whether the costs of new transmission
occasioned by low capacity factor resources should be allocated on a
capacity basis. They assert that the Commission devoted no substantive
consideration to this issue, and deferred it to the regional
transmission planning processes. ELCON, AF&PA, and the Associated
Industrial Groups assert that FERC provided no explanation for why this
issue is better addressed by regional planning agencies. For example,
they argue that allocating the fixed costs of transmission facilities
intended to transmit wind energy to load centers on a volumetric basis
inappropriately subsidies wind energy, which is inconsistent with
resource neutrality and economically efficient resource allocation.
Moreover, ELCON, AF&PA, and the Associated Industrial Groups argue that
allocating these costs on any basis other than a capacity basis would
unfairly penalize and significantly increase costs for those customers
that have invested in operational changes to minimize consumption
during system peak periods.
c. Commission Determination
    717. We disagree with ELCON, AF&PA, and the Associated Industrial
Groups' assertion that the Commission dismissed their proposal for new
principles that would address cost allocation on a capacity basis
without explanation. In Order No. 1000, the Commission declined to
adopt additional principles proposed by commenters because the
Commission believed that to do so would limit the flexibility provided
to public utility transmission providers in proposing the appropriate
cost allocation method or methods for their transmission planning
region or pair of transmission planning regions.\842\ We continue to
believe this to be the case, and we therefore affirm the Commission's
decision on this issue.
---------------------------------------------------------------------------

    \842\ Id.
---------------------------------------------------------------------------

E. Application of Cost Allocation Principles

1. Participant Funding
a. Final Rule
    718. In Order No. 1000, the Commission found that participant
funding is permitted, but not as a regional or interregional cost
allocation method.\843\ The Commission explained that if proposed as a
regional or interregional cost allocation method, participant funding
would not comply with the regional or interregional cost allocation
principles adopted in Order No. 1000.\844\ The Commission explained,
however, that these principles do not in any way foreclose the
opportunity for a transmission developer, a group of transmission
developers, or one or more individual transmission customers to
voluntarily assume the costs of a new transmission facility.\845\
---------------------------------------------------------------------------

    \843\ Id. P 723.
    \844\ Id.
    \845\ Id. P 724.
---------------------------------------------------------------------------

b. Requests for Rehearing or Clarification
    719. Several petitioners request rehearing or clarification of the
Commission's finding that participant funding cannot be the regional or
interregional cost allocation method.\846\ Ad Hoc Coalition of
Southeastern Utilities states that, as a matter of policy, new long-
line transmission facilities that span utility service areas must be
supported by ascertainable demand, and that the most economically sound
way to determine what facilities should be built, and at what price, is
for those entities that will use the facilities to pay for them. ELCON,
AF&PA, and the Associated Industrial Groups argue that prohibiting
participant funding as a regional or interregional cost allocation
method creates a new free rider problem. According to them,
participants who, from an economic perspective, should be funding
transmission, and could do so most expeditiously, will now have an
incentive not to do so, because the cost will be allocated to other
more peripheral beneficiaries as part of the regional transmission
planning process.
---------------------------------------------------------------------------

    \846\ See, e.g., Illinois Commerce Commission; ELCON, AF&PA, and
the Associated Industrial Groups; Arizona Cooperative; Ad Hoc
Coalition of Southeastern Utilities; and Southern Companies.
---------------------------------------------------------------------------

    720. ELCON, AF&PA, and the Associated Industrial Groups argue that
the Commission's explanation of why participant funding should be

prohibited is both arbitrary and inconsistent when compared to
determinations made by the Commission in Order No. 1000 concerning
other cost allocation approaches. For instance, they state that the
Commission was willing to leave the decision of whether postage stamp
rate allocation is an appropriate cost allocation method to regional
planning entities. ELCON, AF&PA, and the Associated Industrial Groups
argue that Order No. 1000 subjects the two different cost allocation
methods to widely divergent standards of scrutiny with no explanation
as to why such differential treatment would be appropriate. They also
seek clarification that Order No. 1000 allows participant funding to be
used as the default for certain types of projects on a category basis
where participant funding best matches cost causation principles.
    721. Arizona Cooperatives and Southwest Transmission are concerned
that Order No. 1000 does not recognize the benefits of participant
funding. For instance, Arizona Cooperatives and Southwest Transmission
state that under participant funding, the cost of associated
transmission is bundled with generation. If the bundled price is
excessive, then the project does not attract customers and an unworthy
investment is avoided.
    722. Southern Companies argue that the Commission's treatment of
participant funding in Order No. 1000 is overly vague and unexplained.
They state that the Commission should refine its guidance on rehearing
to define ``participant funding'' more narrowly and in terms of the
issue that Order No. 1000 seeks to address, rather than categorically
excluding it. Southern Companies state the Commission should clarify
that participant funding is only impermissible as a cost allocation
method if there are identified beneficiaries and those beneficiaries
would receive non-trivial, direct benefits and would be expected to
participate in the facilities as a transmission customer or co-owner
but for others valuing the new transmission facility more and agreeing
to go ahead and support the project financially.
    723. Southern Companies repeats arguments made above that the
Supreme Court held the FPA is premised on the concept of voluntary sale
and purchase of jurisdictional services and the courts have uniformly
applied cost causation principles only in the setting of relationships
where privity exists. Therefore, it asserts that participant funding
may well be the only cost allocation method or rate structure that is
lawful for new regional and/or interregional transmission projects as
envisioned by Order No. 1000. Southern Companies assert that without a
privity relationship between the developer of a project and those
expected to fund the project, there is no lawful basis upon which to
impose a rate, and no assurance that any rate would be in connection
with the provision of a jurisdictional service. Large Public Power
Council and Ad Hoc Coalition of Southeastern Utilities also state that
the Commission's rejection of participant funding confounds a basic
precept of the FPA that a utility's ability to recover its costs rests
on a contractual relationship with its customers.
    724. Southern Companies assert participant funding is consistent
with cost causation and represents a proven-way of getting the costs of
such regional and/or interregional transmission facilities allocated,
paid and constructed on a timely basis.\847\ Southern Companies add
that given the Commission's objective to foster more development,
categorical ex ante exclusion of a cost allocation method that has a
proven track record of success does not reflect reasoned decision
making. Large Public Power Council also believes that the only
economically sound way to determine what facilities should be built,
and at what price, is to have those entities that will use the
facilities pay for them.
---------------------------------------------------------------------------

    \847\ Southern Companies at 109 (citing Bryan K. Hill September
28, 2010 Affidavit at 31-32).
---------------------------------------------------------------------------

    725. On the other hand, Transmission Dependent Utility Systems
commend the Commission's ruling that participant funding cannot be used
as a regional or interregional cost allocation method. Transmission
Dependent Utility Systems also request that the Commission reaffirm its
long-held policy prohibiting ``and'' pricing.\848\ Transmission
Dependent Utility Systems assert the Commission should confirm that any
limited use of participant funding in the future will be bound by the
Commission's same long-standing precedent.\849\
---------------------------------------------------------------------------

    \848\ Transmission Dependent Utility Systems at 31 (citing
Standardization of Generator Interconnection Agreements and
Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146, at P 694
n.111 (2003), order on reh'g, Order No. 2003-A, FERC Stats. & Regs.
] 31,160 (2004), order on reh'g, Order No. 2003-B, FERC Stats. &
Regs. ] 31,171 (2004), order on reh'g, Order No. 2003-C, FERC Stats.
& Regs. ] 31,190 (2005), aff'd sub. nom. Nat'l Ass'n of Regulatory
Utils. Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007)).
    \849\ Transmission Dependent Utility Systems at 31 (citing
Inquiry Concerning the Comm'n's Transmission Pricing Policy for
Transmission Services Provided by Pub. Utils. Under the Fed. Power
Act, 55 Fed. Reg. 55,031, FERC Stats. & Regs. ] 31,005, at 31,142-43
(1994), clarified, 71 FERC ] 61,195 (1995); Am. Elec. Power Co., 67
FERC ] 61,168 (1994)); see also Pennsylvania Elec. Co. v. FERC, 11
F.3d 207 (D.C. Cir. 1993).
---------------------------------------------------------------------------

c. Commission Determination
    726. We affirm Order No. 1000's determination that participant
funding is permitted, but not as a regional or interregional cost
allocation method.\850\ We therefore continue to believe that if
proposed as a regional or interregional cost allocation method,
participant funding will not comply with the regional or interregional
cost allocation principles adopted above. We remain concerned that
reliance on participant funding as a regional or interregional cost
allocation method increases the incentive of any individual beneficiary
to defer investment in the hopes that other beneficiaries will value a
transmission project enough to fund its development. Because of this,
it is likely that some transmission facilities identified in the
regional transmission planning process as more efficient or cost-
effective solutions would not be constructed in a timely manner or
would not be constructed at all, adversely affecting ratepayers.
Moreover, reliance on participant funding as a regional or
interregional cost allocation method leaves a transmission developer
with no opportunity to allocate costs to beneficiaries identified in
the regional transmission planning process, even if the developer's
transmission facility is identified as a more efficient or cost-
effective solution and is selected in the regional transmission plan
for purposes of cost allocation. In light of this prospect, a
transmission developer may decline to propose such a transmission
facility in the regional transmission planning process.
---------------------------------------------------------------------------

    \850\ See Order No. 1000, FERC Stats. & Regs. ] 31,323 at PP
723-29.
---------------------------------------------------------------------------

    727. The Commission rejected participant funding as a regional or
interregional cost allocation method because it does not comply with
the regional or interregional cost allocation principles set forth in
Order No. 1000. This is because participant funding by its nature does
not assess transmission project benefits in regional or interregional
terms. For this reason, it does not ensure that the allocation of costs
will be roughly commensurate with benefits, since its focus is limited
to transmission project participants rather than the regional or
interregional impact of a transmission project. Many petitioners
describe what they consider to be advantages of participant funding,
but these descriptions and the arguments based on them do not show how
participant funding satisfies the

specific requirements or policy goals of Order No. 1000.
    728. However, as Order No. 1000 made clear, we are not finding that
participant funding leads to improper results in all cases. For
example, a transmission developer may propose a project to be selected
in the regional transmission plan for purposes of regional cost
allocation but fail to satisfy the transmission planning region's
criteria for a transmission project selected in the regional
transmission plan for purposes of cost allocation. Under such
circumstances, the developer could either withdraw its transmission
project or proceed to ``participant fund'' the transmission project on
its own or jointly with others. In addition, it is possible that the
developer of a facility selected in the regional transmission plan for
purposes of cost allocation might decline to pursue regional cost
allocation and, instead, rely on participant funding. Moreover, nothing
in Order No. 1000 forecloses the opportunity for a transmission
developer, a group of transmission developers, or one or more
individual transmission customers to voluntarily assume the costs of a
new transmission facility. Accordingly, Order No. 1000 does not
prohibit or, as Southern Companies assert, ``categorically'' exclude
the use of participant funding.
    729. The Commission nowhere intended to suggest that participant
funding has no place in the development of transmission infrastructure.
As noted by Southern Companies, participant funding can result in
timely construction of transmission facilities in many circumstances.
Transmission developers who see particular advantages in participant
funding remain free to use it on their own or jointly with others. This
simply means that they would not be pursuing regional or interregional
cost allocation. ELCON, AF&PA, and the Associated Industrial Groups do
not explain what they mean by the use of participant funding ``as the
default for certain types of projects,'' \851\ and we are not persuaded
that the type of transmission project involved affects the ability of
participant funding to satisfy the cost allocation principles of Order
No. 1000.
---------------------------------------------------------------------------

    \851\ ELCON, AF&PA, and the Associated Industrial Groups at 16.
---------------------------------------------------------------------------

    730. The Commission did not state in Order No. 1000 that entities
who support participant funding must show that it is uniquely the cost
allocation method that follows ``but for'' cost causation principles,
as ELCON, AF&PA, and the Associated Industrial Groups contend. The
Commission simply stated that entities who had argued that it was such
a method had not demonstrated that this was the case and that,
moreover, the contention was at odds with existing precedent on cost
causation.\852\
---------------------------------------------------------------------------

    \852\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 726.
---------------------------------------------------------------------------

    731. Southern Companies maintain that participant funding means
different things to different people and that the Commission should
define it more narrowly for purposes of Order No. 1000. However,
Southern Companies do not describe the different meanings of
participant funding that they have in mind, and we therefore do not
know what further refinements it believes would be in order.\853\ The
Commission stated in Order No. 1000 that ``[u]nder a participant
funding approach to cost allocation, the costs of a transmission
facility are allocated only to those entities that volunteer to bear
those costs.'' \854\ In addition, the Commission noted in Order No.
1000 that the Proposed Rule cited to a number of concrete examples of
the participant funding approach.\855\ We think that this provides
sufficient guidance on the meaning of participant funding for purposes
of Order No. 1000.
---------------------------------------------------------------------------

    \853\ Southern Companies only state that the Commission's
``categorical exclusion'' of participant funding had created a need
to state specifically in Order No. 1000 (in response to Entergy)
that prohibition of participant funding as a regional cost
allocation mechanism ``is not intended to modify existing pro forma
OATT transmission service mechanisms for individual transmission
service requests or requests for interconnection service.'' Southern
Companies at 106 (quoting Order No. 1000, FERC Stats. & Regs. ]
31,323 at P 729). Southern Companies state that specifying this was
important because long-term firm transmission service is a form of
participant funding that addresses free rider issues, and this
demonstrates the need for greater clarity on what the Commission is
prohibiting. Id. However, Order No. 1000 does not create a
``categorical exclusion'' of participant funding, only an exclusion
of the use of participant funding as a regional cost allocation
method. We therefore do not see how the continued use of existing
mechanisms for individual transmission service requests affects our
conclusions on the use of participant funding for new transmission
facilities selected in a regional transmission plan for purposes of
cost allocation. As a result, we do not see the need for further
refinements in the meaning of participant funding for purposes of
Order No. 1000. We think that the two very different contexts at
issue in Southern Companies' argument--firm transmission service
requests and regional transmission planning--make such analogies
inappropriate.
    \854\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 486
n.375 (citing Proposed Rule, FERC Stats. & Regs. ] 32,660 at P 128).
    \855\ Id. See Proposed Rule, FERC Stats. & Regs. ] 32,660 at P
128.
---------------------------------------------------------------------------

    732. We disagree that precluding participant funding as a regional
and interregional cost allocation method creates a new free rider
problem by creating an incentive for what ELCON, AF&PA, and the
Associated Industrial Groups describe as entities who should be funding
a transmission project not to fund it in the hope of an allocation to
additional beneficiaries. The primary goal of Order No. 1000's cost
allocation principles is to ensure that costs of regional transmission
facilities selected in a regional transmission plan for purposes of
cost allocation are allocated to beneficiaries in the region roughly
commensurate with the benefits that they receive. It is unlikely that
entities which benefit from such transmission facilities would decline
to fund them. Moreover, we disagree with the argument that preclusion
of participant funding as a regional or interregional cost allocation
method creates an incentive not to develop a transmission project. On
the contrary, a transmission developer will have the option of using
participant funding or submitting its transmission project for
evaluation in the regional transmission planning process to be selected
for regional or interregional cost allocation. If its transmission
project is selected in the regional transmission plan for purposes of
cost allocation, the transmission developer would be able to allocate
costs to beneficiaries consistent with the relevant cost allocation
method, an opportunity that not only encourages development but also
promotes development of more efficient or cost-effective transmission
solution to regional and interregional transmission needs.
    733. We think that this point helps illuminate why participant
funding does not constitute an appropriate regional or interregional
cost allocation method. Entities that might develop a transmission
project through participant funding remain free to do so. However,
exclusive reliance on such an approach creates an incentive not to
consider potential regional or interregional transmission needs. It
thus is not a method that is tailored to promote better regional and
interregional transmission planning.
    734. We deny Southern Companies' request for clarification on the
situations in which participant funding should be impermissible.
Southern Companies asserts that participant funding should only be
impermissible if there are identified beneficiaries and those
beneficiaries would receive non-trivial, direct benefits and would be
expected to participate in the facilities as a transmission customer or
co-owner but for others valuing the new transmission facility more and
agreeing to go ahead and support the project financially. The

focus of the cost allocation reforms of Order No. 1000 is on
transmission projects that are selected in the regional transmission
plan for purposes of cost allocation, not the circumstances under which
voluntary use of participant funding is appropriate.
    735. We disagree with ELCON, AF&PA, and the Associated Industrial
Groups who see inconsistency in the Commission's willingness to allow
consideration of postage stamp rates as a cost allocation method, but
not participant funding. As we noted above, Order No. 1000 found that a
postage stamp cost allocation method may be appropriate where all
customers within a specified transmission planning region are found to
benefit from the use or availability of a transmission facility or
class or group of transmission facilities, especially if the
distribution of benefits associated with a class or group of
transmission facilities is likely to vary considerably over the long
depreciation life of the transmission facilities amid changing power
flows, fuel prices, population patterns, and local economic
considerations.\856\ Accordingly, unlike participant funding, if such a
showing can be made, a postage stamp cost allocation would meet Cost
Allocation Principle 1's requirement that costs be allocated roughly
commensurate with benefits. Participant funding, on the other hand, is
incapable of meeting the regional or interregional cost allocation
principles set forth in Order No. 1000, because by its nature it is not
a cost allocation method that accounts for potential regional or
interregional benefits.
---------------------------------------------------------------------------

    \856\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 605.
---------------------------------------------------------------------------

    736. We clarify, in response to Transmission Dependent Utility
System's request, that Order No. 1000 did not address or change the
Commission's policy on ``and'' pricing.\857\ Order No. 1000 applies
only to transmission projects that are selected in the regional
transmission planning process for purposes of cost allocation.
Participant funding cannot be the regional or interregional cost
allocation method under Order No. 1000. Therefore, if a project's costs
are allocated under a participant funding method, by definition, it was
not selected in the regional transmission planning process for purposes
of cost allocation.\858\
---------------------------------------------------------------------------

    \857\ Standardization of Generator Interconnection Agreements
and Procedures, Order No. 2003, FERC Stats. & Regs. ] 31,146 (2003),
order on reh'g, Order No. 2003-A, FERC Stats. & Regs. ] 31,160,
order on reh'g, Order No. 2003-B, FERC Stats. & Regs. ] 31,171
(2004), order on reh'g, Order No. 2003-C, FERC Stats. & Regs. ]
31,190 (2005), aff'd sub nom. Nat'l Ass'n of Regulatory Util.
Comm'rs v. FERC, 475 F.3d 1277 (D.C. Cir. 2007), cert. denied, 552
U.S. 1230 (2008).
    \858\ The Commission made clear in Order No. 1000 that
transmission facilities that are selected in the regional
transmission plan for purposes of cost allocation may not comprise
all of the transmission facilities in the regional transmission
plan, and therefore, participant funded facilities may be included
in the regional transmission plan for other purposes. Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 63.
---------------------------------------------------------------------------

    737. Lastly, a number of petitioners argue that participant funding
is the form of cost allocation that corresponds to what they assert is
a requirement that cost allocation be premised on a contractual
relationship. As we explained above,\859\ we reject the interpretation
of the FPA that petitioners have offered, specifically that the FPA
requires a contractual relationship before rates can be assessed.
Contracts do not define or limit the benefits that a transmission
customer receives from the entire transmission grid, which the courts
have recognized in finding that the customer relationship is to the
transmission grid as a whole, rather than the dictates of
contracts.\860\ Therefore, petitioners' arguments that the Commission's
finding that participant funding cannot be the regional or
interregional cost allocation method are unfounded.
---------------------------------------------------------------------------

    \859\ See discussion supra at section 0.
    \860\ See discussion supra at section 0.
---------------------------------------------------------------------------

F. Other Cost Allocation Issues

1. Final Rule
    738. In Order No. 1000, the Commission reiterated the approach it
took in Order No. 890, requiring that generation, demand resources, and
transmission be treated comparably in the regional transmission
planning process.\861\ Also, the Commission stated that while the
consideration of non-transmission alternatives to transmission
facilities may affect whether certain transmission facilities are in a
regional transmission plan, the Commission concluded that the issue of
cost recovery for non-transmission alternatives was beyond the scope of
the cost allocation reforms adopted in Order No. 1000, which are
limited to allocating the costs of new transmission facilities.\862\
---------------------------------------------------------------------------

    \861\  Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 779.
    \862\ The Commission also recognized that, in appropriate
circumstances, alternative technologies may be eligible for
treatment as transmission for ratemaking purposes. Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 779 & n.563.
---------------------------------------------------------------------------

2. Requests for Rehearing or Clarification
    739. California State Water Project argues that on rehearing the
Commission should require all public utilities to exempt sponsors of
demand-based transmission alternatives from Order No. 1000's benefits-
based cost allocation, as well as apply time-sensitive cost allocation.
Specifically, it argues that customers investing in demand-based non-
transmission alternatives and sponsors of demand-based transmission
alternatives should not be subject to benefits-based cost allocation
that in effect imposes discriminatory double billing for both the
transmission alternative provided and for unused transmission
automatically deemed to provide benefits. Moreover, it adds that the
Commission has stated that customers' ability to modify their behavior
in response to price signals benefits the entire grid and is among the
best means of holding down costs and countering market power.\863\
---------------------------------------------------------------------------

    \863\ California State Water Project at 18 (quoting Order No.
719, FERC Stats. & Regs. ] 31,281 at P 41).
---------------------------------------------------------------------------

    740. California State Water Project also argues that the rule
unduly discriminates against demand-based non-transmission alternatives
as it stressed the need for clear cost allocation to promote
transmission construction, yet declined to consider compensation and
cost allocation for demand-based non-transmission alternatives.
California State Water Project states that in the Energy Policy Act of
2005 Congress declared that the national policy of the United States is
to promote demand response and to eliminate unnecessary barriers to
demand response.\864\ It also states that the Commission followed up on
this policy in Order No. 719, stating that ``[a]ny reforms must ensure
that demand response resources are treated on a basis comparable to
other resources.'' \865\ California State Water Project adds that under
the FPA the Commission also must not permit undue discrimination
against such resources. It notes that the Commission has applied this
principle to avert undue discrimination against various kinds of
resources, such as the measures to remedy undue discrimination against
non-incumbent transmission developers in Order No. 1000.\866\
---------------------------------------------------------------------------

    \864\ California State Water Project at 9-10 (citing Energy
Policy Act of 2005, Pub. L. 109-58, Sec.  1252(f), 119 Stat. 594
(2005)).
    \865\ California State Water Project at 10 (quoting Order No.
719, FERC Stats. & Regs. ] 31,281 at P 14).
    \866\ California State Water Project at 11 (citing Order No.
888, FERC Stats. & Regs. ] 31,036 at 31,669; Order No. 1000, FERC
Stats. & Regs. ] 31,323 at P 229).
---------------------------------------------------------------------------

    741. California State Water Project recommends that the Commission

incorporate benchmarks or metrics to support periodic evaluation of its
success or failure in achieving nondiscriminatory promotion of both
physical transmission upgrades and non-transmission alternatives. It
argues that incorporating such benchmarks will ensure that the
Commission and all concerned undertake appropriate improvements on a
timely basis.
    742. Transmission Dependent Utility Systems point out that in their
comments during the Order No. 1000 proceeding, they requested that the
Commission align local, regional and interregional planning and cost
allocation processes and methods with formula rate protocols because
those who pay the costs of needed new transmission infrastructure
should not learn about projects for the first time in formula rate
updates. In particular, Transmission Dependent Utility Systems argue
that to the extent project upgrade costs are not discussed in the
planning processes with stakeholders, a separate FPA section 205 filing
must be made for recovery of these costs. It argues that most public
utility transmission providers have incentive rates and that the
formula rate annual update process provides only limited opportunity to
review and challenge costs included in the formula rate update filing.
Transmission Dependent Utility Systems argue that their requested link
between formula rate cost recovery and the local and regional planning
and interregional coordination processes is within the scope of issues
raised in this proceeding because it is a safeguard needed to ensure
that load-serving customers, which pay for the costs of transmission
upgrades, have a meaningful role in the development of regional and
interregional projects and the allocation of the costs of those
projects. Transmission Dependent Utility Systems further assert that
Order No. 1000 failed to address this issue in a manner that comports
with reasoned decision-making.\867\
---------------------------------------------------------------------------

    \867\ Transmission Dependent Utility Systems at 31 (citing K N
Energy Inc. v. FERC, 968 F.2d 1295, 1303)).
---------------------------------------------------------------------------

    743. Dayton Power and Light requests clarification that the
Commission will issue a separate order on remand from the Seventh
Circuit on Opinion No. 494 \868\ in the near future that will specify a
cost allocation mechanism for new high voltage facilities that complies
with the Order No. 1000 principles.\869\ Dayton Power and Light states
that failing to issue an order on remand would lead to renewed
litigation a year from now to address the same issues using
substantially the same evidence that is already before the Commission
for decision and waste the resources of PJM members, PJM, and the
Commission and its staff.
---------------------------------------------------------------------------

    \868\ PJM Interconnection, L.L.C., 130 FERC ] 61,052 (2010).
    \869\ Dayton Power and Light at 2, 4 (citing Illinois Commerce
Commission v. FERC, 576 F.3d 470).
---------------------------------------------------------------------------

    744. Dayton Power and Light urges the Commission to state
explicitly that the use of the Distribution Factor analysis complies
with the Order No. 1000 cost allocation principles. In support, Dayton
Power and Light states that PJM has used distribution factor analysis
to allocate the costs of new PJM facilities operating at less than 500
kV without question or challenge.
3. Commission Determination
    745. We deny California State Water Project's arguments and affirm
Order No. 1000's determination that cost allocation for non-
transmission alternatives is beyond the scope of this proceeding, which
is limited to allocating the costs of new transmission facilities. In
response to California State Water Project's suggestions regarding
time-sensitive rates and the establishment of benchmarks, we affirm
Order No. 1000, and therefore, will not establish minimum requirements
governing which non-transmission alternatives should be considered or
the appropriate metrics to measure non-transmission alternatives
against transmission alternatives. We continue to believe that those
considerations are best managed among the stakeholders and the public
utility transmission providers participating in the regional
transmission planning process.\870\
---------------------------------------------------------------------------

    \870\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 155.
---------------------------------------------------------------------------

    746. We deny Transmission Dependent Utility Systems' request that
we address a link between formula rates and cost allocation as beyond
the scope of this proceeding. As we note above, and as we found in
Order No. 1000, we are not addressing cost recovery issues here.\871\
In any event, we disagree with Transmission Dependent Utility Systems'
premise that those who pay for project upgrade costs that are selected
in a regional transmission plan for purposes of cost allocation under
the provisions of Order No. 1000 may learn about these costs for the
first time when flowed through a formula rate, when there would be only
a limited opportunity to review the costs.\872\ As is clear in Order
No. 1000, any entity can participate in the regional transmission
planning process and costs will be allocated only for those regional
and interregional transmission facilities that have been selected in
the regional transmission plan for purposes of cost allocation.\873\
Therefore, Transmission Dependent Utility Systems will have a
meaningful opportunity to participate in the development of regional
and interregional transmission projects and the allocation of the costs
of those transmission projects, whether or not these are incorporated
into formula rates, through their ability to participate in the
regional transmission planning process. Additionally, as noted above,
in identifying the benefits and beneficiaries for a new transmission
facility, the regional transmission planning process must provide
entities who will receive regional or interregional cost allocation an
understanding of the identified benefits on which the cost allocation
is based, all of which would occur prior to the recovery of such costs
through a formula rate.
---------------------------------------------------------------------------

    \871\ Id. P 563.
    \872\ In any event, we note that when ratepayers learn of other
formula costs is outside the scope of this proceeding.
    \873\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 503.
---------------------------------------------------------------------------

    747. In response to Dayton Power and Light's request that the
Commission find that the use of the distribution factor analysis
complies with Order No. 1000 cost allocation principles, we reiterate
what the Commission said in Order No. 1000 in response to commenters
making similar arguments. We decline to prejudge whether any existing
cost allocation method complies with the requirements of Order No.
1000. To the extent that Dayton Power and Light believes that to be the
case in its transmission planning region, it can take such a position
during the development of compliance proposals and during Commission
review of compliance filings.\874\ Last, with respect to the timing
concerns Dayton Power and Light describes regarding the relationship
between our order on remand from the U.S. Court of Appeals for the
Seventh Circuit on Opinion No. 494 and the development of an Order No.
1000-compliant cost allocation method in PJM, the Commission has since
issued an order in the Opinion No. 494 proceeding.\875\
---------------------------------------------------------------------------

    \874\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 565.
    \875\ PJM Interconnection, L.L.C., 138 FERC ] 61,230 (2012).
---------------------------------------------------------------------------

V. Compliance and Reciprocity

A. Compliance

1. Final Rule
    748. The Commission required that each public utility transmission
provider must submit a compliance filing within twelve months of the

effective date of Order No. 1000 revising its OATT or other document(s)
subject to the Commission's jurisdiction as necessary to demonstrate
that it meets the local and regional transmission planning and cost
allocation requirements set forth in Order No. 1000. The Commission
also required each public utility transmission provider to submit a
compliance filing within eighteen months of the effective date of Order
No. 1000 revising its OATT or other document(s) subject to the
Commission's jurisdiction as necessary to demonstrate that it meets the
requirements set forth therein with respect to interregional
transmission coordination procedures and an interregional cost
allocation method or methods.\876\
---------------------------------------------------------------------------

    \876\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 792.
---------------------------------------------------------------------------

2. Requests for Rehearing or Clarification
    749. Duke requests that the Commission rule on requests for
clarification as soon as possible before issuance of an Order No. 1000
rehearing order so that stakeholders' compliance efforts are not
interrupted or entirely disrupted. MISO requests that the Commission
clarify that RTOs and ISOs are not required to make any changes to
their tariffs or processes in connection with the participation of non-
jurisdictional entities in regional or interregional planning and cost
allocation processes. According to MISO, requiring the development of a
regional plan and cost allocation process with an entity that has no
such corresponding mandate is unreasonable, and it may not be possible
to comply with such a requirement because compliance would depend
entirely on the desire of such non-jurisdictional entities to
coordinate. MISO states that at most, the Commission should require
that Commission-jurisdictional entities engage in a good faith effort
at regional coordination, planning, and cost allocation with non-
jurisdictional entities.
    750. NextEra seeks clarification that generator tie line owners
that have OATTs on file can seek waiver of compliance with Order No.
1000 requirements, as the Commission has previously found that such
lines are not integrated with the regional transmission grid for
ratemaking purposes. It suggests that there may be confusion as to
whether such tie line owners can seek waiver because of use of the word
``and'' rather than ``or'' when Order No. 1000 states that entities
must seek waivers of Order Nos. 888, 889, and 890. NextEra contends
that if the Commission intended to mean ``or,'' then the vast majority
of tie line owners would not be subject to Order No. 1000.\877\ It also
urges the Commission to adopt a broad-based waiver that focuses on the
nature of a radial line, which it argues would be consistent with the
intent of the transmission planning process. NextEra argues that the
fact that such tie lines are not integrated in the transmission grid
should not be ignored. It states that the nature of a radial line does
not change simply because one tie line owner may provide
interconnection and transmission service to affiliates and have waivers
from Order Nos. 888, 889, and 890 while another may provide the same
service under an OATT to non-affiliates. NextEra states further that no
generation tie lines should be required to participate in the regional
transmission planning process unless they voluntarily choose to do
so.\878\
---------------------------------------------------------------------------

    \877\ NextEra at 16.
    \878\ NextEra at 17 (citing Southern Cal. Edison Co., 117 FERC ]
61,103 (2006); Mansfield Mun. Elec. Dept. v. New England Power Co.,
97 FERC ] 61,134 (2001)).
---------------------------------------------------------------------------

3. Commission Determination
    751. In response to Duke, we believe that addressing the requests
for clarification of Order No. 1000 in this order is appropriate. Many
of the requests for clarification are linked with requests for
rehearing and are thus best addressed in the same order. Moreover, the
Commission considered the need for providing timely clarifications in
issuing this order now, and we believe that its issuance now allows
stakeholders adequate time to address these clarifications in their
compliance processes.
    752. We clarify for MISO that a public utility transmission
provider will not be deemed out of compliance with Order No. 1000 if it
demonstrates that it made a good faith effort, but was ultimately
unable, to reach resolution with neighboring non-public utility
transmission providers on a regional transmission planning process,
interregional transmission coordination procedures, or a regional or
interregional cost allocation method.
    753. In response to NextEra, we clarify that Order No. 1000's
determination that it ``applies to public utilities that own, control
or operate interstate transmission facilities other than those that
have received waiver of the obligation to comply with Order Nos. 888,
889, and 890'' \879\ was meant to provide assurance to those entities
that have existing waivers of those three rules that they would not
also have to seek waiver of Order No. 1000 in order to obtain waiver
from it. This is consistent with the approach the Commission took to
waivers in Order No. 890.\880\ This determination, however, was not
meant to affect the ability of an entity that does not have a waiver to
seek one. The Commission will entertain requests for waiver of Order
No. 1000 on a case-by-case basis from any entity, including a
generation tie line owner, that believes it meets the criteria for such
waiver, which the Commission made clear in Order No. 1000 remains
unchanged from that used to evaluate requests for waiver under Order
Nos. 888, 889, and 890.\881\
---------------------------------------------------------------------------

    \879\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 832.
    \880\ Order No. 890, FERC Stats. & Regs. ] 31,241 at n.105
(``The Commission clarifies that existing waivers of the obligation
to file an OATT or otherwise offer open access transmission service
in accordance with Order No. 888 shall remain in place. The reforms
to the pro forma OATT adopted in this Final Rule therefore do not
apply to transmission providers with such waivers, although we
expect those transmission providers to participate in the regional
planning processes in place in their regions, as discussed in more
detail in section V.B. Whether an existing waiver of OATT
requirements should be revoked will be considered on a case-by-case
basis in light of the circumstances surrounding the particular
transmission provider.''); see also Order No. 890-A, FERC Stats. &
Regs. ] 31,261 at P 36.
    \881\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 832.
---------------------------------------------------------------------------

B. Reciprocity

1. Final Rule
    754. In Order No. 1000, the Commission found that to maintain a
safe harbor tariff, a non-public utility transmission provider must
ensure that the provisions of that tariff substantially conform, or are
superior, to the pro forma OATT as it has been revised by Order No.
1000.\882\ The Commission stated that it was encouraged that, based on
the efforts that followed Order No. 890, both public utility and non-
public utility transmission providers collaborate in a number of
regional transmission planning processes.\883\ Therefore, the
Commission did not believe it was necessary to invoke its authority
under FPA section 211A, which gives it authority to require non-public
utility transmission providers to provide transmission services on a
comparable and not unduly discriminatory or preferential basis.\884\
However, the Commission stated that if it finds on the appropriate
record that non-public utility transmission providers are not
participating in the transmission planning and cost allocation
processes required by Order

No. 1000, the Commission may exercise its authority under FPA section
211A on a case-by-case basis.\885\ The Commission also emphasized that
it is not modifying the scope of the reciprocity provision as
established in Order No. 890.\886\ However, the Commission noted that
it expects all public and non-public utility transmission providers in
an existing regional transmission planning process comprised of both
public and non-public utility transmission providers to participate in
the transmission planning and cost allocation processes set forth in
Order No. 1000. The Commission also noted that those non-public utility
transmission providers that take advantage of open access under an
OATT, including the OATT's new provisions for improved transmission
planning and cost allocation, should be expected to follow the same
requirements as public utility transmission providers.\887\
---------------------------------------------------------------------------

    \882\ Id. P 815.
    \883\ Id.
    \884\ Id.
    \885\ Id.
    \886\ Id. P 816.
    \887\ Id. P 818.
---------------------------------------------------------------------------

2. Requests for Rehearing or Clarification
    755. Petitioners request rehearing of Order No. 1000's reciprocity
requirement, arguing that the Commission is changing the scope of the
principle of reciprocity under Order Nos. 888 and 890. For example,
Large Public Power Council states that reciprocity as initially
conceived in Order No. 888 was a matter of fundamental fairness. It
states that this concept was clarified in Order No. 2004-A, where the
Commission found that service provided by a non-public utility
transmission provider did not have to be identical to the service
provided by an investor-owned utility, only comparable to the service
the non-public utility would receive for its own purposes. Large Public
Power Council explains that Order No. 1000 appears to hold that a non-
public utility's obligation to provide reciprocal service outside a
safe harbor tariff includes an obligation to participate in the
planning and cost allocation processes implemented pursuant to Order
No. 1000. Large Public Power Council states that including these
planning and cost allocation obligations within a non-public utility's
reciprocity obligations would modify the scope of reciprocity, and thus
requests that the Commission clarify whether this is its intention.
    756. Likewise, National Rural Electric Coops state that it appears
that the Commission misstated the reciprocity requirement in Order No.
1000 when it stated in paragraph 819 that ``the non-public utility
transmission provider that owns, controls or operates transmission
facilities must provide comparable transmission service that it is
capable of providing on its own system.'' \888\ They assert that under
the Commission's existing reciprocity requirement, a non-public utility
transmission provider is not obligated to provide such service, because
a public utility transmission provider is not obligated to refuse to
provide service if a non-public utility transmission provider does not
reciprocate. Rather, they point out that there are three alternatives
available to non-public utilities to meet the reciprocity requirement,
including obtaining a waiver from, or entering into a bilateral
agreement with, the public utility transmission provider from which the
non-public utility seeks service, and that providing service under a
safe harbor tariff is only one alternative. National Rural Electric
Coops state that only a few non-public utilities have Commission-
approved reciprocity tariffs and significant disputes could arise from
the unintentional language in Order No. 1000. They state that
clarification would help to minimize controversies over the scope of
non-public utilities' obligations with respect to regional planning and
cost allocation, and would be consistent with the Commission's
statement that it is not proposing any changes to the reciprocity
provision of the pro forma OATT or any other document.
---------------------------------------------------------------------------

    \888\ National Rural Electric Coops at 5-6 (quoting Order No.
1000, FERC Stats. & Regs. ] 31,323 at P 819).
---------------------------------------------------------------------------

    757. Sacramento Municipal Utility District also states that by
asserting that all non-public utilities must abide by Order No. 1000's
transmission planning and cost allocation provisions if they take open
access service, the Commission both: (1) Eviscerates the waiver option
expressly contemplated under Order Nos. 888 and 890 and (2) creates an
automatic trigger directly at variance with the principle that non-
public utilities must reciprocate if asked to do so. Sacramento
Municipal Utility District points out that Order Nos. 888 and 890
unambiguously require safe harbor candidates to adopt tariffs that
match or exceed the terms of the pro forma OATT. It argues, however,
that the Commission's interpretation in Order No. 1000 that non-public
utilities without safe harbor tariffs that take service under open
access tariffs also are automatically bound to follow the transmission
planning and cost allocation provisions of Order No. 1000 improperly
conflates the safe harbor tariff provisions found in Order Nos. 888 and
890 since markedly different reciprocity requirements apply when a non-
public utility does not employ a safe harbor tariff.
    758. Sacramento Municipal Utility District further argues that the
Commission's longstanding policy has been that reciprocity under Order
Nos. 888 and 890 only obligates the non-public utility to provide
transmission service to individual public utility transmission
providers requesting reciprocity as a condition of obtaining their
transmission service if a non-public utility has not sought a ``safe-
harbor'' tariff.\889\ Sacramento Municipal Utility District argues that
the actual provisions of Order Nos. 888 and 890 make clear that a
reciprocity obligation is not automatic, is purely bilateral and
applies only to the transmission provider that asks the non-public
utility to reciprocate.\890\ Thus, Sacramento Municipal Utility
District states that the Commission's determination that the act of
taking service from a public utility with a regional cost allocation
plan in its open access tariff automatically triggers the non-public
utility's reciprocity obligation under Order Nos. 888 and 890
constitutes an arbitrary and unexplained departure from the policies
established in those orders.\891\
---------------------------------------------------------------------------

    \889\ Sacramento Municipal Utility District at 3.
    \890\ Sacramento Municipal Utility District at 18 (citing
Promoting Wholesale Competition Through Open Access Non-
discriminatory Transmission Serv. By Pub. Utils; Recovery of
Stranded Costs by Pub. Utils. And Transmitting Utils., Order No.
888-A, FERC Stats. & Regs. ] 31,048, at P 30, 180-81(1997)).
    \891\ Sacramento Municipal Utility District at 3 (citing FCC v.
Fox Television Stations, Inc., 129 S. Ct. 1800, 1811 (2009); Greater
Boston Television Corp. v. FCC, 444 F.2d 841, 952 (D.C. Cir. 1970),
cert. denied, 403 U.S. 923 (1971)).
---------------------------------------------------------------------------

    759. Bonneville Power further argues that the Commission is
inappropriately attempting to regulate Bonneville Power and other non-
public utility transmission providers under section 206 of the FPA. In
support, Bonneville Power asserts that the Commission's action is more
extreme than its attempt to impose refund liability on non-public
utilities in, for example, BPA v. FERC.\892\ Bonneville Power contends
that in that case, the court held the Commission lacked refund
authority over non-public utilities that participated in a power market
established by a public utility. Bonneville Power argues that the
Commission is similarly imposing cost responsibility on non-public
utilities under section 206 absent statutory authority to do so.
Bonneville Power contends that if the Commission denies

clarification that the regional planning process determination would
not be binding on Bonneville Power and that instead, it and
transmission developers could use the cost allocation analysis as input
to their negotiations and other required statutory processes, then the
Commission is directly regulating Bonneville Power by not allowing
Bonneville Power to follow its own statutory authority in implementing
cost allocation in place of the Commission's policy adopted under
section 206, which the Commission cannot do.
---------------------------------------------------------------------------

    \892\ Bonneville Power at 17 (citing BPA v. FERC, 422 F.3d 908,
921 (9th Cir. 2005)).
---------------------------------------------------------------------------

    760. Sacramento Municipal Utility District argues that the
Commission lacks the authority to mandate regional transmission
planning and therefore it cannot attach an obligation to accept the
cost allocation agreement negotiated under a regional transmission
planning process that the non-public utility was not mandated to join.
Sacramento Municipal Utility District therefore contends that since
non-public utilities under section 201(f) are not subject to section
205 and 206, they cannot be required as a condition of reciprocity to
accept cost allocation agreements that the Commission has no authority
to impose even on public utilities.
    761. Sacramento Municipal Utility District states that when a non-
public utility takes service from a jurisdictional public utility, it
will pay a tariff rate approved by the Commission, and a reciprocity
provision is simply unnecessary to ensure proper cost recovery.
Sacramento Municipal Utility District argues that if the non-public
utility takes no service from a transmission provider that has
constructed a new facility approved by a regional transmission planning
body, and the costs of that facility are not properly included in the
rates of other transmission providers from whom the non-public utility
does take service, the reciprocity provision should be completely
inapplicable.
    762. Moreover, Sacramento Municipal Utility District argues that
cost allocation is not a transmission service so that a non-public
utility requesting only transmission service can be deemed to have
reciprocated only by participating in regional cost allocation.
Similarly, Bonneville Power contends that the Commission should not
condition a non-jurisdictional transmitting utility's ability to
receive transmission service from a public utility on the non-
jurisdictional utility's inclusion of Order No. 1000's planning and
cost allocation reforms in its own tariff because the provisions of
Order No. 1000 go well beyond the basic provision of transmission
service and are not the type of provisions that reasonably fall within
the reciprocity construct.
    763. Edison Electric Institute seeks clarification that section 6
of the OATT, which codifies the reciprocity requirement, enables a
public utility to refuse transmission service to unregulated
transmitting utilities that refuse to participate in regional
transmission planning and cost allocation processes. Furthermore,
Edison Electric Institute seeks clarification that, to satisfy the
reciprocity requirements, unregulated transmitting utilities must
fulfill each of the compliance requirements imposed on public
utilities. If unregulated transmitting utilities do not, then Edison
Electric Institute argues that the Commission should clarify that they
have failed to offer the ``comparable'' service required under section
6 of the OATT.
    764. Large Public Power Council seeks clarification that the
Commission did not intend that it would enforce reciprocity tariff
provisions itself. Large Public Power Council states that if the
Commission does intend to enforce the reciprocity provisions itself,
Large Public Power Council seeks rehearing. Large Public Power Council
argues that to date, the Commission has not intimated that it has
authority to enforce these provisions with respect to a non-public
utility, which is consistent with case law finding that a non-public
utility's involvement in Commission-jurisdictional service does not
authorize the Commission to regulate the non-public utility.
    765. Other petitioners argue that the Commission does not have
authority under section 211A to compel a non-public utility
transmission provider to participate in planning or pay for regional or
interregional transmission projects.\893\ For instance, Large Public
Power Council asserts that section 211A makes it plain that the
Commission's authority is limited to compelling a non-public utility to
provide transmission service at rates and on terms and conditions that
are essentially inward looking. As such, Large Public Power Council
contends that the Commission cannot redefine the terms under which
service is to be provided under section 211A in a manner that would
give the Commission broader authority than that given by Congress.
Accordingly, it states that the Commission does not have the authority
to compel non-public utilities to contribute to new regional or
interregional cost allocation mechanisms, or to operate according to
Commission-approved transmission plans directing the level and nature
of transmission investment.
---------------------------------------------------------------------------

    \893\ See, e.g., Large Public Power Council; Sacramento
Municipal Utility District; and Bonneville Power.
---------------------------------------------------------------------------

    766. Sacramento Municipal Utility District asserts that section
211A of the FPA makes clear that the comparability the Commission is
empowered to enforce is comparability to the transmission services the
non-public utility provides to itself, and that if a non-public utility
chooses not to participate in a regional cost allocation process as
part of its service to itself, it cannot be compelled to participate or
to accept a regional cost allocation plan under section 211A.
Bonneville Power contends that the Commission is inappropriately
attempting to indirectly regulate non-public utility transmission
providers by suggesting that it will use section 211A to obtain their
compliance with mandatory cost allocation. Sacramento Municipal Utility
District and Bonneville Power, therefore, argue that the Commission
should remove its statement that it will use section 211A against non-
public utility transmission providers to obtain compliance with Order
No. 1000. Sacramento Municipal Utility District alternatively urges the
Commission to clarify that its interpretation is not binding and is
without prejudice to the rights of non-public utilities to challenge
such an interpretation in any actual case in which the Commission
invokes the authority to mandate non-public utility participation in
regional planning and cost allocation.
    767. On the other hand, Edison Electric Institute argues that the
Commission erred by relying on non-public utility transmission
providers to voluntarily participate in regional transmission planning
and cost allocation processes.\894\ Edison Electric Institute argues
that the Commission should have exercised its authority under section
211A to ensure that unregulated transmitting utilities comply with the
transmission planning and regional cost allocation provisions on the
same terms and conditions as jurisdictional public utilities. Edison
Electric Institute also asserts that the Commission has not
demonstrated or otherwise explained why mandatory action is required in
the case of public utility but is not required for non-public utility
transmission providers. Edison Electric Institute asserts that both
sets of utilities own transmission facilities, provide transmission
service to customers, and may currently

participate in regional transmission planning processes.
---------------------------------------------------------------------------

    \894\ Edison Electric Institute at 26 (citing Order No. 1000,
FERC Stats. & Regs. ] 31,323 at P 815).
---------------------------------------------------------------------------

    768. Edison Electric Institute asserts that the Commission is
authorized through section 211A to act ``by rule'' to require
unregulated transmitting utilities to remedy discriminatory
transmission rates and practices.\895\ Edison Electric Institute states
that the Commission has recognized that section 211A allows it to
require an unregulated transmitting utility to provide transmission
services on a comparable and not unduly discriminatory basis. Edison
Electric Institute further states that section 211A contains the same
``unduly discriminatory or preferential'' standard found in section
206. Thus, Edison Electric Institute concludes that FPA section 211A,
along with section 206, vests the Commission with the duty to eliminate
undue discrimination and to ensure open access to transmission across
the entire interstate grid.
---------------------------------------------------------------------------

    \895\ Edison Electric Institute at 27 (quoting 16 U.S.C. 824j-
1(b)).
---------------------------------------------------------------------------

    769. Edison Electric Institute argues that the Commission's
decision to rely on voluntary compliance is ill-founded and inadequate
because there is no indication that non-jurisdictional utilities will
voluntarily comply. It also argues that since Order No. 888, non-
jurisdictional utilities have not fully embraced voluntary compliance
with the Commission's open access reforms. Furthermore, Edison Electric
Institute argues that allowing non-public utilities to participate
voluntarily injects uncertainty in transmission planning and cost
allocation, especially in areas that are predominately served by
unregulated entities. Edison Electric Institute asserts that
participants in regional transmission planning and cost allocation
processes should not have to wait to know whether an unregulated
transmitting utility, and potential beneficiary of a transmission
project, is going to be subject to regional cost allocation. Edison
Electric Institute adds that it also is unclear if, when, and how the
Commission will exercise its authority under section 211A. Edison
Electric Institute asserts that the lack of certainty, layered on to
the short period for compliance, will undermine confidence in the
planning and regional cost allocation processes and hinder their
development.
    770. Edison Electric Institute requests that the Commission clarify
and strengthen the obligations of unregulated transmitting utilities to
facilitate full compliance with regional planning and cost allocation
provisions, and make clear when and how it will act on a case-by-case
basis under section 211A. In addition, Edison Electric Institute states
that the Commission has the authority to direct unregulated
transmitting utilities to comply with the requirements in Order No.
1000, whether it learns of non-compliance through a complaint or on its
own motion. Edison Electric Institute argues that failure by the
Commission to act would be an abdication of its obligation to ensure
non-discriminatory treatment in transmission service.
3. Commission Determination
    771. In response to petitioners who are concerned that the
Commission is modifying the scope of the reciprocity requirement under
Order Nos. 888 and 890, we clarify that the reciprocity requirement
remains unchanged. A non-public utility transmission provider may
continue to satisfy the reciprocity condition in one of three ways.
First, it may provide service under a tariff that has been approved by
the Commission under the voluntary ``safe harbor'' provision of the pro
forma OATT. A non-public utility transmission provider using this
alternative submits a reciprocity tariff to the Commission seeking a
declaratory order that the proposed reciprocity tariff substantially
conforms to, or is superior to, the pro forma OATT. The non-public
utility transmission provider then must offer service under its
reciprocity tariff to any public utility transmission provider whose
transmission service the non-public utility transmission provider seeks
to use. Second, the non-public utility transmission provider may
provide service to a public utility transmission provider under a
bilateral agreement that satisfies its reciprocity obligation. Finally,
the non-public utility transmission provider may seek a waiver of the
reciprocity condition from the public utility transmission
provider.\896\
---------------------------------------------------------------------------

    \896\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 799 &
n.574 (citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 163
(citing Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,285-
86)).
---------------------------------------------------------------------------

    772. We affirm the Commission's determination in Order No. 1000
that to maintain a reciprocity tariff under the voluntary ``safe
harbor'' provision, a non-public utility transmission provider must
ensure that the provisions of that tariff substantially conform, or are
superior, to the pro forma OATT and its Attachment K as these have been
revised by Order No. 1000.\897\ As such, if a non-public utility
transmission provider wishes to maintain its safe harbor tariff, it
will need to ensure that it addresses Order No. 1000's transmission
planning and cost allocation reforms, so that it continues to
substantially conform, or be superior, to the pro forma OATT.
---------------------------------------------------------------------------

    \897\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 815 and
Appendix C: Pro Forma Open Access Transmission Tariff.
---------------------------------------------------------------------------

    773. As we note above, the other two ways of satisfying the
reciprocity requirement also remain intact. For example, a non-public
utility transmission provider seeking service from a public utility
transmission provider may seek to enter into a bilateral agreement with
the public utility transmission provider that addresses that public
utility transmission provider's desire for reciprocity. In such case, a
public utility transmission provider may agree to provide service to a
non-public utility transmission provider without requiring that non-
public utility transmission provider to provide reciprocal service
under terms and conditions that are necessarily substantially
conforming with, or superior to, the pro forma OATT, which includes the
transmission planning and cost allocation reforms in Order No. 1000.
With respect to such bilateral agreements, the Commission in Order No.
888-A stated that it ``must leave these agreements to case-by-case
determinations.'' \898\ In doing so, the Commission stated that the
terms and conditions that ``may be necessary for a non-public utility
to provide reciprocal service to the public utility in a bilateral
agreement is necessarily a fact-specific matter not susceptible to
resolution in a generic rulemaking proceeding.'' \899\ As such, we deny
Edison Electric Institute's request for generic clarification that
section 6 of the pro forma OATT, which codifies the reciprocity
requirement, would allow a public utility transmission provider to
refuse service to a non-public utility transmission provider that
refused to enroll in the regional transmission planning and cost
allocation processes. However, we note that in Order No. 888-A, the
Commission also made clear that ``a public utility may refuse to
provide open access transmission service to a non-public utility if its
denial is based on a good faith assertion that the non-public utility
has not met the Commission's reciprocity requirements.'' \900\ While we
will

continue to address such matters on a case-by-case basis consistent
with Order No. 888-A, we nevertheless note our finding in Order No.
1000 that those that ``take advantage of open access, including
improved transmission planning and cost allocation, should be expected
to follow the same requirements as public utility transmission
providers.'' \901\ Finally, a public utility transmission provider
remains free to waive any reciprocity requirement for a non-public
utility transmission provider that seeks service from it.
---------------------------------------------------------------------------

    \898\ Order No. 888-A, FERC Stats. & Regs. ] 31,048 at 30,289.
    \899\ Id.
    \900\ Id. This approach is also consistent with Order No. 890
where the Commission stated that ``[u]nder the reciprocity provision
in section 6 of the pro forma OATT, if a public utility seeks
transmission service from a non-public utility to which it provides
open access transmission service, the non-public utility that owns,
controls, or operates transmission facilities must provide
comparable transmission service that it is capable of providing on
its own system. Under the pro forma OATT, a public utility may
refuse to provide open access transmission service to a non-public
utility if the non-public utility refuses to reciprocate.'' Order
No. 890, FERC Stats. & Regs. ] 31,241 at P 163.
    \901\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 818.
---------------------------------------------------------------------------

    774. We further clarify in response to National Rural Electric
Coops that, in the absence of a safe harbor tariff, a non-public
utility transmission provider's obligation to a public utility
transmission provider to provide a comparable transmission service that
it is capable of providing on its own system begins when that public
utility transmission provider requests comparable reciprocal service
from the non-public utility transmission provider.\902\ We also clarify
for Large Public Power Council that the Commission did not intend that
it would enforce reciprocity tariff provisions sua sponte, except
insofar as the Commission permits a public utility transmission
provider to refuse to offer open access transmission service to that
non-public utility transmission provider, in accordance with Order No.
888.
---------------------------------------------------------------------------

    \902\ Id. P 819 (citing Order No. 890, FERC Stats. & Regs. ]
31,241 at P 163).
---------------------------------------------------------------------------

    775. Because the reciprocity provisions of Order Nos. 888, 890, and
1000 do not impose any requirement on non-public utility transmission
providers, we reject Bonneville Power's and Sacramento Municipal
Utility District's arguments that the Commission is attempting to
regulate non-public utility transmission providers. As the Commission
stated in Order No. 1000, non-public utility transmission providers are
free to decide whether they will seek transmission service that is
subject to the Commission's jurisdiction, and the Commission does not
exercise jurisdiction over them when it determines the terms under
which public utility transmission providers must provide that
transmission service.\903\ As such, the reciprocity provision of Order
No. 1000 does not require non-public utility transmission providers to
comply with the Order No. 1000 transmission planning and cost
allocation reforms. In addition, as explained above in the discussion
of our legal authority to implement Order No. 1000's transmission
planning reforms, we disagree with Sacramento Municipal Utility
District's contention that the Commission lacks the authority to
mandate regional transmission planning for public utility transmission
providers.\904\
---------------------------------------------------------------------------

    \903\ Id.
    \904\ See discussion supra at section 0.
---------------------------------------------------------------------------

    776. In response to Sacramento Municipal Utility District's concern
that a reciprocity provision is ``unnecessary to ensure proper cost
recovery,'' \905\ and Bonneville Power's and Sacramento Municipal
Utility District's concerns that the transmission planning and cost
allocation reforms should be outside the reciprocity construct, we
disagree. Any non-public utility transmission provider that takes
transmission service from a public utility transmission provider after
implementation of Order No. 1000 is likely to benefit from the new OATT
provisions of the public utility transmission providers in that region
providing for improved regional transmission planning and for regional
cost allocation commensurate with benefits for selected facilities, as
provided in Order No. 1000. We therefore in Order No. 1000 applied the
reciprocity provisions of Order Nos. 888 and 890 to provide that it is
within the Commission's discretion to allow a public utility
transmission provider to refuse to offer open access transmission
service to any non-public utility transmission provider that does not
provide comparable reciprocal transmission service insofar as it is
capable of doing so, including regional planning and cost allocation.
However, we reiterate a clarification made above that it is only when a
non-public utility transmission provider actually makes the choice to
become part of a transmission planning region by enrolling in that
region that it would be subject to the regional and interregional cost
allocation methods for that region.\906\
---------------------------------------------------------------------------

    \905\ Sacramento Municipal Utility District at 20.
    \906\ See discussion supra at section 0.
---------------------------------------------------------------------------

    777. In response to Bonneville Power's and Sacramento Municipal
Utility District's contention that certain provisions of Order No.
1000, such as those relating to cost allocation, go beyond the
provision of transmission service and thus should not be incorporated
in the Commission's reciprocity condition, we reiterate that both
transmission planning and cost allocation are integral and essential
components of the provision of transmission service. The transmission
planning and cost allocation reforms adopted in Order No. 1000 are
intended to facilitate the development of a robust transmission system
capable of providing improved open access transmission service and to
help ensure that transmission rates are just and reasonable and not
unduly discriminatory or preferential.
    778. We decline to address petitioners' arguments concerning the
scope of our authority under FPA section 211A in this proceeding
because the Commission did not act under FPA section 211A in Order No.
1000.\907\ As the Commission stated in Order No. 1000, the success of
the transmission planning process set forth therein will be enhanced if
all transmission owners participate. The Commission further stated that
non-public utility transmission providers will benefit greatly from the
improved transmission planning and cost allocation processes required
for public utility transmission providers because a well-planned grid
is more reliable and provides more available, less congested paths for
the transmission of electric power in interstate commerce.\908\
---------------------------------------------------------------------------

    \907\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 821.
    \908\ Id. P 818.
---------------------------------------------------------------------------

VI. Information Collection Statement

    779. The Office of Management and Budget (OMB) requires that OMB
approve certain information collection and data retention requirements
imposed by agency rules.\909\ Upon approval of a collection(s) of
information, OMB will assign an OMB control number and an expiration
date. Respondents subject to the filing requirements of a rule will not
be penalized for failing to respond to these collections of information
unless the collections of information display a valid OMB control
number.
---------------------------------------------------------------------------

    \909\ 5 CFR 1320.11(b).
---------------------------------------------------------------------------

    780. Previously, the Commission submitted to OMB the information
collection requirements arising from Order No. 1000 and OMB approved
those requirements. In this order, the Commission is making no
substantive changes to those requirements, but has provided
clarifications that require public utility transmission providers, and
transmission developers, to collect additional information. Therefore,
the Commission finds it necessary to make

a formal submission to OMB for review and approval under section
3507(d) of the Paperwork Reduction Act of 1995.\910\
---------------------------------------------------------------------------

    \910\ 44 U.S.C. 3507(d).
---------------------------------------------------------------------------

    781. The burden estimates in this order on rehearing and
clarification of Order No. 1000 represent the incremental burden
changes related only to the new and revised requirements set forth in
this order. It also should be noted that the burden estimates are
averages for all of the filers.
    Burden Estimate and Information Collection Costs: The estimated
Public Reporting burden and cost for the new and revised requirements
contained in this order follow.

--------------------------------------------------------------------------------------------------------------------------------------------------------
                                           Annual  number                                                                                Total annual
   FERC-917--New and revised reporting           of        Annual  number                                                  Total annual      hours in
 requirements in order 1000-A in RM10-23     respondents    of  responses                Hours per response               hours in  year    subsequent
                                              (Filers)                                                                           1             years
--------------------------------------------------------------------------------------------------------------------------------------------------------
Transmission Providers (TP) develop &                 132               1  2 in Year 1; 1 in Yrs. 2 & 3.................             264             132
 maintain enrollment process defining how
 entities make choice to become part of
 trans. planning region; and include (&
 maintain) in OATT a list of all pub. &
 non-pub. utility trans. providers
 enrolled as TP in planning region.
Transmission Developers (TD) submit                   140               1  4 (each in Yrs. 1-3).........................             560             560
 development schedule (if selected in
 regional plan for cost allocation).
TP describe in OATT how regional trans.               132               1  5 in Year 1; 0.5 in Yrs. 2&3.................             660              66
 planning process gives stakeholders
 chance to participate & how stakeholders
 & TD can propose interregional trans.
 facilities for TP in neighboring region
 to evaluate jointly.
To the extent that a TP considers either              132               1  18 in Year 1; 1 in Yrs. 2&3..................           2,376             132
 cost containment or cost recovery
 provisions as part of cost allocat.
 method for regional or interregional
 facility, such provisions may be
 included in its compliance filing.
                                          --------------------------------------------------------------------------------------------------------------
    Total Estimated Additional Burden      ..............  ..............  .............................................           3,860             890
     Hours, for FERC-917 due to Order
     1000-A in RM10-23.
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Cost to Comply:
    Year 1: $440,040 [3,860 hours x $114 per hour \911\]
---------------------------------------------------------------------------

    \911\ The estimated cost of $114 an hour is the average of the
hourly costs of: Attorney ($200), consultant ($150), technical
($80), and administrative support ($25).
---------------------------------------------------------------------------

    Subsequent Years: $101,460 [890 hours x $114 per hour]
    Title: FERC-917
    Action: Clarification to Collection.
    OMB Control No.: 1902-0233.
    Respondents: Transmission Developers and Public Utility
Transmission Providers. An RTO or ISO also may file some materials on
behalf of its members.
    Frequency of Responses: Initial filing and subsequent filings.
    Necessity of the Information:
    782. Building on the reforms in Order No. 890, the Federal Energy
Regulatory Commission provides these clarifications to the amendments
to the pro forma OATT to correct certain deficiencies in the
transmission planning and cost allocation requirements for public
utility transmission providers adopted in Order No. 1000. The purpose
of Order No. 1000 is to strengthen the pro forma OATT, so that the
transmission grid can better support wholesale power markets and ensure
that Commission-jurisdictional services are provided at rates, terms,
and conditions that are just and reasonable and not unduly
discriminatory or preferential. We expect to achieve this goal through
Order No. 1000 by reforming electric transmission planning requirements
and establishing a closer link between cost allocation and regional
transmission planning processes.
    783. Interested persons may obtain information on reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street NE., Washington, DC 20426 [Attention:
Ellen Brown, Office of the Executive Director, email:
<EMAIL_ADDRESS>Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>.
Comments concerning the collection of information and the associated
burden estimate(s), may also be sent to the Office of Information and
Regulatory Affairs, Office of Management and Budget, 725 17th Street
NW., Washington, DC 20503 [Attention: Desk Officer for the Federal
Energy Regulatory Commission, phone:<PHONE_NUMBER>, fax (202) 395-
7285]. Due to security concerns, comments should be sent electronically
to the following email address<EMAIL_ADDRESS>Comments
submitted to OMB should include OMB Control No. 1902-0233 and Docket
No. RM10-23-001.

VII. Document Availability

    784. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through the Commission's Home Page (http://www.ferc.gov) and
in the Commission's Public Reference Room during normal business hours
(8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street NE., Room 2A,
Washington, DC 20426.
    785. From the Commission's Home Page on the Internet, this
information is available on eLibrary. The full text of this document is
available on eLibrary in PDF and Microsoft Word format for viewing,
printing, and/or downloading. To access this document in eLibrary,

type the docket number excluding the last three digits of this document
in the docket number field.
    786. User assistance is available for eLibrary and the Commission's
Web site during normal business hours from FERC Online Support at 202-
502-6652 (toll free at 1-866-208-3676) or email at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. Email the Public Reference Room at
<EMAIL_ADDRESS>
VIII. Effective Date and Congressional Notification

    787. Changes to Order No. 1000 made in this order on rehearing and
clarification will be effective on July 2, 2012. The Commission has
determined, with the concurrence of the Administrator of the Office of
Information and Regulatory Affairs of OMB, that this rule on rehearing
and clarification of Order No. 1000 is not a ``major rule'' as defined
in section 351 of the Small Business Regulatory Enforcement Fairness
Act of 1996.

Nathaniel J. Davis, Sr.,
Deputy Secretary.

    Note: The following appendices will not be published in the Code
of Federal Regulations.

Appendix A: Abbreviated Names of Petitioners

------------------------------------------------------------------------
         Abbreviation                       Petitioner names
------------------------------------------------------------------------
Ad Hoc Coalition of            Central Electric Power Cooperative, Inc.;
 Southeastern Utilities.        Dalton Utilities; Georgia Transmission
                                Corporation; JEA; MEAG Power; Orlando
                                Utilities Commission; Progress Energy
                                Service Company, LLC (on behalf of
                                Progress Energy Carolinas, Inc. and
                                Progress Energy Florida, Inc.); South
                                Carolina Electric & Gas Company; South
                                Carolina Public Service Authority
                                (Santee Cooper); and Southern Company
                                Services, Inc. (on behalf of Alabama
                                Power Company, Georgia Power Company,
                                Gulf Power Company, Mississippi Power
                                Company, and Southern Power Company).
AEP..........................  American Electric Power Service
                                Corporation.
Alabama PSC..................  Alabama Public Service Commission.
Ameren.......................  Ameren Services Company.
American Transmission........  American Transmission Company LLC.
APPA.........................  American Public Power Association.
Arizona Cooperative and        Arizona Electric Power Cooperative, Inc.
 Southwestern Transmission.     and Southwest Transmission Cooperative,
                                Inc.
AWEA.........................  American Wind Energy Association.
Baltimore Gas & Electric.....  Baltimore Gas & Electric Company.
Bonneville Power.............  Bonneville Power Administration.
California ISO...............  California Independent System Operator
                                Corporation.
California State Water         California Department of Water Resources
 Project.                       State Water Project.
Coalition for Fair             CMS Energy Corporation; Consolidated
 Transmission Policy.           Edison; DTE Energy Company; Progress
                                Energy, Inc.; Public Service Enterprise
                                Group; SCANA Corporation; Southern
                                Company. \912\*
Dayton Power and Light.......  Dayton Power and Light Company (The).
Duke.........................  Duke Energy Corporation.
Edison Electric Institute....  Edison Electric Institute.
ELCON, AF&PA, and the          Electricity Consumers Resource Council,
 Associated Industrial Groups.  American Forest and Paper Association,
                                Electricity Consumers Resource Council;
                                American Chemistry Council; Association
                                of Businesses Advocating Tariff Equity;
                                Carolina Utility Customers Association;
                                Coalition of Midwest Transmission
                                Customers; Florida Industrial Power
                                Users Group; Georgia Industrial Group-
                                Electric; Industrial Energy Users--Ohio;
                                Oklahoma Industrial Energy Consumers;
                                PJM Industrial Customer Coalition; West
                                Virginia Energy Users Group; and
                                Wisconsin Industrial Energy Group.
Energy Future Coalition Group  Energy Future Coalition; American Wind
                                Energy Association; Center for Energy
                                Efficiency and Renewable Technologies;
                                Center for Rural Affairs; Climate and
                                Energy Project; Denali Energy Inc.;
                                Fresh Energy; Gradient Resources, Inc.;
                                Iberdrola Renewables; Interwest Energy
                                Alliance; Natural Resources Defense
                                Council; Project for Sustainable FERC
                                Energy Policy; Solar Energy Industries
                                Association; The Stella Group, Ltd.;
                                Union of Concerned Scientists; Western
                                Grid Group; Wind on the Wires; and
                                WIRES.*
FirstEnergy Service Company..  FirstEnergy Service Company, on behalf of
                                FirstEnergy Companies: Ohio Edison
                                Company; Pennsylvania Power Company; The
                                Cleveland Electric Illuminating Company;
                                The Toledo Edison Company; American
                                Transmission Systems, Incorporated;
                                Jersey Central Power & Light Company;
                                Metropolitan Edison Company; and
                                Pennsylvania Electric Company, and
                                FirstEnergy Solutions Corp. and their
                                respective electric utility subsidiaries
                                and affiliates.
Florida PSC..................  Florida Public Service Commission.
Georgia PSC..................  Georgia Public Service Commission.
Illinois Commerce Commission.  Illinois Commerce Commission.
ITC Companies................  International Transmission Company;
                                Michigan Electric Transmission Company,
                                LLC; ITC Midwest LLC; ITC Great Plains,
                                LLC; and Green Power Express LP.
Joint Petitioners............  American Electric Power Corp.; AWEA;
                                Iberdrola Renewables; ITC Holdings
                                Corp.; NextEra Energy, Inc.; MidAmerican
                                Energy.
Kentucky PSC.................  Kentucky Public Service Commission.
Large Public Power Council...  Austin Energy; Chelan County Public
                                Utility District No. 1; Clark Public
                                Utilities; Colorado Springs Utilities;
                                CPS Energy (San Antonio); ElectriCities
                                of North Carolina; Grant County Public
                                Utility District; IID Energy (Imperial
                                Irrigation District); JEA (Jacksonville,
                                FL); Long Island Power Authority; Los
                                Angeles Department of Water and Power;
                                Lower Colorado River Authority; MEAG
                                Power, Nebraska Public Power District;
                                New York Power Authority; Omaha Public
                                Power District; Orlando Utilities
                                Commission; Platte River Power
                                Authority; Puerto Rico Electric Power
                                Authority; Sacramento Municipal Utility
                                District; Salt River Project; Santee
                                Cooper; Seattle City Light; Snohomish
                                County Public Utility District No. 1;
                                and Tacoma Public Utilities.*

Long Island Power Authority..  Long Island Power Authority and LIPA.
LS Power.....................  LS Power Transmission, LLC.
MEAG Power...................  MEAG Power.
MISO.........................  Midwest Independent System Transmission
                                Operator, Inc.
MISO Transmission Owners       The Midwest ISO Transmission Owners for
 Group 1.                       this filing consist of: Ameren Services
                                Company, as agent for Union Electric
                                Company d/b/a Ameren Missouri, Ameren
                                Illinois Company d/b/a Ameren Illinois
                                and Ameren Transmission Company of
                                Illinois; American Transmission Company
                                LLC (``ATC''); City Water, Light & Power
                                (Springfield, IL); Dairyland Power
                                Cooperative; Great River Energy;
                                Indianapolis Power & Light Company;
                                MidAmerican Energy Company; Minnesota
                                Power (and its subsidiary Superior
                                Water, L&P); Montana- Dakota Utilities
                                Co.; Northern Indiana Public Service
                                Company; Northern States Power Company,
                                a Minnesota corporation, and Northern
                                States Power Company, a Wisconsin
                                corporation, subsidiaries of Xcel Energy
                                Inc.; Northwestern Wisconsin Electric
                                Company; Otter Tail Power Company;
                                Southern Indiana Gas & Electric Company
                                (d/b/a Vectren Energy Delivery of
                                Indiana); Southern Minnesota Municipal
                                Power Agency; and Wolverine Power Supply
                                Cooperative, Inc.
MISO Transmission Owners       The Midwest ISO Transmission Owners for
 Group 2.                       this filing consist of: Ameren Services
                                Company, as agent for Union Electric
                                Company d/b/a Ameren Missouri, Ameren
                                Illinois Company d/b/a Ameren Illinois
                                and Ameren Transmission Company of
                                Illinois; City Water, Light & Power
                                (Springfield, IL); Dairyland Power
                                Cooperative; Great River Energy; Hoosier
                                Energy Rural Electric Cooperative, Inc.;
                                Indianapolis Power & Light Company;
                                MidAmerican Energy Company; Minnesota
                                Power (and its subsidiary Superior
                                Water, L&P); Montana-Dakota Utilities
                                Co.; Northern Indiana Public Service
                                Company; Northern States Power Company,
                                a Minnesota corporation, and Northern
                                States Power Company, a Wisconsin
                                corporation, subsidiaries of Xcel Energy
                                Inc.; Northwestern Wisconsin Electric
                                Company; Otter Tail Power Company;
                                Southern Illinois Power Cooperative;
                                Southern Indiana Gas & Electric Company
                                (d/b/a Vectren Energy Delivery of
                                Indiana); Southern Minnesota Municipal
                                Power Agency; and Wolverine Power Supply
                                Cooperative, Inc.
MISO Northeast...............  MISO Northeast Transmission Customers of
                                Consumers.
NARUC........................  National Association of Regulatory
                                Utility Commissioners.
National Rural Electric Coops  National Rural Electric Cooperative
                                Association.
NV Energy....................  Nevada Power Company and Sierra Pacific
                                Power Company.
New York ISO.................  New York Independent System Operator,
                                Inc.
New York PSC.................  New York State Public Service Commission.
New York Transmission Owners.  Central Hudson Gas & Electric
                                Corporation; Consolidated Edison Company
                                of New York, Inc.; New York Power
                                Authority; Long Island Power Authority;
                                New York State Electric & Gas
                                Corporation; and Niagara Mohawk Power
                                Corporation; Orange and Rockland
                                Utilities, Inc.; and Rochester Gas and
                                Electric Corporation.
NextEra......................  NextEra Energy, Inc.
North Carolina Agencies......  North Carolina Utilities Commission and
                                Public Staff of the North Carolina
                                Utilities Commission.
Northern Tier Transmission     Northern Tier Transmission Group.
 Group.
Oklahoma Gas and Electric      Oklahoma Gas and Electric Company.
 Company.
PPL Companies................  PPL Electric Utilities Corporation; Lower
                                Mount Bethel Energy, LLC; PPL Brunner
                                Island, LLC; PPL Holtwood, LLC; PPL
                                Martins Creek, LLC; PPL Montour, LLC;
                                PPL Susquehanna, LLC; PPL University
                                Park, LLC; PPL EnergyPlus, LLC; PPL
                                GreatWorks, LLC; PPL Maine, LLC; PPL
                                Wallingford Energy, LLC; PPL New Jersey
                                Solar, LLC; PPL New Jersey Biogas, LLC;
                                PPL Renewable Energy, LLC; PPL Montana,
                                LLC; PPL Colstrip I, LLC; PPL Colstrip
                                II, LLC; Louisville Gas and Electric
                                Company; Kentucky Utilities Company; and
                                LG&E Energy Marketing LLC.*
PSEG Companies...............  Public Service Electric and Gas Company;
                                PSEG Power LLC; and PSEG Energy
                                Resources & Trade LLC.
Sacramento Municipal Utility   Sacramento Municipal Utility District.
 District.
South Carolina Regulatory      South Carolina Office of Regulatory
 Staff.                         Staff.
Southern California Edison...  Southern California Edison Company.
Southern Companies...........  Alabama Power Company; Georgia Power
                                Company; Gulf Power Company; Mississippi
                                Power Company; and Southern Power
                                Company.
Sponsoring PJM Transmission    Certain Sponsoring PJM Transmission
 Owners.                        Owners (American Transmission Systems,
                                Incorporated; Jersey Central Power &
                                Light Company; Metropolitan Edison
                                Company; Monongahela Power Company;
                                Pennsylvania Electric Company; The
                                Potomac Edison Company; Trans-Allegheny
                                Interstate Line Company; and West Penn
                                Power Company (collectively, the
                                FirstEnergy Companies); Baltimore Gas
                                and Electric Company; The Dayton Power
                                and Light Company; Duquesne Light
                                Company; Public Service Electric and Gas
                                Company; PSEG Power LLC and PSEG Energy
                                Resources & Trade LLC (collectively,
                                PSEG Companies); and Virginia Electric
                                and Power Company).
Sunflower, Mid-Kansas and      Sunflower Electric Power Corporation and
 Western Farmers.               Mid-Kansas Electric Company, LLC and
                                Western Farmers Electric Cooperative.
Transmission Access Policy     Transmission Access Policy Study Group.
 Study Group.
Transmission Dependent         Arkansas Electric Cooperative
 Utility Systems.               Corporation; Golden Spread Electric
                                Cooperative, Inc.; Kansas Electric Power
                                Cooperative, Inc.; North Carolina
                                Electric Membership Corporation; and
                                Seminole Electric Cooperative, Inc.; and
                                PowerSouth Energy Cooperative.*
Vermont Department of Public   Vermont Department of Public Service and
 Service and the Vermont        the Vermont Public Service Board
 Public Service Board.
Western Independent            Western Independent Transmission Group.
 Transmission Group.

WIRES........................  Working Group for Investment in Reliable
                                and Economic Electric Systems.
Wisconsin PSC................  Public Service Commission of Wisconsin.
Xcel.........................  Xcel Energy Services Inc.
------------------------------------------------------------------------

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

    \912\ A ``*'' indicates that the composition of this group has
changed since the Final Rule proceeding.
---------------------------------------------------------------------------

Appendix B: Pro Forma Open Access Transmission Tariff

Pro Forma OATT

Attachment K

Transmission Planning Process

Local Transmission Planning

    The Transmission Provider shall establish a coordinated, open
and transparent planning process with its Network and Firm Point-to-
Point Transmission Customers and other interested parties to ensure
that the Transmission System is planned to meet the needs of both
the Transmission Provider and its Network and Firm Point-to-Point
Transmission Customers on a comparable and not unduly discriminatory
basis. The Transmission Provider's coordinated, open and transparent
planning process shall be provided as an attachment to the
Transmission Provider's Tariff.
    The Transmission Provider's planning process shall satisfy the
following nine principles, as defined in Order No. 890:
Coordination, openness, transparency, information exchange,
comparability, dispute resolution, regional participation, economic
planning studies, and cost allocation for new projects. The planning
process also shall include the procedures and mechanisms for
considering transmission needs driven by Public Policy Requirements
consistent with Order No. 1000. The planning process also shall
provide a mechanism for the recovery and allocation of planning
costs consistent with Order No. 890.
    The description of the Transmission Provider's planning process
must include sufficient detail to enable Transmission Customers to
understand:
    (i) The process for consulting with customers;
    (ii) The notice procedures and anticipated frequency of
meetings;
    (iii) The methodology, criteria, and processes used to develop a
transmission plan;
    (iv) The method of disclosure of criteria, assumptions and data
underlying a transmission plan;
    (v) The obligations of and methods for Transmission Customers to
submit data to the Transmission Provider;
    (vi) The dispute resolution process;
    (vii) The Transmission Provider's study procedures for economic
upgrades to address congestion or the integration of new resources;
    (viii) The Transmission Provider's procedures and mechanisms for
considering transmission needs driven by Public Policy Requirements,
consistent with Order No. 1000; and
    (ix) The relevant cost allocation method or methods.

Regional Transmission Planning

    The Transmission Provider shall participate in a regional
transmission planning process through which transmission facilities
and non-transmission alternatives may be proposed and evaluated. The
regional transmission planning process also shall develop a regional
transmission plan that identifies the transmission facilities
necessary to meet the needs of transmission providers and
transmission customers in the transmission planning region. The
regional transmission planning process must be consistent with the
provision of Commission-jurisdictional services at rates, terms and
conditions that are just and reasonable and not unduly
discriminatory or preferential, as described in Order No. 1000. The
regional transmission planning process shall be described in an
attachment to the Transmission Provider's Tariff.
    The Transmission Provider's regional transmission planning
process shall satisfy the following seven principles, as set out and
explained in Order Nos. 890 and 1000: Coordination, openness,
transparency, information exchange, comparability, dispute
resolution, and economic planning studies. The regional transmission
planning process also shall include the procedures and mechanisms
for considering transmission needs driven by Public Policy
Requirements, consistent with Order No. 1000. The regional
transmission planning process shall provide a mechanism for the
recovery and allocation of planning costs consistent with Order No.
890.
    The regional transmission planning process shall include a clear
enrollment process for public and non-public utility transmission
providers that make the choice to become part of a transmission
planning region. The regional transmission planning process shall be
clear that enrollment will subject enrollees to cost allocation if
they are found to be beneficiaries of new transmission facilities
selected in the regional transmission plan for purposes of cost
allocation. Each Transmission Provider shall maintain a list of
enrolled entities in the Transmission Provider's Tariff.
    Nothing in the regional transmission planning process shall
include an unduly discriminatory or preferential process for
transmission project submission and selection.
    The description of the regional transmission planning process
must include sufficient detail to enable Transmission Customers to
understand:
    (i) The process for enrollment in the regional transmission
planning process;
    (ii) The process for consulting with customers;
    (iii) The notice procedures and anticipated frequency of
meetings;
    (iv) The methodology, criteria, and processes used to develop a
transmission plan;
    (v) The method of disclosure of criteria, assumptions and data
underlying transmission plan;
    (vi) The obligations of and methods for transmission customers
to submit data;
    (vii) Process for submission of data by nonincumbent developers
of transmission projects that wish to participate in the
transmission planning process and seek regional cost allocation;
    (viii) Process for submission of data by merchant transmission
developers that wish to participate in the transmission planning
process;
    (ix) The dispute resolution process;
    (x) The study procedures for economic upgrades to address
congestion or the integration of new resources;
    (xi) The procedures and mechanisms for considering transmission
needs driven by Public Policy Requirements, consistent with Order
No. 1000; and
    (xii) The relevant cost allocation method or methods.
    The regional transmission planning process must include a cost
allocation method or methods that satisfy the six regional cost
allocation principles set forth in Order No. 1000.

Interregional Transmission Coordination

    The Transmission Provider, through its regional transmission
planning process, must coordinate with the public utility
transmission providers in each neighboring transmission planning
region within its interconnection to address transmission planning
coordination issues related to interregional transmission
facilities. The interregional transmission coordination procedures
must include a detailed description of the process for coordination
between public utility transmission providers in neighboring
transmission planning regions (i) with respect to each interregional
transmission facility that is proposed to be located in both
transmission planning regions and (ii) to identify possible
interregional transmission facilities that could address
transmission needs more efficiently or cost-effectively than
separate regional transmission facilities. The interregional
transmission coordination procedures shall be described in an
attachment to the Transmission Provider's Tariff.
    The Transmission Provider must ensure that the following
requirements are included in any applicable interregional
transmission coordination procedures:
    (1) A commitment to coordinate and share the results of each
transmission planning region's regional transmission plans to
identify possible interregional transmission facilities that could
address transmission needs more efficiently or cost-effectively than

separate regional transmission facilities, as well as a procedure
for doing so;
    (2) A formal procedure to identify and jointly evaluate
transmission facilities that are proposed to be located in both
transmission planning regions;
    (3) An agreement to exchange, at least annually, planning data
and information; and
    (4) A commitment to maintain a Web site or email list for the
communication of information related to the coordinated planning
process.
    The Transmission Provider must work with transmission providers
located in neighboring transmission planning regions to develop a
mutually agreeable method or methods for allocating between the two
transmission planning regions the costs of a new interregional
transmission facility that is located within both transmission
planning regions. Such cost allocation method or methods must
satisfy the six interregional cost allocation principles set forth
in Order No. 1000 and must be included in the Transmission
Provider's Tariff.

[FR Doc. 2012-12418 Filed 5-30-12; 8:45 am]
BILLING CODE 6717-01-P