facilities would be most effective in meeting the needs of the broadest
set of constituents. San Diego Gas & Electric also states that little
serious consideration is given to how various project proposals could
be modified, combined, or eliminated so as to make the best possible
use of available transmission corridors, minimize adverse environmental
impacts, and enhance overarching system efficiencies.\114\
---------------------------------------------------------------------------

    \114\ San Diego Gas & Electric at 5.
---------------------------------------------------------------------------

    108. Pioneer Transmission states that it has a unique perspective
on interregional transmission planning issues, as it spent the last
year and a half working with the Midwest ISO and PJM in an effort to
develop extra high voltage transmission facilities that will be located
in both the Midwest ISO and PJM footprints. Pioneer Transmission states
that although the Midwest ISO and PJM have undertaken various studies
and have worked cooperatively with Pioneer Transmission, they have been
hampered in their efforts to assess the Pioneer project for inclusion
in their transmission plans because neither RTO has in place formal
procedures for evaluating interregional projects.\115\
---------------------------------------------------------------------------

    \115\ Pioneer Transmission at 1-2.
---------------------------------------------------------------------------

    109. The Ohio Commission states in its comments that ``[j]ust as
the development of RTOs and ISOs was encouraged to better coordinate
individual transmission owners' and operators' plans, the development
of inter-regional planning committees to review and coordinate
individual and RTO and ISO plans should be encouraged.'' \116\ The
California ISO states that it would be easier to analyze and justify
transmission facilities that would be located in more than one region
if the underlying data were consistent in all of the areas that are
part of evaluating the transmission project in question.\117\
Similarly, Public Interest Organizations & Renewable Energy Groups
state that the Commission should require coordinated transmission
infrastructure plan development by regional or interregional
transmission planning authorities informed by interconnection-wide
assessments and broad stakeholder input.
---------------------------------------------------------------------------

    \116\ Ohio Commission Comments at 6.
    \117\ California ISO at 8.
---------------------------------------------------------------------------

    110. The October 2009 Notice also recognized that proposals to
implement interconnectionwide transmission planning were being
developed in response to the above-noted funding opportunities that DOE
offered under the American Recovery and Reinvestment Act of 2009. The
October 2009 Notice observed that it was not clear whether those
activities would result in a regular process for jointly identifying
and evaluating alternatives to solutions identified in transmission
plans developed through existing transmission planning processes
conducted in accordance with Order No. 890.\118\
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    \118\ October 2009 Notice at 2-3.
---------------------------------------------------------------------------

    111. In response to the October 2009 Notice, some commenters state
that interconnectionwide transmission planning undertaken pursuant to
the ARRA should be given a chance to mature before the Commission takes
additional action with respect to transmission planning.\119\ Other
commenters emphasize that funding under the ARRA is an important one-
time opportunity, but should not be viewed as a prerequisite for
initiating or expanding upon other transmission planning efforts.\120\
For example, Exelon states that the ARRA-funded transmission planning
for the Eastern Interconnection is a positive effort, but is aimed at
evaluating what would happen under various scenarios rather than at
evaluating solutions and identifying the best solution for any given
transmission planning problem. AWEA states that the Commission should
not rely on interconnectionwide transmission planning undertaken
pursuant to the ARRA as the sole means for reforming the transmission
planning process because the ARRA-funded efforts cannot be expected to
lead to the near-term changes that need to be implemented in order to
support development of renewable energy resources.
---------------------------------------------------------------------------

    \119\ E.g., ColumbiaGrid, NARUC, New England States' Committee
on Electricity, and Organization of MISO States.
    \120\ E.g., Eastern Interconnection Planning Collaborative
Analysis Team, Entergy, and Progress Energy.
---------------------------------------------------------------------------

    112. The Commission supports and encourages the interconnectionwide
transmission planning efforts being undertaken pursuant to the ARRA. As
noted above, broad participation in sessions to date related to these
efforts suggests that that the availability of Federal funds to pursue
interconnectionwide transmission planning has increased awareness of
the potential for greater coordination among regions in transmission
planning. The Commission anticipates that the ARRA-funded efforts will
enhance transmission planning by, among other actions, building upon
local and regional transmission planning processes and improving
capabilities to model the development of transmission enhancements for
the various scenarios of interest to State and Federal policy makers
and other stakeholders, as well as Canadian provincial policy makers in
the Western Interconnection. We emphasize that this Proposed Rule,
which does not require interconnectionwide planning or cost allocation,
is not intended to interfere with the efforts already underway in ARRA-
funded transmission planning initiatives.
    113. However, even with these important steps toward
interconnection-wide scenario analysis, the Commission remains
concerned that the lack of coordinated transmission planning processes
across the seams of neighboring transmission planning regions could be
needlessly increasing costs for customers of transmission providers.
These circumstances may result in transmission rates that are unjust
and unreasonable. Therefore, the Commission proposes reforms that are
intended to improve coordination between neighboring transmission
planning regions with respect to facilities that are proposed to be
located in both regions, as well as interregional facilities that could
address transmission needs more efficiently than separate intraregional
facilities.
2. Proposed Interregional Planning Reforms
    114. We propose to require each public utility transmission
provider through its regional transmission planning process to
coordinate with the public utility transmission providers in each of
its neighboring transmission planning regions within its
interconnection to address transmission planning issues, as discussed
below.\121\ This coordination between transmission planning regions
must be reflected in an

interregional transmission planning agreement to be filed with the
Commission.
---------------------------------------------------------------------------

    \121\ This proposal does not require a public utility
transmission provider to enter into an interregional transmission
planning agreement with a neighboring transmission planning region
in another interconnection.
---------------------------------------------------------------------------

    115. The interregional transmission planning agreement may be
developed on behalf of the public utility transmission providers within
multiple transmission planning regions. For example, two RTOs may set
forth the requirements of their interregional transmission planning
coordination as part of an overall joint operating agreement between
them. A public utility transmission provider that is not in an RTO or
ISO may, for example, work with other transmission providers that
participate in its regional transmission planning process to create and
enter into a multilateral interregional transmission planning agreement
with transmission providers in a neighboring transmission planning
region. Although not required under this proposal, we encourage public
utility transmission providers to explore possible multilateral
interregional transmission planning agreements among several, or even
all, regions within an interconnection, building on processes developed
through the ARRA-funded transmission planning initiatives. We note that
multilateral interregional transmission planning agreements may
minimize the growing number of planning meetings that some stakeholders
suggest pose barriers to their meaningful participation in the planning
processes, given their limited resources.
    116. The interregional transmission planning agreement must include
a detailed description of the process for coordination between public
utility transmission providers in neighboring transmission planning
regions with respect to facilities that are proposed to be located in
both regions, as well as interregional facilities that are not proposed
but that could address transmission needs more efficiently than
separate intraregional facilities.
    117. While the Commission encourages every interregional
transmission planning agreement to be tailored to best fit the needs of
the regions entering into the agreement, there are certain elements
that we propose each public utility transmission provider must ensure
are included in any interregional transmission planning agreement in
which it participates. Including these elements will help to ensure a
proactive, comprehensive process. Specifically, we propose that an
interregional transmission planning agreement must include: (1) A
commitment to coordinate and share the results of respective regional
transmission plans to identify possible interregional facilities that
could address transmission needs more efficiently than separate
intraregional facilities; (2) an agreement to exchange at least
annually planning data and information; (3) a formal procedure to
identify and jointly evaluate transmission facilities that are proposed
to be located in both regions; and (4) a commitment to maintain a Web
site or e-mail list for the communication of information related to the
coordinated planning process.
    118. With respect to the third proposed requirement for an
interregional transmission planning agreement, the Commission proposes
that the sponsor of a project that would be located in both
transmission planning regions to which that agreement applies must
first propose its project in the transmission planning process of each
of those transmission planning regions. The Commission further proposes
that such a submission would trigger a procedure established by the
interregional transmission planning agreement, under which the
transmission planning regions would coordinate their reviews of and
jointly evaluate the proposed project. The Commission proposes that
such coordination and joint evaluation must be conducted in the same
general timeframe as, rather than subsequent to, each transmission
planning region's individual consideration of the proposed project.
Finally, the Commission proposes that inclusion of the interregional
transmission project in each of the relevant regional transmission
plans would be a prerequisite to application of an interregional cost
allocation method that satisfies the cost allocation principles
proposed below in this NOPR.
    119. We seek comment on any issue of interest or concern related to
the requirements proposed in this section of the Proposed Rule,
including the proposed required elements of an interregional
transmission planning agreement and any other elements that should be
part of an interregional transmission planning agreement. In
particular, we seek comment on how such an agreement would be
implemented in non-RTO or ISO regions and on the impact that an
interregional transmission planning agreement would likely have on the
development of interregional transmission facilities.
    120. We recognize that development of interregional transmission
planning agreements would take time and would necessarily depend on
progress at the regional level. Accordingly, the Commission proposes to
require the interregional transmission planning agreements to be
submitted to the Commission no later than one year after the effective
date of the final rule issued in this proceeding.

V. Proposed Reforms: Cost Allocation

A. Introduction

1. Order No. 890's Transmission Planning Principle on Cost Allocation
for New Transmission Facilities
    121. In Order No. 890, the Commission found that there is a close
relationship between transmission planning, which identifies needed
transmission facilities, and the allocation of costs of the
transmission facilities in the plan. The Commission stated that knowing
how the costs of new transmission facilities would be allocated is
critical to the development of new infrastructure, because transmission
providers and customers cannot be expected to support the construction
of new transmission unless they understand who will pay the associated
costs.\122\
---------------------------------------------------------------------------

    \122\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 557.
---------------------------------------------------------------------------

    122. In light of this close relationship, the Commission included a
principle entitled ``Cost Allocation for New Projects'' among the Order
No. 890 transmission planning principles. The Commission stated that
the Order No. 890 Cost Allocation principle was intended to apply to
projects that did not fit under existing cost allocation methods. As
examples of such projects, the Commission cited regional projects
involving several transmission owners and economic projects that are
identified pursuant to the Order No. 890 economic planning studies
principle for transmission planning, rather than through individual
requests for transmission service.\123\
---------------------------------------------------------------------------

    \123\ Id. P 558.
---------------------------------------------------------------------------

    123. The Commission did not impose a particular cost allocation
method in Order No. 890, but instead permitted public utility
transmission providers, customers, and other stakeholders to determine
a method that would be appropriate given the needs of the region. While
allowing this flexibility among regions, the Commission also stated
that providing some overall guidance on the issue was appropriate. The
Commission stated that when considering a dispute over cost allocation,
it would exercise its judgment by weighing several factors. First, the
Commission stated that it would consider whether a cost allocation
proposal fairly assigns costs among participants, including those who
cause the costs to be incurred and

those that otherwise benefit from them. Second, the Commission stated
that it would consider whether a cost allocation proposal provides
adequate incentives to construct new transmission. Third, the
Commission stated that it would consider whether the proposal is
generally supported by State authorities and participants across the
region.\124\
---------------------------------------------------------------------------

    \124\ Id. P 559.
---------------------------------------------------------------------------

    124. The Commission also stated that these factors are particularly
important as applied to economic projects that are identified pursuant
to the Order No. 890 economic planning studies principle for
transmission planning, such as upgrades to reduce congestion or enable
groups of customers to access new generation. The Commission stated
that, as a general matter, the beneficiaries of any such project should
agree to support its costs. The Commission recognized, however, that
there are free rider problems associated with new transmission
investment, such that customers who do not agree to support a
particular project may nonetheless receive substantial benefit from it.
The Commission also stated that a range of solutions to free rider
problems is available, noting that different regions have attempted to
address those problems in a variety of ways.\125\
---------------------------------------------------------------------------

    \125\ Id. P 561 (``[D]ifferent regions have attempted to address
such issues in a variety of ways, such as by assigning transmission
rights only to those who financially support a project or spreading
a portion of the cost of certain high-voltage projects more broadly
than the immediate beneficiary/supporters of the project.'').
---------------------------------------------------------------------------

    125. To comply with the cost allocation principle, the Commission
directed each public utility transmission provider to clearly define
the details of its cost allocation method as part of a new attachment
to its OATT. The Commission stated that each proposal should identify
the types of new projects that are not covered under previously
existing cost allocation methods and, therefore, would be affected by
the Order No. 890 cost allocation principle.\126\ The Commission also
stated that it is important that each region address these cost
allocation issues up front, at least in principle, rather than having
them relitigated each time a project is proposed.\127\ The Commission
explained that up-front identification of how the cost of a facility
will be allocated will allow transmission providers, customers, and
potential investors to make the decision whether or not to build that
facility on an informed basis.\128\
---------------------------------------------------------------------------

    \126\ Id. P 558.
    \127\ Id. P 561.
    \128\ Order No. 890-A, FERC Stats. & Regs. ] 31,261 at P 251.
The Commission also stated that neither adoption of a cost
allocation method nor identification of an upgrade (whether driven
by reliability or economics) in a transmission plan triggers an
obligation to build. Id.
---------------------------------------------------------------------------

    126. After several rounds of compliance filings, the Commission
approved various public utility transmission providers' proposals
pursuant to the cost allocation principle. The Commission found that
the proposals adequately identified both the types of new projects that
were not covered under previously existing cost allocation methods and
new methods for allocating the cost of those projects.
    127. Particularly in transmission planning regions outside of the
RTO and ISO footprints, many of the cost allocation methods that the
Commission accepted in the Order No. 890 compliance proceedings rely
exclusively on a ``participant funding'' approach to cost allocation.
Under a participant funding approach to cost allocation, the costs of a
new transmission facility are allocated only to entities that volunteer
to bear those costs.
    128. For example, El Paso Electric proposed in its Order No. 890
compliance filing to use a cost allocation method in which such
entities would share the costs proportionally based on each
participant's desired use of the facility to be constructed.\129\ Other
members of WestConnect, such as Public Service Company of Colorado,
filed and now use similar participant funding cost allocation
methods.\130\ South Carolina Electric & Gas included in its Order No.
890 compliance filing the Southeast Inter-Regional Participation
Process (SIRPP) provisions stating that costs for economics-driven
upgrades will be born entirely by the transmission owner that builds
the facilities.\131\ Similarly, Entergy filed and had approved a method
where the costs for projects developed under its Regional Planning
Process and its interregional transmission planning process would be
born by the party that constructs the facilities.\132\ ColumbiaGrid and
the Northern Tier Transmission Group both utilize a study committee
process whereby alternative cost allocation methods can be proposed for
projects within their respective regions.\133\ However, both
ColumbiaGrid and Northern Tier Transmission Group use a process where,
if no agreement on cost allocation among the study team participants or
the project proponents is obtained, the entities requesting the project
will bear the costs.
---------------------------------------------------------------------------

    \129\ El Paso Electric Company, 124 FERC ] 61,051, at P 44
(2008).
    \130\ Xcel Energy Services, Inc.--Public Service Company of
Colorado, 124 FERC ] 61,052 (2008).
    \131\ South Carolina Electric & Gas Company, 127 FERC ] 61,275,
at P 50 (2009).
    \132\ Entergy Services, Inc., 127 FERC ] 61,272 (2009).
    \133\ See Avista Corporation, 128 FERC ] 61,065 (2009) and Idaho
Power Company, 128 FERC ] 61,064 (2009).
---------------------------------------------------------------------------

2. October 2009 Notice and Subsequent Comments
    129. As discussed above, in the October 2009 Notice, the Commission
posed a number of questions with respect to allocating the cost of
transmission facilities. Those questions drew wide-ranging responses as
to whether further Commission action on cost allocation is needed at
this time and, if so, what that action should be.
    130. Among the commenters, there is general agreement that the
Commission should not supersede existing, ongoing processes in various
parts of the country that are attempting to address regional and
interregional cost allocation issues.
    131. Nonetheless, commenters supporting further Commission action
on cost allocation at this time generally assert that the Commission
should provide more detailed guidelines or principles for allocating
the costs of new transmission facilities.\134\ Many commenters argue
that a clear path to cost recovery is necessary for a new transmission
project to move beyond the evaluation stage and to be included in any
regional transmission planning process and ultimately to proceed to
construction.\135\ Such commenters indicate that risks associated with
cost recovery--together with the risks associated with permitting and
siting--are among the most significant obstacles to the construction of
a new transmission facility, especially if customers that are allocated
costs do not perceive that they will benefit from the proposed
facility.\136\ Old Dominion emphasizes that many of the obstacles
inhibiting transmission development are interrelated, but that greater
certainty on cost allocation would likely ease access to capital for
proposed facilities.\137\
---------------------------------------------------------------------------

    \134\ E.g., APPA, National Rural Electric Coops, Transmission
Access Policy Study Group, Transmission Dependent Utility Systems,
and California ISO.
    \135\ E.g., American Transmission, AWEA, E.ON Climate &
Renewables North America, Energy Future Coalition, and NextEra.
    \136\  E.g., AWEA, Transmission Dependent Utility Systems, Xcel,
Transmission Access Policy Study Group, and National Rural Electric
Coops.
    \137\ Old Dominion at 26.
---------------------------------------------------------------------------

    132. Several commenters specifically address cost allocation as an
impediment to the development of generation to satisfy renewable
portfolio

standards implemented by the states.\138\ AWEA, for example, states
that cost allocation policies are the biggest impediment to
construction of new transmission facilities, regardless of location,
and that costs should be assigned to all entities that benefit from a
new facility. AWEA further comments that a participant funding cost
allocation method does not achieve that goal.\139\ These commenters
also state that uncertainty over cost allocation imposes significant
costs on customers attempting to export energy from renewable resources
and inhibit planning for the integration of the most economic
generation resources into the transmission grid. Maine PUC and Public
Advocate state that the existing ISO-NE cost allocation methods are not
optimal when considering large amounts of wind integration.\140\
---------------------------------------------------------------------------

    \138\ E.g., AWEA at 9-10, American Transmission and Exelon.
    \139\ AWEA at 4. See also Transmission Access Policy Study Group
at 25-27.
    \140\ Maine PUC and Public Advocate at 7-8.
---------------------------------------------------------------------------

    133. Similarly, the majority of commenters that address cost
allocation for large, interregional transmission facilities agree that
the Commission should provide more guidance on cost allocation.\141\
Some commenters complain that as a general matter, the Commission has
addressed cost allocation methods only for facilities within the
footprint of a single transmission provider or a single RTO or ISO, and
not for interregional projects. For example, AEP states that it has
experienced delays in developing transmission facilities that cross RTO
boundaries as a result of uncertainty over cost allocation, as well as
difficulties with how the facilities are to be planned.
---------------------------------------------------------------------------

    \141\ E.g., AEP, ITC Holdings, and Exelon.
---------------------------------------------------------------------------

    134. Some of these commenters assert that the expansion of regional
power markets and the increasing adoption by State governments of
renewable energy requirements have led to a growing need for new
transmission facilities that cross several utility and/or RTO or ISO
regions. These commenters generally support, or state that they do not
oppose, the Commission establishing a process to help stakeholders
address cost allocation matters over larger geographic areas. For
example, California ISO and the California Commission comment that,
although cost allocation within the California ISO works well, they
support the Commission creating a process to consider cost allocation
over a larger region in the West.
    135. In addition, the comments in response to the October 2009
Notice reflect a general consensus that those who share in the benefits
of transmission projects should also share in their costs. However,
there is no consensus on what types of benefits should be considered or
how such benefits should be calculated. Certain commenters, for
example, support recognition of a broad spectrum of benefits that may
stem from transmission development, such as environmental impacts, land
conservation and energy security.\142\ Other commenters urge the
Commission to avoid a uniform approach to determining the benefits of
transmission projects.\143\
---------------------------------------------------------------------------

    \142\ E.g., AEP, AWEA, Baltimore Gas and Electric, Energy Future
Coalition, Green Energy Express, ITC Holdings, MidAmerican, National
Audubon Society, NextEra, and Public Interest Organizations &
Renewable Energy Groups.
    \143\ E.g., ColumbiaGrid, ConEd, Delaware Municipal and
Southwestern Electric, and Northeast Utilities.
---------------------------------------------------------------------------

    136. Several commenters suggest that if the Commission decides to
establish a default cost allocation method for new transmission
facilities, such a method should be employed and enforced only when
stakeholders are unable to agree upon their own regional cost
allocation method or methods.\144\ For example, American Transmission,
National Grid, Northern Tier Transmission Group, and NEPOOL
Participants state that the Commission could create a generic cost
allocation method as a backstop, which would apply when parties or
regions could not come to their own agreement. Other commenters express
the view that the Commission should create one or more rebuttable
presumptions about who benefits from various types of facilities in
order to make cost allocation easier.\145\
---------------------------------------------------------------------------

    \144\ E.g., American Transmission, National Grid, Northern Tier
Transmission Group, and NEPOOL Participants.
    \145\ E.g., ITC Holdings, MidAmerican, PJM, Solar Energy
Industries, and WIRES.
---------------------------------------------------------------------------

    137. Finally, many commenters state that no further generic
Commission action on cost allocation is needed at this time because the
processes in their own regions already address, or are now working to
address, cost allocation. For example, in the Southeast, some
commenters state that their processes for cost allocation are working
well and argue that the Commission should continue to allow regional
flexibility on cost allocation processes.\146\ Similarly, in the West,
some commenters state that cost allocation in their region is not a
problem.\147\
---------------------------------------------------------------------------

    \146\ E.g., Entergy, Southern Companies, and Florida
Transmission Providers.
    \147\ E.g., ColumbiaGrid, Northern Tier Transmission Group,
Transmission Agency of Northern California, Salt River Project and
WestConnect Planning Parties.
---------------------------------------------------------------------------

B. Legal Authority and Need for Reform

    138. Based on the comments received in response to the October 2009
Notice, the Commission believes that further reform with respect to
transmission cost allocation methods may be necessary in order to
ensure that the rates, terms and conditions of transmission service in
interstate commerce are just and reasonable and not unduly
discriminatory or preferential.
1. The Cost Causation Principle
    139. Under sections 205 and 206 of the FPA, the Commission is
responsible for ensuring that the rates, terms, and conditions for
transmission of electricity in interstate commerce are just,
reasonable, and not unduly discriminatory or preferential.\148\ With
respect to this responsibility, the Commission and the courts have
found that the costs of jurisdictional transmission facilities must be
allocated in a manner that satisfies the ``cost causation'' principle.
---------------------------------------------------------------------------

    \148\ 16 U.S.C. 824d, 824e.
---------------------------------------------------------------------------

    140. The U.S. Court of Appeals for the District of Columbia Circuit
(D.C. Circuit) has defined the cost causation principle as follows:
``[I]t has been traditionally required that all approved rates reflect
to some degree the costs actually caused by the customer who must pay
them.'' \149\ The U.S. Court of Appeals for the Seventh Circuit
(Seventh Circuit) recently quoted and elaborated on that definition,
stating, ``All approved rates must reflect to some degree the costs
actually caused by the customer who must pay them. Not surprisingly, we
evaluate compliance with this unremarkable principle by comparing the
costs assessed against a party to the burdens imposed or benefits drawn
by that party. To the extent that a utility benefits from the costs of
new facilities, it may be said to have `caused' a part of those costs
to be incurred, as without the expectation of its contributions the
facilities might not have been built, or might have been delayed.''
\150\ The Commission has

frequently made similar statements with respect to the cost causation
principle. For example, as noted above, the Commission stated in Order
No. 890 that one factor it weighs when considering a dispute over cost
allocation is whether a cost allocation proposal fairly assigns costs
among participants, including those who cause the costs to be incurred
and those that otherwise benefit from them.\151\
---------------------------------------------------------------------------

    \149\ K N Energy, Inc. v. FERC, 968 F.2d 1295, 1300 (D.C. Cir.
1992) (K N Energy).
    \150\ Illinois Commerce Comm'n v. FERC, 576 F.3d 470, 476 (7th
Cir. 2009) (Illinois Commerce Commission) (citing K N Energy, 968
F.2d at 1300; Transmission Access Policy Study Group v. FERC, 225
F.3d 667, 708 (D.C. Cir. 2000); Pacific Gas & Elec. Co. v. FERC, 373
F.3d 1315, 1320-21 (D.C. Cir. 2004); Midwest ISO Transmission Owners
v. FERC, 373 F.3d 1361, 1368 (D.C. Cir. 2004) (Midwest ISO
Transmission Owners); Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir.
2009); Sithe/Independence Power Partners, L.P. v. FERC, 285 F.3d 1,
4-5 (D.C. Cir. 2002) (Sithe); 16 U.S.C. 824d).
    \151\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 559.
---------------------------------------------------------------------------

    141. In applying the cost causation principle, the Commission has
generally allocated costs to beneficiaries that have entered a
voluntary arrangement with the public utility that is seeking to
recover those costs. One example of a voluntary cost recovery
arrangement with a public utility is voluntary membership in an RTO or
ISO that makes an entity subject to the cost allocation provisions of
the RTO's or ISO's tariff.\152\ The Commission also has permitted
joint-ownership agreements where the owners share the costs of the new
transmission facilities.
---------------------------------------------------------------------------

    \152\ The Commission notes that RTO or ISO membership does not
eliminate the need to satisfy the other aspects of the cost
causation principle that are discussed above.
---------------------------------------------------------------------------

    142. The cost causation principle, however, is not limited to
voluntary arrangements. Indeed, if the Commission were limited to
allocating costs only to beneficiaries that voluntarily accept those
costs, then the Commission could not fulfill its responsibilities under
the FPA. If the Commission could not address free rider problems
associated with new transmission investment, then it could not ensure
that transmission rates are just and reasonable and not unduly
discriminatory. The cost causation principle provides that costs should
be allocated to those who cause them to be incurred and those that
otherwise benefit from them, as the Commission also recognized in Order
No. 890. In other words, the Commission may determine that an entity's
status as a beneficiary of a transmission facility identified through
an appropriate process is relevant for purposes of applying the cost
causation principle, even if that beneficiary has not entered a
voluntary arrangement with (e.g., as a customer of) the public utility
that is seeking to recover the costs of that facility.
    143. The Commission has expressed a willingness to make such a
determination. For example, when presented with concerns about parallel
path flow,\153\ the Commission has offered repeatedly that if a public
utility can demonstrate that a transaction is a burden on its system,
then that utility can propose a transmission service rate for
Commission consideration that would account for the unauthorized use of
its system.\154\ The Commission has cautioned against the hasty
submittal of such unilateral filings, describing its general policy as
expecting owners and controllers of transmission facilities to attempt
to resolve parallel path flow issues on a consensual, regional
basis.\155\ Nonetheless, if approved by the Commission, such a proposal
to address parallel path flow would allow a public utility to recover
costs from a beneficiary of its system in the absence of a voluntary
arrangement between the utility and that beneficiary.
---------------------------------------------------------------------------

    \153\ The Commission has described the phenomenon of parallel
path flow as follows: ``In general, utilities transact with one
another based on a contract path concept. For pricing purposes,
parties assume that power flows are confined to a specified sequence
of interconnected utilities that are located on a designated
contract path. However, in reality power flows are rarely confined
to a designated contract path. Rather, power flows over multiple
parallel paths that may be owned by several utilities that are not
on the contract path. The actual power flow is controlled by the
laws of physics which cause power being transmitted from one utility
to another to travel along multiple parallel paths and divide itself
along the lines of least resistance. This parallel path flow is
sometimes called `loop flow.' '' Indiana Michigan Power Co. and Ohio
Power Co., 64 FERC ] 61,184, at 62,545 (1993).
    \154\ See, e.g., Amer. Elec. Power Svc. Corp., 49 FERC ] 61,377,
at 62,381 (1989).
    \155\ Id. See also Southern California Edison Co., 70 FERC ]
61,087, at 61,241-42 (1995).
---------------------------------------------------------------------------

    144. The Commission also affirmatively required costs of
transmission facilities to be allocated to beneficiaries in the absence
of a voluntary arrangement in a series of orders involving the Midwest
Independent Transmission System Operator, Inc. (Midwest ISO) and PJM
Interconnection, L.L.C. (PJM). Specifically, the Commission directed
Midwest ISO and PJM to develop cost allocation methods for new
facilities in one of their footprints that benefit entities in the
other's footprint.\156\ Echoing precedent applying the cost causation
principle, the Commission later conditionally accepted a proposal that
Midwest ISO and PJM submitted in compliance with that directive on the
grounds that it ``more accurately identifies the beneficiaries and
allocates the associated costs'' than did the cost allocation methods
that were previously in place.\157\
---------------------------------------------------------------------------

    \156\ Midwest Indep. Transmission Sys. Operator, Inc., 109 FERC
] 61,168, at P 60 (2004) (citing Midwest Indep. Transmission Sys.
Operator, Inc., 106 FERC ] 61,251, at P 56-57 (2004)). The
Commission noted that Midwest ISO and PJM had committed in a Joint
Operating Agreement to develop such a method for allocating the
costs of certain facilities through their joint regional planning
committee. Id. The Commission did not base the above-noted directive
on the existence of the Joint Operating Agreement, which Midwest ISO
and PJM developed in order to comply with a previous Commission
directive. See Alliance Cos., 100 FERC ] 61,137, at P 48, 53 (2002).
    \157\ Midwest Indep. Transmission Sys. Operator, Inc., 113 FERC
] 61,194, at P 10 (2005). See also Midwest Indep. Transmission Sys.
Operator, Inc., 122 FERC ] 61,084 (2008); Midwest Indep.
Transmission Sys. Operator, Inc., 129 FERC ] 61,102 (2009).
---------------------------------------------------------------------------

    145. These examples show that the Commission has asserted its
authority to allocate the costs of jurisdictional facilities to
beneficiaries whether or not those beneficiaries have entered into a
voluntary agreement with the public utility that is seeking to recover
those costs.
    146. In addition, courts have affirmed that the cost causation
principle allows the Commission to allocate at least some types of
costs to beneficiaries that are not customers of the public utility
that is seeking to recover the costs in question. For example, the D.C.
Circuit addressed this issue in a case that involved a proposal for
Midwest ISO to recover administrative costs through a charge that would
apply to transmission loads subject to the Midwest ISO's tariff rates:
i.e., new wholesale loads and unbundled retail loads, but not bundled
retail loads and loads served pursuant to grandfathered contracts.\158\
Describing the core issue as whether the Commission's orders comported
with the cost causation principle, the D.C. Circuit found that the
Commission reasonably allocated the administrative costs more broadly
than Midwest ISO proposed.\159\ After stating that the subject costs
were the administrative costs of having an ISO, the D.C. Circuit found
that the Commission correctly determined that bundled and grandfathered
loads should share the cost of having an ISO because they drew benefits
from Midwest ISO.\160\
---------------------------------------------------------------------------

    \158\ Midwest ISO Transmission Owners, 373 F.3d 1361. The D.C.
Circuit stated that the subject costs ``are primarily MISO's startup
expenses--particularly those pertaining to the MISO Security
Center--and certain expenses pertaining to the creation and
administration of MISO's open access tariff.'' Id. at 1369.
    \159\ Id. at 1370.
    \160\ Id. at 1370-71.
---------------------------------------------------------------------------

    147. Thus, in applying the cost causation principle, the Commission
may allocate costs of a transmission facility to a beneficiary
identified through an appropriate process, such as a Commission-
approved transmission planning process, even if that beneficiary has
not entered a voluntary arrangement with the public utility that

is seeking to recover the costs of that facility. After satisfying this
standard with respect to beneficiary identification, the cost causation
principle also requires the Commission to ensure that the costs
allocated to a beneficiary under a cost allocation method are at least
roughly commensurate with the benefits that are expected to accrue to
that entity.\161\ On this point, the D.C. Circuit has explained that
``the cost causation principle does not require exacting precision in a
ratemaking agency's allocation decisions.'' \162\
---------------------------------------------------------------------------

    \161\ Illinois Commerce Commission, 576 F.3d at 476-77 (``We do
not suggest that the Commission has to calculate benefits to the
last penny, or for that matter to the last million or ten million or
perhaps hundred million dollars.''). See also Midwest ISO
Transmission Owners, 373 F.3d 1361 at 1369 (``we have never required
a ratemaking agency to allocate costs with exacting precision.'');
Sithe, 285 F.3d 1 at 5.
    \162\ Midwest ISO Transmission Owners, 373 F.3d 1361 at 1371
(citing Sithe, 285 F.3d 1 at 5).
---------------------------------------------------------------------------

2. Need for Reform
    148. The Commission's responsibility under FPA sections 205 and 206
to ensure that transmission rates are just and reasonable and not
unduly discriminatory or preferential is not new, nor is the
Commission's recognition of the cost causation principle. However, the
circumstances in which the Commission must fulfill its statutory
responsibilities change with developments in the electric industry,
such as changes with respect to the demands placed on the transmission
grid.
    149. The Commission has previously recognized changes in
circumstances that warranted changes in the manner by which public
utilities recover transmission costs. In the early 1990s, the
Commission identified ``dramatic changes which the electric industry
has faced, and will face in the near term,'' such as ``increased
reliance on market forces to meet power supply needs; new market
entrants such as exempt wholesale generators; a significant number of
utility mergers and combinations; more highly integrated operation of
various power pools; and substantial bulk power trading among electric
systems,'' as well as the initial filing of open access transmission
tariffs.\163\ To account for those developments and the industry's
changing needs, the Commission issued a policy statement that increased
flexibility with respect to transmission pricing.\164\
---------------------------------------------------------------------------

    \163\  See Notice of Technical Conference and Request for
Comments in Inquiry Concerning the Commission's Pricing Policy for
Transmission Services Provided by Public Utilities under the Federal
Power Act, 58 FR 36400, at 36401 (1993).
    \164\ Policy Statement in Inquiry Concerning the Commission's
Pricing Policy for Transmission Services Provided by Public
Utilities under the Federal Power Act, FERC Stats. & Regs.,
Regulations Preambles January 1991-June 1996 ] 31,005 (1994).
---------------------------------------------------------------------------

    150. Many of those changes have not only continued but also
accelerated in recent years. For example, as commenters stated in
response to the October 2009 Notice, the further expansion of regional
power markets has led to a growing need for new transmission facilities
that cross several utility, RTO, ISO or other regions. The industry's
continuing transition from relatively localized trading to larger
regional power markets also results, among other effects, in broader
diffusion of the benefits associated with transmission upgrades and new
transmission facilities.
    151. Similarly, the increasing adoption of State resource policies,
such as renewable portfolio standard measures, has contributed to rapid
growth of location-constrained renewable energy resources that are
frequently remote from load centers, as well as a growing need for new
transmission facilities that cross several utility and/or RTO or ISO
regions. Transmission facilities that are needed to comply with State
renewable portfolio standard measures illustrate the increasing
potential for benefits associated with meeting public policy-driven
transmission needs.
    152. More generally, as stated above, challenges associated with
allocating the cost of transmission appear to have become more acute as
the need for transmission infrastructure has grown. As noted above,
constructing new transmission facilities requires a significant amount
of capital. Therefore, a threshold consideration for any company
considering investing in transmission is whether it will have a
reasonable opportunity to recover its costs. However, there are few
rate structures in place today that provide both for analysis of the
beneficiaries of a transmission facility that is proposed to be located
within a transmission planning region that is outside of an RTO or ISO,
or in more than one transmission planning region, and for corresponding
allocation and recovery of the facility's costs. The lack of such rate
structures creates significant risk for transmission developers that
they will have no identified group of customers from which to recover
the cost of their investment. In addition, cost allocation within RTO
or ISO regions, particularly those that encompass several states, is
often contentious and prone to litigation because it is difficult to
reach an allocation of costs that is perceived as fair. Some comments
filed in response to the October 2009 Notice present these types of
concerns and state the resultant uncertainty regarding cost allocation
remains an impediment to development of needed transmission facilities.
    153. The risk of the free rider problems associated with new
transmission investment that the Commission described in Order No. 890
is also particularly high for projects that affect multiple utilities'
transmission systems and therefore may have multiple beneficiaries.
With respect to such projects, any individual beneficiary has an
incentive to defer investment in the hopes that other beneficiaries
will value the project enough to fund its development. On one hand, a
cost allocation method that relies exclusively on a participant funding
approach, without respect to other beneficiaries of a transmission
facility, increases this incentive and, in turn, the likelihood that
needed transmission facilities will not be constructed in a timely
manner. On the other hand, if costs are allocated to entities that will
receive no benefit from a transmission facility, then those entities
are more likely to oppose inclusion of the facility in a regional
transmission plan or to otherwise impose obstacles that delay or
prevent the facility's construction.
    154. In light of these challenges and recent developments affecting
the industry, the Commission is concerned that existing cost allocation
methods may not appropriately account for benefits associated with new
transmission facilities and, thus, may result in rates that are not
just and reasonable or are unduly discriminatory or preferential.

C. Proposed Reforms

    155. The Commission proposes to amend its regulations to address
the concerns discussed above.
    156. First, we propose to more closely align transmission planning
and cost allocation processes. A transmission planning process includes
a facility in a transmission plan in order to achieve a specific
purpose or purposes, such as to avoid an impending violation of a
Reliability Standard, reduce congestion and thereby increase access to
lower-cost resources, or enable compliance with public policy
requirements established by State or Federal laws or regulations.
Because such purposes involve the identification of expected
beneficiaries--either explicitly or implicitly--establishing a closer
link between transmission planning and cost

allocation will address in part the Commission's concern that existing
cost allocation methods may not appropriately account for benefits
associated with new transmission facilities.
    157. The Commission has previously suggested that transmission
planning at least on a regional basis is closely related to cost
allocation. As noted above, this premise underlies the Commission's
establishment in Order No. 890 of a transmission planning principle on
cost allocation for new transmission facilities. In addition, the
Commission has explained that it may be appropriate to have different
cost allocation methods for facilities that are planned for different
purposes or pursuant to different transmission planning processes. For
example, the Commission distinguished between existing facilities in
Midwest ISO and PJM for which it found that license plate rates are
appropriate, and new facilities in those regions for which it approved
broader cost allocation methods.\165\ The Commission found it
significant that Midwest ISO and PJM plan the construction of new
facilities based on each RTO's independent transmission planning
process, which helps to ensure that new projects are necessary to meet
the reliability and economic needs of each RTO's system as a whole. The
Commission also noted that Midwest ISO and PJM plan certain new
facilities pursuant to a joint RTO planning process under a Joint
Operating Agreement. By contrast, the Commission stated that decisions
to build existing facilities within Midwest ISO and PJM were not made
as part of any regional planning process.\166\
---------------------------------------------------------------------------

    \165\ Amer. Elec. Power Serv. Corp. v. Midwest Indep.
Transmission Sys. Operator, Inc., 122 FERC ] 61,083, at P 13-24
(2008).
    \166\ Id. P 96.
---------------------------------------------------------------------------

    158. The Commission recognizes that identifying which types of
benefits are relevant for cost allocation purposes, which entities are
receiving those benefits, and the relative benefits that accrue to
various beneficiaries can be difficult and controversial. The
Commission believes that a transparent transmission planning process is
the appropriate forum to address these issues. In addition, addressing
these issues through the transmission planning process would increase
the likelihood that facilities included in transmission plans are
actually constructed, rather than being included in a transmission plan
only to later encounter cost allocation disputes that prevent their
construction.
    159. Accordingly, the Commission proposes to require that every
public utility transmission provider have in place a method, or set of
methods, for allocating the costs of new transmission facilities that
are included in the transmission plan produced by the transmission
planning process in which it participates. If the public utility
transmission provider is an RTO or ISO, then the method or methods
would be required to be set forth in the RTO or ISO tariff. In other
transmission planning regions, each public utility transmission
provider located within the region would be required to set forth in
its tariff the method or methods for cost allocation used in its
transmission planning region.
    160. An RTO or ISO or the public utility transmission providers in
a transmission planning region may have a single cost allocation method
for all new transmission facilities or different methods for different
types of facilities. For example, cost allocation methods may
distinguish among facilities that are driven by needs associated with
maintaining reliability, relieving congestion, and achieving public
policy requirements established by State or Federal laws or
regulations, all of which would be required to be considered in the
regional transmission planning process as explained elsewhere in this
Proposed Rule. The Commission recognizes that several transmission
planning regions that have different cost allocation methods by type of
project currently have transmission planning procedures and cost
allocation methods that refer only to the first two categories of
transmission projects. The Proposed Rule would permit a public utility
transmission provider or transmission planning region to distinguish or
not distinguish among these three types of transmission facilities, as
long as each of the three is considered in the transmission planning
process and there is a means for allocating the costs of each type of
facility to beneficiaries.
    161. Second, we propose to require that each public utility
transmission provider within a transmission planning region develop a
method for allocating the costs of a new interregional transmission
facility between the two neighboring transmission planning regions in
which the facility is located or among the beneficiaries in the two
neighboring transmission planning regions.
    162. Third, to ensure that the cost allocation method or methods
are just and reasonable and not unduly discriminatory or preferential,
we propose to assess each cost allocation method based upon the cost
allocation principles set out in the following sections, one set of
principles for intraregional facilities and another for interregional
facilities. To reiterate, we propose that the cost allocation method or
methods be applied to new transmission facilities included in the
transmission plan produced by the transmission planning process in
which the public utility transmission provider participates.
    163. Finally, we note that under our proposals, public utility
transmission providers will have the first opportunity to develop cost
allocation methods for intraregional and interregional transmission
facilities in consultation with customers and other stakeholders. In
the event that no agreement can be reached, the Commission would use
the record in the relevant compliance filing proceeding as a basis to
develop a cost allocation method or methods that meets the Commission's
proposed requirements.
1. Intraregional Cost Allocation
    164. An intraregional transmission facility is defined as a
transmission facility located entirely within the geographic boundaries
of one transmission planning region. As proposed here, each RTO or ISO
on behalf of its transmission owning members, or the individual public
utility transmission providers in a non-RTO or ISO transmission
planning region, would be required to demonstrate through a compliance
filing that it has a cost allocation method or methods that address
cost recovery for each new transmission facility included in its
regional transmission plan and that satisfy the following principles:
    (1) The cost of transmission facilities must be allocated to those
within the transmission planning region that benefit from those
facilities in a manner that is at least roughly commensurate with
estimated benefits.\167\ In determining the beneficiaries of
transmission facilities, a regional transmission planning process may
consider benefits including, but not limited to the extent to which
transmission facilities, individually or in the aggregate, provide for
maintaining reliability and sharing reserves, production cost savings
and congestion relief, and/or meeting public policy

requirements established by State or Federal laws or regulations that
may drive transmission needs.\168\
---------------------------------------------------------------------------

    \167\ Illinois Commerce Commission, 576 F.3d at 476-77 (``We do
not suggest that the Commission has to calculate benefits to the
last penny, or for that matter to the last million or ten million or
perhaps hundred million dollars.''). See also Midwest ISO
Transmission Owners, 373 F.3d 1361 at 1369 (``we have never required
a ratemaking agency to allocate costs with exacting precision.'');
Sithe, 285 F.3d 1 at 5.
    \168\ As discussed above, the Commission proposes to require
each public utility transmission provider to amend its OATT such
that its local and regional transmission planning processes
explicitly provide for consideration of public policy requirements
established by state or Federal laws or regulations that may drive
transmission needs.
---------------------------------------------------------------------------

    (2) Those that receive no benefit from transmission facilities,
either at present or in a likely future scenario, must not be
involuntarily allocated the costs of those facilities.
    (3) If a benefit to cost threshold is used to determine which
facilities have sufficient net benefits to be included in a regional
transmission plan for the purpose of cost allocation, it must not be so
high that facilities with significant positive net benefits are
excluded from cost allocation. A transmission planning region or public
utility transmission provider may want to choose such a threshold to
account for uncertainty in the calculation of benefits and costs. If
adopted, such a threshold may not include a ratio of benefits to costs
that exceeds 1.25 unless the transmission planning region or public
utility transmission provider justifies and the Commission approves a
greater ratio.
    (4) The allocation method for the cost of an intraregional facility
must allocate costs solely within that transmission planning region
unless another entity outside the region or another transmission
planning region voluntarily agrees to assume a portion of those
costs.\169\ However, the transmission planning process in the original
region must identify consequences for other transmission planning
regions, such as upgrades that may be required in another region and,
if there is an agreement for the original region to bear costs
associated with such upgrades, then the original region's cost
allocation method or methods must include provisions for allocating the
costs of the upgrades among the entities in the original region.
---------------------------------------------------------------------------

    \169\ In addition, the Commission preliminarily finds that this
principle does not affect the cross-border cost allocation methods
developed by PJM and the Midwest ISO in response to Commission
directives related to their intertwined configuration. Midwest
Indep. Transmission Sys. Operator, Inc., 113 FERC ] 61,194, at P 10
(2005); Midwest Indep. Transmission Sys. Operator, Inc., 122 FERC ]
61,084 (2008); Midwest Indep. Transmission Sys. Operator, Inc., 129
FERC ] 61,102 (2009).
---------------------------------------------------------------------------

    (5) The cost allocation method and data requirements for
determining benefits and identifying beneficiaries for a transmission
facility must be transparent with adequate documentation to allow a
stakeholder to determine how they were applied to a proposed
transmission facility.
    (6) A transmission planning region may choose to use a different
cost allocation method for different types of transmission facilities
in the regional plan, such as transmission facilities needed for
reliability, congestion relief, or to achieve public policy
requirements established by State or Federal laws or regulations. Each
cost allocation method must be set out clearly and explained in detail
in the compliance filing for this rule.
    165. In proposing these principles, the Commission does not intend
to prescribe a uniform approach to cost allocation for new
intraregional transmission facilities. To the contrary, we recognize
that regional differences may warrant distinctions in cost allocation
methods among transmission planning regions. Therefore, this Proposed
Rule would allow the public utility transmission providers in each
transmission planning region to develop a transmission cost allocation
method that best suits the needs of that transmission planning region.
    166. However, the Commission proposes that, if the public utility
transmission providers in a transmission planning region, in
consultation with customers and other stakeholders, cannot agree on a
cost allocation method for new intraregional transmission facilities
that satisfies these principles, the Commission would use the record in
the relevant compliance filing proceeding as a basis for applying these
principles to develop a cost allocation method that meets the
Commission's requirements. Consistent with the Commission's intention
not to prescribe a uniform approach, this cost allocation method would
not necessarily be the same for every transmission planning region
where the public utility transmission providers are unable to agree on
a cost allocation method that satisfies the principles.
    167. The Commission recognizes that several approaches to cost
allocation may satisfy the proposed principles. For example, 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 facility or class or group of
facilities (e.g., all transmission facilities at 345 kV or higher),
especially if the distribution of benefits associated with a class or
group of facilities is likely to vary considerably over the long
depreciation life of the facilities amid changing power flows, fuel
prices, population patterns, and local economic developments.
Similarly, other methods that propose cost allocation to a narrower
class of beneficiaries may be appropriate, provided that the method
reflects an evaluation of beneficiaries and is adequately defined and
supported by the transmission planning region.
    168. In addition, the principles proposed in this rulemaking do not
foreclose the opportunity for a transmission developer or individual
customer to voluntarily assume the costs of a new transmission
facility. In other words, the proposed principles would not prohibit
voluntary participant funding. However, if a transmission developer
believes that others in the transmission planning region may benefit
from a new transmission facility and want to seek broader cost
allocation, then that developer must be permitted to propose its
project in the regional transmission planning process that will
evaluate the project's beneficiaries. If the facility is included in
the regional transmission plan, the costs of that facility must be
eligible for allocation pursuant to the Commission-approved method for
allocating the cost of a new transmission facility in that plan.\170\
As stated above, a cost allocation method that relies exclusively on a
participant funding approach, without respect to other beneficiaries of
a transmission facility, exacerbates the free rider problem that the
Commission described in Order No. 890. Such a cost allocation method
would not satisfy the proposed principles.
---------------------------------------------------------------------------

    \170\ However, certain transmission developers may seek to
participate in the regional transmission planning process only for
coordination purposes (e.g., to perform a reliability check for a
participant-funded or merchant transmission project), in which case
the transmission plan would not include a cost allocation for such
projects.
---------------------------------------------------------------------------

    169. With regard to a new transmission facility that is located
entirely within one transmission owner's service territory, a
transmission owner may not unilaterally invoke the regional cost
allocation method to require the allocation of the costs of a new
transmission facility to other entities in its transmission planning
region. However, if the regional transmission planning process
determines that a new facility located solely within a transmission
owner's service territory would provide benefits to others in the
region, allocating the facility's costs according to that region's
intraregional cost allocation method would be permitted.
2. Interregional Cost Allocation
    170. An interregional transmission facility is one that in located
within two or more transmission planning regions. In the past, most
transmission upgrades

were planned and constructed to meet the needs of customers within a
given transmission planning region. However, new transmission
facilities located within multiple transmission planning regions are
now being considered by transmission providers in various parts of the
nation. For example, as discussed above, development of renewable
energy resources is increasing rapidly, in part in response to State
renewable portfolio standard requirements. However, many of these
resources are located far from load centers. New transmission
facilities located within multiple transmission planning regions may be
necessary to deliver the output of these renewable energy resources.
    171. There are few rate structures in place today that provide for
the allocation and recovery of costs of interregional transmission
facilities. We are concerned that the absence of clear cost allocation
rules for interregional transmission facilities could impede the
development of such facilities, because of uncertainty regarding
recovery of associated costs. In addition, the combined size of the
multiple transmission planning regions in which an interregional
facility would be located may increase the potential for both free
ridership and the allocation of costs to those that receive no benefit
from a facility.
    172. Therefore, we propose to require that the public utility
transmission providers located in each pair of neighboring transmission
planning regions develop a mutually agreeable method for allocating
between the two transmission planning regions the costs of a new
transmission facility that is located within both regions and that is
eligible for interregional cost recovery pursuant to the region's
interregional transmission planning agreement developed in accordance
with the requirement proposed above. In an RTO or ISO region, we
propose that the method must be filed to become a part of the relevant
tariffs. In other transmission planning regions, we propose that the
cost allocation method be filed as part of the OATT of each public
utility transmission provider in the region.
    173. A group of three or more transmission planning regions within
an interconnection--or all of the transmission planning regions within
an interconnection--may agree on and file a common method for
allocating the costs of a new interregional transmission facility.
However, the Commission does not propose to require such agreements
among more than two neighboring transmission planning regions.
    174. Each cost allocation method filed in accordance with this
proposal would be required to comply with the following principles:
    (1) The costs of a new interregional facility must be allocated to
each transmission planning region in which that facility is located in
a manner that is at least roughly commensurate with the estimated
benefits of that facility in each of the transmission planning regions.
In determining the beneficiaries of interregional transmission
facilities, transmission planning regions may consider benefits
including, but not limited to, those associated with maintaining
reliability and sharing reserves, production cost savings and
congestion relief, and meeting public policy requirements established
by State or Federal laws or regulations that may drive transmission
needs.\171\
---------------------------------------------------------------------------

    \171\ As discussed above, the Commission proposes to require
each public utility transmission provider to amend its OATT such
that its local and regional transmission planning processes
explicitly provide for consideration of public policy requirements
established by state or Federal laws or regulations that may drive
transmission needs.
---------------------------------------------------------------------------

    (2) A transmission planning region that receives no benefit from an
interregional transmission facility that is located in that region,
either at present or in a likely future scenario, must not be
involuntarily allocated any of the costs of that facility.\172\
---------------------------------------------------------------------------

    \172\ For example, a DC line that runs from a first transmission
planning region, through a second transmission planning region, and
into a third transmission planning region, with no tap in the second
region, may not provide any benefits to the second region.
---------------------------------------------------------------------------

    (3) If a benefit-cost threshold ratio is used to determine whether
an interregional transmission facility has sufficient net benefits to
qualify for interregional cost allocation, this ratio must not be so
large as to exclude a facility with significant positive net benefits
from cost allocation. The public utility transmission providers located
in the neighboring transmission planning regions may choose to use such
a threshold to account for uncertainty in the calculation of benefits
and costs. If adopted, such a threshold, may not include a ratio of
benefits to costs that exceeds 1.25 unless the pair of regions
justifies and the Commission approves a higher ratio.
    (4) Costs allocated for an interregional facility must be assigned
only to transmission planning regions in which the facility is located.
Costs cannot be assigned involuntarily under this rule to a
transmission planning region in which that facility is not located.
However, the interregional planning process must identify consequences
for other transmission planning regions, such as upgrades that may be
required in a third transmission planning region and, if there is an
agreement among the transmission providers in the regions in which the
facility is located to bear costs associated with such upgrades, then
the interregional cost allocation method must include provisions for
allocating the costs of the upgrades within the transmission planning
regions in which the facility is located.
    (5) The cost allocation method and data requirements for
determining benefits and identifying beneficiaries for an interregional
facility must be transparent with adequate documentation to allow a
stakeholder to determine how they were applied to a proposed
transmission facility.
    (6) The public utility transmission providers located in
neighboring transmission planning regions may choose to use a different
cost allocation method for different types of interregional facilities,
such as transmission facilities needed for reliability, congestion
relief, or to achieve public policy requirements established by State
or Federal laws or regulations. Each cost allocation method must be set
out and explained in detail in the compliance filing for this rule.
    175. As with intraregional cost allocation, we are not proposing to
require a uniform method of cost allocation for interregional
transmission facilities. There may be legitimate reasons for the public
utility transmission providers located in neighboring transmission
planning regions to adopt different cost allocation methods. The
Commission recognizes that several approaches to cost allocation may
satisfy the proposed principles.\173\
---------------------------------------------------------------------------

    \173\ For the reasons discussed above with respect to cost
allocation for intraregional transmission facilities, a cost
allocation method that relies exclusively on a participant funding
approach, without respect to other beneficiaries of a transmission
facility, would not satisfy the proposed principles for
interregional cost allocation.
---------------------------------------------------------------------------

    176. Therefore, we propose to allow methods for allocating the
costs of new interregional facilities to differ among pairs of
transmission planning regions, as long as each method satisfies the
proposed interregional cost allocation principles listed above.
Moreover, the method used for allocating interregional transmission
facility costs between any two transmission planning regions may be
different from the method used by the public utility transmission
providers located in either of those transmission planning regions to
allocate the costs of new intraregional facilities. In addition, the
cost allocation method used by the

public utility transmission providers located in a transmission
planning region to allocate the costs of new intraregional facilities
could be different from the cost allocation method by which the public
utility transmission providers in the same transmission planning region
further allocate costs to be borne by that transmission planning region
pursuant to an agreed-upon method for allocating the costs of
interregional facilities.
    177. Similar to our proposal for intraregional transmission
facilities, we propose that if the public utility transmission
providers in coordination with their customers and other stakeholders
in a pair of neighboring transmission planning regions cannot agree on
a cost allocation method for new interregional transmission facilities
that satisfies these principles, then the Commission would use the
record in the relevant compliance filing proceedings as a basis for
applying the principles to develop an interregional cost allocation
method that meets the Commission's requirements. Such a cost allocation
method would not necessarily be the same for every pair of neighboring
transmission planning regions that is unable to agree on a cost
allocation method that satisfies the principles.
    178. We seek comment on any issue of interest or concern related to
the requirements proposed in this section of the Proposed Rule. In
particular, we seek comment on the appropriateness and application of
the proposed cost allocation principles with respect to new
intraregional and interregional transmission facilities. If commenters
believe that additional principles should apply to cost allocation for
either intraregional or interregional transmission facilities, the
Commission asks commenters to submit and explain the need for those
principles.

VI. Compliance Filings

    179. The Commission proposes that each public utility transmission
provider must comply with the requirements of this Proposed Rule. With
the exception of the proposed requirements with respect to
interregional transmission planning agreements and an interregional
cost allocation method or methods, the Commission proposes to require
each public utility transmission provider to submit a compliance filing
within six months of the effective date of the final rule in this
proceeding revising its OATT or other document(s) subject to the
Commission's jurisdiction as necessary to demonstrate that it meets the
proposed requirements set forth in this Proposed Rule.\174\ The
Commission proposes to require each public utility transmission
provider to submit a compliance filing within one year of the effective
date of the final rule in this proceeding to demonstrate that it meets
the proposed requirements set forth in the Proposed Rule with respect
to interregional transmission planning agreements. The Commission
proposes to require each public utility transmission provider to submit
a compliance filing within one year of the effective date of the final
rule in this proceeding revising its OATT as necessary to demonstrate
that it meets the proposed requirements set forth in this Proposed Rule
with respect to an interregional cost allocation method or methods.
---------------------------------------------------------------------------

    \174\ See Appendix B for the proposed pro forma Attachment K
consistent with this NOPR.
---------------------------------------------------------------------------

    180. The Commission would assess whether each compliance filing
satisfies the proposed requirements and principles stated above and
issue additional orders as necessary to ensure that each public utility
transmission provider meets the requirements of this Proposed Rule.
    181. The Commission proposes that transmission providers that are
not public utilities would have to adopt the requirements of this
Proposed Rule as a condition of maintaining the status of their safe
harbor tariff or otherwise satisfying the reciprocity requirement of
Order No. 888.\175\
---------------------------------------------------------------------------

    \175\ Order No. 888, FERC Stats. & Regs. ] 31,036 at 31,760-63.
---------------------------------------------------------------------------

VII. Information Collection Statement

    182. The following collection of information contained in this
Proposed Rule is subject to review by the Office of Management and
Budget (OMB) under section 3507(d) of the Paperwork Reduction Act of
1995.\176\ OMB's regulations require approval of certain information
collection requirements imposed by agency rules.\177\ The Commission
solicits comments on the Commission's need for this information,
whether the information will have practical utility, the accuracy of
the burden estimates, ways to enhance the quality, utility and clarity
of the information to be collected or retained, and any suggested
methods for minimizing respondents' burden, including the use of
automated information techniques.
---------------------------------------------------------------------------

    \176\ 44 U.S.C. 3507(d).
    \177\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    Burden Estimate: The estimated public reporting burdens for the
proposed reporting requirements are as follows:

----------------------------------------------------------------------------------------------------------------
                                                                                Total annual
 FERC-917--Proposed reporting    Annual number   Annual number      Hours per      Total annual      hours in
    requirements in RM10-23     of respondents   of responses       response       hours in year    subsequent
                                   (Filers)                                              1             years
----------------------------------------------------------------------------------------------------------------
Participation in a transparent             134             134  100 hrs. in Year          13,400           6,700
 and open intraregional                                          1; 50 hrs. in
 transmission planning process                                   subsequent
 that meets transmission                                         years.
 planning principles, includes
 consideration of public
 policy requirements,
 identifies and evaluates
 facilities to meet needs,
 develops cost allocation
 method, and produces an
 intraregional transmission
 plan that describes and
 incorporates a cost
 allocation method that meets
 the Commission's principles.

Coordination, development, and             134             134  125 hrs. in Year          16,750           6,700
 filing with the Commission of                                   1; 50 hrs. in
 interregional planning                                          subsequent
 agreements that meet the                                        years.
 Commission's requirements,
 that include consideration of
 public policy requirements,
 and that incorporate cost
 allocation methods that meets
 the Commission's principles;
 provide or post ongoing
 communications, and provide
 annual data exchange.
Conforming tariff changes for              134             134  50 hrs. in Year            6,700           3,350
 local transmission planning,                                    1; 25 hours in
 including those related to                                      subsequent
 consideration of public                                         years.
 policy requirements; and
 conforming tariff changes for
 intraregional and
 interregional planning.
                               ---------------------------------------------------------------------------------
    Total Estimated Additional  ..............  ..............  ................          36,850          16,750
     Burden Hours, Proposed
     for FERC-917 in NOPR in
     RM10-23.
----------------------------------------------------------------------------------------------------------------

    Cost To Comply: The Commission has projected costs of compliance
for the reporting requirements as follows:

Year 1: $4,200,900 [36,850 hours x $114 per hour \178\]
---------------------------------------------------------------------------

    \178\ 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: $1,909,500 [or 16,750 hours x $114 per hour]

OMB's regulations require it to approve certain information collection
requirements imposed by an agency rule. The Commission is submitting
notification of this Proposed Rule to OMB. The Commission proposes to
make the reporting requirements mandatory.
    Title: FERC-917.
    Action: Proposed Collection.
    OMB Control No. 1902-0233.
    Respondents: Electric Utility Transmission Providers. RTOs and ISOs
also may file some materials on behalf of their members.
    Frequency of responses: Initial filing and subsequent filings.
    Necessity of the Information:
    183. Building on the reforms in Order No. 890, the Federal Energy
Regulatory Commission is proposing amendments to the pro forma OATT to
correct certain deficiencies in transmission planning and cost
allocation requirements for public utility transmission providers. The
purpose of this proposed rulemaking 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 propose to achieve this goal
by reforming electric transmission planning requirements and
establishing a closer link between cost allocation and regional
transmission planning processes.
    184. Internal Review: The Commission has reviewed the proposed
changes and has determined that the changes are necessary. These
requirements conform to the Commission's need for efficient information
collection, communication, and management within the energy industry.
The Commission has assured itself, by means of internal review, that
there is specific, objective support associated with the information
requirements.
    185. Interested persons may obtain information on the 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, e-mail:
<EMAIL_ADDRESS>Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>. For
submitting comments concerning the collection of information and the
associated burden estimate(s), please send your comments to the contact
listed above and 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:<PHONE_NUMBER>]. Due to
security concerns, comments should be sent electronically to the
following e-mail address<EMAIL_ADDRESS>Please
reference OMB Control No. 1902-0233 and the docket number of this
proposed rulemaking in your submission.

VIII. Environmental Analysis

    186. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\179\ The
Commission concludes that neither an Environmental Assessment nor an
Environmental Impact Statement is required for this Proposed Rule under
section 380.4(a)(15) of the Commission's regulations, which provides a
categorical exemption for approval of actions under sections 205 and
206 of the FPA relating to the filing of schedules containing all rates
and charges for the transmission or sale of electric energy subject to
the Commission's jurisdiction, plus the classification, practices,
contracts and regulations that affect rates, charges, classifications,
and services.\180\
---------------------------------------------------------------------------

    \179\ Regulations Implementing the National Environmental Policy
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. &
Regs., Regulations Preambles 1986-1990 ] 30,783 (1987).
    \180\ 18 CFR 380.4(a)(15).
---------------------------------------------------------------------------

IX. Regulatory Flexibility Act Analysis

    187. The Regulatory Flexibility Act of 1980 (RFA) \181\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
This Proposed Rule 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. The total estimated number of public utility transmission
providers that, absent waiver, would have to modify their current OATTs
by filing the revised pro

forma OATT is 134. Of these public utility transmission providers, an
estimated 10 filers, or 7.3% percent, have output of four million MWh
or less per year.\182\ The Commission does not consider this a
substantial number and, in any event, each of these entities retains
its rights to waiver of these requirements. The criteria for waiver
that would be applied under this rulemaking for small entities is
unchanged from that used to evaluate requests for waiver under Order
Nos. 888, 889 and 890. Accordingly, the Commission certifies that the
proposed rule will not have a significant economic impact on a
substantial number of small entities.
---------------------------------------------------------------------------

    \181\ 5 U.S.C. 601-612.
    \182\ A firm is ``small'' if, including its affiliates, it is
primarily engaged in the generation, transmission, and/or
distribution of electric energy for sale and its total electric
output for the preceding fiscal year did not exceed 4 million
megawatt hours. Based on the filers of the annual FERC Form 1 and
Form 1-F, as well as the number of companies that have obtained
waivers, we estimate that 7.3% of the filers are ``small.''
---------------------------------------------------------------------------

X. Comment Procedures

    188. The Commission invites interested persons to submit comments
on the matters and issues proposed in this notice to be adopted,
including any related matters or alternative proposals that commenters
may wish to discuss. Comments are due 60 days from publication in the
Federal Register. Comments must refer to Docket No. RM10-23-000, and
must include the commenter's name, the organization they represent, if
applicable, and their address in their comments.
    189. The Commission encourages comments to be filed electronically
via the eFiling link on the Commission's Web site at http://
www.ferc.gov. The Commission accepts most standard word processing
formats. Documents created electronically using word processing
software should be filed in native applications or print-to-PDF format
and not in a scanned format. Commenters filing electronically do not
need to make a paper filing.
    190. Commenters that are not able to file comments electronically
must send an original and 14 copies of their comments to: Federal
Energy Regulatory Commission, Office of the Secretary, 888 First
Street, NE., Washington, DC 20426.
    191. All comments will be placed in the Commission's public files
and may be viewed, printed, or downloaded remotely as described in the
Document Availability section below. Commenters on this proposal are
not required to serve copies of their comments on other commenters.

XI. Document Availability

    192. 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 FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    193. From FERC'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.
    194. User assistance is available for eLibrary and the FERC's web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
List of Subjects in 18 CFR Part 35

    Electric power rates, Electric utilities, Reporting and
recordkeeping requirements.

    By direction of the Commission. Commissioner Moeller is
concurring with a separate statement attached.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
    In consideration of the foregoing, the Commission proposes to amend
part 35, Chapter I, Title 18, Code of Federal Regulations, as follows:

PART 35--FILING OF RATE SCHEDULES AND TARIFFS

    1. The authority citation for part 35 continues to read as follows:

    Authority: 16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42
U.S.C. 71-7352.

    2. Amend Sec.  35.28 as follows:
    a. Paragraph (c)(1) introductory text and (c)(1)(i) through
(c)(1)(iii) are revised.
    b. Paragraph (c)(1)(vi) is revised.
    c. Paragraphs (c)(3) introductory text, (c)(3)(i), and (c)(3)(ii)
are revised.
    d. Paragraph (c)(4) is revised.
    e. Paragraph (d) (1) is revised.
    f. Paragraph (e)(1) introductory text, is revised.

Sec.  35.28  Non-discriminatory open access transmission tariff.

* * * * *
    (c) Non-discriminatory open access transmission tariffs.
    (1) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce must have on file with the Commission a tariff of general
applicability for transmission services, including ancillary services,
over such facilities. Such tariff must be the open access pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036 (Final
Rule on Open Access and Stranded Costs), as revised by the open access
pro forma tariff contained in Order No. 890, FERC Stats. & Regs. ]
31,241 (Final Rule on Open Access Reforms) and further revised in Order
No. ------, FERC Stats. & Regs. ] ------ (Final Rule on Transmission
Planning and Cost Allocation by Transmission Owning and Operating
Public Utilities), or such other open access tariff as may be approved
by the Commission consistent with Order No. 888, FERC Stats. & Regs ]
31,306, Order No. 890, FERC Stats. & Regs. ] 32,241, and Order No. ----
--, FERC Stats. & Regs. ] ------.
    (i) Subject to the exceptions in paragraphs (c)(1)(ii),
(c)(1)(iii), (c)(1)(iv) and (c)(1)(v) of this section, the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as
revised by the open access pro forma tariff contained in Order No. 890,
FERC Stats. & Regs. ] 31,241 and further revised in Order No. ------,
FERC Stats. & Regs. ] ------, and accompanying rates, must be filed no
later than 60 days prior to the date on which a public utility would
engage in a sale of electric energy at wholesale in interstate commerce
or in the transmission of electric energy in interstate commerce.
    (ii) If a public utility owns, controls, or operates facilities
used for the transmission of electric energy in interstate commerce as
of [60 days after date of publication of the Final Rule in the Federal
Register], it must file the revisions to the pro forma tariff contained
in Order No. 890, FERC Stats. & Regs. ] 31,241, as amended by Order
No.------, FERC Stats. & Regs. ] ------, pursuant to section 206 of the
FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. ------, FERC Stats. & Regs ] ------.
    (iii) If a public utility owns, controls, or operates transmission
facilities used for the transmission of electric energy in interstate
commerce as of [60 days after date of publication of the Final Rule in
the Federal Register], such facilities are

jointly owned with a non-public utility, and the joint ownership
contract prohibits transmission service over the facilities to third
parties, the public utility with respect to access over the public
utility's share of the jointly owned facilities must file the revisions
to the pro forma tariff contained in Order No. 890, FERC Stats. & Regs.
] 31,241 as amended by Order No. ------, FERC Stats. & Regs. ] ------,
pursuant to section 206 of the FPA and accompanying rates pursuant to
section 205 of the FPA.
* * * * *
    (vi) Any public utility that seeks a deviation from the pro forma
tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036, as
revised in Order No. 890, FERC Stats. & Regs. ] 31,241 and Order No. --
----, FERC Stats. & Regs. ] ------, must demonstrate that the deviation
is consistent with the principles of Order No. 888, FERC Stats. & Regs.
] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. --
----, FERC Stats. & Regs. ] ------.
* * * * *
    (3) Every public utility that owns, controls, or operates
facilities used for the transmission of electric energy in interstate
commerce, and that is a member of a power pool, public utility holding
company, or other multi-lateral trading arrangement or agreement that
contains transmission rates, terms or conditions, must have on file a
joint pool-wide or system-wide open access transmission tariff, which
tariff must be the pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036, as revised by the pro forma tariff contained
in Order No. 890, FERC Stats. & Regs. ] 31,241 and further revised in
Order No. ------, FERC Stats. & Regs. ] ------, or such other open
access tariff as may be approved by the Commission consistent with
Order No. 888, FERC Stats. & Regs. ] 31,036, Order No. 890, FERC Stats.
& Regs. ] 31,241, and Order No. ------, FERC Stats. & Regs. ] ------.
    (i) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed after [60 days after
date of publication of the Final Rule in the Federal Register], this
requirement is effective on the date that transactions begin under the
arrangement or agreement.
    (ii) For any power pool, public utility holding company or other
multi-lateral arrangement or agreement that contains transmission
rates, terms or conditions and that is executed on or before [60 days
after date of publication of the Final Rule in the Federal Register], a
public utility member of such power pool, public utility holding
company or other multi-lateral arrangement or agreement that owns,
controls, or operates facilities used for the transmission of electric
energy in interstate commerce must file the revisions to its joint
pool-wide or system-wide open access transmission tariff consistent
with Order No. 890, FERC Stats. & Regs. ] 31,241 as amended by Order
No.------, FERC Stats. & Regs. ] ------, pursuant to section 206 of the
FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. ------, FERC Stats. & Regs ] ------.
* * * * *
    (4) Consistent with paragraph (c)(1) of this section, every
Commission-approved ISO or RTO must have on file with the Commission a
tariff of general applicability for transmission services, including
ancillary services, over such facilities. Such tariff must be the pro
forma tariff contained in Order No. 888, FERC Stats. & Regs. ] 31,036,
as revised by the pro forma tariff contained in Order No. 890, FERC
Stats. & Regs. ] 31,241 and further revised in Order No. ------, FERC
Stats. & Regs. ] ------, or such other open access tariff as may be
approved by the Commission consistent with Order No. 888, FERC Stats. &
Reg. ] 31,036, Order No. 890, FERC Stats. & Regs. ] 31,241, and Order
No. ------, FERC Stats. & Regs. ] ------.
    (i) Subject to paragraph (c)(4)(ii) of this section, a Commission-
approved ISO or RTO must file the revisions to the pro forma tariff
contained in Order No. 890, FERC Stats. & Regs. ] 31,241 as amended by
Order No. ------, FERC Stats. & Regs. ] ------, pursuant to section 206
of the FPA and accompanying rates pursuant to section 205 of the FPA in
accordance with the procedures set forth in Order No. 890, FERC Stats.
& Regs. ] 31,241 and Order No. ------, FERC Stats. & Regs. ] ------.
    (ii) If a Commission-approved ISO or RTO can demonstrate that its
existing open access tariff is consistent with or superior to the
revisions to the pro forma tariff contained in Order No. 888, FERC
Stats. & Regs. ] 31,036, as revised by the pro forma tariff in Order
No. 890, FERC Stats. & Regs. ] 31,241 and further revised in Order No.
------, FERC Stats. & Regs. ] ------, or any portions thereof, the
Commission-approved ISO or RTO may instead set forth such demonstration
in its filing pursuant to section 206 in accordance with the procedures
set forth in Order No., FERC Stats. & Regs. ] ------.
    (d) Waivers. * * *
    (1) No later than [60 days after date of publication of the Final
Rule in the Federal Register], or
* * * * *
    (e) Non-public utility procedures for tariff reciprocity
compliance.
    (1) A non-public utility may submit a transmission tariff and a
request for declaratory order that its voluntary transmission tariff
meets the requirements of Order No. 888, FERC Stats. & Regs. ] 31,036,
Order No. 890, FERC Stats. & Regs. ] 31,241, and Order No. ------, FERC
Stats. & Regs. ] ------.
* * * * *

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

   Appendix A--List of Short Names of Commenters on the Federal Energy
 Regulatory Commission's Notice of Request for Comments on Transmission
 Planning Processes Under Order No. 890--Docket No. AD09-8-000, October
                                  2009
------------------------------------------------------------------------
         Short name or acronym                      Commenter
------------------------------------------------------------------------
3M.....................................  3M Company, High Capacity
                                          Conductors.
AEP....................................  American Electric Power Service
                                          Corporation.
Alabama PSC............................  Alabama Public Service
                                          Commission.
Allegheny Companies....................  Allegheny Power and Trans-
                                          Allegheny Interstate Line
                                          Company.
Ameren.................................  Ameren Services Company.
American Antitrust Institute...........  American Antitrust Institute.
American Forest and Paper..............  American Forest & Paper
                                          Association.
American Transmission..................  American Transmission Company
                                          LLC.
APPA...................................  American Public Power
                                          Association.
AREVA T&D..............................  AREVA T&D Inc.

AWEA...................................  American Wind Energy
                                          Association.
Baltimore Gas and Electric.............  Baltimore Gas and Electric
                                          Company.
Barbara Luchsinger.....................  Barbara Luchsinger.
Bay Area Municipal Transmission Group..  City of Santa Clara,
                                          California; the City of Palo
                                          Alto, California; and the City
                                          of Alameda, California.
Bonneville.............................  Bonneville Power
                                          Administration.
BP Energy..............................  BP Energy Company.
The Brattle Group......................  Peter Fox-Penner, Johannes
                                          Pfeifenberger, and Delphine
                                          Hou.
California ISO.........................  California Independent System
                                          Operator Corporation.
Californians for Renewable Energy......  Californians for Renewable
                                          Energy, Inc.
California PUC.........................  California Public Utilities
                                          Commission.
California State Water Project.........  California Department of Water
                                          Resources State Water Project.
Calvin Daniels.........................  Calvin Daniels.
Chinook and Zephyr.....................  Chinook Power Transmission, LLC
                                          and Zephyr Power Transmission,
                                          LLC.
Clean Line.............................  Clean Line Energy Partners,
                                          LLC.
Coalition To Advance Renewable Energy    Coalition To Advance Renewable
 Through Bulk Energy Storage.             Energy Through Bulk Energy
                                          Storage.
ColumbiaGrid...........................  ColumbiaGrid.
Consolidated Edison, et al.............  Consolidated Edison Company of
                                          New York, Inc. and Orange and
                                          Rockland Utilities, Inc.
Dayton Power and Light.................  Dayton Power and Light Company.
Delaware Municipal and Southwestern      Delaware Municipal Electric
 Electric.                                Corporation, Inc. and
                                          Southwestern Electric
                                          Cooperative, Inc.
Dominion...............................  Dominion Resources Services,
                                          Inc.
Duke...................................  Duke Energy Corporation.
Eastern Interconnection Planning         Eastern Interconnection
 Collaborative Analysis Team.             Planning Collaborative
                                          Analysis Team.
Eastern PJM Governors..................  Governors of New Jersey,
                                          Delaware, Maryland, and
                                          Virginia.
EEI....................................  Edison Electric Institute.
Electricity Consumers Resource Council.  Electricity Consumers Resource
                                          Council.
ENE (Environment Northeast)............  ENE Environment Northeast.
Energy Future Coalition................  Energy Future Coalition.
Entergy................................  Entergy Services, Inc.
E.ON...................................  E.ON U.S. LLC.
E.ON Climate & Renewables North America  E.ON Climate & Renewables North
                                          America.
EPSA...................................  Electric Power Supply
                                          Association.
Exelon.................................  Exelon Corporation.
Federal Trade Commission...............  Federal Trade Commission.
FirstEnergy............................  FirstEnergy Affiliates.
Florida Transmission Providers.........  Florida Power & Light, Progress
                                          Energy Florida, Tampa Electric
                                          Company, and JEA.
Georgia Transmission Corporation.......  Georgia Transmission
                                          Corporation.
Great River Energy.....................  Great River Energy.
Green Energy Express...................  Green Energy Express, LLC.
Illinois Commission....................  Illinois Commerce Commission.
Imperial Irrigation District...........  Imperial Irrigation District
                                          (CA).
Independent Power Producers Coalition-   Independent Power Producers
 West.                                    Coalition-West.
Indicated Partners.....................  Green Energy Express LLC;
                                          Transmission Technology
                                          Solutions LLC; SouthWestern
                                          Power Group II, LLC; Nevada
                                          Hydro Company; LS Power
                                          Transmission, LLC; and Pattern
                                          Transmission LP.
Integrys, et al........................  Wisconsin Public Service
                                          Corporation, Upper Peninsula
                                          Power Company, and Integrys
                                          Energy Services, Inc.
ISO New England........................  ISO New England Inc.
ITC Holdings...........................  ITC Holdings Corp.
Kelson Companies.......................  Cottonwood Energy Company LP;
                                          Dogwood Energy LLC; and
                                          Magnolia Energy LP.
Large Public Power Council.............  Austin Energy; Chelan County
                                          Public Utility District No. 1;
                                          Clark Public Utilities;
                                          Colorado Springs Utilities;
                                          CPS Energy (San Antonio); IID
                                          Energy; JEA (Jacksonville,
                                          FL); Long Island Power
                                          Authority; 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, et al.....  Long Island Power Authority,
                                          Consolidated Edison Company of
                                          New York, Inc., and Orange and
                                          Rockland Utilities, Inc.
Lorraine Fleming.......................  Lorraine Fleming.
LS Power...............................  LS Power Transmission, LLC.

Maine PUC and Public Advocate..........  Maine Public Utilities
                                          Commission and the Maine
                                          Office of the Public Advocate.
Massachusetts Attorney General.........  Massachusetts Attorney General.
Massachusetts Departments..............  Massachusetts Department of
                                          Public Utilities and
                                          Massachusetts Department of
                                          Energy Resources.
MEAG Power.............................  MEAG Power.
MidAmerican............................  MidAmerican Energy Holdings
                                          Company.
Midwest ISO............................  Midwest Independent
                                          Transmission System Operator,
                                          Inc.
Midwest ISO Transmission Owners........  Ameren Services Company (as
                                          agent for Union Electric
                                          Company, Central Illinois
                                          Public Service Company,
                                          Central Illinois Light Co.,
                                          and Illinois Power Company);
                                          City of Columbia Water and
                                          Light Department (Columbia,
                                          MO); City Water, Light & Power
                                          (Springfield, IL); Great River
                                          Energy; Hoosier Energy Rural
                                          Electric Cooperative, Inc.;
                                          Indiana Municipal Power
                                          Agency; Indianapolis Power &
                                          Light Company; (Minnesota
                                          Power (and its subsidiary
                                          Superior Water, L&P); Montana-
                                          Dakota Utilities Co.; Northern
                                          Indiana Public Service
                                          Company; Northern States Power
                                          Company (Minnesota and
                                          Wisconsin corporations);
                                          Northwestern Wisconsin
                                          Electric Company; Otter Tail
                                          Power Company; Southern
                                          Illinois Power Cooperative;
                                          Southern Indiana Gas &
                                          Electric Company; Southern
                                          Minnesota Municipal Power
                                          Agency; Wabash Valley Power
                                          Association, Inc.; and
                                          Wolverine Power Supply
                                          Cooperative, Inc.
Modesto Irrigation District............  Modesto Irrigation District.
NARUC..................................  National Association of
                                          Regulatory Utility
                                          Commissioners.
National Audubon Society, et al........  National Audubon Society;
                                          Conservation Law Foundation;
                                          Energy Future Coalition; ENE
                                          (Environment Northeast);
                                          Environmental Defense Fund;
                                          Natural Resources Defense
                                          Council; Piedmont
                                          Environmental Council; Sierra
                                          Club; Sustainable FERC
                                          Project; and Union of
                                          Concerned Scientists.
National Grid..........................  National Grid USA.
National Nuclear Security                National Nuclear Security
 Administration Service Center.           Administration Service Center
                                          in Albuquerque, New Mexico.
National Rural Electric Coops..........  National Rural Electric
                                          Cooperative Association.
NationalWind...........................  NationalWind.
NEPOOL Participants....................  New England Power Pool
                                          Participants Committee.
Nevada Hydro...........................  Nevada Hydro Company, Inc.
New England Clean Energy Council.......  New England Clean Energy
                                          Council.
New England States' Committee on         New England States' Committee
 Electricity.                             on Electricity.
New Jersey Board.......................  New Jersey Board of Public
                                          Utilities.
New York ISO...........................  New York Independent System
                                          Operator, Inc.
New York PSC...........................  New York State Public Service
                                          Commission.
NextEra................................  NextEra Energy Resources, LLC.
Northeast Utilities....................  Northeast Utilities Service
                                          Company.
Northern Tier Transmission Group.......  Northern Tier Transmission
                                          Group.
Northwest State Commissions and          Idaho Public Utilities
 Consumer Counsel.                        Commission, Montana Consumer
                                          Counsel, Montana Public
                                          Service Commission, Public
                                          Utility Commission of Oregon,
                                          Utah Public Service
                                          Commission, and Wyoming Public
                                          Service Commission.
NRG....................................  NRG Energy, Inc.
Ohio Commission........................  Public Utilities Commission of
                                          Ohio.
Old Dominion...........................  Old Dominion Electric
                                          Cooperative.
Organization of MISO States............  Organization of MISO States.
Pacific Gas and Electric...............  Pacific Gas and Electric
                                          Company.
Pattern Transmission...................  Pattern Transmission LP.
Peter C. Luchsinger M.D................  Peter C. Luchsinger M.D.
PHI Companies..........................  Pepco Holdings, Inc.; Potomac
                                          Electric and Power Company;
                                          Delmarva Power & Light
                                          Company; and Atlantic City
                                          Electric Company.
Pioneer Transmission...................  Pioneer Transmission, LLC.
PJM....................................  PJM Interconnection, LLC.
PPL....................................  PPL Electric Utilities
                                          Corporation.
Progress Energy........................  Progress Energy, Inc.
PSEG Companies.........................  Public Service Electric and Gas
                                          Company; PSEG Power LLC; PSEG
                                          Energy Resources & Trade LLC.

Public Interest Organizations &          Alliance for Clean Energy New
 Renewable Energy Groups.                 York; American Wind Energy
                                          Association; Center for Energy
                                          Efficiency & Renewable
                                          Technologies; Citizens Utility
                                          Board of Wisconsin;
                                          Conservation Law Foundation;
                                          Environmental Defense Fund;
                                          Environmental Law & Policy
                                          Center; Fresh Energy; National
                                          Audubon Society; Natural
                                          Resources Defense Council;
                                          Northeast Energy Efficiency
                                          Partnerships; Northwest Energy
                                          Coalition; Office of the Ohio
                                          Consumers' Counsel; Pace
                                          Energy and Climate Center;
                                          Piedmont Environmental
                                          Council; Project for
                                          Sustainable FERC Energy
                                          Policy; Sierra Club; Southern
                                          Alliance for Clean Energy;
                                          Union of Concerned Scientists;
                                          Western Grid Group; and Wind
                                          on the Wires.
Public Power Council...................  Public Power Council.
Renewable Energy Systems Americas......  Renewable Energy Systems
                                          Americas Inc.
RRI Energy.............................  RRI Energy, Inc.
Salt River Project.....................  Salt River Project Agricultural
                                          Improvement and Power
                                          District.
San Diego Gas & Electric...............  San Diego Gas & Electric
                                          Company.
Solar Energy Industries................  Solar Energy Industries
                                          Association.
South Carolina Electric & Gas..........  South Carolina Electric & Gas
                                          Company.
Southern California Edison.............  Southern California Edison
                                          Company.
Southern Companies.....................  Southern Company Services, Inc.
SPP....................................  Southwest Power Pool, Inc.
Startrans..............................  Startrans IO, LLC.
Starwood...............................  Starwood Energy Group Global,
                                          LLC.
State Representative Sloan.............  State Representative Tom Sloan.
Sunflower and Mid-Kansas...............  Sunflower Electric Power
                                          Corporation and Mid-Kansas
                                          Electric Company, LLC.
Trans-Elect............................  Trans-Elect Development
                                          Company, LLC.
Transmission Access Policy Study Group.  Transmission Access Policy
                                          Study Group.
Transmission Agency of Northern          Transmission Agency of Northern
 California.                              California.
Transmission Dependent Utility Systems.  Arkansas Electric Cooperative
                                          Corporation, Golden Spread
                                          Electric Cooperative, Inc.,
                                          Kansas Electric Power
                                          Cooperative, Inc., North
                                          Carolina Electric Membership
                                          Corporation, Old Dominion
                                          Electric Cooperative, and
                                          Seminole Electric Cooperative,
                                          Inc.
Upper Great Plains Transmission          Upper Great Plains Transmission
 Coalition.                               Coalition.
WECC...................................  Western Electricity
                                          Coordinating Council.
WestConnect Planning Parties...........  Arizona Public Service Company,
                                          Basin Electric Power
                                          Cooperative, Black Hills
                                          Corporation, El Paso Electric
                                          Company, Imperial Irrigation
                                          District, NV Energy, Public
                                          Service Company of Colorado,
                                          Public Service Company of New
                                          Mexico, Sacramento Municipal
                                          Utility District, Salt River
                                          Project Agricultural
                                          Improvement and Power
                                          District, Southwest
                                          Transmission Cooperative,
                                          Inc., Transmission Agency of
                                          Northern California, Tri-State
                                          Generation and Transmission
                                          Association, Inc., Tucson
                                          Electric Power Company.
WIRES..................................  Working Group for Investment in
                                          Reliable and Economic Electric
                                          Systems.
Xcel...................................  Xcel Energy Services Inc.
------------------------------------------------------------------------

Appendix B: Pro Forma Open Access Transmission Tariff

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 the Final Rule in Docket
No. RM05-25-000: Coordination, openness, transparency, information
exchange, comparability, dispute resolution, regional participation,
economic planning studies, and cost allocation for new projects. The
planning process shall also include the procedures and mechanisms
for evaluating transmission projects proposed to achieve public
policy requirements established by State or Federal laws or
regulations consistent with the Final Rule in Docket No. RM10-23-
000. The planning process shall also provide a mechanism for the
recovery and allocation of planning costs consistent with the Final
Rule in Docket No. RM05-25-000.
    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 and neighboring
transmission providers;
    (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
evaluating transmission projects proposed to achieve public policy
requirements established by State or Federal laws or regulations;
and
    (ix) The relevant cost allocation method or methods.

Intraregional Transmission Planning

    The Transmission Provider shall participate in a regional
transmission planning process through which transmission facilities
and non-transmission solutions 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 not be unduly
discriminatory and must be consistent with the provision of